WESTERN ELECTRICITY COORDINATING COUNCIL DATA

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 • W W W . W E C C . B I Z

1 5 5 N O R T H 4 0 0 W E ST • S U I T E 2 0 0 • S A L T L A K E C I T Y • U T A H • 8 4 1 0 3 - 1 1 1 4 • P H 8 0 1 . 5 8 2 . 0 35 3 • F X 8 0 1 . 5 8 2 . 3 9 1 8

WESTERN ELECTRICITY COORDINATING COUNCIL

DATA COLLECTION MANUAL

January 17, 2014

WECC Data Collection Manual

January 17, 2014 ii

This page intentionally left blank.


January 17, 2014 iii

Table of Contents Introduction and Overview ............................................................................................... 1

Attachment A: Excel Workbook ................................................................................... 5

Attachment B: Existing and Planned Generation Reporting Instructions ................... 11

Reporting Instructions for Existing Generation and Generation Additions Data .................................................................................... 13

Existing Generation and Generation Additions Data: Facility Record Format ................................................................................... 15

Correlation of NERC Class Codes and WECC Class Codes ............. 22

Attachment C: Peak Demands, Demand-Side Management, Energy Loads, and Resource Outages Instructions ................................................... 25

Input Guide for Peak Demand Loads, Demand-Side Management, and Outages Data ....................................................... 27

Data Types and Codes ....................................................................... 28

Actual Peak Demand Loads, DSM, and Outages Data Code Definitions ........................................................................................... 31

60-Minute Peak Demand MW ............................................................ 31

Estimated Peak Demand Loads, DSM, and Outages Data Code Definitions ........................................................................................... 32

Actual and Estimated Peak Demand Loads Coding Data Record Format ................................................................................... 33

Energy Loads Instructions .................................................................. 35

Actual and Estimated Energy Loads Coding Data Record Format ................................................................................................ 36

Attachment D: Reliability and Supply Assessments ................................................... 37

Transfer Path Capabilities .................................................................. 39

Load Temperature Sensitivity and Extreme Forecast Data ................ 39

Regulating Reserves .......................................................................... 40

Energy Efficiency ................................................................................ 40

Attachment E: Miscellaneous Data ............................................................................ 43

Hourly Demand .................................................................................. 45

Hourly Wind Production ...................................................................... 45

Hourly Solar Production ...................................................................... 46


January 17, 2014 iv

Hourly Hydro Production .................................................................... 47

Projected Transmission Line Additions ............................................... 48

Projected Transformer Additions ........................................................ 52

Demand-Side Management (DSM) Programs .................................... 54

Appendix A: Glossary for WECC Data Collection Manual ...................................... 55

Appendix B: WECC Balancing Authorities and Abbreviations ................................ 63

WECC Balancing Authorities .............................................................. 65

State Abbreviations ............................................................................ 66

Appendix C: WECC Criteria for Uniform Reporting of Generator Ratings ............... 67

Appendix D: Information Sharing Policy .................................................................. 71


January 17, 2014 1

Introduction and Overview

Purpose

The Western Electricity Coordinating Council (WECC) Data Collection Manual (Manual) provides instructions for reporting various loads and resources (L&R) information that the 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 L&R information are used by the North American Electric Reliability Corporation (NERC) in its reliability assessment reports.1 The information is also the basis for the resource adequacy evaluation contained in WECC’s Power Supply Assessment (PSA).2 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.3 Annual and seasonal filings are submitted to NERC under NERC’s Standards and Guides compliance templates, according to NERC Rules and Procedure Section 800.4

Data Submission Due Date The data must be submitted to WECC by the first Friday of March.

Important Note to Member and Balancing Authority Representatives:

Information Reporting Responsibility

Planning Coordinating Committee (PCC) representatives are responsible for reporting L&R information for their organizations.5

PCC Representatives of Balancing Authorities The PCC representatives of the organizations that operate the BAs in the Western Interconnection are responsible for reporting the requested information. The L&R information is for the entire BA area (both member and nonmember entity information) and is to include the BA’s information as well as the information for all non-BA entities within the BA’s area. The non-BA entity information includes planning information such as generation additions, load forecasts of LSEs, and scheduled maintenance outages. The PCC or Member representatives of the non-BA entities are responsible for reporting their organizations’ information to the BA and for developing appropriate data collection

1 NERC Assessments 2 WECC Power Supply Assessments 3 http://www.eia.doe.gov/cneaf/electricity/page/eia411/eia411.html 4 http://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx 5 PCC Charter

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

http://www.wecc.biz/library/default.aspx?RootFolder=%2flibrary%2fWECC%20Documents%2fPublications%2fPower%20Supply%20Assessments&FolderCTID=0x012000278A29140A43884799CB122F821DFD01&View=%7b8D18396E%2d7F8B%2d4472%2dAB30%2d18D2A9576FF0%7d

http://www.eia.doe.gov/cneaf/electricity/page/eia411/eia411.html

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

http://www.wecc.biz/library/Documentation%20Categorization%20Files/Charters/PCC/PCC%20Charter.pdf


January 17, 2014 2

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. It is important to note that, 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 WECC 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.

PCC or Member Representatives of Non-Balancing Authority Entities The PCC or Member representatives of non-BA entities are responsible for responding to BA requests for planning information such as generation additions, load forecasts, and scheduled maintenance outages. PCC or Member representatives 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. However, the PCC or Member representatives are ultimately responsible for the quality and timeliness of the data reported for their organizations.

Information Requirements and Manual Overview This Manual consists of five attachments and associated appendices. Attachment A consists of an explanation of pages and terms found in the Excel workbook used to collect data requested in Attachments B and C. Attachment B contains instructions for reporting existing and planned generation capacity. Attachment C is the instruction for reporting peak demands, energy loads, and resource outages. Attachment D contains the reporting instruction for Power Supply Assessment data and Attachment E contains the instructions for several miscellaneous requests.

