CHAPTER 20SERVICE SUPPLIED BY ELECTRIC UTILITIES[Prior to 10/8/86, Commerce Commission]19920.1(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.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. 20.1(2) Application of rules. The rules shall apply to any electric utility 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.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.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).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.These rules shall in no way relieve any utility from any of its duties under the laws of this state. 20.1(3) Definitions. The following words and terms, when used in these rules, shall have the meaning indicated below:
"Acid Rain Program" means the sulfur dioxide and nitrogen oxides air pollution control program established pursuant to Title IV of the Act under 40 CFR Parts 72-78.
"Act" means the Clean Air Act, 42 U.S.C. Section 7401, et seq.
"Affected unit" means a unit or source that is subject to any emission reduction requirement or limitation under the Acid Rain Program, the Clean Air Interstate Rule (CAIR), the Cross-State Air Pollution Rule (CSAPR), or the Mercury and Air Toxics Standards (MATS), or a unit or source that opts in under 40 CFR Part 74.
"Allowance" means an authorization, allocated by the United States Environmental Protection Agency (EPA), to emit sulfur dioxide (SO2) under the Acid Rain Program or SO2 and nitrogen oxide (NOX) under the Clean Air Interstate Rule (CAIR) and the Cross-State Air Pollution Rule (CSAPR) during or after a specified calendar year.
"Allowance futures contract" is an agreement between a futures exchange clearinghouse and a buyer or seller to buy or sell an allowance on a specified future date at a specified price.
"Board" means the utilities board.
"Capacity" means the instantaneous rate at which energy can be delivered, received, or transferred, measured in kilowatts.
"Clean Air Interstate Rule" "CAIR" means the requirements EPA published in the Federal Register (70 Fed.Reg.25161) on May 12, 2005.
"Complaint," as used in these rules, is a statement or question by anyone, whether a utility customer or not, alleging a wrong, grievance, injury, dissatisfaction, illegal action or procedure, dangerous condition or action, or utility obligation.
"Compliance plan" means the document submitted for an affected source to the EPA which specifies the methods by which each affected unit at the source will meet the applicable emissions limitation and emissions reduction requirements.
"Cross-State Air Pollution Rule" "CSAPR" means the requirements established by EPA in 40 CFR 97 Subparts AAAAA, BBBBB, CCCCC, and DDDDD as amended by 81 FR 13275 (March 14, 2016).
"Customer" means any person, firm, association, or corporation, any agency of the federal, state or local government, or legal entity responsible by law for payment for the electric service or heat from the electric utility.
"Delinquent" "delinquency" means an account for which a service bill or service payment agreement has not been paid in full on or before the last day for timely payment.
"Distribution line" means any single or multiphase electric power line operating at nominal voltage in either of the following ranges: 2,000 to 26,000 volts between ungrounded conductors or 1,155 to 15,000 volts between grounded and ungrounded conductors, regardless of the functional service provided by the line.
"Electric plant" includes all real estate, fixtures and property owned, controlled, operated or managed in connection with or to facilitate production, generation, transmission, or distribution, in providing electric service or heat by an electric utility.
"Electric service" is furnishing to the public for compensation any electricity, heat, light, power, or energy.
"Emission for emission trade" is an exchange of one type of emission for another type of emission. For example, the exchange of SO2 emission allowances for NOX emission allowances.
"Energy" means electric energy measured in kilowatt hours.
"Gains and losses from allowance sales" are calculated as the difference between the sale price of allowances sold during the month and the weighted average unit cost of inventoried allowances.
"Mercury and Air Toxics Standards" "MATS" means the requirements established by EPA in 40 CFR Parts 60 and 63 regarding limits of power plant emissions of toxic air pollutants (February 16, 2012).
"Meter" means, unless otherwise qualified, a device that measures and registers the integral of an electrical quantity with respect to time.
"Operating reserve" is a reserve generating capacity required to ensure reliability of generation resources.
"Peaking power" is power and associated energy intended to be available at all times during the commitment and anticipated to have low load factor use.
"Power" means electric power measured in kilowatts.
"Price hedging" means using futures contracts or options to guard against unfavorable price changes.
"Rate-regulated utility" means any utility, as defined in 20.1(3),which is subject to board rate regulation under Iowa Code chapter 476.
"Secondary line" means any single or multiphase electric power line operating at nominal voltage less than either 2,000 volts between ungrounded conductors or 1,155 volts between grounded and ungrounded conductors, regardless of the functional service provided by the line.
"Service limitation" means the establishment of a limit on the amount of power that may be consumed by a residential customer through the installation of a service limiter on the customer’s meter.
"Service limiter" "service limitation device" means a device that limits a residential customer’s power consumption to 3,600 watts (or some higher level of usage approved by the board) and that resets itself automatically, or can be reset manually by the customer, and may also be reset remotely by the utility at all times.
"Speculation" means using futures contracts or options to profit from expectations of future price changes.
"Tariff" means the entire body of rates, tolls, rentals, charges, classifications, rules, procedures, policies, etc., adopted and filed with the board by an electric utility in fulfilling its role of furnishing service.
"Timely payment" is a payment on a customer’s account made on or before the date shown on a current bill for service, or on a form which records an agreement between the customer and a utility for a series of partial payments to settle a delinquent account, as the date which determines application of a late payment charge to the current bill or future collection efforts.
