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WestConnect. WestConnect Activities Overview. SWAT Meeting Las Vegas, NV February 16, 2011. WestConnect. Discussion Topics. WestConnect Overview & Membership Virtual Control Area Work Group Activities Wind & Solar Integration Joint Initiatives Regional Pricing Experiment. WestConnect.

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westconnect activities overview


WestConnect Activities Overview

SWAT Meeting

Las Vegas, NV

February 16, 2011

discussion topics


Discussion Topics
  • WestConnect Overview & Membership
  • Virtual Control Area
    • Work Group Activities
    • Wind & Solar Integration
  • Joint Initiatives
  • Regional Pricing Experiment


  • Executed Restated MOU Among Transmission Owners (TOs) in the Western Grid – Effective January, 2007
  • Purposes:
    • Continue investigation of feasibility of cost-effective wholesale market enhancements
    • Work cooperatively with other Western Grid Organizations and market participants
    • Address seams issues in appropriate forums


  • Southwest Transmission Cooperative
  • Transmission Agency of Northern California
  • Tri-State G & T Association
  • Tucson Electric Power
  • Western Area Power Administration
    • - Rocky Mountain Region
    • - Desert Southwest Region
    • Sierra Nevada Region
    • CRSP Management Office

Arizona Public Service

El Paso Electric

Imperial Irrigation District

Nevada Power Company

Public Service Colorado

Public Service New Mexico

Sacramento Municipal Utility District

Salt River Project

Sierra Pacific Power Company

TOTALS Jan. 2010

46,000 MW of Load

32,000 Miles of Transmission Line

7.0 Million Retail Customers Served

westconnect accomplishments
WestConnect Accomplishments
  • Annual ATC Workshop
    • Disclosure of long-term TTC and potential changes from planned facilities
  • wesTTrans Common OASIS
  • Subregional Planning
    • CATS, SWAT, CCPG and formation of SSPG
    • Quarterly SPG Coordination Meetings
  • WECC Seams Issues Process
  • Development of Annual WestConnect Transmission Plan and Planning Report
  • Developed Regional Pro Forma Conditional Firm Service Business Practice
  • WestConnect Regional Pricing Experiment
westconnect active work groups
WestConnect Active Work Groups
  • Large Generator Interconnection Process WG
  • Energy Imbalance Service WG
  • Virtual Balancing Authority Area WG
  • Regional Planning Management Committee
  • Regional Pricing Management Committee
  • Other Activities
    • Area Control Error (ACE) Diversity Interchange (ADI)
    • Joint Initiatives
virtual control area


Virtual Control Area

Three-pronged approach:

  • ACE Diversity Interchange
  • Western Wind & Solar Integration Study – will provide analysis of combined balancing area authority operations
  • Analysis of reserves sharing pool modifications
virtual control area9


Virtual Control Area
  • WestConnect TOs participating in the Ace Diversity Interchange (ADI) program
    • Xcel Energy (PSCO)
    • SRP
    • APS
    • PNM
    • TEP
    • NV Energy
what is adi
What is ADI?
  • ADI stands for Area Control Error (ACE) Diversity Interchange.
  • ADI is the pooling of individual Area Control Errors (ACE) to take advantage of control error diversity (sign differences associated with the momentary generation/load imbalances of each control or balancing area).
benefits of adi
Benefits of ADI
  • By pooling ACE, participants are able to:
    • Reduce control burden on individual control areas through the ADI “equal share” allocation method;
    • Reduce generator movement;
    • Reduce sensitivity to intermittent resource output; and,
    • Improve Control Performance and reduce CPS2 violations.
what adi is not
What ADI is not
  • An ancillary service;
  • A process that will impact the terms and conditions of transmission or energy service;
  • An energy sale nor does it necessitate the purchase of transmission;
  • A commercial activity;
  • A tool for making economic dispatch decisions; or,
  • A burden on other areas.