Long-Term Reliability Assessment (LTRA) and Season Assessment Information Requirements The LTRA data is primarily gathered through the WECC data request and the season assessment information request. The LTRA incorporates the transfers between subregions that are derived during the development of the PSA. Additional information and/or narrative questions for the LTRA and the Seasonal Assessments will be requested from the BAs after WECC receives these instructions from NERC.

Data Confidentiality The WECC Information Sharing Policy (ISP) addresses confidentiality procedures for L&R data. All data, except as specified in the ISP, will be considered non-confidential. Section E - Information Not Shared Externally states: "The following types of information may be Confidential Information under Section 1500 of the NERC Rules of Procedure or the WECC Confidentiality Policy, Transmission Function Information under the FERC


January 17, 2014 3

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”.

3. Loads and Resources a. Actual year hourly demand data (collected under the Information

Reporting Policy) i. WECC may make this information public when it has been made

public by FERC b. Projected peak demand (years 1-3) c. Projected energy forecasts (years 1-3) d. Scheduled peak hour generation outages (years 1-3)

Future year peak demands, future year energy load, and future year scheduled outages data beyond three years will not be deemed confidential."

Data Submission The completed Excel workbook should be sent via email to [email protected] on or before the Data Submission Due Date. Since BAs are responsible for reporting data from non-BA entities within their respective areas, BAs should establish earlier dates for collecting coordinated future year data from the non-BA entities. The LRS procedures specify that the LRS chair will contact the PCC representatives of reporting entities that have not submitted their data by the Data Submission Due Date. The LRS and PCC chairs will also contact the PCC representatives of reporting entities that have provided data that are incomplete or are inconsistent with these reporting instructions.

Comments on this Manual Questions on data reporting, or suggestions for improving the Data Collection Manual, should be directed to WECC staff, Dick Simons or Layne Brown, at (801) 582-0353.


January 17, 2014 4



January 17, 2014 5

Attachment A: Excel Workbook

WECC Data Collection Manual Attachment A

January 17, 2014 6



January 17, 2014 7

Excel Workbook An Excel workbook is used for the L&R data reporting. The workbook contains L&R data that must be updated and, as needed, have projections added. There are also several reports and charts that show results related to the data submitted through the workbook, along with some data checking. 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 in the workbook.

Worksheet Description Main Used to hold pertinent information about the represented area.

Status Explains data requirements and provides 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, outages, and actual transfers.

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. load_chart A series of charts representing the reported loads and load forecasts. load_comp Comparison sheet of previous and current energy load data. LoadOut Comparison sheet of previous and current peak demands data.

Paths Data input sheet for transmission paths between modeling areas.

Tsens Data input sheet for temperature sensitivity information, and seasonal extreme load forecasts.

Regulating Reserves Data input sheet for regulating reserves information.

Energy Efficiency Data input sheet for energy efficiency information.

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

Hourly Wind Data input sheet for actual hourly wind generation information. (Multiple sheets if required)

Hourly Solar Data input sheet for actual hourly solar generation information. (Multiple sheets if required)

Hourly Hydro Data input sheet for actual hourly hydro generation information. (Multiple sheets if required)

Projected Data input sheet for projected transmission additions.


January 17, 2014 8

Worksheet Description Transmission

Projected Transformer Data input sheet for projected transformer additions.

DSM Programs Voluntary data input sheet for DSM programs.

DVal Data validation checks used in conjunction with the Status sheet of the workbook.

There are a few other worksheets in the workbook. These are hidden intentionally and should not be modified or disturbed. These are for WECC staff only.

Data Reporting The data input sheets ({gen_exist}, {gen_add}, {peak_data}, and {energy_data}) must be updated and checked as part of the L&R data submittal process. The descriptions of the data input sheets are presented below (see Attachments B and C for detailed instructions). There should not be any blank rows in the final versions of the data input sheets. When adding, copying, or deleting rows, it is recommended that row-level editing be used (i.e., click on the row heading(s) to select). Also, data that needs to be deleted should be deleted, not lined through. Lined through data are not excluded when a spreadsheet sums numerical values. The existing generation {gen_exist} worksheet is a detailed list of the generating units in the BA area with in-service dates up to the end of the actual year. Check the data provided in the data request spreadsheet for accuracy and update as necessary, including updating actual retirement dates. If there are older existing units missing from the list, or new units that need to be added, insert a new row and provide the information requested. The generation additions {gen_add} worksheet is a detailed list of the generating units in a BA’s area that represent anticipated increases or decreases in generating capacity during future years. This includes retirements, up-rates and derates to existing plants, and new generation construction. Update the provided list per the instructions and add rows as necessary to provide information for new additions and other changes. The {peak_data} worksheet is a listing of BA loads, outages, and other miscellaneous data. The {energy_data} worksheet contains the actual and projected energy load data for the BA.

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.


January 17, 2014 9

1. 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’ 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 prior actual year load to the current actual year load and from the current actual year load to the first future year forecast load should include references to the actual weather conditions experienced during the prior actual year and the current actual year. The charts in the {load_chart} worksheet can also be helpful for locating inconsistent and/or erroneous data.

2. 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. Charts in the {load_chart} worksheet show the patterns from year to year. A chart is also provided that presents a comparison of the actual peak demands and energy loads to the Hourly Demand data.

Calculation The calculation mode should be set to manual to avoid long calculation delays each time data is entered. The workbook may require several minutes to calculate. With the calculation mode set to manual, the formulas are not calculated and cell results are not automatically updated. Pressing function key F9 will initiate a manual calculation of the entire workbook. Once the calculation is completed, the word ‘Ready’ will be displayed at the left of the status bar. The calculation progress display is generally not indicative of the actual progress. Typing or clicking with the mouse will often interrupt the calculation process, so it is important to be patient. If the word ‘calculate’ is displayed on the status bar, then a change has been made to the workbook that may or may not be reflected in the results. It is recommended that users enter as much data as possible before initiating the calculation process. Note that if the Automatic Calculation option is enabled, the workbook is also calculated each time that it is saved.