"Transmission line" means any single or multiphase electric power line operating at nominal voltages at or in excess of either 69,000 volts between ungrounded conductors or 40,000 volts between grounded and ungrounded conductors, regardless of the functional service provided by the line.
"Utility" means any person, partnership, business association or corporation, domestic or foreign, owning or operating any facilities for providing electric service or heat to the public for compensation.
"Vintage trade" is an exchange of one vintage of allowances for another vintage of allowances with the difference in value between vintages being cash or additional allowances.
"Weighted average unit cost of inventoried allowances" equals the dollars in inventory at the end of the month divided by the total allowances available for use at the end of the month.
"Wheeling service" is the service provided by a utility in consenting to the use of its transmission facilities by another party for the purpose of scheduling delivery of power or energy, or both.20.1(4) Abbreviations. The following abbreviations may be used where appropriate:ANSI—American National Standards Institute, 1430 Broadway, New York, New York 10018.DOE—Department of Energy, Washington, D.C. 20426.EPA—United States Environmental Protection Agency.FCC—Federal Communications Commission, 1919 M Street, Washington, D.C. 20554.FERC—Federal Energy Regulatory Commission, Washington, D.C. 20426.NARUC—National Association of Regulatory Utility Commissioners, P.O. Box 684, Washington, D.C. 20044.NBS—National Bureau of Standards, Washington, D.C. 20234.NFPA—National Fire Protection Association, 470 Atlantic Ave., Boston, Massachusetts 02210.Related ARC(s): 7976B, 4171C19920.2(476) Records, reports, and tariffs. 20.2(1) Location and retention of records. Unless otherwise specified by this chapter, all records required by these rules shall be kept and preserved in accordance with the applicable provisions of 199—Chapter 18. 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. 20.2(3) Form and identification. All tariffs shall conform to the following rules: a. The tariff shall be filed electronically using the board’s electronic filing system. The filed tariff shall be capable of being reproduced on 8½- × 11- inch paper so customers may readily view and reproduce copies of the tariff. A tariff filed with the board may be the same format as is required by a federal agency provided that the rules of the board as to title page; identity of superseding, replacing or revision sheets; identity of amending sheets; identity of the filing utility, issuing official, date of issue, effective date; and the words “Tariff with board” shall apply in the modification of the federal agency format for the purposes of filing with this board. b. The title page of every tariff and supplement shall show: (1) The first page shall be the title page which shall show:(Name of Public Utility)Electric TariffFiled withIowa Utilities Board(Date) (2) When a tariff is to be superseded or replaced in its entirety, the replacing tariff shall show on the upper right corner of its title page that it supersedes a tariff on file and the number being superseded or replaced, for example:tariff no.supersedes tariff no. (3) When a new part of a tariff eliminates an existing part of a tariff it shall so state and clearly indicate the part eliminated. (4) Any tariff modifications as defined above shall be marked in the right-hand margin of the replacing tariff sheet with symbols as here described to indicate the place, nature and extent of the change in text.—Symbols—(C)—Changed regulation(D)—Discontinued rate or regulation (I)—Increase in rate or new treatment resulting in increased rate(N)—New rate, treatment or regulation (R)—Reduction in rate or new treatment resulting in reduced rate(T)—Change in text only c. All sheets except the title page shall have, in addition to the above-stated requirements, the following information: (1) Name of utility under which shall be set forth the words “Filed with board.” If the utility is not a corporation, and a trade name is used, the name of the individual or partners must precede the trade name. (2) Issuing official and issue date. (3) Effective date (to be left blank by rate-regulated utilities). d. All sheets except the title page shall have the following form:(Company Name)(Part identification)Electric Tariff(This sheet identification)Filed with board(Canceled sheet identification, if any)(Content or tariff)Issued: (Date)Effective:Issued by: (Name, title)(Proposed Effective Date:)The issued date is the date the tariff or the amended sheet content was adopted by the utility.The effective date will be left blank by rate-regulated utilities and shall be determined by the board. The utility may propose an effective date. 20.2(4) Content of tariffs. a. A table of contents containing a list of rate schedules and other sections in the order in which they appear showing the sheet numbers of the first page of each rate schedule or other section. In the event the utility filing the tariff elects to segregate a section such as general rules from the section containing the rate schedules or other sections, it may at its option prepare a separate table of contents for each such segregated section. b. A preliminary statement containing a brief general explanation of the utility’s operations. c. All rates for service with indication for each rate of the type and voltage of service and the class of customers to which each rate applies. There shall also be shown any limitations on loads and type of equipment which may be connected, the net prices per unit of service and the number of units per billing period to which the net prices apply, the period of billing, the minimum bill, any effect of transformer capacity upon minimum bill or upon the number of kWh in any step of the rate, method of measuring demands, method of calculating or estimating loads in cases where transformer capacity has a bearing upon minimum bill or size of rate steps, level payment plan, and any special terms or conditions applicable. The period during which the net amount may be paid before the account becomes delinquent shall be specified. In any case where net and gross amounts are billed, the difference between net and gross is a late payment charge and shall be so specified. d. The voltage and type of service, (direct current or single or polyphase alternating current) supplied in each municipality, but without reference required to any particular part thereof. e. Forms of standard contracts required of customers for the various types of service available. f. If service to other utilities or municipalities is furnished at a standard filed rate, either a copy of each signed contract or a copy of the standard uniform contract form together with a summary of the provisions of each signed contract. The summary shall show the principal provisions of the contract and shall include the name and address of the customer, the points where energy is