2013 Biennial Transmission Expansion Plan

Transcription

1 2013 Biennial Transmission Expansion Plan

2 Copies of this report are available from: ColumbiaGrid 8338 NE Alderwood Rd Suite 140 Portland, OR February 2013 Photos provided by: Bonneville Power Administration, Grant County PUD, NW Power and Conservation Council, Seattle City Light, Chelan County PUD, istock Photo. Cover photo: Sam Churchill

3 Acknowledgements ColumbiaGrid Members & Participants Avista Corporation Bonneville Power Administration Chelan County PUD Cowlitz County PUD Douglas County PUD Enbridge Grant County PUD Puget Sound Energy Seattle City Light Snohomish County PUD Tacoma Power Other Contributors Idaho Power Company Northern Tier Transmission Group Northwest Power and Conservation Council Northwest Power Pool Northwestern Energy PacifiCorp Portland General Electric

4 Table of Contents Executive Summary Introduction Ten-Year Plan Joint Areas of Concern Study Team Reports Sensitivity Studies for 2012 Potential Major Transmission s Interfaces with Neighboring Regions Internal Interfaces Study Assumptions and Methodology Base Case Development Load Modeling Assumptions Resource Modeling Assumptions Transmission Modeling Assumptions Flow Diagrams Special Protection System Assumptions Transmission Additions Modeled Study Methodology System Assessment Results Joint Areas of Concern Pg. 1 Pg. 3 Pg. 4 Pg. 18 Pg. 24 Pg. 28 Pg. 31 Pg. 37 Pg. 43 Pg. 62 Pg. 63 Disclaimer: The data and analysis contained in this report are not warranteed by ColumbiaGrid or any other party. Any reliance on this data or analysis is done so at the user s own risk.

5 Table of Contents continued... Figures Figure B1: Figure B2: Figure E1: Figure E2: Figure E3: Figure E4: Figure F1: Figure G1: Figure H1: Figure H2: Figure H3: Figure H4: Figure H5: Figure H6: Figure I1: Figure I2: Figure I3: Figure I4: Figure I5: Figure I6: Figure J1: Figure J2: Figure J3: Figure J4: Figure J5: Process Timeline ColumbiaGrid Ten-Year Plan Puget Sound Area Study Team Proposed Additions Wind Resources Cross Cascades South Cowlitz County Support Map Northern Middle Columbia Preferred Plan Other Potential Transmission s Northwest to British Columbia Montana to Northwest Idaho to Northwest California-Oregon Intertie Pacific DC Intertie Alturas North of John Day South of Allston West of Cascades North West of Cascades South West of McNary West of Hatwai Ten-Year Heavy Winter Base Case Conditions Ten-Year Heavy Summer Base Case Conditions Ten-Year Light Summer High Wind Base Case Conditions Five-Year Heavy Winter Base Case Conditions Five-Year Heavy Summer Base Case Conditions Pg. 3 Pg. 5 Pg. 19 Pg. 20 Pg. 21 Pg. 23 Pg. 26 Pg. 28 Pg. 31 Pg. 33 Pg. 34 Pg. 35 Pg. 36 Pg. 36 Pg. 37 Pg. 38 Pg. 39 Pg. 40 Pg. 41 Pg. 42 Pg. 51 Pg. 52 Pg. 53 Pg. 54 Pg. 55 Tables Table B1: Table B2: Table J1: Table J2: Table K1: s Energized in the Last Year ColumbiaGrid Ten-Year Plan Base Case Summary Transmission s included in Base Cases Potential Reactive Mitigation s Pg. 4 Pg. 5 Pg. 47 Pg. 57 Pg. 65 Attachments Attachment A: Resource Assumptions for Base Cases Attachment B: Transmission Expansion s Pg. 75 Pg. 79 **Critical Electrical Infrastructure Information (CEII) protected documents are available upon request in accordance with ColumbiaGrid CEII policies at (

6 Executive Summary 1 The ColumbiaGrid 2013 Biennial Transmission Expansion Plan (Expansion Plan) looks out over a ten-year planning horizon ( ) and identifies the transmission additions necessary to ensure that the parties to the ColumbiaGrid Planning and Expansion Functional Agreement can meet their commitments to serve load and meet firm transmission service commitments. Since the adoption of the 2012 Update to the 2011 Biennial Transmission Expansion Plan, the following information has become available and is incorporated into this Expansion Plan: 1) In July 2012, ColumbiaGrid staff completed its 2012 System Assessment which highlighted areas of the system where there may be deficiencies in meeting reliability standards. Seventeen areas of concern were identified that affect more than one ColumbiaGrid Planning Participant. Most of these concerns will be addressed by existing study teams. Four of these areas of concern may require the creation of new study teams if existing utility efforts to resolve the issues are not successful. 2) The 2012 System Assessment identified the need for the following sensitivity studies which are documented in this report: a. Further study of voltage stability issues and unsolved outages from the System Assessment; b. Impact of bypassing the Starwood transformer on the Tacoma 230 kv bus outage; c. Transmission assessment of the Northwest Power Planning and Conservation Council 6th Power Plan; d. Mid-Columbia project assessment; e. Transient stability studies using the TEPPC 2022 Light Spring base case; and f. Natural gas generation limitations. 3) On October 28, 2011, The Puget Sound Area Study Team completed an update to the Transmission Expansion Plan for the Puget Sound area. The Puget Sound Area Study Team has recently been focused on supporting the proposed projects in the south-to-north plan and updating the north-to-south transfer section of the

7 original report. This update to the report is scheduled to be completed in January ) The Northern Mid-Columbia Study Team resolved the cost allocation, maintenance and ownership issues related to the preferred plan of service (Rapids-Columbia 230 kv line). Douglas County PUD is building this line and it is expected to be completed in ) The Cross Cascades North Study Team issued its final report in April 2012 which documents the incremental transfer capability benefits of short and long lead time construction alternatives. The results show that the series capacitors is the most beneficial short lead time project and a new Chief Jo-Monroe 500 kv line is the most beneficial long lead time project. Determining project timing was beyond the study team scope. BPA has recently added the Schultz series capacitor project to its committed plans and this project is now included in the ColumbiaGrid Ten Year Plan. 6) Development activities are ongoing for a large number of potential major transmission projects that could affect the northwest transmission system. Updated information on these projects is provided in this report. ColumbiaGrid has documented all of the above in this Expansion Plan which has been reviewed by the various study teams and other interested stakeholders. With the completion of this Expansion Plan, ColumbiaGrid will initiate the 2013 System Assessment cycle which is scheduled for completion in July Resolution to adopt the 2013 Biennial Transmission Expansion Plan WHEREAS, a purpose of ColumbiaGrid is carrying out the ColumbiaGrid Planning and Expansion Functional Agreement ( PEFA ), which is intended to support and facilitate multi-system planning through a coordinated, open, and transparent process and is intended to facilitate transmission expansion based upon such planning; and 2 WHEREAS, pursuant to Article 2.1 of the PEFA, each Planning Cycle, ColumbiaGrid shall develop and review a Draft Biennial Plan and shall adopt, by majority vote of the ColumbiaGrid Board of Directors, a Biennial Plan; and WHEREAS, ColumbiaGrid has prepared a Draft 2013 Biennial Transmission Expansion Plan for the years ( 2013 Transmission Expansion Plan ) based on the ColumbiaGrid planning process and posted this plan for public review and comment on December 24, 2012; and NOW, THEREFORE, BE IT RESOLVED that, based upon the ColumbiaGrid Board of Directors review of the 2013 Transmission Expansion Plan on its technical merits, the consistency of the s listed in the Transmission Expansion Plan with the PEFA, and considering comments and information provided during the review process, the ColumbiaGrid Board of Directors hereby adopts the 2013 Biennial Transmission Expansion Plan (February 20, 2013).

8 Figure B-1: Process Timeline Introduction 3 ColumbiaGrid was formed with seven founding members in 2006 to improve the operational efficiency, reliability, and planned expansion of the northwest transmission grid. Eleven parties have signed ColumbiaGrid s Planning and Expansion Functional Agreement (PEFA) to support and facilitate multi-system transmission planning through an open and transparent process. ColumbiaGrid s primary grid planning activity is to develop a biennial transmission expansion plan that looks out over a ten-year planning horizon and identifies the transmission additions necessary to ensure that the parties to the ColumbiaGrid Planning and Expansion Functional Agreement can meet their commitments to serve load and transmission service commitments. A significant feature of the transmission expansion plan is its singleutility planning approach. The plan has been developed as if the region s transmission grid were owned and operated by a single entity. This approach results in a more comprehensive, efficient, and coordinated plan than would otherwise be developed if each transmission owner completed a separate independent analysis. In the years between the production of biennial plans, ColumbiaGrid may produce an update to the biennial plan if warranted based on changes in transmission plans.

9 Ten-year Plan The projects in the ten-year plan fill a variety of needs such as serving load, integrating new resources, or facilitating economic transfers. To be included in the plan, the projects need to be committed projects that are in the permitting, design, or construction phases. The projects in the plan may have been generated in a variety of forums such as System Assessments, studies completed by the study teams, or studies completed by individual planning participant studies. ColumbiaGrid s Ten Year Plan is shown in Figure B-1 and Table B-2. More detailed information for each of the projects is provided in Attachment B of this report. Changes in this Plan from the prior plan update are also noted along with estimated costs for the ColumbiaGrid member projects. s from the previous Ten-Year Plan that have since been energized are shown in Table B-1. The ColumbiaGrid ten-year plan has been coordinated directly with other sub-regional planning groups (e.g., the Northern Tier Transmission Group) and with the overall region through the Western Electricity Coordinating Council (WECC). In 2011, WECC completed an overall ten-year plan for the western interconnection (2011 WECC 10-Year Regional Transmission Expansion Plan). The previous ColumbiaGrid ten-year plan was part of the foundation for this interconnection-wide plan. The projects in the ColumbiaGrid ten-year plan primarily address issues that occur in the first five years of the ten-year planning horizon. Additional projects will be required to meet the needs in the latter part of the ten-year planning horizon. These additional projects are still being developed as there is sufficient time to study these areas and refine the projects that will address those needs. Several of the long-term needs that may generate additional transmission projects are described below. These projects have not been included in the Ten-Year Plan. 4 Table B-1: s Energized in the last year s Completed Longview-Bakers Corner-Lexington 115 kv line Sammamish Bus Reliability Improvements Sedro Woolley Substation 230/115 kv transformer addition #2 North Bonn-Ross/North Bonn-Troutdale 230 kv line Swap Cowlitz Substation 230 kv line Retermination Phase 1 Ostrander 500/230 kv transformer addition (replacing McLoughlin transformer, converting Ostrander-McLoughlin 500 kv line to 230 kv operation) Longview-Cowlitz #2 upgrade from 69 kv to 115 kv Keeler - Horizon 230 kv line with 230/115 kv transformer at Horizon Substation Cowlitz Puget Sound Energy Puget Sound Energy Bonneville Tacoma Power Bonneville Power/PGE Cowlitz County PUD Portland General Electric

10 Figure B-2: ColumbiaGrid Ten-Year Plan Table B-2: ColumbiaGrid Ten-Year Plan Name Sponsor Date Change Estimated Cost A1 Moscow 230 kv Substation Rebuild and Transformer Replacement Avista 2014 delayed from 2012 $10 Million A2 Benton-Othello 115 kv Line Upgrade Avista 2016 delayed from 2013 $10 Million A3 Westside 230 kv Rebuild and Transformer Upgrades Avista 2016 delayed from 2014 $15 Million A4 Irwin - Spokane Valley Transmission Reinforcements Avista 2016 delayed from 2013 $5 Million A5 Lancaster Combustion Turbine Integration Avista 2013 A6 Bronx - Cabinet 115 kv Line Rebuild Avista 2016 delayed from 2015 $10 Million B1 Big Eddy-Knight 500 kv line connecting to the existing Wautoma-Ostrander 500 kv line at the new Knight Substation Bonneville Power 2014 $115 Million B2 Central Ferry - Lower Monumental 500 kv line and connection to existing Lower Granite - Lower Monumental 500 kv lines at the new Central Ferry Substation Bonneville Power 2014 $99 Million B3 Ponderosa 500/230 kv #2 Transformer Addition Bonneville Power 2013 $31 Million B4 Ostrander Breaker Addition Bonneville Power/PGE 2014 $2.4 Million B5 Castle Rock - Troutdale 500 kv line (I-5 Corridor Reinforcement ) connected to the PaulAllston line at the new Castle Rock Substation Bonneville Power $340 Million B6 Lower Valley Reinforcement Bonneville Power 2014 $48 Million B7 Pearl 500 kv Substation Breaker Addition Bonneville Power 2016 $1.7 Million B8 Montana to Washington (Garrison West) Bonneville Power 2015 $115 Million B9 Monroe Substation 500 kv Caps Bonneville Power 2014 $5.6 Million B10 Columbia Falls 230 kv Bus Reliability Improvements Bonneville Power 2013 $1 Million B11 Hatwai 230 kv Bus Reliability Improvements Bonneville Power 2015 $4.2 Million B12 Port Angeles 230 kv Bus and 230/69 kv Transformer or non-wires project Bonneville Power 2014 $15 Million B13 Keeler 230 kv Bus Reliability Improvements Bonneville Power 2014 $2.3 Million B14 Raver 500/230 kv Transformer, 230 kv line to Covington Substation Bonneville Power 2016 $45 Million B15 Longview - Lexington 230 kv Line Retermination into Longview Annex Bonneville Power 2015 $2 Million $3 Million

