Web view · 2016-06-17LAR Data Collection Manual: Section 1 — Excel Workbook5. LAR...

2016 Loads and Resources Data Collection ManualWECC Staff

January 2016

155 North 400 West, Suite 200

Salt Lake City, Utah 84103-1114

LAR Data Collection Manual ii

Contents

Introduction...............................................................................................................................................1

Reporting Responsibility........................................................................................................................1

Balancing Authority Responsibility....................................................................................................2

Non-Balancing Authority Entity Responsibility..................................................................................2

Manual Overview.................................................................................................................................. 2

NERC Long-Term Reliability Assessment and Special Assessment, and WECC Seasonal Assessment Information Requirements....................................................................................................................2

Data Confidentiality...............................................................................................................................3

Data Submission....................................................................................................................................3

LAR Data Contacts................................................................................................................................. 4

Reliability Assessment Work Group.......................................................................................................4

Questions or Comments........................................................................................................................4

Section 1 — Excel Workbook.....................................................................................................................5

Workbook Structure..............................................................................................................................5

Time Zone Reporting............................................................................................................................. 6

Data Reporting.......................................................................................................................................6

Data Checking........................................................................................................................................6

Data Error and Need for Clarification....................................................................................................7

Section 2 — Existing and Planned Generation Reporting Instructions......................................................8

Data Reporting Process......................................................................................................................... 8

Existing Generation and Generation Additions Data: Facility Record Format.....................................10

Section 3 — Input Guide for Peak Demand, Demand-Side Management, Energy Loads, and Resource Outage Instructions................................................................................................................................. 19

Load Data (Codes 1, 2, and 3)..........................................................................................................20

Unavailable Capability Data ............................................................................................................22

Actual Peak Demand Loads, DSM, Outage Data, and Distributed Generation Code Definitions.........23

W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L

LAR Data Collection Manual iii

Estimated Peak Demand Loads, DSM, Outage Data, Distributed Generation, Energy Efficiency, and Standby Demand Code Definitions......................................................................................................24

Actual and Estimated Peak Demand Loads Coding Data Record Format.............................................26

Energy Load Instructions..................................................................................................................... 27

Actual and Estimated Energy Loads Coding Data Record Format........................................................27

Section 4 — Reliability and Supply Assessments.....................................................................................28

Actual Generation................................................................................................................................28

Transfer Path Capabilities....................................................................................................................29

Transfer Path Capabilities Coding Data Record Format.......................................................................29

Regulating Reserves.............................................................................................................................30

Section 5 — Miscellaneous Data............................................................................................................. 31

Hourly Demand....................................................................................................................................31

Hourly Hydro Production.....................................................................................................................32

Hourly Wind Production......................................................................................................................33

Hourly Solar Production.......................................................................................................................33

Projected Transmission Line Additions................................................................................................34

Projected Transformer Additions........................................................................................................ 39

Appendix A — Modeling Area to Zones.....................................................................................................1

Appendix B — Glossary for LAR Data Collection Manual...........................................................................1

Appendix C — WECC Balancing Authorities...............................................................................................1

State/Province Abbreviations................................................................................................................2

Appendix D — WECC Criteria for Uniform Reporting of Generator Ratings..............................................1


LAR Data Collection Manual 1

Introduction

The Western Electricity Coordinating Council (WECC) Data Collection Manual (Manual) provides instructions for reporting various loads and resources information that WECC requests from all Balancing Authorities (BA) in the Western Interconnection. The information is used for a variety of analytic activities and reporting purposes. Portions of the WECC Loads and Resources (LAR) information are used by the North American Electric Reliability Corporation (NERC) in reliability assessment reports.1 The information is also the basis for the resource adequacy evaluation contained in WECC’s State of the Interconnection2 report and Power Supply Assessment (PSA).3

Portions of the information are reported by NERC to the U.S. Department of Energy’s (DOE) Energy Information Administration (EIA) in satisfaction of its Form EIA-411 filing requirements.4 Annual filings are submitted to NERC under NERC’s Standards and Guides compliance templates, according to NERC Rules and Procedure Section 800.5

Reporting Responsibility

Pursuant to the WECC bylaws section 2.1.6 and 4.6.116, as outlined in the WECC Information Reporting Policy – Exhibit A7, it is required that WECC BAs, Load-Serving Entities (LSE), or other WECC Members provide, and update as necessary, the data listed below:

Actual year hourly demand data; Existing generation; Planned generation; Projected and actual demand reduction data; Projected peak demand; Projected energy forecasts; Scheduled peak hour outages; Actual year peak hour outages; Other data collected in support of the annual WECC PSA and Seasonal Assessments, and the

NERC Long Term Reliability Assessment (LTRA).

1 NERC Reliability Assessments: http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx 2 WECC State of the Interconnection reports: https://www.wecc.biz/ReliabilityAssessment/Pages/State-of-the-Interconnection.aspx3 WECC Reliability Assessments: https://www.wecc.biz/ReliabilityAssessment/Pages/Default.aspx 4 Form EIA-411 Data: http://www.eia.gov/electricity/data/eia411/ 5 NERC Rules of Procedure: http://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx 6 WECC Bylaws: https://www.wecc.biz/Corporate/WECC Bylaws.pdf 7 WECC Information Reporting Policy: https://www.wecc.biz/Corporate/Information Reporting Policy_06-25-14.pdf


https://www.wecc.biz/Corporate/Information%20Reporting%20Policy_06-25-14.pdf

https://www.wecc.biz/Corporate/WECC%20Bylaws.pdf

http://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx

http://www.eia.gov/electricity/data/eia411/

https://www.wecc.biz/ReliabilityAssessment/Pages/Default.aspx

https://www.wecc.biz/ReliabilityAssessment/Pages/State-of-the-Interconnection.aspx

https://www.wecc.biz/ReliabilityAssessment/Pages/State-of-the-Interconnection.aspx

http://www.nerc.com/pa/RAPA/ra/Pages/default.aspx


Balancing Authority Responsibility

The LAR information is for the entire Balancing Authority Area (BAA) including both member and nonmember entity and is to include the BA’s information as well as the information for all non-BA entities within the BAA. The non-BA entity information includes planning information such as generation additions, load forecasts of LSEs, and scheduled maintenance outages. The non-BA entities are responsible for reporting their organizations’ information to the BA and for developing appropriate data collection procedures to ensure that all requested information is provided to the appropriate non-BA entities and that there is no duplication or double reporting of the information. In developing its actual and forecast demand values, each LSE shall count peak demand and energy load only one time on an aggregated and dispersed basis. The demand, net energy for load, and controllable Demand-Side Management (DSM) supplied for this data collection request shall be consistent with the demand, net energy for load, and controllable DSM supplied in response to the eleven annual Power Flow Base Case data requests.

Non-Balancing Authority Entity Responsibility

Non-BA entities are responsible for responding to BA requests for planning information such as generation additions, load forecasts, and scheduled maintenance outages.

Non-BA entities may designate reporting contacts within their organizations. The designated reporting contacts will be asked to provide the requested information to the WECC staff by the established due date and to answer questions that may arise concerning that information.

Manual Overview

This Manual consists of five main sections and four appendices. Section 1 – Excel Workbook consists of an explanation of pages and terms found in the Excel workbook. Section 2 – Existing and Planned Generation Reporting Instructions and Section 3 – Peak Demands, Energy Loads, and Resource Outages Instructions contain directions for the input of the described data. Section 4 – Reliability and Supply Assessments and Section 5 – Miscellaneous Data contain the reporting instruction for data used to improve the accuracy and performance of the production model and to satisfy NERC’s Form EIA-411 filing.

NERC Long-Term Reliability Assessment and Special Assessment, and WECC Seasonal Assessment Information Requirements

The LTRA data is primarily gathered through the WECC LAR data requests. Additional information and/or narrative questions for the NERC LTRA and Special Assessments, as well as the WECC Seasonal Assessments may be requested from the BAs in a separate data request.



Data Confidentiality

The WECC Reporting Policy8 and the WECC Information Sharing Policy9 addresses the confidentiality procedures for LAR data.

The following information shall be Public Information under the WECC Information Sharing Policy and not restricted.

Existing generation list Planned generation list Projected peak demand (years 4-10) Projected energy forecasts (years 4-10) Scheduled peak hour generation outages (years 4-10) Actual year peak hour generation outages

The following types of information are considered Transmission Function Information under the FERC Standards of Conduct and may also be Confidential Information under Section 1500 of the NERC Rules of Procedure or the WECC Confidentiality Policy. This information may only be shared with persons (1) in accordance with the FERC Standards of Conduct, (2) who, at the discretion of WECC, have demonstrated a legitimate need, and (3) who have executed an NDA.

Projected peak demand (years 1-3) Projected energy forecasts (years 1-3) Scheduled peak hour outages (years 1-3)

The following information shall be Information Not Shared Externally and may be Confidential Information under Section 1500 of the NERC Rules of Procedure or the WECC Confidentiality Policy, Transmission Function Information under the FERC Standards of Conduct or otherwise restricted. Due to the nature of this information and/or any applicable restrictions, this information may not be shared externally. The WECC CEO can approve exceptions allowing for the sharing of this data unless otherwise prohibited.

Actual year hourly demand data (collected under the Information Reporting Policy)o WECC may make this information public when it has been made public by FERC

Data Submission

The data must be submitted to WECC by the first Friday of March.