Data Submission After updating and checking the data, the workbook should be sent via email to [email protected]. The LRS procedures specify that the LRS chair will contact the PCC representatives of reporting entities that have not submitted their data in accordance with the Data Submission Due Date. The LRS chair may also contact the PCC representatives of reporting entities that have provided data that are incomplete or are not consistent with these reporting instructions.


January 17, 2014 10

Data Errors 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 L&R data submitted in the BA’s workbook. If the data checking process reveals the need for the BA to provide comments regarding the L&R 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.


January 17, 2014 11

Attachment B: Existing and Planned Generation Reporting

Instructions


January 17, 2014 12


WECC Data Collection Manual Attachment B

January 17, 2014 13

Reporting Instructions for Existing Generation and Generation Additions Data

Data Reporting Process Existing generation and generation additions worksheets are described in Attachment A of this Manual. 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 U.S., should be consistent with the data reported to the DOE in Form EIA-860. The existing generation {gen_exist} worksheet is a detailed list of all generating units in the BA area with in-service dates up to the end of the actual year. Check the data provided for accuracy and update as necessary, including updating 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. For units that were retired during the actual year, report zero (0) capacity in the summer and winter capacity columns, update the Retirement Date to reflect the actual retirement date, and update the Status Code to RE. If a unit was rerated during the actual year, report the new total capacity in the summer and winter columns. Units with a NERC class code of Existing-Inoperable (EI) are to be reported with a summer and winter capacity of zero (0). Units with a Status Code of OS are reported with a summer and winter capacity of zero (0). A cold standby unit should be reported as SB, with a summer and winter capacity that reflects the expected available capacity of the unit. Data for each unit that came into service during the actual year are to be added, with a Status Code of OP and a Commission date, to the {gen_exist} sheet 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 RE and a Retirement date, and removed from the {gen_add} sheet. The generation additions {gen_add} worksheet is a detailed list of the generating units in a BA’s area 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 (for one year only) with a hypen entered for the NERC Class Code, and a WECC Class Code of 5. This process allows WECC staff to track the progress of planned units.


January 17, 2014 14

Comments should be included in the (Published and/or Non-published) comment fields 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 a comment field. Also, use the comment field to report capacity commitment entities and their commitment shares of remote resources. Remote resources are defined as resources that are physically located in one BA area but have capacity commitments to an entity, or entities, located in another BA’s geographic footprint. In the comment field, enter the name of the capacity commitment entities and their commitment shares of each remote resource located in the BAs area 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.) Since WECC’s master database will be manually updated based on submitted worksheet revisions, highlight, in green, all worksheet cells (not rows) where changes are made. Updated worksheets should be submitted via email to [email protected] on or before the Data Submission Due Date.


January 17, 2014 15

Existing Generation and Generation Additions Data: Facility Record Format

Field Name Explanation EIA Plant Code EIA Plant Code

EIA Unit Code EIA Unit Code

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

Modeling Area/Zone Table

BA → AZPS WALC WACM PACE CISO IPCO

Modeling Area ↓ Zones Zones Zones Zones Zones Zones

IID AZID

Arizona AZAZ WAAZ

New Mexico AZNM WANM

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

Field Name Explanation BA Balancing Authority code (see Appendix B). Org Name/acronym of Load Serving Entity where the unit is located.

Unit Name Power Plant Unit Name (Unit Name plus Unit Number should create a unique identifier for the unit.)


January 17, 2014 16

Field Name Explanation Unit Number Unit Number (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) GT ....... Combustion (Gas) Turbine - Simple Cycle (includes jet engine design) IC ........ Internal Combustion Engine (diesel, piston, reciprocating) CA ....... Combined Cycle Steam Part CT ....... 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 future generation) CD ....... Combined Cycle Duct Firing HY ....... Hydraulic Turbine (includes turbines associated with delivery of water

by pipeline) HY-R ... Hydraulic Turbine that qualified as a renewable resource under

applicable state or province definition PS ....... Hydraulic Turbine – Reversible (pumped storage) BT ....... Turbines Used in a Binary Cycle (such as used for geothermal

applications) PV-T .... Solar Photovoltaic with Tracking PV-NT . Solar Photovoltaic without Tracking SP-S .... Solar Thermal with Storage SP-NS . Solar Thermal without Storage WT ...... Wind Turbine, Onshore WS ...... Wind Turbine, Offshore CE ....... Compressed Air Energy Storage FC ....... Fuel Cell OT ....... Other NA ....... Undetermined/Unknown BA ....... Energy Storage, Battery CP ....... Energy Storage, Concentrated Solar Power FW ...... Energy Storage, Flywheel ES ....... Energy Storage, Other HA ....... Hydrokinetic, Axial Flow Turbine HB ....... Hydrokinetic, Wave Body HK ....... Hydrokinetic, Other

Nameplate

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 US.


January 17, 2014 17

Field Name Explanation

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 all units within the US.

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 US.

Behind the Meter Enter “True” if the output of the unit is not included in hourly demand data.

BTM Summer Cap The unit’s summer capacity. Data to be entered in MW.

BTM Winter Cap The unit’s winter capacity. Data to be entered in MW.

For conventional technology generation, refer to WECC Criteria for Uniform Reporting of Generator Ratings (Appendix C) for rating instructions.

