Chapter 12. Service Quality and Reliability Standards

Provide in its annual performance reports the reliability information specified in this regulation; and

Demonstrate compliance with the reliability standards.

Except as otherwise provided in §B(2) of this regulation, the data used by a utility to determine annual reliability performance shall be from the immediately preceding calendar year.

The data used by a utility to determine the poorest performing feeders and multiple device activations shall include outage data from the 12-month period ending September 30 of the immediately preceding calendar year.

A utility shall collect and maintain the data necessary to report CAIDI, SAIDI, and SAIFI for its system and each operating district, consisting of all feeders assigned to Maryland under Regulation .03D of this chapter.

For an investor-owned utility, each index shall be calculated and reported in the annual performance report using the following sets of input data:

For cooperatively owned utilities, each index shall be calculated and reported in the annual performance report using the following sets of input data:

The SAIDI in minutes and SAIFI reliability standards for the calendar years noted and thereafter, unless changed by the Commission, are as follows:

Each investor-owned utility's annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus major outage event interruption data and consisting of all feeders assigned to Maryland under Regulation .03D of this chapter.

For the calendar year 2020 and each calendar year thereafter, each investor-owned utility’s annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days and consisting of all feeders assigned to Maryland under Regulation .03D of this chapter.

Each cooperatively owned utility's annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus major outage event interruption data and minus outage data resulting from an outage event occurring on another utility's electric system.

For the calendar year 2020 and each calendar year thereafter, each cooperatively owned utility’s annual SAIDI and SAIFI reliability standard shall be measured against its system-wide annual SAIDI and SAIFI result, including all interruption data minus the Institute of Electrical and Electronics Engineers’ (IEEE) major event days minus outage data resulting from an outage event occurring on another utility’s electric system.

A utility's annual SAIDI result shall be equal to or less than its annual SAIDI reliability standard established in §D(1) of this regulation.

A utility's annual SAIFI result shall be equal to or less than its annual SAIFI reliability standard established in §D(1) of this regulation.

SAIDI and SAIFI Standards after 2015.

A utility shall report in its annual performance report CAIDI, SAIDI, and SAIFI indices for all feeders assigned to Maryland that are identified by the utility as having the poorest feeder reliability.

For each utility, each index shall be calculated and reported in the annual performance report using all interruption data, and all interruption data minus the following exclusions:

For each utility, the feeders with poorest reliability shall be all feeders having circuit reliability performance 250 percent or more above the utility’s System-Wide SAIFI and SAIDI, which shall be calculated in accordance with the exclusions identified in §A(2) of this regulation.

No feeder shall appear in a utility’s list of poorest performing feeders during three consecutive 12-month reporting periods, unless the utility has undertaken reasonable remediation measures to improve the performance of the feeder.

For each feeder not assigned to Maryland that serves more than ten Maryland customers, the utility shall report the feeder in its annual performance report and the feeder’s CAIDI, SAIDI, and SAIFI indices, if the feeder would have been included on the poorest performing feeder list but for the fact that the feeder is not assigned to Maryland.

For each feeder included in §B(1) of this regulation, the utility shall report the number of customers located in Maryland and the number of customers located in a bordering jurisdiction.

For each feeder reported in §B(1) of this regulation, the utility shall implement reasonable remediation measures to improve the performance of the feeder portion serving Maryland customers, which measures shall be described by the utility in its annual performance report. If implementing a remediation plan is not reasonable, the utility shall provide an explanation of its decision in its annual performance plan.

The reliability indices and method for identifying the performance of feeders under this provision shall be consistent with §A(2), (3), and (4) of this regulation.

In the annual performance report in which the feeders are identified as requiring reasonable remediation measures, a brief description of the actions taken or proposed, if any, to improve reliability and the actual or expected completion date of the action; and

In the five subsequent annual performance reports, the performance of the feeder shall be reported with its performance ranking.

All feeders of a utility that serve only Maryland customers are assigned to Maryland.

For a utility that has one or more feeders that serve a Maryland customer and at least one customer in a bordering jurisdiction:

All IEEE major event days;

Dates of all IEEE major event days; and

Number of customers impacted by the IEEE major event day events.

CEMI2, CEMI4, CEMI6, CEMI8, excluding major outage events; and

CEMI2, CEMI4, CEMI6, CEMI8, including major outage events.

MAIFIE excluding major outage events; and

MAIFIE including major outage events.

