CONTINUING ACHIEVEMENT CLIMATE STRATEGY SUBMISSION

Transcription

1 ONTARIO ENERGY ASSOCIATION CONTINUING ACHIEVEMENT CLIMATE STRATEGY SUBMISSION NOVEMBER 14, 2018 To shape our energy future for a stronger Ontario.

2 ABOUT The Ontario Energy Association (OEA) is the credible and trusted voice of the energy sector. We earn our reputation by being an integral and influential part of energy policy development and decision making in Ontario. We represent Ontario s energy leaders that span the full diversity of the energy industry. OEA takes a grassroots approach to policy development by combining thorough evidence based research with executive interviews and member polling. This unique approach ensures our policies are not only grounded in rigorous research, but represent the views of the majority of our members. This sound policy foundation allows us to advocate directly with government decision makers to tackle issues of strategic importance to our members. Together, we are working to build a stronger energy future for Ontario. This report and the supporting analysis was developed by ICF based on the input and contributions of OEA members.

3 TABLE OF CONTENTS EXECUTIVE SUMMARY... 2 INTRODUCTION... 4 BACKGROUND CONTEXT... 6 ONTARIO S SIGNIFICANT GHG REDUCTION ACHIEVEMENTS TO DATE... 6 BREAKING DOWN ONTARIO S ENERGY CONSUMPTION & GHG EMISSIONS... 6 THE HIGH COST OF DE-CARBONIZATION ON THE ELECTRIC SYSTEM... 8 CDM HAS DRIVEN GHG EMISSION REDUCTIONS TO THE BENEFIT OF THE RATE PAYER SINCE NATURAL GAS MEETS PEAK ELECTRICITY DEMAND IN ONTARIO NATURAL GAS PROVIDES A CRITICAL SOURCE OF RELIABLE, AFFORDABLE, AND SUSTAINABLE ENERGY LOOKING FORWARD OPPORTUNITIES IN THE ELECTRICITY SECTOR Conservation & Demand Management (CDM) Delivered in Synchronicity with Storage and other Distributed Energy Resources Beneficial Electrification (BE) OPPORTUNITIES IN THE NATURAL GAS SECTOR Demand Side Management (DSM) Renewable Natural Gas (RNG) Natural Gas Fuel Switching NEXT STEPS REFERENCES Ontario Energy Association 1

4 EXECUTIVE SUMMARY Ontario has had tremendous success and has led the country in greenhouse gas (GHG) emission reductions since This submission outlines several ways Ontario can build on its past leadership and achieve significant additional GHG reductions, in a way that will be affordable for families and businesses, by leveraging Ontario s tremendous clean energy infrastructure. Since 2005 annual greenhouse gas (GHG) emissions in Ontario have declined by about 22%, from over 200 million tonnes (Mt) of CO2e to around 160 MtCO2e today. Emission reductions have been driven predominantly through energy conservation and energy de-carbonization. In Ontario, energy conservation measures include natural gas demand side management (DSM), electricity conservation demand management (CDM), and a broad array of codes and standards aimed at homes and vehicles. Decarbonization measures in Ontario include the shuttering of coal fired generating stations and their replacement with renewable generation supported by natural gas capacity, and ethanol blending as replacement for conventional transport fuel. These emissions reducing measures have come at significantly varying costs and effectiveness over the last 15 years. The Government of Ontario is in the process of developing a made-in-ontario climate change plan. With a goal of contributing to this plan, the OEA and its members have identified several measures that can be deployed immediately and contribute to a balanced solution ensuring our investments in climate action effectively balance greenhouse gas reductions while supporting economic prosperity and Ontario families. Through beneficial electrification (BE) excess low-ghg intensity energy can be leveraged to re-fuel demand currently met with higher emitting energy sources, through technology such as electric vehicles (EVs). BE drives value from Ontario s existing infrastructure investments and strategic deployment can result in both lower emissions and costs for rate payers. By 2035 BE measures could result in reductions of 8.2 MtCO2e/year. Ontario s legacy electricity conservation & demand management (CDM) programs can be transitioned & optimized to target demand reduction Ontario Energy Association 2

5 during peak electricity periods (MW) instead of broad annual energy reductions (MWh). CDM can be deployed as a resource, in combination with energy storage, distributed generation, and demand response, ensuring capacity shortfalls forecast for the mid-2020s are minimized cost effectively and emissions are reduced. By 2035 CDM & storage could result in reductions of 3.5 MtCO2e/year at reduced cost vs. generation, transmission, and distribution system infrastructure. Continuation of existing programs as well as incremental cost effective natural gas demand side management (DSM) can be deployed to the cost benefit of the rate payer, driving efficiency and significant reductions in emissions. By 2035 this measure could result in reductions of 6 MtCO2e/year. The introduction of domestic renewable natural gas (RNG) into the distribution system offers a carbon neutral source of natural gas for all sectors of the economy. By 2035 this measure could result in reductions of 4.2 MtCO2e/year. Natural gas fuel switching can drive emission reductions through the deployment of new technologies (e.g. CHP and transportation) and the connection of new communities to this lower emitting & cost alternative fuel. Natural gas value as a distributed generating resource can be leveraged to reduce costs and emissions. By 2035 these measures could result in reductions of 2.6 MtCO2e/year. As illustrated on the next page, these measures can begin to reduce Ontario s emissions immediately, and combine to reduce emissions by over 24 MtCO2e/year by 2035, equivalent to 15% of Ontario s current emissions. These measures are complementary and were developed with an appreciation of Ontario s electricity and natural gas systems working in synchronicity and the need for a balanced solution that puts people first, makes life more affordable for families, and takes Ontario s role in fighting climate change seriously. Ontario Energy Association 3