The completed Excel workbook and updated contact list should be sent via email to [email protected] on or before the due date. Since BAs are responsible for reporting data

8 WECC Reporting Policy: https://www.wecc.biz/Corporate/Information Reporting Policy_06-25-14.pdf 9 WECC Information Sharing Policy: https://www.wecc.biz/Corporate/Information Sharing Policy_06-05-14.pdf


mailto:[email protected]

https://www.wecc.biz/Corporate/Information%20Sharing%20Policy_06-05-14.pdf

https://www.wecc.biz/Corporate/Information%20Reporting%20Policy_06-25-14.pdf


from non-BA entities within their respective areas, BAs should establish earlier dates for collecting coordinated future year data from the non-BA entities.

LAR Data Contacts

Data reporters can assure timely communication from WECC regarding all LAR data request by updating and returning the LAR Data Contact list provided with the first LAR data request. Changes throughout the year can also be submitted to [email protected].

Reliability Assessment Work Group

WECC staff encourages LAR data reporters to participate in the Reliability Assessment Work Group (RAWG). The RAWG provides a forum for stakeholder involvement and industry input into the use of LAR data for resource adequacy and reliability assessments, particularly the WECC PSA. To be added to the RAWG mailing list email [email protected]. More information can be found on the WECC website at wecc.biz/RAWG.

Questions or Comments

Questions on data reporting, or suggestions for improving the Data Collection Manual, should be directed to WECC staff, Dick Simons at [email protected] or Layne Brown at [email protected].




https://www.wecc.biz/pcc/Pages/RAWG.aspx



LAR Data Collection Manual: Section 1 — Excel Workbook5

Section 1 — Excel Workbook

An Excel workbook is used for the LAR data reporting. The workbook contains data that must be updated and, as needed, have projections added. The workbook is rather large and will work best if automatic calculation is turned off.

Workbook Structure

The following table is a summary of the worksheets for data entry and data checking. The data input tabs have been color coded in the workbook and table below to assist with easy identification. Section 2 and Section 3 tab names are highlighted blue, Section 4 tab name are highlighted grey, and finally Section 5 tab names are highlighted peach.

Table 1 - Workbook Structure

Worksheet Description

Dashboard Used to hold pertinent information about the represented area, and to provide feedback regarding the status of the input data.

Gen_Exist Data input sheet for existing generation information.

Gen_Add Data input sheet for generation additions information.

Peak_Data Data input sheet for the “peak” data, including peak loads, and outages.

Energy_Data Data input sheet for energy load information.

Growth A data checking form for load growth.

Load_Diff A data checking form for month-to-month load differences.

Actual Generation Data input sheet for the actual net generation generated within the BAA and delivered to the grid in MWhs from all fuel type resources.

Paths Data input sheet for transmission paths between modeling areas.

Regulating Reserves Data input sheet for regulating reserves information.

Hourly Demand Data input sheet for hourly demand for actual year.

Hourly HydroData input sheet for actual hourly hydro generation information reported on separate sheets for Run of River, Pump Storage, and Storage generation, as needed.

Hourly Wind Data input sheet for actual hourly wind generation information.



Worksheet Description

Hourly Solar Data input sheet for actual hourly solar generation information.

Projected Transmission Data input sheet for projected transmission additions/changes.

Projected Transformer Data input sheet for projected transformer additions/changes.

Time Zone Reporting

The Dashboard has a location (E6) to report the time zone of reported information. This is the time zone used to report all hourly demand and generation data. Use the drop down list provided to report either Pacific or Mountain Time.

Data Reporting

The descriptions of the data input sheets and detailed instructions are presented in Sections 2 through 5 below. There should not be any blank rows or cells in the final versions of the data input sheets.

Data Checking

One of the goals of this workbook is to improve the accuracy of the data submittals. This should help to meet the NERC deadlines for forwarding the WECC information. The following data checks should be used to validate the data and locate data inconsistencies.

1. Dashboard – embedded in thirteen of the worksheets10 are checks to verify that the data entered matches acceptable values. The data checks are initiated by clicking on the “Click to Check Workbook” box on the Dashboard sheet, and checks that all data reported in cells with drop down boxes are acceptable options. Data entries on the worksheets that should be investigated are circled in red and the Dashboard worksheet displays a count of potential errors for each worksheet. The data checking process turns off the Auto Save function so it is recommended to periodically manually save your work. However, saving will remove the error checking circles so you will need to reinitiate the data checking process. Also, when saving the workbook a Compatibility Checker box will be displayed. Click on the “Continue” box as all data checks will be re-established each time the workbook is opened. Contact WECC staff with any data validation questions.

2. Load Growth – the {Growth} worksheet lists the annual changes in peak demands and energy loads (% Growth rows) and highlights in yellow year-to-year load growth changes that exceed ± 1% (% Difference rows). An explanation is required for each of the highlighted ‘% Difference’

10 Data checks are embedded in the Gen_Exist, Gen_Add, Peak_Data, Energy_Data, Actual Generation, Hourly Demand, Hourly Hydro – Run of River, Hourly Hydro – Storage, Hourly Hydro – Pump Storage, Hourly Wind, Hourly Solar, Projected Transmission, and Projected Transformer worksheets.



load growths. The purpose of this data check is to identify the causes of unusual patterns in BA load forecasts that may be the result of the addition or deletion of major loads (e.g., startup or shutdown of a large industrial facility). Explanations regarding load changes from the current Actual Year load to the First Future Year forecast load should include references to the actual weather conditions experienced during the current Actual Year.

3. Load Differences – the peak demand and energy load pattern is expected to repeat each year, with some growth from year to year. The differences in the monthly loads from year to year are presented in the {Load_Diff} worksheet.

Data Error and Need for Clarification

WECC staff will contact a BA should the data checking process reveal a potential error or the need for clarification, detailed explanation, or both in the LAR data submitted in the BA’s workbook. If the data checking process reveals the need for the BA to provide comments regarding the LAR workbook data (e.g., certain changes in growth rates exceed pre-defined ranges), WECC staff will contact the affected BA. WECC staff will not make significant data changes without notifying the BA affected by the change.


LAR Data Collection Manual: Section 2 — Existing and Planned Generation Reporting Instructions8

Section 2 — Existing and Planned Generation Reporting Instructions

As discussed in Section 1 — Excel Workbook, each BA receives a workbook containing data to be updated. Section 2 provides instructions for updating the existing generation {Gen_Exist} worksheet and the generation addition {Gen_Add} worksheet. The data are updated by changing the information presented in the worksheets for the BA. The changes should make the information current as of December 31 of the Actual Year and, for BAs in the United States, should be consistent with the data reported to the DOE in Form EIA-860.

Table 2 - Period Definitions

Period Definitions Year

Actual Year (Last Year) 2015

First Forecast Year 2016

Data Reporting Process

The existing generation {Gen_Exist} worksheet is a detailed list of all generating units in the BAA with in-service dates up to the end of the Actual Year. Check the data provided for accuracy and update as necessary, including inserting actual retirement dates. If there are units missing from the list, or new units need to be added, insert a new row at the bottom of the list, and provide the information requested. Data for each unit that came into service during the Actual Year are to be added to the {Gen_Exist} sheet, with a Status Code of Operating (OP) and an updated Commission date and removed from the {Gen_Add} sheet. Likewise, data for each unit that was retired during the Actual Year are to be updated on the {Gen_Exist} sheet, with a Status Code of Retired (RE), summer and winter capacity of zero (0), an updated Retirement date, and the entry on the {Gen_Add} sheet should be removed.

Entities should report Out of Service Units with a Status Code of OS and a summer and winter capacity of zero (0). Mothballed and cold standby units are reported as Standby (SB), with a summer and winter capacity that reflects the expected available capacity of the unit when it is returned to service.

The generation additions {Gen_Add} worksheet is a detailed list of the generating units in a BAA that represent anticipated increases or decreases in generating capacity during future years. This includes retirements and up-rates or derates to existing plants and new generation construction. Update the provided list and add rows as necessary to provide information for new additions and other changes. Planned retirements should be reported as negative values in the summer and winter capacity column (equal to the capacity reported on the {Gen_Exist} sheet), with the anticipated retirement date



reported in the Retirement Date column. Planned up-rates and derates should be reported as the incremental change (a positive or negative value) that, when added to the existing capacity reported on {Gen_Exist}, nets to the future planned capacity. The anticipated rerate date should be reported in the Commission Date column.

Units that were reported on {Gen_Add} last year but are not being reported this year should remain on the {Gen_Add} sheet with CL entered for the NERC Class Code, and a WECC Class Code 5. This process allows WECC staff to track the progress of planned units.

Comments should be included in the (Published and/or Non-published) comment columns as appropriate. For example: for each inoperable unit state that the unit is in deactivated shutdown, on cold standby, etc. For units that were retired or derated during the Actual Year, or are planned to be retired or derated, indicate the reason for the retirement or derate (e.g., due to EPA regulations) in the comments column.

Use the comment column to report capacity commitment entities and their commitment shares of remote resources. Remote resources are defined as resources that are physically located in one BAA but have capacity commitments to an entity, or entities, located in another BA’s geographic footprint. In the comment column, enter the name of the capacity commitment entities and their commitment shares of each remote resource located in the BAA that is reported on the {Gen_Exist} or {Gen_Add} sheets.

The combustion turbine portions and steam portions of combined cycle units should be reported separately. The rating of each should be equal to the rating that applies when the units are operated in a combined cycle configuration. Therefore, the sum of the ratings of each component should equal the rated output of the combined cycle unit. (An existing steam or combustion turbine unit that is planned to be converted to a combined cycle unit should not be reported as a combined cycle unit.)

