65-407 MAINE PUBLIC UTILITIES COMMISSION

1. Chapter 320: ELECTRIC TRANSMISSION AND DISTRIBUTION UTILITY SERVICE STANDARDS

SUMMARY: This Chapter establishes service standards and service quality metrics and reporting requirements for electric transmission and distribution utilities.

TABLE OF CONTENTS

§ 1. SCOPE AND PURPOSE 2

§ 2. DEFINITIONS 2

§ 3. GENERAL PROVISIONS 4

§ 4. QUALITY OF SERVICE 5

§ 5. SERVICE INTERRUPTIONS 8

§ 6. RELIABILITY METRICS……...……………………………………………………………… 8

§ 7. CUSTOMER SERVICE METRICS……………………………………………..…………….. 9

§ 8. BILLING PERFORMANCE METRICS……………………………………………...…....... 10

§ 9. CUSTOMER SATISFACTION METRIC SURVEY…..……………………………………. 11

§ 10. REPORTING ON METRICS…………………………………………………………….…… 11

§ 11. METERING REQUIREMENTS, STANDARDS,

AND TESTING PROTOCOLS 12

§ 12. INDEPENDENT AUDITS OF METERING AND BILLING SYSTEMS 13

§ 13. WAIVER OR EXEMPTION 13

§ 1. SCOPE AND PURPOSE

A. Scope

1. Unless otherwise specified, this Chapter applies to all Transmission and Distribution Utilities.

B. Purpose

1. This Chapter establishes system standards and associated protocols for record keeping and reporting requirements for Transmission and Distribution Utilities. It also establishes for the investor-owned utilities metrics and reporting requirements for system reliability, Call answering, billing and customer satisfaction.

§ 2. DEFINITIONS

1. The following words and terms, when used in this Chapter, shall have the following meanings, unless the context clearly indicates otherwise.
   1. A. “Annual Report” means the final cumulative quarterly report each Investor-Owned T&D Utility is required to file under this Chapter on an annual basis to report metrics information.
      1. B. “Applicable Codes, Standards and Requirements” means any codes standards or requirements identified by the American National Standards Institute (ANSI), Institute of Electrical and Electronics Engineers (IEEE), Independent System Operator – New England (ISO-NE), National Electric Safety Code (NESC), North American Electric Reliability Corporation (NERC), Northern Maine Independent System Administrator (NMISA) or Northeast Power Coordinating Council, Inc. (NPCC). The version that applies to a device will be the version in effect at the time the device is initially put into service.
      2. C. “Call” means a telephone Call received on the utility’s customer service line as specified on customer bills. Call time begins when a Customer opts to speak to a live person and ends when the Call is answered by a live person.
      3. D. “Case Management System” or “CMS” means the Commission’s online electronic filing system.

E. "Commission" means the Public Utilities Commission of the State of Maine.

1. F. “Consumer-Owned T&D Utility” means any transmission and distribution utility wholly owned by its consumers, including, but not limited to:
   1. 1. The transmission and distribution portion of a rural electrification cooperative organized under chapter 37 of Title 35-A;
      1. 2. The transmission and distribution portion of an electrification cooperative organized on a cooperative plan under the laws of the State;
         1. 3. A municipal or quasi-municipal transmission and distribution utility;
         2. 4. The transmission and distribution portion of a municipal or quasi-municipal entity providing generation and other services; and
         3. 5. A transmission and distribution utility wholly owned by a municipality.
      2. G. “Customer” means a person or entity that receives service from a T&D Utility.
      3. H. “Customer Average Interruption Duration Index” or “CAIDI” is the average time required to restore service to the average customer per Sustained Interruption. It is measured in minutes or hours of interruption.