ADI is a reliability tool

adi project implementation
ADI Project Implementation
  • ACE Diversity Interchange Agreement (including the Technical Design) was executed November, 2006.
  • Operating Group’s goal to “GO LIVE” March 31, 2007 was achieved; due to EMS commitments, Idaho Power Company’s “GO LIVE” date was June, 2007.
  • On-going discussions regarding ADI (British Columbia stakeholders, CAISO, ColumbiaGrid, FERC, NWPP entities, Northwest Wind Integration Workgroup, PNW Regional Council, Pacific NW Security Coordinator, WECC, WestConnect members, Western Governors’ Association, Utility Wind Integration Group, CAISO, etc.).
second phase of adi
Second Phase of ADI
  • Participating Control Areas include:
    • Arizona Public Service
    • Bonneville Power Administration
    • British Columbia Transmission Corporation (and the Host)
    • Idaho Power Company
    • NaturEner
    • PS New Mexico
    • Nevada Power
    • NorthWestern Energy
    • PacifiCorp – East
    • PacifiCorp – West
    • Puget Sound Energy
    • Salt River Project
    • Seattle City Light
    • Sierra Pacific
    • Tucson Electric
    • PS Colorado (Xcel)
  • Expanded evaluation (real-time screen shot) and reporting tools.
key adi design principles
Key ADI Design Principles
  • Reliable operations of ADI assured by suspension protocols, e.g.,
    • Transmission overloads
    • Directed by Reliability Coordinator
    • Frequency deviation
    • Reserve sharing
  • Participants can suspend or trigger a global suspension, e.g., Idaho Power triggered a global suspension on July 30, 2008 and a global resumption on August 28, 2008.
  • Suspension defaults to normal (i.e., without ADI) operations; this provides a fail-safe back-up.
  • Adjacency requirement between/among Participants ensures transmission connectivity.
rbc summary
RBC Summary
  • RBC allows a wider range of operation without negatively impacting reliability, while controlling resources more tightly at times.
  • Five new Balancing Area standards are under development – BAL-007 thru BAL-011.
rbc field trial
RBC Field Trial
  • On-going since 2008 in the Eastern Interconnection with approximately 40% of BA’s participating, representing 60% of interconnection load.
  • Began March 1, 2010 in WECC with 75% of BA’s participating, representing 80% of interconnection load.
  • RBC Field Trial duration is one year, ending February 28, 2011.
  • NERC will suspend compliance with CPS2 criteria for BA’s participating in the RBC Field Trial.
  • Compliance with CPS1 criteria is still required.
  • Compliance with the new BAAL criteria is not required, but any non-compliance must be reported.
rbc purpose statements
RBC Purpose Statements
  • To maintain Interconnection frequency within predefined frequency limits under all conditions (i.e., normal and abnormal), to manage frequency related issues such as frequency oscillations, instability, and unplanned tripping of load, generation or transmission, that adversely impact the reliability of the Interconnection.
  • To support corrective action by the BA when its excessive Area Control Error, as determined by this standard, may be contributing to or causing action to be taken to correct an SOL or IROL problem.
  • To prevent Interconnection frequency excursions of short-duration attributed to the ramping of Interchange Transactions.
  • To support timely congestion relief by requiring the Balancing Authority to employ corrective load / generation management within a defined time frame when participating in transmission loading relief procedures.
  • To address the directives of FERC Order 693.
bal 007 standard
BAL-007 Standard
  • BAL-007 R1. – ACE may not exceed BA ACE Limit (BAAL) for more than 30 consecutive minutes. During the Field Trial any violation for more than 20 consecutive minutes must be reported and explained.
  • BAL-007 R2. – Maintain at least 100 % on 12-month rolling average of one-minute CPM. One-minute CPM is similar to the existing CPS1 criteria.
field trial reporting requirements
Field Trial Reporting Requirements
  • Monthly reports submitted to the Standard Development Team (SDT)
  • Report contains clock-minute averages of ACE, Frequency Error, Actual Frequency, Scheduled Frequency, BA Frequency Bias, BA ACE Limits, Limit Violation Minute Count
ems changes
EMS Changes
  • New BA ACE Limit calculation program.
  • New BA ACE Limit violation alarms.
    • “ACE exceeds BA ACE limit for 1 minute”
    • “ACE exceeds BA ACE limit for 10 (or 20) minutes”
    • “BA ACE limit violation”
  • Initially, no changes to the AGC control algorithm.
  • Investigating possible AGC tuning or control algorithm changes.
pros and cons
Pros and Cons
  • Reduced wear on units assigned to frequency and interchange regulation.
  • Reduced chance for performance criteria violations.
  • More severe penalties for performance criteria violations.