Updated worksheets should be submitted via email to [email protected] on or before the Data Submission Due Date.




Existing Generation and Generation Additions Data: Facility Record Format

Column Name

Explanation

NERC ID NERC assigned ID. This cell is protected and should not be adjusted or modified.

EIA Plant Code

EIA-860 Plant Code should be used for all units within the United States

EIA Unit Code

EIA-860 Unit Code should be used for all units within the United States

Zone For BAs with resources in multiple modeling areas, enter the zone where the resource is located. The affected BAs and the zone names are identified in Appendix A — Modeling Area to Zones. For all other BAs, enter the same code as entered in the BA column.

BA Balancing Authority code (see Appendix C — WECC Balancing Authorities).

Org Name/acronym of Load Serving Entity where the unit is located. If the LSE is not known, enter the same code as entered in the BA column.

Unit Name Power Plant Unit Name. This should be the same name reported on EIA-860 for units within the United States.

Unit Number Unit Number (No more than 4 characters, and do not leave blank)

Unit Type The following options are included in the workbook:

ST..........Steam Turbine, including nuclear, geothermal and solar steam (does not include combined cycle)

ST-S.......Solar Thermal with StorageST-NS.....Solar Thermal without StorageGT.........Combustion (Gas) Turbine - Simple Cycle (includes jet engine design)IC...........Internal Combustion Engine (diesel, piston, reciprocating)CA.........Combined Cycle Steam PartCT..........Combined Cycle Combustion Turbine Part (type of coal or solid must be

reported as energy source for integrated coal gasification)CS..........Combined Cycle Single Shaft (combustion turbine and steam turbine

share a single generator)CC..........Combined Cycle Total Unit (use only for plants/generators in planning

stages, for which specific generator details cannot be provided)HY.........Hydraulic Turbine (includes turbines associated with delivery of water by

pipeline)



Column Name

Explanation

HY-R......Hydraulic Turbine that qualified as a renewable resource under applicable state or province definition

PS..........Energy Storage, Reversible Hydraulic Turbine (Pumped Storage)BT..........Turbines Used in a Binary Cycle (including those used for geothermal

applications)PV-T......Solar Photovoltaic with TrackingPV-NT....Solar Photovoltaic without TrackingWT........Wind Turbine, OnshoreWS.........Wind Turbine, OffshoreCE..........Energy Storage, Compressed AirFC..........Fuel CellOT..........Other/Unknown (Specify in comments section)BA..........Energy Storage, BatteryCP..........Energy Storage, Concentrated Solar PowerFW.........Energy Storage, FlywheelES..........Energy Storage, Other (Specify in comments section)HA.........Hydrokinetic, Axial Flow TurbineHB..........Hydrokinetic, Wave BuoyHK..........Hydrokinetic, Other (Specify in comments section)

Nameplate11 The initial capacity of a piece of electrical equipment as stated on the attached nameplate. Actual capability can vary from the nameplate rating due to age, wear, maintenance, or ambient conditions. Data to be entered in MW, rounded to the tenth of a MW. EIA-860 nameplate capacity should be used for all units within the United States.

Summer Cap The expected capability available to the grid, of a generating unit during the peak of the summer season. Do not include station service capacity and do not reduce to reflect planned outages (e.g., scheduled maintenance). Data to be entered in MW, rounded to the tenth of a MW. EIA-860 summer capacity should be used for

11 For conventional technology generation, refer to Appendix D — WECC Criteria for Uniform Reporting of Generator Ratings for rating instructions.



Column Name

Explanation

all units within the United States.

Winter Cap The expected capability available to the grid, of a generating unit during the peak of the winter season. Do not include station service capacity and do not reduce to reflect planned outages (e.g., scheduled maintenance). Data to be entered in MW, rounded to the tenth of a MW. EIA-860 winter capacity should be used for all units within the United States.

Primary Fuel The energy source code for the fuel used in the largest quantity (Btus) to power the generator EIA-860 Predominant Energy Source should be used for all units. If a unit can burn two or more fuel types, report the type most likely to be burned as the primary fuel. Report the next fuel type most likely to be burned, based on expected annual energy predominance, as the secondary fuel. See the fuel types below for the options included in the workbook.

ANT.......Anthracite CoalBIT.........Bituminous CoalLIG.........Lignite CoalSGC.......Coal-Derived Synthesis GasSUB.......Subbituminous CoalWC........Waste/Other Coal (Including anthracite culm, bituminous gob, fine coal,

lignite waste, waste coal)RC..........Refined CoalDFO.......Distillate Fuel Oil. Including Diesel, No. 1, No. 2, and No. 4 Fuel OilsJF...........Jet FuelKER........KerosenePC..........Petroleum CokePG.........Gaseous PropaneRFO.......Residual Fuel Oil (Including No. 5, No. 6 Fuel Oils, and Bunker C Fuel Oil)SGP........Synthetic Gas from Petroleum CokeWO........Waste/Other Oil (Including Crude Oil, Liquid Butane, Liquid Propane,

Naphtha, Oil Waste, Re-Refined Motor Oil, Sludge Oil, Tar Oil, or other



Column Name

Explanation

petroleum-based liquid wastes)BFG.......Blast Furnace GasNG.........Natural GasOG.........Other Gas (Specify in comment field)AB.........Agriculture By-productsMSW.....Municipal Solid WasteOBS.......Other Biomass Solids (Specify in comment field)WDS......Wood/Wood Waste Solids (Including paper pellets, railroad ties, utility

poles, wood chips, bark, and wood waste solids)OBL Other Biomass Liquids (Specify in comments field)

OBL.......Other Biomass Liquids (Specify in comment field)SLW.......Sludge WasteBLQ.......Black LiquorWDL......Wood Waste Liquids excluding Black Liquor (includes red liquor, sludge

wood, spent sulfite liquor, and other wood-based liquids)LFG........Landfill GasOBG.......Other Biomass Gas (includes digester gas, methane, and other biomass

gases; Specify in the comments field)SUN.......SolarWND.....WindGEO.......GeothermalWAT......Water at a conventional hydroelectric turbine, and water used in Wave

Buoy Hydrokinetic Technology, Current Hydrokinetic Technology, and Tidal Hydrokinetic Technology. Pumping Energy for Reversible (Pumped Storage) Hydroelectric Turbine

NUC.......Nuclear (Including Uranium, Plutonium, Thorium)PUR.......Purchased SteamWH........Waste heat not directly attributed to a fuel source (WH should only be

reported where the fuel source for the waste heat is undetermined, and for combined cycle steam turbines that do not have supplemental firing)

TDF........Tire-derived FuelsMWH.....Electricity used for energy storageOTH.......Other (Specify in comments field)UKN.......Unknown (Specify in comments field)



Column Name

Explanation

Secondary Fuel

The energy source code for the energy source used in the second largest quantity (Btus) to power the generator. Use one of the options listed above under primary fuel. Fuel used for start-up should not be reported as an alternate fuel. For units with no secondary energy source, leave this field blank.

Status Code The following options are available for reporting the Status Code:

Existing Generation Only (WECC Class Code 0)OP.........Operating or short-term outage (Report as EC in NERC Class Code)SB..........Cold standby, 3-6 mo. to reactivate. Report a summer and winter

capacity that reflects the expected availability capacity (Report as MB in NERC Class Code)

OS.........Out of service. Report a summer and winter capacity of zero (0) (Report as EC in NERC Class Code)

RE..........Retired (Report as RE in NERC Class Code)

Generation Additions/Repowers OnlyP............Planned for installation but not under active constructionL............Regulatory approval pending but not under active construction (started

site preparation)T............Regulatory approval received but not under active constructionU...........Under active construction, less than or equal to 50% complete (based on

construction time to first electric date)V............Under active construction, more than 50% complete (based on

construction time to first electric date)TS..........Construction complete, but not yet in commercial operation (including

low power testing of nuclear units)A............Generator capability increased (rerated or relicensed)D...........Generator capability decreased (rerated or relicensed) (indicate reason

in comments field)M..........Generator to be put in deactivated shutdown statusRA.........Previously retired or deactivated generator planned for reactivationRC..........Retirement-committed (Report as NERC Class Code Tier 1)RU.........Retirement-uncommitted (Report as NERC Class Code Tier 2)FC..........Existing generator planned for conversion to another fuel or energy

sourceIP...........Indefinitely postponed (Report as NERC Class Code CL and WECC Class

Code 5)CO.........Change of ownership (including change of shares of jointly-owned units)

State State/Province Code (see Appendix C — WECC Balancing Authorities).



Column Name

Explanation

County County where generation is located

NERC Class Code

When determining the class code of a generation resource, refer to the criteria listed within each category. Determine the resource's applicability to the class code by assessing the criteria in each category in order of certainty (use logical progression). A resource will qualify within a class code if any one of the listed criteria is true for that resource. For example, first assess whether the resource falls into the Existing-Certain category. If not, next consider if the resource meets the criteria of Existing-Other. Continue this progression through the remaining categories of Tier 1, 2, or 3 until the unit meets at least one criteria of a class code.

EXISTING RESOURCES

Enter the class code that best reflects the current status of existing generation.

EC - Existing-Certain - Included in this category are existing generator units (expressed in MW), or portions of existing generator units, that are physically located within the assessment [balancing authority] area that meet at least one of the following requirements when examining the period of peak demand for each season/year:

Unit must have firm capability12 and have a Power Purchase Agreement (PPA)13 with firm transmission,

Unit must be classified as a Designated Network Resources14, Where energy-only markets exist, unit must be a designated market

resource eligible to bid into the market.

