2014–2015 Local Transmission Plan

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2014–2015 Local Idaho Power Transmission Plan Delivery Planning

Idaho Power Company 2014–2015 Local Transmission Plan

TABLE OF CONTENTS

Table of Contents ...... i

List of Tables ...... ii

List of Figures ...... iii

List of Appendices ...... iii

1. Introduction ...... 1

1.1. Local Planning ...... 1

1.2. Regional and Interconnection-Wide Coordination ...... 1

2. Planning Process and Time Line...... 2

3. Transmission System Plan Inputs and Components ...... 3

3.1. Idaho Power’s Transmission System ...... 3

3.2. Load Forecast ...... 3

3.2.1. Western Load Area ...... 5

3.2.2. Treasure Valley Load Area ...... 5

3.2.3. Southern Load Area ...... 6

3.2.4. Eastern Load Area...... 7

3.3. Forecasted Resources ...... 8

3.4. Transmission Use Forecast ...... 9

3.5. Area Planning ...... 10

3.6. Economic studies ...... 16

4. System Conditions Studied ...... 16

4.1. Scenarios Studied ...... 16

4.2. Transmission System Model ...... 17

5. Reliability Evaluation ...... 18

5.1. Transmission System Analysis ...... 18

5.2. 2020 Heavy Winter Study Results ...... 19

5.3. 2024 Heavy Summer Study Results...... 19

5.4. 2024 NTTG case Study Results ...... 21

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5.5. 2034 Heavy Summer Study Results...... 21

6. Summary and Conclusions ...... 21

LIST OF TABLES

Table 1 Meeting dates and descriptions ...... 2

Table 2. Load forecasts for areas of Idaho Power ...... 4

Table 3 2013 IRP Preferred Portfolio ...... 8

Table 4 Generation Interconnection Projects with signed GIAs or PPAs since 2013 ...... 8

Table 5 Transmission Service Obligations submitted in Quarter 5 ...... 9

Table 6 Transmission Capacity Needed in the year 2024 ...... 9

Table 7 Comparison of 2024 Transmission Needs with Expected TTC for various RTPs ...... 10

Table 8 Modeled loads in 2034 power flow case ...... 17

Table 9 Summary of performance criteria issues ...... 19

Table B-1 Projects planned for 1-5 year horizon ...... 27

Table B-2 Projects planned for 5-10 year horizon ...... 28

Table B-3 Projects planned for 10-20 year horizon ...... 30

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LIST OF FIGURES

Figure 1 Planning cycle schedule ...... 2

Figure 2 Idaho Power transmission system ...... 3

Figure 3 Idaho Power load areas ...... 4

Figure 4 Western load area ...... 5

Figure 5 Treasure Valley load area ...... 6

Figure 6 Southern load area ...... 7

Figure 7 Eastern load area ...... 7

Figure 8 Treasure Valley electrical plan ...... 11

Figure 9 Magic Valley electrical plan ...... 12

Figure 10 Wood River Valley electrical plan ...... 12

Figure 11 Eastern Idaho electrical plan ...... 13

Figure 12 Western Treasure Valley electrical plan ...... 14

Figure 13 Eastern Treasure Valley electrical plan—Ada County ...... 15

Figure 14 Eastern Treasure Valley electrical plan—Elmore County ...... 16

LIST OF APPENDICES

Appendix A Community Advisory Committee Process ...... 23

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Appendix B Twenty-year project list ...... 27

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Idaho Power Company 2014–2015 Local Transmission Plan

1. INTRODUCTION

The 2015 Local Transmission Plan is the culmination of the 2014-2015 local transmission planning process as described in Idaho Power’s Open Access Transmission Tariff (OATT) Attachment K. The plan includes all transmissions system facility improvements identified through this planning process. A power flow reliability assessment of the plan was performed which demonstrated that the planned facility additions will meet NERC and WECC reliability standards.

Idaho Power’s OATT is located on its Open Access Same-time Information System (OASIS) at http://www.oatioasis.com/ipco. Additional information regarding Transmission Planning is located in the Transmission Planning folder on Idaho Power’s OASIS. Unless otherwise specified, capitalized terms used herein are defined in either Section 1 of Idaho Power’s OATT or Section 1 of Idaho Power’s OATT Attachment K. 1.1. Local Planning

This Local Transmission Plan (LTP) has been prepared within the two-year process as defined in Idaho Power’s OATT Attachment K. The LTP identifies the Transmission System facility additions required to reliably interconnect forecasted generation resources and serve the forecasted Network Customers’ load, Native Load Customers’ load, and Point-to-Point Transmission Customers’ requirements, including both grandfathered, non-OATT agreements and rollover rights, over a twenty (20) year planning horizon. Additionally, the LTP incorporates any stakeholders requested economic congestion studies results. Links to documents related to the LTP are located in the Local Transmission Plan folder on Idaho Power’s OASIS site. 1.2. Regional and Interconnection-Wide Coordination

Idaho Power coordinates its planning processes with other transmission providers through membership in Northern Tier Transmission Group (NTTG) and the Western Electric Coordinating Council (WECC). Idaho Power uses the NTTG process for regional planning, coordination with adjacent sub-regional groups and other planning entities, and development of proposals to WECC for interconnection-wide planning. Additional regional coordination information is located in Idaho Power’s OATT Attachment K and on the NTTG’s website at www.nttg.biz.