6 Emissions Reduction from All Measures Included in this Study Ontario Energy Association 4

7 INTRODUCTION With a goal of contributing to a made-in-ontario climate change plan, the OEA and its members have identified several measures that can be deployed immediately and contribute to a balanced solution that puts people first, makes life more affordable for families, and takes Ontario s role in fighting climate change seriously while ensuring our investments in climate action effectively balance greenhouse gas reductions while supporting economic prosperity and Ontario families. First, it is important to understand some context on the province s energy sector and emissions profile. This information both highlights how far Ontario has already come in reducing GHG emissions and highlights key considerations that future climate efforts will need to consider to minimize cost impacts on the province. Following this, the sections define how Ontario can reduce GHG emissions. Ontario Energy Association 5

8 BACKGROUND CONTEXT Under the Paris Agreement within the United Nations Framework Convention on Climate Change (UNFCCC), Canada committed to reducing GHG emissions from a 2005 level of 733 million tonnes of carbon dioxide equivalent (MtCO2e) by 30% to 517 MtCO2e by The Federal Government projects that with measures from Canada's clean growth and climate plan, including a tax on fossil fuel consumption, emissions will be 583 Mt CO2e, or 21% below 2005 levels. Limited provincial level context is provided related to specific measures and the emissions pathway, but this would still leave Canada 66 MtCO2e short of the target. The OEA is proposing an emissions reduction pathway that can deliver a significant portion of the required reductions at a low cost to Ontario families and businesses. Ontario s Significant GHG Reduction Achievements to Date Between 2005 and 2016, greenhouse gas (GHG) emissions in Ontario declined by about 22%, from 205 million tonnes (Mt) of CO2e to 161 MtCO2e. Canada s emissions have remained relatively stagnant (-2%) during the same period, at approximately 720 MtCO2e. Figure 1 highlights 2005 and 2016 emissions by province. Figure 1: Emissions by Province (2005 and 2016) (1) Breaking Down Ontario s Energy Consumption & GHG Emissions Emission reductions are driven predominantly through energy conservation and energy de-carbonization. In Ontario, energy conservation measures include natural gas demand side management (DSM), electricity conservation demand Ontario Energy Association 6

9 management (CDM) and a broad array of codes and standards aimed at homes (heating, cooling and lighting) and vehicles (fuel efficiency). Historical de-carbonization related measures in Ontario include the shuttering of coal fired generating stations and replacement with renewable generation supported by natural gas capacity within the electricity system, and ethanol blending as replacement for conventional transport fuel. Since energy consumption and GHG emissions correlate it is essential to appreciate the energy driving an economy to understand emission reduction pathways. Figure 2 below illustrates the contribution of natural gas, electricity, refined petroleum products, and other fuels (e.g. propane, industrial fuels) to Ontario s energy mix. Refined Petroleum Products (RPP) makes up the largest portion of energy demand and predominantly fuels the transportation segment. Natural gas makes up 30% of the energy mix and is used for heat in residential and commercial sectors and thermal energy for industry. Electricity makes up less than 16% of energy demand and is used throughout the economy. Ontario Energy by Source 2015 (3000 PJs) 8% 30% 46% 16% Natual Gas Electricity RPPs Other Figure 2: Ontario Energy by Source (2015) (2) The majority of GHG emissions in Ontario result from the consumption of refined petroleum products (RPP gasoline and diesel) for transportation. The use of natural gas for residential, commercial, industrial heat, and electricity generation makes up the second most common source of GHG emissions. Natural gas and transport fuel consumption, and the resulting GHG emissions, have remained relatively steady despite an increase in natural gas connected Ontario Energy Association 7

10 homes, buildings, and businesses, and an increase in transport activity (personal and freight) in the province. Emission reductions from the supply-side of Ontario s electricity system have been dramatic and well publicized, however the impact of conservation demand management (CDM) has been equally impressive. Ontario s legacy baseload nuclear and hydroelectric assets, coupled with shuttering of 6 GW of coal fired generation, and introduction of renewables (7 GW) and natural gas (5 GW), has resulted in an 80% reduction in our electricity s emissions intensity, from 0.2 tco2/mwh in 2005 to less than 0.04 tco2/mwh today. Annual electrical demand has declined by 10%, and coupled with the reduction in emissions intensity, has resulted in a 90% net reduction of electricity generation emissions, or -30 MtCO2e from 2005 levels, which can be seen in the change of the middle bar in Figure Ontario Emissions by Source 2005 and 2015 (MtCO2e/yr) Natural Gas Electricity RPP Figure 3: Ontario Emissions by Source (2005 and 2015) (3) The High Cost of De-Carbonization on the Electric System Electrical de-carbonization has come at considerable cost. In 2017 alone the renewable solar and wind contracts added $3.3B in cost to Ontario s electricity system while supplying 14.2 TWhs of electrical energy.(4) The 14.2 TWhs of intermittent energy provided by solar and wind displaced a mix of natural gas (predominantly) and non-emitting baseload generation. It therefore resulted in approximately 4-6 MtCO2e of emission reductions. Figure 4 illustrates this Ontario Energy Association 8

