Official RM 43 Rules

IN THIS ISSUE

General Assembly

Judiciary

Regulations

Errata

Special Documents

General Notices

Volume 39 • Issue 4 • Pages 311—358

Pursuant to State Government Article, §7-206, Annotated Code of Maryland, this issue contains all previously unpublished documents required to be published, and filed on or before February 6, 2012, 5 p.m. Pursuant to State Government Article, §7-206, Annotated Code of Maryland, I hereby certify that this issue contains all documents required to be codified as of February 6, 2012.

Brian Morris Acting Administrator, Division of State Documents

Office of the Secretary of State

Issue Date: February 24, 2012

341

MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012

Proposed Action on Regulations

Title 20

PUBLIC SERVICE

COMMISSION

Subtitle 50 SERVICE SUPPLIED BY

ELECTRIC COMPANIES

Notice of Proposed Action

[12-071-P-I]

The Public Service Commission proposes to:

(1) Amend Regulation .03 under COMAR 20.50.01 General;

(2) Amend Regulations .02 and .04 under COMAR 20.50.02

Engineering;

(3) Amend Regulation .05 and repeal Regulations .06 and .07

under COMAR 20.50.07 Quality of Service; and

(4) Adopt new Regulations .01 — .14 under a new chapter,

COMAR 20.50.12 Service Quality and Reliability Standards.

This action was considered at a scheduled rule-making meeting on

December 8, 9, 12, and 15, 2011, notice of which was given pursuant

to State Government Article, §10-506, Annotated Code of Maryland.

Statement of Purpose

The purpose of this action is to implement service quality and

reliability standards relating to the delivery of electricity to retail

customers by electric companies, to require electric companies to file

annual reports specifying whether the electric company met the

service quality and reliability standards, to require electric companies

to file corrective actions plans if it fails to meet the service quality

and reliability standards, and to otherwise provide for the

enforcement of the established service quality and reliability

standards.

Comparison to Federal Standards

There is no corresponding federal standard to this proposed action.

Estimate of Economic Impact

I. Summary of Economic Impact. The regulations promulgate

service quality and reliability standards that are designed to improve

utility performance. The standards apply to the largest six electric

utilities that operate in Maryland. The standards will have a positive

economic impact in that they result in an overall benefit to

consumers. The costs and benefits are quantified as discussed herein.

Revenue (R+/R-)

II. Types of Economic

Impact.

Expenditure

(E+/E-) Magnitude

A. On issuing agency: NONE

B. On other State

agencies: NONE

C. On local

governments: NONE

Benefit (+)

Cost (-) Magnitude

D. On regulated

industries or trade groups: (-)

$365 million through

year 2015

E. On other industries

or trade groups: NONE

F. Direct and indirect

effects on public: (+)

$1,400 million

through year 2015

III. Assumptions. (Identified by Impact Letter and Number from

Section II.)

D. The regulations require electric utilities to establish a high level

of service quality and reliability performance. The level is established

through the implementation of specific service quality and reliability

standards. The cost estimate provided above is an estimation of

potential costs the six largest utilities may incur to improve service

quality and reliability to a high level as required under current law.

For information concerning citizen participation in the regulation-making process, see inside front cover.

Symbol Key

• Roman type indicates existing text of regulation.

• Italic type indicates proposed new text.

• [Single brackets] indicate text proposed for deletion.

Promulgation of Regulations

An agency wishing to adopt, amend, or repeal regulations must first publish in the Maryland Register a notice of proposed action, a

statement of purpose, a comparison to federal standards, an estimate of economic impact, an economic impact on small businesses, a notice

giving the public an opportunity to comment on the proposal, and the text of the proposed regulations. The opportunity for public comment

must be held open for at least 30 days after the proposal is published in the Maryland Register.

Following publication of the proposal in the Maryland Register, 45 days must pass before the agency may take final action on the

proposal. When final action is taken, the agency must publish a notice in the Maryland Register. Final action takes effect 10 days after the

notice is published, unless the agency specifies a later date. An agency may make changes in the text of a proposal. If the changes are not

substantive, these changes are included in the notice of final action and published in the Maryland Register. If the changes are substantive,

the agency must repropose the regulations, showing the changes that were made to the originally proposed text.

Proposed action on regulations may be withdrawn by the proposing agency any time before final action is taken. When an agency

proposes action on regulations, but does not take final action within 1 year, the proposal is automatically withdrawn by operation of law,

and a notice of withdrawal is published in the Maryland Register.

PROPOSED ACTION ON REGULATIONS

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The estimation includes some costs currently being incurred by

electric utilities to improve reliability performance, as well as

expected costs that may be incurred through 2015. Some of these

costs and cost items may be included in future electric utility rates,

subject to Commission review to ensure expenditures are just and

reasonable. The cost estimation is based on improving each utility‟s

performance relative to its 5-year historical performance average

using calendar years 2006—2010.

F. The benefits are derived from an improvement in reliability

performance by the electric utilities through 2015. The benefits are

based on improving each utility‟s performance relative to its 5-year

historical performance average using calendar years 2006—2010.

The regulations also require an improvement in utility customer call

center performance. The benefit derived from an improvement in call

center performance is unquantifiable.

Economic Impact on Small Businesses

The proposed action has a meaningful economic impact on small

business. An analysis of this economic impact follows.