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2. PLANNING PROCESS AND TIME LINE

This plan is for the 2014–2015 planning cycle. The planning cycle schedule is shown below in Figure 1.

Figure 1 Planning cycle schedule

Idaho Power holds webinar meetings throughout the planning cycle to keep stakeholders and interested parties informed. The following table lists the meeting dates.

Table 1 Meeting dates and descriptions

Date Meeting Meeting Description 3/19/2014 2014-2015 1st Quarter Idaho Power Local Transmission Plan Request for Information 6/18/2014 2014-2015 2nd Quarter Idaho Power Local Transmission Plan Presentation of assumptions 9/17/2014 2014-2015 3rd Quarter Idaho Power Local Transmission Plan Initial analysis results 12/17/2014 2014-2015 4th Quarter Idaho Power Local Transmission Plan Analysis results 3/18/2015 2014-2015 5th Quarter Idaho Power Local Transmission Plan Draft study results 6/17/2015 2014-2015 6th Quarter Idaho Power Local Transmission Plan Draft report 9/16/2015 2014-2015 7th Quarter Idaho Power Local Transmission Plan Draft report 12/16/2015 2014-2015 8th Quarter Idaho Power Local Transmission Plan Final report

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3. TRANSMISSION SYSTEM PLAN INPUTS AND COMPONENTS 3.1. Idaho Power’s Transmission System

Idaho Power’s transmission system exists mostly in southern Idaho and eastern Oregon. The system extends north to the Montana border, east into Wyoming to the Jim Bridger power plant, south to Wells, Nevada (not shown), and west to LaGrande, Oregon as shown in Figure 2.

Figure 2 Idaho Power transmission system 3.2. Load Forecast

Idaho Power produces a forecast of native and network loads for its balancing area. This forecast includes Idaho Power’s twenty-year load forecast and a 20 year network customer load forecast based on Bonneville Power Administration’s ten-year forecast and PacifiCorp’s ten-year forecast. The load forecasts include expected energy efficiency reductions.

Table 2, below, lists the load forecasts for the Western and Treasure Valley, Southern and Eastern load areas based on load forecasts established during quarter 1 of the process. Idaho

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Power generally divides its service territory into four load areas; however the load forecast reporting for the Western and Treasure Valley load areas are combined as their geographic areas overlap.

Table 2. Load forecasts for areas of Idaho Power

Area Description Load Level Western and Treasure Valley Idaho Power’s system west of Mountain Home 2,793 MW Southern Idaho Power’s system bounded by Mountain Home on the west and 1,338 MW American falls on the east. Eastern Idaho Power’s system east of American Falls 630 MW

A transmission map with the load areas presented in Table 2 is shown below in Figure 3.

Eastern

ONTARIO Western CALDWELL BOISE

BLACKFOOT MOUNTAIN HOME

Treasure Valley POCATELLO

Legend TWIN FALLS Operating Voltage 138kV 161kV 230kV 345kV 500kV Southern

Figure 3 Idaho Power load areas

The following sub-sections will present further information on Idaho Power load areas.

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3.2.1. Western Load Area

The Western Load Area includes Malheur County in Oregon and Payette, Valley, and Washington counties in Idaho. The area also includes the Brownlee East (Path 55) and Idaho to Northwest (Path 14) WECC transmission paths. The Western load area, including the area substations, generation facilities and transmission paths is shown in Figure 4.

Figure 4 Western load area 3.2.2. Treasure Valley Load Area

The Treasure Valley Load Area includes the Idaho counties of Ada, Boise, Canyon, Elmore, and Gem. The Treasure Valley load area, including the area substations, generation facilities and transmission paths is shown in Figure 5.

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Figure 5 Treasure Valley load area 3.2.3. Southern Load Area

The Southern Load Area includes the Idaho counties of Blaine, Cassia, Gooding, Jerome, Lincoln, Minidoka, and Twin Falls. The area also includes the Idaho to Sierra (Path 16) WECC rated transmission path and the Midpoint West internally monitored transmission path. The Southern load area, including the area substations, generation facilities and transmission paths is shown in Figure 6.

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Figure 6 Southern load area 3.2.4. Eastern Load Area

The Eastern Load Area includes the Idaho counties of Bannock, Bingham, and Power. The area also includes the Borah West (Path 17) WECC rated transmission path. The Eastern load area, including the area substations and transmission paths is shown in Figure 7.

Figure 7 Eastern load area

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3.3. Forecasted Resources

Table 3 contains the preferred resource portfolio for the next 20 years as presented in Idaho Power’s 2013 IRP.

