Amended 2019 IRP

Jared Hansen, Resource Planning Leader

Tuesday, March 31st, 2020

Amended 2019 IRP IDAHOPOWERAn IDACORP Company

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Jared Hansen, Resource Planning Leader

Tuesday, March 31st, 2020

Integrated Resource Planning

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 20382

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Integrated Resource Planning j/;>1

2,500

Hydroelectric

44.8%Natural Gas

11.4%2.200

1,900

S2CO

1,600

Coal1.300

16.3%1,000

700 TT

1983 1988 1993 1993 2003 2008 2013 2018 2023 2028 2033 2038

OtherWA less Astaris Weather Adjusted Expected Case 70th Percentile 90th Percentile

Purchases

8.3%Long-Term Purchases

19.3%

019 8

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Integrated Resource Planning

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Cost

Risk

Environment

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Environment

Integrated Resource Planning

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Our Clean-Energy Goal

As Idaho Power continues serving customers and communities with reliable, affordable energy, we look to do so with a new and exciting goal:

Providing

6

We’re Well On Our Way2019 Energy Mix

Idaho Power sells the Renewable Energy Credits (REC) associated with our renewable energy purchases on Long-Term Purchases and a small portion of our hydro generation to offset power supply costs and keep customer prices as low as possible. The buyer of the REC claims the renewable attributes of that energy; therefore, Idaho Power does not represent that this resource mix represents the energy delivered to our customers.

About the sale of renewable energy credits:

7

We’re Well On Our Way2019 Energy Mix

National Average

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2019 Energy Mix

National Average

Hydroelectric

44.8%Natural Gas - Hydroelectric

^7%Natural Gas

37%11.4%

BigSfeNuclear

20%

Coal

16.3%

\ Non-Hydro

RenewablesCoal

24% Other10%1%

OtherPurchases

8.3%Long-Term Purchases

19.3%Data Source: U.S. Energy Information Administration

Totals may not equal 100% due to rounding 8

Resources

762 MW1773 MW 1118 MW

9

1284 MW

Resources

762 MW1773 MW 1118 MW

10

1284 MW

Jackpot Solar120 MW

Valmy Unit 1 127 MW

Resources – Demand-Side

Energy Efficiency234 aMW

Demand Response440 MW

11

Load and Resource Balance

1.0% Average-Energy

Growth

12

2,500

2,200

1,900

51.0%

Average-Energy

^ Growth

1,600

1,300

1,000

700

1983 1988 1993 1998 2003 2008 2013 2018 2023 2028 2033 2038

Weather Adjusted Expected Case

Figure 7.1 Average monthly load-growth forecast

WA less Astaris 70th Percentile 90th Percentile

12

1.2% Peak-Hour

Growth

13

5,100

4,700

4,300

3,900

3,500

S 3,1001.2%

Peak-Hour

Growth

5

2,700uA

2,300

1,900

1,500 1—r

1983 1 988 1 993 1 99 8 2 00 3 2 00 8 2 013 2 018 2 02 3 202 8 2 03 3 2038

50th Percentile

Figure 7.2 Peak-hour load-growth forecast (MW)

Actual less Astaris 90th PercentileActual 95th Percentile

13

Levelized Capacity Costs

14

Levelized Capacity CostsBoard man to Hemingway (350 MW) $5

Reciprocating Gas Engine (111.1 WW) S10

SCCT—Frame F Class (170 WW) $11

Reciprocating Gas Engine (55.5 MW) S11

Solar PV— Utility Scale 1-Axis Tracking (40 MW)

CCCT (1x1) F Class (300 MW)

$13

$13

Solar PV—Utility Scale 1-Axis Tracking Battery (50 MW)

Solai PV—Targeted Siting for Grid Benefit (0.5 MW)

Solar PV—Utility Scale 1 -Axis Tracking Battery (60 MW)

Solar PV—Utility Scale 1-Ax is Tracking Battery (70 MW)

$15

$16

$17

Storage—Pumped-Hydro (500 MW) $19

Storage—Li Battery 4 hour (5 MW)

Wind WY (100 MW)

$20

$20

Wild Common (1 00 MW) $21

Wind ID (100 MW) $22

Storage—Zn Battery 4 hour (5 MW) $31

Solar PV—Rooftop Commercial (.005 MW)

Sola rPV—Rooftop (.005 MW)

Biomass (35 MW)

$34

S44

Storage—Li Battery 8 hour (5 MW)

Small Modular Nuclear (60 MW)

Geothermal (30 MW)

$46

$56

S85

$0 $10 520 $30 $40 $50 $60 $70 $80 $90

$ per kW/Month

Cost of Capital Fixed O&M

Figure 7.5 Levelized capacity (fixed) costs in 2019 dollars14 14

Levelized Energy Costs

15

Boardman to Hemingway (350 MW) 33%

Levelized Energy CostsSolar PV—Utility Scale 1-Axis Tracking (40 MW) 26.0%

CCCT (1x1) F Class (300 MW) 60%

Solar PV—Targeted Siting for Grid Benefit (0.5 MW) 26%

Solar PV—Utility Scale 1 Axis Tracking Battery (50 MW)