The benefit estimate is based on the total customer base of the six

largest electric utilities operating in Maryland and not specifically

attributable to small businesses. However, all electric utility

customers will benefits from the improvements in service quality and

reliability performance, including small businesses operating in a

utility‟s service territory. Additionally, when utilities recover costs

associated with complying with service quality and reliability

standards, the costs will be allocated to customer classes, including

customer classes with small businesses. The amount of any potential

increase in utility rates that will be applicable to small businesses is

unquantifiable at this time.

Impact on Individuals with Disabilities

The proposed action has no impact on individuals with disabilities.

Opportunity for Public Comment

Comments may be sent to David J. Collins, Executive Secretary,

Public Service Commission, William Donald Schaefer Tower, 6 St.

Paul Street, Baltimore, Maryland 21202-6806, or call 410-767-8067.

Comments will be accepted through March 26, 2012. A public

hearing has not been scheduled.

Editor‟s Note on Incorporation by Reference

Pursuant to State Government Article, §7-207, Annotated Code of

Maryland, the Guide for Electric Power Distribution Reliability

Indices, IEEE Standard 1366—2003, 4.5 Major event day

classifications has been declared a document generally available to

the public and appropriate for incorporation by reference. For this

reason, it will not be printed in the Maryland Register or the Code of

Maryland Regulations (COMAR). Copies of this document are filed

in special public depositories located throughout the State. A list of

these depositories was published in 39:2 Md. R. 104 (January 27,

2012), and is available online at www.dsd.state.md.us. The document

may also be inspected at the office of the Division of State

Documents, 16 Francis Street, Annapolis, Maryland 21401.

20.50.01 General

Authority: Public Utilities Article, §§2-113, 2-121, 5-101, 5-303, and 7-203,

Annotated Code of Maryland

.03 Definitions.

A. (text unchanged)

B. Terms Defined.

(1) Answer.

(a) ―Answer‖ means rendering assistance to a telephone

caller or accepting information necessary to process a telephone call

by a customer service representative or an automated voice response

system.

(b) ―Answer‖ does not include an acknowledgement that a

telephone caller is waiting on the line.

(1-1) ―Abandoned call‖ means a telephone call in which the

customer has elected to speak to a customer service representative

but the call is terminated before the customer service representative

answers.

[(1)] (1-2) “Bordering jurisdiction” (text unchanged)

(2)—(5) (text unchanged)

(5-1) ―Cultural control practices‖ means control of vegetation

through the establishment of compatible stable plant communities or

the use of crops, pastures, mulching, or other managed landscapes.

[(5-1)] (5-2) — [(5-2)] (5-3) (text unchanged)

(5-4) ―Customers experiencing multiple interruptions

(CEMIn)‖ means the ratio of the total number of customers

experiencing more than ―n‖ sustained interruptions divided by the

total number of customers served.

[(5-3)] (5-5) — [(5-6)] (5-8) (text unchanged)

(6) — (7) (text unchanged)

(7-1) ―Government emergency responder‖ means fire and

police personnel and government employees who:

(a) Are working at the direction of fire, police, or 911

emergency dispatcher personnel to respond to an emergency; or

(b) Have been identified by fire, police, or 911 dispatcher

personnel as responding to an emergency.

(7-2) ―Hazard tree‖ means a structurally unsound tree or tree

limb that could strike poles, substations, or energized overhead

electric plant when it falls.

(7-3) ―Institute of Electrical and Electronics Engineers’ (IEEE)

major event day‖ means a day determined to be a major event day

using the IEEE method of determining excludable data for

calculation of reliability indices under IEEE Std 1366TM – 2003.

(8) (text unchanged)

[(9) “Major event interruption data” means all electric customer

interruption occurrence and duration information collected by the

utility during a time period when:

(a) More than 10 percent of a utility‟s Maryland, or

bordering jurisdiction, customers are without service; and

(b) Restoration of electric service to these customers takes

more than 24 hours.]

[(10)] (9) “Major [storm] outage event” means a weather-

related event during which:

(a) Both:

(i) More than 10 percent or 100,000, whichever is less, of

the electric utility‟s Maryland customers experience a sustained

interruption of electric service; and

[(b)] (ii) Restoration of electric service to any of these

customers takes more than 24 hours; or

(b) The federal, State, or local government declares an

official state of emergency in the utility’s service territory and the

emergency involves interruption of electric service.

(10) ―Major outage event interruption data‖ means all electric

customer interruption occurrence and duration information collected

by the utility during a major outage event.

(10-1) ―Mature tree‖ means a tree, whether or not previously

pruned by the utility, that is well-established with a defined crown

and that is at least 20 feet tall or 6 inches in diameter at breast

height. Mature tree does not include a hazard tree.


(11-1) ―Momentary average interruption frequency index

(MAIFIE)‖ means the ratio of the total number of customer

momentary interruption events divided by the total number of

customers served.



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(12-1) ―Normal conditions‖ means conditions other than a

major outage event.

(13)-(17) (text unchanged)

(17-1) ―Protective devices‖ means substation breakers and

reclosers, line reclosers, line sectionalizing equipment, and line

fuses.


(20) “System average interruption duration index (SAIDI)”

[means the sum of the customer interruption hours divided by the

total number of customers served] has the meaning stated in Public

Utilities Article, §7-213(a)(2), Annotated Code of Maryland.

(21) “System average interruption frequency index (SAIFI)”

[means the sum of the number of customer interruptions divided by

the total number of customers served] has the meaning stated in

Public Utilities Article, §7-213(a)(3), Annotated Code of Maryland.