11 B16 Name Sponsor Date Change Extend Northern Intertie RAS for the combined loss of Monroe-SnoKing-Echo Lake and Chief Joseph-Monroe 500 kv lines Estimated Cost Bonneville Power 2018 delayed from 2015 $3 Million B17 Celilo Terminal Replacement (PDCI upgrade 3220 MW) Bonneville Power 2016 $320 Million B18 McNary 500/230 kv Transformer #2 Bonneville Power 2016 new project $18.5 Million B18 McNary 230 kv Shunt Capacitors (2x150 MVAR banks) Bonneville Power 2013 new project $5.7 Million B19 Rogue Static VAR Compensator Bonneville Power 2013 $9 Million B20 Paul 500 kv Shunt Reactor Bonneville Power 2016 new project $6 Million B21 Split Pearl-Sherwood 230 kv lines Bonneville Power 2017 new project $1.4 Million B22 Split McLoughlin-Pearl-Sherwood 230 kv lines Bonneville Power 2017 new project $1.3 Million B7 Pearl 230 kv Bus Section Breaker Bonneville Power 2017 new project $1 Million B23 Salem-Chemawa 230 kv Line Upgrade Bonneville Power 2016 new project $0.9 Million B24 Tucannon River 115 kv Shunt Capacitors (2x6.5 MVARs) Bonneville Power 2013 new project $2 Million B25 North Bonneville - Troutdale 230 kv #2 line Retermination Bonneville Power 2015 new project $2.1 Million B26 Columbia 230 kv Bus Section Breaker Bonneville Power 2016 new project $1 Million B27 LaPine Reactive (19 MVAR Cap, 40 MVAR reactor) Bonneville Power 2014 new project $3.3 Million B28 Bell 230 kv Bus Section Breaker Bonneville Power 2015/2016 new project $1 Million B29 Kalispell 115 kv Shunt Capacitors (2x16 MVARs) Bonneville Power 2014 new project $3.1 Million B30 Schultz-Raver 500 kv Series Capacitors Bonneville Power 2017/2018 new project $35 Million B31 White Bluffs 115 kv Shunt Capacitors (30 MVARs) Bonneville Power 2013 new project $2 Million B32 Tacoma 230 kv Bus Section Breaker Bonneville Power 2016 new project $1 Million CH1 Rerating of McKenzie - Andrew York 115 kv #1 and #2 lines Chelan County PUD 2013 $0.5 Million CO1 Longview-Lexington #2 upgrade from 69 kv to 115 kv Cowlitz County PUD $4.9 Million CO1 Longview - Lexington - Cardwell upgrade from 69 kv to 115 kv Cowlitz County PUD 2015/2017 $10.1 Million CO2 South Cowlitz County Cowlitz County PUD new project $7.7 Million D1 Douglas - Rapids 230 kv line and Rapids 230/115 kv Substation Douglas County PUD 2013 $17 Million D2 Rapids - Columbia 230 kv line and Columbia terminal Douglas County PUD 2015 $14 Million G1 Columbia - Larson 230 kv line Grant County PUD 2014 $42 Million G2 Rocky Ford - Dover 115 kv line Grant County PUD 2016 $5 Million I1 Hemingway - Boardman 500 kv line Idaho Power/BPA 2016 $820 Million PA1 Wanapum - Pomona Heights 230 kv line PacifiCorp 2015 delayed from 2013 PA2 Wallula-McNary 230 kv line PacifiCorp 2014 delayed from 2013 PA3 Whetstone 230/115 kv Substation PacifiCorp 2015 delayed from 2014 PA4 Union Gap 230/115 kv transformer #3 PacifiCorp 2016 delayed from 2013 PG1 Cascade Crossing (Coyote - Boardman - Bethel 500 kv line) Portland General Electric 2017 PG2 Blue Lake - Gresham 230 kv line Portland General Electric 2017 PS1 Alderton Substation 230/115 kv transformer Pierce County Puget Sound Energy 2015 delayed from 2014 $28 Million PS2 St. Clair Transformer in Thurston County Transformer Puget Sound Energy 2013 $30 Million PS3 Rebuild Sammamish-Lakeside-Talbot 115 kv lines and energize one at 230 kv, install a new 230/115 kv Transformer at Lakeside Puget Sound Energy 2017 $70 Million PS4 Starwood Autotransformer Removal Puget Sound Energy 2013 new project $1 Million PS5 Talbot 230 kv Bus Improvements Puget Sound Energy $11 Million PS6 Woodland - St Clair 115 kv Line Puget Sound Energy 2015 $13 Million PS7 Sedro Woolley - Bellingham #4 115 kv Line Reconductor Puget Sound Energy 2015 $14 Million PS8 Portal Way 230/115 kv Transformer #2 and Line Upgrades Puget Sound Energy/BPA 2016 delayed from 2015 $25 Million SC1 Reconductor Bothell-SnoKing 230 kv Double Circuit Line Seattle City Light/BPA 2016 $3 Million SC2 Series Inductors on Broad Street - Union - Massachusetts and Broad Street - Denny 115 kv Underground Cables Seattle City Light 2016 $13 Million SC2 Denny Substation - Phase 1 Seattle City Light 2016 $120 Million SC2 Upgrade Denny Substation Transmission - Phase 2 Seattle City Light 2020 $50 Million SC3 Reconductor Delridge - Duwamish 230 kv transformer Seattle City Light 2016 $2 Million SN1 Beverly Park 230/115 kv transformer Snohomish County PUD $25 Million 6 SN2 Granite Falls 115 kv Transmission Loop Snohomish County PUD 2014 new project $7 Million T1 Cowlitz 230 kv Line Retermination Tacoma Power $1 Million T1 Cowlitz 230 kv Substation Reliability Improvement Tacoma Power $3 Million T2 Southwest Substation 230 kv bus Reliability Improvement Tacoma Power $3 Million TB1 Montana Alberta Tie-Line (MATL) Enbridge/MATL LLC 2013 $209 Million Total of all ColumbiaGrid projects $2,847 Million

12 7 1. North King County 230/115 kv Transformation and Capacity Increase - In addition to the Lakeside transformer in the Ten-Year Plan, Puget Sound Energy is also planning additional 230/115 kv transformation at Lake Tradition in the long term. 2. Mid-Columbia Area Reinforcement Grant County PUD is contemplating additional reinforcements between the Wanapum and Midway 230 kv Substations in central Washington. 3. Lewiston Reinforcements A second Lolo-Hatwai 230 kv line is a possible solution to increase capacity to meet Avista load growth and for operational flexibility. 4. Chemawa 230/115 kv transformer additions Additional transformation is expected to be necessary in the north Salem area to meet growing Bonneville loads. 5. Kalama Energy A new 230 kv line from Kalama to Longview is being considered by Cowlitz PUD to connect a 346 MW gas fired generation plant to the system and provide for load growth in the area. 6. Horizon Phase II The new Horizon-Trojan 230 kv line could provide additional capacity on the South of Allston path to assist in delivering new generation adjacent to Port Westward to Portland General Electric loads in the west Portland area. In addition, a second 230/115 kv bulk power transformer is planned to be installed at Horizon Substation. As these proposed projects mature into committed plans to meet these long-range needs, they will be incorporated into future ColumbiaGrid ten-year plans.

13 Joint Areas of Concern The 2012 System Assessment identified several planning areas with needs that require multiple utility studies during this planning cycle. All of these areas involve load service issues with impacts to ColumbiaGrid participants. s that are developed to address these concerns would typically be characterized as Existing Obligation s under PEFA. s to mitigate these issues are in various stages of development. Some are well defined with firm commitments from the responsible utilities. Others are still in the conceptual stage. Future Biennial Plans will include updates to these projects as they become available. The transmission deficiencies identified in the 2012 System Assessment that were also identified in 2011 and prior System Assessments include: 1. The Olympia-Shelton Area In the winter cases, several 230 kv bus outages at Shelton did not solve. These problems were identified in previous System Assessments. Bonneville and Puget Sound Energy own facilities in this area. These issues were included as sensitivities in the 2013 Biennial Plan. Load shedding is a possible mitigation measure for these outages. 2. Centralia Area In the five-year and ten-year cases, the N-2 outage of the Paul-Olympia and Paul- Satsop 500 kv lines did not solve indicating a possible voltage stability issue. In the summer, the N-2 outage of the Raver-Paul 500 kv and Coulee-Olympia 287 kv lines overloads the White River-Sumner-Pioneer 115 kv line. This latter problem is sensitive to Northern Intertie imports and improves as transfers increase. Mitigation for this problem is not necessary as the adjacent circuit criteria applies only to lines above 300 kv and the Coulee-Olympia line voltage is 287 kv. These facilities are owned by Bonneville and Puget Sound Energy. The first issue listed is a new issue this year while the second was noted in previous system assessments. Investigation of the Paul-Olympia and Paul- Satsop 500 kv outage showed this instability was due to modeling issues in the Port Angeles/Sappho area, low initial voltages, and circulating reactive flows. This system deficiency can be mitigated by adding a 35 MVAR SVC at Port Angeles. Voltage instability in heavy winter conditions due to Shelton breaker failures can also be mitigated by the same Port Angeles 35 MVAR SVC. There are no committed plans for this area. Progress on resolution of these issues will be monitored to determine if a Study Team effort is warranted. The voltage stability issue was included as a sensitivity study for this Biennial Plan. 3. Salem-Eugene area In both the five-year and ten-year summer cases, a breaker failure outage at the Santiam west 230 kv bus overloads the Santiam-Chemawa 230 kv line. The bus section breaker outage of the Santiam 230 8

14 9 kv bus overloads the Fry-Oromet 115 kv line. In the winter, there were failed solutions for outages of the Santiam West 230 kv bus, the bus section breaker outage of the Santiam 230 kv bus and the Santiam-Wren 230 kv line. In both summer cases, a breaker failure at the Albany 115 kv bus overloads the Fry-Oromet 115 kv line. In the winter, this breaker failure overloads the Bethel-Parish Gap 115 kv line along with the Fry-Oromet 115 kv line. Most of these problems were identified in previous system assessments. BPA has recently added the Santiam-Chemawa line upgrade to its committed plans and this project is now included in the ColumbiaGrid Ten Year Plan. This plan will be tested in the 2013 System Assessment. BPA is also considering the addition of a bus section breaker at Santiam. PacifiCorp has the ability to shift load on their distribution system to help alleviate their transmission overloads. These plans should be sufficient to mitigate the overload problems. The unsolved outages could cause voltage stability issues in the Salem-Eugene-Florence areas and further study of these problems was included as a sensitivity study for this Biennial Plan. overloads the Saint Marys-Murrayhill 230 kv line. In the winter, this same outage overloads the Forest Grove-McMinnville 115 kv, Sherwood-Springbrook 115 kv lines, and the Sherwood 230/115 kv transformer. A bus section breaker failure at the Pearl 230 kv bus overloads the Canemah-Rosemont 115 kv lines. These problems occurred in both the five-and ten-year cases. A N-2 outage of the Pearl-Ostrander/Pearl-Marion 500 kv lines overloads the McLoughlin 230/115 kv transformer and the Alder-Tabor 115 kv and Troutdale-Gresham 230 kv lines in the fiveyear case only (the proposed Castle Rock- Troutdale line appears to resolve this N-2 outage). Many of these system issues in the Pearl- Sherwood area have been identified in previous system assessments and involve Bonneville and Portland General Electric facilities. BPA has recently added a Pearl 230 kv bus section breaker and re-termination of the Pearl-Sherwood- McLoughlin double circuit lines to its committed plans. These projects are now included in the ColumbiaGrid Ten Year Plan. These plans will be tested in the 2013 System Assessment. Since there is only one ColumbiaGrid member involved, these issues will be the responsibility of the affected parties and no study team is proposed. 4. Pearl-Sherwood Area In the summer, the N-2 outage of the Carlton-Sherwood 230 kv and Newburg- Sherwood 115 kv lines overloads the Forest Grove-McMinnville 115 kv and Sherwood- Springbrook 115 kv lines. A bus section breaker failure at the Pearl 230 kv bus 5. Bend Area Voltage Stability In both summer cases, the loss of the Redmond 230 kv bus overloads the Ponderosa-Prineville 115 kv line. In both winter cases, a breaker failure at Pilot Butte 230 kv overloads the Pilot Butte 230/69 kv transformer. A breaker failure at Ponderosa

15 230 kv also overloads the Redmond-Pilot Butte 115 kv line. A bus outage at Redmond 230 kv did not solve which may be a symptom of voltage instability. These facilities are owned by PacifiCorp and Bonneville and these problems were also identified in the 2011 System Assessment. The 115 kv line overloads could be a modeling issue (these lines have been upgraded recently and an investigation is underway to determine if the upgrades are modeled correctly). The unsolved outages could cause voltage stability issues in the Bend-Redmond area. Since there is only one ColumbiaGrid member involved, these issues will be the responsibility of affected parties and no study team is proposed. Bonneville has plans to build an additional 230/115 kv station in the area (Bonanza) that could help mitigate these problems. The voltage stability issue was included as a sensitivity study for this Biennial Plan. 6. Sandpoint, Idaho Area Libby 230/115 kv transformer outages and Libby 115 kv bus outages overload the Bronx-Sand Point 115 kv line in the five- and ten-year summer cases. These facilities are owned by Bonneville and Avista. Similar issues were identified in previous System Assessments. Bonneville and Avista have proposed sectionalizing the system at Sand Creek to help mitigate this problem along with reconductoring of the Bronx-Sand Point 115 kv line which is underway. These reinforcements should be included in future system assessments. 7. Yakima/Wanapum Area In the winter, outages of either the Union Gap 230 kv bus, the Wanapum 230 kv bus or the Midway-Union Gap 230 kv line will cause the Outlook-Punkin 115 kv and Punkin- Toppenish 115 kv lines to overload. An outage of the Midway 230 kv bus overloads the Outlook 230/115 kv transformer. An outage of Midway 230 kv buses #2 and #3 overloads the Wanapum-Pomona 230 kv line. A breaker failure at the Outlook 115 kv bus overloads the Union Gap-Wapato 115 kv line. In the summer, an outage of the Midway 230 kv buses #2 and #3 overloads the A8- A6 230 kv line, Hew Tap-Ashe Tap 230 kv line and Warden-Othello 115 kv line. An outage 10

16 11 of the Midway 230 kv bus overloads the Wanapum-Pomona 230 kv line. An outage of the Midway-Outlook 230 kv line overloads Wine Country-Sunnyside 115 kv line. An outage of the Midway-Wine Country 230 kv line overloads the Outlook-Sunnyside 230 kv line, Outlook 230/115 kv transformer and the Sunnyside-Wine Country 115 kv line. A breaker failure at Outlook 115 kv overloads the Union Gap-Wapato 115 kv line. These facilities are owned by BPA and PacifiCorp with minor ownership by Grant County PUD and Avista. Avista has plans to reconductor the Warden-Othello 115 kv line which would resolve their issues in the area. The A8-A6 230 kv and Hew Tap-Ashe Tap 230 kv line ratings and the Midway 230 kv bus arrangement are being reviewed to determine if they are modeled correctly. Since there is essentially only one ColumbiaGrid member involved (BPA) and the worst overloads are on PacifiCorp s system for outages of PacifiCorp facilities, final resolution of these issues will be the responsibility of those parties and no study team is proposed but these issues will continue to be monitored for resolution. New issues from the 2012 System Assessment 1. South of Allston Area In the five-year summer case, the N-2 loss of the Allston-Paul and Allston-Napavine 500 kv lines overloads the Aberdeen- Cosmopolis 115 kv and Holcomb-Valley Tap 115 kv lines. The loss of the Allston- Keeler 500 kv line overloads the Astoria Tap- Seaside 115 kv line. The loss of sections of the Keeler 500 kv bus overloads the Keeler- Rivergate 230 kv, Rivergate-Trojan 230 kv and Saint Marys-Trojan 230 kv lines. There is RAS for the line outage although the details on how it functions are not available at this time to verify its functionality for all the issues identified above. These outages and overloaded facilities are owned by Bonneville, Portland General and PacifiCorp. These overloads only occur in the five-year cases; the addition of the I-5 Corridor (Castle Rock-Troutdale) corrects these problems, so these issues will be dealt with operationally. Since these problems will likely be resolved in the longer term with a planned project, no study team is proposed.