Based solely upon those calls offered to its customer service representatives:

The average speed of answer, which shall be calculated by dividing the total amount of time callers spend in queue after requesting to speak to a customer service representative through the automated voice response system by the total number of calls handled, including calls handled by the automated voice response system.

First Call Resolution. Each utility shall measure the percentage of customer issues resolved that are reported to the utility in a single interaction with its customer service representatives.

Average Handling Time. Each utility shall measure an average amount of time needed to resolve a customer’s request. This includes any time spent on holds, delays, or follow-up actions necessary to fulfill the customer’s needs.

Vulnerable Individuals Notified Before Storms. Each utility shall measure the percentage of vulnerable individual customers notified in advance of a storm event.

Each standard in this regulation is measured using the 12-month period ending December 31.

For the calendar year in which the regulations become effective, the standards shall be measured from the date the regulations are effective until and including December 31 of that year for reporting purposes only.

It is the intent of the Commission that a utility engage in vegetation management programs that are necessary and appropriate to maintain safety and electric system reliability.

The standards set forth in this regulation shall constitute minimum vegetation management requirements applicable to utilities in the State, and are not intended to supersede or prohibit a utility’s implementation of more aggressive vegetation management standards and practices.

The vegetation management requirements in this chapter apply to the extent not limited by contract rights, property rights, or any controlling law or regulation of any unit of State or local government.

This regulation applies to any electric transmission plant not regulated by the Federal Energy Regulatory Commission.

Each utility shall ensure that vegetation management conducted on its energized plant is performed in accordance with the standards applicable to Maryland Licensed Tree Experts, which are incorporated by reference under COMAR 08.07.07.02.

Each utility’s vegetation management program shall address, at a minimum, all of the following activities:

Each utility using a call center to handle vegetation management calls shall adopt a script or job aid that is specifically catered to vegetation management practices for usage by call center representatives.

Each utility shall perform periodic reviews of its vegetation management complaints with the goal of improving its complaint resolution process, as necessary.

Each utility shall develop its own vegetation management program, which shall be consistent with this regulation. In developing the program, a utility shall conduct its vegetation management and determine the extent and priority of vegetation management to be performed at a particular site based on these factors:

Each utility shall file a copy of its vegetation management program with the Commission within 90 days of the effective date of this regulation. If a utility makes a change in its vegetation management program, the utility shall file a copy of the change with the Commission no later than 30 days prior to implementing the change, unless exigent circumstances warrant implementation without prior notice, in which case the change shall be filed by no later than 30 days after implementation.

Each utility shall adopt standards, to the extent not covered by other existing law, to be used by all persons who perform vegetation management for the utility, whether employees or contractors, for the proper care of trees and other woody plants, including safety practices and line clearance techniques.

The utility shall monitor and document scheduled vegetation management and related activities the utility or its contractor performs. Documentation shall include, but is not limited to:

Each utility shall include a summary of the information required under §C(2) of this regulation about its vegetation management during the preceding calendar year, and shall describe vegetation management planned for the current calendar year, as part of the annual performance report required to be filed with the Commission under Regulation .11 of this chapter. The annual performance report also shall include:

Each utility shall report its own violation of this chapter to the Commission within 60 days of discovery and include its plan for correcting each violation.

Each utility shall make a reasonable attempt to notify an owner or occupant of all properties upon which cyclical, planned vegetation management is to be performed. This requirement will be satisfied if the utility provides notice to affected property owners or occupants at least 7 days, but not more than 120 days, prior to performing cyclical, planned vegetation management activity. Notice shall be provided by direct mailing, door hanger, postcard, personal contact, or a different method if approved by the Commission, but may not be made solely by bill insert. All direct mailings, door hangers, postcards, or any other method approved by the Commission shall include the contact information of a dedicated group for customers to call for further information. Nothing in this regulation prohibits a utility from using more than one of these methods.

Each utility or its contractor shall provide written notice of any cyclical, planned vegetation management activities to a primary contact for each county and municipality affected at least 2 months before commencing the activities unless the county or municipality notifies the utility that written notification is not required.

Each utility shall include on its website general information about upcoming vegetation management planned work and shall include a link or reference to the Maryland Department of Natural Resources’ website for additional information about tree experts and related information.

For all tree removals that have been readily identified on residential properties, each utility shall proactively contact the customer or owner of the property to discuss the removal of the tree prior to performing the work.

