Post on 02-Jan-2016
description
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Pursuant to State Government Article, §7-206, Annotated Code of Maryland, this issue contains all previously unpublished documents required to be published, and filed on or before February 6, 2012, 5 p.m. Pursuant to State Government Article, §7-206, Annotated Code of Maryland, I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
342
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
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) (text unchanged)
(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.
(12) (text unchanged)
PROPOSED ACTION ON REGULATIONS
343
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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.
(18) — (19) (text unchanged)
(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.
(22) — (26) (text unchanged)
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)
(2) — (3) (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
calculated and reported in the annual performance report using the
following sets of input data:
(a) All interruption data;
(b) All interruption data minus major outage event
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
PROPOSED ACTION ON REGULATIONS
344
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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
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
calculated and reported in the annual performance report using the
following sets of input data:
(a) All interruption data;
(b) All interruption data minus major outage event
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;
PROPOSED ACTION ON REGULATIONS
345
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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
PROPOSED ACTION ON REGULATIONS
346
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
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
PROPOSED ACTION ON REGULATIONS
347
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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
than 40 percent of its total distribution miles;
(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
than 12 percent of its total distribution miles;
(b) 24 months perform vegetation management on not less
than 32 percent of its total distribution miles;
(c) 36 months perform vegetation management on not less
than 56 percent of its total distribution miles;
(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
PROPOSED ACTION ON REGULATIONS
348
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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
Clearances achieved at time of trimming
Drawing Not To Scale
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
4 to 5 Yrs. Radial Clearance
Clearances achieved at time of trimming
Drawing Not To Scale
(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.
PROPOSED ACTION ON REGULATIONS
349
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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)
4 to 5 Yrs. Radial Clearance
4 to 5 Yrs. Radial Clearance
Clearances achieved at time of trimming
Drawing Not To Scale
4 to 5 Yrs. Radial Clearance
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.
PROPOSED ACTION ON REGULATIONS
350
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
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
4 to 5 Yrs. Radial Clearance
Clearances achieved at time of trimming
Drawing Not To Scale
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.
PROPOSED ACTION ON REGULATIONS
351
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
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
required in this chapter;
(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
required in this chapter;
(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;
PROPOSED ACTION ON REGULATIONS
352
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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
PROPOSED ACTION ON REGULATIONS
353
MARYLAND REGISTER, VOLUME 39, ISSUE 4, FRIDAY, FEBRUARY 24, 2012
(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