2018 INTEGRATED RESOURCE PLAN FINAL Commission Presentation August - - PDF document

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2018 INTEGRATED RESOURCE PLAN

FINAL

Commission Presentation August 9, 2016

Why do an Integrated Resource Plan

Chapter 19.280 RCW

2

 Washington legislature intends to encourage development of new

safe, clean, and reliable energy resources…for affordable and reliable electricity.

 Utilities with more than twenty-five thousand customers…shall

develop or update an integrated resource plan

 progress reports every two years  updated plan at least every four years  Consumer-owned utility governing body shall encourage

participation of consumers in development of plans/progress reports

 approve plans and progress reports after providing public notice and

hearing

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2018 IRP Project Timeline

3

Start Feb 7 Commission April 10 Commission Progress Report June 26 Commission

2018 IRP Draft Report

July 24

Final Public Comment Possible Commission Approval

Aug 14

2018 IRP to State

Before

September 1

IRP Contents

4

1)

Executive Summary

2)

Load Forecast

3)

Current Resources

4)

Policy & Regulation

5)

Supply Side Resource Costs

6)

Macro Utility Environment

7)

Capacity Requirements

8)

Market Simulation

9)

Risk Analysis and Portfolio Selection

10) Action Plan Summary

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2018 IRP Starting Point

 District’s 2016 IRP identified a long resource position

with seasonal capacity deficits

 Not pursuing purchase of additional firm resources  Relying on wholesale market  Sell surplus energy  Cover seasonal energy and capacity deficits

5

2018 IRP Starting Point

 Anti Fossil-Fuel Ideology



Retirement of baseload coal-fired generation



Carbon legislation and Initiatives



Increasing regional capacity deficits

 Increasing popularity of solar and continued federal

subsidies for solar and wind



“Belief” in batteries

 Evolving Western Power Markets



Expanding Western Energy Imbalance Market (EIM)



Momentum towards Enhanced Day Ahead Market (EDAM)



Momentum towards west wide Regional Transmission Organization (RTO)

6

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7

Energy Position

25 50 75 100 125 150 175 200 225 250 275 300 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 aMW Block Critical Slice Renewables Market Frederickson Resource Requirement*

Block Slice

Renewables

Frederickson

Market

Load/Resource Balance

Annual – Critical Water

8 * Retail Load Forecast plus distribution & transmission losses

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25 50 75 100 125 150 175 200 225 250 275 300 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 aMW Block Critical Slice Average Slice Adder Renewables Frederickson Resource Requirement*

Renewables

Average Water Slice Adder

Block Slice

Frederickson

Load/Resource Balance

Annual – Average Water

9 * Retail Load Forecast plus distribution & transmission losses $26 $33 $42 $47 $52 $54 $56 $64 $72 $78 $100 $0 $25 $50 $75 $100 $125 Market Conservation Landfill Gas Biomass CCCT Solar (E. WA) Wind Small Modular Reactor Solar (W. WA) Coal Geothermal

Green bars represent EIA qualifying resources

District Conservation $22 per MWh1 2

Notes:

• 1. Based on 2017 Actuals
• 2. SIS not included
• 3. CCCT=Combined Cycle Combustion Turbine

Green bars represent EIA qualifying resources Green bars represent EIA qualifying resources

Current BPA Power Cost $35 per MWh Levelized $/MWh

Green bars represent EIA qualifying resources

Resource Costs

10

Increased cost due to reduced future energy dispatch & assumed higher effective heat rate

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11

Capacity Position

• 50

100 150 200 250 300 350 January February March April May June July August September October November December aMW Block Critical Slice Average Slice Renewables Frederickson 2018 Resource Requirement

Current Load/Resource Balance

Action Plan

12

 Long energy position with seasonal capacity deficits  Relying on market/Frederickson to cover seasonal energy and capacity deficits

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Load/Resource Balance

Peak Hour Net Position with Frederickson

13

Load/Resource Balance

Peak Hour Net Position without Frederickson

14

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Market Purchases

15

Peak Load Resource Planning

16 HLH Peak Hourly Peak

 Hourly

Peak

Largest 60 minute load

 HLH Peak

Heavy Load Hour Peak is largest average load during period from 6 am to 10 pm

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Peak Load Resource Planning

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 Utilities in BPA Balancing Area  No requirement to demonstrate

Resource Sufficiency on a forecast basis

 Only required to enter hour of

delivery with scheduled resources sufficient to meet forecasted load

 No required methodology for

forecasting hourly load

 BPA Slice Customers  Give up share of slice capacity for

within hour services

 Purchase these services from BPA:

regulation; imbalance & reserves

Peak Load Resource Planning

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Summer 2018 Deficits July HLH = 39 MW July Peak = 45 MW Resource Assumptions BPA Block w/ Typical Peak Slice and Frederickson Summer & Winter 2025 Deficits July Peak = 107 MW January Peak = 38 MW Resource Assumptions BPA Block w/ Typical Peak Slice

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Regional Capacity Planning

19

 Retirement of NWPP baseload generation

Plant Name Capacity (MW) Retirement Year Centralia Generation (1) 670 2020 Boardman 585 2021 Colstrip (1) 307 2022 Colstrip (2) 307 2022 Centralia Generation (2) 670 2025 Various Coal, NG, Hydro 1,769 2018-2025 TOTAL 4,308

Regional Capacity Planning

20  Utilities at a Crossroads  The gap between peak power supply

and demand is narrowing in the winter, but growing in the summer.