Table 3 2013 IRP Preferred Portfolio

Date Resource Capacity 2016 – 2017 Demand Response Up to 150 MW 2018 Boardman to Hemingway 500 MW Transfer Capacity 2024-2032 Demand Response Up to 370 MW in 50 MW Increments

Idaho Power released the 2015 IRP in June of 2015. The results from the 2015 IRP will be included in the 2016-2017 Local Transmission Plan. The 2015 IRP can be found on the Idaho Power website: https://www.idahopower.com/AboutUs/PlanningForFuture/irp/default.cfm Table 4 contains a list of the resources with signed Generation Interconnection Agreements or signed Power Purchase Agreements with Idaho Power since the last Local Transmission Plan was completed in late 2013.

Table 4 Generation Interconnection Projects with signed GIAs or PPAs since 2013

IPC Queue# In Service Date County State Resource Capacity (MW) 394 2016 Elmore ID Solar 20.00 395 2016 Elmore ID Solar 20.00 397 2016 Elmore ID Solar 20.00 401 2016 Baker OR Wind 10.00 402 2016 Baker OR Wind 10.00 403 2016 Baker OR Wind 10.00 404 2016 Baker OR Wind 10.00 405 2016 Baker OR Wind 10.00 411 2016 Elmore ID Solar 10.00 412 2016 Malheur OR Solar 10.00 413 2016 Malheur OR Solar 10.00 414 2016 Malheur OR Solar 6.00 418 2016 Elmore ID Solar 10.00 419 2016 Malheur OR Solar 9.00 424 2016 Malheur OR Solar 10.00 425 2016 Malheur OR Solar 4.50 426 2016 Owyhee ID Solar 20.00 428 2016 Elmore ID Solar 20.00 431 2016 Power ID Solar 20.00 432 2016 Ada ID Solar 40.00 433 2016 Power ID Solar 20.00 435 2016 Elmore ID Solar 20.00 436 2016 Power ID Solar 20.00 441 2016 Elmore ID Solar 20.00

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3.4. Transmission Use Forecast

In Quarter five, Idaho Power and Bonneville Power Administration each submitted transmission service obligations (“TSOs”) to NTTG. Table 5 below shows these transmission service obligations.

Table 5 Transmission Service Obligations submitted in Quarter 5

Transmission WECC Path Point of Point of Obligation Number/ Submitted By Receipt Delivery Start Date End Date (MW) Direction Idaho Power Northwest IPCO 1/1/2021 - 500 (summer) 14 W-E 200 (winter) 82 W-E BPA Northwest BPA SEID 1/1/2020 12/31/2028 250 (summer) 14 W-E 550 (winter) 82 W-E 17 W-E

Table 6 below shows the existing transmission transfer capabilities ("TTCs") and ATCs for the critical paths between Idaho and the Northwest. The fourth column is the difference of the TTCs and the ATCs which shows the transmission capacity being utilized in the year 2014. The TSOs from Table 4 are listed in column five. The last column is the sum of columns four and five which indicates the total amount of transmission capacity that is needed in 2034 to fulfill all of the transmission requirements for that path assuming rollover rights.

Table 6 Transmission Capacity Needed in the year 2034

2014 Transmission Transmission Obligation WECC Path 2014 2014 Capacity Change 2034 Transmission Number/ TTC ATC Utilized Between 2014 Capacity Needed Direction (MW) (MW) (MW) and 2034 (MW) (MW) 14 W-E 1200 0 1200 750 1950 82 W-E 2465 150 2315 750 3065 17 W-E 1600 1445 155 550 705

Table 7 is a comparison of the 2034 transmission capacity needed ("TCN") from Table 5 with TTCs of the critical paths with and without the Boardman to Hemingway 500 kV transmission project (“B2H”). The TTCs are based on Path Rating Studies performed for the B2H project. Numbers in red indicates a deficiency in meeting the transmission needs on the path. Green numbers are those which have sufficient capacity to meet the transmission needs.

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Table 7 Comparison of 2034 Transmission Needs with Expected TTC for various RTPs

WECC Path Number/ 2034 Transmission 2034 TTC 2034 TTC Direction Capacity Needed (MW) (w/ B2H) (w/o B2H) 14 W-E 1950 2250 1200 82 W-E 3065 3515 2465 17 W-E 705 1600 1600

The results of this comparison illustrate the need for the B2H project. 3.5. Area Planning

Idaho Power develops long-term local area transmission plans with regional community advisory committees. These committees consist of jurisdictional planners; mayors; council members; commissioners; and large industry, commercial, residential, and environmental representatives. The plans identify the transmission and substation infrastructure required through the full development or “build-out” of the local area. The Treasure Valley, Western Treasure Valley, Eastern Treasure Valley, Magic Valley, Wood River Valley, and Eastern Idaho electrical plans have been completed. Figures 9 through 15 present the future transmission infrastructure plans for each of the aforementioned electrical plans. A description of the community advisory committee process can be found in Appendix A.