Field Name Explanation

Primary Fuel

The following options are included in the workbook: MWH .... Electricity used for energy storage BIT ....... Anthracite Coal and Bituminous Coal SUB ..... Subbituminous Coal LIG ....... Lignite Coal WC ...... Waste/Other Coal. Including anthracite culm, bituminous gob, fine

coal, lignite waste, waste coal SC ....... Coal Synfuel. Coal-based solid fuel that has been processed by a coal

synfuel plant; and coal-based fuels such as briquettes, pellets, or extrusions, which are formed from fresh or recycled coal and binding materials

PC ....... Petroleum Coke DFO ..... Distillate Fuel Oil. Including Diesel, No. 1, No. 2, and No. 4 Fuel Oils SG ....... Synthetic Gas, other than coal-derived SGC ..... Synthetic Gas, derived from coal JF ........ Jet Fuel KER ..... Kerosene RFO ..... Residual Fuel Oil. Including No. 5, No. 6 Fuel Oils, and Bunker C Fuel

Oil WO ...... Waste/Other Oil. Including Crude Oil, Liquid Butane, Liquid Propane,

Oil Waste, Re-Refined Motor Oil, Sludge Oil, Tar Oil, or other petroleum-based liquid waste

NG ....... Natural Gas PG ....... Gaseous Propane


January 17, 2014 18

Field Name Explanation Primary Fuel The following options are included in the workbook:

BFG ..... Blast Furnace Gas OG ....... Other Gas (coke oven, refinery etc.) NUC ..... Nuclear including Uranium, Plutonium, Thorium GEO..... Geothermal Steam WAT..... Water at a conventional hydroelectric turbine- base ratings on median

hydro conditions AB ........ Agriculture Crop Byproducts/Straw/Energy Crops BLQ ..... Black Liquor LFG...... Landfill Gas MSW .... Municipal Solid Waste OBL ..... Other Biomass Liquids OBS ..... Other Biomass Solids OBG..... Other Biomass Gas (includes digester gas, methane, and other

biomass gases) PUR ..... Purchased Steam SLW ..... Sludge Waste TDF...... Tire-derived Fuels WDL..... Wood Waste Liquids excluding Black Liquor (includes red liquor,

sludge wood, spent sulfite liquor, and other wood-based liquids) WDS .... Wood/Wood Waste Solids. Including paper pellets, railroad ties, utility

poles, wood chips, bark, and wood waste solids SUN ..... Solar WND .... Wind OTH ..... Other (Describe in Comments) WH ...... Waste heat not directly attributed to an energy source. WH should only

be reported where the energy source for the waste heat is undetermined

Secondary Fuel

Use one of the options listed above under primary fuel. Fuel used for start-up should not be reported as an alternate fuel.

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.

Field Name Explanation 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 (Should be reported as EC in NERC

Class Code) SB ........ Cold standby, 3-6 mo. to reactivate (Should be reported as EC in

NERC Class Code) OS ....... Out of service (Should be reported as EI in NERC Class Code) RE ....... Retired (Should be reported as EC in NERC Class Code)


January 17, 2014 19

Field Name Explanation Status Code

Generation Additions/Repowers Only P .......... Planned for installation but not under active construction L .......... Regulatory approval pending but not under active construction (started

site preparation) T .......... Regulatory approval received but not under active construction U .......... 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 status RA ....... Previously retired or deactivated generator planned for reactivation RT ........ Existing generator scheduled for retirement (indicate reason in

comments field) FC ........ Existing generator planned for conversion to another fuel or energy

source IP ......... Indefinitely postponed (WECC Class Code 5) CO ....... Change of ownership (including change of shares of jointly-owned

units) State State Code (see Appendix B). County County where generation is located. NERC 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 capability6 and have a Power Purchase Agreement (PPA)7 with firm transmission,

• Unit must be classified as a Designated Network Resources8,

6 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). 7 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. 8 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


January 17, 2014 20

Field Name Explanation NERC Class Code

• 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 existing generator units, or portions of existing generator units, that are physically located within the assessment [balancing authority] area that do not qualify as Existing-Certain when examining the period of peak demand for each season/year. Accordingly, these units, or portions of units, may not be available to serve peak demand for each season/year.

EI - Existing-Inoperable - This category contains generation resources that are out-of-service and cannot be brought back into service to serve load during peak demand. However, this category can include inoperable resources that could return to service at some point in the future. This includes ALL existing generation within a Region or subregion not included in Existing-Certain or Existing-Other.

FUTURE RESOURCES Enter the class code that best reflects the current status of generation additions. T1 - Tier 1 - 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:

• Resource construction is underway or complete (not in commercial operation),

• Resource has been issued an approved Power Purchase Agreement (PPA),

• Resource has been designated or approved by a market operator and an Interconnection Agreement has been signed,

• Resource has been specifically included in an Integrated Resource Plan or under a regulatory environment that mandates a resource adequacy requirement,

• Resource has been identified by a Load-Serving Entity (LSE) to meet the obligation to serve load.

T2 - Tier 2 - Planned units in Tier 2 (that do not meet the requirements of Tier 1), must meet at least one of the following requirements when examining the period of peak demand for each season/year:

• All regulatory approvals, including those for inclusion in the rate base

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.


January 17, 2014 21

Field Name Explanation have been requested,

• A Power Purchase Agreement (PPA) or Generation Interconnection has been requested.

T3 - Tier 3 - Planned units in Tier 3 include all other announced units that do not meet the requirements of Tier 1 or Tier 2 when examining the period of peak demand for each season/year.

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 resources 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 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.


January 17, 2014 22

Correlation of NERC Class Codes and WECC Class Codes

NERC Class Codes

WECC Class Codes

EC 0

EO*

T1 1 2 3

T2 2 3

T3 4 EI 4 - 5

* 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. Field 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.

Conceptual generation only

Month and Year unit is conceptually 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.XXXX/ –XX.XXXX 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.XXXX/ –XXX.XXXX 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.

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

Wind/Solar/Hydro reporting area

For Wind, Solar or Hydro Generation, indicate the reporting area where the generation is located or, for new construction, will be located. See the drop-down list on the respective Wind, Solar, or Hydro workbook sheets.

TEPPC Wind/Solar For Wind or Solar Generation, indicate the TEPPC Profile


January 17, 2014 23

Field Name Field Content Explanation Profile Profile Location where the generation is located or, for new construction, will

be located. If the wind facility is not located in or near a TEPPC Profile, do not enter a code in this cell. See TEPPC Renewable Energy Cases9 for Profile names.

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.