Each utility shall provide the option for customers or the owner of the property to have direct communication with a utility vegetation management representative within 7 business days.

Each utility shall conduct an annual public education program to inform its customers, as well as a primary contact for each county and municipality in the utility’s service territory, of the importance of vegetation management, and of the utility’s role and responsibility in managing vegetation near electric lines, poles, and substations.

The public education program required under this section shall be implemented by direct mail, bill inserts, or a different method if approved by the Commission.

Each utility shall post its vegetation management public education materials on its website.

Initially beginning on January 1 of the year immediately following the effective date of this regulation, a utility on a 4-year trim cycle shall within:

Initially beginning on January1 of the year immediately following the effective date of this regulation, a utility on a 5-year trim cycle shall within:

Each utility shall follow the vegetation management performance requirement under §F(1) or (2) of this regulation for each subsequent trim cycle.

Horizontal clearances:

Vertical clearances:

Mature trees may be exempt from the minimum clearance requirements specified above at the utility's reasonable discretion for voltage levels at 34.5 kV and below.

Include the frequency or triggers for performing an inspection;

Identify the electric plant inspections to be performed; and

Identify acceptance criteria for the inspections.

The reliability index information and results required in this chapter, including a table showing the actual values of the reliability indices required in this chapter for each of the preceding 3 calendar years;

Annual year-end and 3-year average performance results as required under Public Utilities Article, §7-213(g)(2)(i) and (ii), Annotated Code of Maryland, including a table showing the actual values for each of the preceding 3 calendar years;

The time periods during which major outage event interruption data and, if a cooperatively owned utility, the outage data resulting from an outage event occurring on another utility's electric system was excluded from the CAIDI, SAIDI, and SAIFI indices, including a brief description of the interruption causes during each time period;

A description of the utility’s reliability objectives, planned actions and projects, and programs for providing reliable electric service;

An assessment of the results and effectiveness of the utility’s reliability objectives, planned actions and projects, programs, and load studies in achieving an acceptable reliability level as required under Public Utilities Article, §7-213(g)(2)(iii), Annotated Code of Maryland. The assessment of the results and effectiveness shall include, to the extent estimated or determined by the utility, the program's, project’s, or planned action’s impact on reliability indices, including CAIDI, SAIDI, and SAIFI and any other reliability index considered. The method for estimating or determining the impact on any reliability index shall be explained;

Current year expenditures, an estimate or budget amount for the following 2 calendar years, if available, current year labor resources hours, and progress measures for each capital and maintenance program designed to support the maintenance of reliable electric service as required under Public Utilities Article, §7-213(g)(2)(iv)(1), Annotated Code of Maryland;

An explanation for any material differences between current year expenditures and cost estimates filed pursuant to §A(6) of this regulation;

The number of outages by outage type as required under Public Utilities Article, §7-213(g)(2)(iv)(2), Annotated Code of Maryland, including planned outage, nonplanned outage minus major outage event, and major outage event;

The number of outages by outage cause required under Public Utilities Article §7-213(g)(2)(iv)(3), Annotated Code of Maryland, including, but not limited to, animals, overhead equipment failure, and underground equipment failure;

The total number of customers that experienced an outage required under Public Utilities Article, §7-213(g)(2)(iv)(4), Annotated Code of Maryland;

The total number of customer minutes of outage time required under Public Utilities Article, §7-213(g)(2)(iv)(5), Annotated Code of Maryland;

To the extent practicable, a breakdown, by the number of days each customer was without electric service, of the number of customers that experienced an outage required under Public Utilities Article, §7-213(g)(2)(iv)(6), Annotated Code of Maryland;

Poorest performing feeder information and results required in this chapter; and

Multiple device activation information and results required in this chapter.

The actual operation and maintenance and capital expenditures for the past 3 calendar years for each of the utility's reliability programs, including, but not limited to underground and overhead distribution plant inspection, maintenance and replacement programs, vegetation management, subtransmission inspection and maintenance programs, and distribution substation plant inspection and maintenance programs;

Service restoration requirement information and results required in this chapter;

Downed wire response performance information and results required in this chapter;

Customer communications performance information and results required in this chapter;

The vegetation management information required in this chapter;

Periodic equipment inspection information and results required in this chapter;

For the immediately preceding calendar year, and considering normal conditions only:

Any corrective action plans required under Public Utilities Article, §7-213(e)(1)(iii), Annotated Code of Maryland, or this chapter; and

The number of manhole and conduit events during the preceding year that result in a lid displacement, the date of the event, the location and feeder designation, whether the event involved a feeder, primary or secondary services, and the number of customer outages recorded.

