Published by Power System Engineering, Inc.
S p ri ng 2015
NERC Impact on
Transmission Planning:
MOD-032
Are you registered with NERC/Regional Entity1 as a Balancing Authority (BA), Load
Serving Entity (LSE), Transmission Service Provider (TSP), Transmission Owner (TO),
Transmission Planner (TP), Generator Owner (GO), or Resource Planner (RP)? If so, you
are annually required to submit your Bulk Electric System (BES) data to your Planning
Coordinator/Authority beginning July 1, 2016.
On April 1, 2005, the North American Electric Reliability Corporation (NERC) Board of
Trustees (BOT) adopted 40 operating and 50 planning NERC version 0 standards. The
following six standards cover the reporting and data requirements for modeling the BES;
the collection and management of the BES data was assigned to the Regional Reliability
Organizations (RRO).
MOD-010-0: Steady-State Data for Modeling and Simulation of the
Interconnected Transmission System
MOD-011-0: Maintenance and Distribution of Steady-State Data Requirements
and Reporting Procedures
MOD-012-0: Dynamics Data for Modeling and Simulation of the
Interconnected Transmission System
MOD-013-0: Maintenance and Distribution of Dynamics Data Requirements
and Reporting Procedures
MOD-014-0: Development of Steady-State System Models
Atlanta, GA
May 5 - 8
PSE’s Charles Plummer will present
the following sessions:
Wireless Workshop: A Survey of
Wireless Technologies for Utility
Communications
The Survivor’s Guide to IT/OT
Convergence: Do It Right and Our
Future Will be Bright
PSE’s Joe Warren will present:
Think Inside the Lines: Leveraging
Utility Assets for Smart Grid and
Automation Network Devices
Please visit us at Booth # 634
2015 APPA E&O
Technical Conference
Sacramento, CA
May 17 - 20
Case Studies in DA Deployments
In 2013, these standards were revised and combined to shift the responsibility from the
RRO to the Planning Coordinator (PC) and other functional entities. Under the version 0
standards, large system owners and operators typically assisted smaller system owners and
operators with data submissions to the RRO. As compliance has become more rigid, these
larger system owners and operators will most likely terminate their assistance, and this
responsibility will be delegated to the smaller entities.
The models once coordinated and built by 8 entities are now built and coordinated by 812
registered PCs for submission to the Electric Reliability Organization (ERO).
Continued on page 2
Midwest Reliability Organization (MRO), Reliability First Corporation (RFC),
Southwest Power Pool (SPP), Western Electricity Coordinating Council (WECC),
Northeast Power Coordinating Council (NPCC), SERC Reliability Corporation (SERC),
Florida Reliability Coordinating Council (FRCC), Texas Reliability Entity (TRE)
2 NERC Compliance Registry as of 12/31/2014 http://www.nerc.com/pa/comp/Pages/Registration.aspx
© 2015 Power System Engineering, Inc. (PSE)
UTC Telecom &
Technology 2015
PSE’s Jim Weikert will present the
following sessions:
MOD-015-0: Development of Dynamics System Models
1
Upcoming Events:
Developing a Strategic
Communications Plan
PSE’s Jamie Sieren will present:
Procurement Best Practices
Please visit us at Booth #209
APPA National
Conference and
Public Power Expo
Minneapolis, MN
June 5 - 10
Please visit us at Booth #701
Continued from page 1
NERC Impact on Transmission Planning: MOD-032
•
•
•
•
•
•
•
•
6 in MRO
3 in RFC
2 in SPP
20 in WECC
6 in NPCC
18 in SERC
15 in FRCC
1 in TRE
• R3 requires that, “Each registered entity … that has received written notification … regarding technical concerns with the
data submitted under Requirement R2 shall provide evidence
… that it has provided either updated data or an explanation
with a technical basis for maintaining the current data.”
PCs, in
coordination with
TPs, are required to
have reporting procedures in
place by July 1, 2015 (one year prior
to the date that actual reporting is required). The responsible
entities should monitor their respective PC or TO planning criteria
and prepare to adhere to their specific data submission requirements
prior to the effective date (July 1, 2016) of MOD-032-1 Data for
Power System Modeling and Analysis Requirements R2 and R3.
Currently, these requirements are as follows:
•
R2 requires that the applicable entities, “shall provide steadystate, dynamics, and short circuit modeling data to its
Transmission Planner(s) and Planning Coordinator(s) according
to the data requirements and reporting procedures developed by
its Planning Coordinator and Transmission Planner3.”