9 Document is available on the WECC website at: http://www.wecc.biz/committees/StandingCommittees/PCC/LRS/Shared%20Documents/Wind%20Profiles/Renewable%20Energy%20Generation%20Paper.pdf

http://www.wecc.biz/committees/StandingCommittees/PCC/LRS/Shared%20Documents/Wind%20Profiles/Renewable%20Energy%20Generation%20Paper.pdf



January 17, 2014 24

This page intentionally left blank


January 17, 2014 25

Attachment C: Peak Demands, Demand-Side Management, Energy

Loads, and Resource Outages Instructions


January 17, 2014 26


WECC Data Collection Manual Attachment C

January 17, 2014 27

Input Guide for Peak Demand Loads, Demand-Side Management, and Outages Data

Introduction Peak demand L&R information is collected to provide a data base that may be used to prepare power supply evaluations for the WECC subregions’ report to NERC and for other sub-areas, including the zones used in the PROMOD model that are represented in the LTRA and PSA. To accomplish this, the following data are required: 1. Loads – Both firm and non-firm, include transmission losses and Standby Demand

but not station use, self-serve load (behind the meter), or pumped storage pumping, are to be reported separately.

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

hydro and non-hydro are to be reported. A discussion about each of these required data types is presented in the next section of this manual. This discussion section is followed by a section that presents detailed information about the required data codes and data formats that must be used when populating the data responses. Monthly peak demand L&R 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 eleven 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 BA area.


January 17, 2014 28

Data Types and Codes

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. DDSM total program enrollments are reported under data code 3.

• Firm peak demand load data are reported as Code 1. Firm peak demand includes transmission losses and Standby Demand but does not include station use, self-serve load (behind the meter), or pumped storage pumping served at time of monthly BA peak demand during the actual year. For future years one through eleven, firm peak demand load data are to include transmission losses and the amount of Standby Demand, but does not include station use, self-serve load (behind the meter), or pumped storage pumping that is expected to be served at time of monthly BA peak demand.

• For actual year, non-firm peak demand load data are reported as Code 2. It includes the amount of non-firm Dispatchable DSM (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.10

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 demands are designated by an 'I' in column C (DSM Code) 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 an ‘L’ in column C (DSM Code) and are the amount of customer demand that can be interrupted at the time of the BAs monthly peak.

10 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.


January 17, 2014 29

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 ‘P’ in column C (DSM Code) 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 an ‘R’ in column C (DSM Code) 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 contractual 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 an 'IT' in column C (DSM Code) and is the amount of customer demand enrolled as IL.

o Direct Control Load Management (DCLM) program totals are designated by a ‘LT’ in column C (DSM Code) and represents the amount of customer demand enrolled in DCLM programs.

o Critical Peak-Pricing with Control (CPP) program totals are designated by a ‘PT’ in column C (DSM Code) and is the amount of customer demand enrolled in CPP programs.

Note: CCP is a sub-set of DCLM. DSM associated with these programs should be counted only once as either DCLM or CCP but not as both.

o Load as a Capacity Resource (LCR) program totals are designated by a ‘RT’ in column C (DSM Code) 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.


January 17, 2014 30

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 (Codes 14-16) 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.


January 17, 2014 31

Actual Peak Demand Loads, DSM, and Outages Data 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 Inoperable Capability is reported either as Code 15/Code 15H or on the {gen_exist} sheet, not both. (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


January 17, 2014 32

Estimated Peak Demand Loads, DSM, and Outages Data 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 Inoperable Capability is reported either as Code 15/Code 15H or on the {gen_add} sheet, not both. (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 field the expected monthly reduction in energy, in GWh, associated with the inoperable capability. Contact WECC staff with questions.)

Load Forecasting Information New Energy Efficiency (Impacts).............................................................................. 70

Permanent changes to electricity usage at peak conditions, through use of more efficient end-use devices or more effective operation of existing devices. Generally these measures result in reduced consumption across most hours of a month, rather than event-driven targeted load reductions affecting only a few hours. Only effects of new programs on estimated loads should be reported. [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.]

Standby Demand...................................................................................................... 73 Demand 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.


January 17, 2014 33

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

B Year Year

C DSM Code

For data Code 2 (Non-firm peak demand) I - Interruptible L - Load Management P - Critical Peak-Pricing with Control R - Load as a Capacity Resource

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

D Code Data Code - Identifies type of data (see previous tables for actual and future year codes)

E 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.




IID AZID

Arizona AZAZ WAAZ


Colorado WACO

Wyoming WAWY PAWY

Idaho PAID

Utah PAUT

PG&E_Bay CIPB

PG&E_Vly CIPV

SCE CISC

SDGE CISD


January 17, 2014 34

Treas Vly IPTV

Magic Vly IPMV

Far East IPFE

F BA WECC BA Organization Codes (See Appendix B)

G, H, I NA NA J – U Jan-Dec Monthly Values

V Comment Comment


January 17, 2014 35

Energy Loads Instructions

Energy load data are reported as firm and non-firm loads under data Codes 1 and 2 respectively in column D of 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 fence), or pumped storage pumping and including 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 columns J through U. All energy load numbers are to be reported in gigawatt-hours (GWh).


January 17, 2014 36

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)

COLUMN HEADING DESCRIPTION B Year Year C NA NA

D Code Data Code - Identifies type of data :

1 - Firm Energy 2 - Non-Firm Energy

E 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 below. For all other BAs, enter the same code that is entered in the BA column.




IID AZID

Arizona AZAZ WAAZ


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

F BA WECC BA Organization Codes (See Appendix B) G, H, I NA NA J – U Jan-Dec Monthly Values

V Comment Comment


January 17, 2014 37

Attachment D: Reliability and Supply Assessments


January 17, 2014 38


WECC Data Collection Manual Attachment D

January 17, 2014 39

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 PROMOD 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 (column A) should be reported in both the {Paths} and {Projected Transmission} worksheets.

Detailed Column Descriptions for updating the {Paths} worksheet Column Heading Data Description

J 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.

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

L 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 PROMOD to calculate transfers for the NERC LTRA and the WECC PSA.

M 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.

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

O 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 PROMOD to calculate transfers for the NERC LTRA and the WECC PSA.