Wind WY (100 MW)

22%

45%

Biomass (35 MW) 85.0%

Wind Common (1 00 MW) 35%

Wind ID (100 MW) 35%

Solar PV—Utility Scale 1-Axis Tracking Battery (60 MW)

Small Modular Nuclear (60 MW)

18%

90%

Solar PV—Rooftop Commercial (.005 MW) 21%

Geothe rmal (30 MW) 88%

Solar PV—Utility Scale 1-Axis Tracking Battery (70 MW) 15%

Reciprocating Gas Engine (111.1 MW) 15%

Reciprocating Gas Engine (55 5 MW) 15%

Storage—Pumped-Hydro (500 MW) 16%

Solar PV—Rooftop ( 005 MW) 21%

Storage—Li Battery 4 hour (5 MW) 11%

Storage—Li Battery 8 hour (5 MW) 23%

SCOT—Frame F Class (170 MW) 5%

Storage—Zn Battery 4 hour (5 MW) 11%

($25) $0 $25 $50 $75 $100 $125 $150 $175 $200 $225 $250 $275 $300 $325 $350 $375 $400 $425

$ per MWh

Cost of Capital Non-Fuel O&M Fuel "Offsets Wholesale Energy %=Capacity Factor

Levelized cost of energy (at stated capacity factors) in 2023 dollars 15Figure 7.6

2019 Integrated Resource Plan

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Demand

Battery Response Coal ExitGas Wind Solar

2019 -127

2020 -58

2021

2022 120 -1772,500

2023

20242,200

2025 -133

2026 -1801,900

2027

2028 -1741,600

2029 40 30

Optimized Resource

Expansion

2030 300 -1771,300

2031 5

2032 80 10 51,000

2033 80 20 5

2034 80 20 5

7002035 111 5

1983 1988 1993 1998 2003 2008 2013 2018 2023 2028 2033 2038

t2036 5

2037 320^WA less Astaris Weather Adjusted Expected Case 70th Percentile 90th Percentile

2038 300 440

fi,.

Nameplate Total

B2H (2026)

411 300 1,160 80 30 -1,026

500

P

16

Qualitative Risks

17

Qualitative Risks

R|SKahead

Uncertainty Analysis

18

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Uncertainty Analysis$16 00

$14 00

/$1200

$1000

3CD

2 $8 00Z•y)

$6 00

>-

$4 00 /

/

$2 00

$0 00

2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038

Figure 9.2 Natural gas sampling (Nominal $/MMBtu) 18

Uncertainty Analysis

19

.

Uncertainty Analysisif.

X• Portfolio 1 • • • • • •• • • •

X• Portfolio 2 • * • • • • • • •

•X• Portfolio 3 • • • • • *•• • • • •

XPortfolio 4 • •• • • •• •

• Portfolio 5 • • • •

•X •"• Portfolio 6 9 • • • • • • • • • • •

•X• Portfolio 7 • • • •• • •• •• • • • • •

X*• Portfolio 8 • • • * • • • •• •

K • •••••« • • • • • •• Portfolio 9

X® •• • m• Portfolio 10

•X• Portfolio 11 • •

x - • • • • • • • M •• Portfolio 12

x • • • — • • •• Portfolio 13

x • • • •• • •• • • •• •• Portfolio 14

X • •Portfolio 15

• X • «•Portfolio 16

x• •• Portfolio 17

• «X

• • • • • •• Portfolio 18

• • • »• • • •• Portfolio 19

X*• • • •• •• •• • •• Portfolio 20

• • X * • *• Portfolio 21

• •• • • • •• Portfolio 22

• • • x *** * ••• • • • •• Portfolio 23

•• •• • • •< •••• Portfolio 24

$5,500,000 $6,000,000 $6,500,000 $7,000,000

NPV ($ x 1000)

$7,500,000 $8,000,000 $8,500,000

Portfolio stochastic analysis, total portfolio cost, NPV years 2019-2038 ($x 1,000)Figure 9.5 19

Portfolio Cost and Variance

20

Portfolio Cost and Variance$7,400,000

• Portfolio 24

• Portfolio 23$7,200,000

$7,000,000 • Portfolio/

• Portfolios

• Portfolio 10• Portfolio 20

Portfolio 19

Portfolios• Portfolio 4

~ $6,800,000

-X

l 'ortfolio 16>£ $6,600,000

a?