20.50.02 Engineering

Authority: Public Utilities Article, §§2-113, 2-121, 5-101, and 5-303, Annotated Code of Maryland

.02 Acceptable Standards.

A.—E. (text unchanged)

F. Conformance Test Procedures for Equipment Interconnecting

Distributed Resources with Electric Power Systems, IEEE Standard

1547.1—2005; [and]

G. NEMA Standards Publication TP 1-2002; and

H. Guide for Electric Power Distribution Reliability Indices, IEEE

Standard 1366—2003, 4.5 Major event day classifications.

.04 Electric Plant Operation and Maintenance.

[A.] Each utility shall adopt written operation and maintenance

procedures for its electric plant in order to determine the necessity for

replacement and repair. The frequency of the various procedures shall

be based on the utility‟s experience and accepted good practice. Each

utility shall keep sufficient records to give evidence of compliance

with its operation and maintenance procedures.

B. — E. (proposed for repeal)

20.50.07 Quality of Service

Authority: Public Utilities Article, §§2-121, 5-101, and 5-303 Annotated Code

of Maryland

.05 Interruption of Service.

A. (text unchanged)

B. Report to Commission.

(1) Each utility shall promptly report to the Commission‟s

Engineering Division and Office of External Relations:

(a) The onset of a major [storm] outage event;

(b) — (c) (text unchanged)


C. — F. (text unchanged)

20.50.12 Service Quality and Reliability Standards

Authority: Public Utilities Article, §§7-213, 13-201, and 13-202 Annotated

Code of Maryland

.01 Applicability.

These regulations apply to an electric company with a total number

of 40,000 or more customers served in Maryland.

.02 System-Wide Reliability Standards.

A. Reliability Data. Each utility shall collect and maintain the

data required to:

(1) Provide in its annual performance reports the reliability

information specified in this regulation; and

(2) Demonstrate compliance with the reliability standards.

B. Reliability Reporting Period.

(1) 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.

(2) 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.

C. Reliability Standards — System-Wide Indices.

(1) 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.

(2) For an investor-owned utility, each index shall be

calculated and reported in the annual performance report using the

following sets of input data:

(a) All interruption data; and

(b) All interruption data minus major outage event

interruption data.

(3) For cooperatively owned utilities, each index shall be



(a) All interruption data;


interruption data; and

(c) 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.

D. SAIDI and SAIFI Standards.

(1) The SAIDI and SAIFI reliability standards for calendar

years 2012—2015 and thereafter, unless changed by the Commission,

are as follows:

(a) Baltimore Gas and Electric Company

2012 2013 2014 2015

SAIDI 4.24 3.96 3.69 3.44

SAIFI 1.51 1.47 1.43 1.39

(b) Choptank Electric Cooperative, Inc.

2012 2013 2014 2015

SAIDI 2.99 2.92 2.74 2.58

SAIFI 1.50 1.49 1.44 1.39

(c) Delmarva Power and Light Company

2012 2013 2014 2015

SAIDI 3.25 2.99 2.78 2.62

SAIFI 1.77 1.65 1.55 1.46

(d) Potomac Edison Company

2012 2013 2014 2015

SAIDI 3.28 3.05 2.92 2.79

SAIFI 1.11 1.10 1.09 1.08

(e) Potomac Electric Power Company

2012 2013 2014 2015

SAIDI 3.18 2.82 2.58 2.39

SAIFI 1.95 1.81 1.61 1.49

(f) Southern Maryland Electric Cooperative, Inc.

2012 2013 2014 2015

SAIDI 2.37 2.35 2.33 2.32

SAIFI 1.39 1.38 1.37 1.36


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(2) 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.

(3) 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.

(4) 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.

(5) 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.

(6) Effective Date and Proration.

(a) For the year in which the regulations become effective,

each utility’s SAIDI and SAIFI reliability standard shall be effective

on July 1, or the effective date of this regulation, whichever is later,

and prorated to account for the number of days from the effective

date of this regulation until the end of that calendar year.

(b) The prorating shall be calculated by dividing the SAIDI

and SAIFI reliability standard for the applicable year by the number

of days in the calendar year to determine a daily SAIDI and SAIFI

value.

(c) The daily SAIDI and SAIFI value shall be multiplied by

the number of days remaining in the calendar year starting from the

effective date of these regulations to establish the SAIDI and SAIFI

standard for the year in which this regulation is promulgated.

(d) The utility’s actual SAIDI and SAIFI performance shall

be measured over the same time period specified in §D(6)(c) of this

regulation.

(7) SAIDI and SAIFI Standards after 2015.

(a) For the calendar year 2016 and each calendar year

thereafter, the Commission shall establish SAIDI and SAIFI

reliability standards and any other appropriate reliability

requirements for each utility.

(b) By March 1, 2014 and every 4 years thereafter, unless

otherwise directed by the Commission, each utility:

(i) Shall file proposed annual SAIDI and SAIFI reliability

standards and supporting testimony for its Maryland service

territory. The proposed annual SAIDI and SAIFI reliability standards

shall be for a 4-calendar-year period, at a minimum; and

(ii) May propose any other appropriate reliability

requirement for the Commission’s consideration along with

supporting testimony.

E. If a utility fails to satisfy the standard in §D(4) or (5) of this

regulation, it shall provide a corrective action plan, preferably in its

annual performance report but by no later than April 1.

.03 Poorest Performing Feeder Standard.

A. Poorest Performing Feeder Standard for Feeders Assigned to

Maryland.