More information about electrical plans can be found on the Idaho Power website at: http://www.idahopower.com/AboutUs/PlanningForFuture/RegionalElectricalPlans/default.cfm

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Figure 8 Treasure Valley electrical plan

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Figure 9 Magic Valley electrical plan

Figure 10 Wood River Valley electrical plan

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Figure 11 Eastern Idaho electrical plan

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Figure 12 Western Treasure Valley electrical plan

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Figure 13 Eastern Treasure Valley electrical plan—Ada County

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Figure 14 Eastern Treasure Valley electrical plan—Elmore County 3.6. Economic studies

Eligible customers or stakeholders may submit an economic congestion study request during either quarter 1 or quarter 5 of the planning cycle. Idaho Power did not receive any study requests during quarter 1 or quarter 5 of the 2014-2015 planning cycle.

4. SYSTEM CONDITIONS STUDIED 4.1. Scenarios Studied

Idaho Power uses scenario planning to evaluate the performance of the transmission system for different load and generation dispatch patterns in the future. A 20 year heavy summer load study case was evaluated as the primary study scenario.

A five year heavy winter load scenario and a 10 year heavy summer load scenario were also studied. These cases were selected to assess future system adequacy and performance under different load and generation patterns (seasonal conditions).

Further, a 10 year base case developed from WECC TEPPC production cost model data through NTTG was also evaluated to determine if any unusual flow pattern exists that is not represented

Page 16 2014–2015 Local Transmission Plan Idaho Power Company 2014–2015 Local Transmission Plan in the selected seasonal cases. A summer condition with heavy load in the Idaho area was selected. 4.2. Transmission System Model

The 20 year power flow case was based on the WECC 2024 HS1 base case, approved by WECC on December 13, 2013. Load levels in the 20 year case were increased to approximate Idaho Power’s forecasted control area load in the year 2034. The total Idaho Power control area load was modeled at approximately 4,760 MW. This is roughly a 1,000 MW increase in load from Idaho Power’s historical area peak load, including Network Customer load, of 3,750 MW, which occurred on July 2, 2013. The loads in the case were increased to approximately achieve the distribution across the Idaho Power’s system noted below in Table 8.

Table 8 Modeled loads in 2034 power flow case

The 20 year power flow case was also modified to reflect the expected 500 kV transmission improvements for the Gateway West and Boardman to Hemingway (B2H) transmission projects. Lower voltage transmission modeling detail was added to the Idaho Power service territory that was not originally modeled in the WECC base case. Transmission growth and reliability driven projects that have been planned for the next 20 years have also been added to the case. A list of projects scheduled for the next 20 years can be found in Appendix B.

The five year and ten year scenarios utilized WECC approved power flow cases. Idaho Power evaluated the same cases as part of its 2014 NERC TPL compliance reliability evaluation. The following two WECC cases were utilized:

 2020 Heavy Winter case (20hw1), approved 8/12/14  2024 Heavy Summer case (24hs1), approved 12/13/13

The load, resource dispatch and path flow data modeled in the WECC base cases for the five and ten year cases were not modified from the WECC published cases.

The 2024 heavy summer NTTG base case utilized WECC TEPPC 2024 production cost model data. The TEPPC 2024 model is a security constrained economic-commitment-and-dispatch model based on forecasted loads and resources for the year 2024 that were submitted from all WECC balancing authorities. The balancing authorities supply monthly peak and energy forecasts. The forecasts are then dispersed into hourly load demands.

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After reviewing the hourly 2024 production cost data, the model data for a heavy summer load hour was extracted into a PowerWorld power flow model by the Northern Tier Transmission Group (NTTG) Technical Work Group (TWG) for its 2014-2015 planning process. The extracted case was selected by the NTTG TWG because it represented an NTTG footprint heavy load condition.

5. RELIABILITY EVALUATION 5.1. Transmission System Analysis

PowerWorld power flow software was utilized to perform contingency analysis on each of the cases. Single element outage contingencies (N-1) were evaluated based on single transmission line or single transformer outages on the 138 kV, 161 kV, 230 kV, 345 kV and 500 kV systems. Two element outage contingencies (N-2) contingencies were also evaluated. Idaho Power’s “Common Corridor” analysis was the basis for a list of credible N-2 contingencies.

The power-flow simulation results are measured against North American Electric Reliability Council (NERC) and WECC reliability criteria. Specifically, the NERC Reliability Standards TPL-001-0.1 and TPL-002-0b require that transmission facilities maintain operation within normal and emergency limits. The WECC business practice TPL-001-WECC-RBP-2 establishes the voltage violation threshold for N-1 contingencies. Additionally, Idaho Power files its reliability criteria via FERC Form No. 715, part IV – Reliability Criteria for System Planning. Combined, the NERC, WECC and Idaho Power criteria formed the criteria for which every N-1 and N-2 contingency was screened.

Every N-1 contingency was screened for thermal overloads and voltage issues. Thermal overloads over 100% of equipment emergency ratings were reported. Voltage deviations greater than 5% were reported. Per Idaho Power’s Reliability Criteria for System Planning, post-outage deviations greater than 5% are acceptable if minimum voltage remains above nominal of 0.90 per unit and distribution bus voltage is within ANSI Emergency Range. Regardless, 5% deviations were flagged as part of the screening process. A low voltage screening threshold was set for 0.93 PU and a high voltage threshold was set for 1.10 PU. Thus, any contingency that resulted in a voltage below 0.93 or greater than 1.10 was reported, regardless of the amount of voltage deviation. Flagged contingencies were then reviewed further to determine if the reported issue was a reliability criteria violation.