17 2. Northern Intertie Transfer Issues In both summer cases, a breaker failure outage at the Bothell 230 kv bus overloads the Snohomish-Bothell 230 kv #1 line. by an increase in the load forecast for Cowlitz County PUD. Progress on resolution of this issue will be monitored to determine if a study team effort is warranted. The Puget Sound Area Transmission Expansion Plan was modeled in this System Assessment along with an increase in the north to south transfers on the west side of the Northern Intertie to 2100 MW in the tenyear case to reflect the increased north to south commitments Bonneville is planning to make on the Northern Intertie (2010 Network Open Season). These overloads are caused by bus section breaker outages that may no longer be a concern due to changes in the new NERC TPL standards. 3. Longview Area The loss of the Longview 115 kv bus, as could occur with the failure of a bus sectionalizing breaker, overloads the Longview-Lexington 230 kv line. Loss of the Lexington 230/115 kv transformer overloads the Longview 230/115 kv transformer. A breaker failure at the Longview 230 kv south bus overloads the Longview-Allston 115 kv line. Re-terminating the Longview-Lexington line to Longview Annex may mitigate this problem. BPA has recently added this project to its committed plans to resolve this issue. This project is now included in the ColumbiaGrid Ten Year Plan and will be tested in the 2013 System Assessment. These outages occur in the winter and summer, five and ten-year cases. There are also unsolved outages for the Lexington and Cowlitz CCP 115 kv buses. These facilities are owned by Bonneville and Cowlitz County PUD. This is probably caused 4. SnoKing/Everett Area In the summer and winter five-year and ten-year cases, an outage of SnoKing 115 kv buses #2 and #3 (bus section breaker) overloads the Paine Field-Halls Lake 115 kv line. All of these cases were simulated with one 230/115 kv transformer at Beverly Park. These system issues involve Bonneville and Snohomish facilities. They are caused by a bus section breaker outage that might be resolved by changes in the new NERC TPL standards. These issues are noted here for information. In the winter, loss of the Murray 115 kv bus overloads the Everett-Tap-Navy-Norton- Delta 115 kv line. These facilities are also owned by Bonneville and Snohomish and work is underway to resolve these issues. Progress on resolution of this issue will be monitored to determine if a study team effort is warranted. Possible solutions include adding a new 230 kv source to the north end of the system and line reconductoring. 12

18 13 5. Tacoma Area In the summer five-year and ten-year cases, the bus section breaker outage at the Tacoma 230 kv bus overloads the Midway- Zenith 115 kv, Tide Flats-Pioneer-Pioneer Tap 115 kv, Weyerhaeuser Tap-Marine View 115 kv, White River-West Campus 115 kv and Zenith-Redondo 115 kv lines. In both winter cases, this same outage overloads the Starwood 115/110 kv transformer and White River-West Campus 115 kv lines. This problem appears to have a reverse sensitivity to Northern Intertie flow (it gets better with higher imports). This system problem was identified in previous system assessments and involves Bonneville, Tacoma and Puget Sound Energy facilities. BPA has recently added the Tacoma bus section breaker project to its committed plans to resolve this issue. This project is now included in the ColumbiaGrid Ten Year Plan and will be tested in the 2013 System Assessment. Bypassing the Starwood transformer for this outage might provide some relief and the effectiveness of this operational solution was studied as a sensitivity study in this Biennial Plan. Progress on resolution of the bus section issue will be monitored to determine if a study team effort is warranted. 6. Spokane Reliability In the five and ten-year summer cases, the outage of the Bell 230 kv bus section breaker overloads the Pine Street-Newport 115 kv line. BPA has recently added a project for additional bus section breakers on the Bell 230 kv bus to its committed plans to resolve this issue. This project is now included in the ColumbiaGrid Ten Year Plan and will be tested in the 2013 System Assessment. These facilities are owned by Bonneville and Avista. This issue will be monitored in the future as these plans get firmed up to determine if a study team effort is needed. 7. Orofino Area in Northern Idaho In five-year and ten-year summer cases, the outage of the Dworshak-Hatwai 500 kv line overloads the Ahsahka-Orofino 115 kv line

19 and the Dworshak 115/13.8 kv transformer. Avista and Bonneville have operating procedures and RAS in place to sectionalize the system and redispatch generation for this outage. Future system assessments will attempt to model these procedures. No further study team effort should be needed. 8. McNary Area In the summer five and ten-year cases, an outage of the McNary 230 kv Bus 2 and 3 overloads the Badger-Nine Canyon Wind- H2F-Berrian 115 kv lines. An outage of McNary 230 kv bus section #3 overloads the Cold Springs 230/69 kv transformer. BPA has recently added a second 500/230 kv transformer at McNary to its committed plans that should resolve these issues. This project is now included in the ColumbiaGrid Ten Year Plan and will be tested in the 2013 System Assessment. the Cold Springs transformer removes the parallel 69 kv systems and improves the flows in the area although there are still low voltages. Redispatch of generation at McNary could relieve these problems. This problem appears to be confined to the local area. These are joint problems between BPA and PacifiCorp. Since there is only one ColumbiaGrid member, no study team will be formed. Redispatch of generation at McNary could relieve these problems. One area of concern with the McNary 230 kv bus section #3 outage is the high loading of the Cold Springs 230/69 kv transformer (176%). This area was tested to determine what would happen if the Cold Springs Transformer were to trip before operators could re-adjust the system. Power flow models of this problem showed that the McNary bus outage removes all generation and voltage support from the McNary 230 kv bus and the Cold Springs substation tries to provide voltage support to McNary. Tripping 9. Okanogan Area In the five and ten-year winter cases, a breaker failure at Wells 230 kv bus would overload the Okanogan-Ophir Tap 115 kv line. These facilities are owned by Douglas County PUD and Okanogan. Since there is only one ColumbiaGrid member involved, these issues will be the responsibility of affected parties and no study team is proposed. Possible solutions include bus sectionalizing or line upgrades. 10. Clark County/Troutdale Area In the summer, in both the five-year and ten-year cases, a breaker failure outage of the Troutdale west 230 kv bus overloads the Fishers-Joe Ast 115 kv, Lacamas-Sifton 14

20 kv and Troutdale-Linneman 230 kv lines. A Ross 230 kv bus section breaker outage overloads the Merwin-View Tap- Cherry 115 kv line. Reduced Yale and Merwin generation levels would resolve this issue. In both winter cases, an N-2 North Bonneville-Sifton Tap-Ross # 1 and #2 230 kv outage overloads the Troutdale 230/115 kv transformer. BPA has recently added a project to reterminate the North Bonneville - Troutdale #2 230 kv line to a different position at North Bonneville to its committed plans to resolve these issues. This project is now included in the ColumbiaGrid Ten Year Plan and will be tested in the 2013 System Assessment. These system issues involve Bonneville, PacifiCorp and Clark County facilities. Since there is only one ColumbiaGrid member, these issues will be the responsibility of affected parties and no study team is proposed. Possible mitigation includes line upgrades, bus section breakers and/or redispatching generation at Merwin Dam. Problems areas that have been resolved since the 2011 System Assessment include: 1. Northern Olympic Peninsula Voltage instability and overloads in the Fairmount and Port Angeles area occurred for loss of the Shelton-Fairmount 230 kv #1 and #2 lines, which are on double circuit towers, in several previous System Assessments. This issue is not being included in this year s System Assessment since Puget Sound Energy is transferring ownership of its facilities in the Jefferson County area around Fairmount Substation to the local PUD which means that this issue is no longer a joint issue. The North of Fairmont back tripping scheme that is planned for 2013 should mitigate this issue. This scheme will be tested in the 2013 System Assessment. 2. Puget Sound 500/230 kv Transformation A limitation in the 500/230 kv transformation in the Puget Sound area was noted in previous System Assessments. The Puget Sound Area Transmission Expansion Plan and the ColumbiaGrid Ten-Year Plan include a new transformer at Raver which is scheduled to be installed in With this transformer included in the base cases, the limitation noted in earlier System Assessments has been resolved. 3. Interaction of Proposed I-5 Corridor BPA is planning to build the I-5 Corridor project which is a 500 kv line from the new Castle Rock Substation to Troutdale Substation. PGE is also planning to reinforce their system between Troutdale and Gresham by building a Blue Lake- Gresham 230 kv line. Both of these projects appear to correct the problems they were designed to mitigate, however there was an interaction between these two projects that created some new transmission issues in the 2011 System Assessment. PGE is now planning to upgrade its existing Troutdale- Blue Lake-Gresham line to resolve these issues. This change was modeled this year and no problems resulted from the new configuration.

21 4. Benton AVA-Taunton-South Othello 115 kv overloads Several outages around Larson, Frenchman Hills and Warden caused the Benton AVA-Taunton-South Othello 115 kv line to overload in the 2011 System Assessment. Avista is proposing to reconductor this line in 2016 which was modeled in this year s base cases. With the upgrade in place, this overload did not show up in the 2012 System Assessment. 5. Spokane Area 230/115 kv Transformation Bonneville s and Avista s 230/115 kv transformation in the Spokane area was overloaded in the summer base cases in the prior system assessments. Avista s plan to upgrade the transformer at Westside was included in the 2012 System Assessment. This addition mitigated the transformer overloads in this assessment. 6. Moscow Area The Moscow 230/115 kv transformer in northern Idaho overloaded for numerous outages in prior system assessments. Avista s plan to upgrade the existing transformers was modeled in this assessment and has mitigated the overloads that occurred in previous assessments. 7. Interaction of Proposed Cascade Crossing In the summer, the N-2 Marion-Alvey/Marion- Lane 500 kv outage overloads the Santiam- Marcola 230 kv line and the Bethel-Parish Gap-Fry 230 kv line; especially after the Cascade Crossing is added in the ten-year cases. However, the RAS for this outage was not modeled in previous System Assessments. With this RAS, this problem is mitigated. Proposed joint study efforts from 2012 System Assessment The following joint issues have ongoing efforts between the affected utilities to resolve the issues. These study efforts will be monitored as transmission plans are developed to determine if any additional study team effort is needed. 16

22 17 Puget Sound Area Study Team One issue was identified in the Puget Sound area that relates to the operation of the Northern Intertie and the Puget Sound Transmission Expansion Plan that includes a Bothell 230 kv bus outage overloading the Bothell-Snohomish 230 kv #1 line. This issue is likely caused by the increase in imports (north to south flows) from 1500 MW to 2100 MW on the Westside Northern Intertie in the later years. This issue will be directed to the ongoing efforts of the Puget Sound Area Study Team for resolution. Longview Area The loss of the Longview 115 kv and 230 kv busses and the Lexington 230/115 kv transformer overloads several facilities. These facilities are all owned by Bonneville and Cowlitz County PUD. There has been significant load growth forecast in this area. If progress is not being made on resolution of these issues, a study team with Bonneville and Cowlitz may be instigated. Snoking/Everett Area Two issues were identified in the SnoKing/ Everett area. These involve facilities owned by Bonneville and Snohomish PUD with ongoing mitigation efforts. This issue will be monitored in the future as transmission plans for the area are developed. Tacoma Area A bus section breaker outage at BPA s Tacoma s 230 kv Substation overloads several Puget Sound Energy and Tacoma Power facilities. BPA s plan to add a series bus section breaker at Tacoma should resolve this issue. This issue will be monitored in the future as these transmission plans are further developed. This new project will be added to future system assessments. Spokane Area A bus section breaker outage at BPA s Bell 230 kv Substation overloads Avista s Pine Street-Newport 115 kv line. Bonneville is now planning to add a series bus section breaker at Bell to resolve this problem. This issue will be monitored in the future as these plans are developed. This new project will be added to future system assessments.

23 Study Team Reports The following study teams have been active over the last year: 1. Puget Sound Area Study Team 2. Wind Integration Study Team 3. Cross Cascades North Study Team 4. Woodland Study Team 1. Puget Sound Area Study Team Over the past decade, the transmission owners in the Puget Sound Area have been concerned about the ability of their transmission systems to economically and reliably serve area load while simultaneously supporting power transfer commitments between the Northwest and British Columbia. The primary focus for the Puget Sound Area Study Team has been to address these concerns by developing a long-term transmission expansion plan for the Puget Sound Area. Planning the transmission system in the Puget Sound Area is a complex undertaking. There are a large number of transmission facilities which means that it is very common in actual system operation to have one or more transmission facilities out of service for scheduled maintenance or for forced outages. As a result, the traditional transmission planning approach of assuming that all facilities are in service may not be reflective of system operation in a system with a large number of transmission lines. To address this concern, the study considered not only system performance following N-1 and N-2 contingencies with all lines in service, but also the system performance with a prior single element out of service. There are many generators in the north Puget Sound Area that affect the transmission capacity and flows in the Puget Sound Area. The study also used historical generation levels to model likely generation patterns. The study also included the effects of ambient air temperature variations on thermal facility ratings. The information gathered from studying the system response during multiple outage conditions provided valuable insight into system performance and was used to determine transmission facility additions that would be required to minimize operating actions like curtailing firm transfers or adjusting area generation with an initial facility out of service. In October 2010, the Puget Sound Area Study Team issued a report on these results entitled, Transmission Expansion Plan for the Puget Sound Area. The portion of this report that addressed south-to-north transfer limitations was updated in October 2011 ( columbiagrid.org/psast-overview.cfm). The Puget Sound area utilities continue to meet regularly since the publication of the original report in October 2010 and have developed several additional scenarios to be studied. 18

24 19 Figure E-1: Puget Sound Area Study Team Proposed Additions The following six projects were identified as being the most effective at correcting the major limitations found on the system for south-to-north transfers and significantly reducing the risk of curtailing firm transfers. These facilities are shown in Figure E Reconductor the Bothell-SnoKing 230 kv double circuit line. 2. Add series inductors to the Massachusetts - Union - Broad Street and Broad Street-East Pine 115 kv underground cables. 3. Extend the Northern Intertie Remedial Action Scheme (RAS) for the combined loss of Monroe-SnoKing-Echo Lake and Chief Joseph-Monroe 500 kv lines. 4. Add a Raver 500/230 kv transformer and a 230 kv Raver Covington line. 5. Rebuild both the Sammamish- Lakeside-Talbot 115 kv lines to 230 kv. Energize one line at 230 kv and the other at 115 kv 6. Reconductor the Duwamish - Delridge 230 kv line.

25 The update to the north-to-south portion of the Transmission Expansion Plan for the Puget Sound Area report is scheduled to be completed in early The following two projects will be identifi ed as being the most effective at correcting the major limitations found on the system for north-tosouth transfers. Add a second Portal Way 230/115 kv transformer. Upgrade Monroe Novelty 230 kv line to operate at 80 degrees Celsius. The Puget Sound Area Study Team will continue to investigate ways to further reduce the risk of fi rm curtailments. 2. Wind Integration Study Team The Northern Tier Transmission Group (NTTG) and ColumbiaGrid formed the Wind Integration Study Team (WIST) to facilitate the integration of renewable generation into the northwest transmission grid. Substantial growth of wind generation development has occurred in recent years. A summary of operational and under-construction wind resources by state is shown in Figure E-2 (with a comparison to the 2011 data). The current focus of the group is to support the technical study needs of existing sub-regional and regional initiatives by addressing system constraints caused by the increased use of dynamic scheduling. There are technical constraints on the various scheduling paths that limit the acceptable magnitude or rate of these schedule changes. This issue was highlighted on the Northern Intertie where it was determined that voltage support issues 20 Wind Resources as of June 2012 Under Construction Operating Previous Year (2011) Figure E-2: Wind Resources

26 have been introduced by dynamic transfers. These efforts are being closely coordinated with other sub-regional groups and WECC. 3. Cross Cascades North Study Team The West of Cascades North path consists of the Chief Joe-Monroe, Schultz-Raver #1, #3 and #4 and the Schultz-Echo Lake 500 kv lines; the Chief Joe-Snohomish #3 and #4 and Rocky Reach-Maple Valley 345 kv lines; the Coulee-Olympia 287 kv line; and the Rocky Reach-White River and Columbia- Covington 230 kv lines. The transfer limit of this path is approximately 10,000 MW due to voltage stability limits in the Puget Sound area. These facilities are shown in Figure E Figure E-3: Cross Cascades Transmission limited the amount of dynamic schedules that could be accommodated. In 2010, a dynamic transfer capability study by BPA was presented and reviewed by WIST. This type of analysis was expanded by WIST in October 2010 to study the dynamic transfer capability of other paths. In 2011, this Dynamic Transfer Capability Task Force produced Phase 1, Phase 2 and Phase 3 reports confirming the need for dynamic transfer capability limits, exploring dynamic transfer capability study methodologies and applying this methodology to several NW paths. Through 2012, the Dynamic Transfer Capability Task Force continued its work to quantify the dynamic transfer capability of NW paths and identify reliability issues that This path typically loads most heavily during abnormally cold weather events. The path is usually loaded well below the limit for the rest of the time (refer to path loading diagram Figures I-3 and I-4). The most recent cold weather event occurred in December With increasing amounts of remote renewable generation in the east side potentially displacing westside thermal generation, the heavy path flow could occur during normal winter weather. To work toward resolving these issues, a ColumbiaGrid Cross Cascades North Study Team was formed with ColumbiaGrid participants and other interested parties. The purpose of this study team is to calculate the incremental path limit increases that various alternative projects could provide. The calculation methods include both load growth and west-side generation displacement, including the permanent closure of the Centralia generation station.