11 outcome by overlaying the 2016 non-emitting electric generation mix in blue, orange, and grey (excluding solar and wind and including non-emitting imports from Quebec) vs. domestic demand in green, to make the point that incremental supply fired by natural gas would have been required to meet the majority of demand (6,000 hours of 8,760) not provided by wind and solar. Therefore, the cost of the supply side GHG reductions through wind & solar contracts were $510-$800/tCO2e for This corresponds to around $ per year per residential customer, based on average electricity bills. Green peaks show demand that would be met by natural gas in absence of wind/solar Figure 4: Ontario s Nuclear, Hydro Generation, and Imports vs. Electricity Demand (5) Conservation Demand Management (CDM) has Driven GHG Emission Reductions to the Benefit of the Rate Payer Since 2005 In contrast to de-carbonization measures, electricity conservation demand side measures delivered between 2005 and 2020 resulted in over 200 TWhs (6) of lifetime electricity energy savings, and emission reductions between 12 MtCO2e (assuming average grid intensity is displaced) and 90 MtCO2e (where natural gas generation is displaced). The CDM programs were delivered at a total cost of $3.3 Billion (7) and at negative cost to the electrical system / rate payer and per tco2e. Funds deployed into CDM over the past 15 years have driven avoided electrical generation costs of over $5 Billion (assuming $25/MWh for commodity and operating cost for natural gas fired generation). Other electric demand focused measures such as storage, demand response, and distributed generation have influenced energy consumption and the associated emissions profile, illustrating significant potential, however their contribution to GHG emission reductions to date is modest. Ontario Energy Association 9

12 Table 1: Comparison of CDM and FIT from the Perspective of Cost and GHG Reduction 15 Years of CDM Programs One Year of Solar & Wind FIT Contracts Cost $3.3 Billion Cost $3.3 Billion From 2005 to Reduced Emissions by up to 90 MtCO2e Negative Cost (-$/tco2e) from avoided generation & customer savings Reduced emissions by 4 to 6 MtCO2e Emission Reductions >$500/tCO2e Natural Gas Meets Peak Electricity Demand in Ontario The combination of Ontario s baseload nuclear and hydroelectric assets, Annual Demand vs. Peak Demand conservation success, and investment in Demand is the rate at which electricity is intermittent renewables has resulted in an used, and is typically measured in kilowatts (kw). Peak demand is the electricity system that currently has more highest rate of electricity use during a non-emitting energy than is needed many period of time. hours of the year. The intermittent nature of the solar and wind generation unfortunately manifests in non-emitting energy being curtailed or sold outside Ontario at low price and limited impact on domestic emissions. Further, the intermittent nature of solar & wind energy reduces its reliability / capacity value to the system, and thus between 200 and 400 MW of natural gas fired generation is always called on to ensure system reliability. This is illustrated in Figure 5, and further when natural gas generation is graphed together with baseload, it can be seen that natural gas responds in situations when there is a shortfall between baseload and domestic demand. Blue peaks show natural gas consistently on the margin Figure 5: Surplus Baseload Generation and Natural Gas Generation (MW in each Hour) (5) Ontario Energy Association 10

13 When Ontario s non-emitting intermittent energy sources are providing more energy than required to meet demand (10 TWhs of excess in 2017), they could be made available to fuel switch off higher GHG intensity fuels or stored for use at times of peak demand. This resource can be used to reduce emissions at no/low incremental cost to the electrical system, providing an opportunity to drive added load to dilute fixed system costs, resulting in a lower cost per kwh. Natural Gas Provides a Critical Source of Reliable, Affordable, and Sustainable Energy Ontario s natural gas transmission, storage, and distribution systems provide access to an affordable, reliable, and plentiful supply of energy. Through the 1980 s and 1990 s, natural gas emerged as a replacement for higher emitting fuels (heating oil, propane, and coal) in the residential and commercial heating markets, and in the industrial sector for thermal energy. Per Figure 2, on an annual basis the natural gas system provides 33% (equivalent of 270 TWh or ~1,000 PJs) of the energy used in Ontario, twice that of electricity, to customers in Ontario at $0.03/kWh. Natural gas plays an important role as a backup for intermittent renewable electricity and in lowering electricity sector emissions, as a replacement for coal fired generation. It also provides Ontario s energy intensive industrial end users a continental advantage as a result of the low cost per unit of energy. In addition to providing energy at a low cost, it is critical to appreciate the role of natural gas in meeting peak winter energy demand in Ontario. As seen in Figure 6, Natural gas meets over 80% of winter peak day demand or the equivalent of 80 GWs of electrical capacity. Figure 6: Comparison of the Scale & Seasonality of Natural Gas and Electricity Demand (8) Ontario Energy Association 11