(1) A utility shall report in its annual performance report

CAIDI, SAIDI, and SAIFI indices for 3 percent of feeders assigned to

Maryland that are identified by the utility as having the poorest

feeder reliability.

(2) For an investor-owned utility, each index shall be



(a) All interruption data; and


interruption data.

(3) For cooperatively owned utilities, each index shall be



(a) All interruption data;


interruption data; and

(c) 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.

(4) The method used by a utility to identify the feeders with

poorest reliability and the quantitative results derived from the

method shall be stated in the annual performance report and the

method may not be subsequently changed by the utility without

Commission approval.

(5) No feeder ranked in the poorest performing 3 percent of

feeders shall perform in the poorest performing 3 percent of feeders

during either of the two subsequent 12-month reporting periods, after

allowing one 12-month reporting period for the utility to implement

remediation measures, unless the utility has undertaken reasonable

remediation measures to improve the performance of the feeder.

(6) A utility shall not consider the poorest performing feeders

from the immediately preceding reporting period when determining

the poorest performing feeders for the current reporting period.

B. Poorest Performing Feeder Standard for Feeders Not Assigned

to Maryland.

(1) 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.

(2) 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.

(3) 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.

(4) The reliability indices and method for identifying the

performance of feeders under this provision shall be consistent with

§A(2), (4), and (6) of this regulation.

C. Evaluation of Remedial Actions. For the feeders that are

identified as having the poorest performance, the utility shall provide

the following information:

(1) 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

(2) In the five subsequent annual performance reports, the

performance of the feeder shall be reported with its performance

ranking. This reporting requirement does not alter §A(6) of this

regulation.

D. Feeders Assigned to Maryland.

(1) All feeders of a utility that serve only Maryland customers

are assigned to Maryland.

(2) For a utility that has one or more feeders that serve a Maryland

customer and at least one customer in a bordering jurisdiction:

(a) The feeders used in determining the utility’s system-wide

SAIDI and SAIFI performance results as reported to the Commission

by the utility’s 2010 annual reliability report shall be assigned to

Maryland unless otherwise directed by the Commission;


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(b) The utility may not change the assignment list without

Commission approval; and

(c) For a new feeder added to the utility’s system, or an existing

feeder that is modified, that serves more than ten Maryland customers

and at least one customer in a bordering jurisdiction, the utility shall file

notice with the Commission advising of the feeder’s assignment.

E. If a utility fails to satisfy the standard in §A(5) of this

regulation with respect to a feeder assigned to Maryland, it shall

provide a corrective action plan, preferably in its annual

performance report but by no later than April 1.

.04 Multiple Device Activation Standard.

A. Each utility shall report in its annual performance report the

number of protective devices that activated five or more times during the

prior 12-month reporting period specified in Regulation .02B(2) of this

chapter causing sustained interruptions in electric service, including

during major outage events, to more than ten Maryland customers.

B. For each device referenced in §A of this regulation, the utility

shall evaluate and report in its annual performance report the cause

for the multiple activations.

C. For each device referenced in §A of this regulation, the utility shall

implement reasonable remediation measures to reduce the number of

activations and describe the measures in its annual performance report.

D. For each device referenced in §A of this regulation, the device

shall not experience five or more activations, including all customer

sustained interruption data, during either of the two subsequent 12-

month reporting periods after allowing one 12-month reporting

period for the utility to implement remediation measures.

E. If a utility fails to satisfy the standard in §D of this regulation,

it shall provide a corrective action plan, preferably in its annual

performance report but by no later than April 1.

.05 Additional Reliability Indices Reporting.

A. CAIDI, SAIDI, and SAIFI Excluding Major Event Days. A

utility shall calculate and report in its supplemental annual

performance report the following annual reliability information for

its Maryland service territory:

(1) CAIDI, SAIDI, and SAIFI, excluding major event days;

(2) All IEEE major event days; and

(3) The reliability indices, including and excluding planned

outages.

B. A utility shall calculate and report in its supplemental annual

performance report an annual (CEMIn) for customers experiencing

three or more (CEMI2), five or more (CEMI4), seven or more

(CEMI6), and nine or more (CEMI8) sustained interruptions unless it

does not have the means to make the calculation, in which case it

shall provide an explanation of the reason, and an estimate of the

cost to provide the information in the future.

C. A utility shall calculate and report in its supplemental annual

performance report an annual (MAIFIE) for its Maryland service

territory unless it does not have the means to make the calculation, in

which case it shall provide an explanation of the reason, and an

estimate of the cost to provide the information going forward.

.06 Service Interruption Standard.

A. During each calendar year, a utility shall restore service within

8 hours, measured from when the utility knew or should have known

of the outage, to at least 92 percent of its customers experiencing

sustained interruptions during normal conditions.

B. During each calendar year, a utility shall restore service within 50

hours, measured from when the utility knew or should have known of the

outage, to at least 95 percent of its customers experiencing sustained

interruptions during major outage events where the total number of

sustained interruptions is less than or equal to 400,000 or 40 percent of

the utility’s total number of customers, whichever is less.

C. If more than one major outage event subject to the standard set

forth in §B of this regulation occurs during a calendar year, the

restoration percentage shall be calculated by giving equal weight to

all sustained interruptions occurring during the major outage events.

D. During each calendar year, a utility shall restore service as

quickly and safely as permitted to its customers experiencing

sustained interruptions during each major outage event in which the

total number of sustained interruptions is greater than 400,000 or 40

percent of the utility’s total number of customers, whichever is less.