delivered, rate, term, minimum, load conditions, voltage of delivery and any special provisions such as rentals. Standard contracts for such sales as that of energy for resale, street lighting, municipal athletic field lighting, and for water utilities may be filed in summary form as above outlined. g. Copies of special contracts for the purchase, sale, or interchange of electrical energy. All tariffs must provide that, notwithstanding any other provision of this tariff or contract with reference thereto, all rates and charges contained in this tariff or contract with reference thereto may be modified at any time by a subsequent filing made pursuant to the provisions of Iowa Code chapter 476. h. A list of all communities in which service is furnished. i. The list of service areas and the rates shall be filed in a form to facilitate ready determination of the rates available in each municipality and in unincorporated communities that have service. If the utility has various rural rates, the areas where the same are available shall be indicated. j. Definitions of classes of customers. k. Extension rules for extending service to new customers indicating what portion of the extension or cost thereof will be furnished by the utility; and if the rule is based on cost, the items of cost included. l. Type of construction which the utility requires the customer to provide if in excess of the Iowa electric safety code or the requirements of the municipality having jurisdiction, whichever may be the most stringent in any particular. m. Specification of such portion of service as the utility furnishes, owns, and maintains, such as service drop, service entrance cable or conductors, conduits, service entrance equipment, meter and socket. Indication of the portions of interior wiring such as range or water heater connection, furnished in whole or in part by the utility, and statement indicating final ownership and responsibility for maintaining equipment furnished by utility. n. Statement of the type of special construction commonly requested by customers which the utility allows to be connected, and terms upon which such construction will be permitted, with due provision for the avoidance of unjust discrimination as between customers who request special construction and those who do not. This applies, for example, to a case where a customer desires underground service in overhead territory. o. Rules with which prospective customers must comply as a condition of receiving service, and the terms of contracts required. p. Rules governing the establishment and maintenance of credit by customers for payment of service bills. q. Rules governing the procedure followed in disconnecting and reconnecting service. r. Notice required from a customer for having service discontinued. s. Rules covering temporary, emergency, auxiliary and stand-by service. t. Rules covering the type of equipment which may or may not be connected, including rules such as those requiring demand-limiting devices or power-factor corrective equipment. u. General statement of the method used in making adjustments for wastage of electricity when accidental grounds exist without the knowledge of the customer. v. Statements of utility rules on meter reading, bill issuance, customer payment, notice of delinquency, and service discontinuance for nonpayment of bill. w. Rules for extending service in accordance with 20.3(13). x. If a sliding scale or automatic adjustment is applicable to regulated rates and charges of billed customers, the manner and method of such adjustment calculation shall be covered through a detailed explanation. y. Rules on how a customer or prospective customer should file a complaint with the utility, and how the complaint will be processed. z. Rules on how a customer, disconnected customer or potential customer for residential service may negotiate for a payment agreement on amount due, determination of even payment amounts, and time allowed for payments. 20.2(5) Annual, periodic and other reports to be filed with the board. a. System map verification. The utility shall file annually a verification that it has a currently correct set of utility system maps in accordance with the general requirements of subrule 20.3(11) and a statement as to the location of the utility’s offices where such maps, except those deemed confidential by the board, are accessible and available for examination by the board or its agents. The verification and map location information shall also be reported to the board upon other occasions when significant changes occur in either the maps or location of the maps. b. Accident reports. Rescinded IAB 12/11/91, effective 1/15/92. See 199—25.5(476,478). c. Rescinded IAB 11/13/02, effective 12/18/02. d. Electric service record. Each utility shall compile a monthly record of electric service showing the production, acquisition and disposition of electric energy, the number of customer terminal voltage investigations made, the number of customer meters tested and such other information as may be required by the board. The monthly “Electric Service” record shall be compiled not later than 30 days after the end of the month covered and such record shall, upon and after compilation, be kept available for inspection by the board or its staff at the utility’s principal office within the state of Iowa. A summary of the 12 monthly “Electric Service” records for each calendar year shall be attached to and submitted with the utility’s annual report to the board. e. The utility shall keep the board informed currently by written notice as to the location at which the utility keeps the various classes of records required by these rules. f. The utility’s current rules, if any, published or furnished by the utility for the use of engineers, architects, electrical contractors, etc., covering meter and service installations shall be maintained and made available to the board upon request. g. A copy of each type of customer bill form in current use shall be filed with the board. h. A copy of the adjustment calculation shall be provided the board prior to each billing cycle on the forms adopted by the board. i. Rescinded IAB 1/9/91, effective 2/13/91. j. Residential customer statistics. Each rate-regulated electric utility shall file with the board on or before the fifteenth day of each month one copy of the following residential customer statistics for the preceding month: (1) Number of accounts; (2) Number of accounts certified as eligible for energy assistance since the preceding October 1; (3) Number of accounts past due; (4) Number of accounts eligible for energy assistance and past due; (5) Total revenue owed on accounts past due; (6) Total revenue owed on accounts eligible for energy assistance and past due; (7) Number of disconnection notices issued; (8) Number of disconnection notices issued on accounts eligible for energy assistance; (9) Number of disconnections for nonpayment; (10) Number of reconnections; (11) Number of accounts determined uncollectible; and (12) Number of accounts eligible for energy assistance and determined uncollectible. k. List of persons authorized to receive board inquiries. Each utility shall file with the board in the annual report required in 199—subrule 23.1(2) a list of names, titles, addresses, and telephone numbers of persons authorized to receive, act upon, and respond to communications from the board in connection with: (1) general management duties; (2) customer relations (complaints); (3) engineering operations; (4) meter tests and repairs; (5) franchises for electric lines; (6) certificates for electric generating plants. Each utility shall file with the board a telephone contact number where the board can obtain current information 24 hours a day about outages and interruptions of service from a knowledgeable person. The contact information required by this paragraph shall be kept current as changes or corrections are made.This rule is intended to implement Iowa Code section 476.2.Related ARC(s): 4171C19920.3(476) General service requirements. 