Data Collection guide 2015 Electric T&D Benchmarking Updated versions of the Guidelines and recordings from the webinars are available at our website.

Data Collection guide

2015 Electric T&D Benchmarking

Updated versions of the Guidelines and recordings from the webinars are available at our website.

www.1qconsulting.com :: Benchmarking Community :: Data Entry Gateway

Introduction

Purpose of this document◼ The purpose of this Data Collection Guide is to provide guidance and

direction in how to complete the detailed questionnaire for the T&D benchmark study. It gives instructions regarding the types of answers expected, as well as errors to avoid. This Guide has been described as the “rules” for providing data.

◼ It provides the underlying process models around which the various sections of the questionnaire are organized, to help in understanding the purpose of some of the questions.

◼ The appropriate costs to include, and those to exclude, are highlighted, so that each member utility can provide accurate, comparable data for comparisons.

◼ A few key definitions are provided throughout the document. A comprehensive set of definitions is provided in a separate Glossary.

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Data Collection Guide Outline

The purpose of this Data Collection Guide is to describe the “rules” for providing data. The organization follows the questionnaire outline: ◼ ST. Statistics◼ SA. System Activity◼ DF. Distribution Financial◼ TF. Transmission Financial◼ CP. Capital Project & Portfolio Management◼ SF. Safety◼ SO. Staffing/Outsourcing◼ SU. Support◼ DR. Distribution Reliability◼ SR. Substation Reliability◼ TR. Transmission Line Reliability◼ ER: Emergency Response◼ SG: T&D Strategy◼ AM: Asset Management◼ DP. Distribution Practices (Parts 1 and 2)◼ SP. Substation Practices ◼ TP. Transmission Line Practices

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Sections T&D Dist Subs Trans

Statistics X * * *

System Activity X * * *

Financial Data X * X

Staffing/Outsourcing X

Support (Inventory, Fleet, etc.) X

Safety X

T&D Strategy X * * *

Asset Management X * * *

Capital Portfolio and Project Management X

Emergency Response X

Reliability X X X

Practices X X X

Add New Customers Process * *

Add Capacity Process * * *

Operate System Process * *

Sustain System Process * * *

Structure of the 2015 T&D Survey

The 2015 T&D survey is structured as follows:

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X Primary Sections of questionnaire* Indicates subsections within the primary section

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Working With the Process Model

◼ We have been evolving to our T&D process model over the last two years.   In 2014, we restructured much of the questionnaire to fit the model. For 2015, we have made some further modifications to flesh out the

model and to consolidate some areas based on learning from last year.◼ Benefits of a process view accrue where processes cut across multiple

functional silos.◼ By focusing attention on process steps across functions, we are able to:

Design questions that are specific enough to identify critical success factors in each process area.

Identify some operational metrics at the process/operating level

Develop System Strategy

Develop and Approve Asset Plans

Project/Portfolio Management

Expand System

A Process Model for Managing the T&D Business

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The T&D benchmarking survey is built around a process model of the T&D business. This model helps in analysis of the performance and practices of the member utilities, and gives a framework for deeper investigation.

Operate System

Sustain System

Indicates separate D, S, T components

Add New Customers

Respond to Emergencies

Statistics and System Activity

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Statistical & System Activity Sections

◼ The purpose of these sections◼ Statistical: to gather demographic information about the existing electric system

such as: size, voltage, customer density, etc. This information is used in doing analysis of the results, understanding the inherent advantages and limitations of the circumstances facing each utility.

◼ System Activity: to identify work load drivers associated with activity There are a variety of questions designed to understand the amount of capital

activity and that ask for capital unit additions Other questions ask about selected O&M activities for the year.

◼ Changes for 2015: Several new questions have been added to collect information on existing [statistical] and new [system activity]: Distributed Generator penetration Percentages of customers served by different types of primary distribution systems Current transmission interconnections Age profile of key asset components within Distribution, Substations and

Transmission. New/added Distributed Generator connections, work volumes of distribution

primary cable treatment and replacement, and new/added transmission interconnections.

◼ Companies may need to identify new subject matter experts to furnish some of this data. 8

Transmission versus Distribution

For purposes of this survey, we define distribution to be a voltage level of 45kV and below. The distinction is somewhat arbitrary, but picks a point between 69kV which is generally considered a transmission (or at least sub-transmission) level and 21kV which would generally be considered distribution.

It is unrealistic to ask utilities to redefine their cost or reliability reporting on the basis of these definitions. However, a utility that has very different definitions may want to restate these statistics to better compare their performance.