The majority of Eastern Interconnection transmission planning
models are built using the Siemens Power System Simulation for
Engineers® PSS/E software. Therefore, the responsible entities will
need to be familiar with the software in order to submit steadystate, dynamic, and short-circuit information in the correct format.
Depending on the amount of BES facilities you own or operate,
the time and effort involved with tracking NERC standards and the
PC and TO data submission requirements can be overwhelming.
In addition, responsible entities will need to verify and submit the
BES data on an annual basis. Staffing needs could range from one
to three full-time employees.
PSE has the industry-used software tools, PSS/E and MUST, as
well as knowledge of NERC standards and processes. In addition,
our team members have a great range of expertise in all aspects
of distribution and transmission planning. If you are unsure of
your NERC reporting requirements or status, let us know and we
can help.
Submitted by Laura Couillard – Resource and System Planning Engineer
– couillardl@powersystem.org
3 NERC MOD-032-1 http://www.nerc.com/pa/Stand/Reliability%20Standards/MOD-032-1.pdf
Now Is the Time to Establish a Periodic
Communications Maintenance Plan
As utilities continue to evolve toward smart grid technology, they
are deploying a growing number of communication devices—
whether radio, fiber, or cellular—throughout their service territory.
This increase in devices means organized, periodic maintenance of
these devices is more important than ever. And, utilities must make
sure they have the proper workforce to perform that maintenance.
In the case of tower-based systems such as microwave backbone
transport and Land Mobile Radio (LMR) base stations, planning
and scheduling of routine maintenance activities is usually not
particularly complicated. These sites are generally relatively easy
to reach without specialized equipment, and tasks can be scheduled
with some flexibility and consideration for workforce priorities.
However, utilities can now have more than a thousand feederlocated Distribution Automation (DA) and Advanced Metering
Infrastructure (AMI) collector nodes, plus their backhaul
communications which also require periodic preventive
maintenance. The nature of communications devices located at
remote sites throughout the service territory can present unique
maintenance challenges.
Page 2
• PSE / / The Utility Edge
Creating an overarching plan, including schedules and report
forms, will help the utility keep these feeder-located systems
operating to their full potential. A well-developed periodic
maintenance plan should include all annual, bi-annual, and
quarterly maintenance tasks laid out in a schedule that is easy to
follow by the communications technicians at each site. Along with
the defined tasks, it should include estimated time to complete the
task, required tools, and the necessary forms to document the work
completed. If designed properly, the maintenance plan should also
provide an accurate estimate of the required staffing to complete the
required tasks for all of the utility communications assets.
We have a complete staff qualified to develop maintenance plans
for equipment in both the traditional communications space and
at the utility feeders. Please contact us to take advantage of our
experience in designing this complex but critical plan need for
your utility.
Submitted by Joe Warren – Communications Consultant –
warrenj@powersystem.org
What Do the New Water Heater Efficiency Standards
Mean for Demand Response?
Water heater manufacturers will need to comply with new
Department of Energy (DOE) efficiency standards for all
products manufactured after April 16, 2015. These new standards
were established in 2010 under the National Appliance Energy
Conservation Act, and are just now taking effect.
For small residential water heaters (under 55 gallons), the new
DOE standards call for modest increases in efficiency. Meeting the
new standards was achievable by making minor improvements, and
water heaters that comply are already on the market.
Residential water heaters over 55 gallons, however, see a much
larger increase in required efficiency under the DOE standards. In
fact, the required efficiency level for these large heaters is currently
achievable only by using heat-pump water heater technology and is
not achievable using electric resistance water heaters. Thus, most
large residential electric resistance water heaters will no longer
be manufactured. This is a problem for cooperatives, since many
use large residential electric water heaters in demand response
programs. In these programs, the water is heated during off-peak
times, and the water heaters are then shut off during peak times.
Some utilities worry that heat-pump water heaters are not as
effective in demand response programs. Thus, the NRECA (along
with ACEEE and others) has proposed a bill in the U.S. House of
Representatives (H.R. 906) that would allow the continued use of
large residential electric water heaters that do not meet the new
standard, with the condition that they be used for load control or
thermal storage. The DOE recently released a report which suggests
that heat-pump water heaters (HPWHs) can be used effectively in
demand response programs; however it remains to be seen whether
HPWHs and the remaining resistance water heaters are as effective
as the older and larger electric resistance heaters in these programs.
