2014 Integrated Resource Plans Duke Energy Carolinas and Duke ...
2016 Integrated Resource Plans Duke Energy Carolinas and Duke Energy Progress
1/23/2017
1
Resource Planning Overview
Growth in Customer Consumption
Resource Retirements
Resource Need
Changes in Load Forecast Impacts of Energy Efficiency (EE)
Plant Retirement Purchase Contract Expiry
Load Resource Balance Reserve Margin
Non-conventional Resources Remaining Resource Gap
2016 Resource Plans 1/23/2017
Base Plan w/ Carbon Tax Base Plan w/ Carbon Mass Cap 2
DEC Load Resource Balance (Including Reserve Requirements)
Peak demand growth and asset retirements are largest drivers for resource needs in DEC First need in DEC occurs in winter of 2023 1/23/2017
3
DEP Load Resource Balance (Including Reserve Requirements)
Peak demand growth, asset retirements, and purchase contract expirations are the largest drivers for resource needs in DEP First need in DEP occurs in winter of 2022
1/23/2017
4
Resource Adequacy Study
1/23/2017
5
Conclusions
Load response in cold weather and solar penetration have transitioned DEC/DEP systems to winter capacity planning utilities Based on 1 day in 10 year criteria DEC: 16.5% winter reserve margin DEP: 17.5% winter reserve margin
Adopted a 17% minimum winter reserve margin target for DEC and DEP based on the consensus of the two studies Economics support the 17% winter reserve margin
1/23/2017
6
Solar Sensitivities
1/23/2017
7
Key Inputs
1/23/2017
8
Load Forecast - System Winter Peaks Before and After EE
1/23/2017
9
Key Inputs: Energy Efficiency & Demand Side Management
1/23/2017
10
DEC Base Case EE
1/23/2017
11
DEP Base Case EE
1/23/2017
12
Key Inputs: Renewables
1/23/2017
13
Process for Forecasting Renewable Generation
Identify Key Drivers NC REPS and SC DERP Targets
PURPA & other Incentives
Customer Demand
Operational Consideration; Jurisdictional Differences
Interest in customer programs
Least Cost, System Benefits
Evaluate main variables
Economic Factors
Markets, Policy and Regulatory Developments
Produce Renewable MW & MWH forecasts
• • •
Multiple internal reviews with subject matter experts Alignment with recent trends and other studies Assessment of market environment to determine base case or most likely outcome
1/23/2017
14
14
Forecast Results: DEC Renewable MW by Category
1/23/2017
15
Forecast Results: DEP Renewable MW by Category
The renewable projection for DEP shows a different mix between solar PURPA and NC REPS compliance vs. DEC due to two factors: a) much larger pipeline of solar projects in the queue and b) lower compliance needs relative to MWH targets
1/23/2017
16
Solar Generation Capacity – North Carolina vs Other States
1/23/2017
17
NC REPS
DEC
DEP
2020 System Load Forecast
2020 System Load Forecast
99,132 GWh
65,869 GWh
2020 NC Load Forecast
2020 NC Load Forecast
71,347 GWh
58,586 GWh
2020 NC Retail Load Forecast 62,760 GWh
12.5% of 2020 NC Retail Load 7,845 GWh (DEC) 5,058 GWh (DEP)
2020 NC Retail Load Forecast 40,460 GWh
* 7,845 GWh (DEC) and 5,058 GWh (DEP) only represents the projected amount of Renewables and EE required to meet REPS compliance in 2021 based on the NC Retail load forecast for the year 2020. The cumulative EE and renewables energy on the DEP system is expected to be greater than what is represented here. Additionally, NC REPS allows 65% of the 2021 target to be met by EE and Out of State Renewable Energy Certificates (RECs). 1/23/2017
18
Technology Screening
1/23/2017
19
Technology Screening
1/23/2017
20
Economic Screening
Technologies Screened During Economic Screening1 Baseload
Peaking/Intermediate
Renewable
782 MW Ultra-Supercritical Pulverized Coal with CCS
166 MW 4 x LM6000 CT
2 MW / 8 MWh Li-ion Battery
557 MW 2x1 IGC with CCS