Distribution Voltage Classes

(Phase to Phase)◼ 5kV class (>1kV, <=9kV)◼ 15kV class (>9kV, <=15kV) ◼ 25kV class (>15kV to <=26kV) ◼ 35kV class (>26kV to <=36kV) ◼ 44kV class (>36kV to <=44kV)

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Transmission classes >=45kV

(Phase to Phase) <69kV class (>=45kV <69kV) 69kV class (>=69kV <100kV) 100kV class (>=100kV <200kV) 200kV Class (>=200kV <300kV) 300kV Class (>=300 kV <400 kV) 400kV and above

Substation Definitions

One way to determine whether a substation is Transmission vs. Distribution would be based upon usage.◼ For multi-purpose substations, you may either segregate costs or assign costs based

upon predominant use.

For purposes of this survey, we generally will recommend a low-side definition based upon a 45kV or below as a distribution substation.

It is unrealistic to ask utilities to redefine their cost or reliability reporting on the basis of these definitions. We will rely on each utility’s self-assigned definitions. However, a utility that has very different definitions may want to restate these statistics to better compare their performance.

Distribution Voltage Classes

(Phase to Phase)◼ 5kV class (>1kV, <=9kV)◼ 15kV class (>9kV, <=15kV) ◼ 25kV class (>15kV to <=26kV) ◼ 35kV class (>26kV to <=36kV) ◼ 44kV class (>36kV to <=44kV)

10Note: We will have transmission-only and distribution-only entities participating in this survey. Their voltage levels will not necessarily line up with the above definitions.

Transmission classes >=45kV

(Phase to Phase) <69kV class (>=45kV <69kV) 69kV class (>=69kV <100kV) 100kV class (>=100kV <200kV) 200kV Class (>=200kV <300kV) 300kV Class (>=300 kV <400 kV) 400kV and above

Substation Definitions (cont.)

◼ Because our benchmarking is done at a relatively high level, we want to include transmission substations that have auto-transformers, but not AC/DC converter stations. While these components aren’t all directly measurable, nor are the MVA

calculations comparable, we want to recognize the existence of these units of property to make the benchmarking as comparable as possible.

◼ Customer-owned or dedicated substations are an issue in making comparisons. If customers own and maintain their own stations, the reporting option for this

questionnaire is clear – please exclude both the O&M costs and the capacity for those stations..

In the event that you maintain one or more customer-owned stations, the answer may be different. The preferred approach to responding to this portion of the questionnaire is to exclude the costs of the customer-owned stations, and exclude the capacity as well. However, if you cannot practically exclude them, then be sure that both the O&M costs and the capacity are included in all your answers.

◼ Small, pole-mounted or pad-mounted mini-substations (e.g. transformers, protective devices and a switch) should not be counted as distribution substations.

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Substation Transformer Nameplate rating

◼ Generally speaking, we want to measure transformers by MVA rating at normal operating conditions.

◼ Since utilities have different operating conditions and different manufacturers have different ratings, we will rely on each utility to report their own conditions. Use the number you report in FERC Form 1.

◼ We recognize that autotransformers may have a different set of conditions and that the comparison is imprecise, however, we think this is a better solution than leaving them out entirely.

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Financial – Overview of the Cost Model

Working with an adjusted FERC model

and the

Activity-Based Cost Model

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Financial Section Overview

◼ The Financial sections of the questionnaire (Sections DF and TF) ask for the costs of running the business, separated into Capital and O&M costs.

◼ There are two cost reporting systems: FERC: The overall cost model is based on the FERC system of accounts, with a

number of adjustments designed to make the cost reporting more consistent between the companies. Specific questions within the questionnaire ask for the data reported in individual FERC accounts, and then subsequent questions ask for the information required to make the desired adjustments.

ACTIVITY-BASED: The guiding principle of the activity cost model is to capture the expenditures associated with the year in which they were made, regardless of when they were actually reported to FERC. The activities also are more aligned with typical budgetary categories, such as New Business (capital) and Vegetation Management (O&M). While budget categories differ among utilities, we have developed a set of budget categories that most companies have been able to use.