20.3(1) Disposition of electricity. The meter and associated instrument transformers shall be owned by the utility. The wiring between the instrument transformers and the meter shall be owned or controlled by the utility. The utility shall place a visible seal on all meters in customer use, such that the seal must be broken to gain entry. a. All electricity sold by a utility shall be on the basis of meter measurement except: (1) Where the consumption of electricity may be readily computed without metering; or (2) For temporary service installations not otherwise metered. b. The amount of all electricity delivered to multioccupancy premises within a single building, where units are separately rented or owned, shall be measured on the basis of individual meter measurement for each unit, except in the following instances: (1) Where electricity is used in centralized heating, cooling, water-heating, or ventilation systems; (2) Where a facility is designated for elderly or handicapped persons; (3) Where submetering or resale of service was permitted prior to 1966; (4) Where individual metering is impractical. “Impractical” means: 1. Conditions or structural barriers exist in the multioccupancy building that would make individual meters unsafe or physically impossible to install; or 2. The cost of providing individual metering exceeds the long-term benefits of individual metering; or (5) Where the benefits of individual metering (reduced and controlled energy consumption) are more effectively accomplished through a master meter arrangement. 1. A new multioccupancy building qualifies for master metering under this subparagraph if the predicted annual energy use would result in at least a 30 percent energy savings compared to the predicted annual energy use of a new building meeting the requirements of the State of Iowa Energy Code and operating with equipment, fixtures, and appliances meeting federal energy standards for manufactured devices for a new building. 2. An existing multioccupancy building qualifies for master metering under this subparagraph when the predicted annual energy use would result in at least a 20 percent energy savings compared to the building’s current annual energy usage levels. 3. Credits for on-site renewable energy generation shall not be taken into account when determining the predicted energy savings. 4. A report from a qualified, independent third party stating that the proposed building or renovation will meet the energy savings requirements of this subparagraph shall establish a rebuttable presumption of eligibility for master metering. “Qualified, independent third party” means a licensed architect or engineer, a certified residential energy services network home energy rating system (RESNET HERS) rater, or any other professional deemed qualified by the board.If a multioccupancy building is master-metered, the end-user occupants may be charged for electricity as an unidentified portion of the rent, condominium fee, or similar payment, or, if some other method of allocating the cost of the electric service is used, the total charge for electric service shall not exceed the total electric bill charged by the utility for the same period. c. Master metering to multiple buildings is prohibited, except for multiple buildings owned by the same person or entity. Multioccupancy premises within a multiple building complex may be master-metered pursuant to this paragraph only if the requirements of paragraph 20.3(1)“b” have been met. d. For purposes of this subrule, a “master meter” means a single meter used in determining the amount of electricity provided to a multioccupancy building or multiple buildings. e. This rule shall not be construed to prohibit any utility from requiring more extensive individual metering than otherwise required by this rule if pursuant to tariffs filed with and approved by the board. f. All electricity consumed by the utility shall be on the basis of meter measurement except where consumption may be readily computed without metering, or where metering is impractical. 20.3(2) Condition of meter. Rescinded IAB 11/12/03, effective 12/17/03. 20.3(3) Meter reading records. The meter reading records shall show: a. Customer’s name, address, and rate schedule or identification of rate schedule. b. Identification of the meter or meters either by permanently marked utility number or by manufacturer’s name, type number and serial number. c. Meter readings. d. If the reading has been estimated. e. Any applicable multiplier or constant. 20.3(4) Meter charts. Rescinded IAB 12/5/18, effective 1/9/19. 20.3(5) Meter register. If it is necessary to apply a multiplier to the meter readings, the multiplier must be marked on the face of the meter register or stenciled in weather-resistant paint upon the front cover of the meter. Customers shall have continuous visual access to meter registers as a means of verifying the accuracy of bills presented to them and for implementing such energy conservation initiatives as they desire, except in the individual locations where the utility has experienced vandalism to windows in the protective enclosures. Where remote meter reading is used, whether outdoor on premises or off premises automated, the customer shall also have readable meter registers at the meter. A utility may comply with the requirements of this subrule by making the required information available via the Internet or other equivalent means.Where a delayed processing means is used, the utility may comply by having readable kWh registers only, visually accessible.In instances in which the utility has determined that readable access, to locations existing July 1, 1981, will create a safety hazard, the utility is exempted from the access provisions above.In instances when a building owner has determined that unrestricted access to tenant metering installation would create a vandalism or safety hazard, the utility is exempted from the access provision above.Continuing efforts should be made to eliminate or minimize the number of restricted locations. The utility should assist affected customers in obtaining meter register information. 