E. If a utility fails to satisfy the standard in §A, B or D of this

regulation during the previous calendar year, it shall provide a

corrective action plan, preferably in its annual performance report

but by no later than April 1.

F. In the calendar year these regulations become effective, §§A

and B of this regulation shall apply from the effective date of the

regulations until the end of the calendar year.

.07 Downed Wire Response Standard.

A. Considering data for normal and major outage event conditions

for a calendar year, each utility shall respond to a government

emergency responder guarded downed electric utility wire within 4

hours after notification by a fire department, police department, or

911 emergency dispatcher at least 90 percent of the time.

B. If a utility fails to satisfy the standard in §A of this regulation

during the previous calendar year, it shall provide a corrective

action plan, preferably in its annual performance report but by no

later than April 1.

C. Each utility shall coordinate its response to a government

emergency responder guarded downed electric wire consistent with

any program established by a fire department, police department, or

911 emergency dispatcher.

D. Each utility shall exercise reasonable care to reduce the

potential hazard caused by a downed electric wire to which its

employees, its customers, and the general public may be subjected.

.08 Customer Communications Standards.

A. Customer Telephone Call Answer Time Standard. Each utility

shall answer within 30 seconds, on an annual basis, at least 75

percent of all calls offered to the utility for customer service or

outage reporting purposes.

B. Abandoned Call Rate Standard. Each utility shall achieve an

annual average abandoned call percentage rate of 5 percent or less,

calculated by dividing the total number of abandoned calls by the

total number of calls offered to the utility for customer service or

outage reporting purposes.

C. Busy Signals. Each utility shall design its telecommunications

systems to accommodate expected volumes of customer calls with

minimal or, if possible, no customer busy signals during both normal

conditions and major outage events.

D. Other Customer Communications Information. Each utility

shall state in its supplemental annual performance report:

(1) Based solely upon those calls offered to its customer service

representatives:

(a) The percentage of calls that are answered within 30

seconds; and

(b) The abandoned call percentage rate; and

(2) 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.

E. Customer Communications Standards Period.

(1) Each standard in this regulation is measured using the 12-

month period ending December 31.

(2) For the calendar year in which the regulations become

effective, the standards shall be measured from the date the


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regulations are effective until and including December 31 of that

year for reporting purposes only.

F. Reporting. Each utility shall report its year-ending

performance in its annual performance report.

G. Except as otherwise set forth in §D of this regulation, the

standards in this regulation shall apply to customer calls offered to

or received by a utility’s call overflow system or a third-party vendor

retained by the utility.

H. Corrective Action Plan. If a utility fails to satisfy the standard in

§A, B or C, of this regulation, it shall provide a corrective action plan,

preferably in its annual performance report but by no later than April 1.

.09 Vegetation Management Requirements.

A. Intent and Scope.

(1) 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.

(2) 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.

(3) 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.

(4) This regulation applies to any electric transmission plant

not regulated by the Federal Energy Regulatory Commission.

B. Technical Standards for Vegetation Management.

(1) 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.

(2) Each utility’s vegetation management program shall

address, at a minimum, all of the following activities:

(a) Tree pruning and removal;

(b) Vegetation management around poles, substations, and

energized overhead electric plant;

(c) Manual, mechanical, or chemical vegetation

management along rights-of-way;

(d) Inspection of areas where vegetation management is

performed after the vegetation management;

(e) Cultural control practices;

(f) Public education regarding vegetation management

practices;

(g) Public and customer notice of planned vegetation

management activities; and

(h) Debris management during routine vegetation

management and during outage restoration efforts.

(3) 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:

(a) The extent of the potential for vegetation to interfere with

poles, substations, and energized overhead electric plant;

(b) The voltage of the affected energized conductor, with

higher voltages requiring larger clearances;

(c) The relative importance of the affected energized

conductor in maintaining safety and reliability;

(d) The type of conductors and type of overhead

construction;

(e) The likely regrowth rate for each species of vegetation at

the site;

(f) The potential movement of energized conductors and

vegetation during various weather conditions;

(g) The utility’s legal rights to access the area where

vegetation management is to be performed;

(h) The maturity of the vegetation;

(i) The identification of the structural condition of the

vegetation, including the characteristics of a species as one having a

high probability of causing a service interruption during weather

events;

(j) State and local statutes, regulations, or ordinances

affecting utility performance of vegetation management;

(k) Customer acceptance of the proposed vegetation

management where the utility does not have legal rights to perform

vegetation management; and

(l) Any other appropriate factor approved by the

Commission.

(4) 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.

C. Training, Record Keeping, and Reporting.

(1) 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.

(2) 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:

(a) Identification of each circuit or substation or, if

applicable, both circuit and substation where vegetation management

was performed;

(b) The type of vegetation management performed including

removal, trimming, and spraying and methods used;

(c) The name of the Maryland Licensed Tree Expert responsible

for oversight of vegetation management at the circuit or substation level;

(d) The approximate date of activity;

(e) Any occurrence resulting in serious injury to a person as

a result of vegetation management activities; and

(f) When a utility seeks to remove a tree or limb, but is

unable to do so because permission or cooperation is not obtained.