CAIDI = ∑ customer Sustained Interruption durations

Total number of customer Sustained Interruptions

1. I. “Flicker” means noticeable illuminations changes from lighting equipment caused by fluctuations in power demands.
   1. J. “Harmonics” means, a sinusoidal component of the 60 Hertz fundamental wave having a frequency that is an integral multiple of the fundamental frequency.
      1. K. “IEEE 2.5 Beta Method” is used for identifying outlying service performance, usually caused by major storms, when calculating service quality metrics. The IEEE 2.5 Beta Method identifies “major event days,” which is a day in which daily SAIDI exceeds a threshold value T_med. These “major event days” are then removed from the calculation of a particular service quality metric.
      2. L. “Investor-Owned T&D Utility” means a transmission and distribution utility that is not a Consumer-Owned T&D Utility.
      3. M. “IVR” means Interactive Voice Response telephone answering system.
      4. N. “Major Event Days” means a day in which the daily system SAIDI exceeds a threshold value that is determined by using the IEEE 2.5 beta method.
      5. O. “Major Outage Event” means a disruption of utility service to more than 500 customers or 1% of a utility's customers, whichever is greater, for a period of longer than 30 minutes.
      6. P. “Meter” means a device that measures the amount of energy consumption or real and reactive demand by a Customer from a T&D Utility.
      7. Q. “Momentary Interruption” means the brief loss of power delivery to one or more Customers caused by the opening and closing operation of an interrupting device. A Momentary Interruption does not exceed 5 minutes.
      8. R. “New Service Build (simple service only)” means a field service that involves running a section of overhead secondary line, connecting to a designated point on the customer’s premises, inspecting the electrical service, installing and activating a meter, and, if necessary, installing a transformer. It does not involve pole installation or other pole work. The calculation of target days (business days) for this metric begins when the Investor-Owned T&D Utility’s planner orders the project to be released to the Investor-Owned T&D Utility’s line department for completion.
      9. S. “Nominal System Voltage” means the voltage by which a portion of the system is designed, and to which certain operating characteristics of the system are related. Each Nominal System Voltage pertains to a portion of the system bounded by transformers or utilization equipment.
      10. T. “Sustained Interruption” means any service interruption that lasts longer than 5 minutes.
      11. U. “System Average Interruption Duration Index or “SAIDI” is the average time that customers are interrupted. It is measured in minutes or hours of interruption.

          SAIDI = ∑ Customer Sustained Interruption durations

          Total number of customers served

      12. V. “System Average Interruption Frequency Index” or “SAIFI” is the average frequency of Sustained Interruptions per customer over a predefined area.

          SAIFI = Total number of customer Sustained Interruptions

          Total number of customers served

      13. W. “Service Voltage” means the voltage at the point where the electrical system of the T&D Utility and electrical system of the Customer are connected.
      14. X. “Temporary to Permanent Service (no line appointment needed)” means a field service that involves converting a temporary electrical service, typically used for construction, into a permanent service. This type of field service involves running a section of overhead secondary line to the customer’s permanent service point and moving the meter from the temporary service point to the permanent service point. The calculation of target days (business days) for this metric begins when the Investor-Owned T&D Utility’s planner orders the project to be released to the Investor-Owned T&D Utility’s line department for completion.
      15. Y. “Terms and Conditions” are the provisions filed by the public utility with the Commission which show the basis on which various utility services will be provided to Customers, or which in any manner affect the rates charged for any service. 35-A M.R.S.A. § 304 requires that public utility schedules which were formerly designated as “rules” shall be designated as “terms and conditions”.
      16. Z. "Transmission and Distribution Utility" or “T&D Utility” means a person, its lessees, trustees, receivers or trustees appointed by a court, owning, controlling, operating, or managing electric transmission and/or distribution plant for compensation within the State.

§ 3. GENERAL PROVISIONS

1. A. Each T&D Utility must construct, maintain, and operate its T&D system such that it provides safe and adequate T&D service to its Customers.
   1. B. All new construction, reconstruction, maintenance, design, and operation of T&D Systems must comply with the provisions of this Chapter and with all Applicable Codes, Standards, and Requirements.
      1. C. Each Investor-Owned T&D Utility must collect all information required by this Chapter that is necessary to comply with Sections 5, 6, 7, and 8.
      2. D. Each T&D Utility must maintain Terms and Conditions to implement the provisions of this Chapter. The Terms and Conditions must be approved by the Commission and must be periodically reviewed and modified or updated as necessary by each T&D Utility to conform to any changes or updates to, or replacements of, the applicable standards and requirements set forth in this Chapter, or to any other Applicable Codes, Standards, and Requirements. Modifications or updates to the Terms and Conditions must be approved by the Commission.
      3. E. Unless otherwise indicated in this Chapter, T&D Utilities must keep all records required by this Chapter for a period of at least ten years. All such records must be available to the Commission upon request.