Each N-2 contingency was screened for thermal overloads and voltage issues. Thermal overloads over 100% of equipment emergency ratings were reported. Voltage deviations greater than 10% were reported. Per Idaho Power’s Reliability Criteria for System Planning, post-outage deviations greater than 10% are acceptable if minimum voltage remains above nominal 0.90 per unit and distribution bus voltage is within ANSI Emergency Range. Voltage screening thresholds of 0.90 per unit and 1.10 per unit were utilized.

A summary of results can be found below in Table 5 and the results are discussed further in the following sections. The system improvements identified for the next 20 years are presented in Appendix B.

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Table 9 Summary of performance criteria issues

Number of Flagged Case Contingencies Thermal Issues Voltage Issues 2020 Heavy Winter 2 0 0 2024 Heavy Summer 12 12 0 2024 NTTG Heavy Summer 0 0 0 2034 Heavy Summer 22 2 0

5.2. 2020 Heavy Winter Study Results

The 2020 heavy winter case resulted in two flagged contingencies. One of the flagged contingencies was the outage of the King-Wood River 138 kV line. This outage resulted in post- outage voltages of 0.90 per unit on several busses. The performance was deemed acceptable for this contingency because the affected buses have distribution transformers set to boost the voltage on the distribution side of the transformers. Furthermore, the distribution feeders in the area are configured to trip specified amounts of load to increase the voltage to an acceptable level if the voltage drops below certain thresholds.

The other contingency was flagged based on a voltage deviation greater than 5%. The loss of the Ontario-Quartz-Weiser 138 kV line resulted in a voltage deviation greater than 5% at the Weiser substation. However, the performance was deemed acceptable for this outage because the post- outage voltage was greater than 0.93 per unit at the flagged bus (0.97 per unit). 5.3. 2024 Heavy Summer Study Results

The 2024 peak summer load case resulted in 12 flagged contingencies, all of which were deemed criteria violations.

The loss of one of the two Locust 230/138 kV transformers resulted in a 6.0% emergency rating thermal overload of the adjacent transformer. The two transformers are identical so each N-1 transformer outage was flagged. The proposed solution to address the overload is to install a 230/138kV transformer at the nearby Cloverdale substation.

The loss of the Boise Bench-Grove 138 kV line results in a 3.5% overload on the Butler-Wye 138 kV line. The proposed solution to address the overload is the same for the Locust 230/138 kV transformer above – install a 230/138kV transformer at Cloverdale substation.

The loss of the Boise Bench-Wye 138 kV line results in a 1.9% overload on the Boise Bench- Gowen Tap 138 kV line section. The proposed solution to address the overload is the same for the Locust 230/138 kV transformer above – install a 230/138kV transformer at Cloverdale substation.

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The loss of the Blackfoot-Goshen 161 kV line results in 5.3% overload of the Don-Pingree Jct. 138 kV line section. The proposed solution to address the overload is a new 161 kV line that taps the existing Antelope-Goshen 161 kV line and runs 12 miles south to the existing Haven 138 kV substation.

The N-2 loss of the Boise Bench-Wye 138kV line and Boise Bench-Locust 230kV line results in loading beyond the emergency rating of several 138kV line sections in the Boise area. The proposed solution to address the overloads includes installing a 230/138kV transformer at Cloverdale substation, constructing a new 230/138kV substation near Dry Creek Tap on the Boise Bench-Emmett-Ustick 138kV line, rebuilding the Dry Creek Tap-Gary 138kV line (4.5 mi), installing 138kV breakers at Gary substation, building a new 11 mi 138kV line between Willis and Star substations, and increasing the rating of the Boise Bench-Gowen Tap 138kV line by replacing disconnect switches at the Boise Bench terminal.

The N-2 loss of the Cloverdale-Wye 138kV line and Boise Bench-Locust 230kV line results in loading beyond the emergency rating of the Boise Bench-Gowen Tap 138kV line. The proposed solution to address the overload is to increase the rating of the Boise Bench-Gowen Tap 138kV line by replacing disconnect switches at the Boise Bench terminal.

The N-2 loss of the Boise Bench-Grove 138kV line and Boise Bench-Emmett-Ustick 138kV line results in loading beyond the emergency rating of several 138kV line sections in the Boise area. The proposed solution to address the overloads includes installing a 230/138kV transformer at Cloverdale substation, constructing a new 230/138kV substation near Dry Creek Tap on the Boise Bench-Emmett-Ustick 138kV line, rebuilding the Dry Creek Tap-Gary 138kV line (4.5 mi), and installing 138kV breakers at Gary substation.