27 The study team issued the final report in April 2012 ( CCST-overview.cfm). The study addressed the incremental transfer capability benefits of potential system expansion alternatives. Alternatives were categorized into short lead time construction and long lead time construction. Two different simulation methods were used to quantify the transfer capability benefit for each study alternative. Method #1 kept loads at the forecasted ten-year winter peak and increased Cross Cascades North transfers by displacing westside generation with remote eastside generation. Method #2 kept the westside generation constant and increased west-side load above the forecasted tenyear peak with the generation to serve the increased load provided by remote Columbia and Snake hydro generation. Both methods showed the short lead time alternative of adding series capacitors at Schultz Switching Station on the Raver #3 and #4 lines as providing the most benefit. Both methods showed that the most beneficial long lead time construction alternative appears to be a new line between Chief Jo and Monroe Substations. Although timing of system expansion was not included in the study team scope, the results indicate that the timing of the long lead construction alternatives should be beyond 10 years. Since this study team effort and 2012 System Assessment has been completed, BPA has decided to include the Schultz series capacitors in its firm transmission plans to be energized in 2017 or This project will be tested in the 2013 System Assessment. 4. Woodland Study Team Cowlitz County PUD has a long term need to support loads in the southern part of their system around the Lewis River area. They have worked with Bonneville on a preliminary study of the impacts of a 230/115 kv transformer at Woodland. This is a critical area of the system for a variety of reasons. There is much local generation and through flows that impact local transmission flows (this system is within the South of Allston path and would be impacted by the proposed Castle Rock - Troutdale line). The proposed Kalama generation project, a 346 MW gas combustions turbine, could also impact the area system. Besides Bonneville and Cowlitz County, PacifiCorp and Clark County also have transmission facilities in the area. 22

28 Figure E-4: South Cowlitz County Support Map 23 Cowlitz asked ColumbiaGrid to perform a regional assessment of this transformer addition along with other possible upgrade options. ColumbiaGrid completed the study of this project with Cowlitz and other impacted utilities. This report is posted on the ColumbiaGrid website. This study determined that a new 115 kv line between Merwin and Lewis River is a more favorable option than a new 230/115 kv transformer at Woodland. Cowlitz County PUD is pursuing this project which they now call the South Cowlitz County Support. This project is now included in the ColumbiaGrid Ten Year Plan. Figure E-4 shows a map of the affected area of this project.

29 Sensitivity Studies for 2012 The sensitivities that were proposed for analysis in 2012 are described below: 1. Further study of voltage stability issues and unsolved outages from the System Assessment: The unsolved outages listed in Attachment C of the 2012 System Assessment (CEII protected) required further investigation to determine the cause and mitigation of the failed solutions. Outages involving several areas of the system were investigated: Redmond-Bend area in Oregon. The Longview area in southwestern Washington. The McKenzie area in Wenatchee Washington. The Centralia area in southwestern Washington. The Shelton area in the Washington southeastern Olympic Peninsula. The Santiam area in Oregon. All unsolved outages were tested with the WECC post transient power flow solution methodology, which eliminated simulation of manual and slow automatic actions. Failed solutions are often caused by the modeled conditions exceeding voltage stability or angular stability solution limits. As a screening tool, the voltage threshold for voltage sensitive loads was set to 0.90 per unit voltage. During the power flow solution iterations, if the voltage at a load is below 0.90 per unit, the load is no longer constant power and it decreases with voltage. The decrease is nonlinear to facilitate the solution. With successful power flow solutions and QV analysis, potential mitigation was developed that could mitigate the voltage stability issues in these areas. For the Redmond-Bend area, breaker failures at Pilot Butte and the N-2 Pilot Butte Ponderosa 230 kv and Pilot Butte Redmond 230 kv outage can be mitigated with a new 150 MVAR SVC at Pilot Butte (although this N-2 outage will no longer be a credible outage with the new WECC adjacent circuit definition which excludes circuits less than 300 kv). Unsolved outages in the Longview area (Lexington and Cowlitz CCP 115 kv buses) were related to missing line drop compensation models. Once the model corrections were made, these outages proved to be stable. Voltage stability issues for the Cardwell 115 kv bus outage can be mitigated by constructing the South Cowlitz County Support which is a new 115 kv transmission line from Lewis River Substation, past Ariel Substation to Merwin Substation and adding 27 MVAR of switched shunt capacitors in the Woodland area. Issues in the Wenatchee area around McKenzie Substation were a result of improperly modeled post contingency generator voltage controls at Rock Island. No unsolved contingencies remained in the McKenzie area once the proper settings were applied. 24

30 25 In the Centralia area, the N-2 Paul Olympia 500 kv and Paul Satsop 500 kv outage results indicated voltage instability under heavy summer loading conditions. Investigation showed this instability was due to modeling issues in the Port Angeles/ Sappho area and low initial voltages and circulating reactive flows. The planned addition of shunt capacitors at Sappho should also help this issue. This system deficiency can be mitigated by adding a 35 MVAR SVC at Port Angeles. Voltage instability in heavy winter conditions due to Shelton breaker failures can also be mitigated by the same Port Angeles 35 MVAR SVC. In addition, the North of Fairmont Back Trip Scheme should address this issue. Instability in the Santiam area due to Santiam bus and breaker outages, as well as the Marion Alvey 500 kv and Marion Lane 500 kv double line outage, can be mitigated with a new 35 MVAR SVC at Tahkenich (along the coast near Florence, Oregon). There may also be local RAS that addresses this issue. In the five-year winter case, these outages were further aggravated by precontingency low voltages in the northern California area, which can be corrected by switching in existing capacitors and tuning transformer tap settings. 2. Impact of bypassing the Starwood transformer on the Tacoma 230 kv bus outage: As mentioned above, a bus section breaker outage at BPA s Tacoma s 230 kv Substation overloads several Puget Sound Energy and Tacoma Power facilities. BPA has plans to add a series bus section breaker to resolve this issue. Participants suggested that bypassing Tacoma Power s Starwood 115/110 kv transformer could also help mitigate this problem. This bypass project is being planned as part of the conversion of the areas 110 kv system to 115 kv. Winter and summer five year cases were run with the Starwood 115/110 kv transformer bypassed. The same full set of outages was run as the System Assessment. This new configuration did not cause any new overloads. In the summer, the four overloads that occurred for the Tacoma Bus section outage increased by about 3% with the transformer bypassed. In the winter, two overloads were caused by the bus section breaker outage, the Starwood transformer and the 115 kv White River- West Campus line. Bypassing the Starwood transformer would obviously eliminate the first overload. It also reduces the loading on the White River-Campus line to about 100%. The Bonneville project to add a series bus section breaker would still be needed to mitigate all of the deficiencies. Since the completion of the 2012 System Assessment, Puget has committed to this project and it is now included in the ColumbiaGrid Ten Year Plan. 3. Transmission Assessment of the Northwest Power Planning and Conservation Councils (NWPCC s) 6th Power Plan: Stakeholders have requested a sensitivity to test the transmission needs associated with the NWPCC s 6th Power Plan load and resource scenarios. The NWPCC provides a power plan for the region to use as a policy guide.

31 Figure F-1: Northern Mid-Columbia Preferred Plan 26 This analysis of the regional power plan will provide policy makers and stakeholders with information about the long-term transmission needs of the plan. This sensitivity study would be consistent with the regional transmission analysis promoted in FERC s recent Order 1000 related to transmission planning and cost allocation. To complete this analysis, ColumbiaGrid has been working with the Council and other stakeholders to acquire the necessary data inputs (e.g. specific resource locations) from the 6th Power Plan and initiate the work. As a result of this effort, it has been determined that the sensitivity study should be expanded to become part of the next planning cycle. Several scenarios will be studied rather than the single scenario planned for the sensitivity study. Three time frames are to be investigated; five, ten, and twenty years. Work on these scenarios has been initiated and the base assumptions for the next System Assessment cycle will be adjusted to be consistent with the NWPCC s 6th Power Plan. This work will be coordinated in regular ColumbiaGrid planning meetings rather than in a separate study team.

32 27 4. Mid-Columbia project assessment: Several transmission projects have been proposed for the Mid-Columbia area in recent years and these projects are in various stages of design and construction. This sensitivity was proposed to study the entire system in the area with the expected projects in service to verify that the planned projects are resolving the transmission problems in the area. A small study team was assembled to formulate a study plan for this sensitivity. Many of the proposed projects have been completed. The remaining plans in the area appear to be moving forward but each has its own timeline. The study group decided that the most important study that could be performed would be an operational study as the remaining projects are sequentially energized and added to the system. A Study Team has been formed to perform the necessary operation studies. 5. Transient Stability Studies using TEPPC 2022 Light Spring base case: Critical 500 kv breaker failures in the Northwest were simulated using switching data provided to ColumbiaGrid for the study. No performance issues were found with the approved case as posted on the WECC website. Path flows in the WECC approved case were less than the existing limits documented in the WECC Path Rating Catalog. A ColumbiaGrid modified case was prepared to explore potential issues with COI and PDCI at maximum north to south power flow. All simulations were found to be stable and damped. A side benefit of the study was the discovery of several errors in the WECC Master Dynamics File affecting present and future users. A WECC task force is now correcting these and other errors to improve accuracy of future transient stability simulations. 6. Natural Gas Generation Limitations: Natural gas supply infrastructure in the I-5 corridor is designed to meet electric utility loads during moderate to severe cold weather events. There is a significant amount of existing natural gas-fired generating capacity in the I-5 corridor. The scenario developed for this study is that the existing natural gas supply system has had a major outage such that natural gas to the Puget Sound area is severely limited. This gas supply disruption scenario was studied under an extended winter peak load event to study the potential impact to transmission system performance. Rather than a sensitivity study, this effort has been carried out in its own study team which was closely coordinated with the Pacific Northwest Utilities Conference Committee (PNUCC) and the Northwest Gas Association (NWGA). Necessary data on the natural gas system was gathered, a ColumbiaGrid Study Team was formed, and a reliability analysis of the electrical system was completed. A detailed study report is available on the ColumbiaGrid website (to be available by mid-2013).

33 Figure G-1: Other Potential Transmission s Potential Major Transmission s S everal large 28 projects assessment cases but the projects without have been proposed in the region firm commitments were not (since the I-5 to Corridor integrate accommodate transmission new economy resources transfers and project, Boardman-Hemingway to and Cascade Crossing are not expected to There are be completed until at least 2017, they were firm commitments by sponsors to build only included in the ten-year studies). This several of these projects; Big Eddy-Knight, approach avoids masking problems on the Hemingway-Boardman, Cascade Crossing, transmission systems that would need to be Montana-Alberta Transmission Line (MATL), addressed if the more speculative projects Central Ferry-Lower Monumental, Wallula- are not built. Analysis of impacts that these McNary and the I-5 Corridor Reinforcement. major projects might have on the load service These and firm transmission service commitments access lower cost resources. projects were included in the of the PEFA parties will be addressed later by

34 29 the appropriate ColumbiaGrid study teams. The other major projects in the region that do not have commitment to build are described below. See Figure G-1 for a map of these projects. If these projects are firmed up, they will be modeled in future system assessments. However, support for these projects has diminished over the last couple of years. These projects are electrically in parallel with ColumbiaGrid member facilities and could have impacts to the existing system. a. Horizon Phase II The Portland General Electric Horizon Phase II project consists of a new 230/115 kv bulk power transformer at Horizon Substation and a new 37-mile Horizon-Trojan 230 kv circuit. This project is the result of a merchant request and will provide the capacity needed to integrate 200 MW of proposed generation at the existing Port Westward plant. The target energization date for this project is December This project is currently on hold pending the outcome of the merchant request. b. Garrison-Ashe The 2010 BPA Network Open Season included several requests that could not be accommodated by the Colstrip Upgrade. To gain additional capacity to fulfill these requests, a 430 mile series compensated Garrison-Ashe 500 kv line was proposed with an intermediate station between Taft and Hot Springs. Due to the high cost of this project, BPA has not made any commitment to pursue this project. No WECC Regional Planning or Rating studies have been started. c. Canada-Pacific Northwest to Northern California The Canada-Pacific Northwest-California (CNC) is a 1000 mile transmission line from British Columbia to northern California that was sponsored by Avista, BC Hydro and Pacific Gas and Electric. The plan of service involves a 500 kv AC transmission line from Selkirk Substation to Devils Gap Substation to NEO (Northeast Oregon) Substation (Northern Segment) and a +/-500 kv DC transmission line from NEO Substation to the San Francisco Bay Area (Southern Segment). The project has a Planned Rating of 3000 MW in the north-to-south direction. Since developing this project, the sponsors have analyzed a scaled down, 2000 MW version of the project as their needs for renewable generation have changed. They also investigated aligning the Northern and Southern Segments of their project in a common corridor with existing facilities to reduce the s environmental impact. A study completed called the Pacific Northwest-California New Transmission Feasibility Assessment showed acceptable system performance for several options. An investigation was also made into the availability of existing capacity on COI in lieu of constructing the Southern Segment. This COI Utilization analysis indicated some unused transmission capacity from timeto-time, but such capacity would not be sufficient to meet the needs of the generation and load entities. These two reports were completed in April and May of 2011 and are available on the ColumbiaGrid website. The Sponsors have since put these projects on hold.