Revised Study Footprint

Control areas:


El Paso

Nevada Power


Sierra Pacific






current status


Current Status
  • Final Report issued May, 2010
  • NREL self assessment: Preliminary effort with much more work to do
  • Additional work in progress:
    • Working with NOAA to understand value of wind forecasting
    • Assessing cost & impacts of cycling coal generating units
    • Assessing dynamic response effects
    • Benefit/cost analysis
    • Value of solar thermal storage (focused on CAISO)
nrel wind solar study contacts and information


NREL Wind & Solar StudyContacts and information
  • Debbie Lew – NREL
  • 303-384-7037
  • debra_lew@nrel.gov
  • Study Executive Summary: http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_executive_summary.pdf
  • Study Final Report: http://www.nrel.gov/wind/systemsintegration/pdfs/2010/wwsis_final_report.pdf
Joint Initiatives

Facilitated by:

  • Columbia Grid
  • Northern Tier Transmission Group
  • WestConnect
joint initiatives goal


Joint Initiatives Goal
  • Encourage and facilitate Western Interconnection parties to develop and implement high-value cost-effective regional products
  • Broader focus than integration of variable generation, but immediate wind and solar integration issues provide significant motivation
ji work streams
JI Work Streams
  • Existing Efforts
    • Dynamic Scheduling System (DSS)
    • Intra-Hour Transmission Scheduling
    • Intra-Hour Transaction Accelerator Platform (I-TAP)/webExchange
  • New Effort
    • FERC VER NOPR Comments/Status Report
    • ATC MOD Compliance Coordination
  • Possible New Efforts
    • Work relating to a Voluntary Capacity Market
    • Work relating to a Voluntary Energy Imbalance Market
    • Other


new efforts ferc ver nopr comments
New EffortsFERC VER NOPR Comments
  • JI Facilitators will file a non-positional status report with FERC
  • Participants can point to Facilitators Comments, as appropriate
  • Schedule
    • February 17th - Draft Comments distributed
    • February 22nd – Comments filed
    • March 2nd – Deadline for Comments


new efforts atc mod compliance coordination
New EffortsATC MOD Compliance Coordination
  • New Strike Team being formed
  • Initial meeting on January 27th
    • Scope work
    • Firm up participation
    • Develop contingency plan for April 1 compliance
      • WestConnect Utilities have requested 18-month extension
  • Some TSPs planning to comply on April 1 will monitor group for informational purposes


ongoing efforts dss update
Ongoing Efforts - DSS Update
  • Testing underway
  • Targeting February “Implementation Date”
  • Additional training sessions for Participants in March


ongoing efforts intra hour transmission scheduling
Ongoing Efforts Intra-Hour Transmission Scheduling
  • TSPS/BAs currently accepting intra-hour schedules

NV Energy PacifiCorp BPA

PSE PGE Chelan

Grant Tacoma Seattle



  • TSPs/BAs working towards 7/1/11 standardized practice
    • Those already offering intra-hour scheduling
    • Avista, Idaho Power, NorthWestern Energy, BC Hydro, SRP, other WestConnect providers
    • CAISO coordinating through dynamic scheduling/pseudo-tie approach
    • Alberta considering but has some higher priorities


standardization step one
Standardization – Step One

Requests for new intra-hour e-Tags (INC) can be submitted

Requests for intra-hour adjustments to existing e-Tags (INC/DEC) as soon as the TSP or BA establishes sufficient tools/automation (may be after 7/1/11)

No transaction limitation (by any party, for any reason, import/export/wheel-through)

Intra-hour requests must be submitted between XX:00 and XX:15 for the second half of the current hour


standardization step one38
Standardization – Step One

Intra-hour requests will default to 10-minute duration straddle ramps

Intra-hour requests will be for a duration of 30 minutes but will be integrated over the full hour for interchange accounting purposes

No bumping (access to intra-hour scheduling is subject to availability on a first-come first-serve basis and the participating TSPs have indicated they will not displace an existing hourly or intra-hourly schedule to "make room" for a subsequent intra-hour request even if that request is utilizing higher priority transmission service)


standardization caveats
  • Focused on intra-hour scheduling opportunities for unanticipated events, NOT going to half-hour scheduling
  • Relies on more flexible use of existing transmission products (no new intra-hour product)
  • Requires automation


ongoing efforts i tap webexchange
Ongoing Efforts I-TAP/webExchange
  • Participants include