P Loss % The transmission loss percent on the path. Q Wheel $/MWh The cost for wheeling on the path. These charges are used in

PROMOD to calculate transfers for the NERC LTRA and the WECC PSA.

Term Definition

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.

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. These limits are used in PROMOD to calculate transfers for the NERC LTRA and the WECC PSA.

Load Temperature Sensitivity and Extreme Forecast Data

Load temperature sensitivity data requested provides a basis for modeling extreme weather conditions in the Western Interconnection for the NERC LTRA and the WECC


January 17, 2014 40

PSA. In providing the requested data, BAs with non-BA operator entities are asked to make best efforts to factor those loads into their response. Provide a best estimate where the requested data are not available due to special load forecasting methodologies.

In addition, NERC has requested that each BA provide an Extreme Load Forecast for the upcoming summer and winter seasons. Extreme Load Forecast is defined as a “90/10” forecast. Provide the forecasts on line 3 of the {Tsens} sheet of the workbook.

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 as either a MW amount or as a percentage of load.

Energy Efficiency (VOLUNTARY)

In addition to its use by WECC, the Transmission Expansion Planning Policy Committee (TEPPC) study program specifies that the “reference case be guided by existing utility integrated resource plans (IRPs), and other utility-level information, with appropriate review from state regulators,” and, specifically, that the load forecast be “consistent with utility and state assumptions on energy efficiency, DSM, and demand response.” Specifically, TEPPC relies on the LRS data collection process for securing necessary data to be used in developing the reference case load forecast:

1. The reference case load forecast should reflect the expected energy and peak demand savings achieved through (a) ratepayer-funded energy efficiency and demand response programs, and (b) standards resulting from existing state and federal laws and regulatory decisions in place as of March 1 of each year.

2. In the case of ratepayer-funded energy efficiency and demand response programs, expected energy and peak demand savings should be based on the level of savings specified in energy efficiency resource standards, integrated resource plans, and DSM program plans. Programs should be assumed to continue at the annual savings levels in the last year covered by the existing policies or plans. In the absence of any specific policy or resource plan, savings should be assumed to continue at current levels.

3. In the case of federal and state appliance efficiency standards, the reference case load forecast should reflect the savings that are realized in the future as a result of standards that are already in place, as well as expected savings from standards that are scheduled to take effect over the TEPPC study period.


January 17, 2014 41

TEPPC will use the data collected on energy efficiency to create a set of adjusted load forecasts, developed by deducting from the balancing authorities’ load forecasts some amount of incremental energy and peak demand savings. Collecting program-specific data as defined below will also help to track program performance and to quantify the level of energy efficiency, DSM, and demand response modeled.

On the {Energy Efficiency} worksheet, report the monthly reduction in the submitted load forecast (GWh) from all ratepayer-funded energy efficiency programs implemented over the forecast period. Only include the impact of future energy efficiency programs captured within the submitted forecast.

Report the future energy efficiency program savings for each of the following end-use types:

• Lighting savings is designated by an 'L' in column B (EE Code) of the data record and is the amount of monthly energy savings resulting from all future energy efficiency programs that are captured within the submitted load forecast and that primarily target lighting measures.

• Heating, ventilation, and air-conditioning (HVAC) is designated by an 'H' in column B (EE Code) of the data record and is the amount of monthly energy savings resulting from all future energy efficiency programs that are captured within the submitted load forecast and that primarily target HVAC measures.

• Other savings is designated by an 'O' in column B (EE Code) of the data record and is the amount of monthly energy savings resulting from all future energy efficiency programs that are captured within the submitted load forecast and that primarily target measures affecting end-uses other than lighting or HVAC.

• Report the total monthly energy savings from all future energy efficiency programs, across all end use categories, using a code ‘T’ in column B. This total should be equal to the sum of values reported for the three aforementioned end-use categories (codes L, H, and O). If energy efficiency program savings by end-use category are not available, report only the total (code ‘T’).


January 17, 2014 42



January 17, 2014 43

Attachment E: Miscellaneous Data


January 17, 2014 44


WECC Data Collection Manual Attachment E

January 17, 2014 45

Hourly Demand

In the {Hourly Demand} worksheet column A corresponds to the hour from the actual year and column B correspond to BA’s hourly data. 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 column B, the actual hourly demand (in MWs) corresponding to each hour in column A. Additional instructions are included on the {Hourly Demand} sheet. 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 following BAs, whose areas contain several modeling zones, should report the Hourly Demand data by the following zones:

Balancing Authority PACE CISO IPCO Zone

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

Idaho, Far East IPFE

Hourly Wind Production

BAs that report a wind resource on the {gen_exist} are to reports the nameplate capacity, available capacity and actual generation for each hour of the year on the {Hourly Wind Profile} sheet as requested below. One sheet should be used for each Wind Profile and additional sheets may be added to the workbook as needed to record profile-specific data. Wind generation that does not fit into any Wind Profile should be reported on a separate sheet, leaving the Wind Profile (F1) cell blank.

Column Row Field Name Definition Instructions A Hour of the year Hour of year reported


January 17, 2014 46

Column Row Field Name Definition Instructions

B 1 Time Zone Time zone where generation is located

Report the time zone for where generation is located.

B

Nameplate 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 capacity from that hour forward.

C

Available Capacity

The total nameplate capacity less any capacity unavailable due to forced or planned outages.

Report the sum of all nameplate capacity less capacity unavailable due to forced or planned outages only. Do not reduce available capacity for control measures, e.g., blade feathering. Report in MWs.

D 1 Reporting Area Reporting Area where generation is located

Report the Reporting Area where the generation is located (use dropdown).

D Actual Hourly

Generation Actual hourly generation in MWs.

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

F 1 TEPPC Wind Profile Regional location of generation

Report the Profile name for the location of the generation. If the wind facility is not located in or near a TEPPC Wind Profile, leave this cell blank. (See TEPPC Renewable Energy Cases11 for Profile names)

Hourly Solar Production

BAs that report a solar resource on the {gen_exist} are to report the nameplate capacity, available capacity and actual generation for each hour of the year on the {Hourly Solar Profile} sheet as requested below. One sheet should be used for each Solar Profile and additional sheets may be added to the workbook as needed to record profile-specific data. Solar generation that does not fit into any Solar Profile should be reported on a separate sheet, leaving the Solar Profile (F1) cell blank.