§ 4. QUALITY OF SERVICE

A. Frequency

1. Each T&D Utility must design and operate its T&D system such that alternating current service is supplied at 60 cycles per second (Hertz or Hz) under normal, steady state conditions and may vary only in accordance with Applicable Codes, Standards, and Requirements. The system must operate within a +/-0.5 Hertz limit.

B. Voltage

1. Nominal System and Service Voltages

1. Each T&D Utility must establish and maintain Nominal System and Service Voltages as may be required by the design of its T&D System and the service to be provided to its Customers. The Nominal System and Service Voltages must conform with the standard nominal system voltages established by ANSI C84.1.
2. 2. Voltage Variation; Limits
   1. a. Each T&D Utility must maintain and operate its system to conform to the voltage variation ranges established by ANSI C84.1 for Voltage Range A and Voltage Range B. Figure IV.B.2.a and Figure IV.B.2.b below set forth the voltage variation limit requirements specified by the current version of ANSI C84.1 (ANSI C84.1-2016), Range A and Range B.
      1. b. T&D Systems must be designed, maintained, and operated so that Service Voltages will generally be within the Range A limits. Infrequent and limited periods during which Service Voltages are outside of the Range A limits but are within the Range B limits are acceptable. When Service Voltages occur that are outside of Range B, T&D Utilities must take prompt corrective action to restore the Service Voltages to acceptable levels.

Figure IV.B.2.a (Range A)

Figure IV.B.2.b (Range B)

3. Voltage Testing and Records

1. Each T&D Utility must sufficiently test voltage levels within its service territory to assess and ensure compliance with voltage requirements set forth in this Chapter. The voltage testing protocols must be specified in the T&D Utility’s Terms and Conditions, subject to Commission review and approval. Test results must be maintained and made accessible in accordance with Subsection 3(D) of this Chapter.

4. Harmonics

1. Each T&D Utility must maintain and operate its system in a manner consistent with the IEEE 519 Standard: Recommended Practice and Requirements for Harmonic Control in Electric Power Systems. In accordance with the IEEE 519 recommendations, current distortion limits are determined by the short-circuit ratio, or the ratio of short-circuit current at the point of common coupling (PCC) to the maximum load or demand current.
2. 5. Flicker
   1. T&D Utilities must limit the frequency and magnitude of Flicker events in accordance with IEEE Recommended Practice 1453.

§ 5. SERVICE INTERRUPTIONS

A. General

1. In the event of a Sustained Interruption, each T&D Utility must employ reasonable utility practices to restore service in a timely manner, consistent with appropriate consideration of safety and costs.

B. Sustained Interruption/Outage Reporting

1. In the event of a Sustained Interruption affecting more than 500 customers or 1% of a T&D Utility’s customers, whichever is greater, the T&D Utility must provide immediate notification to the Commission. The notification must include the date and time of the Sustained Interruption; the number of customers affected in each service center or county, and town; the cause of the Sustained Interruption; and any other information descriptive of or relevant to the event. The T&D Utility must provide periodic updates no less frequently than daily for the duration of the Sustained Interruption. This reporting requirement does not apply to Momentary Interruptions.
   1. C. Major Outage Event Response
      1. For each Major Outage Event, each Investor-Owned T&D Utility must calculate the percentage of customers that experience one or more Sustained Interruptions in each hour of the event. The Investor-Owned T&D Utility must quarterly provide to the Commission a graph for each Major Outage Event showing the number of customers experiencing one or more Sustained Interruptions for every hour of the event. The Commission may ask utilities to provide reports that support the reasonableness of its restoration response for Major Outage Events.