Grant PGE Snohomish

PSE Tri-State Seattle

WAPA Xcel PowerEx


Avista Tacoma NorthWestern



i tap webexchange
  • Technical Steering Committee (TSC) formed:
    • Develop Technical Specification with OATI
    • Liaison among all ITAP Parties & OATI
    • Factory testing during product development phase
    • John Jamieson (PGE) is Chair
  • Go live implementation mid-2011
i tap webexchange42
  • On track for implementation summer of 2011
    • Functional Specifications finalized 12/10
    • OATI currently writing code
    • TSC will review initial results early 2/11
    • Testing likely in spring
  • New subscribers welcome


possible additional work
Possible Additional Work
  • November 19, 2011 Brainstorming Session
  • Small scale voluntary capacity market/Resource Pool
    • Identify the functionality, implications, and options as a “proof of concept” tool
    • Voluntary participants contribute a block of resources into economic dispatch pool and commit to bringing those resources


possible additional work44
Possible Additional Work
  • EDT
    • Get interested participants to discuss implementation issues, might result in a participants agreement as a fundamental starting point
      • Design options
      • Contractor options
      • Solution details, including financing alternatives


possible additional work45
Possible Additional Work
    • EIM Strike Team with Information-sharing Role
      • WestConnect has stakeholder group discussing and sharing information on EIM – this group could be broadened
  • Add “ghost market” modeling component to I-TAP to see how I-TAP would work if prices cleared through a single dispatch model


possible additional work46
Possible Additional Work
  • Continue within-hour transmission scheduling work, taking into account possible implications of VER NOPR
  • Identify additional ways to improve ability to transact over multiple systems in the same manner


possible additional work47
Possible Additional Work
  • Identify whether there are FERC policies that impede within-hour or real-time transactions across multiple systems and seek appropriate modification of such policies (e.g., undesignation of resources – once resources are designated for a system’s use it is difficult to use them to respond to other systems’ issues)


dss process overview
DSS Process Overview
  • The DSS is a communications infrastructure that exchanges dynamic signals via e-Tag and ICCP links
    • Before the scheduling period, participants will create DYNAMIC type e-Tags reflecting their dynamic schedules.
    • During the operating hour, webDynamic will use the composite e-Tag data to distribute MW requests to BAs with obligations to requesting participants.
    • After the scheduling period, webDynamic willupdate the e-Tag with the correct integrated quantity.
  • DSS is scheduled to ‘go live’ early October, 2010
  • Moratorium on additional parties joining will be lifted once DSS is operational
joint initiatives contacts


Joint InitiativesContacts
  • Products and Services Co-Facilitators

Charlie Reinhold (480-215-0299)

Kristi Wallis (206-726-1699)

  • Infrastructure Facilitator

Sharon Helms (503-644-6262)

  • Joint Initiative materials posted on CG website


regional transmission pricing


Regional Transmission Pricing
  • Status:
    • Began two-year Experiment on July 1, 2009
    • Modest usage of the service
      • Majority of transactions from PV to CAISO
    • Participants will file to extend Experiment for an additional two years until June 30, 2013
      • Administrative Fee will increase to $ 0.95 / MWh (from current fee of $ 0.08) in the first year of extension, and may increase to $ 1.25 / MWhif volumes do not increase
      • Transmission Customers pay Administrative Fee
the experiment


The Experiment
  • 2-Year Pilot
  • Eliminates transmission rate pancaking for limited transactions. The Regional Rate will be the highest posted OATT rate in the path.
  • Continues to pancake ancillary services and losses.
  • Retains participants’ posted OATT rates.
  • Start-up/implementation costs borne by Transmission Customers (thru OATI).
  • Can be implemented through wesTTrans platform.
  • Did not Require FERC filing for NJs.
  • No State approval required.
  • Fail-safe clause for NJs.
  • Revenue distributed pro rata based on posted rates
price components


Price Components
  • The Regional Rate will be the highest posted OATT rate in the path.
  • Ancillary Service 1 remains pancaked
  • Ancillary Service 2 assessed only at sink
  • Losses remain pancaked: Monetized at Palo Verde Index price for date of transaction
  • Administrative adder of $ 0.08/MWh (increasing to $ 1.25/MWh)

WestConnect Pricing Experiment Participants

  • Southwest Transmission Cooperative
  • Transmission Agency of Northern California
  • Tri-State G & T Association
  • Tucson Electric Power
  • Western Area Power Administration
    • - Rocky Mountain Region
    • - Desert Southwest Region
    • Sierra Nevada Region
    • CRSP Management Office