The loss of the Adelaide 138kV bus results in loading beyond the emergency rating of the American Falls-Lamb 138kV line section. The proposed solution to address the overload is to increase the rating of the American Falls-Lamb 138kV line by replacing a wave trap at the American Falls terminal.

The loss of the Hunt 138kV bus results in loading beyond the emergency rating of the Heyburn Jct-Paul138kV line section. The proposed solution to address the overload is to increase the rating of the Heyburn Jct-Paul 138kV line by replacing a wave trap at the Paul terminal.

The loss of Boise Bench 230/138kV transformer T232 with a Boise Bench 207Z breaker failure will result in loading beyond the emergency limits of the remaining Boise Bench 230/138kV transformers. The proposed solution to address the overloads includes installing a 230/138kV transformer at Cloverdale substation, constructing a new 230/138kV substation near Dry Creek Tap on the Boise Bench-Emmett-Ustick 138kV line, rebuilding the Dry Creek Tap-Gary 138kV line (4.5 mi), and installing 138kV breakers at Gary substation.

The loss of the Adelaide 345kV bus with an Adelaide 301Z breaker failure will result in loading beyond the emergency limits of several 138kV line sections in the Adelaide area. The proposed solution is to replace several wave traps in the area.

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5.4. 2024 NTTG case Study Results

No thermal or voltage issues in the Idaho Power system resulted from the N-1 and N-2 contingency analysis in the 2024 Heavy Summer NTTG case. Contingencies evaluated by NTTG were limited to circuits 200kV and above. 5.5. 2034 Heavy Summer Study Results

The 2034 peak summer load case resulted in several flagged contingencies, 20 of which were based on post transient voltage deviation of greater than 5%. Two contingencies resulted in thermal criteria violations.

Several transmission upgrades were included in the 2034 case that were not modeled in the 2024 heavy summer case, resulting in fewer violations. Appendix B is a list of the significant projects included in the 2034 case.

The loss of one of the two Adelaide 345/138 kV transformers resulted in a 17% emergency rating thermal overload of the adjacent transformer. The two transformers are identical so each N-1 transformer outage was flagged. The proposed solution to address the overloads is to add a new 230/138kV substation in the area.

6. SUMMARY AND CONCLUSIONS

Idaho Power’s Local Transmission Plan has been prepared as part of the two-year process defined in Idaho Power’s OATT Attachment K. The Plan has identified the transmission system facility additions required to reliably interconnect forecasted generation resources, serve Native Customer and Network Customer forecasted load and Point-to-Point Transmission Customers’ requirements over a twenty (20) year planning horizon.

An analysis of forecasted transmission service obligations was performed to determine whether additional transmission capacity is needed to meet forecasted use. A power flow reliability assessment was performed on cases modeling system facilities and conditions 5, 10, and 20 years into the future. The results of the transmission obligation analysis and reliability analysis triggered the following projects:

 Construct new Boardman to Hemingway 500kV line and associated Treasure Valley integration projects  Add 230/138kV transformer at Cloverdale substation  Construct Dry Creek 230/138kV substation and rebuild Dry Creek-Gary 138kV line  Build new Willis-Star 138kV line  Add a new 230/138kV substation in the Adelaide substation area

A complete list of the significant facility additions and upgrades that have been identified to reliably interconnect forecasted generation resources, serve Native Customer and Network Customer forecasted load and Point-to-Point Transmission Customers’ requirements over a 20 year planning horizon are included in Appendix B.

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Appendix A Community Advisory Committee Process 1. Background

The process develops a plan to meet needs through build out, regardless of when that occurs. The process is possible due to an effective collaboration driven by significant commitment from both Idaho Power and the specific area “community”. Idaho Power dedicates significant skilled staff resources through the integral participation of planners and engineers to support the technical needs of the process. The unique community needs, interests and goals are represented through the Community Advisory Committee; a broad-based participation of elected officials, businesses, landowners, planners, agencies and other key stakeholders. The result is an effective blend of technical and non-technical input, combined to develop an electrical plan that is both technically sound and sensitive to each area’s needs. 2. Purpose of the Electrical Plan Process

To create a clear and documented electrical energy supply plan to serve the load needs of the area from now through build out.

The public process is the starting point of all electrical supply plans and any resulting transmission rights-of-way and substation siting requirements 3. The Planning Process

The planning process follows a specific outline of steps, divided into three basic components; education, infrastructure siting and plan implementation. The overall process typically involves 9 to 12 months beginning with education, followed by development of community criteria and alternatives, to a committee consensus decision for the final plan. Committee input is focused on two primary areas; where to, and where not to locate new infrastructure such as transmission lines, substations, etc. to be acceptable to the “community”, and recommendations for related delivery, conservation and demand-side management programs to support desired implementation of electrical service in the area. In general, the planning process does not address recommendations for electrical generation or future high voltage (500kV) transmission lines to move electricity into and through the region. 4. Typical Planning Steps

Meeting 1: Bus Tour  Committee orientation and ground rules  Idaho Power introduction and overview  Electric Power 101  Idaho Power voltage levels Meeting 2: Education  Generation  Transmission—including Gateway West, etc.