14 Since 2005, the price of natural gas has declined significantly, and Ontario s industrial, commercial, and residential end users and energy system operators have become more reliant on natural gas. During this same timeframe, annual demand has remained stable. This speaks to the success of natural gas DSM programs. Between 2005 and 2020, regulated DSM programs have delivered lifetime energy savings 1 of 78 billion m 3, resulting in the reduction of around 147 MtCO2e. Natural gas DSM measures also conserve electricity, and over this same period have contributed 14 TWh of lifetime electricity savings, almost 6 MtCO2e. Despite a declining energy commodity cost challenging cost effectiveness, these savings have been deployed within a budget of $1.2 Billion, and at a negative cost to the rate payer and per tco2e reduced. It is important to note that compared to natural gas as a source for electrical energy (0.42 tco2e/mwh), the emissions intensity of natural gas consumed in the home is approximately 50% lower (0.2 tco2e/mwh), and natural gas used in combined heat and power (CHP) is 30% lower (0.27 tco2e/mwh). The energy storage and capacity afforded by natural gas in Ontario can be further leveraged to improve energy system affordability, reliability, and sustainability, while still contributing to emissions reductions objectives. 1 Gross m 3 savings are the total savings from all energy efficiency measures and actions that occurred during the noted timeframe. Ontario Energy Association 12

15 LOOKING FORWARD With a goal of contributing to a made-in-ontario climate change plan, the OEA and its members have identified several measures that can be deployed immediately and contribute to a balanced solution that puts people first, makes life more affordable for families, and takes Ontario s role in fighting climate change seriously while ensuring our investments in climate action effectively balance greenhouse gas reductions while supporting economic prosperity and Ontario families. Ontario s electrical system is long on non-emitting energy much of the year and is expected to have an adequate supply of energy to meet energy demand forecast through to Through beneficial electrification (BE) measures, such as electric vehicles (EV), this excess low GHG intensity energy can be leveraged to re-fuel demand currently met with higher emitting energy sources. BE drives value from existing infrastructure investments and the non-emitting intermittent electrical energy; limiting impact on peak / capacity requirements and reducing emissions at no/low cost. By 2035 BE measures could result in reductions of 8.2 MtCO2e/year. See Section 1.2 for additional context and detail. Despite being long on forecast annual electrical energy out to 2035, the IESO projects a shortfall of 1,400 MW by 2023 and 3,700 MW by In tandem with BE, Ontario s electrical legacy conservation & demand management (CDM) can be transitioned / optimized to focus on demand reduction during peak electricity periods (MW) vs broad annual energy reductions (MWh). CDM can be deployed as a resource, in combination with energy storage, distributed generation, and demand response, ensuring capacity shortfalls forecast for mid-2020s are minimized cost effectively. By 2035 CDM & storage could result in reductions of 3.5 MtCO2e/year. See Section 1.1 for additional context and detail. Continuation of existing programs and incremental cost effective natural gas demand side management (DSM) can be deployed to the benefit of the rate payer driving efficiency and significant reduction in emissions at no/low cost. By 2035 this measure could result in reductions of 6 MtCO2e/year. See Section 2.1 for additional context and detail. Ontario Energy Association 13

16 The production and blending of domestic renewable natural gas (RNG) into the distribution system offers a carbon neutral source of natural gas for all sectors of the economy. By 2035, this measure could result in reductions of 4.2 MtCO2e/year. See Section 2.2 for additional context and detail. Natural gas fuel switching can drive emission reductions through the deployment of new technologies (e.g. CHP), the connection of new communities via pipelines and deliveries of liquefied natural gas (LNG), and compressed natural gas (CNG) as a fuel alternative to transportation fuel. Further, with an appreciation for not only the reliability and affordability of natural gas, but also the sustainability of natural gas delivered for use at the energy end user natural gas value as a distributed generating resource can be leveraged to reduce peak load within the electricity sector. By 2035 these measures could result in reductions of 2.6 MtCO2e/year. See Section 2.3 for additional context and detail. As illustrated below in Figure 7, these measures can begin to reduce Ontario s emissions immediately, and combine to reduce emission by over 24 MtCO2e/year by 2035, equivalent to 15% of Ontario s current emissions. These measures are complimentary and were developed with an appreciation of Ontario s electricity and natural gas systems working in synchronicity to meet total annual demand (~400TWhs or ~1500PJs) for energy, as well as winter (natural gas 80GW) and summer (electricity 25GW) peak demand. Figure 7: Emissions Reduction from All Measures Ontario Energy Association 14