EO - Existing-Other - [WECC staff does not believe that the Existing-Other class code applies to resources in the Western Interconnection. Contact WECC staff before classifying a resource as Existing-Other]

Included in this category are commercially operating generating units, or portions of generating units, that are expected to be available to serve load for the period of peak demand for each season/year of the assessment period, but do not meet

12 The commitment of generation service to a customer under a contractual agreement to which the parties to the service anticipate no planned interruption (applies to generation and transmission). 13 Power Purchase Agreement: Guarantees a market for power produced by an independent power producer and the price at which it is sold to a purchaser. Such an agreement imposes legal obligations on both parties to perform previously accepted tasks in a predetermined manner.14 Designated Network Resource: Any designated generating resource owned, purchased or leased by a Network Customer under the Network Integration Transmission Service Tariff. Network Resources do not include any resource, or any portion thereof, that is committed to sale to third parties or otherwise cannot be called upon to meet the Network Customer’s Network Load on a non-interruptible basis, except for purposes of fulfilling obligations under a Commission-approved reserve sharing program.



Column Name

Explanation

the requirements of Existing-Certain.

RE - Retired - Permanently removed from commercial operation.

MB - Mothballed - Currently inactive or on Standby, but available for commercial operation.

FUTURE RESOURCES

Future Resources that are directly associated with resource retirement or fuel conversions are to be classified as Tier 1 if the retirement/repower is reported with a status code of RC. If the retirement/repower is reported with a status code of RU, report the associated future resource with a classification of Tier 2.

Enter the class code that best reflects the current status of generation additions.

T1 - Tier 1 - [Report with the Status Code RC – Retirement committed] Planned units in Tier 1 must meet at least one of the following requirements when examining the period of peak demand for each season/year:

Construction complete (not in commercial operation), Under construction Signed/approved Interconnection Service Agreement (ISA) A Power Purchase Agreement (PPA) has been signed/approved, Signed/approved Interconnection Construction Service Agreement (CSA), Signed/approved Whole Market Participant Agreement (WMPA) Included in an integrated resource plan or under a regulatory environ-

ment that mandates a resource adequacy requirement (Applies to Verti-cally Integrated Entities)

T2 - Tier 2 - [Report with the Status Code RU – Retirement uncommitted] Planned units in Tier 2 (that do not meet the requirements of Tier 1), must have:

A completed feasibility study, A completed system impact study, A completed facilities study, Requested Interconnection Service Agreement, Included in an integrated resource plan or under a regulatory

environment that mandates a resource adequacy requirement (Applies to RTOs/ISOs)

T3 - Tier 3 - Project in an interconnection queue that does not meet the Tier 1 or Tier 2 requirements.



Column Name

Explanation

CL - Cancelled - Planned unit (previously reported as Tier 1, 2, or 3) that has been cancelled/removed from the interconnection queue. This class includes units that have been indefinitely postponed.

WECC Class Code

See Table 3 for map of NERC class codes to WECC class code

0 - Existing Generation - All generation existing as of December 31 of the Actual Year should be identified in Class 0.

Enter the class code that best reflects the current status of generation additions or retirements.

1 - Class 1 - Generation additions that were reported to be under active construction as of December 31 of the Actual Year and are projected to be in-service within the period ending five years from the end of the Actual Year. Also include any facility or unit that has a firm date for retirement within the assessment period as a result of regulatory requirements or corporate decisions.

2 - Class 2 - Generation additions that were reported to have 1) received regulatory approval, or are undergoing regulatory review, 2) with a signed interconnection agreement, and 3) with an expected on-line date within the period ending seven years from the end of the Actual Year. This class includes resources that were expected to be in service as early as Class 1 resource but do not meet the test of being under construction. Also include any facility or unit that is estimated by the reporting entity to be retired-committed or retired-uncommitted within the assessment period.

3 - Class 3 - Generation additions that were reported which have met the NERC criteria for Tier 1 or Tier 2 Resources but, because of expected on-line requirements, do not qualify as Class 1 or 2 Resources.

4 - Class 4 - Generation additions that were reported which have met the NERC criteria for Tier 3 Resources.

5 - Class 5 - Generation additions that were reported last year but are no longer expected to enter service, retire, etc., within the assessment period.

Table 3 - Correlation of NERC Class Codes and WECC Class Codes

NERC Class Codes WECC Class Codes

EC 0EO15



NERC Class Codes WECC Class Codes

MB 1

T1 1

2

3

T2 2

3

T3 4

RE 5

CL 5

Column Name Field Content Explanation

Commission Date Existing generation only Month and Year the unit entered service.

Planned generation only Month and Year unit is expected to be in service.

Retirement Date Existing generation only

Month and Year the unit was, or is expected to be retired.

Latitude Generation Latitude

Latitude location of generating unit. Use XX.XXXXXX/–XX.XXXXXX convention. This should be the actual location of the unit, not the center of the County as is allowed when supplying this data to EPA for the eGRID report.

Longitude Generation Longitude

Longitude location of generating unit. Use XXX.XXXXXX/–XXX.XXXXXX convention. This should be the actual location of the unit, not the center of the County as is allowed when supplying this data to EPA for the eGRID report.

15 WECC staff does not believe that the Existing-Other class code applies to resources in the Western Interconnection. Contact WECC staff before classifying a resource as Existing-Other.



Column Name Field Content Explanation

TSS Bus Bus Number Bus number associated with generation location. The Bus number should be the same number submitted for TSS base cases.

Reporting Area Hydro/Wind/Solar reporting area

For Hydro, Wind, and Solar hourly generation indicate the reporting area where the generation is located or, for new construction, will be located. A dropdown list is provided in this column of the Hourly Hydro, Wind, and Solar worksheets.

Published Comments

Published Comments

Comments are used for purposes such as providing explanations for OT unit type codes and fuel type codes, giving unit ownership information, explaining plant operating status, and documenting status of new generation, etc. Also use the published comment field to report the reason for derating or retirement of generating units.

Non-Published Comments

Non-Published Comments

For WECC staff use and non-public information provided by reporting entities.

Modeling ID Modeling ID For WECC staff use.


LAR Data Collection Manual: Section 3 — Input Guide for Peak Demand, Demand-Side Management,Energy Loads, and Resource Outage Instructions 20

Section 3 — Input Guide for Peak Demand, Demand-Side Management, Energy Loads, and Resource Outage Instructions

Peak demand LAR information may be used to prepare power supply evaluations for the WECC subregions’ report to NERC and other Western Interconnection sub-areas, including the zones used in the production model as represented in the LTRA and PSA. To accomplish this, the following data are required:

1. Loads - Both firm and non-firm, include transmission losses but exclude station use, self-serve load (behind-the-meter), and/or pumped storage pumping.

2. Demand-Side Management (DSM) - DSM program information.3. Unavailable capability - Total maintenance and outage data broken down between hydro and

non-hydro.

A discussion about each of these required data types is presented in the following pages under the headings of Load Data (Codes 1, 2, and 3) and Unavailable Capability Data . This discussion is followed by the detailed information about the required data codes and data formats used for populating the data response worksheets of {Peak_Data} and {Energy_Data}. The code and format information is provided under the headings of Actual Peak Demand Loads, DSM, Outage Data, and Distributed Generation Code Definitions and Estimated Peak Demand Loads, DSM, Outage Data, Distributed Generation, Energy Efficiency, and Standby Demand Code Definitions.

Monthly peak demand LAR information is needed for the actual year through the eleventh (11) future year plus January, February, and March of the twelfth (12) future year.

The LSE shall count its customer demand once and only once, on an aggregated and dispersed basis, in developing its actual and forecast customer demand values. The demand, net energy for load, and controllable DSM supplied for this WECC Data Collection request shall be consistent with the demand, net energy for load, and controllable DSM supplied in response to the annual Power Flow Base Case data requests. BAs are to aggregate the LSEs’ demand forecast data, or provide a coincident BA forecast, for all LSEs within their BAA.



Load Data (Codes 1, 2, and 3)

Peak demand load data are reported as firm and non-firm loads under data codes 1 and 2 respectively. Dispatchable DSM (DDSM) total program enrollments are reported under data code 3.

Firm peak demand load data are reported as Code 1. Firm peak demand is the projected sum of the metered (net) outputs of all generators within the system and the metered line flows into the system, less the metered line flows out of the system. The demands for station service or auxiliary needs (such as fan motors, pump motors, and other equipment essential to the operation of the generating units) are not included. Firm peak demand should be reduced by indirect demand-side management programs such as conservation programs, improvements in efficiency of electric energy use, Stand-by Load under Contract, all non-controllable or non-dispatchable demand response programs (such as Time-of-Use, Critical Peak Pricing, Real Time Pricing, etc.).

For Actual Year, non-firm peak demand load data are reported using the Code 2 options. It includes the amount of non-firm DDSM demand that was served at the time of the monthly BA peak. For future year’s one through eleven, non-firm peak demand load data are the amount of DDSM that is expected to be served at the time of monthly BA peak demand. DDSM programs include: 1) Interruptible Demand (also known as contractual interruptible demand); 2) Direct Control Load Management; 3) Critical Peak Pricing with Control; and 4) Load as a Capacity Resource. These programs are described in detail below.16

o Interruptible demand is defined as demand that the end-use customer has made available to the LSE, via contract or agreement, for curtailment. Interruptible/Contractually Interruptible peak demand is designated by a 2-I in the code column of the data record and is the amount of customer demand that can be interrupted at the time of the monthly BA peak. In some instances, the demand reduction may be affected by action of the System Operator (remote tripping), after notice to the customer, in accordance with contractual provisions.

o Direct Control Load Management (DCLM) is DSM that is under the direct control of the system operator. DCLM may control the electric supply to individual appliances or equipment on customer premises. DCLM as defined here does not include Interruptible Demand. DCLM loads are designated by a 2-L and are the amount of customer demand that can be interrupted at the time of the BAs monthly peak.