20.3(6) Meter reading and billing interval. Readings of all meters used for determining charges and billings to customers shall be scheduled at least monthly and for the beginning and termination of service. Bills to larger customers may, for good cause, be provided weekly or daily for a period not to exceed one month. Intervals other than monthly shall not be applied to smaller customers, or to larger customers after the initial month provided above, without a waiver from the board. A waiver request must include sufficient information to comply with 199—1.3(17A,474,476). If the board denies a waiver, or if a waiver is not sought with respect to a high-demand customer after the initial month, that customer’s meter shall be read monthly for the next 12 months. The group of larger customers to which shorter billing intervals may be applied shall be specified in the utility’s tariff sheets, but shall not include residential customers.An effort shall be made to obtain readings of the meters on corresponding days of each meter reading period. When the meter reading date causes a given billing period to deviate by more than 10 percent (counting only business days) from the normal meter reading period, such bills shall be prorated on a daily basis.The utility may permit the customer to supply the meter readings by telephone, by electronic means, or on a form supplied by the utility. The utility may arrange for customer meter reading forms to be delivered to the utility by United States mail, electronically, or by hand delivery. The utility may arrange for the meter to be read by electronic means. Unless the utility has a plan to test check meter readings, a utility representative shall physically read the meter at least once each 12 months.In the event that the utility leaves a meter reading form with the customer when access to meters cannot be gained and the form is not returned in time for the billing operation, an estimated bill may be provided.If an actual meter reading cannot be obtained, the utility may provide an estimated bill without reading the meter or supplying a meter reading form to the customer. Only in unusual cases or when approval is obtained from the customer shall more than three consecutive estimated bills be provided. 20.3(7) Demand meter registration. When a demand meter is used for billing, the meter installation should be designed so that the highest expected annual demand reading to be used for billing will appear in the upper half of the meter’s range. 20.3(8) Service areas. Service areas are defined by the boundaries on service area maps. Paper 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. 20.3(9) Petition for modification of service area and answers. 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.Any electric utility or municipal corporation may file a petition for modification of service area which shall contain a legal description of the service area desired, a designation of the utilities involved in each boundary section, and a justification for the proposed service area modification. 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.Filing of the petition with the board, and service to other parties, shall be in accordance with 199—Chapter 14.All parties shall file an answer which complies with 199—subrule 7.5(1). 20.3(10) Certificate of authority. Any electric utility or municipal corporation requesting a service territory modification pursuant to subrule 20.3(9) which would result in service to a customer by a utility other than the utility currently serving the customer must also petition the board for a certificate of authority under Iowa Code section 476.23. The electric utility or municipal corporation shall pay the party currently serving the customer a reasonable price for the facilities serving the customer. 20.3(11) Maps. a. Each utility shall maintain a current map or set of maps showing the physical location of electric lines, stations, and electric transmission facilities for its service areas. The maps shall include the exact location of the following: (1) Generating stations with capacity designation. (2) Purchased power supply points with maximum contracted capacity designation. (3) Purchased power metering points if located at other than power delivery points. (4) Transmission lines with size and type of conductor designation and operating voltage designation. (5) Transmission-to-transmission voltage transformation substations with transformer voltage and capacity designation. (6) Transmission-to-distribution voltage transformation substations with transformer voltage and capacity designation. (7) Distribution lines with size and type of conductor designation, phase designation and voltage designation. (8) All points at which transmission, distribution or secondary lines of the utility cross Iowa state boundaries. (9) All current information required in Iowa Code section 476.24(1). (10) All county boundaries and county names. (11) Natural and artificial lakes which cover more than 50 acres and all rivers. (12) Any additional information required by the board. b. All maps, except those deemed confidential by the board, shall be available for examination at the utility’s designated offices during the utility’s regular office hours. The maps shall be drawn with clean, uniform lines to a scale of one inch per mile. A large scale shall be used where it is necessary to clarify areas where there is a heavy concentration of facilities. All cartographic details shall be clean cut, and the background shall contain little or no coloration or shading. 20.3(12) Prepayment meters. Prepayment meters shall not be geared or set so as to result in the charge of a rate or amount higher than would be paid if a standard type meter were used, except under tariffs approved by the board. 20.3(13) Plant additions, electrical line extensions and service lines. a. Definitions. The following definitions shall apply to the terms used in this subrule:
"Advance for construction," as used in this subrule, means cash payments or equivalent surety made to the utility by an applicant for an extensive plant addition or an electrical line extension, portions of which may be refunded depending on the attachment of any subsequent service line made to the extensive plant addition or electrical line extension. Cash payments or equivalent surety shall include a grossed-up amount for the income tax effect of such revenue. The amount of tax shall be reduced by the present value of the tax benefits to be obtained by depreciating the property in determining tax liability.
"Agreed-upon attachment period," as used in this subrule, means a period of not less than 30 days nor more than one year mutually agreed upon by the utility and the applicant within which the customer will attach. If no time period is mutually agreed upon, the agreed-upon attachment period shall be deemed to be 30 days.