January 17, 2014 47


B

Nameplate 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 capacity from that hour forward.

C

Available Capacity The total nameplate capacity less any capacity unavailable due to forced or planned outages.

Report the sum of all nameplate capacity less capacity unavailable due to forced or planned outages only.


Report the Reporting Area where generation is located (use dropdown).

D

Actual Hourly Generation Actual hourly generation in MWs. Report the actual energy generation for the solar location. Report in MWs.

F 1 TEPPC Solar Profile Regional location of generation

Report the Profile name for the location of the generation. If the solar facility is not located in or near a TEPPC Solar Profile, leave this cell blank. (See TEPPC Renewable Energy Cases12 for Profile names)

Hourly Hydro Production

BAs that report a hydro resource on the {gen_exist} are to report the nameplate capacity, available capacity and actual generation for each hour of the year on the {Hourly Hydro Profile} sheet as requested below. WECC has not requested this data in prior requests and asks that data for the past five years be reported. One sheet should be used for each type of hydro resource; Storage Capable, Run-Of-River, and Pump-Storage. (Contact WECC staff with questions.)




B

Nameplate Total nameplate capacity of that hydro type

Report the sum of nameplate capacity of all generation installed of that hydro type. Report in MWs. Indicate when new generation is installed by increasing the capacity from that hour forward.





January 17, 2014 48


C

Available Capacity The total nameplate capacity less any capacity unavailable due to forced or planned outages.

Report the sum of all nameplate capacity less capacity unavailable due to forced or planned outages only.


Report the Reporting Area where generation is located (use dropdown).

D

Actual Hourly Generation Actual hourly generation in MWs. Report the actual energy generation for the hydro 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 current 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 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 Conductor Material Type, Bundling Arrangement, Circuits Per Structure Present, Circuits Per Structure Ultimate, Pole/Tower Material, and Comments are optional. Leave the Project Identification Number column blank.

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

Column Field Name Definition Instruction

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




IID AZID


January 17, 2014 49

Arizona AZAZ WAAZ


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

C BA WECC BA Organization Codes Report the BA where transmission is located. (See Appendix B for BA codes)

D Project ID N/A Leave Blank

E Project Name Reporting entity defined project name.

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

F Project Type

New Line Upgrade (Voltage Class Change)

Select for a new transmission line. (Do not include projects under 1 circuit mile.)

A project that involves the upgrading of an existing line to a higher voltage class.


January 17, 2014 50

G Project Status

(Choose One)

Under Construction -Construction of the line has

begun Planned (any of the following) -Permits have been

approved to proceed -Design is complete -Needed in order to meet a

regulatory requirement Conceptual (any of the

following) -A line projected in a

transmission plan -A line that is required to

meet a NERC TPL Standard or powerflow model and cannot be categorized as "Under Construction" or “Planned”

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

Planned Retirement -Any lines that will be taken

out of service during the assessment period.

Planned Upgrade -Projects that involve

upgrades to existing transmission lines.

Cancelled -Project has been cancelled

and no work is being done Completed -Project was completed

during the prior year

Choose one of the predefined transmission categories.

Enter negative line length, in column R, for Planned Retirement entries.

If a Planned Upgrade does not involve a voltage change, enter zero line length, in column Q.

If a Planned Upgrade involves a voltage change, provide two entries – one with negative circuit miles in column Q and the existing operating voltage in column T. The other entry is to have positive circuit miles in column Q and the new operating voltage in column V.

H Tie Line A tie line connects two or more systems.

A circuit connecting two BA areas or two separate systems. Specify (Yes/No) whether the project is classified as a tie line.

I Primary Driver (choose one)

Reliability Generation Integration (Choose

one from below) -Variable/Renewable

Integration -Nuclear Integration -Fossil-Fire Integration -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.


January 17, 2014 51

J Secondary Driver (if applicable)

Reliability Generation Integration (Choose

one from below) -Variable/Renewable

Integration -Nuclear Integration -Fossil-Fire Integration -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 (if applicable).

K Terminal From Location Beginning terminal point. Enter the name of the beginning terminal point of the line.

L Terminal To Location Ending terminal point. Enter the name of the ending terminal point of the line.

M 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.

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

O Entity Type

I – Investor-owned M – Municipality C – Cooperative S – State-owned F – Federally-owned O - Other

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

P 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.

Q Line Type OH-Overhead UG-Underground SM-Submarine

Select the predominate physical location of the line conductor.

R Voltage Type Select alternating current (AC) or direct current (DC).

S Line Length (Circuit Miles)

For lines fully contained within a BA area, enter circuit miles (not linear miles) between the terminal origin and end point. If line crosses into multiple BA areas, 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.

T Operating Voltage Class (kV)

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.


January 17, 2014 52

U 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).

V 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.

W Circuits Per Structure Present

1 Three-Phase Circuit 2 Three-Phase Circuits 3 Three-Phase Circuits

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

X Circuits Per Structure Ultimate

1 Three-Phase Circuit 2 Three-Phase Circuits 3 Three-Phase Circuits

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.

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

Z 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.

AA 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.

AB 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.

AC 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.

AD 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 current year. Replacement transformers should be reported and noted in the Description/Status field.

Column Field Name Definition Instructions

B Zone Zone where transformer is located.

Enter the Zone where the transformer is located. The affected BAs and the zone


January 17, 2014 53

Column Field Name Definition Instructions names are identified below. For all other BAs, enter the same code as entered in the BA column.




IID AZID

Arizona AZAZ WAAZ


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

C BA WECC BA Organization Codes Report the BA where transformer is

located. (See Appendix B for BA codes)

D Transformer Project Name/ID Enter the name of the project.

E Project Status Indicate whether the project is Under Construction, Planned or Conceptual.