17 The following sections (1.1 through 2.3) provide additional details on the measures listed above. Looking out more than 15 years to 2035, innovation & technology advancement will be critical to both maximizing the savings from these measures and providing additional future technology options to drive emission reductions. 1. Opportunities in the Electricity Sector The key electricity related opportunities to be leveraged for an Ontario provincial climate strategy include; Deployment of conservation and demand management (CDM) in synchronicity with storage and other distributed energy resources, and Beneficial electrification (BE) measures such as electric passenger vehicles (EV) and other strategic opportunities. By 2035 these measures could be deployed to ensure emissions from the electricity sector are minimized and avoid GHG emissions in other sectors of the economy (e.g. transportation), resulting in emission reductions of 11.8 MtCO2e/year, as shown below in Figure 8. Figure 8: Emissions Reduction from Electricity Measures 1.1 Conservation & Demand Management (CDM) Delivered in Synchronicity with Storage and other Distributed Energy Resources Ontario s Conservation & Demand Management (CDM) framework enables the energy efficiency and demand response programs that serve the province s electricity users. Guided by policy direction from the Ministry of Energy, Northern Development and Mines (MENDM), the Independent Electricity System Operator (IESO) leads the development and administration of these Ontario Energy Association 15

18 programs. The programs are then delivered by the province s 60+ Local Distribution Companies (LDCs) as well as the IESO. In Ontario, electricity costs have risen significantly over the years, however CDM programs have helped mitigate this rise playing a critical role in both minimizing overall system costs for all electricity rate payers and helping program participants reduce their individual bills. Despite the low GHG intensity of Ontario s electricity generation mix (0.04 tco2e/mwh), CDM programs have achieved significant GHG emission reductions when natural gas generation is offset by demand-reducing CDM. As illustrated earlier, natural gas has been on margin in Ontario over the past decade, and this trend is forecast to continue as nuclear units retire and are refurbished through Despite being long on forecast annual electrical energy out to 2035 the IESO projects a shortfall of 1,400 MW by 2023 and 3,700 MW by As can be seen in the recent IESO planning outlook in Figure 9, this shortfall would be even larger unless existing gas generators contract lifetimes can be extended. Figure 9: Forecast Shortfalls in Ontario Capacity from IESO Planning Outlook (9) However, with an appreciation of the electricity system supply/demand dynamic comes the conclusion that CDM must transition from a measure focused on energy savings today to a measure focused on peak (or capacity) savings. Further, CDM should be considered as, and along with, other distributed energy resources (DERs) including storage, distributed generation, and demand response. CDM, Energy Storage, & DERs: Valued as a System Resource When coupled with other distributed energy resources (DERs), such as distributed generation, demand response, and energy storage, CDM can be designed and deployed to ensure that capacity shortfalls forecast for the mid- 2020s are minimized cost effectively. Taking into consideration the system benefits at the provincial generation- and transmission-level, as well as the Ontario Energy Association 16

19 locational benefits at the distribution level, CDM and other DERs can be valued as a resource. They should compete as a resource against traditional infrastructure options with the goal of system optimization considering affordability, reliability, and sustainability. This transition is not new or only relevant in Ontario. The consideration of DERs as cost effective Non-Wires Alternatives (NWA) are gaining precedent in many jurisdictions. When peak demand is driving system shortfalls and infrastructure spending, NWAs seek to identify the lowest cost option to meet the required load relief. NWAs are targeted efforts aimed at deploying a mix of DERs that has been customized to avoid a specific system shortfall. This can achieve savings for rate payers by only pursuing NWAs in areas where the infrastructure spending can be avoided, and only NWAs that are lower cost and risk than the infrastructure option. Figure 10 demonstrates this concept, where if a shortfall in capacity (black line) is anticipated, it may be possible to stack a portfolio of different resources to meet that demand at a lower cost than building new infrastructure. Figure 10: Example of Distributed Energy Resources Used to Avoid a Forecast Shortfall in Electricity Supply To ensure full consideration of DERs / NWAs critical insight into distribution system constraints and costs must be afforded. This speaks to the role of the LDCs for context on their service territories. These distribution costs will be critical to maximizing the value of a more targeted CDM framework and DERs more broadly. Ontario Energy Association 17

20 CDM and Energy Storage Related Emission Reductions Figure 11 showcases the potential for CDM to contribute to a provincial climate change strategy, beginning with a new CDM framework in 2021 and growing to a potential reduction of 3.1 MtCO2e per year by 2035, equivalent to 1.9% of Ontario s total emissions in These GHG reductions will be achieved at a negative cost to Ontarians, as paying for CDM to avoid generation (~$25/MWh) alone can be cost effective targeted CDM can create further transmission and distribution system benefits Conservation & Demand Management (CDM) Mt CO2e / year OPO Forecast Savings from 'Future Programs & Codes and Standards', beyond 2020 (TWh) Forecast Savings from Future CDM Programs 58% of total forecast Avoided Emissions with Gas on Margin (Mt CO₂e / 0.42 Mt/MWh Figure 11: Forecast Emission Reductions from Conservation & Demand Management The estimates for future CDM savings in the table above are based on the IESO s Ontario Planning Outlook (OPO), which accounts for 'planned savings from future programs & Codes and Standards' of 12.8 TWh by It is assumed that the CDM portion makes up 60% of this category, or 7.4 TWh once the impact of codes and standards is removed. The avoided emissions in the exhibit above use a marginal emission intensity based on natural gas generation (0.42 MtCO2e/MWh). Savings claimed under CDM programs are net of free riders (the portion of participants that evaluation reports determine would implemented a measure in a business as usual scenario) and represent only the level of improvement above what is required by codes and standards. CDM savings are therefore representative of incremental performance that would not have been achieved without program support. Figure 12 showcases the potential for energy storage (as an example of a DER) to contribute to a provincial climate change strategy, with annual reductions of 0.4 MtCO2e per year by 2035, equivalent to 0.3% of Ontario s total emissions in Ontario Energy Association 18