   § 6. RELIABILITY METRICS

   1. A. Each Investor-Owned T&D Utility must collect and maintain the following Sustained Interruption and outage metrics information:
      1. a. Monthly and annual CAIDI.
         1. b. Monthly and annual SAIFI
         2. c. Monthly and annual SAIDI.
         3. d. For each service area, on a monthly and annual basis a classification of Sustained Interruptions by the identified cause. Information in this Subsection (d) shall not be included in the Subsection 10(B) customer report cards.
      2. B. The Commission will set individual benchmarks for SAIFI and CAIDI metrics for each Investor-Owned T&D Utility through Commission order that may be revised from time to time in accordance with Title 35-A. The benchmarks will be based on the historic performance of each utility, or otherwise at levels that reflect reasonable service quality. The Commission may, by Commission order (1) direct the T&D Utility to take corrective actions if benchmarks are not met, or, (2) impose financial penalties established by the order.
      3. C. The CAIDI, SAIFI, and SAIDI metrics will be calculated and reported with and without “major event days.” The IEEE 2.5 Beta Method will be used to determine “major event days.”

§ 7. CUSTOMER SERVICE METRICS

A. Utility Call Response Metrics

1. 1. Each Investor-Owned T&D Utility must collect and maintain the following annual Call answering metrics information for the purpose of this metric. For the purpose of this Chapter a “live person” is someone working for or on behalf of the Investor-Owned T&D Utility who is qualified to assist the Customer in the subject area of the metric.
   1. a. Speed of Answer for Calls to Business Office. The formula for this metric is:
      1. Number of Calls answered ≤30 seconds

         Total number of Calls answered by a live person

         1. 2. The benchmark for each metric in this Subsection is 80% of Calls answered by a live person in thirty (30) seconds or less. Compliance with the benchmark for these metrics must be calculated excluding major event days.

B. Call Abandonment Rate

1. 1. Each Investor-Owned T&D Utility must collect and maintain the following annual Call abandonment metrics information for the purpose of this metric. A Call is considered “abandoned” if the caller hangs up after the Call is received by the utility’s IVR system (or other automated Call answering system) and after the Customer makes a choice to speak with a live person. The “Call abandonment rate” is calculated by the following formula:
   1. Number of abandoned Calls
      1. Total number of business Calls received
         1. 2. The benchmark for this metric is 7% and must be calculated excluding major event days.

C. Blocked Call Rate

1. 1. Each Investor-Owned T&D Utility must collect and maintain the following annual blocked Call metrics information for the purpose of this metric. A Call is considered “blocked” if the caller receives a busy signal, automated message asking to Call back later, or the Call is terminated by the system prior to the Call reaching the utility’s IVR (or other automatic call distribution system). A busy signal condition is only recognized under this Subsection if all phone line trunks into the utility’s telephone phone system are being utilized. The “blocked Call rate” is calculated by the following formula:
   1. Number of blocked Calls
      1. Total number of business Calls received
         1. 2. The benchmark for this metric is 3% and must be calculated excluding major event days.
2. D. Field Services

1. Beginning on the effective date of this Subsection but in any event no earlier than January 1, 2025, each Investor-Owned T&D Utility must track and maintain the days to complete each of the following five field services tasks. Each time the Investor-Owned T&D Utility performs one of the five tasks, the action must be measured as an individual observation and each of the observations must be totaled to evaluate the Investor-Owned T&D Utility’s overall performance regarding the metric.

1. Task Target Days (business days)
   1. Reconnection of Customer at pole 3 days
      1. Temporary to permanent service
         1. (no line appointment needed) 10 days

            New service build (simple service only) 15 days

            Customer requested meter test 12 days

            Customer requested field planner appointment 15 days

            The 15-day period to complete customer requested field planner appointments begins to run from the time the utility determines the customer’s service location is ready for inspection.

            The “field services” metric is calculated using the following formula:

            Number of tasks completed by target date

            Total number of tasks completed

         2. 2. The benchmark for this metric is 85% and must be calculated excluding major event days.

§ 8. BILLING PERFORMANCE METRICS

A. Bill Error

1. 1. Each Investor-Owned T&D Utility must measure the number of erroneous bills. For purposes of this Chapter, a bill is considered erroneous if: (1) it contains an incorrect rate or charge or is issued to the wrong Customer, account or address; (2) it lacks a proper charge, fee, or tax; (3) the total amount due is not correct; or (4) it is not sent to the Customer within ten days of the scheduled monthly billing date for that Customer. Estimated bills are not considered erroneous. The calculation is based on actual bills and not on accounts. The “Bill Error” rate is calculated by the following formula:
   1. Number of erroneous bills
      1. Total number of bills
         1. 2. The benchmark for this metric is 0.4%.