F Low-Side Voltage (kV) Enter the Low-Side Voltage. G High-Side Voltage (kV) Enter the High-Side Voltage.

H Expected In-Service Month

Enter the projected month the transformer will be energized under the control of the system operator.

I Expected In-Service Year

The projected year the transformer will be energized under the control of the system operator.

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


January 17, 2014 54

Demand-Side Management (DSM) Programs (VOLUNTARY)

The {DSM Programs} sheet may be completed by all BAs that report non-firm load for the ten-year period. The total amount enrolled of each DSM program or tariff should be entered as a separate row in the sheet. These DSM programs will be designated by the same four non-firm load types — Interruptible Demand (I), Direct Control Load Management (L), Critical Peak Pricing with Control (P), and Load as a Capacity Resource (R) — with the associated program name or tariff listed in the Program/Tariff/Comment field (Column Q). If the disaggregated DSM programs are unknown, enter the total aggregate non-firm load with appropriate corresponding DSM Code designation and make a notation of this in the Program/Tariff/Comment field (Column Q).

NOTE: The amount reported in this section should be equal to or greater than the amount reported as interruptible demand in Code 2.

Column Field Name Definition Instructions A Year Year reported

B DSM Code Demand-Side Management Code

Identify the Demand-Side Management category: I - Interruptible L- Load Management P - Critical Peak-Pricing with Control R - Load as a Capacity Resource

C Code Data Code Enter a 2 for non-firm demand.

D BA Balancing Authority WECC Balancing Authorities Organization Code (See Appendix B)

E-P Month Jan-Dec

Monthly data values associated with each Demand-Side Management program. This amount is the total enrolled in the specific program and not the amount that is expected to be served.

Q Program/Tariff/Comment Enter the specific Demand-Side Management program name/tariff.


January 17, 2014 55

Appendix A: Glossary for WECC Data Collection Manual


January 17, 2014 56


WECC Data Collection Manual Appendix A

January 17, 2014 57

Glossary for WECC Data Collection Manual

Term Definition

ACTIVE 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.


January 17, 2014 58

Term Definition

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.

Coincident 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.


January 17, 2014 59

Term Definition

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.)

Load 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.


January 17, 2014 60

Term Definition

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.

Cogeneration 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.


January 17, 2014 61

Term Definition

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.

PREVIOUS YEAR The calendar year immediately preceding the reporting year.

RESERVE Synonymous with Margin.

SUMMER SEASON The summer season begins on June 1 and runs through September 30.

SYSTEM 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.

WINTER SEASON The winter season begins on December 1 and runs through the end of February of the following year. It is convenient to describe the winter season by means of two years.


January 17, 2014 62



January 17, 2014 63

Appendix B: WECC Balancing Authorities and Abbreviations


January 17, 2014 64


WECC Data Collection Manual Appendix B

January 17, 2014 65

WECC Balancing Authorities Balancing Authority Canada Power Area Organization Code Alberta Electric System Operator ....................................................... AESO British Columbia Transmission Company ........................................... BCHA Northwest Power Area Avista Corp. .......................................................................................... AVA Bonneville Power Administration – Transmission ............................... BPAT Chelan County Public Utility District .................................................. CHPD Constellation Energy Control and Dispatch, LLC................................ CSTO Douglas County Public Utility District ................................................. DOPD Glacier Wind Agency ........................................................................... GWA Grant County Public Utility District ..................................................... GCPD NaturEner Wind Watch, LLC .............................................................. WWA NorthWestern Energy ....................................................................... NWMT PacifiCorp – West .............................................................................. PACW Portland General Electric Company ..................................................... PGE Puget Sound Energy ........................................................................... PSEI Seattle Department of Lighting .............................................................. SCL Tacoma Power .................................................................................. TPWR Western Area Power Administration, Upper Great Plains – West .... WAUW Basin Power Area Idaho Power Company ........................................................................ IPCO Nevada Power Company-Sierra Pacific Power Company .................. NEVP PacifiCorp – East ................................................................................ PACE Rocky Mountain Power Area Public Service Company of Colorado ................................................ PSCO Western Area Power Administration, Colorado-Missouri Region...... WACM Arizona-New Mexico Power Area Arizona Public Service Company ....................................................... AZPS DECA, LLC – Arlington Valley ............................................................ DEAA El Paso Electric Company .................................................................... EPE Gila River ........................................................................................... GRMA Griffith Energy ...................................................................................... GRIF Harquahala ....................................................................................... HGMA Public Service Company of New Mexico .............................................. PNM Salt River Project .................................................................................. SRP Tucson Electric Power Company ........................................................ TEPC Western Area Power Administration, Lower Colorado Region .......... WALC Northern California Power Area California Independent System Operator ............................................ CISO Balancing Authority of Northern California .......................................... BANC Turlock Irrigation District ...................................................................... TIDC

WECC Data Collection Manual Appendix B

January 17, 2014 66

Southern California Power Area California Independent System Operator ............................................ CISO Imperial Irrigation District ......................................................................... IID Los Angeles Department of Water and Power................................... LDWP Mexico Power Area Comisión Federal de Electricidad ......................................................... CFE

State 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


January 17, 2014 67

Appendix C: WECC Criteria for Uniform Reporting of Generator Ratings


January 17, 2014 68


WECC Data Collection Manual Appendix C

January 17, 2014 69

WECC Criteria for Uniform Reporting of Generator Ratings A. STEAM TURBO-GENERATOR CAPABILITY (No regulating or emergency loading limits included)

1. Conditions a. 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 (No regulating or emergency loading limits included)

1. Conditions a. 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.

WECC Data Collection Manual Appendix C

January 17, 2014 70

C. HYDRO TURBO-GENERATOR CAPABILITY (No regulating or emergency loading limits included)

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



January 17, 2014 71

Appendix D: Information Sharing Policy

WECC Data Collection Manual Appendix D

January 17, 2014 72


January 17, 2014 73


January 17, 2014 74


January 17, 2014 75


January 17, 2014 76


January 17, 2014 77


January 17, 2014 78