201 MW 12 x Reciprocating Engine Plant
5 MW Landfill Gas
2 x 1,117 MW Nuclear Units (AP1000)
870 MW 4 x 7FA.05 CT2
150 MW Wind – On-Shore (NonDispatchable)
576 MW 1x1x1 Advanced CC (Inlet Chiller & Fired)
5 MW Solar PV (Non-Dispatchable)
1,160 MW 2 x 2 x 1 Advanced CC (Inlet Chiller & Fired) 20 MW CHP
Notes 1: Units highlighted in Red font were screened into the quantitative analysis as potential supply-side resource options to meet future capacity needs 2: A 2x7FA.05 version was also included based upon the cost to construct 4 units
1/23/2017
21
Analytic Analysis
1/23/2017
22
IRP Process – Drivers
Key drivers were varied in System Optimizer (SO) to assess impacts on resource plans Potential Carbon Constraints 1. Carbon Tax on existing coal and gas units 2. System Carbon Mass Cap (System Mass Cap)
Nuclear license extensions All units relicensed in sensitivity
Coal and natural gas fuel prices (high / low sensitivities) Capital costs (high / low sensitivities) All assets (nuclear, CC/CT, Renewables) Renewables Only
Solar penetration (high / low sensitivities) In all cases, SO was able to select “economic” solar
Energy Efficiency (high sensitivity) Peak demand (high / low sensitivities) 1/23/2017
23
IRP Process – Portfolios (DEP)
Six portfolios were developed based on the results of the SO sensitivity analysis
1/23/2017
24
IRP Process – Portfolios (DEC)
Six portfolios were developed based on the results of the SO sensitivity analysis
1/23/2017
25
IRP Process – Portfolio Analysis
The six portfolios were evaluated under several “world view” scenarios using an hourly production cost model called PROSYM Carbon Tax/No Carbon Tax Scenarios1
Fuel
CO2
CAPEX
1
Current Trends
Base
CO2 Tax
Base
2
Economic Recession
Low Fuel
No CO2 Tax
Low
3
Economic Expansion
High Fuel
CO2 Tax
High
System Mass Cap Scenarios2
Fuel
CO2
CAPEX
Current Trends - CO2 Mass Cap
Base
Mass Cap
Base
4
Portfolios #1 - #4 were run under the Carbon Tax/No Carbon Tax Scenarios Portfolios #5 & #6 were run under the System Mass Cap Scenario Portfolios #1 - #4 would not meet the system mass cap constraints
1/23/2017
26
IRP Process – Portfolio Carbon Emission Profiles
Portfolio #4 (High CC) has the highest CO2 emissions over the long term
The system CO2 mass cap constraint is not met without nuclear relicensing, or new nuclear generation, in the late 2020s.
1/23/2017
27
IRP Process – Conclusions
DEP Portfolio #1 (CT Centric) is the least cost portfolio under a Carbon Tax paradigm The short-term build plan in Portfolio #1 would keep the Company on track if a system CO2 mass cap were implemented
DEC Portfolio #4 (High CC) is the least cost portfolio under a Carbon Tax paradigm, however its carbon foot print would not be sustainable under a System Carbon Mass Cap With Lee Nuclear included, Portfolio #1 (CT Centric) is the least cost portfolio followed by high EE and high renewable portfolios
1/23/2017
28
Results
1/23/2017
29
2016 IRP - DEP Expansion Plan – Base Case Duke Energy Progress Resource Plan (1) Base Case - Winter Resource Nuclear Uprates
Year 2017 2018
Sutton Blackstart CT
2019
Nuclear Uprates
2020
Nuclear Uprates
2021 2022
100 14 CHP
12
CHP Nuclear Uprates
2023 2024
CHP Asheville CC
2025 2026 2027 2028 2029 2030 2031 Notes:
22 560
22
22 New CC
6
New CT Nuclear Uprates
MW 8
Potential Asheville CT
1221 468
4
186
New CT
468
New CT New CT
468 468
New CT
1404
(1) Table includes both designated and undesignated capacity additions Future additions of renewables, EE and DSM not included
1/23/2017
DEP Base Case Resources Cumulative Winter Totals - 2017 - 2031 44 Nuclear 1781 CC 3562 CT 66 CHP 5453 Total
30
2016 IRP - DEC Expansion Plan – Base Case Duke Energy Carolinas Resource Plan (1) Base Case - Winter Resource Nuclear Uprates