16 Customer demand that can be curtailed in accordance with a contractual agreement (interruptible peak demand) is generally separately metered so actual year monthly interruptible peak demand data are usually available. However, Direct Control Load Management peak demand is generally not separately metered so estimated data may be required. The “Critical Peak Pricing with Control” DDSM program or the “Load as a Capacity Resource” program also may, or may not, be separately metered so estimated data may be required.



o Critical Peak-Pricing with Control is DSM that combines direct remote control with a pre-specified high price for use during designated critical peak periods. Critical Peak-Pricing is designated by a 2-P in the code column and is the amount of customer demand that can be interrupted at the time of the monthly BA peak.Note: Critical Peak Pricing is a sub-set of DCLM. DSM associated with these programs should be counted only once as either DCLM or Critical Peak-Pricing, not as both.

o Load as a Capacity Resource are demand-side resources that acts as a capacity resource that can be committed for pre-specified load reductions under certain conditions. Load as a Capacity Resource is designated by a 2-R and is the amount of customer demand that can be interrupted at the time of the monthly BA peak.

The total demand that is enrolled in each DDSM program is reported as Code 3. Report the total amount of customer demand enrolled in each of the above DDSM programs for future year’s one through eleven. DDSM programs include: 1) Interruptible Demand (also known as contrac-tual interruptible demand); 2) Direct Control Load Management; 3) Critical Peak Pricing with Control; and 4) Load as a Capacity Resource.

o Interruptible/Contractually Interruptible (IL) program totals are designated by a 3-IT and is the amount of customer demand enrolled as IL.

o Direct Control Load Management (DCLM) program totals are designated by a 3-LT and represents the amount of customer demand enrolled in DCLM programs.

o Critical Peak-Pricing with Control (CPP) program totals are designated by a 3-PT and is the amount of customer demand enrolled in CPP programs.Note: Critical Peak Pricing is a sub-set of DCLM. DSM associated with these programs should be counted only once as either DCLM or Critical Peak-Pricing, not as both.

o Load as a Capacity Resource (LCR) program totals are designated by a 3-RT and represents the amount of customer demand enrolled in LCR programs.

For the Actual Year, the monthly sum of the firm peak demand (Code 1) and served DDSM peak demand (Code 2) must equal the total monthly metered peak demand. For future years, the monthly sums must equal the total monthly forecast peak demands. Likewise, the amount reported in Code 3 for each of the four programs, for both actual and future years, must be greater than, or equal to, the amount reported in the respective Code 2 data.

The peak demand load forecasts should include the effects of such factors as economic, demographic, weather effects , and customer trends; conservation, improvements in the efficiency of electrical energy use, and other changes in the end uses of electricity. The peak demand load forecast for each month should have a 50% probability of not being exceeded (expected peak demand). This load forecast is commonly referred to as the 1-in-2 monthly peak load forecast.



Individual systems should maintain documentation regarding the assumptions, methodologies, and the manner in which forecast uncertainties are addressed in their forecasts. This information would be helpful in understanding forecast discontinuities and deviations from actual-year peak demands.

Unavailable Capability Data

Actual year unavailable utility generating capability is reported under five data codes – 14 (Scheduled Maintenance – non-hydro), 14H (Scheduled Maintenance – hydro), 15 (Inoperable Capacity – non-hydro), 15H (Inoperable Capability – hydro) and 16 (Forced Outages). Future years 1-11 unavailable utility generating capability is reported under four data codes – 14 (Scheduled Maintenance – non-hydro), 14H (Scheduled Maintenance – hydro), 15 (Inoperable Capability – non-hydro) and 15H (Inoperable Capability – hydro). Code 16 (Forced Outages) is not reported for future years.



Actual Peak Demand Loads, DSM, Outage Data, and Distributed Generation Code Definitions

60-minute Peak Demand MW

(Actual Year- Report Monthly Data)

DATA DESCRIPTION............................................................. DATA CODE

Loads - Firm (excluding station use)..........................................................................................................1

Loads - Non-firm (DDSM programs, served)..............................................................................................2

Loads – DDSM total program enrollment..................................................................................................3

Scheduled Maintenance Non-Hydro........................................................................................................14

Scheduled Maintenance Hydro.............................................................................................................14H

Inoperable Capability Non-Hydro............................................................................................................15

Inoperable Capability Hydro..................................................................................................................15H

(Note: If the reduction in capability did not affect monthly hydro energy generation, do not report as inoperable capability. Contact WECC staff with questions.)

Forced Outages........................................................................................................................................16

Rooftop Solar Generation Installed..........................................................................................................18

Report in MWs, the best estimation for existing rooftop solar generation in the BAA.

Rooftop Solar Generation Embedded......................................................................................................19

Report in MWs, the best estimation for the amount of demand that was served from rooftop solar (code 18) on the peak hour for each month of the Actual Year.



Estimated Peak Demand Loads, DSM, Outage Data, Distributed Generation, Energy Efficiency, and Standby Demand Code Definitions

(Future Years one through eleven - Report Monthly Data, and January, February, and March of twelfth Future Year)

DATA DESCRIPTION DATA CODE

Loads - Firm (excluding station use)..........................................................................................................1

Loads - Non-firm (DDSM programs, served)..............................................................................................2

Loads – DDSM total program enrollment..................................................................................................3

Scheduled Maintenance Non-Hydro........................................................................................................14

Scheduled Maintenance Hydro.............................................................................................................14H

Inoperable Capability Non-Hydro............................................................................................................15

Inoperable Capability Hydro..................................................................................................................15H

(Note: If the reduction in capability is not expected to affect monthly hydro energy generation, do not report as inoperable capability. Only report if the inoperable capability is expected to reduce hydro generation. Report in the comment column the expected monthly reduction in energy, in GWh, associated with the inoperable capability. Contact WECC staff with questions.)

Load Forecasting Information

Rooftop Solar Generation Forecasted to be Installed..............................................................................18

Report in MWs, the best estimation for rooftop solar generation expected to be installed over the assessment period.

Rooftop Solar Generation Embedded......................................................................................................19

Report in MWs, the best estimation for the amount of demand that is expected to be served from rooftop solar generation (code 18) on the peak hour for each month over the assessment period.

Combined Conservation and New Energy Efficiency Impacts.................................................................70

Conservation – A reduction in energy consumption that corresponds with a reduction in service demand. Service demand can include buildings-sector end use such as lighting, refrigeration, and heating; or industrial processes. Unlike energy efficiency, which is typically a technology measure, conservation is better associated with behavior. Examples of conservation include



adjusting the thermostat to reduce the output of a heating unit or using occupancy sensors that turn off lights or appliances.

New Energy Efficiency - refers to programs that are aimed at reducing the energy used by specific end-use devices and systems, typically without affecting the services provided. These programs reduce overall electricity consumption, often without explicit consideration for the timing of program-induced savings. Such savings are generally achieved by substituting technologically more advanced equipment to produce the same level of end-use services (e.g. lighting, heating, motor drive) with less electricity. Examples include high-efficiency appliances, efficient lighting programs, high-efficiency heating, ventilating and air conditioning (HVAC) systems or control modifications, efficient building design, advanced electric motor drives, and heat recovery systems.

[WECC understands this to mean the monthly reduction in the submitted peak demand forecast resulting from all ratepayer-funded energy efficiency programs implemented over the forecast period. Only include the impact of future energy efficiency programs reflected within the submitted forecast.]

Enter, in MWs, the combined impacts of energy efficiency and conservation programs that impact load growth beyond its natural or normal rate. Impacts should be reported on a cumulative basis, starting with the expected impacts in the Actual Year, and continuing throughout the assessment period.

Standby Demand under Contract...................................................................................................73

Standby demand is load that is normally served by behind-the-meter generation that has a contract with a LSE to provide power if the generator becomes unavailable. Standby Demand power is intended to be used infrequently by any one customer.

Enter, in MWs, the expected demand at time of system peak required to provide power and energy (under a contract with a customer as a secondary source or backup for an outage of the customer’s primary source) for the Actual Year, and continuing throughout the assessment period.



Actual and Estimated Peak Demand Loads Coding Data Record Format

Actual Year and Estimated Future Years one through eleven, and January, February, and March of twelfth Future Year.

Column Heading Description

Row Leave column blank. (Used by WECC for post-processing)

Year Year

Code For data Code 2 (DDSM peak demand)2-I - Interruptible2-L - Load Management2-P - Critical Peak-Pricing with Control2-R - Load as a Capacity Resource

For data Code 3 (DDSM total program enrollment)3-IT - Interruptible3-LT - Load Management3-PT - Critical Peak-Pricing with Control3-RT - Load as a Capacity Resource

Zone For BAs with demand in multiple modeling areas, enter the zone where the demand is located. The affected BAs and the zone names are identified below. For all other BAs, enter the same code as entered in the BA column.

BA WECC BA Organization Codes (see Appendix C — WECC Balancing Authorities).

Jan-Dec Monthly Values (Report in MWs)

Comment Comment



Energy Load Instructions

Energy load data are reported as firm and non-firm loads under data Codes 1 and 2 respectively in the code column of the worksheet {Energy_Data}. The energy load data are to be reported on the same basis as the peak demand load data (e.g., net of station use, self-serve load (behind-the-meter), or pumped storage pumping and includes transmission line losses).

