1. Transmission Planning Attachment K Public Input Meeting
FERC Order 1000, Biennial Planning Cycle
Quarter 3 Meeting September 13, 2018

2. Agenda Pacific Time Topic Presenter 9:00 – 9:05
Greetings and Introductions
Jamie Austin
9:05 – 9:15
Explain the Planning Process
Discuss status of the local planning process and any interim iterations of the draft Local Transmission Plan;
9:15 – 9:30
TPL Study Process
Scott Beyer
9:30 – 9:40
Status of Ongoing Area Planning Studies
Scott Beyer, Jake Barker
9:40 – 9:55
Five Year Studies
PACW Area, Kickoff Studies:
Coos Bay Study
PACE Area, Kickoff Studies:
Montpelier Study
Adam Lint, Larry Frick
Sachith Abayakoon
9:55 – 10:00
Q&A

3. The Planning Process Jamie Austin

4. 3rd Quarter Deliverables Process
Discuss status of the local planning process and interim iterations of the draft Transmission System Plan:
Technical Studies – for designing a reliable system
Economic Studies - economic analysis to identify transmission congestion
PacifiCorp has been Providing quarterly updates to Stakeholders on local transmission studies (5-yrs studies; reliability assessment studies)
Current plan includes posting a draft TSP in Q4, 2018
Review of the Transmission System Plan Outline

5. Transmission System Plan Outline
INTRODUCTION
FERC ORDER 890\1000, ATTACHMENT K, LOCAL TRANSMISSION PLANNING
PROCESS DISCUSSION THAT TIES THIS WORK TO OUR EXISTING PLANNING
LOCAL PLANNING
OBJECTIVES OF THE TRANSMISSION SYSTEM PLAN
SUB-REGIONAL & REGIONAL COORDINATION
PLANNING PROCESS AND TIMELINE
TRANSMISSION SYSTEM PLAN INPUTS AND COMPONENTS
ASSUMPTIONS\DATABASES
GENERAL DESCRIPTION OF PACIFICORP’S TRANSMISSION SYSTEM
PacifiCorp East Balancing Area – Description
PacifiCorp West Balancing Area – Description
LOAD AND RESOURCE PROCESS
RELIABILITY ASSESSMENT
AREA PLANNING STUDIES
10-YEAR PLANNING HORIZON
ECONOMIC STUDIES
COST ALLOCATION

6. Economic Planning Studies Background
The Economic studies identify “significant and recurring” congestion.
Stakeholders can submit study requests through the OASIS process.
No study requests were submitted in Q1
Next chance to submit requests will be in Q5

7. PAC BIENNIAL TRANSMISISON PLANNING CYCLE 2018-2019
PacifiCorp 8 Quarter Process
Time Line
PAC BIENNIAL TRANSMISISON PLANNING CYCLE
Quarter
Date
Technical Studies
Economic Studies
Activities
Year Q1
Jan - Mar
Data Collection
Data Collection for Economic Studies Q2
Apr - Jun
Reference Case Development Q3
Jul - Sep
Technical Studies to determine System Adequacy
Economic Studies to Identify Congestion Q4
Oct - Dec
Draft Report on System Adequacy
Draft Reporting
Year Q5
Data Collection for Re-Study
Re-Study Requests
Economic Study Second Year Requests Q6
Draft Report Review
Draft Re-Study Review Q7
Final Report and Review Q8
Final Transmission Plan approval

8. NERC TPL-001-4 Standard Overview Scott Beyer

9. Overview Areas Background NERC TPL-001-4 Standard
2018 TPL Plan and Status Update
2017 Planning Assessment Results
Compliance Monitoring and Enforcement

10. Common Acronyms BES – Bulk Electric System
ERO – Electric Reliability Organization
FERC – Federal Energy Regulatory Commission
NERC – North American Electric Reliability Corporation
WECC – Western Electricity Coordinating Council
RE – Regional Entity
TPL – Transmission Planning (Standards Family)