◼ The Financial section also covers assets, depreciation and Construction Work In Progress (CWIP)

◼ Changes for 2015: Financial Matrix (FL): This is a new section that requests a breakdown of the activity costs reported in the DF and TF sections by major cost input categories (different types of labor, transportation costs, materials, etc.). This will require some additional effort on the part of the company subject matter experts who have furnished the data for sections DF and TF in the past

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Substations

General Plant FERC Costs

Transmission

Capital

Trans Lines

Exclusions

Trans Substations

O&M

Trans Lines

Exclusions

Trans Substations

Distribution

Capital

Dist Lines

Exclusions

Dist Substations

O&M

Dist Lines

Exclusions

Dist Substations

A&G

FERC: The ADJUSTED FERC COST MODEL

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Certain costs are excluded to provide fair comparisons that focus on operations (see next pages)

Substation costs need to be allocated from Transmission and Distribution accounts

FERC Exclusions: general

The goal of the exclusions is to provide a fairer comparison of T&D operational performance, by excluding certain costs that relate to demographic differences not under the control of T&D management. ◼ A&G costs: exclude costs typically reported as A&G (e.g. pensions and benefits) from

their O&M data.◼ General plant costs: exclude costs typically reported as General Plant (e.g.

IT/Communications infrastructure, capital cost of buildings) from their T&D Capital data.◼ Land acquisition costs or rents/leases: Although less common for distribution, land

acquisition costs vary greatly by region and also can occur at very different points in time, based upon land policies. Similarly, rents/leases are an alternative to ownership and have some of the same shortcomings from a benchmarking perspective.

◼ Extraordinary items: These can run the gamut and should be identified individually. To be considered "extraordinary", the O&M cost of the event or transaction should be more than 10% of budgeted T&D O&M expense less exclusions already noted. Major storms should be excluded as an extraordinary item if the total O&M spent on

the restoration (all O&M accounts combined) meets the above criteria. This is to account for the fact that some utilities utilize an “insurance reserve”, so that extraordinary storm expenses are charged to the “reserve” account, and are not “O&M” expenses. If your utility uses an “insurance reserve” account, you do not need to make any adjustment.

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FERC Exclusions: specific

Distribution◼ Do not include street lighting capital or expense costs. There is a large

variation of what street lighting exists in a service territory and what percent is owned and operated by the incumbent utility.

Substation ◼ If you have O&M expenses for which you are reimbursed, such as

maintenance done for customers, do not include them.

Transmission◼ Wheeling expenses: Generally, the transmission metrics are geared to

operational performance of the infrastructure. So while an argument could be made that wheeling is a substitute for system ownership, it may also be simply an economic arrangement to purchase incremental or low-cost power.

◼ Regional Transmission Operators: These costs vary between regions and many utilities don’t even incur these costs, so they should be excluded.

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Financials

DF50, DF55, TF45, TF50: the main set of answers for capital additions should be net of CIAC. Then the CIAC row should be a positive number and should be the total CIAC.

Example:

1QC to do analysis with and without CIAC18

This should be spending net of CIAC

This should be a positive number – the amount given as CIAC

FERC: CIAC

2. Electric Plant To Be Recorded at Cost.

A. All amounts included in the accounts for electric plant acquired as an operating unit or system, except as otherwise provided in the texts of the intangible plant accounts, shall be stated at the cost incurred by the person who first devoted the property to utility service. All other electric plant shall be included in the accounts at the cost incurred by the utility, except for property acquired by lease which qualifies as capital lease property under General Instruction 19. Criteria for Classifying Leases, and is recorded in Account 101.1, Property under Capital Leases, or Account 120.6, Nuclear Fuel under Capital Leases. Where the term cost is used in the detailed plant accounts, it shall have the meaning stated in this paragraph.

B. When the consideration given for property is other than cash, the value of such consideration shall be determined on a cash basis (see, however, definition 9). In the entry recording such transition, the actual consideration shall be described with sufficient particularity to identify it. The utility shall be prepared to furnish the Commission the particulars of its determination of the cash value of the consideration if other than cash.

C. When property is purchased under a plan involving deferred payments, no charge shall be made to the electric plant accounts for interest, insurance, or other expenditures occasioned solely by such form of payment.

D. The electric plant accounts shall not include the cost or other value of electric plant contributed to the company. Contributions in the form of money or its equivalent toward the construction of electric plant shall be credited to accounts charged with the cost of such construction. Plant constructed from contributions of cash or its equivalent shall be shown as a reduction to gross plant constructed when assembling cost data in work orders for posting to plant ledgers of accounts. The accumulated gross costs of plant accumulated in the work order shall be recorded as a debit in the plant ledger of accounts along with the related amount of contributions concurrently be recorded as a credit.

The actual expenditures, on the other hand, may or may not be net, depending on how the company accounting works.  When the company issues an invoice for the contribution, it should credit to the plant accounts when the invoice is issued, whether or not the invoice is ever collected, so the actual expenditures should also be net, unless they don ’t issue the invoice timely.  I believe that the way most companies do it, and the prudent business practice, would be to issue the invoice, and maybe collect it, before construction begins.