3Portfolio22

Portfolio 21Portfolio 15

e$6,400,000

* P°rlf*olio6" Portfolio 1

• Portfolios

O-Portfolio 13• • Porlfolio 17

$6,200,000• Portfolio 2

, »Portfolio 14

Porlfolio 1 8

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$6,000,000

$450,000 $650,000 $850,000 $1,060,000

Four-Scenarios NPV Variance ($ x 1,000)

$1,250,000 $1,450,000

20Figure 9.1 NPV cost versus cost variance

Manual Adjustments - Timing

21

Manual Adjustments - Timing

Table 9.4 Jim Bridger exit scenarios

Scenario 1 Scenario 2 Scenario 3 Scenario 4 Scenario 5 Scenario 6

2022 2022 2022 2022 2023 2024

2026 2026 2028 2026 2026 2026

2034 2028 2034 2028 2028 2028

2034 2034 2034 2030 2030 2030

P14 derived portfolios—PI 4(1), P14(2), P14 (3), P14 (4), P14 (5), P14 (6)

21

Amended 2019 IRP

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Amended 2019 IRPi/;

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a 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 20380)

i1 I MilEg -100

-200

-300

-400

Solar Battery Demand and Response Coal ExitWind B2H Gas

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Action Plan

23

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Action Plan p**.

Table 10.3 Action Plan (2019-2026)

Tear Action

2019-2022 Plan and coordinate with PacifiCorp and regulators for early exits from Jim Bridge r units. Target dates

for early exits are one unit during 2022 and a second unit during 2026. Timing of exit from second unit

coincides with the need for a resource addition.

2019-2022 Incorporate solar hosting capacity into the customer-owned generation forecasts for the 2021 IRP.

Jackpot Solar PPA regulatory approval*—on-line December 2022

Exit Valmy Unit 1 by December 31 . 2019.*

2019-2021 Conduct ongoing B2H permitting activities. Negotiate and execute B2H partner

construction agreement(s).

2019-2026 Conduct preliminary' construction activities, acquire long-lead materials, and construct the

B2H project.

2019-2020 Monitor VER variability and system reliability needs, and study projected effects of additions of 120

MW of PV solar (Jackpot Solar) and early exit of Btidger units.

Exit Boardman December 31, 2020.

Bridget Unit 1 and Unit 2 Regional Haze Reassessment finalized.

Conduct a VER Integration Study.

2021-2022 Continue to evaluate and coordinate with PacifiCorp for timing of exih'closure of remaining Jim Bridger

units.

Subject to coordination with Pacif Corp, exit Jim Bridget unit (as yet undesignated; by

December 3f, 2022.

Jackpot Solar 120 MW on-line December 2022.

2023-2026 Procure or construct resources resulting from RFP (if needed).

Exit Valmy Unit 2 by December 31. 2025.

Subject to coordination with PacifiCorp. exit Jim Bridger unit (as yet undesignated) by December 31.

2026. Tinning of the exit from the second Jim Bridger unit is tied to the need for a resource

addition (B2H).

2019

2019

2020

2020

2020

2022

2022

2025

2026

23

Mitch ColburnEngineering & Construction Director

Boardman to Hemingway Transmission Line Project

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Boardman to Hemingway

Transmission Line Project Mitch Colburn

Engineering & Construction Director

B2H Overview

➢ 500 kV transmission line

➢ ~300 miles through Oregon and Idaho

➢ ~1,000 MW bi-directional capacity

➢ Proposed by Idaho Power, PacifiCorp, and Bonneville Power Administration

Detail Area 25

Need and Benefits

✓ Cost: serve customers cost-effectively

✓ Connectivity: move energy between Pacific Northwest and Mountain West

✓ Reliability: new infrastructure increases robustness of the grid.

✓ Flexibility: able to accommodate any resources type and future changes in technology

✓ Environment: operating B2H is carbon neutral and provides ability to integrate and move renewable resources

Bliss Dam, Idaho 26

Project Updates

• All major federal permits secured– BLM Record of Decision (ROD) – Nov 2017

– Forest Service ROD – Nov 2018

– Navy ROD – Sept 2019

• Oregon permitting process:– ODOE issues Draft Proposed Order – May 2019

– 20,000 page application

• Preliminary construction activities commenced in 2018 and are ongoing

UPDATES!

27

Costs

Total cost to-date ~$106 million

Total cost estimate is $1 to 1.2 billion, includes:

• Permitting

• Engineering

• Construction

• Substations

• 20% contingency

28

B2H Upcoming Activities

• ODOE Proposed Order

• Preliminary construction activities

• Construction agreement

29

Supplemental Slides

30

Supplemental Slides IDAHOPOWERAn IDACORP Company

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Inputs Modified During Filing Suspension

1. REC Values for Jackpot Solar

2. Transmission Interconnection Costs for Jackpot Solar

3. Removal of Franklin Solar

4. Corrected Online Date for Jackpot Solar

5. Peak Capacity Credit for Solar Resources

6. B2H Transmission Revenue Credits

7. Discount Rate Modification

8. Natural Gas Pipeline and Capacity Considerations31

Preferred Portfolio Comparison

32

June 2019 Filing Amended Filing