35 d. Northern Lights The Northern Lights project is a 970-mile high-voltage DC line (+/- 500 kv) beginning at Edmonton, Alberta and ending at a new substation near the existing Buckley Substation in north central Oregon. At least one intermediate terminal is planned in a location south of Calgary, near Alberta s largest wind development region. The project is planned to have bi-directional capacity as high as 3,000 MW. This project takes advantage of the diversities in load and generation between the two areas. The project is currently on hold. e. Juan de Fuca Cable #1 Sea Breeze Pacific is proposing an underwater 550 MW high-voltage DC +/- 150 kv cable across the Strait of Juan de Fuca from Pike Substation near Victoria on Vancouver Island Canada to the Port Angeles Substation in Port Angeles, Washington. This project rating is planned to be fully controllable and bi-directional. According to the Bonneville and BC Hydro interconnection studies completed to date, the project will also require existing system reinforcements, including 230 kv line upgrades from Satsop to Port Angeles Substations. This project was granted Phase 2 rating status on June 29, f. Juan de Fuca Cable #2 Sea Breeze Pacific is proposing a Multiterminal underwater 1,100 MW high-voltage DC cable (+/- 300 kv) across the Strait of Juan de Fuca from Ingledow Substation near Vancouver, British Columbia, Canada to Pike Substation near Victoria on Vancouver Island Canada, to either the Shelton or Olympia Substations on the Olympic Peninsula, Washington. The 1100 MW project rating is planned to be fully controllable and bi-directional. g. West Coast Cable Sea Breeze Pacific is proposing an underwater high-voltage DC cable from Allston Substation in northwest Oregon near Rainier to the San Francisco Bay area. This project has a planned rating of 1,600 MW. This project is intended to bring renewable resources from the Northwest to California. h. Green Line In conjunction with the MATL project, Enbridge is proposing the Green Line to provide access to the Mid-Columbia Hub. This project is a 100 mile extension of the MATL project to connect to the Colstrip Transmission system at Garrison or Townsend. This project is expected to provide up to 1000 MW capacity and is in the feasibility stage. i. Hemingway-Captain Jack Line PacifiCorp had proposed to build a new 375- mile 500 kv line from Hemingway Substation in the Boise area to Captain Jack Substation in southern Oregon. PacifiCorp is no longer pursuing this project. j. Mountain States Transmission Intertie NorthWestern Energy had been pursuing construction of the Mountain States Transmission Intertie (MSTI), a 500 kv singlecircuit electric transmission line that would begin about five miles south of Townsend, Montana and proceed south to Jerome, Idaho. This project was expected to add about 1500 MW to Path 18, the Montana to Idaho Intertie. Due to lack of sponsorship, this project is currently on hold. 30

36 Figure H1: Northwest to British Columbia Interfaces with Neighboring Regions 31 Oregon and Washington are electrically interconnected to Canada, Montana, Idaho, Nevada, and California. The historical use of these interconnections has been high and of benefit to the Northwest and others. Transmission service requests submitted to transmission owners and proposals for generation resources within and outside the Northwest suggest that demands on these interconnections in the future may exceed their present-day capabilities. The following sections discuss each of the major interfaces, recent historical usage, and potential projects to increase their capabilities. All of the interfaces with neighboring regions have been rated through the WECC Rating Process. Each diagram includes seven years of data, 2006 thru The light orange jagged line in the background shows the 2012 hourly flow data in chronological order from January through December (in MW). These chronological data show how the flows vary throughout the year. These same data and the data for 2006, 2007, 2008, 2009, 2010 and 2011 are also shown re-ordered and plotted from highest to lowest flow for each year. Annual changes and trends can be determined from these data. These charts can vary from year to year due to load levels, hydro conditions, market conditions, etc. 1. Northwest to British Columbia The Northwest to British Columbia path consists of two 500 kv lines (Ingledow-Custer

37 #1 & #2) and two 230 kv lines, Nelway- Boundary and Waneta-Boundary (which is normally open). The path is rated 3,150 MW north-to-south. The old south-to-north rating of this path was 2,000 MW but it was granted Phase 3 status for 3,000 MW in December, Port Angeles, Washington and associated system reinforcements is to export potential future wind generation development on Vancouver Island to the United States. Transfers into Canada from the Northwest are also possible. The sponsor is Sea Breeze Pacific. The historical loading on this path is shown in Figure H-1. As can be seen from the figure, this interface is used in both directions, although the predominant flow is south to north. Generally, the path flows are in the south-tonorth direction in the fall, winter and spring when the return of the downstream benefit of U.S. dams to Canada is the predominant influence. In the summer, Canada typically is exporting large amounts of power to the Northwest and California, and the flows are in the north-to-south direction. Depending on the relative generation development plans in the United States and Canada, increased utilization in either or both transfer directions could occur. In 2011 and 2012, the flows were more in the north to south direction than most other years which aligns with the good water years we experienced recently (good water years typically have more flows from British Columbia south to the NW and California). Juan de Fuca Cable #2 : This project is described in more detail in the Major Regional s section of this report. The intent of the proposed 1,100 MW undersea cable between Vancouver, British Columbia and either Shelton or Olympia Substations on the Olympic Peninsula and associated system reinforcements is to export potential future wind generation development in British Columbia to the United States. Transfers into Canada from the Northwest are also possible. The sponsor is Sea Breeze Pacific. Northern Lights : This project is described in more detail in the Major Transmission s section of this report. The intent of this proposed 3,000 MW DC transmission line from Alberta to Oregon is to export wind and other types of generation to the Northwest and also to import Northwest resources to Alberta. The sponsor is TransCanada. 32 Four projects are currently in the planning and/or permitting phase that could increase the capability of this interface. Juan de Fuca Cable #1 : This project is described in more detail in the Major Regional s section of this report. The intent of the proposed 550 MW undersea cable between Vancouver Island and The Canada-Pacific Northwest-Northern California Transmission Line : This project is described in more detail in the Major Transmission s section of this report. The project could add up to 3,000 MW of transmission capability between Canada, the Northwest, and California although smaller upgrades are also being contemplated. The primary purpose of the

38 33 Figure H-2: Montana to Northwest project is to provide California with access to Canadian renewable resources. The project also includes connections to the Northwest that will provide access to these same resources. 2. Montana to the Northwest The Montana to the Northwest path consists primarily of the Broadview-Garrison #1 and #2 500 kv lines. In addition, the path contains four 230 kv lines, three 115 kv lines, and a 230/161 kv transformer. The path has an east-to-west rating of 2,200 MW and a west-to-east rating of 1,350 MW. The historical loading on this path is shown in Figure H-2. As can be seen from the figure, this interface only reaches its maximum capability in the east-to-west direction, as the primary purpose of the path is to deliver major resources, such as the Colstrip Power Plant, to the Northwest. During peak load periods, the loading on this path can be lower in response to loads in Montana consuming more of the available resources. In 2011 and 2012, the path loadings were reduced from previous years. This is indicative of a good water year when the thermal resources in Montana are shut down to take advantage of the surplus hydro and coal generation was out of service due to more favorable gas prices. There are proposals for additional resources in Montana which indicate that the transmission loadings on this path are expected to increase in the future. In addition to the committed Colstrip Upgrade project, there is one other project in the planning phase to increase the transmission capability of this path. The Garrison-Ashe is a 430 mile series compensated Garrison-Ashe 500 kv line that is being discussed with an intermediate station between Taft and Hot Springs to integrate additional renewables in Montana. Other options include starting the line farther to the east at Broadview. 3. Idaho to the Northwest The Idaho to the Northwest path consists

39 of the Hemingway-Summer Lake 500 kv line, the Imnaha-Lolo 230 kv line, the Hells Canyon-Enterprise 230 kv line, the Quartz Tap-LaGrande 230 kv line, and the Hines- Harney 115 kv line. The path has an east-towest rating of 2,400 MW and a west-to-east rating of 1,200 MW. The historical loading on this path is shown in Figure H-3. As shown, this path generally delivers power to the Northwest during the fall and winter, and delivers Northwest power to Idaho during the spring and summer. In 2012 there was much more power flowing into Idaho than other years which is a result of abundant hydro and lower natural gas costs. In addition to the committed Boardman- Hemingway project, the Hemingway- Captain Jack 500 kv line project was proposed to increase capacity of this path but this project is not active at this time. This project included a 500 kv line starting near Boise and traversing to Captain Jack Substation near Klamath Falls, Oregon. It was proposed to increase transfer capability for new wind generation and other resources planned in Idaho, Wyoming and Montana. 4. Northwest to California There are two major connections between the Northwest and California: the California - Oregon Interties (COI) and the Pacific DC Intertie. The COI consists of the two Malin- Round Mountain 500 kv lines (the Pacific AC Intertie) and the Captain Jack-Olinda 500 kv line (the California-Oregon Transmission ). The COI is rated at 4,800 MW northto-south and 3,675 MW from south-to-north. The Pacific DC Intertie is a +/- 500 kv bipole DC line between The Dalles, Oregon and Los Angeles, California. The Pacific DC Intertie is rated 3,100 MW in both directions. The historical loading on these paths is shown in Figures H-4 and H-5. As shown, this interface frequently operates near its maximum capability in the north-to-south 34 Figure H-3: Idaho to Northwest

40 35 Figure H-4: California - Oregon Interties direction, but does not reach its capability in the south-to-north direction. Loadings are highest in the north to-south direction in the spring and summer when Northwest and Canadian generation is being delivered to loads in California. During the winter, flows tend to be in both directions. These loadings are usually in the south-to-north direction when northwest loads peak in the winter as California resources are used to help meet the peak load requirements. The flows in 2011 and 2012 were much higher than previous years indicating the new wind that is being exported to California and the better than normal hydro conditions. In addition, both nuclear units at San Onofre in Southern California were out of service for almost all of 2012 (and remain out until further notice) due to defects in the generator tubes. That removed over 2000 MW of baseload generation from the area which increased demand for imports on the PDCI and may have indirectly impacted COI flows. Bonneville has recently completed a California-Oregon Interties Upgrade that includes the addition of shunt and series capacitors to enable this interface to be utilized at its full capability more often. This project does not increase the existing rating but improves the availability of the full rating, which previously was rarely available to operations. This project was completed in A replacement of the Celilo terminals on the PDCI is also planned for This replacement will result in a slight upgrade from 3100 MW to 3220 MW. Two projects are currently in the planning phase to increase the capability between the Northwest and California. West Coast Cable : The intent of this proposed 1,600 MW undersea cable between Oregon and California is to export potential future wind development in the Northwest to California. The sponsor is Sea Breeze Pacific. This project starts at Allston Substation in northwest Oregon and extends

41 Figure H-5: Pacific DC Intertie to Newark Substation in the San Francisco Bay area. with access to Canadian and Northwest renewable resources. The Canada/Pacific Northwest to Northern California : As described previously, this project would add up to 3,000 MW of transmission capability between Canada, the Northwest, and California. The primary purpose of this project is to provide California 5. Northwest to Nevada (Alturas tie to Sierra): The Alturas line is a 300 MW bi-directional path between southern Oregon and the Reno, Nevada area and is typically used to transfer Northwest resources to Nevada. The historical flows are shown below in Figure H-6. There are no known plans to upgrade this path. 36 Figure H-6: Alturas

42 Figure I-1: North of John Day Internal Interfaces 37 The flows between the Northwest and other sub-regions in combination with the internal northwest generation and loads, determines the flow on the Northwest s internal transmission system. Several internal interfaces have been defined in critical areas for monitoring and operation of the system. These internal interfaces include North of John Day, South of Allston, West of McNary, West of Cascades North, West of Cascades South and West of Hatwai. All of these interfaces are WECC Rated Paths except West of McNary. This section discusses these interfaces, recent historical usage, and potential projects to increase their capabilities. 1. North of John Day The North of John Day path consists of six 500 kv lines; Raver-Paul, Wautoma-Ostrander, Wautoma-John Day, Ashe-Marion, Ashe- Slatt and Lower Monumental-McNary. This path shows the stress on the system in the lower Columbia area due to spill (when this generation is replaced by more remote generation, additional stress is placed on the system). This path helps determine the total export capability to California. The maximum rating of this path is 8400 MW. The flows on this path are shown in Figure I-1. This path loads most heavily in spring and summer when water is being spilled over the lower Columbia dams for fish migration and power is being exported to California. Its use is much reduced in fall and winter when spill is minimal and northwest resources are used to meet northwest loads. The flows in 2011 and 2012 were higher than normal due to the high hydro conditions and increased exports to California.

43 There are proposed projects that would upgrade this path or add capacity in parallel including: Bonneville s I-5 Corridor Reinforcement project (Castle Rock- Troutdale), TransCanada s Northern Lights and PG&E s Canada-Pacific Northwest to Northern California. The Big Eddy-Knight project could also provide capacity increases to this path when it is finished in South of Allston The South of Allston path consists of the Allston-Keeler 500 kv line, the Allston-Rainier 115 kv line, the Astoria Tap-Seaside 115 kv line, the Merwin-View 115 kv line, the Trojan-Rivergate 230 kv line, the Trojan- St Marys 230 kv line and the Woodland Tap-Ross 230 kv line. This path is rated at approximately 2,900 MW (the actual rating is determined by seasonal OTC studies and system conditions). This path is most limiting in summertime when exports to California are supplied with imports from Canada and west side gas resources. Flows on this path are much lower in other seasons. Recent loading on this path is shown in Figure I-2 and matches prior years. Bonneville s I-5 Corridor Reinforcement would substantially increase the capability of this path. Portland General Electric s Horizon Phase II could provide an increase in capability for the South of Allston path (south of Trojan). Figure I-2: South of Allston 38

44 Figure I-3: West of Cascades North West of Cascades North The West of Cascades North Path consists of the Chief Joseph-Monroe 500 kv line, the Schultz-Raver #1, #3, and #4 500 lines, the Chief Joe-Snohomish 345 kv #3 and #4 lines, the Rocky Reach-Maple Valley 345 kv line, the Coulee-Olympia 287 kv line, the Rocky Reach-White River 230 kv line, the Columbia-Covington 230 kv line and the Schultz-Echo Lake 500 kv line. This path is rated at 10,200 MW. This path is most limiting in the winter when temperatures are low and loads are high in the Northwest, especially if local west side generation is unavailable and/or exports to Canada are high. Loading on this path is typically not critical in other seasons. Recent loading on this path is shown in Figure I flows on this path were higher than in recent years which can indicate that temperatures were lower than normal. Proposed projects that would upgrade this path include Puget Sound Energy s IP Line uprate to 230 kv and Bonneville s series capacitors at Schultz. Several other options have been investigated by the Cross Cascades Study Team.

45 4. West of Cascades South This path consists of the Big Eddy-Ostrander 500 kv line, the Ashe-Marion 500 kv line, the Buckley-Marion 500 kv line, the Wautoma- Ostrander 500 kv line, the John Day-Marion 500 kv line, the McNary-Ross 345 kv line, the Big Eddy-McLoughlin 230 kv line, the Big Eddy-Chemawa 230 kv line, the Midway- North Bonneville 230 kv line, the McNary- Santiam 230 kv line, the Big Eddy-Troutdale 230 kv line and the Round Butte-Bethel 230 kv line. This path is rated at approximately 7,000 MW. This path is most limiting in the winter when temperatures are low and loads are high in the Northwest, especially if local west side generation is unavailable. Loading on this path is usually not critical in other seasons. Recent loading on this path is shown in Figure I-4. These annual flows have similar characteristics to the West of Cascades North Path. s proposed that would upgrade this path, or add parallel capacity, include Bonneville s Big Eddy-Knight project (which is part of the West of McNary Area Reinforcement) and Portland General Electric s Cascade Crossing. 40 Figure I-4: West of Cascades South

46 Old Rating Figure I-5: West of McNary West of McNary The West of McNary path consists of the following lines; Coyote-Slatt 500 kv line, McNary-Ross 345 kv line, McNary-Horse Heaven 230 kv line, the McNary-Boardman 230 kv line and the new McNary-John Day 500 kv line. The purpose of this path is to monitor the stress on the system when there is heavy generation in the McNary area and transfers to the west. The capacity of this path is now 4,500 MW (it was 2870 MW prior to the McNary-John Day.) The WECC Phase 1 rating process has been completed for this path. This path is most limiting in the spring of the year. Path flows typically recede under summer and winter conditions. Recent loading on this path is shown in Figure I-5. The much higher loading in 2012 reflects the project reinforcements and the additional wind being operated on the system. One proposed project that would add parallel capacity to this path is Portland General Electric s Cascade Crossing.