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FERC: T&D Capital Adjustments

◼ Each portion of the financial section asks for the key FERC accounts, and then asks for the information necessary to make the adjustments.

◼ Since FERC doesn’t capture Substations as a separate area, the blue arrow in the figure below (taken directly from the questionnaire) highlights how to move the FERC T or D cost to Substations.

◼ As noted on the preceding page, FERC costs are net of CIAC.

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FERC: T&D O&M Adjustments

For Line O&M expenses, the Substations expenses need to be removed from the overall O&M expenses (shown with the blue arrow). Other individual exclusions are identified as well.

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Exclude ISO and RTO charges.

ACTIVITY-BASED Cost Model: Capital

While FERC has the benefit of being a uniform system of accounts, there are several important shortcomings:◼ FERC capital spending lags behind actual spending and costs for large

projects go into a Construction Work in Progress (CWIP) account and are not transferred until the assets are placed into service, sometimes a several year lag.

◼ For those reasons, a simplified Activity-Based Costing system was developed to get current year spending by activity. The diagram on the following page depicts the Activity-Based approach.

For reporting purposes:◼ The total capital activity is intended to be the amount actually spent during

the year, not necessarily what was reported to FERC (and not necessarily the “adjusted FERC capital” reported in this survey); we believe that this eliminates some of the perturbations caused by changes in CWIP accounts.

◼ FERC capital accounts generally follow plant accounts and units of property (e.g. poles, towers, and fixtures) – not the typical reasons why utilities spend (e.g. new business)

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ACTIVITY-BASED Cost Model: O&M

◼ FERC O&M accounts tend to be more activity-oriented, but do not necessarily track important categories (e.g. vegetation management)

◼ While capital expenditures are split among several different processes from the overall process model, O&M expenses are almost entirely associated with sustaining or operating the network.

◼ Unlike Capital, we expect the O&M Expense should equal the amount reported as “Adjusted FERC”

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Activity-Based Cost Model

◼ The activity-based cost model breaks the expenditures into capital and O&M, and then splits them into the activities shown on the process model introduced above. The following pages provide more details of the individual activities for Transmission, Substations, and Distribution.

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Activity-Based Costs

Transmission Lines

Transmission Subs Distribution Subs Distribution Lines

Transmission Line Capital• Serve New• Expand• Sustain• Other • CIAC

T&D Substation Capital• Serve New• Expand• Sustain• Other• CIAC

Distribution Line O&M• Sustain• Other

T&D Substation O&M• Sustain the Network• Operate the Network• Other

Transmission Line O&M• Sustain the Network• Operate the Network

Distribution Line Capital• Serve New• Expand• Sustain• Other • CIAC

Activity-Based Costs: Transmission Lines

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Activity Based Costs – T&D Substations

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Activity Based Costs – Distribution Lines

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Assets, Depreciation, CWIP

The last series of questions in each Financial section asks about the FERC account values for the existing assets. These values are needed in order to determine asset replacement rates

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Safety

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Safety Reporting

Most of the statistics come directly from OSHA definitions (see www. OSHA.gov)

There are, however, some safety reporting issues:◼ Vehicular accidents – Most utilities report all reportable accidents, whether

preventable or not and regardless of fault. In general, we want utilities to include personal vehicles when used on company business.

◼ There are some differences in how utilities treat limited duty work, which will not be resolved as part of this benchmarking.

◼ Changes for 2015 New this year we’re asking for high-risk vehicle incidents: incidents where

there is an actual or credible potential injury to workers or third parties as a result of inattention, careless behavior or reckless operation of a vehicle.

There are also new questions requesting counts of Leading Indicators, and a new set of practice questions covering what companies are doing to comply with the new OSHA PPE and FR regulations relating to electric arc risk exposure.

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Where the Data comes from

Statistic Columns Used

Recordable Incidence Rate: Sum (G, H, I, J)

Non-Fatal “Incidence” Rate: Sum (H, I, J)

DART rate Sum (H & I)

Lost Time Severity Rate: K

Lost Work Day Case Rate aka (Lost Time Case Rate or Lost Time Incidence Rate)

Sum (G, H)

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All of the data should come from the OSHA form. We need total hours worked by all employees for normalization and the total numbers of each type of case, as well as the days away and days restricted totals.

Safety Question

We’re asking for raw data directly off your OSHA form for the safety stats. Within the question we calculate the safety rates we’ll be using on the performance profiles and in the report. We will also calculate these as part of the report. When on-line you may want to enter the calculated data in the appropriate fields so that both the on-line version and excel version match.