Year 2017
MW 25
2018
Lee CC
CHP
683
43
2019
Hydro Refurb Return to Service Nuclear Uprates CHP
CHP
10
22
2020 2021
Bad Creek Uprate
2022 2023
Hydro Refurb Return to Service CHP
60
22 46.4
Bad Creek Uprate
46.4 New CC
Bad Creek Uprate
1221
46.4
2024
Bad Creek Uprate
46.4
2025 2026 2027 2028 2029 2030 2031
New CT
468
New Nuclear
1117
New Nuclear
1117
Notes:
6 22
(1) Table includes both designated and undesignated capacity additions Future additions of renewables, EE and DSM not included (2) Lee CC capacity is net of NCEMC ownership of 100 MW (3) Rocky Creek Units currently offline for refurbishment; these are expected return to service dates (4) Lee Nuclear in service dates are assumed to be Nov 2026 and May 2028
1/23/2017
DEC Base Case Resources Cumulative Winter Totals - 2017 - 2031 Nuclear 2319 CC 1904 CT 468 Hydro 202 CHP 109 Total 5002
31
2016 IRP - Joint System Energy by Resource Type
Carolinas Energy by Fuel Type - 2017
1/23/2017
Carolinas Energy by Fuel Type - 2031
32
Key Takeways
1/23/2017
33
Key Takeaways
Short Term Completion of 1,250 MWs of CC, 100 MWs CTs and 185 MWs Pumped Storage System impact of increasing amounts of Solar T&D, Unit Flexibility, Storage
Winter Planning Based on the LOLE study new generation need is driven by winter peaks.
First need best met with CC in DEC and DEP 2022 in DEP, 2023 in DEC New Gas Capacity and associated Infrastructure
Long Term Pursue 80 year license life for existing nuclear COL for Lee Nuclear
1/23/2017
34
Q&A
1/23/2017
35
1/23/2017
1
Resource Planning Overview
Growth in Customer Consumption
Resource Retirements
Resource Need
Changes in Load Forecast Impacts of Energy Efficiency (EE)
Plant Retirement Purchase Contract Expiry
Load Resource Balance Reserve Margin
Non-conventional Resources Remaining Resource Gap
2016 Resource Plans 1/23/2017
Base Plan w/ Carbon Tax Base Plan w/ Carbon Mass Cap 2
DEC Load Resource Balance (Including Reserve Requirements)
Peak demand growth and asset retirements are largest drivers for resource needs in DEC First need in DEC occurs in winter of 2023 1/23/2017
3
DEP Load Resource Balance (Including Reserve Requirements)
Peak demand growth, asset retirements, and purchase contract expirations are the largest drivers for resource needs in DEP First need in DEP occurs in winter of 2022
1/23/2017
4
Resource Adequacy Study
1/23/2017
5
Conclusions
Load response in cold weather and solar penetration have transitioned DEC/DEP systems to winter capacity planning utilities Based on 1 day in 10 year criteria DEC: 16.5% winter reserve margin DEP: 17.5% winter reserve margin
Adopted a 17% minimum winter reserve margin target for DEC and DEP based on the consensus of the two studies Economics support the 17% winter reserve margin
1/23/2017
6
Solar Sensitivities
1/23/2017
7
Key Inputs
1/23/2017
8
Load Forecast - System Winter Peaks Before and After EE
1/23/2017
9
Key Inputs: Energy Efficiency & Demand Side Management
1/23/2017
10
DEC Base Case EE
1/23/2017
11
DEP Base Case EE
1/23/2017
12
Key Inputs: Renewables
1/23/2017
13
Process for Forecasting Renewable Generation
Identify Key Drivers NC REPS and SC DERP Targets
PURPA & other Incentives
Customer Demand
Operational Consideration; Jurisdictional Differences
Interest in customer programs
Least Cost, System Benefits
Evaluate main variables
Economic Factors
Markets, Policy and Regulatory Developments
Produce Renewable MW & MWH forecasts
• • •
Multiple internal reviews with subject matter experts Alignment with recent trends and other studies Assessment of market environment to determine base case or most likely outcome
1/23/2017
14
14
Forecast Results: DEC Renewable MW by Category
1/23/2017
15
Forecast Results: DEP Renewable MW by Category
