data collection guide
DESCRIPTION
2014 Electric T&D Benchmarking. Data Collection guide. 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 - PowerPoint PPT PresentationTRANSCRIPT
Data Collection guide
2014 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.
2
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 RP: Storm Response DP. Distribution Practices (Parts 1 and 2) SP. Substation Practices TP. Transmission Line Practices
3
Dist Subs Trans T&DPlanning, Engineering, Design X X X
Field Operations & Maintenance X X X
New Business Capital X X X
Field Construction X X X
Distribution Dispatch X
Vegetation Management X X
Staffing & Outsourcing X X X
Energy Control Center X
Support (inc: Inventory, Fleet)
X
Core Areas to Survey Annually
Each year, the core subjects are investigated through the survey:
4See Guidelines for detailed definition of terms
Develop Network Strategy
Develop and Approve Asset Plans
Project/Portfolio Management
A Process Model for Managing the Network
5
Expand Network
Operate Network
Sustain Network
Add New Customers
Respond to Emergencies
We have begun structuring the benchmark survey around a process model for managing the energy delivery network. This appears in the cost model and in the practices areas of the questionnaire.
Example Results
Statistical Report and Analysis
6
Example Metrics Comparisons – Distribution cost
7
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.
8
Example Demographic Comparison
A variety of demographic variables are tracked, to enable analysis of performance based on company demographics
9
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.
10
Example Open-Ended Question Responses
11
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
12
Statistics and System Activity
13
Purpose of the Section
The purpose of this section of the questionnaireire is twofold: to gather statistical information about the existing electric system, and then to gather further information about activities during the year that affect the system and the company.
The statistical section gathers a variety of demographic information that describes each company's system in terms of 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.
The system activity portion of the questionnaire is designed to identify work load drivers associated with activity. There are a variety of questions designed to understand the amount of capital activity as well as things that are done for O&M.
14
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 5kV class (>1kV, <=9kV) 15kV class (>9kV, <=15kV) 25kV class (>15kV to <=26kV) 35kV class (>26kV to <=36kV) 44kV class (>36kV to <=44kV)
15
Transmission classes >=45kV <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 DefinitionsFERC provides definitions on what constitutes a Transmission vs. Distribution substation based upon use.
For multipurpose substations, FERC allows either segregating costs, or assigning 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.
We understand that a typical Canadian practice would be to define a substation based upon high side voltage (e.g. 115kv to 12kv stations are defined as transmission). Based upon predominant use, these still can be classified as transmission substations. 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.
16
Distribution Voltage Classes:5kV (>1kV, <=9kV)15kV (>9kV, <=15kV)25kV (>15kV, <=26kV)35kV (>26kV, <=36kV)44kV )>36kV, <=48kV)
Transmission Voltage Classes:<69kV69kV class (>=69kV <100kV)100kV class (>=100kV <200kV)200kV Class (>=200kV <300kV)300kV Class (>=300kV <400kV)400kV and above
Note: We will have transmission-only and distribution-only entities participating in this survey. Undoubtedly their voltage levels will not necessarily line-up with the above definitions.
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 mini-substations (e.g. transformers, protective devices and a switch) should not be counted as substations.
17
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.
18
System Activity Questions
The purpose of this section is to identify work load drivers associated with activity. We ask for capital unit additions and selected O&M activities for the year. The goal is to understand the major drivers of work, not to capture all of the individual work activities.
The questions are separated into Distribution Lines, Substations, and Transmission Lines
19
Financial – Overview of the Cost Model
Working with an adjusted FERC model
and the Activity-Based Cost Model
20
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. We also further ask companies to allocate costs to Substations. There are two alternative 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 reported to FERC, separated by Distribution and Transmission. We also ask companies to allocate assets between lines and substations. Construction Work In Progress (CWIP) is also covered in this section.