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Staffing & Support

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Staffing

Staffing FTEs:◼ Count all company employees assigned full time to a function, including

direct labor, supervision, administrative support and technical support◼ Also count contract employees who work in company offices and/or on

company facilities and who are directly supervised by company employees (see Glossary definition for “Contract FTE”)

◼ Add in partial counts for part-time employees (seasonal employees or employees who work less than 40 hours per week) and for full-time employees who split their time across different functions When calculating FTE value use 2080 hours per year as the denominator. When counting FTEs we don’t expect companies to get total number of

employee hours and divide that by 2080. We do expect companies to look at changes in head count throughout the year and use that information to adjust final headcount to get an estimate of actual FTEs. So a person working ½ the year is only ½ an FTE. A person working 20/hrs per week is ½ FTE.

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Staffing

◼ We do want you to adjust somewhat for overtime, if you have particularly high levels of overtime. So if you have a group of people working a lot of overtime (for your company, not as foreign crews for someone else) please factor that in because if they weren’t working overtime you’d have another FTE on staff.

◼ 50% guideline: Include a person in a function if they spend at least 50% of their time on that function. If a person divides their time so that they don't spend 50% on any single function, count them in the “Other” category.

◼ Engineering should include Engineering & Design◼ FTEs to exclude from staffing (SO12, SO15, SO20, SO25):

Meter Shop; Meter technicians; Meter Reading Distribution Shop (Transfomer Repairs, Rubber Goods Testing, Tool

Maintenance, etc.) Storerooms/Warehouse Fleet Land Management Street Light Maintenance (street light costs are excluded) Environmental Project Management

◼ Combined electric & gas distribution companies should prorate staffing in any of the functional areas that support both electric and gas, and exclude the gas portion in all four of the FTE count questions.  

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How are companies handling overtime?

Staffing

Changes for 2015: ◼ Companies are being asked to include “Contract FTE” (non-company employees who

work on company property and who are supervised by company employees) as well as their own full time employees in the functional staffing counts requested in questions SO12 through SO25.

◼ In question SO12, a new “Information Technology” function has also been added to capture the count of IT support people focused on T&D systems. To clarify the difference between WMS and Information Technology (both defined in the glossary): people with IT degrees and who do the computer programming-type work associated with Work Management Systems should be counted in the IT row while those who use the WMS to plan and schedule work and those who administer the WMS (e.g., deciding on and managing any changes that are needed to support changes in the work management process) should be counted in the WMS row.

◼ New questions regarding vacancy rates within the T&D organization, total utility company staffing, measures of employee engagement, labor utilization and employee training costs within T&D have been added.

◼ Due to the added questions, this section will require some additional effort by the company subject matter experts who have furnished data for this section in the past.

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Support

Inventory◼ Provide the portion of the value reported in FERC Account 154, "Plant Materials and

Operating Supplies", FERC Form 1, Page 110, line 48, column C, allocated by function as below

◼ We ask for Normal Inventory (Omitting storm stock, spares, power transformers, regulators, reclosers from inventory value) and Storm Stock and Major Construction Stock. Normal inventory is the key measure we are looking for.

◼ For our purposes, a “storeroom” is a facility where inventory materials are normally kept for charge-out and use by construction and maintenance forces.

Fleet◼ We have just selected a few key measures for Fleet. This section is not intended to

cover the entire fleet operations area◼ Vehicle counts should include both company owned and leased vehicles assigned to

T&D employees. Do not include vehicles assigned to anyone who is not included in your T&D staffing count in the Staffing section

Changes for 2015: ◼ New “Physical Security” subsection. Companies may need to identify a new subject

matter expert (e.g., from their Corporate Security Department) to answer those questions.

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Reliability

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Changes for 2015

◼ Emergency Response (ER): This section has been reorganized and renamed (it was titled “Storm Restoration [RP]” last year). The storm data questions (ER5 through ER31 in the core questionnaire and ER35 and ER55 in a Supplemental Questionnaire) are the same as in last year’s Storm Restoration/RP section. The process questions (ER100 through ER171) are almost identical to questions that were presented in the Distribution Reliability (DR) section last year. One new process question was added to capture information on company arrangements/contracts to provide housing for off-system crews during larger storm events.

◼ Distribution Reliability (DR): Emergency Response process questions which were presented at the end of this section last year have been moved to the above described Emergency Response (ER) section. Also, three new questions have been added in a new “Blue Sky Day Trouble Response” section (see the Glossary definitions for “Blue Sky Day” and “Trouble Call”). All of the other questions are identical to those in last year’s questionnaire.