Utilities with existing programs may want to reconsider the direct
load control incentives offered on HPWHs or smaller water
heaters to ensure that the lower benefit levels still exceed program
costs. Shortening control periods and more sophisticated layering
strategies may also warrant consideration.
Submitted by Steve Fenrick – Leader, Economics and Market Research
Group – fenricks@powersystem.org
2014 Client Rate Survey Report
The Rates and Financial Planning team at PSE is pleased to roll
out our 2014 Client Rate Survey Report. This annual customized
report is provided to our cost-of-service (COS) study clients each
year. The intent of the report is to provide interesting and valuable
insights gained from projects we have conducted for utilities around
the country.
During 2014, there was much discussion and focus on fixed cost
recovery. The majority of an electric utility’s expenses are fixed
in that they do not vary based on sales volume. In contrast, the
majority of a utility’s revenue stream is variable, recovered through
the energy charge, and with a smaller portion being recovered
through the customer charge.
The chart below represents the residential customer charge in
comparison to the residential COS consumer cost for each utility.
In spite of these changes, utilities in the study are still recovering
only 60 percent of the COS consumer costs on average through the
customer charge.
PSE is hopeful that this report will be of value to each of our rate
and COS study clients. While this report focuses on a few major
topics, the data that we have compiled will allow us to expand and
incorporate additional relevant issues and trends as we go forward.
In the meantime,
we recommend
Residential Customer Charge
utilities take a close
look, if you haven’t
already, at how
your residential
customer charge
weighs in against the
average. Is it time to
reevaluate?
$100.00
$80.00
$60.00
$40.00
$20.00
ra
ge
-A
ll
$-
Av
e
Over the last few
years, many utilities
have been taking
steps to increase the
customer charge in
order to recover more
of the fixed expenses.
In fact, the customer
charge is the primary
tool that utilities use
to recover the COS
consumer costs for
the residential class.
Based on over 50 studies that PSE has conducted over the last three
years, increases in the customer charge ranged from no increase to
$16.50, with the average increase being $3.75.
Residential COS Consumer Cost
New Residential Customer Charge
Submitted by Shaurice Moorman – Manager, Rates and
Financial Planning – moormans@powersystem.org
Page 3
• PSE / / The Utility Edge
ASK PSE A QUESTION
When Is a Grounding Transformer Needed?
These days, most distribution systems are 4-wire with the neutral
wire being grounded throughout the system. However, it was
common for early systems to be ungrounded delta e.g. at 2.4 and
34.5 kV, and these are still around.
When there is a need to supply a 4-wire system, but the source
is delta, a neutral point must be established by installing a
grounding transformer which will create voltage from each
phase-to-neutral which is 58% of the phase-to-phase voltage.
This is important for underground cable insulation, for
enabling improved arrester protection, and where loads are to
be connected phase-to-neutral. Wind farms, for instance, have
collector systems in which the generator step-up transformers
have delta windings on the collector side.
If the collector system becomes disconnected from the utility’s
wye source, one or more grounding transformers would be
needed to maintain the line-to-neutral voltage on the collector
system. Without the grounding transformers, and although the
wind turbine generators would shut down, there would be a brief
period of time when damage could be done to voltage sensitive
equipment. A wye-delta connected transformer bank with all
4 wires of the wye side connected to the utility system and the
secondary delta side having no load connected can serve as a
grounding bank. Zig-zag transformers are a special design for
this purpose and are more compact than the run-of-the-mill
wye-delta bank.
FULL-SERVICE
Note that grounding banks must be properly sized for ground
fault duration and levels, and/or to supply unbalanced current
caused by line-to-neutral connected loads.
Fuses alone do not provide adequate protection, nor do
conventional CT arrangements with 3-phase relays having
residual elements. Special CT arrangements must be used
involving each phase and neutral; the best protection is with
a differential scheme.
Keep in mind that any wye-delta transformer bank could act
as a grounding bank if the primary wye side neutral point is
connected to the primary system’s grounded neutral. They
could possibly suffer damage during primary line-to-ground
faults. Older overhead transformer banks usually did not have
the neutral point grounded permanently, but they could become
possible sources for ferroresonance. One common solution
for the ferroresonance would then be to remove all fuses and
not allow single-phase switching in the line between this
transformer and the substation, replacing them with 3-phase
overcurrent devices.