21
FERC: Specific Adjustments
The following page is a schematic of how basic FERC cost data will be adjusted for this benchmarking study. ● A&G costs will be excluded – Utilities are asked to adjust their costs to exclude costs typically
reported as A&G (e.g. pensions and benefits) from their O&M data.● General plant costs will be excluded – Utilities are asked to adjust their costs to exclude costs
typically reported as General Plant (e.g. IT/Communications infrastructure) from their T&D Capital data.
● Other T&D Capital exclusions: Transmission: Land acquisitions and extraordinary items Distribution: Land acquisitions, street lighting and extraordinary items
● Other O&M exclusions: Transmission: Wheeling, Rents/Leases, IT costs, extraordinary items. If you charge IT
support to account 569, you should exclude it. Regional Market Expenses (Accts 575, 576). Distribution: Streetlight Maintenance, Rents/Leases, IT costs, extraordinary items. If you
charge IT support to Distribution O&M accounts, you should exclude it. If you normally charge R&D, such as EPRI dues, to O&M, include it, unless it is an
unusually large amount for this year● Substation costs will be allocated from Transmission and Distribution accounts, and similar
adjustments made. 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.
22
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
FERC provides a general framework Certain costs must be excluded to provide fair comparisons that focus on operations Substation costs must be separated out, including certain allocations
23
FERC: Rationale for Exclusions - Distribution Do not include 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. 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. Do not include extraordinary items. These can run the gamut and should be identified individually. Storm costs should be excluded if they are outside your “normal” experience. 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.
24
FERC: Rationale for Exclusions - Transmission
If you have O&M expenses for which you are reimbursed, such as maintenance done for customers, do not include them. Do not include land acquisition costs or rents/leases. 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. Do not include 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. Do not include extraordinary items. These can run the gamut and should be identified individually. Storm costs should be excluded if they are outside your “normal” experience. 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.
25
FERC: Rationale for Exclusions - Substation
Do not include land acquisition costs or rents/leases. 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. Do not include extraordinary items. These can run the gamut and should be identified individually. Storm costs should be excluded if they are outside your “normal” experience. 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.
26
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.
27
FERC: Distribution 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. In the figure below (taken directly from the questionnaire), the blue arrow highlights the value to insert for the exclusion, if it isn't already clear. As noted on the preceding page, FERC costs are net of CIAC.
28
FERC: Distribution O&M Adjustments
For Distribution Line O&M expenses, the Substations expenses need to be removed from the overall Distribution expenses (shown with the blue arrow). Then individual exclusions are identified as well.
29
FERC: Transmission 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. In the figure below (taken directly from the questionnaire), the blue arrow highlights the value to insert for the exclusion, if it isn't already clear. As noted on page 25, the FERC costs are net of CIAC.
30
FERC: Transmission O&M Adjustments
For Transmission Line O&M expenses, the Substations expenses need to be removed from the overall Transmission expenses (shown with the blue arrow). Then individual exclusions are identified as well.
31
ACTIVITY-BASED Cost Model
While FERC has the benefit of being a uniform system of accounts, there are several important shortcomings:• FERC capital spending lags behind actual spending; 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.
• 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)
• FERC O&M accounts tend to be more activity-oriented, but do not necessarily track important categories (e.g. vegetation management)
For those reasons, a simplified Activity-Based Costing system was developed to get current year spending by activity. The following diagram depicts the Activity-Based approach
32
Activity-Based Cost Model
33
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
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 3 pages provide more details of the individual activities for Transmission, Substations, and Distribution.
Activity Based Costs – Transmission Lines
While capital expenditures are split among several different processes from the overall process model, O&M expenses are almost entirely associated with sustaining the network.
