Regional Transmission Adequacy Guidelines Technical Workshop

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Regional Transmission Adequacy Guidelines(Technic
al Workshop)

• PDX Conference Center
• June 3, 2005
• Ravi K. Aggarwal

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Action Items (Apr. 27)

• Process Clarification
• Transfer Vs Load Service Issues
• Reasons for limitations on COI/PDCI and NI
• Other ongoing efforts for developing Transmission
  Adequacy Guidelines
• Revised studies for N-2 and N-1-1
• Benefit/Cost Tools and Other Tools to measure
  system performance and identify system
  requirements

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Process Objective

• How does the region address transmission adequacy
  challenges that current reliability criteria
  dont address?
• How do the existing NERC/WECC standards for the
  bulk system apply to local load areas
• What guidelines are needed to address challenges
  that we have planning economic upgrades?
• Current NERC/WECC address physical adequacy and
  not economic adequacy

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Value Proposition

• Better informed investments Addressing Physical
  and Economical aspect of transmission system
• Controlled costs
• Application of appropriate risk

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Risk Assessment

• Establish Context Transmission Planning
• Identify Risk factors ? Serves as a checklist
• Analyze (Quantifiable) Provide importance of
  risk (rank) and Consequences
• Evaluate Summarize risks in terms of decision
  (alternate, timing, etc)
• Treat Define Actions to mitigate or reduce
  (manage) risk

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Risk Assessment(Redefine Thresholds)
Make Better Informed Decision (Systematic,
Controllable, Measurable, Repeatable)
Identify level where we do not take risk
Redefining Thresholds (Suggestive) MW Loss
(Magnitude) Duration Exposure Time and
Condition Outage history Probability of outage
Ref. BPA Risk Assessment Tool
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Issues

• Load service issue (e.g., Olympic Peninsula
  Energy Efficiency/DSM)
• N-2 requirements (should it be based on MW or
  geographic scope)
• Robustness of the system N-1-1?
• Metrics to measure performance
• Minimum guidelines need to focus on customer
  requirements
• Native load Vs. firm transmission customers (PTP)
  ? Eventually tie to transfers

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Firm Transfers Vs Load Service

• Economic Decision
• FERC Treat firm transfers and load as same
• Routine Cut transfers to avoid load shedding
• Build Transmission?
• Consequences
• Build for low probability event
• Upward pressure on rates

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N-2

• Local Area Network
• Loads and Transfers
• N-2 benchmarking discussed for following areas
• BPA Load areas (Olympic Peninsula, and So.
  Oregon Coast)
• PAC So. Oregon
• Snohomish System

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Olympic Peninsula
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Southwest Oregon Coast
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N-1-1

• One element is out of service and a unplanned
  contingency trips another element
• Power system generally not planned to operate for
  all N-1-1 conditions (Number of combinations are
  tool large to plan and cost of the infrastructure
  needed will be too high)
• Operations cannot mitigate all N-1-1 conditions
  with the available tool box (Safety Net?)

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Examples

• Puget Sound - PSANI
• Eugene Area
• Redmond Area
• Suggested Solutions
• Under-voltage load shedding
• Coordinated Planned Outages (timeframe)
• Does not cover for unplanned outages

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Example N-1-1(Eugene Area)

• Outage of one of the 500/230 kV transformer banks
  at Santiam, Lane, or Alvey
• Next outage of any of the other remaining bank in
  the area results in extremely low voltages ?
  Potential Voltage Collapse
• This problem does not appear to be confined to
  winter operations.

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Possible Solutions (Eugene Area)

• Ensure sufficient under-voltage load shedding is
  available in the immediate area, and that its
  settings will allow it to operate in time to
  prevent large-scale problems.
• Concern
• Under voltage load shedding available between
  Nov. 15-Apr. 15 (WILSWA)
• Under voltage load shedding designed for winter
  season (voltage sensitive load). Does this cover
  for summer load conditions?
• Other than winter Reactive capability available
  but not on Coordination for faster reactive
  insertion scheme
• Outages taken outside this timeframe

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Example N-1-1(Redmond Area)

• Outage of the Ponderosa 500/230 bank, or the
  Round Butte 500/230 bank
• When an outage is taken that affects service from
  one of these transformer banks (e.g.
  Grizzly-Summer Lake 500 kV line), a contingency
  that affects service from the other 500/230 bank
  can cause the voltages in the Redmond area to
  collapse.
• Approximately 90 of the Redmond area load is
  served by these two transformer banks

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Possible Solutions (Redmond Area)

• Under-voltage load shedding Possible addition in
  the Redmond area provides safety net
• Transmission Build Expensive alternative
• RAS Controller Expensive alternative
• Note Same flexibility may not be available for
  other areas. Cutting transfers are not always the
  solution. The problem is a embedded local
  problems.