"Contribution in aid of construction," as used in this subrule, means a nonrefundable cash payment grossed-up for the income tax effect of such revenue covering the costs of a service line that are in excess of costs paid by the utility. The amount of tax shall be reduced by the present value of the tax benefits to be obtained by depreciating the property in determining the tax liability.
"Electrical line extensions" means distribution line extensions and secondary line extensions as defined in subrule 20.1(3), except for service lines as defined in this subrule.
"Equivalent overhead transformer cost," as used in this subrule, is that transformer capitalized cost, or fraction thereof, that would be required for similarly situated customers served by a pole-mounted or platform-mounted transformer(s). For each overhead service, it shall be the capitalized cost of the transformer(s) divided by the number of customers served by that transformer(s). For each underground service, it shall be the capitalized cost of an overhead transformer(s) with the same voltage and volt-ampere rating divided by the number of customers served by that transformer(s).
"Estimated annual revenues," as used in this subrule, shall be calculated based upon the following factors, including, but not limited to: The size of the facility to be used by the customer, the size and type of equipment to be used by the customer, the average annual amount of service required by the equipment, and the average number of hours per day and days per year the equipment will be in use.
"Estimated base revenues," as used in this subrule, shall be calculated by subtracting the fuel expense costs as described in the uniform system of accounts as adopted by the board and energy efficiency charges from the estimated annual revenues.
"Estimated construction costs," as used in this subrule, shall be calculated using average current costs in accordance with good engineering practices and upon the following factors: amount of service required or desired by the customer requesting the electrical line extension or service line; size, location, and characteristics of the electrical line extension or service line, including appurtenances, except equivalent overhead transformer cost; and whether the ground is frozen or whether other adverse conditions exist. In no event shall estimated construction costs include costs associated with facilities built for the convenience of the utility. The customer shall be charged actual permit fees in addition to estimated construction costs. Permit fees are to be paid regardless of whether the customer is required to pay an advance for construction or a nonrefundable contribution in aid of construction, and the cost of any permit fee is not refundable.
"Plant addition," as used in this subrule, means any additional plant required to be constructed to provide service to a customer other than an electrical line extension or service line.
"Point of attachment" is that point of first physical attachment of the utilities’ service drop (overhead) or service lateral (underground) conductors to the customer’s service entrance conductors. For overhead services it shall be the point of tap or splice to the service entrance conductors. For underground services it shall be the point of tap or splice to the service entrance conductors in a terminal box or meter or other enclosure with adequate space inside or outside the building wall. If there is no terminal box, meter, or other enclosure with adequate space, it shall be the point of entrance into the building.
"Service line," as used in this subrule, means any secondary line extension, as defined in subrule 20.1(3), on private property serving a single customer or point of attachment of electric service.
"Similarly situated customer," as used in this subrule, means a customer whose annual consumption or service requirements, as defined by estimated annual revenue, are approximately the same as the annual consumption or service requirements of other customers.
"Utility," as used in this subrule, means a rate-regulated utility.b. Plant additions. The utility shall provide all electric plant at its cost and expense without requiring an advance for construction from customers or developers except in those unusual circumstances where extensive plant additions are required before the customer can be served. A written contract between the utility and the customer which requires an advance for construction by the customer to make plant additions shall be available for board inspection. c. Electrical line extensions. Where the customer will attach to the electrical line extension within the agreed-upon attachment period after completion of the electrical line extension, the following shall apply: (1) The utility shall finance and make the electrical line extension for a customer without requiring an advance for construction if the estimated construction costs to provide an electrical line extension are less than or equal to three times estimated base revenue calculated on the basis of similarly situated customers. The utility may use a feasibility model, rather than three times estimated base revenue, to determine what, if any, advance for construction is required by the customer. The utility shall file a summary explaining the inputs into the feasibility model and a description of the model as part of the utility’s tariff. Whether or not the construction of the electrical line extension would otherwise require a payment from the customer, the utility shall charge the customer for actual permit fees, and the permit fees are not refundable. (2) If the estimated construction cost to provide an electrical line extension is greater than three times estimated base revenue calculated on the basis of similarly situated customers, the applicant for the electrical line extension shall contract with the utility and make, no more than 30 days prior to commencement of construction, an advance for construction equal to the estimated construction cost less three times estimated base revenue to be produced by the customer. The utility may use a feasibility model to determine whether an advance for construction is required. The utility shall file a summary explaining the inputs into the feasibility model and a description of the model as part of the utility’s tariff. A written contract between the utility and the customer shall be available for board inspection upon request. Whether or not the construction of the electrical line extension would otherwise require a payment from the customer, the utility shall charge the customer for actual permit fees, and the permit fees are not refundable. (3) Where the customer will not attach within the agreed-upon attachment period after completion of the electrical line extension, the applicant for the electrical line extension shall contract with the utility and make, no more than 30 days prior to the commencement of construction, an advance for construction equal to the estimated construction cost. The utility may use a feasibility model to determine the amount of the advance for construction. The utility shall file a summary explaining the inputs into the feasibility model and a description of the model as part of the utility’s tariff. A written contract between the utility and the customer shall be available for board inspection upon request. Whether or not the construction of the electrical line extension would otherwise require a payment from the customer, the utility shall charge the customer for actual permit fees, and the permit fees are not refundable. (4) Advances for construction may be paid by cash or equivalent surety and shall be refundable for ten years. The customer has the option of providing an advance for construction by cash or equivalent surety unless the utility determines that the customer has failed to comply with the conditions of a surety in the past. (5) Refunds. When the customer is required to make an advance for construction, the utility shall refund to the depositor for a period of ten years from the date of the original advance a pro-rata share for each service line attached to the electrical line extension. The pro-rata refund shall be computed in the following manner:
- If the combined total of three times estimated base revenue, or the amount allowed by the feasibility model, for the electrical line extension and each service line attached to the electrical line extension exceeds the total estimated construction cost to provide the electrical line extension, the entire amount of the advance for construction provided shall be refunded.