34
Transmission Line Capital• Serve New: Extension to new customers
or utility substations [Industrial/Generation/Wholesale]
• Expand: Capacity Additions (Adding additional lines to existing substations, increasing capacity of existing lines)
• Sustain: Replace/Repair in kind• Sustain: system improvements
(reliability/efficiency)• Sustain: Service Restoration• Sustain: Line Relocations• Sustain: Transmission Operations Center• Sustain: Asset Retirement Costs for
Transmission Plant (FERC 359.1) • Other • CIAC
Transmission Line O&M• Inspection and Maintenance
Expense (except 569.1-4)• ROW/Vegetation Management • Service Restoration• Transmission Operations Center• Engineering/Design O&M
(including FERC 561.5-8)• Other
Activity Based Costs - Substations
35
T&D Substation Capital• Serve New: New Substations and
new substation capacity to serve specific new customer requests
• Expand: Capacity Additions to meet generic load growth
• Sustain: Repair/replace-in-kind• Sustain: system improvement
(reliability/efficiency, system hardening, physical security)
• Sustain: Service Restoration• Sustain: Mobile/Spare Transformer
Purchases• Other• CIAC
T&D Substation O&M• Inspection & Maintenance• Service Restoration• Distribution Operations
Center• Engineering/Design O&M
(Planning studies, standards, mapping)
• Other
While capital expenditures are split among several different processes from the overall process model, O&M expenses are almost entirely associated with sustaining the network.
Activity Based Costs – Distribution Lines
Almost all of O&M is considered to be work designed to “sustain the network” or “operate the network”.
Capital work is split among adding new customers, expanding the system, and sustaining the network
36
Distribution Line O&M• Inspection & Maintenance (planned
or unplanned not associated with service restoration)
• Vegetation Management • Service Restoration• Distribution Operations Center• O&M associated with capital work• Engineering/Design O&M (Planning
studies, standards, mapping)• Damage Prevention/Facility
Locating• Field Switching• Meter Expenses (O&M)• Transformer Expenses (O&M)• Other
Distribution Line Capital• Serve New: Extension to new distribution customers• Expand: Capacity Additions (adding additional lines,
increasing capacity of existing lines)• Sustain: System improvement (reliability/efficiency
including distribution automation, feeder hardening, worst circuits, etc.)
• Sustain: Replace/Repair in kind (not including meters & transformers)
• Sustain: Service Restoration• Sustain: Line Relocations• Sustain: Distribution Operations Center• Sustain: Meter Purchases (including AMS investment)• Sustain: Transformer Purchases• Other • CIAC
Activity-Based: Distribution Capital Activities
In order to better understand your capital spending, we ask that the capital figures be allocated in accordance with a specified list of activities.
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.
37
Activity-Based: Distribution O&M
As is done with Capital, we ask that the O&M figures be allocated in accordance with a specified list of activities.
Unlike Capital, we expect the O&M Expense should equal the amount reported as “Adjusted FERC”
38
Activity-Based: Transmission Capital
In order to better understand your capital spending, we ask that the capital figures be allocated in accordance with a specified list of activities.
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.
39
Activity-Based: Transmission O&M
As is done with Capital, we ask that the O&M figures be allocated in accordance with a specified list of activities.
Unlike Capital, we expect the O&M Expense should equal the amount reported as “Adjusted FERC”
40
Distribution Assets
The last series of questions in the Distribution Financial section asks about the FERC account values for the existing assets. These values are needed in order to determine asset replacement rates
41
Transmission Assets
The last series of questions in the Transmission Financial section asks about the FERC account values for the existing assets. These values are needed in order to determine asset replacement rates
42
Safety, Staffing & Support
43
Safety ReportingMost 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. The “DART” (Days Away, Restricted or Transferred) rate is a standard OSHA statistic. The OSHA definition is included in the Glossary.
44
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.
45
StaffingStaffing FTE:
Count all company employees assigned full time to a function, including direct labor, supervision, administrative support and technical support 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. 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.
Outsourcing Percentages: Estimate and report the percent of the total direct labor work for each functional area that was performed by contractors rather than company employees. You may use different methods to estimate these outsourcing percentages such as % of total labor hours, % of total miles built, etc.. There are text questions in the survey that ask you to identify the method(s) used.