The renewable projection for DEP shows a different mix between solar PURPA and NC REPS compliance vs. DEC due to two factors: a) much larger pipeline of solar projects in the queue and b) lower compliance needs relative to MWH targets
1/23/2017
16
Solar Generation Capacity – North Carolina vs Other States
1/23/2017
17
NC REPS
DEC
DEP
2020 System Load Forecast
2020 System Load Forecast
99,132 GWh
65,869 GWh
2020 NC Load Forecast
2020 NC Load Forecast
71,347 GWh
58,586 GWh
2020 NC Retail Load Forecast 62,760 GWh
12.5% of 2020 NC Retail Load 7,845 GWh (DEC) 5,058 GWh (DEP)
2020 NC Retail Load Forecast 40,460 GWh
* 7,845 GWh (DEC) and 5,058 GWh (DEP) only represents the projected amount of Renewables and EE required to meet REPS compliance in 2021 based on the NC Retail load forecast for the year 2020. The cumulative EE and renewables energy on the DEP system is expected to be greater than what is represented here. Additionally, NC REPS allows 65% of the 2021 target to be met by EE and Out of State Renewable Energy Certificates (RECs). 1/23/2017
18
Technology Screening
1/23/2017
19
Technology Screening
1/23/2017
20
Economic Screening
Technologies Screened During Economic Screening1 Baseload
Peaking/Intermediate
Renewable
782 MW Ultra-Supercritical Pulverized Coal with CCS
166 MW 4 x LM6000 CT
2 MW / 8 MWh Li-ion Battery
557 MW 2x1 IGC with CCS
201 MW 12 x Reciprocating Engine Plant
5 MW Landfill Gas
2 x 1,117 MW Nuclear Units (AP1000)
870 MW 4 x 7FA.05 CT2
150 MW Wind – On-Shore (NonDispatchable)
576 MW 1x1x1 Advanced CC (Inlet Chiller & Fired)
5 MW Solar PV (Non-Dispatchable)
1,160 MW 2 x 2 x 1 Advanced CC (Inlet Chiller & Fired) 20 MW CHP
Notes 1: Units highlighted in Red font were screened into the quantitative analysis as potential supply-side resource options to meet future capacity needs 2: A 2x7FA.05 version was also included based upon the cost to construct 4 units
1/23/2017
21
Analytic Analysis
1/23/2017
22
IRP Process – Drivers
Key drivers were varied in System Optimizer (SO) to assess impacts on resource plans Potential Carbon Constraints 1. Carbon Tax on existing coal and gas units 2. System Carbon Mass Cap (System Mass Cap)
Nuclear license extensions All units relicensed in sensitivity
Coal and natural gas fuel prices (high / low sensitivities) Capital costs (high / low sensitivities) All assets (nuclear, CC/CT, Renewables) Renewables Only
Solar penetration (high / low sensitivities) In all cases, SO was able to select “economic” solar
Energy Efficiency (high sensitivity) Peak demand (high / low sensitivities) 1/23/2017
23
IRP Process – Portfolios (DEP)
Six portfolios were developed based on the results of the SO sensitivity analysis
1/23/2017
24
IRP Process – Portfolios (DEC)
Six portfolios were developed based on the results of the SO sensitivity analysis
1/23/2017
25
IRP Process – Portfolio Analysis
The six portfolios were evaluated under several “world view” scenarios using an hourly production cost model called PROSYM Carbon Tax/No Carbon Tax Scenarios1
Fuel
CO2
CAPEX
1
Current Trends
Base
CO2 Tax
Base
2
Economic Recession
Low Fuel
No CO2 Tax
Low
3
Economic Expansion
High Fuel
CO2 Tax
High
System Mass Cap Scenarios2
Fuel
CO2
CAPEX
Current Trends - CO2 Mass Cap
Base
Mass Cap
Base
4
Portfolios #1 - #4 were run under the Carbon Tax/No Carbon Tax Scenarios Portfolios #5 & #6 were run under the System Mass Cap Scenario Portfolios #1 - #4 would not meet the system mass cap constraints
1/23/2017
26
IRP Process – Portfolio Carbon Emission Profiles
Portfolio #4 (High CC) has the highest CO2 emissions over the long term
The system CO2 mass cap constraint is not met without nuclear relicensing, or new nuclear generation, in the late 2020s.