47 6. West of Hatwai The West of Hatwai path consists of the following lines; Hatwai - Lower Granite 500 kv, Bell - Coulee 230 kv #3 and #5, Westside Grand Coulee 230 kv, Dry Creek -Walla Walla 230 kv, Bell - Creston 115 kv, North Lewiston - Tucannon River 115 kv, Harrington Odessa 115 kv, Lind - Roxboro 115 kv, Dry Gulch 115/69 kv transformer and Bell Grand Coulee 500 kv lines. This path is rated at 4,277 MW. The purpose of this path is to measure the stress on the system when there is heavy generation in Montana and Northern Idaho and transfers through eastern Washington to the west. This path is most limiting in the spring of the year. Path flows are typically lower under summer and winter conditions. Recent loading on this path is shown in Figure I-6. The 2012 loading was lower than previous years and reflects the reduced flows from Montana. This project was recently upgraded with the Bell-Coulee 500 kv line and several other Avista line upgrades. A Garrison Ashe 500 kv line project has been identified in the BPA NOS process to meet additional transmission requests between Montana and the Northwest. The Colstrip Upgrade project discussed earlier would increase the capacity of the Montana to Northwest and West of Hatwai paths. Figure I-6: West of Hatwai 42

48 43 Study Assumptions and Methodology for the System Assessment The Northwest transmission grid is interconnected and, as a result, it was necessary for all Northwest entities to participate in the development of this Expansion Plan whether or not they are parties to the ColumbiaGrid PEFA. Major transmission owners in the Northwest were notified individually and encouraged to participate in the planning process. All participants who provided input to the study or helped to screen results had access to the same information whether or not they were parties to PEFA. The major assumptions that form the basis of the System Assessment are load, generation, external path flows, and planned transmission additions. These assumptions were used to develop the cases that were studied in the System Assessment. The approach used for developing each of these assumptions is summarized below. Base Case Development Standard five-year and ten-year base cases for winter peak load, summer peak load and light load conditions were used in the System Assessment. The five-year cases used were based on the recent heavy winter case HW2 and the heavy summer case 2017HS2. The ten-year winter case was based on 22HW1. A recent tenyear summer peak load case was not available and one was created by using the five-year summer case with loads increased to reflect expected load growth in the tenyear timeframe. Light load studies were run on 2022LS1-S which includes high renewable generation in the Western Interconnection and light summer loads. A different philosophy was used for resource assumptions in the System Assessment this year. In previous years, resources were modeled in the base cases based on firm commitments. Those assumptions have been tested for several years now. The actual system may encounter a variety of different dispatches depending upon load conditions, resource outages and possibly other factors. It was decided this year to use the resource dispatch that WECC used in each case with minimal modification to test other possible dispatches. Important interties, such as Canada to the NW and California Interties would still be loaded to their contractual limits. Some generation

49 changes were needed to obtain the desired intertie flows. These are discussed more fully below. All of the base case assumptions, such as the load levels and the transmission projects, were selected by the ColumbiaGrid Planning participants during open meetings. Corrections and updates to the transmission system were made to all of the cases to ensure consistency. Each case was analyzed under pre-outage and outage conditions and any deficient areas were noted and corrections or updates were made as appropriate. Load Modeling Assumptions As required in the NERC Reliability Standards, the transmission system is planned for expected peak load conditions. Normal summer and winter peak loads were based on a probability of 50 percent not to exceed the target load peak. As modeled in the base cases, the total winter peak load for the Northwest system is forecasted to be 32,913 MW in the fiveyear case (this is up from the 32,260 MW in the five-year case in last year s System Assessment) and 34,933 MW in the ten-year case. The forecast summer peak load is 26,268 MW in the five-year case (this is up from the 26,145 MW modeled in last year s case) and 27,450 MW in the ten-year case (27,535 MW was modeled in last year s tenyear case). The ten-year light summer case includes 18,852 MW of load in the Northwest. While the Northwest system as a whole peaks in the winter, this does not mean that summer conditions require less attention. The capacity of electrical equipment is often limited by high temperatures, which means the equipment has lower capacity in summer than in winter. As a result, it is possible that a lower summer load can be more limiting than a higher winter load due to the ambient temperature differences and the impact on equipment. Resource Modeling Assumptions Resource additions ten years into the future are much more difficult to forecast than loads. Although there are numerous potential generating projects in the region in various stages of development, there is much uncertainty for a variety of reasons about whether and when they will come into service. Many of the variables are outside the control of transmission providers. Adding to the complexity, these resource assumptions are particularly important. Depending upon their location, some resources can mask 44

50 45 transmission problems while others can create new problems. Previous System Assessments modeled the firm resource commitments on Northwest resources and this dispatch has been studied numerous times. There are many more feasible dispatches within these firm commitments levels that could impact the transmission system. WECC base cases are not developed with these firm commitments specifically modeled. To study other feasible dispatches, planning participants agreed that the System Assessment base cases would use the generation dispatch within each WECC base case to test other dispatches. Only changes to include known retirements and provide sufficient resources to load external paths to desired levels were made. These resource assumptions for each base case are listed in Attachment A. While the existing northwest resources are adequate to meet summer loads, they are not adequate to meet winter peak loads. Northwest utilities rely on seasonal diversity in resource needs with other regions to meet winter load obligations by importing from California and the Southwest. For this reason, imports into the Northwest from California were used to meet the shortfall of new resource additions in the Northwest. However, there are many indicators, such as the number of requests for interconnection that transmission providers have received, to suggest that other resources will be developed in the region during this ten-year planning horizon. The addition of proposed generation projects, especially thermal projects on the west-side of the Cascades, could have a significant impact on the performance of the transmission system and reduce the reliance on California imports that was assumed in the winter cases. Planned transmission projects will be reviewed periodically to determine whether changes in resource additions would impact the need for, or scope of, these projects. Two generation retirements were included in the assessment. The state of Washington has come to an agreement with the owner of the Centralia Power Plant that one 700 MW coal-fired unit will be retired in 2020 and the second unit in To match these system conditions, the base cases were run with one unit on (transmission impacts of the retirement of both units was studied in 2011 and this study report is posted on the ColumbiaGrid website). The state of Oregon has reached agreement with Portland General Electric to retire the Boardman

51 Coal Power Plant in Portland General Electric plans to replace the coal generation with gas-fired generation and these changes for Boardman are modeled in the ten-year cases. There is a significant amount of new wind generation proposed in the ColumbiaGrid footprint. Figure E-2 shows the existing wind resources, along with projects under construction as of June 2012 and June The development of new wind projects has slowed. The sum of the wind projects in service plus the wind projects that are under construction is similar to the previous year especially in Oregon and Washington. However, more of this generation is now in service and less is in the construction phase. Although there are several thousand MWs of wind generation in the Northwest, none is usually modeled during peak load conditions in the System Assessment. Historical operation has shown there is often little wind generation during either winter or summer peak load conditions. Operation without wind generation results in increased reliance on local gas generation and/or increased imports from California and the southwest. The light summer base case used this year has significant wind generation in operation. This is typical operation since wind generation is usually highest during off peak conditions. This case will be used to investigate transmission problems that may occur for these types of conditions. Also, in the sensitivity studies run for the System Assessment, several combinations of plausible wind generation scenarios were modeled. These studies are described more fully in the study results section. To balance the load and generation in the Northwest, ColumbiaGrid assumed 1498 MW was imported into the Northwest from California over the California-Oregon and Pacific DC Interties in the five-year winter study. For the ten-year winter study, ColumbiaGrid assumed 2,088 MW was imported into the Northwest on the combined Interties. A list of all the resources used in the base cases is included in Attachment A. Transmission Modeling Assumptions As required by the NERC Reliability Standards and PEFA, it was necessary to model firm transmission service commitments in the System Assessment. PEFA requires that plans be developed to address any projected inability of the PEFA planning parties systems to serve the existing long-term firm transmission service commitments during the planning horizon, consistent with the planning criteria. The NERC Reliability Standards do not allow any loss of demand or curtailed firm transfers for Level B contingencies (single elements) and allow only planned and controlled loss of demand or curtailment of firm transfers for Level C contingencies (multiple elements). The ColumbiaGrid planning process assumes that all ColumbiaGrid members transmission service and native load customer obligations represented in WECC and ColumbiaGrid base cases are firm, unless specifically identified otherwise (such as interruptible loads). 46

52 Base Case Summary (MWs) 5-Year Summer 5-Year Winter 2017HS HW2 10-Year Summer 2017HS2 with 2022 loads 10-Year Winter 10-Year Light Summer 22HW1 2022LS1-S Total Northwest Load 26,268 32,913 27,450 34,933 18,852 Total Northwest Generation 32,439 32,517 33,165 34,001 24,497 Northwest - British Columbia Flow -1,499 1,498-2,102/-199 1,499-2,301/0 Idaho - Northwest Path Flow Montana - Northwest Path Flow , ,386 1,727 North of John Day Path Flow 7,478 1,530 8,117 1,076 4,611 California-Oregon Interties Path 4, ,807-1,368 4,670 Flow Pacific DC Intertie (PDCI) Path Flow 3, , ,106 South of Allston Path Flow 2, , West of Cascades North Path Flow 4,653 9,136 4,743 8,947 3,367 West of Cascades South Path Flow 4,150 6,701 4,340 7,148 3,251 West of Hatwai Path Flow 1, ,246 Table J-1: Base Case Summary 47 The firm transmission service commitments between the Northwest and areas outside the Northwest are scheduled on specific transmission paths (e.g., British Columbia- Northwest, California-Oregon Interties, and Pacific DC Intertie). The other external paths (Montana-Northwest and Idaho- Northwest) were modeled at loading levels used in the original WECC base cases but as it turns out, loading on these paths is similar to their known firm transmission service commitments. Of the external paths, the British Columbia- Northwest and the two California Interties are most crucial during peak load conditions. These paths are bi-directional and there are often different stresses during winter and summer conditions. The Montana- Northwest and Idaho-Northwest paths are stressed more during off-peak load conditions and are less important during peak load conditions. The adequacy of these latter paths is verified annually through operational and light load studies. Conversely, the transmission paths internal to the Northwest are not scheduled. The flows on internal paths are a result of flows on the external paths, internal resource dispatch, internal load level, and the transmission facilities that are in service. During the winter, returning the firm Canadian Entitlement to British Columbia is the predominant stress on the Puget Sound area and the British Columbia-Northwest path. In the winter, the California interties were used to balance the load and generation modeled in the studies. This results in moderate imports which is not uncommon in winter.

53 In the summer, transfers on the British Columbia-Northwest and California Interties are typically in the opposite direction as in winter. Surplus power resources from Canada and the Northwest are often sent south to California and the Southwest. The path flows in the System Assessment were within their limits. The West of Hatwai and West of McNary flows are quite low in these cases but that is expected, as these paths typically experience stress only during off-peak conditions. of firm transmission service commitments are projected for the ten-year studies. Puget Sound Energy also has a 200 MW share at full transfer capability into British Columbia, which translates to a 130 MW allocation at the 1,350 MW level. Bonneville has committed to maintaining this pro-rata share of the Northern Intertie above its firm transmission service commitments. Both of these firm transmission service commitments are on the west-side of the path so 1,500 MW of transfers are modeled in the south to north direction in winter. The path flows modeled in the System Assessment are shown in Table J-1. The background for the specific existing firm transmission service commitments on members paths that were modeled in the Transmission Expansion Plan is as follows: With reduced loads in the Puget Sound area in the summer, the return of the Canadian Entitlement is not typically a problem. The most significant stressed condition in the summer is north to south flows of Canadian resources to meet loads south of the border. 1. Canada to Northwest Path The capacity of this path in the north to south direction is 2,850 MW on the west-side and 400 MW on the east-side with a combined total transfer capability limit of 3,150 MW. The total capacity of the path in the south to north direction is 2,000 MW, with a limit of 400 MW on the east-side. The south to north rating of 3000 MW was granted Phase 3 status in December Both of these directional flows can impact the ability of the system to serve loads in the Puget Sound area. The Canadian Entitlement return is the predominant south to north commitment on this path and is critical during winter conditions. Although the total amount of commitment varies somewhat, 1,350 MW Powerex has long-term firm rights for about 242 MW for their Skagit contract, plus 193 MW to Big Eddy and 450 MW to John Day, for a total of 885 MW in the north to-south direction. Powerex also owns 200 MW of transmission rights for the Cherry Point which is just south of the Canadian border and can be reassigned to the border. Puget Sound Energy has long-term firm contracts for 150 MW and Snohomish has firm contracts for 100 MW. The total of all of these contracts is 1,335 MW. The Puget Sound Area Study Team has been planning the system in the Puget Sound area to maintain 1,500 MW in the north to south direction to cover these firm transfers. The System Assessment was completed consistent with this requirement by modeling 48

54 49 1,500 MW on the west-side of the Northern Intertie (and no flow on the east side portion of this path) for the five-year cases. Bonneville is making commitments to increase the firm transactions to 2,300 MW through the Network Open Season that will show up in the ten-year time frame. 200 MW of this new commitment is planned to be scheduled on the east side of the Northern Intertie at Nelway. Therefore in the ten-year summer cases this flow will increase to 2300 MW to cover the additional commitments that are being made on the Northern Intertie including the 200 MW on the east side of the tie at Nelway. Path rating studies have been completed to upgrade the south-to-north rating of this path to 3,000 MW. 2. Montana to Northwest Path This path is rated at 2,200 MW east to west and 1,350 MW west to east. The predominant flow direction is east to west. The path can only reach its east to west rating during light load conditions. Imports into Montana usually only occur when the Colstrip Power Plant facilities are out of service. The firm commitments on this path exceed 1,400 MW east to west. There are also some counter-schedules that reduce the actual flows on the system. For the five-year studies, flow was modeled as 1,395 MW in normal winter and 1,642 MW in summer. Flows are similar in the outer-year cases. Flows are highest in the ten-year light load case at 1,727 MW. 3. Northwest to California/Nevada Path The combined COI and Pacific DC Intertie are rated at 7,900 MW in the north to south direction, although the combined operating limit can be lower due to the North of John Day nomogram. The COI is individually rated at 4,800 MW and the Pacific DC Intertie is rated at 3,100 MW. The 300 MW Alturas tie from Southern Oregon into Nevada utilizes a portion of the 4,800 MW COI capacity. In the south to north direction, the COI is rated at 3,675 MW and the Pacific DC Intertie is rated at 3,100 MW. Bonneville has constructed upgrades to these paths to increase the potential to use these paths at their full capability. With these upgrades, the long-term firm transmission service commitments on these paths are increasing to total about 7,700 MW. To cover these commitments, these two interties were loaded close to their combined limit of 7,900 MW in the summer cases used in the System Assessment. Bonneville is also planning a major equipment replacement at the Celilo terminal of the Pacific DC Intertie to replace the aging equipment there. These replacements are planned for 2016 at which time the rating of the PDCI will increase from 3,100 MW to 3,220 MW. There are some firm transmission service commitments on this path in the south tonorth direction but not a significant amount. Non-firm sales are relied on by many parties in the winter, especially during very cold weather, when there are insufficient resources within the Northwest to meet the