The monthly actual energy loads and monthly forecast loads for the first through eleventh future year and January, February, and March of the twelfth future year are reported in the month columns.

All energy load numbers are to be reported in gigawatt-hours (GWh).

Actual and Estimated Energy Loads Coding Data Record Format

Actual Year and Future Years one through eleven, and January, February, and March of the twelfth Future Year.



Year Year

Code Data Code - Identifies type of data :1 - Firm Energy2 - Non-Firm Energy

Zone For BAs with load in multiple modeling areas, enter the zone where the load is located. The affected BAs and the zone names are identified in Table 4. For all other BAs, enter the same code that is entered in the BA column.

BA WECC BA Organization Codes (see Appendix C — WECC Balancing Authorities).

Jan-Dec Monthly Values (Report in GWhs)

Comment Comment


LAR Data Collection Manual: Section 4 — Reliability and Supply Assessments 29

Section 4 — Reliability and Supply Assessments

The data requested in Section 4 will be used to enhance the performance and accuracy of WECC’s production model. The model is used to calculate resource adequacy numerical values that are presented in NERC and WECC reliability and supply assessments.

Actual Generation

On the {Actual Generation} worksheet, enter the monthly net generation, in MWh, internal to the BAA from all power plants whose output is telemetered and monitored by the BA. Include any external generation dynamically scheduled as part of the BAA, less any generation in the BAA dynamically scheduled as part of another BAA. This should be identical to generation reported by the BA though FERC 714.

Net generation is defined as gross generation less plant use, measured at the high-voltage terminals of the station’s step-up transformer. The energy required for pumping at pumped-storage plants is regarded plant use and is excluded from the gross generation. Generation from auxiliary and start-up generators should not be reported.

Report net generation by the primary fuel types identified in Section 2 — Existing and Planned Generation Reporting Instructions.



Fuel Type Report net generation using the primary fuel types identified in Section 2 – Existing and Planned Generation Reporting Instructions.

Jan-Dec Report, by Fuel Code, the net generation produced and delivered to the grid (MWh) within each BAA. The amount of generation should match the generation reported to FERC on form 714.

Comment Comment



Transfer Path Capabilities

Verify and update the {Paths} worksheet with the appropriate transfer capabilities between modeling areas. Note that there are two sets of transfer data for each path (inbound and outbound). The data reflects the values that were used in the production model for the current NERC LTRA and WECC PSA. The list of transmission lines in the {Paths} worksheet identifies the cut planes between modeling areas. Planned upgrades/changes, with the effective date should be reported in both the {Paths} and {Projected Transmission} worksheets. The transfer capability terms and definitions are listed below.

Maximum Transfer Capability - Maximum Transfer Capabilities are the rated-path capabilities associated with ratings found in the WECC Path Rating Catalog. If the path is not rated, please provide the best estimate.

Operating Transfer Capability (OTC) - Nominal Operating Transfer Capabilities are the transfer limits used in day-to-day operations based on seasonal thermal and/or stability limits.

"High Load" Transfer Capability - The capacity that may reasonably be expected to apply under simultaneous high seasonal transmission loading conditions. Transfer restrictions such as simultaneous flows, loop flows, and other transfer restrictions should be reflected in the high load transfer capability limits. These limits are used in the production model to calculate transfers for the NERC LTRA and the WECC PSA.

Transfer Path Capabilities Coding Data Record Format


Transfer Capability - Summer - Max

The aggregate maximum transfer capability from the modeling area in column B to the modeling area in column C for summer.

OTC - Summer

The aggregate Operating Transfer Capability (OTC) from the modeling area in column B to the modeling in column C for summer.

Transfer Capability - Summer - High Load

The aggregate "High Load" transfer capability from the modeling area in column B to the modeling area in column C for summer. These limits are used in the production model to calculate transfers for the NERC LTRA and the WECC PSA.

Transfer Capability - Winter - Max

The aggregate maximum transfer capability from the modeling area in column B to the modeling area in column C for winter.

OTC - Winter The aggregate OTC from the modeling area in column B to the modeling area in column C for winter.




Transfer Capability - Winter - High Load

The aggregate "High Load" transfer capability from the modeling area in column B to the modeling area in column C for winter. These limits are used in the production model to calculate transfers for the NERC LTRA and the WECC PSA.

Loss % The transmission loss percent on the path.

Wheel $/MWh

The cost for wheeling on the path. These charges are used in the production model to calculate transfers for the NERC LTRA and the WECC PSA.

Regulating Reserves

Regulating Reserves — the amount of spinning reserves responsive to automatic generation control that are sufficient to provide normal regulating margin, or reserves to balance variations in output from variable resources (such as wind) — are an element of the building block reserve margin used in the annual NERC LTRA and WECC PSA. On the {Regulating Reserve} sheet, each BA should report the amount of regulating reserves expected to be available during the summer and winter seasons. The BA can report the reserves either as a MW amount or as a percentage of load.


LAR Data Collection Manual: Section 5 — Miscellaneous Data 32

Section 5 — Miscellaneous Data

The data outlined in Section 5 will be used to enhance the production model (Hourly Demand, Hourly Hydro, Wind, and Solar Production), be reported to NERC to satisfy its Form EIA-411 filing (Projected Transmission Lines and Transformer Additions) requirements, or in other reliability assessments.

Hourly Demand

In the {Hourly Demand} worksheet, the hour column corresponds to the hour from the actual year. The use of the hourly format removes the need to adjust for daylight-saving time (contact WECC staff if there are questions regarding adjustments for daylight-saving time). Report in the Hourly Demand column the actual hourly integrated demand (in MWs) corresponding to each hour of the year. The Hourly Demand data should be consistent with the data reported to FERC in Form 714.

A separate request for January and February current reporting year hourly demand will be sent to the BAs before the end of the second quarter.

The BAs listed in Table 4, whose areas contain several modeling zones, should report the Hourly Demand data separately by the listed zones.

Table 4 - BA Multiple Zones Designations

BA → PACE CISO IPCO

Area ↓ Zones Zones Zones

BA Total Load PACE

Wyoming, PACE Utility PAWY

Idaho, PACE Utility PAID

Utah, PACE Utility PAUT

California, PG&E_Bay CIPB

California, PG&E_Vly CIPV

California, SCE CISC

California, SDGE CISD

Idaho, Treasure Valley IPTV

Idaho, Magic Valley IPMV



BA → PACE CISO IPCO

Idaho, Far East IPFE

Column Name

Definition Instructions

Hour of the year

Hour of year reported

Name Area where demand is reported

Report the Zone where the demand is located (use dropdown).

Hourly Demand

Actual hourly demand in MWs.

Report the actual hourly demand for the location. Report in MWs.

Hourly Hydro Production

BAs that report a hydro resource on the {Gen_Exist} are to report the nameplate capacity and actual integrated generation for each hour of the year on the Hydro sheets as requested below. One sheet should be used for each type of hydro resource; Storage Capable, Run-Of-River, and Pump-Storage. Contact WECC staff with questions. Note: the generation reported here may not be the same as the generation reported in Actual Generation above.

Column Name


Hour of the year


Name Area where generation is located

Report the Zone where the generation is located (use dropdown).

Nameplate Sum

Total nameplate capacity of the hydro location

Report the sum of nameplate capacity of all generation installed at the wind location. Report in MWs. Indicate when new generation is installed by increasing the Nameplate Sum from that hour forward.

Hourly Generation

Actual integrated hourly generation

Report the actual integrated energy generation for the hydro location. Report in MWs.



Column Name


in MWs.

Hourly Wind Production

BAs that report a wind resource on the {Gen_Exist} are to report the nameplate capacity and actual integrated generation for each hour of the year on the {Hourly Wind} sheet as requested below. Note: the generation reported here may not be the same as the generation reported in Actual Generation above.

Column Name


Hour of the year


Name Area where generation is located

Report the Zone where the generation is located (use dropdown).

Nameplate Sum

Total nameplate capacity of the wind location

Report the sum of nameplate capacity of all generation installed at the wind location. Report in MWs. Indicate when new generation is installed by increasing the Nameplate Sum from that hour forward.

Hourly Generation

Actual integrated hourly generation in MWs.

Report the actual integrated energy generation for the wind location. Report in MWs.

Hourly Solar Production

BAs that report a solar resource on the {Gen_Exist} are to report the nameplate capacity and actual integrated generation for each hour of the year on the {Hourly Solar} sheet as requested below. Note: the generation reported here may not be the same as the generation reported in Actual Generation above.

Column Name Definition Instructions

Hour of the year Hour of year reported

Name Area where Report the Zone where the generation is



Column Name Definition Instructions

generation is located

located (use dropdown).

Nameplate Sum Total nameplate capacity of the solar location

Report the sum of nameplate capacity of all generation installed at the solar location. Report in MWs. Indicate when new generation is installed by increasing the Nameplate Sum from that hour forward.

Hourly Generation Actual integrated hourly generation in MWs.

Report the actual integrated energy generation for the solar location. Report in MWs.

Projected Transmission Line Additions

The {Projected Transmission} sheet should be verified and updated by each BA for all transmission line additions at 100 kV and above projected for the eleven-year period beginning with the Actual Year.

Each entry should have the same attributes over the entire reported-line addition. For example, a reported line of 200-299 kV should be the same voltage for the entirety of the specified line mileage. If line attributes change over a single project, this should be reported by two or more separate entries.