- If the combined total of three times estimated base revenue, or the amount allowed by the feasibility model, for the electrical line extension and each service line attached to the electrical line extension is less than the total estimated construction cost to provide the electrical line extension, the amount to be refunded shall equal three times estimated base revenue, or the amount allowed by the feasibility model, when a service line is attached to the electrical line extension.
- In no event shall the total amount to be refunded exceed the amount of the advance for construction. Any amounts subject to refund shall be paid by the utility without interest. At the expiration of the above-described ten-year period, the advance for construction record shall be closed and the remaining balance shall be credited to the respective plant account.
- For customers who received a disconnection notice or who have been disconnected less than 120 days and are not in default of a payment agreement, the utility shall offer an agreement with at least 12 even monthly payments. For customers who have been disconnected more than 120 days and are not in default of a payment agreement, the utility shall offer an agreement with at least 6 even monthly payments. The utility shall inform customers they may pay off the delinquency early without incurring any prepayment penalties.
- The agreement shall also include a provision for payment of the current account.
- The utility may also require the customer to enter into a budget billing plan to pay the current bill.
- When the customer makes the agreement in person, a signed copy of the agreement shall be provided to the customer.
- The utility may offer the customer the option of making the agreement over the telephone or through electronic transmission.
- When the customer makes the agreement over the telephone or through electronic transmission, the utility shall provide to the customer a written document reflecting the terms and conditions of the agreement within three days of the date the parties entered into the oral agreement or electronic agreement.
- The document will be considered provided to the customer when addressed to the customer’s last-known address and deposited in the U.S. mail with postage paid. If delivery is by other than U.S. mail, the document shall be considered provided to the customer when delivered to the last-known address of the person responsible for payment for the service.
- The document shall state that unless the customer notifies the utility otherwise within ten days from the date the document is provided, it will be deemed that the customer accepts the terms as stated in the written document. The document stating the terms and conditions of the agreement shall include the address and a toll-free or collect telephone number where a qualified representative can be reached.
- Once the first payment required by the agreement is made by the customer or on behalf of the customer, the oral or electronic agreement is deemed accepted by the customer.
- Each customer entering into a first payment agreement shall be granted at least one late payment that is four days or less beyond the due date for payment, and the first payment agreement shall remain in effect.
- The initial payment is due on the due date for the next regular bill.
- To show the actual amount of sales of energy by month for which an adjustment was utilized, and
- To support the energy cost adjustment balance utilized in the monthly energy adjustment clause filings.
- To show the actual amount of sales of energy by month for which an adjustment was utilized, and
- To support the energy cost adjustment balance utilized in the monthly energy adjustment clause filings.
"Auction allowances" are allowances acquired or sold through EPA’s annual allowance auction.
"Boot" means something acquired or forfeited to equalize a trade.
"Direct sale allowances" are allowances purchased from the EPA in its annual direct sale.
"Fair market value" is the amount at which an allowance could reasonably be sold in a transaction between a willing buyer and a willing seller other than in a forced or liquidation sale.
"Historical cost" is the amount of cash or its equivalent paid to acquire an asset, including any direct acquisition expenses. Any commissions paid to brokers shall be considered a direct acquisition expense.
"Original cost" is the historical cost of an asset to the person first devoting the asset to public service.