1/23/2017
27
IRP Process – Conclusions
DEP Portfolio #1 (CT Centric) is the least cost portfolio under a Carbon Tax paradigm The short-term build plan in Portfolio #1 would keep the Company on track if a system CO2 mass cap were implemented
DEC Portfolio #4 (High CC) is the least cost portfolio under a Carbon Tax paradigm, however its carbon foot print would not be sustainable under a System Carbon Mass Cap With Lee Nuclear included, Portfolio #1 (CT Centric) is the least cost portfolio followed by high EE and high renewable portfolios
1/23/2017
28
Results
1/23/2017
29
2016 IRP - DEP Expansion Plan – Base Case Duke Energy Progress Resource Plan (1) Base Case - Winter Resource Nuclear Uprates
Year 2017 2018
Sutton Blackstart CT
2019
Nuclear Uprates
2020
Nuclear Uprates
2021 2022
100 14 CHP
12
CHP Nuclear Uprates
2023 2024
CHP Asheville CC
2025 2026 2027 2028 2029 2030 2031 Notes:
22 560
22
22 New CC
6
New CT Nuclear Uprates
MW 8
Potential Asheville CT
1221 468
4
186
New CT
468
New CT New CT
468 468
New CT
1404
(1) Table includes both designated and undesignated capacity additions Future additions of renewables, EE and DSM not included
1/23/2017
DEP Base Case Resources Cumulative Winter Totals - 2017 - 2031 44 Nuclear 1781 CC 3562 CT 66 CHP 5453 Total
30
2016 IRP - DEC Expansion Plan – Base Case Duke Energy Carolinas Resource Plan (1) Base Case - Winter Resource Nuclear Uprates
Year 2017
MW 25
2018
Lee CC
CHP
683
43
2019
Hydro Refurb Return to Service Nuclear Uprates CHP
CHP
10
22
2020 2021
Bad Creek Uprate
2022 2023
Hydro Refurb Return to Service CHP
60
22 46.4
Bad Creek Uprate
46.4 New CC
Bad Creek Uprate
1221
46.4
2024
Bad Creek Uprate
46.4
2025 2026 2027 2028 2029 2030 2031
New CT
468
New Nuclear
1117
New Nuclear
1117
Notes:
6 22
(1) Table includes both designated and undesignated capacity additions Future additions of renewables, EE and DSM not included (2) Lee CC capacity is net of NCEMC ownership of 100 MW (3) Rocky Creek Units currently offline for refurbishment; these are expected return to service dates (4) Lee Nuclear in service dates are assumed to be Nov 2026 and May 2028
1/23/2017
DEC Base Case Resources Cumulative Winter Totals - 2017 - 2031 Nuclear 2319 CC 1904 CT 468 Hydro 202 CHP 109 Total 5002
31
2016 IRP - Joint System Energy by Resource Type
Carolinas Energy by Fuel Type - 2017
1/23/2017
Carolinas Energy by Fuel Type - 2031
32
Key Takeways
1/23/2017
33
Key Takeaways
Short Term Completion of 1,250 MWs of CC, 100 MWs CTs and 185 MWs Pumped Storage System impact of increasing amounts of Solar T&D, Unit Flexibility, Storage
Winter Planning Based on the LOLE study new generation need is driven by winter peaks.
First need best met with CC in DEC and DEP 2022 in DEP, 2023 in DEC New Gas Capacity and associated Infrastructure
Long Term Pursue 80 year license life for existing nuclear COL for Lee Nuclear
1/23/2017
34
Q&A
1/23/2017
35