Arizona Public Service

El Paso Electric

Imperial Irrigation District

Nevada Power Company

Public Service Colorado

Public Service New Mexico

Sacramento Municipal Utility District

Salt River Project

Sierra Pacific Power Company

what s the risk


What’s the Risk?
  • The risk here is one of decreased non-firm transmission revenue for the Regional Participants (RP).
  • Without an increased number of transactions, transmission revenues would decrease for the affected RPs .
  • The resulting financial impact is that an RPs non-firm sales revenues decrease with the potential of harm to firm transmission service customers.
westconnect contacts and information


WestConnect Contacts and Information
  • WestConnect (www.westconnect.com)
  • Charles Reinhold – Project Manager
      • reinhold@globalcrossing.net
      • 208-253-6916
ba ace limit baal calculation
BA ACE Limit (BAAL) Calculation
  • IF Factual < 60 then

BAAL = -10B x (FTL Low – 60)2 / (Factual -60)

  • IF Factual > 60 then

BAAL = -10B x (FTL High – 60)2 / (Factual -60)

  • FTL Low = 59.932 Hz (low frequency trigger limit for WECC)
  • FTL High = 60.068 Hz (high frequency trigger limit for WECC)
atl ace transmission limit
ATL (ACE Transmission Limit)
  • ACE limit that prevents unscheduled flow from causing SOL or IROL violations.
  • Not currently mentioned in the proposed BAL-007 … BAL-011 standards, but the need for this type of limit has been recognized.
one minute cpm rolling average
One-minute CPM Rolling Average
  • CF 1-min = (ACE / -10B) 1-min x (DF) 1-min / e1
  • e1 = .00228 (constant for WECC)
  • CPM 1-min = (2 - CF 1-min) x 100%
  • CPM month = Average(CPM 1-min for the month)
  • CPM Rolling Average = Average(CPM month for the last 12 months)
other new bal standards
Other New BAL Standards
  • BAL-008 – RC’s must notify BA’s that an FTL has been exceeded for more than 5 minutes.
  • BAL-009 – BA’s must comply with the RC’s directive to return frequency within the FTL.
  • BAL-010 – BA’s must calculate their frequency bias annually and document how they do it.
  • BAL-011 – NERC must calculate the FTLs.
dynamic scheduling system dss
Dynamic Scheduling System (DSS)
  • A more efficient way to implement dynamic schedules
    • Participants can establish dynamic schedules between any number of BAs at any scheduling granularity, depending upon need and capability
    • Minimal changes to existing processes and procedures
    • a one-time DSS implementation replaces the month’s it takes today to negotiate and make system changes and accommodates all future dynamic schedules
conventional dynamic schedule exchange
Conventional Dynamic Schedule Exchange

Dynamic Signal Transfers

EMS to EMS Connection, Fixed Point to Point, Fixed Data Points,

Using ICCP on the WON








EMS = Energy Management System, SCADA, ACE, AGC

ICCP = Inter-Control Center Protocol

WON = WECC Operational Network

dss schedule exchange using dss webdynamic application
DSS Schedule Exchange Using DSS webDynamic Application

Multiple Dynamic Signal Transactions between Multiple BAs

Etag Driven

Public Internet




Tag Data




Tag Data













advantages of dss
Advantages of DSS
  • DSS facilitates
    • Development of intermittent resources
    • More efficient use of generating resources
    • Potential reduction in imbalance charges
    • Potential market opportunities that may result in lower portfolio costs
    • NERC and WECC standards and business practices
dss participation
DSS Participation
  • 18 parties have executed participant and vendor contracts
  • Arizona Public Service Company
  • BCTC
  • BPA
  • Grant County PUD
  • Idaho Power
  • Imperial Irrigation District
  • NaturEner, USA
  • Northwestern Energy
  • PacifiCorp
  • Portland General
  • PowerEx
  • Public Service of New Mexico
  • Puget Sound Energy
  • Seattle City Light
  • Salt River Project
  • Tri-State G&T
  • WAPA
  • Xcel Energy
dss structure
DSS Structure


Sharon Helms

DSS Management and Facilitation











Management Committee

Ron Schellberg, Chair

Idaho Power

DSS Vendor


Develops, operates and maintains the DSS



Robert Harshbarger, Chair

Puget Sound Energy

Finance Agent

Idaho Power

Collects fees and pays vendors