 There are few power plants expected

to be built in the coming years and available generation is expected to shrink as coal-fired power plants are taken offline.

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Regional Capacity Planning

21 Source: PNUCC Northwest Regional Forecast of Power Loads and Resources 2019 through 2028 Assumptions: Low water, normal weather; includes only generation resources owned and contracted by utilities and firm long- term contracts.

4,000 MW Deficit

Regional Capacity Planning

22 Source: PNUCC Northwest Regional Forecast of Power Loads and Resources 2019 through 2028 Assumptions: Low water, normal weather; includes only generation resources owned and contracted by utilities and firm long-term contracts.

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Regional Capacity Planning

23 Source: PNUCC Northwest Regional Forecast of Power Loads and Resources 2019 through 2028

Regional Capacity Planning

24  “…Northwest power supply is likely to become

inadequate by 2021, primarily due to the retirement of the Centralia 1 and Boardman coal plants…The loss-of-load probability (LOLP) for that year is estimated to be over 6 percent, which exceeds the Council’s standard

• f 5 percent. ”

 “By 2022 the LOLP is projected to rise to about

7 percent, due to the additional retirements of the North Valmy 1 coal plant, the Colstrip 1 and 2 coal plants...”

 “While it appears that regional utilities are well

positioned to face the anticipated shortfall beginning in 2021, different manifestations of future uncertainties could significantly alter the

• utcome.”

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Resource Adequacy

Natural gas generation will still be needed for reliability and is a good complement to hydro/wind/solar

Gas generation is dispatched to help meet electric loads during cold weather events

Cold Winter Day under 80% Reduction

Without thermal generation, there is not enough energy to serve load during all hours

Cold Winter Day Without Gas



Most challenging conditions for the Northwest power system are multi‐day cold snaps that

• ccur during drought years



Wind and solar production tends to be very low during these conditions

Production capacity Actual production

Energy from Zero‐Carbon Resources

Source: E3, “Investigating a High RPS in California,” https://ethree.com/documents/E3_Final_RPS_Report_2014_01_06_with_appendices.pdf

Absent a technology breakthrough, gas generation will continue to be needed for reliability

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Regional planning reserve sharing mechanism could happen even without a full Regional System Operator



Relying on “front office transactions” to meet capacity needs only works if there is someone to transact with



Looming capacity deficit due to thermal resource retirements



Regional planning reserve sharing system could provide benefits



Ensures sufficient capacity is available



Reduces the total amount of capacity required



Certified, tradable capacity product could provide an efficient means to monetize capacity surpluses

Potential Benefits BPA+ Area NWPP (US) Individual Utility Peak + 15% PRM 33,574 46,398 Regional Peak + 12% 31,977 41,777 Reduction (MW) 1,597 4,621

Savings ($MM/Year $192 $555

• Diff. btw. coincident and non‐coincident peaks, 2006‐2012
• Assumes capacity cost of $120/kW‐yr.

It may be time to formalize the current practice of relying

• n the market for Resource

Adequacy capacity

Regional Capacity Planning

28

 Decisions to build and/or fund construction of power

generation plants are made by utilities…and maybe investors; not regional planning entities or politicians.

 Reliance on the market for capacity shortfalls is the

theme of the region.

 There is no resource adequacy enforcement mechanism to

guarantee load/resource balance under extreme conditions

 Musical chairs (or a game of chicken) seems to be

underway

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Market Simulation

Market Simulation

Aurora Model

30

Stochastic definition: Having a random probability distribution or pattern that may be analyzed statistically but may not be predicted precisely. Stochastic inputs: 1. Natural gas prices 2. Hydro generation 3. Wind/solar generation

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Future Wholesale Market Prices

Mid-Columbia Average Price Forecast

31

Future Wholesale Market Prices

Mid-Columbia HLH/LLH Spread Forecast

32

By end of study period; LLH heat rates and power prices are higher than HLH heat rates and power prices. Attributable to decreasing loads, low natural gas prices, and the continued increase in solar generation through the entire WECC region.

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33

Risk Analysis And Portfolio Selection

Portfolios Analyzed

34 Portfolio 2

50 MW natural gas engines

Portfolio 1

Rely on Market Purchases

Portfolio 3

25 MW CCCT & Market Purchases

Portfolio 4

20 MW Solar & 30 MW Wind

Portfolio 5

Portfolios 2 & 4

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Portfolio – Cost vs. Risk

35

Increasing Risk 1 2 3 4 5

50

x

36

Action Plan

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Action Plan Summary – Short Term

Peak Hour Net Position with Frederickson

37

• 1. Continue to make

purchases from the market

• 2. Closely monitor

summer capacity deficits as region’s coal plants are retired

• 3. Develop tactical plan

for future purchase

• f capacity products
• 4. Monitor regional

LOLP; if >5% consider 3 to 5 year capacity products

Action Plan Summary – Longer Term

Peak Hour Net Position without Frederickson

38

• 1. Purchase 5 year

forward electricity call option tied to a physical power plant to cover the District’s winter HLH shortfall.

• 2. Budget and plan to

purchase Q3 electricity call options to cover the District’s summer HLH capacity deficit.

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Questions

39