11. Why the need of Reliability Standards?
November 9, 1965:
Northeast Blackout resulting in loss of power to 30 million people
July 13-14, 1977:
Blackout of New York City resulting in loss of power to 9 million people and widespread looting, arson and rioting
July 2-3, 1996 & August 10, 1996:
Western North American Blackouts impacting areas across Western Canada, Western United States and Northwest Mexico, resulting in loss of power to more than 7.5 million people
August 14, 2003:
Northeast/Midwest Blackout, including Ontario, Canada, resulting in loss of power to 50 million people (largest to date)

12. Actions taken after the 2003 Blackout?
2005: U.S. Energy Policy Act of 2005 creates the Electric Reliability Organization (ERO)
2006: Federal Energy Regulatory Commission (FERC) certified NERC as the ERO; Memorandum of Understanding (MOUs) with some Canadian Provinces
2007: North American Electric Reliability Council became the North American Electric Reliability Corporation (NERC); FERC issued Order 693 approving 83 of 107 proposed reliability standards; became mandatory and enforceable

13. What are the Reliability Standards?
Reliability Standards are the planning and operating rules that electric utilities follow to ensure the most reliable system possible
Standards are developed by the industry using a inclusive process managed by the NERC Standards Committee
Committee is facilitated by NERC staff and comprised of representatives from many electric industry sectors
NERC has eight Regional Entities (RE’s) across the United States and Canada
The RE’s are responsible for compliance monitoring and enforcement of the reliability standards
PacifiCorp’s RE is the Western Electricity Coordinating Council (WECC)

14. Who develops the Reliability Standards?
FERC
Approves/denies following full NERC process
NERC
Standard Action Request (SAR)
Board of Trustees (BOT) approves/denies continent wide (NERC) and regional (WECC) standards
Standard Drafting Teams (SDT)
Industry involved approval process
WECC
Oversees regional enforcement of reliability standards
Oversees the development of regional standards (more stringent than continent standards)
BOT approves regional (WECC) standards
Committee only approves Criterion
FERC
NERC
WECC

15. Who are NERC’s Regional Entities?
WECC: Western Electricity Coordinating Council
MRO: Midwest Reliability Organization
SPP: Southwest Power Pool
TRE: Texas Regional Entity
NPCC: Northeast Power Coordinating Council
RFC: ReliabilityFirst Corporation
SERC: SERC Reliability Corporation
FRCC: Florida Reliability Coordinating Council

16. Development of NERC TPL-001-4 Standard
NERC standard TPL refers to Transmission System Planning Performance requirements – became fully effective and enforceable on January 1, 2016
The TPL standard revision officially replaced the four individual standards previously in place – i.e., TPL , TPL-002-0b, TPL-003-0b and TPL a
TPL was for performance under normal conditions (Category A)
TPL-002-0b was for loss of a single BES element (Category B)
TPL-003-0b was for loss of two or more BES elements (Category C)
TPL-004-0a was for loss of two or more BES elements (Category D or Extreme Events)
Overall, the new standard was expanded over the previous standards with increased performance criteria and requirements – it has 65 requirements and sub- requirements

17. TPL-001-004 Standard Requirements
R1 – Each Transmission Planner and Planning Coordinator shall maintain system models within its respective area for performing the studies needed to complete its Planning Assessment…
R2 – Each Transmission Planner and Planning Coordinator shall prepare an annual Planning Assessment of its portion of the BES…
R3 – For the Steady-State portion of the Planning Assessment, each Transmission Planner and Planning Coordinator shall perform studies for the Near-Term and Long-Term Transmission Planning Horizons…
R4 – For the Stability portion of the Planning Assessment, each Transmission Planner and Planning Coordinator shall perform the Contingency analysis listed in Table 1…
R5 – Each Transmission Planner and Planning Coordinator shall have criteria for acceptable Steady-State voltage limits, post-Contingency voltage deviations, and transient voltage response for its system…
R6 – Each Transmission Planner and Planning Coordinator shall define and document, within their Planning Assessment, the criteria or methodology used in the analysis to identify System instability…
R7 – Each Planning Coordinator, in conjunction with each of its Transmission Planners, shall determine and identify each entity’s individual and joint responsibilities for performing the required studies…
R8 – Each Transmission Planner and Planning Coordinator shall distribute its Planning Assessment results to adjacent Planning Coordinators and adjacent Transmission Planners…
Each Requirement has multiple Sub-Requirements – 57 in total

