Published by Power System Engineering, Inc.

Spring 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

MOD-015-0: Development of Dynamics System Models

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).

Upcoming Events:

© 2015 Power System Engineering, Inc. (PSE)

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APPA National Conference and

Public Power ExpoMinneapolis, MN

June 5 - 10Please visit us at Booth #701

2015 APPA E&O Technical Conference

Sacramento, CAMay 17 - 20

PSE’s Jim Weikert will present the following sessions:Case Studies in DA DeploymentsDeveloping a Strategic Communications Plan

PSE’s Jamie Sieren will present:Procurement Best Practices

Please visit us at Booth #209

UTC Telecom & Technology 2015

Atlanta, GAMay 5 - 8

PSE’s Charles Plummer will present the following sessions:Wireless Workshop: A Survey of Wireless Technologies for Utility CommunicationsThe 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

1 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

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• 6inMRO• 3inRFC• 2inSPP• 20inWECC• 6inNPCC• 18inSERC• 15inFRCC• 1inTRE

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 andpreparetoadheretotheirspecificdatasubmissionrequirementsprior 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:

• R2requiresthattheapplicableentities,“shallprovidesteady- state, 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.”

•R3requiresthat,“Eachregisteredentity…thathasreceived writtennotification…regardingtechnicalconcernswiththedata submitted under Requirement R2 shall provide evidence …thatithasprovidedeitherupdateddataoranexplanationwith a technical basis for maintaining the current data.”

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 steady-state, 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 BESdataonanannualbasis.Staffingneedscouldrangefromoneto 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

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NERC Impact on Transmission Planning: MOD-032

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 feeder-located 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.

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

Now Is the Time to Establish a Periodic Communications Maintenance Plan

3 NERC MOD-032-1 http://www.nerc.com/pa/Stand/Reliability%20Standards/MOD-032-1.pdf

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.

Forsmallresidentialwaterheaters(under55gallons),thenewDOE 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

What Do the New Water Heater Efficiency Standards Mean for Demand Response?

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2014 Client Rate Survey ReportTheRatesandFinancialPlanningteamatPSEispleasedtorollout 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.

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.

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 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?

$20.00

$-

$40.00

$60.00

$80.00

$100.00

Residential COS Consumer Cost New Residential Customer Charge

Residential Customer Charge

Avera

ge - A

ll

Submitted by Shaurice Moorman – Manager, Rates and Financial Planning – moormans@powersystem.org

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ASK PSE A QUESTIONWhen Is a Grounding Transformer Needed?

C O N S U L T A N T SF U L L - S E R V I C EPSE 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

Foracompletelistofservices,pleasevisitourwebsite.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.

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.

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.

Fusesalonedonotprovideadequateprotection,nordoconventional 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

Page 5 • 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 well-implemented 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 extent, repair time, and restoration?

Another key component is how well distributed OMS information is to all who could benefit from it.

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.

OMS

AMI

CustomerService

Customer

SCADA Operator/Dispatch

FeederOutages

SCADA

Line Crews

Submitted by Jim Weikert – Lead Utility Automation Consultant – weikertj@powersystem.org

AnnouncementsAs 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

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.

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

What Do the New Water Heater Efficiency Standards Mean for Demand Response? ................. pg. 3

2014 Client Rate Survey Report ................................ pg. 3

Ask PSE a Question: When Is a Grounding Transformer Needed? ................................................. pg. 4

How Progressive Is Your Outage Management? ..... pg. 5

Email shekelss@powersystem.org with questions, comments, or for more information.

PSE Office Locations:

Madison, WI – (608) 222-8400

Minneapolis, MN – (763) 755-5122

Marietta, OH – (740) 568-9220

Indianapolis, IN – (317) 322-5906

Prinsburg, MN – (320) 978-8022

Sioux Falls, SD – (605) 221-1770

Visit our website for more information

www.powersystem.org

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