46
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
47
Reliability
48
Distribution ReliabilityStatistics
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)
49
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 processesReliability Improvement Initiatives
Please take the time to provide brief but complete answers to recent improvement initiatives that you have undertaken
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.
Emergency Response Time
50
Substation Reliability (Cont)Reliability Improvement Initiatives
Please take the time to provide concise, complete answers to recent improvement initiatives that you have undertaken Note that the substation practice area 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.
51
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.
52
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
53
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.pdfReliability 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 Transmission and Substation practices sections, which ask questions about the intelligent grid.
54
Storm Restoration
55
Storm Restoration
56
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
Storm Restoration
57
Data Reported on Supplemental Questionnaire (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 first sheet 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]
Storm Restoration
58
RP35 responses
Accumulated RP55 responses
Calculated Values (Accumulated RP55 responses + RP35 responses)
(Time line was manually adjusted so that Hour 0 = Hour of Peak Customers Out)
Example Restoration Curves
Practice sections
59
Initiatives vs. Practices
In many areas of the questionnaire, there are open-ended questions, in which we are looking for insights about how you operate. Answers should be:
Brief and succinct – so that the reader doesn't need to read through an extensive volume of material to understand the message; because the responses will be printed verbatim, don't mention your company name or individual 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.
60
Distribution Practices
This section is organized around the following topics: Distribution Automation Strategy Metering – performance metrics, smart metering Asset Management – Role of asset management, problematic equipment,
replacement programs, inspection and maintenance programs. Quality Management – Approaches to measurement and improvement of quality New Business – approach, process, cost and staffing scenarios Network Expansion – Design, standards, construction, construction productivity Vegetation Management – Trim cycles, methods, and improvement initiatives Replacement Planning, Execution – maintenance practices, staffing approaches, grid
hardening, resiliency initiatives Distribution Operations Center – Challenges, improvement initiatives, Distribution
management system Customer Satisfaction –JD Power Surveys and Customer Experience
61Note: Please keep your answers to open-end questions concise but complete. We would like one or two sentences, not extended explanations
Substation Practices
This section is organized around the following topics: Strategy – Mobiles/Spares Asset Management – RCM and Life cycle costing approaches; replacement
programs, and problematic equipment Capacity Expansion -- Planning/Engineering/Design –Changes to standards Substation Automation – Technology and initiatives underway Job Estimating – Software tools and role of construction Mobiles/Spares – Deployment of mobiles and spare, and optimization techniques Field Maintenance Activities – Initiatives underway, degree of crew specialization,
and work management systems Maintenance – Inspections, impact of deferred maintenance, initiatives to reduce
outages
62Note: Please keep your answers to open-end questions concise but complete. We would like one or two sentences, not extended explanations
Transmission Line Practices
This section is organized around the following topics: Strategy – Transmission Automation Asset Management – Role of Asset Management, replacement programs, and
problematic equipment Planning/Engineering/Design – Improvement initiatives and changes to standards Contractor Productivity – Challenges, measures and initiatives Right of Way – Growth inhibitors, ROW uses, challenges and practices. Transmission Lines Field Activities – facilities, improvement initiatives Work Management Systems – WMS Vendor and efforts to improve usefulness Maintenance – Regulatory drivers, Inspections Transmission Operations Center (TOC) – Changes and challenges. NERC Standards – Impact of NERC standards on transmission organizations,
especially Critical Infrastructure Protection (CIP), Protection and Control (PRC), and Facilities Design (FAC).
63Note: Please keep your answers to open-end questions concise but complete. We would like one or two sentences, not extended explanations
64
Corporate Offices
California
400 Continental Blvd. Suite 600El Segundo, CA 90245(310) 426-2790
Maryland
3 Bethesda Metro Center Suite 700Bethesda, MD 20814(301) 961-1505
New York | Texas | Washington | 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 McLain [email protected]
Tim. [email protected]
Dave [email protected]
Dave [email protected]
Your Presenters
Ken Buckstaff [email protected]
Thank You for Your Input and Participation!