TEP Integrated Resource P lan

Advisory Council Meeting

July 18, 2019

Welcome

KEVIN SKINNER

CORPORATE TRAINING PROGRAM MANAGER

Modeling Overview

JEFF YOCKEY

DIRECTOR, RESOURCE PLANNING

Overview of Portfolio Cost Assessment

4

Portfolioand

ScenarioAssumptions

Portfolio Cost(NPV)

Fixed Costs and Portfol io Net Present Value

5

o Aurora estimates TEP’s operating / dispatch costs

o Capital and other fixed costs are estimated in a spreadsheet model that accounts for:— Asset depreciation

— Cost of capital (debt and equity)

— Fixed O&M

— Capital improvements

— Insurance and taxes

— Renewable tax credits

— Transmission and gas transportation costs

o For each portfolio, a net present value is determined for the total (operating + fixed) cost. Portfolios can then be compared on the basis of their cost and sensitivity to different market and regulatory conditions (scenarios)

Overview of Aurora

o Example specifications:

— Electricity demand

— Fuel prices and other O&M costs

— Unit capacities and efficiencies

— Unit emission rates

— Planned and unplanned outages

— Ramp rates and minimum up/down times

— Demand side programs

— Wholesale electricity market prices

— Power contracts

o Example constraints:

— Transmission limits

— Ancillary service requirements (reserves)

— Minimum renewable energy generation

— Minimum fuel use (take or pay contracts)

— Fuel limits (hydro, gas, storage)

— Emission limits

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o Specifically designed for simulating electricity system dispatch and costs (minutes to years)

o Determines the least-cost dispatch subject to a variety of specifications and constraints

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Unit Dispatch

o To determine the least-cost dispatch, Aurora generally follows the process below for each hour of a simulation:

— Distributed generation and other demand-side programs are applied to determine the net demand

— “Must run” thermal units are dispatched at their lowest possible capabilities. (Hence, this generation appears at the bottom of the “resource stack.”)

— Because they have no fuel costs and very low variable O&M costs, renewable units are generally the cheapest and second type of resource to be dispatched. These will be dispatched at their maximum capabilities (subject to solar and wind availability in the hour), unless curtailment is necessary to avoid over generation.

— The remaining net load for the hour is met through a least-cost combination of wholesale market purchases, further dispatch of must-run units, and dispatch of cycling and non-cycling units.

o Dispatch Cost = Fuel Cost + VOM + Startup Cost (if not already operating)

Fuel Cost = Fuel Price * Unit Efficiency (heat rate) * Unit Generation (dispatch)

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Unit Commitment

o By nature of their design, many common generation technologies (e.g., coal, nuclear, and larger natural gas units) cannot turn on and off by the hour. They are either physically incapable or incur significant startup costs when doing so.

o Such units are designated “non-cycling” and are assigned minimum up times, minimum down times, start-up costs, and shut-down penalties.

o Non-cycling units must be “committed” before they are eligible for dispatch. Aurora will commit a unit if: 1) it has been off for its min down time, and 2) it is profitable to operate over its min up time, given its startup and dispatch costs and an “internal” price forecast generated by Aurora specifically for commitment decisions.

o Once committed, a non-cycling unit must generate at least its minimum generation for at least its min up time. After such time, Aurora will shut down a unit when its unprofitability exceeds its start-up costs (plus any shut-down penalty).

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Daily Dispatch Profile

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0

200

400

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1600

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MW

Hours

Spring Day

Wind Solar Storage Coal NGCC NGST RICE NGCT Purchases Load

NGCC=Natural Gas Combined Cycle | NGST=Natural Gas Steam | NGCT=Natural Gas Combustion Turbine | RICE=Reciprocating Internal Combustion Engine

Other Aurora Capabilities

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Stochastic Natural Gas Price Forecast (2017 TEP IRP)o Long-term capacity expansion— Least-cost build-out and retirement

pathway given specific requirements

o Risk studies— Evaluate how model outputs (costs,

emissions, etc.) are affected by uncertainty in the inputs

— Input values can be stochastically varied or demand, unit outages, renewable generation, and fuel prices

o Marginal cost studies

o Wholesale electricity price forecasts

o Market valuation of electricity assets

Technology and Cost Projections

Technology Cost and Performance Projections

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o Wood Mackenzie — An industry leading research, analysis and consulting firm

— Requires a subscription: North American Power and Renewables Subscription

— The North America Power and Renewables subscription includes a Long-Term Outlook (LTO), which is a comprehensive integrated forecast of energy demand and supply

o National Renewable Energy Laboratory (NREL) — The National Renewable Energy Laboratory is a national laboratory of the U.S Department of

Energy, Office of Energy Efficiency and Renewable Energy

— Annual Technology Baseline (ATB) workbook documenting detailed cost and performance data (both current and projected) for both renewable and conventional technologies.

— The ATB data are freely available for use

o U.S. Energy Information Administration(EIA) — Statistical and analytical agency within the U.S. Department of Energy.