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Alberta Transmission Development Study

• Develop LT Planning framework for AIES
• Need Accommodate variety of alternate generation
  expansion scenarios
• Assessment of overall delivered energy cost
  (generation plus transmission) under various
  transmission and generation development scenarios
• Strategic Decision Process Use of scenario
  planning to identify combinations of possible
  future events
• Alberta Interconnect Electric System

Ref. Navigant Consulting AESO (Jan. 2004)
Alberta Transmission Development (A Scenario
Approach) Summary Report
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Methodology

• Use of scenario analysis
• Range of potential transmission, generation, load
  forecasts, and export scenarios
• Identify and determine transmission cost
• Determine energy cost
• PV of overall delivered energy costs

Ref. Navigant Consulting AESO (Jan. 2004)
Alberta Transmission Development (A Scenario
Approach) Summary Report
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Report Analysis

• Optimization of transmission development
  requires maintaining flexibility to better manage
  uncertainties associated with generation
  Competitive market for electricity

Ref. Navigant Consulting AESO (Jan. 2004)
Alberta Transmission Development (A Scenario
Approach) Summary Report
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Linkage of Resource and Transmission Adequacy
Adequacy Physical (lights stay on) and
Economic (acceptable risk that prices reasonable
not volatile) or just Physical?
2 10 Years out
Resource Adequacy
Transmission Adequacy
Timeframe
Power System Adequacy
Power System Reliability Operational Adequacy
Well-Functioning Electricity Markets
Within Year
Source NW Resource Adequacy Metrics Standards.
TAS meeting, Jan. 10, 05, PDX.
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Proposed Methodology

• Consequence
• Peak load
• Fraction of load that can be served under N-2
• Exposure
• Likelihood of outage(s)
• Load-duration curve
• Benefit/Cost analysis
• Cost to fix
• Societal cost of outages

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Contact Information

• Ravi K. Aggarwal Chair
• Bonneville Power Administration
• Phone [phone]
• Fax [phone]
• Email rkaggarwal_at_bpa.gov
• OR
• Dana Reedy - Facilitator
• Northwest Power Pool
• Phone [phone]
• Email dana.reedy_at_nwpp.org

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Backup Slides
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Potential Elements of a Transmission Adequacy
Guidelines

• Reliability Standards
• NERC, WECC and Utilitiy standards
• Explicit performance criteria such as LOLP
• Probabilistic criteria
• Robustness tests
• Extreme event tests
• WECC standards are more restrictive than NERC
  and utility standards

• Economic Indicators
• Societal benefit/cost analysis of reliability
  Value of load loss
• Acceptable levels of congestion
• Definition of least cost solutions
• Price volatility and tolerance
• Assurance level for maintaining ATC across
  flowgates

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Potential Elements of a Transmission Adequacy
Guidelines

• Other Objectives
• Development of renewable
• Resource diversity
• Economic development
• Seasonal products

• Expansion Pricing Policy
• Drivers
• Generation
• Load
• Transfers into, out of and through the region
• Flexibility
• Financial
• pricing expansion
• Advance financing requirements or other risk
  management tools

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Possible Solutions

• Amounts and obligations for RAS (or special
  protection scheme)
• Re-dispatch (mechanisms)
• Curtailment strategies
• Non-Wires Solutions
• Changes to maintenance practices to provide for
  more flexibility
• Better load forecast mechanisms
• Investigate and incorporate new technologies
• Locational Marginal Pricing (LMP) Requires
  formation of an Independent Transmission Operator
• Computer tools to assess state of the
  transmission system in real-time

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Olympia-Shelton and Shelton Transformer
Fairmount
W
69kv
W
Port Angeles
South Bremerton
W
W
115kV
W
Kitsap
Shelton
230kV
S. Shelton
W
230kV
W
X
15 mi
Satsop
.
X
White Rv
230kV
Olympia
W
W
Coulee
Paul
500kV
6 mi
Source Mark Bond BPA (Transmission)
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Olympic Peninsula Support (Three Primary
Problems)

• Voltage Stability Problem - for an outage of the
  Olympia 500/230-kV transformer or line
• Voltage Collapse Problem - for an outage of both
  Olympia-Shelton 230-kV lines
• Voltage Collapse Problem - for an Outage of the
  Olympia 230-kV East Bus Section

Source Mark Bond BPA (Transmission)