55 load level. For the base cases, Northwest resources were dispatched first, and firm transmission service commitments were modeled on external paths. Additional resources needed to meet the remaining load obligations in the Northwest were imported from the south, split between the COI and Pacific DC Intertie. In the five-year heavy winter base case, the imports into the Northwest totaled 1,498 MW with 536 MW on the COI and 962 MW on the PDCI. The ten-year winter case has a total of 2,088 MW import on the combined COI and PDCI paths. In the five-year and both ten-year summer cases (peak and light load), the combined exports were modeled very close to 7,900 MW, the full rating of the two interties. 4. Idaho to Northwest Path The Idaho to Northwest path is rated at 2,400 MW east to west and 1,200 MW west to east. This path has about 300 MW of firm schedules into Idaho to meet firm transfer loads, in addition to a 100 MW point-to-point service contract. Summer conditions with flows at these levels are typical as there are few surplus resources to export from the east. In the winter, these transfer loads are reduced and PacifiCorp typically exports its east-side resources into the Northwest to meet its westside load obligations. Due to the nature of the flows from Idaho, they are not expected to cause significant system problems in the Northwest during peak load periods. With the addition of the Hemingway-Boardman project, the rating of this path is expected to increase to 800 MW in the east to west direction and 1,300 MW west to east (this east to west rating is expected to increase to 1400 MW with the stage one of the Gateway West ). 50

56 Ten-Year Winter Base Case Conditions 51 Figure J-1: Ten Year Heavy Winter Base Case Conditions For the fi ve-year winter cases, 511 MW is modeled fl owing into the Northwest. In summer, 135 MW was modeled. Flows were slightly higher in the respective ten-year cases. The ten-year light load case had 725 MW fl owing into Idaho. path is loaded to 1,132 MW in the summer and 695 MW in winter. In the outer-year cases, the path is loaded to 1,227 MW in the summer and 604 MW in winter. In the tenyear light load case with high wind, the West of Hatwai path is loaded to 1,246 MW. 5. West of Hatwai Path The West of Hatwai path is rated at 4,277 MW in the east to west direction but it is not a scheduled path. This path is stressed most during light-load conditions when eastern loads are down and the excess resources from the east fl ow into Washington. This 6. West of Cascades North and South Paths The West of Cascades North path is rated at 10,200 MW and the West of Cascades South path is rated at 7,000 MW, both in the east to west direction (the South path rating is expected to increase to about 8,500 MW with the Cascade Crossing ). These

57 Ten-Year Heavy Summer Base Case Conditions Figure J-2: Ten-Year Heavy Summer Base Case Conditions 52 paths are not scheduled paths but transfer east-side resources to the west-side loads. These paths are most stressed during winter load conditions, especially when westside generation is low. The north path was loaded to 4,653 MW in the fi ve-year summer base case and 9,136 MW in the winter base case. These loadings are 4,743 MW and 8,947 MW, respectively, in the outer-year cases. The south path was loaded to 4,150 MW in the summer base case and 6,703 MW in the winter base case. These loadings are 4,340 MW and 7,148 MW, respectively, in the out-year cases. The increased loading on the South path and the reduced loading of the North path in the winter cases is due to the addition of the Cascade Crossing project which reinforces the southern path. For the light load case, the north path is loaded to 3,367 MW and the south path is loaded to 4,633 MW. Flow Diagrams The loads, generation and fl ows modeled in the base cases are shown in Figures J-1, J-2, J-3, J-4 and J-5. The Seattle-Tacoma area includes the area west of the cascades from the Canadian border south through

58 Ten-Year Light Summer Base Case Conditions 53 Figure J-3: Ten-Year Light Summer Base Case Conditions Tacoma. The Longview/Centralia bubble includes the areas south of Tacoma through Longview and west to include the Olympic Peninsula. The Portland/ Eugene area includes the Willamette Valley and Vancouver, Washington area. The Southern/Central Oregon bubble includes the Roseburg area down to the California border and east to the Bend-Redmond area. The Mid-Columbia Area includes load in the Washington area east of the Cascades, west of Spokane, south of the Canadian border and north of the Columbia River. The Lower Columbia bubble includes loads to the south of Mid-Columbia to Central Oregon. The Spokane area includes loads to the east in Western Montana, north to the Canadian border and south to the Oregon border. The Lower Snake bubble includes the major generation in the area. Figures J-1 and J-2 show the ten-year peak winter and summer conditions. Figure J-3 shows the ten-year light load summer conditions. Figures J-4 and J-5 show the fi ve-year peak winter and summer conditions.

59 Five-Year Heavy Winter Base Case Conditions Figure J-4: Five-Year Heavy Winter Base Case Conditions 54 The red circles in the fi gures represent the load levels in the identifi ed areas; the load level is proportional to the area of the circle. The two major west-side load areas, Seattle/ Tacoma and Portland/Eugene, each have approximately 10,000 MW of load in the tenyear peak winter case as shown in Figure J-1. The area of the green circles represents the amount of generation in that area. The Seattle/Tacoma and Portland/Eugene load areas have more load than generation and rely on other areas to supply the load resource balance. The Mid-Columbia, Lower Columbia and Lower Snake areas have surplus generation that is used in other areas. The Mid-Columbia area has about 11,000 to 12,000 MW of generation represented in the peak load cases. The load/resource ratios in the Spokane, Central/Southern Oregon and Longview/Centralia areas have greater balance. The dark blue lines between the areas represent the major transmission paths that connect the areas. The width of the dark blue lines represents the relative capacity

60 Five-Year Heavy Summer Base Case Conditions 55 Figure J-5: Five-Year Heavy Summer Base Case Conditions of the paths. For example, the West of Cascades North path is rated at 10,200 MW. The light blue lines within these paths represent the capacity that is used in the studies. In the winter cases, the West of Cascades paths are heavily used to meet the load levels in the west-side areas while the North of John Day and West of Hatwai paths are lightly loaded. The external path to Canada is loaded to the fi rm obligations on the path as discussed earlier which is mostly the downstream benefi t return. Power is imported from California to provide overall load resource balance in the northwest in the winter. The ten-year peak summer conditions modeled in the base cases are shown in Figure J-2. The load levels are typically lower in summer than in winter in the west-side areas, and are shown here with proportionally smaller bubbles. Also note that the Portland/Eugene area load level is greater than Seattle/Tacoma in the summer. These two areas had similar load levels in the winter case. This difference is due to

61 a greater use of air conditioning. The Mid- Columbia and Lower Columbia areas have higher levels of generation in the summer as compared to the winter. The path usage levels change significantly between summer and winter. In the summer, Canadian hydro generation exceeds the internal loads in British Columbia and excess generation is exported to the northwest and California. The northwest load levels are also lower in summer and there are available resources to export to the south. All of the north-to-south paths load much heavier in the summer due to these flows. The interties to California are loaded to their limit in the summer peak cases to represent the firm commitments on those paths. The loading on the west of Cascades paths is reduced in summer due to the reduced load level in the west-side. The ties to Idaho are mostly floating with little power moving on that path. The pattern modeled in the light summer, high wind case is unique for that condition. The cross cascades flows are even lighter than the summer cases described above due to the reduced westside load. The majority of the NW wind is located in the Gorge which is within the Lower Columbia bubble. During this high wind condition, the generation in the Mid-Columbia area is reduced significantly to accommodate the high wind level. The north to south flow is still high. Special Protection System Assumptions At the transfer levels modeled in the base cases, existing Special Protection Systems may be required for reliable operation of the transmission system. Some of these Special Protection Systems will effectuate tripping or ramping of generation (some of which have firm transmission rights) for specified single and double line outages. This Special Protection System generation dropping relies on the use of operating reserves to meet firm transfer requirements (no schedule adjustments are made until the next scheduling period and no firm transfers are curtailed). If the outages are permanent, firm transfers might then need to be curtailed during the next scheduling period to meet the new operating conditions. Firm transmission service commitments are met with this use of Special Protection Systems consistent with NERC and WECC standards. Transmission Additions Modeled Since the 2011 System Assessment, the following projects have been placed in service: 1. The Ostrander 500/230 kv transformer was added to replace the McLoughlin transformer. 2. The Longview-Cowlitz #2 line was upgraded from 69 kv to 115 kv. 3. The Keeler-Horizon 230 kv line was added with a 230/115 kv transformer at Horizon. 4. The California-Oregon Intertie Upgrades were completed All of these transmission additions were modeled in the base cases used in the 2012 System Assessment. 56

62 Table J-2: Transmission s Included in the Base Cases Name Sponsor Date Moscow 230 kv Substation Rebuild and Transformer Replacement Avista 2012 Benton-Othello 115 kv Line Upgrade Avista 2013 Westside 230 kv Rebuild and Transformer Upgrades Avista 2014 Irwin - Spokane Valley Transmission Reinforcements Avista 2013 Lancaster Combustion Turbine Integrations Avista 2013 Bronx - Cabinet 115 kv Line Rebuild Avista 2015 Big Eddy - Knight 500 kv line connecting to the existing Wautoma-Ostrander 500 kv line at the new Knight Substation Bonneville Power 2014 Central Ferry - Lower Monumental 500 kv line and connection to existing Lower Granite - Lower Monumental 500 kv lines at the new Central Ferry Substation Bonneville Power 2014 Ponderosa 500/230 kv #2 Transformer Addition Bonneville Power 2013 Ostrander Breaker addition Bonneville Power/PGE 2014 Lower Valley Reinforcement Bonneville Power 2014 Double breaker, double bus at Pearl 500 kv Substation Bonneville Power 2014 Montana to Washington (Garrison West) Bonneville Power 2015 Monroe Substation 500 kv Caps Bonneville Power Columbia Falls 230 and 115 kv Bus Relieability Improvements Bonneville Power Hatwai 230 kv Bus Reliability Improvements Bonneville Power 2015 Port Angeles 230 kv Bus and 230/69 kv Transformer or non-wires project Bonneville Power 2014 Keeler 230 kv Bus Reliability Improvements Bonneville Power 2014 Raver 500/230 kv Transformer, 230 kv line to Covington Bonneville Power 2016 Longview - Lexington 230 kv Line Retermination into Longview Annex Bonneville Power 2015 Extend Northern Intertie RAS for the combined loss of Monroe-SnoKing-Echo Lake and Chief Joseph-Monroe 500 kv lines Bonneville Power 2015 Rerating of Andrew York - McKenzie 115 kv #1 and #2 lines Chelan County PUD 2013 Longview - Lexington #2 upgrade from 69 kv to 115 kv Cowlitz County PUD Longview - Lexington - Cardwell upgrade from 69 kv to 115 kv Cowlitz County PUD Douglas - Rapids 230 kv line and Rapids 230/115 kv Substation Douglas County PUD 2013 Rapids - Columbia 230 kv line (Mid-Columbia area) Douglas County PUD 2015 Columbia - Larson 230 kv line Grant County PUD 2014 Rocky Ford - Dover 115 kv line Grant County PUD 2016 Wanapum - Pomona Heights 230 kv line (Yakima area) PacifiCorp 2013 Whetstone 230/115 kv Substation in Medford area PacifiCorp 2014 Union Gap 230/115 kv transformer #3 in Yakima area PacifiCorp 2013 Alderton 230/115 kv Transformer in Pierce County Puget Sound Energy 2014 St Clair 230/115 kv Transformer in Thurston County Transformer Puget Sound Energy 2013 Rebuild Sammamish-Lakeside-Talbot 115 kv lines and energize one at 230 kv, install a new 230/115 kv Transformer at Lakeside Puget Sound Energy Sedro Woolley Substation 230/115 kv Transformer addition (#2) in north Puget Sound area Puget Sound Energy 2012 Sammamish Bus Reliability Improvements Puget Sound Energy 2012 Woodland - St Clair 115 kv Line Puget Sound Energy 2015 Sedro Woolley-Bellingham #4 115 kv Double Circuit Line Puget Sound Energy 2015 Talbot 230 kv Bus Improvements Puget Sound Energy Reconductor Bothell - SnoKing 230 kv Double Circuit Line Seattle City Light/BPA 2016 Series Inductors to Broad Street - Union - Massachusetts and Broad Street - Denny 115 kv Underground Cables Seattle City Light 2016 Reconductor Delridge - Duwamish 230 kv Line Seattle City Light 2016

63 Name Sponsor Date Denny Substation (previously NODO Substation) - Phase 1 Seattle City Light 2016 Beverly Park Substation 230/115 kv Transformer addition (North Puget Sound) Snohomish County PUD Beverly Park and South Snohomish County 115 kv Expansion Snohomish County PUD 2014 Cowlitz 230 kv Line Retermination Tacoma Power Cowlitz 230 kv Substation Reliability Improvement Tacoma Power Southwest 230 kv Substation Reliability Improvement Tacoma Power Montana Alberta Tie Ltd Enbridge s added only in Ten Year Base Cases Celilo Terminal Replacement (PDCI Upgrade to 3220 MW) Bonneville Power 2016 Castle Rock - Troutdale 500 kv line (I-5 Corridor Reinforcement ) connected to the Paul - Allston line at the new Castle Rock Substation. Bonneville Power Hemingway - Boardman 500 kv line Idaho Power/BPA/PAC 2016 Blue Lake - Gresham 230 kv line Portland General Electric 2017 Cascade Crossing (Coyote - Boardman - Bethel 500kV line) Portland General Electric 2017 Second Portal Way 230/115 kv Transformer and Line Upgrades Puget Sound Energy/BPA Upgrade Denny Substation Transmission - Phase 2 Seattle City Light 2019 Table J-2 lists the future projects that were included in the System Assessment. These projects are more fully described in Attachment B entitled Transmission Expansion s. Several of the larger projects that were included in the base cases are discussed below: Major Additions in the Five-Year Case West of McNary Area Reinforcement This Bonneville project includes two new lines (McNary-John Day 500 kv line and a Big Eddy-Knight 500 kv line) and miscellaneous upgrades. These projects in their entirety include about 110 miles of new line construction and are proposed to increase the capacity of the West of McNary, West of Slatt, West of John Day and West of Cascades South transmission paths. This would provide additional transmission capability to accommodate transmission service requests in eastern Oregon that are being addressed in the Bonneville Network Open Season process. The McNary-John Day line has been completed and energized. The Big Eddy-Knight line is expected to be completed in 2014 pending cultural resource and land review. Central Ferry - Lower Monumental 500 kv line This Bonneville project has been proposed to integrate wind generation projects into the system. The new Central Ferry Substation is located between Little Goose and Lower Monumental Dams. The project would add a new forty-mile 500 kv line from this new substation to Lower Monumental Substation. It is planned to be completed in 2014 pending environmental review. This project is currently on hold pending review of the transmission requests that precipitated this project. 58