— EIA’s information is issued daily, weekly, monthly, annually, and periodically as needed or as requested

— Annual Energy Outlook (AEO) provides long-term energy projections for the United States

https://my.woodmac.com/ | https://atb.nrel.gov/ | https://www.eia.gov/outlooks/aeo/

Fossil CapEx Forecast

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$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

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

$/k

W

Combustion Turbine

WoodMac ATB

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

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

$/k

W

Natural Gas Combined Cycle

Woodmac ATB EIA

Solar CapEx Forecast

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$0

$500

$1,000

$1,500

$2,000

$2,500

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

$/k

W

Single Axis Tracking

WoodMac ATB EIA

$0

$500

$1,000

$1,500

$2,000

$2,500

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

$/k

W

Fixed PV

Woodmac ATB EIA

Wind and Battery CapEx Forecast

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$0

$500

$1,000

$1,500

$2,000

$2,500

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

$/k

W

Wind

WoodMac ATB EIA

$0

$500

$1,000

$1,500

$2,000

$2,500

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

$/k

W

Batttery Storage 4h

WoodMac ATB NREL Low NREL mid NREL high

NREL - https://www.nrel.gov/docs/fy19osti/73222.pdf

Phase Out of Federal Tax Incentives

Production Tax Credit (PTC) — $23/MWh credit for each unit of

generation

— Annual inflation-adjustment

— Applies for 10 years after the date the facility is placed in service

— Safe harbor

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(1) Must achieve commercial operation within four years.

Year Construction Commences (1)

PTC Available ITC Available

2017 PTC amount is reduced by 20% 30% Deduction

2020 PTC amount is reduced by 40% 30% Deduction

2019 PTC amount is reduced by 60% 30% Deduction

2020 PTC no longer available 26% Deduction

2021 22% Deduction

2022+ 10% Deduction

Investment tax credit (ITC) — Deducts the percentage from the cost of

installing a solar energy system from federal taxes

— Credit is amortized over the life of the asset

Impacts of Tax Credits

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$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$0

$200

$400

$600

$800

$1,000

$1,200

2021 2022 2023 2024 2025 2026

LCO

E, $

/MW

h

Inst

alle

d C

ost

, $/k

W

Solar PV - Tracking

Solar PV - Tracking (>20 MW) $/KW

$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

$2,000

2017 2018 2019 2020 2021 2022

LCO

E, $

/MW

h

Inst

alle

d C

ost

, $/k

W

Wind (50 MW)

$/MWh $/KW

Candidate Resources

19TEP Preliminary Integrated Resource Plan, p. 50

o Future resources to be modeled— Reliable cost data

— Successfully deployed at TEP

— Successfully deployed at similar utilities for similar purposes

— Particular interest to stakeholders

o Future resources not being considered— Conventional hydroelectric

— Coal

— Integrated gasification combined cycle

— Small modular nuclear reactors

— Geothermal

Market Projections

Market and Gas Forecast

o Need integrated forecast with Gas, Power & Carbon Pricing

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$0.00

$10.00

$20.00

$30.00

$40.00

$50.00

$60.00

$70.00

$80.00

$90.00

2018 2020 2022 2024 2026 2028 2030 2032 2034 2036

$/M

WH

(N

om

inal

)

Palo Verde (7x24) Market Prices

2018 Base Case 2018 Low Gas Case 2018 High Gas Case

2019 Base Case E3

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

$8.00

$9.00

2018 2020 2022 2024 2026 2028 2030 2032 2034 2036

Del

iver

ed P

rice

$/m

mB

tu (

No

min

al)

Natural Gas Price Forecast

2018 Base Case 2018 Low Gas Case 2018 High Gas Case

2019 Base Case EIA E3

Midday Pricing

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$-

$20.00

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$60.00

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$120.00

$140.00

$160.00

$180.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

$/M

Wh

Hours

Monday 2020 vs Monday 2030 in March

2020 2030

$-

$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

$140.00

$160.00

$180.00

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

$/M

Wh

Hours

Wednesday 2020 vs Wednesday 2030 in August

2020 2030

Advisory Council Member Feedback

KEV IN SKINNER

CORPORATE TRAINING PROG RAM MANAG ER

May Meeting - Uncertainty Summary

o The future is uncertain and strong forecasting tools do not change that

o Avoid “big bets” – decisions involving significant expense yet which do not perform well across all reasonably foreseeable futures

o The timing of resource acquisitions can have a significant impact on the cost effectiveness of those decisions

o Diversification helps mute the impact of unfavorable future outcomes and provides opportunity to take advantage of favorable future outcomes

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June Meeting - Load Forecast

7,000

8,000

9,000

10,000

11,000

12,000

13,000

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GW

h

Ex. Rosemont Ex. Electric Vehicles and Rosemont Total Sales (MWh)

Peak Demand Forecast

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2,000

2,100

2,200

2,300

2,400

2,500

2,600

2,700

2,800

2,900

3,000

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TEP

Ret

ail P

eak

Dem

and

(M

W)

Load Forecast

0.7% growth

1.4% growth

2.0% growth

June Meeting - Resources Overview

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New Resourceso Borderlands Wind (2020)

o Wilmot Solar and Storage (2020)

o Oso Grande Wind (2020)

o RICE (2020)

o Gila River Unit 2 (2019)

July Meeting - Modeling Assumptions

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July Meeting - Price Forecast

28TEP Preliminary Integrated Resource Plan, Appendix B

Next Steps

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Future Agenda Items Next Meeting

o Monday, August 19??

Questions

o August— Revenue requirement

— Resource adequacy

o September— Energy efficiency / DSM

— Demand response

o October— Greenhouse gas emission reductions