B. Percentage of Bills Based on Estimated Meter Reads

1. 1. Each Investor-Owned T&D Utility must measure the annual number of estimated bills issued. A bill is considered estimated when an actual meter read is not obtained, either through the utility’s AMI system or through a manual read and the utility estimates usage. A utility may exclude from this calculation meter reads that fall on “major event days” to be determined using the IEEE 2.5 Beta method, estimated reads that meet the conditions specified in Chapter 815, Section 8(M), and estimated reads for Customers that have declined to have remote meter reads. This calculation is based on actual bills issued and not on accounts. The “Bills Based on Estimated Meter Reads” rate is calculated by the following formula:
   1. Total number of estimated bills
      1. Total number of bills issued
         1. 2. The benchmark for this metric is measured as a percentage of the utility’s bills based on estimated meter reads over a one-year period. The benchmarks are no more than 1) 1% for utilities using automatic meter reads, or 2) 5% for utilities using manual meter reads.

§ 9. CUSTOMER SATISFACTION METRIC SURVEY

1. Each Investor-Owned T&D Utility annually must contract with a third party not affiliated with the Investor-Owned T&D Utility to randomly survey a statistically valid sample of customers who have contacted the utility with a report, request, inquiry, complaint, or request for work. The purpose of the survey is to assess the level of customer satisfaction with the utility’s response. Surveys will be conducted by email, follow-up cards sent through the U.S. Postal Service, or via a phone Call. The unaffiliated, third-party contractor will process completed surveys and report results. The administrative process and question format for the survey will be established by Commission order. The utility may add more questions to the list of prescribed questions.

§ 10 REPORTING ON METRICS

A. Quarterly and Annual Reports to the Commission

1. Each year, every Investor-Owned T&D Utility must open a new docket in the Commission’s CMS and file quarterly reports not later than 30 days after the close of the quarter and the last quarter report, the Annual Report, no later than January 31.
2. Each quarterly report must provide the cumulative calculations and underlying information for the prior quarter or quarters for that calendar year for each of the metrics listed in Sections 6, 7, and 8. Each quarterly report must provide information on a monthly basis.
3. The Annual Report must contain he cumulative calculations and the underlying information for each of the metrics listed in Sections 6, 7, and 8 for the calendar year provide on a monthly basis.

B. Customer Report Cards

1. Each year each Investor-Owned T&D Utility must, on or before June 1, issue a customer report card to each of its residential customers with information regarding the utility’s performance and rates. The customer report card must include explanations in non-technical, plain language of the individual performance benchmarks described in Sections 6, 7, and 8 including an explanation of how each is measured and providing the utility’s performance score in the previous calendar year with respect to each benchmark. The customer report card must be in substantial conformance with a template to be reviewed and approved by Commission order for each utility. The customer report card must be sent to each customer in either a U.S. Postal Service mailing, or in an email, depending on how the customer is billed. The utility must also post the customer report card on its website.

§ 11. METERING REQUIREMENTS, STANDARDS, AND TESTING PROTOCOLS

1. A. General
   1. All T&D Service provided by a T&D Utility must be measured by Meters owned and maintained by the utility, except where it is impracticable to do so.
      1. Each T&D Utility must keep a complete set of records of its Meters by customer account, including the meter type, unique meter identification code, and date of installation. The records should include all Meter repairs and upgrades, including all physical, hardware, software, or firmware repairs, modifications, upgrades, and updates, as well as all notifications or other relevant information provided by the Meter Manufacturers that could potentially affect meter registration.
2. B. Performance and Accuracy Standards
   1. Each T&D Utility must ensure that its Meters comply with the performance criteria and other applicable standards set forth in ANSI C12.1 (American National Standard for Electric Meters – Code for Electricity Metering).