Note that in most cases separate entries must be made for each three-phase circuit of a multi-circuit line. An exception to this rule occurs when the projected in-service date of one or more of the circuits is beyond the assessment period. Note, also, that retirements and operating voltage changes to multi-circuit lines are to be reported on a circuit-by-circuit basis and not on a multi-line basis.

Data entries for Circuits Per Structure Present, Circuits Per Structure Ultimate, and Comments are optional. Do not adjust or modify the Project Identification Number.

Data Validation drop-downs have been provided in the {Projected Transmission} sheet.

Column Name

Definition Instruction


Zone Zone where transmission is located. For BAs with transmission in multiple modeling areas, enter the Zone where the transmission is located. The affected BAs and the zone names



Column Name


are identified below. For all other BAs, enter the same code as entered in the BA column.

BA WECC BA Organization Codes Report the BA where transmission is located. (See Appendix C — WECC Balancing Authorities)

RADS Transmission ID

NERC assigned ID Do not adjust or modify this cell.

Project Name Reporting entity defined project name Reporting entity defined project name. Enter the project name associated with this addition.

Project Status

Choose One: Under Construction: Construction of

the line has begun Planned: any of the following

o Permits have been approved to proceed

o Design is completeo Needed in order to meet a

regulatory requirement Conceptual: any of the following

o A line projected in a transmission plan

o A line that is required to meet a NERC TPL Standard or powerflow model and cannot be categorized as "Under Construction" or “Planned”

o Other projected lines that do not meet requirements of “Under Construction” or “Planned”

Completed: Project was completed during the prior year

Delayed - Load Growth Delayed - Permitting Challenges Delayed - Siting Challenges Delayed - Economics Delayed - Other (comment required) Cancelled - Load Growth

Choose one project status



Column Name


Cancelled - Permitting Challenges Cancelled - Siting Challenges Cancelled - Economics Cancelled - Other (comment required)

Tie Line A tie line connects two or more systems. A circuit connecting two BAA or two separate systems. Specify (Yes/No) whether the project is classified as a tie line.

Primary Driver

Choose One: Reliability Generation Integration

o Variable/Renewable Integrationo Nuclear Integrationo Fossil-Fire Integrationo Hydro Integration

Economics or Congestion Other

Choose one of the predefined drivers for each line addition. While it is understood that one line could serve multiple functions (i.e., reliability and economics), please specify the primary consideration/driver for this addition. Do not write in other drivers in these fields; instead, select “Other” and include an explanation in the comment field.

Secondary Driver(if applicable)

Choose One: Reliability Generation Integration

o Variable/Renewable Integrationo Nuclear Integrationo Fossil-Fire Integrationo Hydro Integration

Economics or Congestion Other

Choose one of the predefined drivers for each line addition. While it is understood that one line could serve multiple functions (i.e., reliability and economics), please specify the primary consideration/driver for this addition. Do not write in other drivers in these fields; instead, select “Other” and include an explanation in the comment field.

Terminal From Location

Beginning terminal point Enter the name of the beginning terminal point of the line.

Terminal Origin State

Beginning terminal state Enter the name of the state of the beginning terminal point of the line.

Terminal To Location

Ending terminal point Enter the name of the ending terminal point of the line.

Terminal Endpoint State

Ending terminal state Enter the name of the state of the ending terminal point of the line.



Column Name


Company Name

The name of the majority owner of the transmission line

Enter the name of the company that owns the majority of the transmission line.

EIA Company Code

Identify each organization by the six-character code assigned by EIA. Required for all projects within the U.S.

Entity Type Choose One: C - Cooperative F - Federally-owned I - Investor-owned M - Municipality S - State-owned O - Other

Identify the type of organization that best represents the line owner.

Ownership (%)

For jointly-owned projects, enter the percentages owned by the entity with the highest ownership shares. List each of the owners in the comments section with corresponding percentage of ownership. If a line is not jointly owned, enter 100 percent.

Line Type Choose One OH - Overhead UG - Underground SM - Submarine

Select the predominate physical location of the line conductor.

Voltage Type Choose One AC - Alternating Current DC - Direct Current

Select alternating current (AC) or direct current (DC).

Line Length (Circuit Miles)

For lines fully contained within a BAA, enter circuit miles (not linear miles) between the terminal origin and end point. If line crosses into multiple BAA, report only that portion (in circuit miles) located in your BA. Projects with a line length of less than 1 circuit miles should not be included.



Column Name


Operating Voltage Class (kV)

Choose One 100 - 120 121 - 150 151 - 199 200 - 299 300 - 399 400 - 599 600 +

For new lines, select the voltage class that the line is designed to operate. For existing lines that are being upgraded to a higher operating voltage class, enter the voltage class that the line will operate at after the upgrade.

Voltage Design (kV)

For new lines, manually enter the exact voltage the line is designed to operate. For existing lines that are being upgraded to a higher operating voltage class, enter the current voltage (prior to the upgrade).

Upgraded Voltage Design (kV)

Only required for existing lines that are being upgraded to a higher operating voltage class. Enter the exact voltage the line will operate at following the upgrade.

Circuits Per Structure Present

Choose One 1 Three-Phase Circuit 2 Three-Phase Circuits 3 Three-Phase Circuits TBD

The line structures are projected to utilize a one (1) to three (3) three-phase circuit, once operational.

Circuits Per Structure Ultimate

Choose One 1 Three-Phase Circuit 2 Three-Phase Circuits 3 Three-Phase Circuits TBD

For new projects, enter the number of three-phase circuits expected to be used on each tower. For the ultimate field, enter the total number of three-phase circuits that the tower is capable of accommodating.

Capacity Rating (MVA)

Enter the normal load-carrying capacity of the line in millions of volt-amperes (MVA).

Original In-Service Month

For delayed projects, select the original month the line was scheduled to be energized under the control of the system operator. This cell is required for delayed lines only.



Column Name


Original In-Service Year

For delayed projects, select the original year the line was scheduled to be energized under the control of the system operator. This cell is required for delayed lines only.

Expected In-Service Month

Select the expected month the line will be energized under the control of the system operator. This field is required for all projects.

Expected In-Service Year

Select the expected year the line will be energized under the control of the system operator. This field is required for all projects.

Cause of Delay/Other Comments

Describe any information available regarding the reasons for the delay. Provide any other important information regarding the project. For jointly-owned projects, list each of the owners with corresponding percentage of ownership.

Projected Transformer Additions

The {Projected Transformer} sheet should be completed by each BA for all transformer additions at 100 kV Low-Side and above projected for the eleven-year period beginning with the Actual Year. Replacement transformers should be reported and noted in the Description/Status column.

Column Name Definition /Instruction


Zone Enter the Zone where the transformer is located. The affected BAs and the zone names are identified below. For all other BAs, enter the same code as entered in the BA column.

BA Report the BA where transformer is located. (See Appendix C — WECC Balancing Authorities)

Project ID Provided by NERC staff for tracking purposes. Do not adjust or modify this cell.



Column Name Definition /Instruction

Status Choose One:

Under Construction Planned Conceptual Completed (Provide actual In-Service date in comment field) Delayed (Comment required) Cancelled (Comment required)

Name Enter the project name.

Low-Side Voltage (kV) Enter the Low-Side Voltage.

High-Side Voltage (kV) Enter the High-Side Voltage.

In-Service Month Enter the projected month the transformer will be energized under the control of the system operator.

In-Service Year The projected year the transformer will be energized under the control of the system operator.

Description/Status Provide a brief description/status on the projected transformer addition.


LAR Data Collection Manual: Appendix A — Modeling Area to Zones 1

Appendix A — Modeling Area to Zones

For BAs with resources in multiple modeling areas, enter the zone where the resource is located. The affected BAs and the zone names are identified below

Table 5 - Modeling Area to Zones Table

BA → AZPS WALC TEPC WACM PACE CISO IPCO

Modeling Area ↓ Zones Zones Zones Zones Zones Zones Zones

IID AZID

Arizona AZAZ WAAZ TEAZ

New Mexico AZNM WANM TENM

Colorado WACO

Wyoming WAWY PAWY

Idaho PAID

Utah PAUT

PG&E_Bay CIPB

PG&E_Vly CIPV

SCE CISC

SDGE CISD

Treas Vly IPTV

Magic Vly IPMV

Far East IPFE


LAR Data Collection Manual: Appendix B — Glossary for LAR Data Collection Manual 1

Appendix B — Glossary for LAR Data Collection Manual

Term DefinitionACTIVE CONSTRUCTION Active construction includes personnel consistently onsite, payroll met,

building materials delivery ongoing, turbine or other major items on order, etc.

ACTUAL YEAR The calendar year just completed for which actual results are reported.

BIOMASS Any organic material not derived from conventional fossil fuels. Examples are animal waste, agricultural or forest by-products, and municipal refuse.

CAPABILITY The maximum load that a generator, turbine, transmission circuit, apparatus, stations, or system can supply under specified conditions for a given time interval, without exceeding approved limits of temperature and stress.

Inoperable The coincident sum of capabilities (net generation) that could not be operated for reasons such as lack of fuel availability, legal restrictions, lack of manpower, etc., at the time of the peak demand for the month specified. Inoperable capability does not include scheduled maintenance or forced outages.

CAPACITY Synonymous with capability.

CAPACITY WITH FULL RESERVE

The highest (in availability) form of capacity transaction. The system is obligated to deliver power and energy at a specified degree of reliability. The selling system must purchase power or take other appropriate actions before curtailing the transactions.