64 59 Montana Alberta Tie Line Enbridge is constructing the Montana Alberta Tie-Line (MATL) project that is a 200 mile, 300 MW, 230 kv line connecting Lethbridge, Alberta and Great Falls, Montana going through Cutbank, Montana which has significant wind generation potential. This project is fully permitted with construction underway and energization expected in The WECC rating process for this line has been completed (it has a Phase 3 rating of 325 MW in the north to south direction and 300 MW south to north). Mid-Columbia Area Reinforcements The plan for the Northern Mid-C area that has been developed in the ColumbiaGrid Northern Mid-C Study Team was included. It includes a Grant County PUD Columbia- Larson 230 kv line; the Douglas PUD Douglas- Rapids-Columbia 230 kv line, Rapids Substation and a 230/115 kv transformer; and upgrades to the Chelan County PUD s McKenzie-Wenatchee Tap line and line re-terminations at Chelan s Andrew York Substation. These projects are planned to be energized by 2015 or before. Cost allocation for the Rapids-Columbia 230 kv line has been agreed to by the impacted parties and Douglas is proceeding with construction of this project. Denny Substation Phase 1 Phase 1 of the Denny Substation project creates a new 115/13 kv Denny Substation looped into the East Pine Broad Street 115 kv underground cable. Load would be transferred to this substation from Broad Street Substation. Puget Sound Area Transmission Expansion Plan Reinforcements Six of the recommended projects in the expansion plan developed in the Puget Sound Area Study Team are planned to be energized by 2017 or before. These projects include: 1. reconductoring the Bothell SnoKing 230 kv double circuit line, 2. reconductoring the Delridge Duwamish 230 kv line, 3. installing a Raver 500/230 kv transformer and, utilizing an existing line, creating a Raver-Covington 230 kv line,

65 4. extending the NI RAS to include the combined loss of Monroe-SnoKing-Echo Lake and Chief Joseph-Monroe 500 kv lines, 5. rebuilding both Sammamish-Lakeside- Talbot 115 kv lines to 230 kv (initially operating one line at 230 kv and the other at 115 kv) and installing a Lakeside 230/115 kv Substation, and 6. adding series inductors to the Massachusetts-Union-Broad Street and Broad Street Denny 115 kv underground cables. These projects support south to north transfer capability on the northern intertie and load service reliability in the Puget Sound Area. Cost allocation for these projects has been agreed to by the impacted parties and they are proceeding with the projects. Ponderosa Reinforcements Bonneville and PacifiCorp have developed a plan to provide additional transformation in the Bend/Redmond area with a transformer added at Ponderosa connected to the Grizzly-Captain Jack 500 kv line. This project is planned for a 2013 energization. horizon. These additional projects were only included in the ten-year cases and are listed below: Hemingway - Boardman 500 kv This Idaho Power project includes a 300- mile 500 kv line from the Boise Idaho area to Boardman Substation. This project is intended to provide 1,300 MW of capacity in the west to east directions and 800 MW in the east to west direction. This project is expected to be completed by This project has recently been granted Phase 3 status in the WECC rating process. When this project is complete, the Idaho to Northwest path will have a combined rating of 2,250 MW in the west to east direction and 3,400 MW in the east to west direction. I-5 Corridor Reinforcement This Bonneville project consists of a mile 500 kv line from a new Castle Rock Substation north of Longview to Troutdale Substation east of Portland. The project is scheduled to be energized in the 2016 to 2018 timeframe and is planned to remove the most limiting bottleneck along the I-5 corridor, the South of Allston Cutplane. 60 The above projects were included in all System Assessment base cases. Major Additions in the Ten-year cases The ten-year System Assessment cases also included some additional projects beyond those in the five-year cases. There were a few projects that utilities have committed to build, however, due to significant lead times they are not expected to be completed until the latter part of the ten-year planning Cascade Crossing The PGE Cascade Crossing is a 200-mile 500 kv line starting at the Coyote Springs Generation Plant and terminating into a new 500/230 kv transformer at Bethel Substation. This line will also interconnect at a new Grassland Substation connecting to the Boardman Power Plant and a new Cedar Spring Substation approximately 26 miles southwest of Boardman where it interconnects with new wind generation. The proposed rating of the initial project is 1,500

66 61 MW and it is scheduled for energization in The WECC Phase 1 rating process has been completed. This project was modeled in the 2012 System Assessment. PacifiCorp and Bonneville have partnered with PGE to study this project. Once the final plan of service is determined for this project, the WECC Phase 2 rating process will resume. BPA and PGE have recently signed a nonbinding Memorandum of Understanding to explore and evaluate a proposed change to PGE s proposed Cascade Crossing Transmission. Under the new option being explored, PGE would build Cascade Crossing beginning at Boardman, as originally proposed, but would terminate the dual circuit, 500 kv transmission line at a new substation near Maupin, Oregon, called Pine Grove. This option would eliminate a substantial number of miles of new construction from the project. The new option also proposes that PGE would invest in several enhancements to BPA s system that could increase transmission capacity, reduce congestion and enhance reliability of the region s grid. In return, PGE could receive up to 2,600 MW of transmission capacity rights from BPA. This modified project will be explored in the 2013 System Assessment. Blue Lake-Gresham The Portland General Electric Blue Lake- Gresham project is planned for 2017 in east Portland and consists of a new 4 mile 230 kv line. Portal Way 230/115 kv Transformer Puget Sound Energy and BPA are planning to add a second 230/115 kv transformer at Portal Way in the Bellingham, Washington area. This project is part of the Puget Sound Area Transmission Expansion Plan and is planned to be energized in 2015 or The project will help improve north to south transfer capability on the Northern Intertie. Denny Substation Phase 2 Seattle City Light is planning the second phase of the Denny Substation project for This project expands on phase 1 of the Denny Substation project, adding a new 115 kv transmission line from Massachusetts Substation to Denny Substation. Celilo/PDCI Replacement/Upgrade This Bonneville project will replace the aging equipment at the northern Celilo terminal of the PDCI (the southern terminal at Sylmar has already been replaced). This project is planned to be completed in 2016 and will increase the capacity of the PDCI from 3,100 MW to 3,220 MW. All transmission facility ratings included in this study were determined by the owner of the facility. ColumbiaGrid conducted a study team analysis of the Cross Cascades North transmission which is posted on the ColumbiaGrid website. This report compared system expansion alternatives to increase the West of Cascades North interface voltage stability limit and specified that the next steps should include addressing the conditions that trigger the need for system expansion and the prerequisite projects outside of the West of Cascades North interface. Although these additions are expected to be needed around the end of the ten-year planning horizon, none of these additions were included in the base case models.

67 Study Methodology The system was analyzed for all base cases without outages (N-0 conditions) and tuned to be within required voltage limits. Any voltage violations or facility overloads that could not be resolved through this tuning were noted. All single element (N-1 or NERC Category B) outages down to 115 kv were studied on each base case (at PGE s and PacifiCorp s request; only outages at voltages greater than or equal to 230 kv were studied). Participants in the System Assessment provided ColumbiaGrid with information on the multiple contingencies that they wanted to be studied. These included common mode outages, which are plausible outages of multiple facilities caused by a single event, also called Category C events. These common-mode outages are listed in Attachment C (CEII protected and available upon request). Included in this System Assessment were inadvertent breaker openings, which are especially important on multi-terminal lines. The System Assessment also included known automatic and manual actions associated with each contingency. Loadings greater than 98% were identified in the system results along with voltage violations. As of April 1, 2012, the WECC Planning Criteria for adjacent circuits changed to include only circuits within 250 feet of each other if both circuits are greater than 300 kv. In addition, the new criteria allows for the exclusion for circuits that are adjacent for less than three miles (for pinch points, river crossings, substation entrances, etc.). The older criteria did not specify voltage level and the minimum circuit spacing was based on the maximum span length between towers which was typically in the order of 1,000 feet or more. Although most of the adjacent circuits by the old criteria were studied, only those now required to meet the new criteria need to be mitigated. Seattle, Tacoma Power, Chelan and Douglas requested numerous N-1-1 outages to be run. These outages were run for information and shared with all participants but no mitigation was suggested for these outages. In identifying the voltage violations, the WECC criteria of no more than a 5% voltage drop following a Category B (single) contingency or a 10% voltage drop following a credible Category C (multiple) contingency was used. Outages that did not solve were noted for further exploration. Participants were not only asked to review outages of their facilities that caused problems, but also to review any violation of limits on their facilities that were caused by any owner s outage. ColumbiaGrid staff also reviewed the results. Participants were also encouraged to provide a peer review of the results. Although the focus of this System Assessment is the facilities of the PEFA planning parties, the interconnected nature of the system requires that neighboring facilities also are modeled to determine if there are any interactions between the systems. As mentioned earlier, ColumbiaGrid invited the owners of systems neighboring PEFA parties to participate in the System Assessment. All study results were available to the planning participants. Single system outages (events where the outage facility and the overloaded facilities were owned by the same utility) were assumed to be the responsibility of that utility to mitigate. The focus of this report is the joint issues where the outages and associated overloads were owned by multiple utilities and joint transmission planning may be needed. 62

68 operated at 115 kv and above that overloaded during various outage conditions where mitigation was not identified. Of these overloaded lines, 37 are owned by ColumbiaGrid planning participants. A total of 109 line sections overloaded in the 2017 heavy summer case where mitigation was not identified; 79 of these overloaded lines are owned by ColumbiaGrid planning participants. No specific mitigation was identified in the five-year studies. Although many types of mitigation would be possible in that timeframe, this study concentrated on mitigation for the ten-year studies (below). 63 Study Results Five-Year Study Results There were no loading violations on ColumbiaGrid planning participant facilities in the five-year base cases with all facilities in-service. All outages that resulted in loadings or voltages outside of criteria were listed in spreadsheets and individually reviewed. Some of the more severe outages did not converge during the initial power flow simulations. Unsolved solutions are an indicator that the voltage stability limit may be exceeded. The Assessment resulted in 29 failed solutions in the summer and 42 failed solutions in the winter. These outages were studied in more detail in the Sensitivity Study section of this report. The System Assessment identified 58 line sections in the 2017 heavy winter case Ten-Year Study Results Contingencies were studied on the tenyear peak summer, peak winter, and light summer cases in the same manner as the five-year cases. Additional problems were noted in these studies. As noted above, the ten-year studies also included the I-5 Corridor Reinforcement, Hemingway-Boardman, Cascade Crossing, Blue Lake-Gresham, Portal Way Transformer, Phase 2 of the Denny Substation and the Celilo Replacement/upgrade. There were no loading violations on ColumbiaGrid planning participant facilities in the ten-year base cases with all facilities in-service. The System Assessment identified 80 line sections in the 2022 heavy winter case operated at 115 kv and above that overloaded during various outage conditions where mitigation was not identified. Of these overloaded lines, 62 are owned by ColumbiaGrid planning participants. A

69 total of 128 line sections operated at 115 kv and above, overloaded in the 2022 heavy summer case where mitigation was not identified; 94 of these overloaded lines are owned by ColumbiaGrid planning participants. A total of 16 line sections operated at 115 kv and above overloaded in the 2022 light summer case where mitigation was not identified; 12 of these overloaded lines are owned by ColumbiaGrid planning participants. It was assumed that these line sections could be rerated, reconductored, or rebuilt as mitigation and these types of projects are considered placeholder projects until more thorough reviews can be completed by the affected parties and specific transmission projects can be identified. These assessment cases also resulted in 29 failed solutions in the heavy summer, 64 failed solutions in the heavy winter, and 16 failed solutions in the light summer. These outages were studied in more detail in the Sensitivity Study section of this report. All contingencies were first run without mitigation and all violations noted. Participants in the System Assessment provided ColumbiaGrid with descriptions of mitigating actions for some contingencies that the participants have been planning. Mitigating actions include non-wires alternatives such as; operator actions (opening or closing lines, or adjusting generation) as well as infrastructure upgrades like reconductoring, line additions, or bus reconfigurations. Contingencies with potential mitigation were then re-examined. For each contingency with mitigation, changes to the contingency definition were made only if violations occurred in the first run. In the out year cases, both operator actions and upgrade projects were modeled in the mitigation cases. The 2022 light summer case represents peak wind generation in the northwest. This generation pattern resulted in two branch overload issues that were not seen in cases with lower wind generation levels. The first issue was overloads on all five sections of the McNary Jones Canyon 230 kv line for an outage of the Santiam Tumble Creek 230 kv line and the second issue was overloads of the Nine Canyon Wind Tap Badger 115 kv line for a breaker failure at McNary Substation. In addition to the branch overloads, seven new unsolved contingencies were linked to the increased wind generation. The failed solutions listed below are areas likely to have voltage stability issues. These contingencies involve thirteen areas of the system: 64

70 Substation (all 230 kv) MVARs Owner Albany 55 Bonneville Chiloquin 25 PacifiCorp Dixonville 55 PacifiCorp East Omak 15 Bonneville Flathead 15 Bonneville Garrison 50 Bonneville Martin Creek 10 Bonneville McKenzie W 85 Eugene Water & Elec Bd Pilot Butte 95 PacifiCorp Ponderosa 10 Bonneville Roundup 40 Bonneville South Bremerton 5 Puget Sound Energy Tahkenich 35 Bonneville Tillamook 30 Bonneville Troutdale 10 PacifiCorp Union Gap 70 PacifiCorp Total 605 Table K-1: Potential Reactive Mitigation s 65 The Redmond-Bend area in Oregon The Kalispell area in Montana The McKenzie area in Wenatchee Washington The Port Angeles area in northwestern Washington The Shelton area in the Washington southeastern Olympic Peninsula The Centralia area in southwestern Washington The Santiam area in East Salem, Oregon The Columbia Gorge area (Hood River, Bonneville and The Dalles) The Yakima area in central Washington The Grants Pass areas in southwest Oregon The Alturas area in northern California The Fairview area in western Oregon The Longview area in southwestern Washington All but the Longview area have been identified in previous assessments. The McKenzie, Centralia, Shelton, Santiam, Longview and Redmond-Bend areas were explored further in the sensitivity studies. Voltage problems were addressed similarly to overloading issues except that the interim corrective action was assumed to be capacitor additions rather than rerating, reconductoring, or rebuilding lines. In identifying the need for capacitor additions, the standard WECC criteria of no more than a 5% voltage drop following a credible Category B (single) contingency or a 10% voltage drop following a credible Category C (multiple) contingency was used. The reactive requirements to prevent voltage violations were studied for the 230 kv and 500 kv system. The reactive additions

71 necessary to mitigate voltage problems for the ten-year planning horizon total 605 system deficiencies between ColumbiaGrid members. Mvars of shunt capacitance in 16 different locations, all at the 230 kv level. These additions are listed in Table K-1. If a problem did not involve multiple utilities, it was considered to be a single-system issue and remained the responsibility of the These voltage results will be used as the basis for further transmission owner or study team technical studies. Only voltage violations on facilities 230 kv and above were addressed with capacitor additions since these systems individual owner. In this instance the owner is obligated through PEFA to report back to the ColumbiaGrid process on the measures they have planned to mitigate the singlesystem problem. ColumbiaGrid will use usually impact multiple transmission systems. Correcting voltage issues on lower voltage these mitigation plans to update its future base cases. transmission facilities was left to the individual transmission owners, as there is ample time to identify and implement these additions. Seventeen problem areas where identified in this assessment that involve more than one transmission system. Several of these The final screening results of all solved outages are included in supporting data for the System Assessment in Attachment C; however, this is CEII protected information and can only be obtained by request. This spreadsheet includes results for each facility that overloaded for outages studied during the System Assessment. The spreadsheet areas may require further study to determine the extent of the system problems and to develop mitigation. These areas will be monitored in the future to determine if study teams are needed. These problem areas are described on pages 8 through 17 and include several updates since the 2012 System Assessment was completed. 66 shows separate results for the five-year summer and winter base cases, the ten-year winter base case and the ten-year summer peak and light load cases. Joint Areas of Concern Joint areas of concern (those that occurred between systems or that involve the bulk grid) are the primary focus of ColumbiaGrid s System Assessment. These areas were identified when multiple planning parties had outages that caused overloads and/or had facilities that overloaded as a result of such outages. ColumbiaGrid will organize study teams as necessary to resolve these