21 2016. The focus of this storage would be system cost savings through reduced peak demand, with emission reductions as an add-on benefit. Energy Storage Mt CO2e / year Incremental Electricity Storage Capacity (MW) Annual Energy Peaking Shifting (TWh) Avoided Emissions with Gas on Margin (Mt CO₂e / 0.42 Mt/MWh Figure 12: Forecast Emission Reductions from Energy Storage This illustrative level of energy storage growth represents a volume that could be used to better create system value (reliability, affordability, and sustainability) during periods where Ontario is long on non-emitting intermittent wind and solar; displacing significant natural gas fired peak generation, as well as transmission and distribution system infrastructure. As is the example in the IESO s report on energy storage, this peak shifting capacity would displace gasfired generation for 3 hours each day, allowing off-peak baseload and intermittent renewables to instead meet this portion of peak demand. Finally, it is important to understand that this transition to a new form of CDM and DER integration with system options will not take place instantaneously As efforts are transitioned to a capacity focus CDM program continuity is critical to leveraging the value that targeted CDM / DERs / NWAs can bring to the province over the next 15 years. The energy end-user can be challenging to engage and influence to economic-optimizing behavior. Market penetration and customer connectivity of existing CDM programs must be leveraged to minimize cost and drive performance of the programs of the future. This transition to a more targeted CDM brings many benefits, but also some challenges, including the following: NWA opportunities will not be evenly distributed among LDC service territories - the value of the same technology / response will be very different in each application Disconnect between system cost and rate payer burden: Energy Cost (low) vs. System Cost (high) Ontario Energy Association 19

22 1.2 Beneficial Electrification (BE) Leveraging Ontario s excess supply of non-emitting electrical energy provides an opportunity to fuel switch from higher emitting fossil fuel powered vehicles and equipment with electrically driven alternatives. This can result in significantly lower emissions as well as better value created from domestic usage of intermittent renewables vs export. BE is a targeted measure aimed at driving emission reductions affordably and reliably. The key factor to making electrification beneficial for Ontario is to avoid an increase in peak demand (MW) and thus increases to system costs. With no/low impact on system costs, adding new off-peak load (MWh) can reduce average system cost ($/unit of energy) and better leverage existing intermittent capacity (wind and solar). How BE Can Reduce Electricity Charges Adding new off-peak electricity loads can better utilize existing resources and spread the fixedsystem costs over more units of energy sold. Technologies like Electric Passenger Vehicles can lend themselves well to this model. If well planned, significant load can be added to the system with limited impact on generation, transmission, and distribution systems, while the customer can benefit from offset transport fuel cost savings in the region of $1,000 / year. Beyond the EV, a range of other transit and non-road electrification opportunities could be launched beneficially and are illustrated herein. Electrification of peaky types of equipment, like residential and commercial space heating, have been illustrated in the past for Ontario; these peaky load types are not considered here, as significant increases in their adoption would drive up peak demand and energy costs. Electric Passenger Vehicles Figure 13 showcases the potential for passenger EVs to contribute to a provincial climate change strategy. Starting from minimal EV adoption today and building up to 1.5 million EVs and a potential reduction of 6.8 MtCO2e per year by 2035, equivalent to 4.2% of Ontario s total emissions in These GHG reductions can be achieved at no / low cost, given the ability to charge EVs offpeak and the customer value proposition of reduced transport fuel expenditures. There were approximately 7.6 million light duty vehicles on Ontario s roads in 2015; 1.5 million EVs would represent roughly 20% of light duty vehicles. Ontario Energy Association 20

23 Mt CO2e / year Electric Passenger Vehicles (EVs) Number of EVs (millions) Electricity Consumption 4.1 MWh/EV Net Emissions Reductions with Avg. Grid Intensity (Mt CO₂e / year) Figure 13: Forecast Emission Reductions from Electric Passenger Vehicles The scenario illustrated would results in an additional load of 4.1 MWh per year per passenger vehicle, which avoids about 4 tco2e per year per passenger vehicle, based on Ontario s average grid emission intensity. Assuming avoided petroleum costs of $1,000 / year and 4 MWhs / year of electrical consumption, even at Ontario s current off peak rate of 6.5 cents / kwh an EV could drive customer energy savings of $740 / year. The scale of electrification envisioned in Figure 13 re-enforces the need for EVs to be deployed strategically, in tandem with a plan to address possible distribution system impacts. To ensure EVs as a BE measure are optimized, LDCs need to have a role with customers and access to data to be able to do this effectively. Finally rate structure options could be considered to ensure system benefits are maximized and customers are incentivized with an appreciation of system cost impacts. Electrification of Non-road Equipment & Transit Beyond traditional EVs there are a number of other BE opportunities where electric options compete with diesel/propane equivalents, offering significant potential to achieve cost-effective GHG savings by increasing electric uptake. These include transit electrification (bus fleets and passenger trains) as well as non-road equipment categories (e.g. forklifts in warehouses). Figure 14 below showcases the potential for other BE categories to contribute to a provincial climate change strategy. This range of opportunities offers a potential reduction of 1.4 MtCO2e per year by 2035, equivalent to 0.9% of Ontario s total emissions in Ontario Energy Association 21