(3) 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:

(a) Expenditures for vegetation management in the

preceding calendar year;

(b) Vegetation management budget for the current calendar

year;

(c) Circuits or substations, completion dates, and the

estimated number of overhead circuit miles trimmed in the preceding

calendar year in compliance with the cyclical vegetation

management requirements set forth under §F of this regulation;

(d) Circuits or substations and the estimated number of

overhead circuit miles scheduled for the current calendar year in

compliance with the cyclical vegetation management requirements

set forth under §F of this regulation;

(e) Total overhead circuit miles for the system; and


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(f) If applicable, a corrective action plan, preferably in its

annual performance report or, if necessary, in the supplemental

annual performance report.

(4) 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.

D. Public Notice of Planned Vegetation Management.

(1) 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. Nothing in this regulation

prohibits a utility from using more than one of these methods.

(2) 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.

E. Outreach Programs.

(1) 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.

(2) 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.

(3) Each utility shall post its vegetation management public

education materials on its website.

F. Specific Requirements. Each utility shall perform vegetation

management based on the following schedule:

(1) 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:

(a) 12 months perform vegetation management on not less

than 15 percent of its total distribution miles;

(b) 24 months perform vegetation management on not less


(c) 36 months perform vegetation management on not less

than 70 percent of its total distribution miles; and

(d) 4 years perform vegetation management on not less than

100 percent of its total distribution miles.

(2) 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:

(a) 12 months perform vegetation management on not less


(b) 24 months perform vegetation management on not less


(c) 36 months perform vegetation management on not less


(d) 48 months perform vegetation management on not less

than 75 percent of its total distribution miles; and

(e) 5 years perform vegetation management on not less than

100 percent of its total distribution miles.

(3) Each utility shall follow the vegetation management

performance requirement under §F(1) or (2) of this regulation for

each subsequent trim cycle.

_________________________________

G. Vegetation management shall be performed based on the factors set forth under §B(3) of this regulation. The following minimum

clearances shall be obtained at the time vegetation management is conducted to the extent not limited by contract rights, property rights or

other controlling legal authority:

(1) Horizontal clearances:

(a) Greater than 34.5 kV: The clearance from the conductors shall be the greater of 15 feet or 4 years’ growth if using a 4-year trim

cycle (or 5 years’ growth if using a 5-year trim cycle). Horizontal clearance beneath the conductors shall be measured radially.

Figure No. 1: >34.5 kVNo Overhanging Limbs – Clear Above

15 Feet15 Feet

15 Feet Radial

Clearances achieved at time of trimming

Drawing Not To Scale

Note that 15 Feet represents the > of 15 Feet or Cycle Length Clearance


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(b) From 14 kV to 34.5 kV: The clearance from the conductors shall be the greater of 10 feet or 4 years ’ growth if using a 4-

year trim cycle (or 5 years’ growth if using a 5-year trim cycle). Horizontal clearance beneath the conductors shall be measured

radially.

Figure No. 2: From 14 kV to 34.5 kV

No Overhanging Limbs – Clear Above

10 Feet10 Feet

10 Feet Radial



Note that 10 Feet represents the > of 10 Feet or Cycle Length Clearance

(c) Less than 14 kV but at least 600 volts: The clearance from the conductors shall be 4 years ’ growth if using a 4-year trim

cycle (or 5 years’ growth if using a 5-year trim cycle). Horizontal clearance beneath the conductors shall be measured radially.

Figure No. 3: < 14 kV, but at Least 600 VoltsSubstation to First Protective Device

Multiple Open Wires on Cross-Arm and Armless ConstructionNo Overhanging Limbs – Clear Above

(Also applies to a conductor between 14 kV and 34.5 kVoperated only as a distribution feeder)

4 to 5 Yrs. Radial Clearance




(d) For a conductor with a voltage from 14 kV to 34.5 kV which is operated only as a distribution feeder, the horizontal

clearance shall be as set forth under §G(1)(c) of this regulation as if its voltage were less than 14 kV but at least 600 volts.


349


(e) The horizontal clearances are the minimum clearances the utility shall establish during each cyclical planned vegetation

management trim cycle.

(2) Vertical clearances:

(a) Greater than 34.5 kV: The vertical clearance above the conductors shall be established by removing all overhanging limbs within

the maximum horizontal clearance zone specified under §G(1)(a) of this regulation. The vertical clearance below the conductors shall be the

greater of 15 feet or 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearance below the conductors shall be

measured radially. See Figure No. 1

(b) From 14 kV to 34.5 kV: The vertical clearance above the conductors shall be established by removing all overhanging limbs above

the conductors within the horizontal clearance zone specified under §G(1)(b) of this Regulation. The vertical clearance below the conductors

shall be the greater of 10 feet or 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The vertical clearance below the conductors

shall be measured radially. See Figure No. 2.

(c) Less than 14 kV but at least 600 volts:

(i) Multiple open wires on a cross-arm or armless construction from the substation to the first protective device: The vertical

clearance above the conductors shall be established by removing all overhanging limbs above the conductors wi thin the horizontal

clearance zone specified under §G(1)(c) of this regulation. The vertical clearance below the conductors shall be 4 years’ growth (or 5

years’ growth if using a 5-year trim cycle). The vertical clearance below the conductors shall be measured radially.

(ii) Except as provided in §G(2)(c)(i) for multiple open wires on a cross-arm or armless construction, the vertical clearance

above the conductors is 15 feet. The vertical clearance below the conductors is 4 years’ growth (or 5 years’ growth if using a 5-year

trim cycle). The vertical clearances above and below the conductor shall be measured radially.