 Substation

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Meeting 3: Education  Rates and regulatory (continued)  Demand side management (energy efficiency)  Planning area existing electrical system conditions  Begin developing community criteria Meeting 4: Education  Confirm community criteria (continued)  Future electrical build out needs  Transmission & related components to meet build out needs  Initial alternative discussion Meeting 5: Infrastructure  Review of community criteria Mapping  Mapping/alternatives development orientation  Small group mapping exercises Meeting 6: Mapping  Mapping/alternatives development review and feedback and Evaluation  Resume mapping exercises if needed  Evaluation/scoring matrix orientation Meeting 7: Preferred  Alternatives evaluation and scoring process Alternatives  Identify preferred alternatives for each of the planning areas Meeting 8: Plan Consensus  Verify/confirm preferred alternative(s) and ranking  Develop implementation plan  Discuss local plans coordination Meeting 9: Plan Document  Review draft plan and Next Steps  Comments  Plan rollout discussion

5. The Community Advisory Committee

The Community Advisory Committee for each of the Electrical Plans includes individuals, representing a broad cross section of elected officials, local governments, businesses, community development organizations, planning entities, landowners, affected agencies, environmental organizations, and other key stakeholders. Together, they provide both individual and regional perspective regarding the key issues and concerns that are important to the specific area residents when meeting the long-term electrical needs for that area.

5.1.1. Advisory Committee Purpose Develop consensus support and lend credibility for identified electrical energy supply improvements necessary to serve the area.

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5.1.2. Advisory Committee Role Propose ideas and solutions to Idaho Power’s load serving needs that meet the area through build out. 6. Benefits and Uses of the Plan

The development of the Electrical Plans provide two primary benefits; First, the completed document outlines a specific plan based on community goals, with a range of acceptable alternatives for Idaho Power to follow as it implements specific infrastructure projects to meet the area’s electrical needs through build out. Second, the planning process develops significant community awareness and support that is critical to successful project development that is acceptable to community residents.

In addition to its use by Idaho Power, the plan is also intended for use by local jurisdictions, governments and affected agencies through incorporation into local planning documents. The plan is also a key tool for use by economic development organizations in support of existing and potential new businesses to the region. Finally, it is important to note that the plan is intended to be a living document, that can be adjusted with additional advisory committee and community input to respond to significant changes in electrical needs of the area. 7. Summary of Community Plans

Electrical Plans Year Completed Updates Year Updated Treasure Valley Electric Plan 2006 Revised for Birds of Prey Area 2007 Wood River Electric Plan 2007 Ongoing Magic Valley Electric Plan 2008 Planned for 2118 Eastern Idaho Electric Plan 2009 Planned for 2019 Western Treasure Valley Electrical Plan 2011 Planned for 2021 Eastern Treasure Valley Electrical Plan 2012 Planned for 2022

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Page 26 2014–2015 Local Transmission Plan Idaho Power Company Appendix B

Appendix B Twenty-year project list

Table B-1 Projects planned for 1-5 year horizon

Region Time Frame Project Title Project Scope Southern 5 year Rebuild 138 kV line from King to Moonstone Rebuild existing 138 kV line between King substation and Moonstone substation to improve reliability and performance to the Wood River loop. Treasure Valley 5 year Add 138kV circuit breakers at Gary substation Install circuit breakers at Gary substation to increase reliability in the Boise area 138kV system. Treasure Valley 5 year Build new Lakeshore distribution substation Construct new 138-12.5 kV distribution substation south of Nampa near Lake Lowell. Treasure Valley 5 year Build new 138 kV line from Lowell Junction to new Build a 138 kV transmission line to serve the new Lakeshore substation Lakeshore substation south of Nampa near Lake Lowell. Treasure Valley 5 year Add T232 300 MVA 230/138 kV tie transformer at Add a second 300 MVA 230/138 kV transformer at Bowmont Bowmont

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Table B-2 Projects planned for 5-10 year horizon

Region Time Frame Project Title Project Scope NTTG 10 year Boardman to Hemingway 500 kV Line Build a new 500 kV transmission line from Boardman, Oregon area to Idaho Power’s Hemingway substation. Treasure Valley 10 year Hemingway-Bowmont Build 230 kV line Add the second 230 kV line circuit on existing structures from Hemingway to Bowmont to integrate B2H project into Treasure Valley. Treasure Valley 10 year Hubbard-Bowmont Build 230 kV line This project uprates the existing 138 kV line from Bowmont-Hubbard to 230 kV to integrate B2H project into Treasure Valley. Treasure Valley 10 year Add T233 300 MVA 230/138 kV tie transformer at Add a third 300 MVA 230/138 kV transformer t at Bowmont Bowmont to integrate B2H project into the Treasure Valley Treasure Valley 10 year Kuna-Bowmont Build 138 kV line Build new 7 mile 138 kV line from Kuna Tap to Bowmont to serve Kuna after the existing 138 kV line between Bowmont and Mora/Hubbard is converted to 230 kV. Treasure Valley 10 year Willis-Star Build 11 mile 138 kV line Build a new approximately 11 mile 138 kV transmission line between Willis and Star to improve reliability in the area. Treasure Valley 10 year Add 230/138 kV capability at Cloverdale Add a 230 kV line terminal and T231 230/138 kV 300 MVA transformer in the north side of the station. NTTG 10 year Gateway West 500 kV Line – Bridger to Populus Build a new 500 kV transmission line from Jim Bridger station in Wyoming to Populus station in Southeastern Idaho. NTTG 10 year Gateway West 500 kV Line – Populus to Borah Build a new 500 kV transmission line from Populus Station in Southeastern Idaho to Borah Station in Southeastern Idaho. NTTG 10 year Gateway West 500 kV Line – Populus to Cedar Hill Build a new 500 kV transmission line from Populus Station in Southeastern Idaho to Cedar Hill Station in Southern Idaho.