Preparation, training, and drills;

Early warning and storm tracking;

Emergency organization structure;

Activation and mobilization;

Materials management and logistics;

Major outage event restoration priorities, including, but not limited to:

Damage assessment;

Public safety, including wire down response;

Crew deployment;

External communications, including communications with emergency officials, the public, and other persons;

Internal communications;

Communications technology use, including high call volume capability and capacity;

Development of estimated times of restoration and assessment of estimated times of restoration accuracy;

Ramp-down; and

Major outage event performance review.

The total number of Maryland customers served by the utility;

The date and time when the major outage event started;

The date and time when all sustained interruptions in Maryland related to the major outage event were restored;

The total number of Maryland customers who experienced a sustained interruption of service related to the major outage event;

The total number of customer interruption hours experienced by customers reported under §B(4) of this regulation;

The average duration of customer service interruption, expressed in hours, and calculated by dividing the total number of customer interruption hours reported in §B(5) of this regulation by the total number of Maryland customers who experienced an interruption reported in §B(4) of this regulation;

The maximum number of Maryland customers who concurrently experienced a sustained interruption related to the major outage event and the date and time this occurred;

The number of Maryland customers who experienced a sustained interruption recorded at a maximum of 6-hour intervals throughout the major outage event;

Information about requests for outside assistance, including the:

Information about outside assistance received, including the:

Information about electric utility crews working on restoration, including the following:

The following information about communications with customers:

With regard to system damage, the number of each of the following occurring during restoration:

Any issues concerning the availability of materials or equipment that affected restoration progress, including a description of how any unavailability affected restoration, and a description of the emergency measures taken to resolve the issues;

A self-assessment, including lessons learned and future plans to improve service restoration efforts during major outage events;

A description of the manner in which customers were informed of the status of the outages in their geographic area by means of the customer call center or by other means of customer communications;

A description of the manner in which the utility informed elected officials, government officials, and members of the public of the status of the outage and restoration efforts;

A description of the manner in which the utility estimated restoration times;

A description of any areas where the utility did not comply with its major outage event response plan;

The number of customer service interruptions under §B(4) of this regulation and the number of customer service interruption hours under §B(5) of this regulation categorized by outage caused by each one of the following:

For each interruption to normal expected information technology systems used to manage a major outage event, details on deficiencies experienced in these systems including dates, time, and duration of any interruptions to normal expected functionality for the following:

The percentage of total Maryland customers who had service restored in 50 hours pursuant to Regulation .06B of this chapter;

If the company could not safely work due to high wind conditions for the major outage event, an explanation of the company policy and how this impacted restoration;

The percentage of calls that are answered within 30 seconds, the abandoned call percentage rate, and the average speed of answer pursuant to Regulation .08D of this chapter, except measured only for the duration of the major outage event;

The average amount of time customers were put on hold for every hour during the major outage event after the customer selected the option to talk to a call center representative in the electric company’s Interactive Voice Response (IVR) system:

For the duration of the major outage event, the number of customers experiencing multiple sustained interruptions, categorized by the number of multiple sustained interruptions, such as the number of customers experiencing “n” sustained interruptions, where n= 1, 2, 3, etc.;

The downed wire response performance to a government emergency responder guarded downed electric utility wire within 3 hours after notification by a fire department, police department, or 911 emergency dispatcher pursuant to Regulation .07A of this chapter, except measured only for this major outage event;

The number of peak sustained interruptions restored by county and municipal jurisdiction for the duration of the major outage event;

The number of customers sustained interruptions caused by off-right-of-way trees;

All press releases, if any, issued and details on the date, time, location, and company participants in all press conferences held, if any;

The date and time centralized and regional emergency operations centers, district headquarters, and mutual assistance staging areas activated for the major outage event were operational completed;

Electric system infrastructure that was damage assessed and how this damage assessment information was used to establish a Global ETR;

The number of Maryland critical facilities who experienced a sustained interruption recorded at a maximum of 6-hour intervals throughout the major outage event; and

The percentage critical facility sustained interruptions restored within 24 hours and 48 hours of the start of the major outage event.