Figure No. 4: < 14 kV, but at Least 600 VoltsMultiple Open Wires on Cross-Arm and Armless Construction

(Also applies to a conductor between 14 kV and 34.5 kV operated only as a distribution feeder)






15 Feet Clearance Above

(iii) Spacer cable, tree wire with messenger cable above, aerial cable, and single-phase: The vertical clearance above the

conductors is 6 feet. The vertical clearance below the conductors is 4 years’ growth (or 5 years’ growth if using a 5-year trim cycle). The

vertical clearance above and beneath the conductors shall be measured radially.


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Figure No. 5: < 14 kV, but at Least 600 VoltsSpacer Cable, Aerial Cable, Armless w/Messenger, Single Phase(Also applies to a conductor between 14 kV and 34.5 kV operated

only as a distribution feeder)

4 to 5 Yrs.Radial Clearance





6 Feet Clearance

Above

(d) For a conductor with a voltage from 14 kV to 34.5 kV which is operated only as a distribution feeder, the vertical clearance

shall be as set forth in the corresponding standard contained in §G(2)(c) of this regulation as if its voltage were less than 14 kV but at least 600

volts.

(e) The vertical clearances are the minimum clearances the utility shall establish during each cyclical planned vegetation

management trim cycle.

(3) 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

H. Federal Energy Regulatory Commission Jurisdictional Transmission Plant. Each utility shall file with the Commission’s Engineering

Division a copy of all vegetation management related filings associated with a transmission line in Maryland to the Federal Energy Regulatory

Commission or an entity approved by the Federal Energy Regulatory Commission. If the information is confidential or critical energy

infrastructure information, the utility shall advise the Commission’s Engineering Division in writing and make the information available for

review at a mutually agreeable time and location.

_________________________________

.10 Periodic Equipment Inspections.

A. Each utility shall adopt and follow written operation and

maintenance procedures for its electric plant in order to maintain

safe and reliable service. The operation and maintenance programs

shall account for the utility’s experience, good engineering practices,

and judgment, and manufacturer’s recommendations.

B. Each electric utility shall file its written operation and

maintenance programs required under §A of this regulation with the

Commission within 60 days from the effective date of these

regulations and the programs shall be designed to achieve, at a

minimum, the level of reliability established by the Commission’s

regulations.

C. If the electric utility makes a material change to its written

operation and maintenance programs required under §B of this

regulation, the utility shall file the change with the Commission not

less than 60 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. The filing shall describe each change and the reason

for the change.

D. The operation and maintenance programs required by §B of

this regulation shall:

(1) Include the frequency or triggers for performing an

inspection;

(2) Identify the electric plant inspections to be performed

including, but not limited to:

(a) Poles;

(b) Overhead and underground conductors and cables;

(c) Transformers;

(d) Switching and protective devices;

(e) Substations;

(f) Regulators; and

(g) Capacitors; and

(3) Identify acceptance criteria for the inspections.

E. Except as provided under §D of this regulation and Regulation

.09 of this chapter, the operation and maintenance programs

required by §B of this regulation need not include detailed

procedures.

F. Each utility shall maintain sufficient records to give evidence of

compliance with its operation and maintenance programs and shall

demonstrate compliance with its program in its annual performance

report.


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G. If a utility fails to comply with its operation and maintenance

programs, the utility shall provide a corrective action plan,

preferably in its annual performance report but by no later than April

1.

H. The following electric distribution plant shall be inspected

consistent with the following minimum frequency intervals measured

from the effective date of these regulations:

(1) Poles — 10 years;

(2) Overhead primary distribution lines from the substation to

the first protective device — 2 years;

(3) Above-ground pad-mounted transformers — 5 years;

(4) Below-ground transformers — 5 years; and

(5) Substations — 2 months.

I. A utility may request an interval greater than the intervals listed

in §H of this regulation. The request shall include an explanation of

any change in the utility’s cost to perform the inspection and the

expected reliability impact resulting from the change.

.11 Annual Performance Reports.

A. On or before February 1 of each year, each utility shall file an

annual performance report which shall include, at a minimum, the

following:

(1) 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;

(2) 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;

(3) 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;

(4) A description of the utility’s reliability objectives, planned

actions and projects, and programs for providing reliable electric

service;

(5) 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;

(6) 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;

(7) 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;

(8) 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;

(9) The total number of customers that experienced an outage

required under Public Utilities Article, §7-213(g)(2)(iv)(4),

Annotated Code of Maryland;

(10) The total number of customer minutes of outage time

required under Public Utilities Article, §7-213(g)(2)(iv)(5),

Annotated Code of Maryland;

(11) 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;

(12) Poorest performing feeder information and results

required in this chapter; and

(13) Multiple device activation information and results

required in this chapter.

B. On or before April 1 of each year, each utility shall file a

supplemental annual performance report which shall include, at a

minimum, the following:

(1) 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;

(2) Service restoration requirement information and results

required in this chapter;

(3) Downed wire response performance information and results


(4) Customer communications performance information and

results required in this chapter;

(5) The vegetation management information required in this

chapter;

(6) Periodic equipment inspection information and results


(7) For the immediately preceding calendar year, and

considering normal conditions only:

(a) The number of downed electric utility wires to which the

utility responded in:

(i) 4 hours or less;

(ii) More than 4 hours but less than 8 hours; and

(iii) 8 hours or more; and

(b) The total number of downed electric utility wires

reported to the utility; and

(8) Any corrective action plans required under Public Utilities

Article, §7-213(e)(1)(iii), Annotated Code of Maryland, or this

chapter.

C. The Commission may designate a specific report format for the

information required to be included in the written reports mandated

under §§A and B of this regulation.