18. Example sub-requirements of TPL-001-4
Spare Equipment Strategy
R2.1.5 requires an annual study of impacts for the loss of major equipment, such as power transformers, that do not have a spare unit available and have a lead time of one year or more – studies shall be performed for the P0, P1 and P2 categories shown in Table 1 with the identified equipment out of service
Short Circuit Analysis
R2.3 requires a short circuit analysis to be conducted annually within the Near-Term Transmission Planning Horizon to determine if circuit breakers have interrupting capability for faults they would be expected to interrupt
R2.8 requires a Corrective Action Plan to address circuit breakers subject to short circuit interrupting duty levels that exceed their equipment rating
Non-consequential Load Loss
R2.7.2 cites that if situations arise that are beyond the control of the Transmission Planer or Planning Coordinator that prevent implementation of a Corrective Action Plan in the required timeframe, it is permitted to utilize Non-Consequential Load Loss and curtailment of firm Transmission Service (≤ 75 MW) to correct the situation that would normally not be permitted in Table 1 – this grace period is in place for five years from the date the standard was approved in 2015
Protection System Studies (R3.3.1)
R3.3.1 requires simulating the removal of all elements that the protection system and other automatic controls are expected to disconnect for each Contingency without operator intervention – includes RAS and other protection systems with automatic control

19. PacifiCorp’s TPL Study Schedule and Status
TPL Study Status
Study Plan draft completed April 24, 2018
Study Methodology draft completed May 31, 2018
10 Base Cases completed for Steady-State analysis in June 2018 – four for PACE and six for PACW
PACW Bases Cases – 2019 summer peak, winter peak, 2020 light spring, 2023 summer peak, winter peak, and 2028 summer peak (Long-Term)
PACE Base Cases – 2019 summer peak, 2020 light spring, 2023 summer peak and 2028 summer peak (Long-Term)
2 Base Cases for PACE and PACW to perform Stability Analysis – 2023 summer peak, 2020 light spring
Simulations are currently being run for Steady-State base cases
Stability analysis will be performed based upon the results of the Steady-State simulations
Short-circuit study is completed
Analysis for extreme events, sensitivity studies and loss of major equipment without spares will proceed at the conclusion of the Steady-State analysis
Study team is targeting November 2018 to deliver preliminary reports for PACE and PACW

20. Compliance Monitoring and Enforcement
WECC, with delegated authority from NERC, is the Regional Entity responsible for compliance monitoring and enforcement for the Western Region of the United States
WECC provides the environment for development of reliability criteria, occasional regional variances, and coordination of the operating and planning activities of its members
NERC is the driving force for developing new standards through its process of an Open Call for Standard Drafting to get team members from its Regional Entities memberships – FERC reviews and approves new and modified NERC Standards
WECC provides audit oversight for compliance with NERC Standards for Critical Infrastructure Protection and Operations and Planning Standards
NERC has a three year auditing cycle for its TPL Standards – the next audit of PacifiCorp’s TPL compliance is scheduled for 2019

21. NERC TPL-001-4 Standard Overview
Questions?

22. Local Area Studies Update - PACW Scott Beyer

23. Time-line 5-yr studies - West
Study Area
State
Existing Study Completion Date
Update Study Status
Comments
Crescent City CA
Feb-17
Grants Pass OR
Dec-15
Hood River
Nov-15
Pendleton/Hermiston/Enterprise
May-17
Walla Walla/Wallula WA
Dec-09
85%
Roseburg
Sep-10
40%
Portland
Mar-11
Dalreed/Arlington/Sherman County
100%
Completed May 2018
Klamath Falls
May-11
Lakeview/Alturas
Coos Bay
Aug-11
Attachment K Kick-Off September 2018
North Oregon Coast
Sep-17
Yakima
Dec-11
95%
Medford
Sep-12
Willamette Valley
Dec-12
Junction City/Cottage Grove
Central Oregon
Mar-13
Yreka
Dec-14

24. Attachment-K Q3 Public Meeting Coos Bay Area Transmission Planning Study Kickoff Area Planner: Adam Lint Presented by Larry Frick September 13, 2018
Choose from three different title slide designs by selecting “New Slide.” These slides are suitable for business and community presentations.