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Distribution Reliability

Statistics◼ IEEE Standard 1366 has become the major guide for definitions on

distribution reliability. Though not every utility follows it exactly, some of the key issues identified by this standard include: Outage duration to be considered an interruption Definition of a major event (2.5 Beta Method) IEEE 1366-2012 can be purchased for download at:

• http://standards.ieee.org/findstds/standard/1366-2012.html There are still some reporting differences among utilities in terms of the

following: • Step restoration reporting• Level of reporting (are single services included)• Accuracy of estimates

◼ We will also calculate “mileage adjusted” SAIDI and SAIFI values, as well as CEMIx values (adjusted for each integer level)

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Distribution Reliability (cont)

Worst Circuit Performance◼ Many jurisdictions have introduced “worst circuit performance” measures. We have

asked questions around typical measures (e.g.“bottom 10%”), but do not cover all the possible variations.

◼ We also ask a few questions to highlight some of the adjustments to these measures (in particular low customer counts might skew the measures).

Outage Management System◼ We ask about OMS systems and features, along with enhancements utilities are

investing in to improve the restoration processes

Reliability Improvement Initiatives◼ Please take the time to provide brief but complete answers to recent improvement

initiatives that you have undertaken◼ Note that the T&D Strategy section questions ask about distribution automation and

smart grid initiatives; so you can reference them here, but do not duplicate.

Estimated Restoration Times◼ Customer research shows ERT’s are very important and that most utilities are

providing them under normal circumstances; please provide information on your experience with ERTs, both under normal conditions and in storm situations.

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Substation Reliability

Statistics◼ The impact of substation components on distribution reliability (customer interruption)

statistics is of interest. These include SAIDI and SAIFI. The Substation SAIDI and SAIFI here are from causes that originate “within the substation fence”. An example of this follows: A cable failure outside the substation occurs, the protecting feeder

breaker fails to trip due to a relay mis-operation, and the back-up device trips out the substation transformer, causing an interruption to the original feeder with the cable fault, as well as 3 additional feeders on the same transformer. The outage of the feeder with the cable failure is not counted in “substation” (its cause is “distribution equipment failure”), but the outage of the other 3 feeders is counted in “substation”.

◼ We also ask about the availability of substation transformers. ◼ We are asking for the “Percent Misoperation Rate” for relays as defined in a

document from IEEE/PSRC Working Group 13. The definition is included in the Glossary.

◼ The impacts of substation components on transmission line reliability measures are all included in the Transmission Reliability section.

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Substation Reliability

Reliability Improvement Initiatives◼ Please take the time to provide concise, complete answers to recent improvement

initiatives that you have undertaken◼ Note that the T&D Strategy section questions ask about substation automation

initiatives; so you can reference them here, but do not duplicate.◼ We recognize that Transmission-only organizations may not have detailed

customer interruption data — so leave questions related to SAIDI and SAIFI blank. ◼ In general, we follow the TADS instructions. For most companies, the “element” is

at the “transmission line” level, since most of our companies do not have 200kV low-side equipment.

Changes for 2015: ◼ The one question that has been added at the end of this section was presented in

the Substation Practices (SP) section last year. Otherwise, this section is identical to the corresponding section of last year’s questionnaire.

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Transmission Line Reliability

Statistics◼ In general, for transmission lines, we are interested in availability, as impacted by

sustained outages that may or may not have an impact on an end-use customer. ◼ We ask for raw data on outages by voltage class. We have aligned the definitions

with TADS for all voltages (even though TADS only applies to 200kV and above) Cause codes for all voltages based upon TADS Cause code definitions are in the glossary, or at

http://www.nerc.com/docs/pc/tadswg/Appendix%207%2020101202a%20clean.pdf “Automatic” operation replaces the terminology “unplanned” (with minor impact on

the values)◼ Those codes that are “substation related” will be reported in transmission lines, but

also in the substation section of the final report◼ For Transmission reliability the term “outage” refers to a ‘component’ or line outage

(most of which may not have any customer impact).  For instance, you might have had 10 transmission component outages last year but only 3 of them resulted in an outage to a customer.