24 Mt CO2e / year Other Beneficial Electrification (BE): Non-road Equipment & Transit Electricity Consumption of New Non-Road Electric Equipment (TWh) Electricity Consumption of New Electric Commuter Trains (TWh) Net Emissions Reductions with Avg. Grid Intensity (Mt CO₂e / year) Figure 14: Forecast Emission Reductions from Beneficial Electrification of Non-road Equipment & Transit The non-road forecast of 1.4 TWh by 2030 is based on a 2018 screening of the potential for emissions abatement in Ontario through non-road BE programs. This includes forklifts, golf carts, pushback tractors, tow tractors, belt loaders, airport ground power units, transport refrigeration units (TRUs), truck stop electrification (TSE). These numbers do not include the potential for electrification of mining equipment, port cranes, agricultural equipment, or other non-road opportunities. The transit electrification estimates for 0.5 TWh incremental load by 2035 from new electric trains, is an estimate for the province scaling up from a study showing that the electrification of Toronto's Metrolinx network would add TWh of load to the grid. Much of this additional load could be met through off-peak charging, and hence emission reductions would be based on use of average grid intensity. Some of the electrification measures, such as transit during peak hours, must be assessed and planned for more than others to ensure that the electrification is beneficial and does not add to system cost. 2. Opportunities in the Natural Gas Sector The key natural gas opportunities to be leveraged for a provincial climate strategy include; Demand side management (DSM), Renewable natural gas (RNG), and A variety of natural gas fuel switching options including combined heat & power (CHP), transit bus, refuse truck, & heavy transportation fuel switching, and gas expansion to new communities. Ontario Energy Association 22

25 By 2035 these measures could result in emission reductions of 12.7 MtCO2e/year, as shown below. Figure 15: Emissions Reduction from Natural Gas Measures Natural gas represents both a critical source of affordable energy and a significant portion of GHG emissions in the province. This emphasizes the importance of opportunities like DSM and RNG which allow Ontarians to achieve significant GHG reductions, while continuing to benefit from this affordable and reliable fuel. Natural gas is also less GHG-intensive than other fossil fuels, so there is an opportunity for Ontarians to convert from diesel, fuel oil, and propane to take advantage of this lower emitting fuel. 2.1 Demand Side Management (DSM) Ontario s Demand Side Management (DSM) natural gas energy efficiency programs have served the province s residential, commercial, institutional, industrial, and low-income gas-users since Guided by policy direction from the MENDM, the Ontario Energy Board (OEB) sets the framework guidelines and approves the programs planned by Enbridge & Union Gas for delivery to their customers. Across North America, natural gas prices have dropped significantly over the last ten years, yet Ontario s gas utilities continue to find new cost-effective DSM opportunities to help Ontarians reduce their consumption, drive down their costs, and reduce GHG emissions. Figure 16 showcases the potential for DSM to contribute to a provincial climate change strategy. This starts from the launch of a new DSM framework in 2021 and builds up to a potential reduction of 6 MtCO2e per year by 2035, equivalent to 3.7% of Ontario s total emissions in These GHG reductions Ontario Energy Association 23

26 will be achieved at a negative cost to Ontarians, since paying for DSM to avoid natural gas consumption is cheaper than paying for its commodity cost. Demand Side Management (DSM) Mt CO2e / year Annual Natural Gas Savings (billion m3 / year ) Avoided Natural Gas Emissions (Mt CO₂e / year) Figure 16: Forecast Emission Reductions from Demand Side Management (DSM) The estimates for future DSM savings in the table above are based on the OEB s Conservation Potential Study, which shows significant opportunity to drive additional cost-effective savings. The Semi-Constrained budget scenario shows DSM achieving incremental annual savings of almost 2.2 billion m 3 /year between 2021 and This level of savings is assumed here to be split evenly between each of the years, with annual savings building up linearly at a rate of 215 million m 3 /year. This same rate of savings is assumed to continue from 2031 to 2035, while 2019 and 2020 are kept blank as these incremental savings do not include any impacts from the current DSM framework, which runs until the end of To put these numbers in context, the total annual DSM savings achieved here by 2035 (3.2 billion m 3 /year), would represent roughly 14% of 2017 natural gas consumption in Ontario (22.6 billion m 3 /year). Natural gas utilities only claim DSM savings based on the amount their program measures are above the level of efficiency that a customer would have normally installed (base-case). As an example, if a customer is replacing an 80% efficient furnace with a 95% efficient furnace, but the standard for new furnaces is 90% efficiency, then the utility claims 5% incremental savings. This highlights that beyond the GHG reductions counted in DSM results, energy efficiency is driving even greater savings for Ontarians. To optimize DSM performance, scale, precedent, and system benefit, it is important for the province s gas utilities to play a role in the planning, design, and delivery duties. Ontario Energy Association 24