D. The Commission may require reporting information required to

track performance under these regulations on a quarterly basis on a

form approved by the Commission.

.12 Major Outage Event Plan.

A. Within 60 days of the effective date of this regulation, each

utility shall file a major outage event plan providing a description of

and procedures for its response to major outage events, and

performance measures associated with the assessment of the

implementation of the major outage event plan, including, but not

limited, to the following topics and issues:

(1) Preparation, training, and drills;

(2) Early warning and storm tracking;

(3) Internal and external staffing levels;


352


(4) Activation and mobilization;

(5) Materials management and logistics;

(6) Major outage event restoration priorities, including, but not

limited to:

(a) How the utility prioritizes restoration customers; and

(b) How the utility communicates with customers that are

identified as high priority due to medical needs for electricity and

how it schedules restoration actions for such customers;

(7) Damage assessment;

(8) Public safety, including wire down response;

(9) Crew deployment;

(10) External communications, including communications with

emergency officials, the public, and other persons;

(11) Internal communications;

(12) Communications technology use, including high call

volume capability and capacity;

(13) Development of estimated times of restoration and

assessment of estimated times of restoration accuracy;

(14) Ramp-down; and

(15) Major outage event performance review.

B. Each utility shall file with the Commission any material change

to its major outage event plan at least 60 days prior to

implementation, unless it will delay implementation of the change in

a manner inconsistent with restoring service in the shortest time

practicable, in which case the change shall be filed by no later than

30 days after implementing the change.

C. Each utility shall comply with its major outage event plan when

preparing for and responding to major outage events.

.13 Major Outage Event Reporting.

A. Written Reports. Each utility shall file a written report with the

Commission within 3 weeks of the end of a major outage event.

B. Contents. The written report shall contain:

(1) The total number of Maryland customers served by the

utility;

(2) The date and time when the major outage event started;

(3) The date and time when all sustained interruptions in

Maryland related to the major outage event were restored;

(4) The total number of Maryland customers who experienced a

sustained interruption of service related to the major outage event;

(5) The total number of customer interruption hours

experienced by customers reported under §B(4) of this regulation;

(6) 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;

(7) 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;

(8) The number of Maryland customers who experienced a

sustained interruption recorded at a maximum of 6-hour intervals

throughout the major outage event;

(9) Information about requests for outside assistance, including

the:

(a) Name of the organization to which the request was

made;

(b) Date and time of the request; and

(c) Resources requested;

(10) Information about outside assistance received, including

the:

(a) Name of the organization providing crews and the

nature of the assistance, i.e., mutual assistance, third-party

contractor crew normally dedicated to the utility, additional third-

party contractor crew, or other (explain in report);

(b) Date and time of crew arrivals and departures;

(c) Number and types of vehicles;

(d) Total number of personnel;

(e) Number of personnel on primary overhead line crews;

(f) Number of personnel on secondary overhead line crews;

and

(g) Number of personnel on tree trimming crews;

(11) Information about electric utility crews working on

restoration, including the following:

(a) Number and types of vehicles;

(b) Total number of personnel;

(c) Number of personnel on primary overhead line crews;

(d) Number of personnel on secondary overhead line crews;

(e) Number of personnel on damage assessment crews; and

(f) Number of personnel on tree trimming crews;

(12) The following information about communications with

customers:

(a) The total number of calls received by the utility during

each hour of the major outage event;

(b) The total number of calls answered by the utility’s voice

response system, customer service representatives, and any high

volume call systems during each hour of the major outage event;

(c) The total number of customer service representatives

logged into the call center and supporting phone systems actively

taking or waiting to take customer calls on an hourly basis during the

major outage event; and

(d) On a daily basis during the length of the outage and for

the entire major outage event, the percentage of all calls that were

offered and answered by the utility’s voice response system, customer

service representatives, and any high volume call systems within a

30-second timeframe and within a 60-second timeframe.

(13) With regard to system damage, the number of each of the

following occurring during restoration:

(a) Poles replaced;

(b) Distribution transformers replaced;

(c) Fuses replaced;

(d) Downed wires; and

(e) Substations with damaged equipment;

(14) 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;

(15) A self-assessment, including lessons learned and future

plans to improve service restoration efforts during major outage

events;

(16) 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;

(17) 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;

(18) A description of the manner in which the utility estimated

restoration times;

(19) A description of any areas where the utility did not comply

with its major outage event plan; and

(20) 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 caused by each one of the

following:

(a) Fallen tree or tree limb;

(b) Fallen or broken pole;

(c) Lightning damage;

(d) Ice accumulation on conductors; and


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(e) Each other direct cause of interruption of service to 5

percent or more of total customers interrupted, listing and providing

a descriptive name for each cause.

C. The Commission may designate a specific report format for the

information required to be included in the written report mandated

under this regulation.

.14 Customer Perception Surveys.

A. Each utility shall perform a customer perception survey no less

than every 4 years. The Commission will establish a process for

determining how and by whom the surveys will be conducted.

B. The objective of the survey is to measure customer perceptions

regarding the utility’s reliability performance, vegetation

management activities, effectiveness of customer communications,

and service quality performance.

C. The first survey shall be performed by the end of calendar year

2013 and shall be included with each utility’s submittal under

Regulation .02D(7)(b) of this chapter.

DAVID J. COLLINS

Executive Secretary

Public Service Commission

Official RM 43 Rules

Documents

Transcript of Official RM 43 Rules