◼ See the glossary for definitions of “automatic” and “non-automatic” outages

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Transmission Line Reliability

TADS Measures◼ The TADS framework (first used in 2008) introduced some slightly new and

different terminology, and has evolved some over the past couple of years. Elements are defined to be transmission circuits of 200kV and above, and

include AC/DC lines. For purposes of this survey, we are only interested in AC lines. Automatic outages replace the more common unplanned outages, and

have a few distinctions. Mileage adjusted measures are introduced TADS metric definitions can be found at http

://www.nerc.com/docs/pc/tadstf/TADS_Phase_II_Final_Report_091108.pdf

Reliability Improvement Initiatives◼ Please take the time to provide concise, complete answers to recent

improvement initiatives that you have undertaken◼ Note that there may be some overlap with the T&D Strategy section, which

asks questions about automation initiatives and technology upgrades

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Emergency Response

Data Reported via NOVI Tool (Core Questionnaire)

Summary Information: For all storm events that interrupted >1% of total customers:◼ Count of storm events by size range◼ Average Storm CAIDI for events in each size range

Detailed Information: For all storm events that interrupted >10% of total customers: ◼ Descriptive information◼ Customers out at peak and total customers interrupted◼ Time of peak customer outages◼ Total hours to restore◼ Poles replaced◼ Total restoration cost (capital and O&M combined)◼ Weather conditions and/damage descriptions◼ Field staffing information

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Emergency Response (Continued)

Data Reported on Supplemental Tab (Excel File) ◼ Use the Excel File to report the following additional data for storm events

that interrupted >10% of customers: Hour by hour counts of customers still out Hour by hour restorations

Instructions:◼ All data entry should be done on the Supplemental Tab in the Excel file◼ After entering data, check the protected sheets labeled “Storm 1, “Storm

2”, etc., to verify that that the entered data produced a logical set of restoration curves (see example on next page)

Send completed Excel file to Dave Carter at [email protected]

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Emergency Response (Continued)

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ER35 responses

Accumulated ER55 responses

Calculated Values (Accumulated ER55 responses + ER35 responses)

(Time line was manually adjusted so that Hour 0 = Hour of Peak Customers Out)

Example Restoration Curves

Strategy, Asset Management, Capital Project and Portfolio Management and

Practice Sections

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Guidelines for Responses

In the strategy, asset management, capital project/portfolio management and practice sections of the questionnaire, there are many open-ended questions, in which we are looking for insights about how you operate. Your answers should be:◼ Brief and succinct – so that the reader will not need to read through an extensive

volume of material to understand the message; ◼ Anonymous: don't mention your company name or other company identifying

information (e,g. city or state names) in your replies◼ Complete enough to be understood in terms of the practice you are describing◼ Practically speaking, this translates to 2-3 sentence answers to most of the text

questionsFor our purposes:◼ Practices are current activities, programs or processes that have been around for a

while. For these, sufficient time has passed in which to assess their success or failure. We mostly ask about practices that have proven successful in accomplishing a specific goal.

◼ Initiatives are new activities, programs or processes that have been enacted recently with the goal of improvement. These are so recent (1 to 2 years) that insufficient time has passed in which to assess their success.

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Develop System Strategy

Develop and Approve Asset Plans

Project/Portfolio Management

Expand System

A Process Model for Managing the T&D Business

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The T&D benchmarking survey is built around a process model of the T&D business. This model helps in analysis of the performance and practices of the member utilities, and gives a framework for deeper investigation.

Operate System

Sustain System

Indicates separate D, S, T components

Add New Customers

Respond to Emergencies

T&D Strategy, Asset Management and Capital Portfolio & Project Management

◼ T&D Strategy (SG): This is a new section that consolidates strategy questions that were presented in the Distribution Practices (DP1), Substation Practices (SP) and Transmission Practices (TP) sections last year. A few new questions have been added and a roughly equal number of existing questions have been deleted.

◼ Asset Management (AM): This is a new section that consolidates the asset management questions that were presented in the Distribution Practices (DP1), Substation Practices (SP) and Transmission Practices (TP) sections last year. A few existing questions have been deleted and several identical questions that were in the previous separate practice sections about asset management roles and responsibilities, concerns, software tools and use of life cycle costing concepts have been consolidated into a smaller set of questions that encompass distribution, substations and transmission. Also, check-off lists have been added to several of the questions to make it easier for the subject matter experts to quickly respond.

◼ Capital Projects and Portfolio Management (CP): Several new questions have been added about the capital workplan development phase. In the workplan execution phase, several questions requesting information on KPI’s used to measure overall project and program success have been added.

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Practice Sections

◼ Distribution Practices (DP1): New questions have been added in each of the process subsections (Planning/Engineering/Design, Construction, etc.,) to better flesh out our understanding of how companies carry out these processes. It is likely that all of these new process-related questions can be answered by the same subject matter experts who submitted responses for the various process subsections last year.

◼ Distribution New Business (DP2): Changes have been to sharpen up comparisons of timing response on new service installation requests.