CAPACITY WITHOUT RESERVE

A transaction in which the capacity is supplied when available from the aggregate of generating units of the seller. The seller does not have to deliver power and energy whenever certain system conditions exist that would impose undue hardship on the seller.

CONSERVATION Implementation of measures that decrease energy consumption of targeted end uses resulting in beneficial load shape changes, often by encouraging the use of more efficient appliances and equipment.

DEMAND The rate at which electric energy is delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any designated interval of time.

The rate at which energy is being used by the customer.



Term DefinitionCoincident Two or more demands that occur in the same demand interval.

Firm That portion of the Demand that a power supplier is obligated to provide except when system reliability is threatened or during emergency conditions.

The maximum 60-minutes coincident load for the month specified. It includes transmission system losses and standby demand, and excludes station service, load management, and interruptible loads.

Non-coincident The sum of individual systems’ Peak Demands, regardless of when they occur. Non-coincident Peak Demand will always be greater than or equal to the Coincident Peak Demand.

Maximum (Peak) The highest hourly integrated Net Energy for Load within a Balancing Authority Area occurring within a given period (e.g., day, month, season, or year).

The highest instantaneous demand within the Balancing Authority Area.

Standby Standby Demand is demand that may be served, in accordance with contractual arrangements, to provide power and energy to a customer (often to a cogenerating industrial customer) as a second source or backup for outage of the customer’s generation. Standby power is intended to be used infrequently by any given customer. Probability considerations should be applied to determine the amount of standby demand included in firm load.

DEMAND-SIDE MANAGEMENT (DSM)

The term for all activities or programs undertaken by an electric system or its customers to influence the amount and timing of electricity use. Included in DSM are the planning, implementation, and monitoring of utility activities that are designed to influence consumer use of electricity in ways that will produce desired changes in a utility’s load shape, such as, direct load control, interruptible load, and conservation.

Direct Control Load Management (DCLM)

Demand-side management that is under the direct control of the system operator. DCLM may control the electric supply to individual appliances or equipment on customer premises. DCLM as defined here does not include Interruptible Demand.

Critical Peak-Pricing with Control

Demand-side management that combines direct remote control with a pre-specified high price for use during designated critical peak periods, triggered by system contingencies or high wholesale market prices. (This does not to include Critical Peak Pricing that does not have direct control but only has economic penalties if not followed.)



Term DefinitionLoad as a Capacity Resource

Demand-side resources that act as a capacity resource to commit to pre-specified load reductions for certain system conditions. (Similar to Interruptible demand, but is compensated differently.)

ENERGY Electric energy usually measured in gigawatt-hours.

FUEL CELL A device in which a chemical process is used to convert a fuel directly into electricity.

FULL RESPONSIBILITY PURCHASE

A Full Responsibility capacity purchase results when the seller is contractually obligated to deliver power and energy to the purchaser with the same degree of reliability as provided to the seller’s own native load (customers).

FULL RESPONSIBILITY SALE

A Full Responsibility capacity sale results when the seller is contractually obligated to deliver power and energy to the purchaser with the same degree of reliability as provided to the seller’s own native load (customers).

GENERATION The act or process of producing electric energy from other forms of energy; also the amount of energy so produced.

Gross Generation The total amount of electric energy produced by a generating station or stations, measured at the generator terminals.

Hydro A term used to identify a type of electric generating station, capacity, or capability, or output in which the source of energy for the prime mover is falling water.

Net Generation Gross generation less station use.

Pumped Storage Plant

A power plant utilizing an arrangement whereby electric energy is generated for peak load use by utilizing water pumped into a storage reservoir usually during off-peak periods. A pumped storage plant may also be used to provide reserve generating capacity.

Station Use Energy used in a generating plant as necessary in the production of electricity. It includes all energy consumed for plant light, power, and auxiliaries regardless of whether such energy is produced at the plant or comes from another source.

Thermal A term used to identify a type of electric generating station, capacity, or capability, or output in which the source of energy for the prime mover is heat.



Term DefinitionCogeneration Equipment used to produce electric energy and forms of useful thermal

energy, such as heat or steam, used for industrial, commercial, heating, or cooling purposes, through sequential use of energy. Combined Cycle generation is not considered cogeneration.

LOAD An end-use device or customer that receives power from the electric system.

Firm Load Electric power load (including standby demand) intended to be served at all times during the period covered by a commitment, even under adverse conditions.

Interruptible Demand (Load)

Demand that the end-use customer makes available to its Load- Serving Entity via contract or agreement for curtailment.

MARGIN The differences between capacity and peak demand. Margin is usually expressed in megawatts.

Reserve The difference between capacity and firm peak demand divided by firm peak demand expressed as a percentage. The reserve margin (RM) equals the capacity margin (CM) divided by one minus the capacity margin or RM = CM / (1 - CM).

NET ENERGY The electric energy requirements of a system. It is defined as system net generation plus energy received from others less energy delivered to others. It includes system losses but excludes energy required for “pumping up” pumped storage plants.

OUTAGE The period during that a generating unit, transmission line, or other facility is out-of-service.

Forced The removal from service availability of a generating unit, transmission line, or other facility for emergency reasons.

The condition in which the equipment is unavailable due to unanticipated failure.

Scheduled The shutdown of a generating unit, transmission line, or other facility, for inspection or maintenance, in accordance with an advance schedule.

RESERVE Synonymous with Margin.



Term DefinitionSYSTEM The physically connected generation, transmission, distribution and other

facilities operated as an integral unit under one control, management, or operating supervision, often referred to as “electric system,” “electric power system” or “power system.”

TRANSFER The transfer of electrical energy across a point or points of interconnection during a stated period. For purposes of this request transfers include: transfers, sales, purchases, imports, exports, firm capacity transfers, contractual firm transfers, firm system transfers, full responsibility purchases, and full responsibility sales.


LAR Data Collection Manual: Appendix C — WECC Balancing Authorities 1

Appendix C — WECC Balancing Authorities


LAR Data Collection Manual: Appendix C — WECC Balancing Authorities 2

State/Province Abbreviations

ABBREVIATION STATE/PROVINCE

AB .................................................................Alberta

AZ .................................................................Arizona

BC ...................................................British Columbia

CA ..............................................................California

CO ..............................................................Colorado

ID ....................................................................Idaho

KS ..................................................................Kansas

MT .............................................................Montana

MX ...............................................................Mexico

NE ..............................................................Nebraska

ND .......................................................North Dakota

NM .......................................................New Mexico

NV ................................................................Nevada

OK ............................................................Oklahoma

OR .................................................................Oregon

SD .......................................................South Dakota

TX ....................................................................Texas

UT .....................................................................Utah

WA ........................................................Washington

WY ............................................................Wyoming


LAR Data Collection Manual: Appendix D — WECC Criteria for Uniform Reporting of GeneratorRatings 1

Appendix D — WECC Criteria for Uniform Reporting of Generator Ratings

A. STEAM TURBO-GENERATOR CAPABILITY

(No regulating or emergency loading limits included)

1. Conditionsa. All essential equipment available for service.

2. Ratings (report on summer, winter, or monthly basis) –Those net kW ratings for individual generating units that the owner is willing to use for regular day-to-day operation. An owner may include units that are not operated on a day-to-day basis but that are maintained in operable condition. Ratings would be based on the capability expected by the operator at the time of the monthly or seasonal peak load. Such ratings will be based on condensing water temperatures and ambient temperatures that influence capability at the time of peak load (use a, b, or c below as it applies to a system's use of the unit).

a. Unit for a 4-hour period.b. Unit for a 10-hour period.c. Unit for a 24-hour period.

For a common header plant, use a, b, or c above on a plant basis.

B. GAS TURBO-GENERATOR CAPABILITY


1. Conditionsa. All essential equipment available for service.

2. Ratings (report on summer, winter, or monthly basis) –Those net kW ratings for individual generating units that the owner is willing to use for regular day-to-day operation. An owner may include units that are not operated on a day-to-day basis but that are maintained in operable condition. Ratings would be based on the capability expected by the operator at the time of the monthly or seasonal peak load. Such ratings will be based on ambient temperatures that influence capability at the time of peak load (use a, b, c or d below as it applies to a system's use of the unit).

a. Unit for a 1-hour period.b. Unit for a 4-hour period.c. Unit for a 10-hour period.d. Unit for a 24-hour period.


LAR Data Collection Manual: Appendix D — WECC Criteria for Uniform Reporting of GeneratorRatings 2

C. HYDRO TURBO-GENERATOR CAPABILITY


1. Conditions (Median and Adverse Water)a. All essential equipment available for service.b. Water conditions based upon minimum head during that period of the month

or season when system peak is maximum.c. For multiple-unit hydro plants, each unit is assigned a rating by apportioning

the combined capabilities among the units.2. Ratings (report on summer, winter, or monthly basis) –Those net kW ratings for the

individual generating plant that the owner is willing to use for regular day-to-day operation.

a. Plant for a 1-hour period.b. Plant for a 4-hour period (or longer period if the system's daily peak period is

longer than 4 hours).

Prepared and Submitted by the

Operating Studies Work Group

Approved by the Technical Operations

Subcommittee, February 15, 1974

Approved by the Operations Committee

March 14, 1974

Submitted to the Executive Committee

March 21, 1974

Adopted by the Executive Committee

June 20, 1974


Web view · 2016-06-17LAR Data Collection Manual: Section 1 — Excel Workbook5. LAR...

Documents

Transcript of Web view · 2016-06-17LAR Data Collection Manual: Section 1 — Excel Workbook5. LAR...