25. Sub-Transmission Planning Studies
Pacific Power study plan
Service Area is divided into 17 study areas
The studies are designed to predict the future electrical system requirements about 5-7 years out.
The goal is to update each about every 36 months.
This is intended as an agenda slide template. Choose from different slide layouts by selecting “New Slide.”

26. Pacific Power Study Areas
This is intended as an agenda slide template. Choose from different slide layouts by selecting “New Slide.”

27. Inputs to a Planning Study
New load requests (L&R)
Customer transmission & substation data
Generation increases and operations plans
Potential system modification data
Two restrictions to public access
Maintaining confidential customer information
Maintaining FERC & WECC codes of conduct
This is intended as an agenda slide template. Choose from different slide layouts by selecting “New Slide.”

28. Coos Bay Area Topology Main Grid Sources
230 kV
Alvey-Fairview
Dixonville-Fairview
Common Corridor
Fairview-Isthmus
115 kV
Tahkenitch-Fairview
Coos-Curry system downstream via BPA Rogue and BPA Bandon

29. Coos Bay Area Topology Northern Portion
kV Isthmus source
Distribution substations
Coos River South Dunes
Lockhart Empire
State Street Jordan Point
Normal open points
At Empire facing State Street, switch 2C14
At Lockhart facing Red Dike Tap, breaker 2C6
Both SCADA controlled
Normal Open Points

30. Coos Bay Area Topology Southern Portion
Pacific Power subs
Coquille
Myrtle Point
Norway Tie
Bandon
(Pac. portion)
Foreign subs
Fairview
Norway
CCEC subs

31. Coos Bay Area Loads (Pacific Power)
Based on most recent load projections
Summer ~ 94 MW
Winter ~ 150 MW
Overall growth rate 0.2%
Winter limited
Overall load factor 51%
This is intended as an agenda slide template. Choose from different slide layouts by selecting “New Slide.”

32. Coos Bay Area Transmission Planning Study
Expected completion 2019 Q2
Questions or Input requests?
This is intended as an agenda slide template. Choose from different slide layouts by selecting “New Slide.”

33. Local Area Studies Update – PACE Jake Barker

34. Time-line 5-yrs studies – East
Study Area
State
Last Studied
Update
Ogden UT
Aug-14
65% Complete
Utah (Southwest)
Dec-14
90% Complete
Pavant
Feb-15
95% Complete
Goshen ID
Jun-15
Powder River WY
Nov-15
Completed
Montpelier
Feb-16
Utah Valley
Apr-16
Honeyville/Malad
May-16
Grace
Jul-16
Smithfield
Price
Utah (Southeast)
Jun-16
Vernal
Nov-16
Sigurd
Feb-17
Presented Q5
North Salt Lake
Wyoming (Southern)
Mar-17
Salt Lake Valley
May-17
Presented Q6
Tooele
Jun-17
Wyoming (West)
Oct-17
Presented Q8
Park City/Midway
Big Horn
Nov-17
Nebo
Apr-18
Presented Q2

35. Montpelier, Idaho Study
Sachith Abayakoon
Montpelier, Idaho Study

36. MONTPELIER, IDAHO AREA STUDY
Primary Sources
Ovid – kV
138 kV source from Oneida
Reactive Support to the Area
Sage – kV
69 kV source from Naughton Generation
Serves 46 kV Loads
15 area substations in three different states: Idaho, Utah and Wyoming. The total area is approximately 1,900 square miles. Includes Bear Lake recreational area.
Sachith Abayakoon

37. Load Growth Area Loading Growth
Summer of 2017 area loading was at 29 MW
Winter of area loading was at 22 MW
Growth
Average area growth has been about 2.1%
Are there any questions?

38. Powder River, Wyoming Study
Sachith Abayakoon
Powder River, Wyoming Study
No changes to previous study identified.

39. Attachment K 2018-19 Biennial Planning Cycle Q4 Public Meeting
December, 2018
PacifiCorp

40. Q & A Session
Contact Information – Link to PacifiCorp OASIS:
For Attachment K related comments\questions, address your requests to: