Decarbonizing the North American Northeast Power Sector: BAU or Integration? Pierre-Olivier Pineau, HEC Montreal Session 1: The implications of emerging technologies on electricity markets design and pricing Electricity Market Design in Transition Annual Workshop on the Economics of Electricity Policy and Markets Ivey Energy Policy and Management Centre October 18 th 2018 8h45am-5h30pm Ivey Tangerine Leadership Centre 130 King Street West, Toronto
UK 1,400 MW Netherland 700 MW 1,000 MW 1,500 MW 500 MW Denmark: 14 GW of Capacity 5 GW of Peak Load 500 MW 500 MW 1,500 MW 400 MW 30 TWh 42.5% wind 18% biofuels 2.5% solar 28.8% coal 7.3% gas 1% oil IEA (2017) 2
2016 2019: North American Renewable Integration Study 2017 3
Region: Load (TWh) Installed Capacity (GW) Population (million) Ontario: 136 TWh 39 GW 13.6 million Quebec: 189 TWh 45 GW 8.2 million HQT Maritime: 27 TWh 15 GW 2 million MAR NERC (2017) New York: 158 TWh 39 GW 19.8 million IESO NY ISO ISO- NE New England: 143 TWh 34 GW 15 million 4
Agenda 1. Motivation 2. Results 3. Model 4. Further Studies http://energie.hec.ca/npcc/ 5
1. Motivation 6
Paris Agreement, state and provincial climate goals, Under 2 Coalition 177 jurisdictions (37 countries) 1.2 billion people (16% of the world) $28.8 trillion in GDP (39% of the global economy) Under2 Coalition s shared goal: limiting GHG emissions to 2 tons per capita, or 80-95% below 1990 level by 2050. Under2mou (2017) 7
Region of Interest: Northeast Power Coordinating Council (NPCC) (5 sub-regions) Ontario (ON) 137 TWh Quebec (QC) 180 TWh Maritime (NB+NS+PE+NL) 39 TWh New York (NY) 161 TWh New England (NE) 124 TWh 8
Hourly Load data for 2016 9 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 1 161 321 481 641 801 961 1121 1281 1441 1601 1761 1921 2081 2241 2401 2561 2721 2881 3041 3201 3361 3521 3681 3841 4001 4161 4321 4481 4641 4801 4961 5121 5281 5441 5601 5761 5921 6081 6241 6401 6561 6721 6881 7041 7201 7361 7521 7681 7841 8001 8161 8321 8481 8641 QC NY NE ON Maritme
NPCC GHG Emissions 1990-2015 70 64.2 NY -55% 1990: 151 Mt 60 NE -40% Maritime -19% ON -76% 50 QC -86% 2015: 74 Mt Mt per year 40 30 20 10 25.6 44.7 14.6 29.2 26.6 11.8 6.2 80% below 1990: 30 Mt 0 1.5 0.2 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 10
45,000 40,000 Intalled Capacity by Region (2018) Total: 172 GW 35,000 30,000 25,000 20,000 15,000 10,000 Nuclear Oil Coal Natural gas Solar PV (Distributed) Biomass Hydro Solar PV Wind 5,000 0 NE NY MA QC ON EIA (2018), Statistics Canada (2018), IESO (2018) and HQ (2018) 11
What are the Gains from Integration? Physical integration: no transmission constraints between sub-regions Institutional integration: no local capacity constraint (NPCC only capacity requirement) 12
2. Results 13
Results: Annual Power System Cost ($Billion per year) No carbon cap Carbon cap 1.1 1.2 2.1 2.2 Transmission Transmission Unlimited Limited Gain Unlimited Limited Gain $0.1 $2.2 BAU $14.1 $14.2 Shared capacity Gain $12.5 $13.6 0.7% $1.1 $21.9 $24.1 $20.0 $23.3 8.1% $1.5 $0.6 $1.9 $0.8 11.0% 4.2% 8.8% 3.5% 9.3% $3.3 14.2% 14
Total Capacity in the BAU Scenarios (GW) 250 217 GW 200 Total NPCC Installed Capacity (GW) 150 100 50 30 GW 38 GW 65 GW 60 GW Energy Storage NG CCGT NG CT Nuclear Solar Wind New Hydro Hydro from 10 GW now 0 1.1 No cap, unc. T. 1.2 No cap, limited T. 2.1 Cap, unc. T. 2.2 Cap, limited T. 15
Total Capacity in the Shared Capacity Scenarios (GW) 250 203 GW 200 184 GW Total NPCC Installed Capacity (GW) 150 100 50 35 GW 39 GW 65 GW 60 GW Energy Storage NG CCGT NG CT Nuclear Solar Wind New hydro Hydro 0 1.1 No cap, unc. T. 1.2 No cap, limited T. 2.1 Cap, unc. T. 2.2 Cap, limited T. 16