1. Testing Protocols and Processes

1. Each T&D Utility must conform to the testing protocols and processes set forth in ANSI C12.1 for new and in-service metering devices.
2. 2. Testing Upon Customer Request
   1. a. Each T&D Utility must test the accuracy of a Customer’s Meter upon request of the Customer. The test must be done at no charge to the Customer, provided that the Customer has not requested such a test within the past 12 months, or the Meter has not otherwise been tested within the past 12 months.
      1. b. If a Customer requests a Meter test within 12 months of the date of the most recent test of its Meter, the T&D Utility may charge the Customer for the reasonable cost of the test. The charge must be refunded or credited to the Customer if the Meter does not meet the Performance and Accuracy Standards of this Chapter.
         1. c. A Customer may be present when the T&D Utility conducts the requested test of its Meter or, the Customer may send another person as its representative. The T&D Utility must provide a written report to the Customer that provides the results of the Meter test and must retain a copy of the report for a period of no less than five years.

C. Audits Performed by the T&D Utility

1. The results of any audits evaluating the accuracy or performance of a T&D utility’s billing or metering systems, performed by or for the T&D utility, must be provided to the Commission within 60 days of the completion of the audit.

§ 12. INDEPENDENT AUDITS OF METERING AND BILLING SYSTEMS

1. A. The Commission may administer periodic audits by an independent auditor of the billing and metering systems of Investor-Owned T&D Utilities. The audits must be conducted pursuant to 35-A M.R.S. § 113.
   1. B. The Commission will select the independent auditor pursuant to the applicable rules and processes of the State of Maine Division of Procurement Services, or any successor entity. In selecting an independent auditor, the Commission will ensure that the methodologies to be used by the auditor are sufficiently objective, thorough and rigorous, and that any statistical sampling and analyses will be sufficiently robust to represent the relevant population and range of systems being audited.
      1. C. Each Investor-Owned T&D Utility must conduct an audit once every five years, or as otherwise deemed necessary by the Commission. The Commission may focus the audit on only residential and small commercial customers, or the Commission may include other customer groups in the audit.
      2. D. The Commission will determine the allocation of the cost of the periodic audit between the utility and its ratepayers based on the results of the audit.

§ 13. WAIVER OR EXEMPTION

1. Upon the request of any person subject to the provisions of this Chapter or upon its own motion, the Commission may, for good cause, waive any of the requirements of this Chapter that are not required by statute. The waiver may not be inconsistent with the purpose of this Chapter or Title 35-A. The Commission, the Director of Electric and Natural Gas Industries, the Director of Consumer Assistance and Safety, or the Presiding Officer assigned to a proceeding related to this Chapter may grant the waiver.

BASIS STATEMENT: The factual and policy basis for this Rule is set forth in the Commission’s Order Adopting Rule and Statement of Factual and Policy Basis, Docket No. 2024-00236, issued on December 3, 2024. Copies of this Statement and Order have been filed with this rule at the Office of the Secretary of State. Copies may also be obtained from the Administrative Director, Public Utilities Commission, 18 State House Station, Augusta, Maine, 04333-0018.

STATUTORY AUTHORITY: 35-A M.R.S. §§ 104, 111, 301(1-A), 2305-A, 3104-A, 3106, 3108.

EFFECTIVE DATE: This major substantive rule adoption was approved as to form and legality by the Attorney General on June 12, 2019. It was filed with the Secretary of State on June 14, 2019, and became effective on July 14, 2019 (filing 2019-098).

EFFECTIVE DATE: This routine technical rule adoption was approved as to form and legality by the Attorney General on May 1, 2020. It was filed with the Secretary of State on May 1, 2020, and became effective on May 6, 2020 (filing 2020-113).

EFFECTIVE DATE: This routine technical rule adoption was approved as to form and legality by the Attorney General on August 22, 2022. It was filed with the Secretary of State on August 22, 2022, and became effective on August 27, 2022 (filing 2022-158).

EFFECTIVE DATE: This routine technical rule adoption was approved as to form and legality by the Attorney General on January 7, 2025 and became effective on January 14, 2025 (filing 2025-oo6).

APAO WORD VERSION CONVERSION (IF NEEDED) AND ACCESSIBILITY CHECK: July 18, 2025