"Statutory allowances" are allowances allocated by the EPA at no cost to affected units under the Clean Air Act either through annual allocations as a matter of statutory right and those for which a utility may qualify by using certain compliance options or effective use of conservation and renewables.20.17(3) Valuing allowances for ratemaking purposes. a. Statutory allowances. Valued at zero cost to electric utility. b. Direct sale allowances. Valued at historical cost. c. Auction allowances. Valued at historical cost. d. Purchased allowances. Valued at historical cost. 20.17(4) Valuing allowance inventory accounts. Allowance inventory accounts shall be valued at the weighted average cost of all allowances eligible for use during that year. 20.17(5) Valuing allowances acquired as part of a package. Allowances acquired as part of a package with equipment, fuel, or electricity shall be valued at their fair market value at the time the allowances were acquired. 20.17(6) Valuing allowances acquired through exchanges. a. Exchanges without boot. Electric utilities shall value allowances received in exchanges based on the recorded inventory value of the allowances relinquished. b. Exchanges with boot. Electric utilities shall value allowances as the sum of the inventory cost of the allowances given up and the monetary consideration paid in boot for the newly acquired allowances. In determining the historical cost of allowances received, a gain (or loss) shall be recorded to the extent that the amount of boot received exceeds a proportionate share of the recorded weighted average inventory cost of the allowance surrendered. The proportionate share shall be based upon the ratio of the monetary consideration received (i.e., boot) to the total consideration received (monetary consideration plus the fair market value of the allowances received). The historical cost of the allowances received shall be equal to the amount derived by subtracting the difference between the boot received and the gain from the old inventory cost. 20.17(7) Valuing allowances transferred among affiliates. a. Allowances transferred from a utility to a parent or unregulated subsidiary. Allowances shall be transferred at the higher of historical cost or fair market value. b. Allowances transferred from an unregulated subsidiary or parent to a utility. Allowances shall be transferred at the lesser of original cost or fair market value. c. Allowances transferred from a utility to an affiliated utility. Allowances shall be transferred at fair market value. 20.17(8) Expense recognition and recovery of allowance costs. a. Expense recognition. Electric utilities shall charge allowances (including fractional amounts) to expense in the month in which related emissions occur. b. Expense recovery. The expense associated with allowances used for compliance shall be passed through the energy adjustment as specified in rule 199—20.9(476). The expense associated with allowances used for compliance shall include expenses associated with vintage trades and emission for emission trades. c. Allowance inventory shortage. If a utility emits more emissions in a month than it has allowances in inventory, the utility shall pass the estimated cost of acquiring the needed allowances through the energy adjustment. When the needed allowances are acquired, any difference between the estimated and actual cost of the allowances shall be passed through the energy adjustment as specified in rule 199—20.9(476). 20.17(9) Gains/losses from allowance transactions. The gains and losses, including net gains and losses, from allowance transactions shall be passed through the energy adjustment as specified in rule 199—20.9(476). Allowance transactions shall include vintage trades and emission for emission trades. 20.17(10) Allowance futures or option contracts. a. Price hedging. Electric utilities shall defer the costs or benefits from hedging transactions and include such amounts in inventory values when the related allowances are acquired, sold, or otherwise disposed of. Where the costs or benefits of hedging transactions are not identifiable with specific allowances, the amounts shall be included in inventory values when the futures contract is closed. b. Speculation. Allowance transactions entered into for the purpose of speculation shall not affect allowance inventory pricing. 20.17(11) Working capital reserve of allowances. A working capital reserve of allowances shall be established in each utility’s rate case proceeding based on the probability of forced outages, fuel quality variability, variability in load growth, nuclear exposure, the price and availability of allowances on the national market, and any other factors that the board deems appropriate. The working capital reserve will earn at the utility’s authorized rate of return. 20.17(12) Allowances banked for future use. Allowances banked for future use shall be considered plant held for future use in utility rate proceedings if a definitive plan and schedule for use of the allowances is deemed adequate by the board. 20.17(13) Prudence of allowance transactions. The prudence of allowance transactions shall be determined by the board in the periodic electric energy supply and cost review. The prudency review of allowance transactions and accompanying compliance plans shall be based on information available at the time the options or plans were developed. Costs recovered from ratepayers through the energy adjustment that are deemed imprudent by the board shall be refunded with interest to ratepayers through the energy adjustment as specified in rule 199—20.9(476).Related ARC(s): 4171C19920.18(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 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. 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. 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. 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.CAIDI=Sum of All Customer Interruption DurationsTotal 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:
- 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;
- Interruptions due to nonpayment of a bill;
- Interruptions due to tampering with service equipment;
- Interruptions due to denied access to service equipment located on the affected customer’s private property;
- Interruptions due to hazardous conditions located on the affected customer’s private property;
- Interruptions due to a request by the affected customer;
- 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;
- 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" 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 event" 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" 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" 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, 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:
- Wind speed exceeds 90 mph for the affected area, or
- One-half inch of ice is present and wind speed exceeds 40 mph for the affected area, or
- 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
- 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.MAIFI=Total Number of Customer Momentary InterruptionsTotal Number of CustomersServed
"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.SAIDI=Sum of All Customer Interruption DurationsTotal Number of Customers Served
"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.SAIFI=Total Number of Customer InterruptionsTotal Number of Customers Served
"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:
- State jurisdiction;
- Operating area (if any);
- Number of interruptions in reporting period; and
- Number of hours of interruptions in reporting period.
- Starting date and time the utility became aware of the interruption;
- Duration of the interruption;
- Date and time service was restored;
- Number of customers affected;
- Description of the cause of the interruption;
- Operating areas affected;
- Circuit number(s) of the distribution circuit(s) affected;
- Service account number or other unique identifier of each customer affected;
- Address of each affected customer location;
- Weather conditions at time of interruption;
- System component(s) involved (e.g., transmission line, substation, overhead primary main, underground primary main, transformer); and
- Whether the interruption was planned or unplanned.
- The minimum interruption cause code set should include: animals, lightning, major event, scheduled, trees, overload, error, supply, equipment, other, unknown, and earthquake.
- The minimum interruption weather code set should include: wind, lightning, heat, ice/snow, rain, clear day, and tornado/hurricane.
- The minimum interruption isolating device set should include: breaker, recloser, fuse, sectionalizer, switch, and elbow.
- The minimum interruption equipment failed code set should include: cable, transformer, conductor, splice, lightning arrester, switches, cross arm, pole, insulator, connector, other, and unknown.
- Utilities may augment the code sets listed above to enhance tracking.
- All Iowa customers, excluding major events.
- All Iowa customers, including major events.
- All Iowa customers, excluding major events.
- All Iowa customers, including major events.
- 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.
- 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.
- 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.
- 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.
- 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.