Daily Production Profile BAU-Limited T Millions 2.5 2.0 2.5 2.0 Millions DR CT 1.5 1.0 0.5 0.0 1.5 1.0 0.5 0.0 CCGT Wind Solar ROR Reservoir Hydro Storage Losses Wind Curt. 0.41 correlation with load -0.5 5.7 TWh curtailed -0.5 Solar Curt. 1 19 37 55 73 91 109 127 145 163 181 199 217 235 253 271 289 307 325 343 361 17
Daily Production Profile Shared Capacity-Unlimited T. Millions 2.5 2.5 Millions 2.0 2.0 DR CT 1.5 1.0 1.5 1.0 CCGT Wind Solar 0.5 0.0 0.5 0.0 ROR Reservoir Hydro Storage Losses 0.62 correlation with load -0.5 2.0 TWh curtailed -0.5 Wind Curt. 1 19 37 55 73 91 109 127 145 163 181 199 217 235 253 271 289 307 325 343 361 18
3. Model 19
Objective Model: Capacity Expansion Minimize the annualized investment and operation costs, subject to: Meeting hourly load in each region Capacity constraints Linear programming model Transportation Model (no real power flows) 20
Hourly Load data for 2016 21 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 1 161 321 481 641 801 961 1121 1281 1441 1601 1761 1921 2081 2241 2401 2561 2721 2881 3041 3201 3361 3521 3681 3841 4001 4161 4321 4481 4641 4801 4961 5121 5281 5441 5601 5761 5921 6081 6241 6401 6561 6721 6881 7041 7201 7361 7521 7681 7841 8001 8161 8321 8481 8641 QC NY NE ON Maritme
8 Main Scenarios 1. No cap on emissions 1.1 Unconstrained Transmission 1.2 Limited Transmission 2. Carbon cap 2.1 Unconstrained Transmission 2.2 Limited Transmission Institutional integration BAU BAU BAU BAU Shared Capacity Shared Capacity Shared Capacity Shared Capacity Physical integration 22
Business as Usual vs. Shared Capacity BAU: each sub-region is under its own capacity constraint Nameplate Capacity per region (Thermal+Nuclear) max hours {Demand DR Production(Wind+Solar+Hydro) Battery(Discharge - Charge)} Shared Capacity: interconnections count Nameplate Capacity per region (Thermal+Nuclear) max hours {Demand DR Production(Wind+Solar+Hydro) Battery(Discharge - Charge) Transmission(Imports - Exports)} (only 1 global capacity NPCC constraint in the unconstrainted transmission case) 23
Technologies All legacy hydro from all sub-regions is used Run-of-river (ROR) in all 5 sub-regions Reservoir (RES) in Quebec Pumped hydro in New York Additional investment is required: Increamental hydro Thermal: natural gas combusion turbine (CT) and combined-cycle gas turbine (CCGT) Nuclear Wind Solar Storage Demand response / load shedding ($10,000/MWh) 24
4. Further Studies 25
Identified Options Optimal investment in transmission capacity Impact of load profile changes: increased electricity demand and higher peak Energy efficiency Sensitivity to technology costs Tighter emission cap (90% reduction, 95% reduction) Hydropower: Analysis of the system s value of reservoir storage Sensitivity to the amount of water storage availability Sensitivity to the amount of water available in a given year Representation of intra-region transmission bottlenecks and higher fidelity transmission system modeling (dc power flow) Climate change impacts Demand-side flexibility and endogenous investment in demand-side technologies Modeling of the energy transition over the years to capture the effects of policy decisions 26
Next Steps Links with ongoing initiatives: NARIS Pan-Canadian grid development initiatives Outreach: Canada-US Ontario & Maritimes 27
Conclusion and Take Aways Both physical and institutional integration have value With the current loads, yearly gains are about $4B Higher loads would be much more expensive to serve (new wind, solar + storage needed) 28
Internet energie.hec.ca Twitter @HECenergie Courriel energie@hec.ca MERCI! Nos partenaires 29