Submitted by Duane Craig, PE – Engineering Consultant –
craigd@powersystem.org
CONSULTANTS
PSE is driven to be your trusted advisor for all of your consulting and engineering needs.
Our services include:
n Communications, IT, and Smart Grid Automation
nEconomics, Rates, and Business Planning
nElectrical Engineering
n Planning and Design
nProcurement, Contracts, and Deployment
For a complete list of services, please visit our website.
www.powersystem.org
Are You a Leader in Your Field?
We are always looking for experienced professionals to join our team.
Check out the career section of our website for more information.
Page 4
• PSE / / The Utility Edge
How Progressive Is
Your Outage Management?
The Outage Management System (OMS) should be one of the
most central and crucial systems in your utility. However, many
utilities aren’t taking full advantage of the benefits of a wellimplemented OMS. PSE has developed a maturity model that
measures how well you are maximizing your OMS and helps
determine how this crucial system can benefit you more.
One key component of the maturity model measures how
well the utility’s OMS receives useful information from other
systems. Is your OMS well integrated with your Automated
Metering (AMI), for example, so that it receives outage
notifications that enable dispatchers to easily verify the extent
of outage or restoration directly through the OMS? Does your
OMS receive not only breaker statuses from SCADA but also
fault location information to give operators better direction to
line crews in terms of where to search for the fault in need
of repair? Are you fully utilizing your Integrated Voice
Response (IVR) system and web portals to not only
receive outage calls from members
but also provide members
notification of outage
Customer
extent, repair time, and
Service
restoration?
Most utilities find great benefit in making sure that customer
service representatives (CSRs) have a clear picture of the
extent of outages and that dispatchers can see all fault and crew
locations and statuses. Advanced utilities make sure that line
crews have visibility to the OMS to allow them to adapt better
to changing conditions. These utilities also make sure that the
OMS provides high-level storm management visibility to senior
management without burdening operations personnel.
As utilities progress even further, the OMS can become a single
point of operational control. By having full visibility and control
of the distribution system, system operators can work with line
crews to tag and operate breakers to address outages from the
same system that provides them a clear picture of the
outages, faults, and crew locations.
Your OMS ought to serve both you and
your members by communicating
amongst all involved so members feel
better cared for and personnel are more
efficient in their roles.
AMI
OMS
Another key component is
how well distributed OMS
information is to all who
could benefit from it.
Feeder
Outages
Submitted by Jim Weikert –
Lead Utility Automation Consultant –
weikertj@powersystem.org
SCADA
Customer
SCADA Operator/
Dispatch
Line Crews
Announcements
As we continue to grow, we are excited to add the following
professionals to our team:
Madison, WI
Sarah Pink – Manager, Smart Grid Applications
Kyle Kopczyk – Utility Automation Consultant
Marietta, OH
David Dunbar – Designer
Page 5
• PSE / / The Utility Edge
Marietta, OH
PSE’s Sean Kufel elected to join the Institute of
Electrical and Electronics Engineers (IEEE)
Rural Electric Power Committee
The Rural Electric Power Committee is a technical committee
of the Industry Applications Society within the IEEE. The
Committee has a number of standing subcommittees engaged in
the administration of its business and the investigation of special
technical issues.
Sean will serve on the Guides and Standards subcommittee.
Power System Engineering, Inc.
1532 W. Broadway
Madison, WI 53713
PRSRT STD
US POSTAGE
PAID
MADISON, WI
PERMIT No.549
Published by Power System Engineering, Inc.
Inside this issue:
NERC Impact on Transmission Planning: MOD-032 .pg. 1
Now Is the Time to Establish a Periodic
Communications Maintenance Plan .......................... pg. 2
PSE Office Locations:
Madison, WI – (608) 222-8400
Minneapolis, MN – (763) 755-5122
Marietta, OH – (740) 568-9220
What Do the New Water Heater Efficiency
Standards Mean for Demand Response?.................. pg. 3
Indianapolis, IN – (317) 322-5906
2014 Client Rate Survey Report ................................. pg. 3
Sioux Falls, SD – (605) 221-1770
Ask PSE a Question: When Is a Grounding
Transformer Needed?.................................................. pg. 4
Visit our website for more information
How Progressive Is Your Outage Management? ...... pg. 5
Email shekelss@powersystem.org with questions,
comments, or for more information.
Prinsburg, MN – (320) 978-8022
www.powersystem.org