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Region Time Frame Project Title Project Scope NTTG 10 year Gateway West 500 kV Line – Borah to Midpoint Convert the existing 345kV line between Borah and Midpoint (part of Kinport-Midpoint 345kV line) to 500 kV. Add new 345kV line terminal at Borah to terminate 345kV line from Kinport. NTTG 10 year Gateway West 500 kV Line – Cedar Hill to Midpoint Build a new 500 kV transmission line from Cedar Hill Station in Southern Idaho to Midpoint Station in Southern Idaho. NTTG 10 year Gateway West 500 kV Line – Cedar Hill to Build a new 500 kV transmission line from Cedar Hill Hemingway Station in Southern Idaho to Hemingway Station in Southwestern Idaho. Southern 10 year Add 200 MVA 230/138 kV transformer at Midpoint Add a 200 MVA 230:138 kV transformer at Midpoint to relieve overload concerns. Western 10 year Relieve N-1 overload on Ontario tie bank Add 3rd tie bank or upgrade existing tie banks at Ontario.

Eastern 10 year Add 161/138kV transformer at Haven Install a 161/138kV transformer at Haven and build a new 161kV line from Haven to tap point on Goshen- Antelope 161kV line. Treasure Valley 10 year Build new Wagner distribution substation Construct new 138-12.5 kV distribution substation in the area of Farmway and Purple Sage Road Treasure Valley 10 year Add Dry Creek 230/138kV substation Construct new 230/138kV substation near Dry Creek Tap on Boise Bench-Ustick-Emmett 138kV line and Boise Bench-Brownlee#1 230kV line. Rebuild Dry Creek Tap-Gary 138kV line. Treasure Valley 10 year Build new Cherry distribution substation Construct new 138-12.5 kV distribution substation at the SE corner of Cherry Lane and Can-Ada in Nampa. Build 138kV tap to Zilog-Blackcat 138kV line.

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Table B-3 Projects planned for 10-20 year horizon

Region Time Frame Project Title Project Scope Treasure Valley 20 year Build new Beacon Light Substation Build new Beacon Light distribution substation in the area northwest of Eagle. Treasure Valley 20 year Star-Beacon Light – Build new 138 kV line Extend 138 kV line approximately 2 miles to new Beacon Light substation. Treasure Valley 20 year Build 138 kV line from Zilog substation to Blackcat Obtain ROW and build 138 kV transmission line from station substation Zilog tap to Blackcat substation. Treasure Valley 20 year Build new Amity distribution substation Construct new 138-12.5 kV distribution substation at Amity and Ten Mile Roads. Treasure Valley 20 year Build 138 kV 4.5 mile line from Happy Valley to new Build a new 138 kV transmission line from the Happy Amity substation Valley station to the new Amity distribution substation at Amity and Ten Mile Roads. Treasure Valley 20 year Add second 230 kV line terminal at Nampa and Add 230 kV line terminals and convert Nampa to an convert 230 kV tap into in/out in/out station on the existing Hubbard-Nampa- Caldwell 230 kV line. Add 2nd 230/138kV transformer at Nampa. Southern 20 year Twin Falls-Filer-Buhl Build new 138 kV line Build new 138 kV transmission line from Twin Falls substation to Filer to Buhl substation. Convert Filer from 46 kV to 138 kV. Add 138/46kV transformer at Filer. Southern 20 year Convert the Golden Valley Loop to 138 kV. This includes the following substations: Lake, Burley Rural, Golden Valley, Kenyon, Buckhorn, Artisian. Southern 20 year Upgrade Shoshone station to 138 kV Convert Shoshone station from 46 kV to 138 kV, build new 138kV line from Midpoint substation to Shoshone substation. Southern 20 year Connect Hagerman to the Lower Malad-King 138 kV Connect Hagerman to the Lower Malad-King 138 kV line line Eastern 20 year Convert 46 kV substations to 138 kV This includes the following substations: Crater, Cinder, Sterling, Rockford, Moreland, Aiken, & American Potato.

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Eastern 20 year Build 138 kV line between Kramer and Pingree Build a new 138 kV transmission line between Kramer substation and Pingree substation to provide a second source to the 46 kV system served out of Pingree

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Thank you for your interest.

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