◼ Substation Practices (SP): We’ve reorganized this section and added new questions that may require the identification of new company subject matter experts. Note in particular the series of questions presented in the “Serve New and Capacity Additions” and “Construction Contractor Performance Management” subsections.

◼ Transmission Practices (TP): We’ve reorganized this section and added new questions that may require the identification of new company subject matter experts. Note in particular the series of questions presented in the “Serve New and Capacity Additions”, “Construction Contractor Performance Management” and “Customer Interconnection Practices” subsections. Also, several new questions have been added to the existing Transmission Operations Center (TOC) subsection.

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Distribution Practices

This section is organized around the following topics:◼ Expand System:

Distribution Line Planning/Engineering/Design Distribution Line Construction

◼ Sustain System: Equipment Maintenance: Inspection programs, maintenance practices,

staffing approaches, grid hardening Vegetation Management: Trim cycles, methods, and improvement

initiatives Work Management Quality Management: Approaches to measurement and improvement of

quality ◼ Operate System:

Challenges, improvement initiatives, Distribution management system◼ Customer Satisfaction:

JD Power Surveys and Customer Experience◼ Add New Customers

New Business (DP2): approach, process, cost and staffing scenarios

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Substation Practices

This section is organized around the following topics:

Expand System: ◼ Planning/Engineering/Design – Improvement initiatives and changes to

standards ◼ Serve New / Capacity Additions◼ Construction Contractor Management

Sustain System:◼ Maintain the System:

Field Maintenance Activities – Initiatives underway, degree of crew specialization, and work management systems, Inspections, impact of deferred maintenance, initiatives to reduce outages

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Transmission Line Practices

This section is organized around the following topics:New Customers:◼ Customer Interconnection Practices

Expand System:◼ Planning/Engineering/Design: Improvement initiatives and changes to

standards◼ Construction Practices◼ Contractor Productivity – Challenges, measures and initiatives

Sustain System:◼ Maintenance – Regulatory drivers, Inspections◼ Right of Way – Growth inhibitors, ROW uses, challenges and practices.◼ Work Management Systems – WMS Vendor and efforts to improve

usefulnessOperate System:◼ Transmission Operations Center (TOC) – Changes and challenges.

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Corporate Offices

400 Continental Blvd. Suite 600El Segundo, CA 90245(310) 426-2790

New York | Maryland | Texas | Wyoming | Wisconsin

First Quartile Consulting is a utility-focused consultancy providing a full range of consulting services including continuous process improvement, change management, benchmarking and more. You can count on a proven process that assesses and optimizes your resources, processes, leadership management and technology to align your business needs with your customer’s needs.

Visit us at www.1stquartileconsulting.com | Follow our updates on LinkedIn

About 1QC

Satellite Offices

Debi [email protected]

David [email protected]

Dave [email protected]

Dave [email protected]

Your Presenters

Ken Buckstaff [email protected]

Thank You for Your Input and Participation!

Example Results

Statistical Report and Analysis

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Example Metrics Comparisons – Distribution cost

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This page is one of many in the statistical report.

The basic format includes the graph, showing relative position of each company, a listing of the mean and quartile values, any comments needed to clarify the graph, and the calculation used for the graph.

This page is one of many in the statistical report.

The basic format includes the graph, showing relative position of each company, a listing of the mean and quartile values, any comments needed to clarify the graph, and the calculation used for the graph.

Example Functional Area Cost Comparison

For each major subject area, there are cost and service level metrics. Costs are provided per customer and per unit. Service levels depend on the specific subject area.

For each major subject area, there are cost and service level metrics. Costs are provided per customer and per unit. Service levels depend on the specific subject area.

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Example Demographic Comparison

A variety of demographic variables are tracked, to enable analysis of performance based on company demographics

A variety of demographic variables are tracked, to enable analysis of performance based on company demographics

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Organization/Operational Practice Example

Operational and organizational practices were tracked and summarized in a variety of different ways, helping companies to understand their practices in relation to other companies in the community.

Operational and organizational practices were tracked and summarized in a variety of different ways, helping companies to understand their practices in relation to other companies in the community.

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Example Open-Ended Question Responses

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Many areas of the questionnaire focus on practices and initiatives, with the goal of getting concise but descriptive responses.

Many areas of the questionnaire focus on practices and initiatives, with the goal of getting concise but descriptive responses.

Example Summary from Insights Conference

Various findings from the survey program are assembled for discussion during the Insights conference.

These typically focus on practices and demographics among the companies in the community

Various findings from the survey program are assembled for discussion during the Insights conference.

These typically focus on practices and demographics among the companies in the community

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