27 2.2 Renewable Natural Gas (RNG) RNG is a renewable source of non-fossil based methane that would allow the province to continue using its existing natural gas distribution network to deliver a decarbonized energy supply making the switch seamless for Ontarians and continuing to reliably serve peak energy needs. RNG is carbon neutral while its combustion releases emissions, this carbon would have been emitted to the atmosphere where not captured and can therefore be considered non-emitting. This opportunity for made-in-ontario energy is showcased in Figure 17. Farms, landfills, and water & waste treatment facilities are some of the sites that produce methane-rich biogas. This biogas can be cleaned to pipeline caliber RNG and injected into natural gas distribution systems, displacing fossil derived natural gas. In North America, RNG has recently gained significant momentum of the 76 operational RNG facilities in the U.S. and Canada, 35 of them were built in the last four years. The main drivers of these RNG projects have been the Renewable Fuel Standard (RFS) across the U.S. and California s Low Carbon Fuel Standard (LCFS), which provide monetary credits for RNG used as a transportation fuel. The success of these programs demonstrate that RNG production can rise rapidly with the proper regulatory enablement and cost-recovery options. Figure 17: RNG and Ontario s Circular Economy (10) While there are currently 35 Anaerobic Digestion (AD) facilities in Ontario producing biogas, only one of these is upgrading the biogas to pipeline quality RNG; the other facilities opt to consume it on-site. Several studies have estimated the potential for significant volumes of RNG in Ontario but more work is needed to quantify and validate this potential, and to develop new technologies like gasification that unlock greater potential. In the Ontario Ministry of Energy's 2016 Fuels Technical Report, Scenario F forecasts RNG supplying 155 PJ of natural gas for Ontario by 2035, while Scenario E forecasts 78 GJ of RNG. These numbers build on previous estimates for Ontario, including an Alberta Innovates study (May 2011) and a Canadian Biogas study (Dec 2013). Actual market transformation and the corresponding RNG Ontario Energy Association 25

28 availability will significantly depend on evolving policy and technology development support. Figure 18 showcases the potential for RNG to contribute to a provincial climate change strategy, with annual reductions of 4.2 MtCO2e per year by 2035, equivalent to 2.6% of Ontario s total emissions in Renewable Natural Gas (RNG) Mt CO2e / year Volume of Annual RNG Supply (billion m3) Net Emissions Reductions (Mt CO₂e / year) Figure 18: Forecast Emission Reductions from Renewable Natural Gas The final assumption of 85PJ (2.2 billion m 3 ) of RNG in 2035 was chosen to represent roughly 10% of 2017 natural gas consumption in Ontario (22.6 billion m 3 ). This volume is illustrative and more pilot programs are required to demonstrate provincial and regional potential. The work to date indicates that RNG can play a material role in decarbonizing Ontario s energy supply. The benefits from RNG s ability to reduce emissions while leveraging the existing natural gas distribution networks cannot be understated. Ontario has already invested heavily in this infrastructure, to provide reliable and affordable energy for critical needs like heating. Despite a low natural gas commodity price, there are ways to drive RNG uptake, develop proof of concept pilots, and limit impact to rate payers. For example, one win-win approach would involve affording RNG to Ontarians as a voluntary option whereby individual customers could choose to pay a premium for carbon neutral energy and the utility would facilitate securing supply. This approach has already been deployed successfully in British Columbia and Quebec. Regulatory enablement for Ontario s gas utilities is critical to stimulating the RNG market. Additionally, new technology development will play an important role in RNG s future. This includes the gasification technologies that would allow more types of biomass & waste products to be converted to RNG, as well as emerging power-to-gas technologies where surplus electricity from the grid can be used to produce hydrogen that is then injected into the natural gas pipeline Ontario Energy Association 26

29 taking advantage of existing natural gas infrastructure investments to serve as energy storage for the province s peaky and intermittent sources of electricity. 2.3 Natural Gas Fuel Switching The three measures included here illustrate the emission reduction potential for natural gas fuel switching through the deployment of new technologies (e.g. CHP), the connection of new communities via pipelines and deliveries of liquefied natural gas (LNG), and compressed natural gas (CNG) as a fuel alternative to transportation fuel. Further, with an appreciation for not only the reliability and affordability of natural gas, but also the sustainability of natural gas delivered for use at the energy end user. Importantly, to enable the transition of the market to RNG, wider deployment of CNG fueling stations will be required to drive the business case for fleet owners and operators. Combined Heat & Power (CHP) CHP is a form of distributed generation that allows customers to generate their own electricity and steam from a combined process. Through this combination, CHP units are more efficient than technology focused on electricity generation alone or from dedicated boilers on-site to generate thermal energy. CHP is a proven technology, widely used to improve the affordability of energy costs and the resilience of electricity supply during grid power outages, typically installed by large customers like industry or hospitals. Until July 2018 behind-the-meter gas-fired CHP projects were eligible for incentives through Ontario s CDM programs but were excluded to align the (previous) government s climate change policies. As with the CDM opportunity, the contribution of CHP to GHG reductions depends on what type of grid electricity generation is being displaced. The GHG intensity of CHP is in the region of tco2e/mwh, lower than the 0.42 tco2e / MWh emissions from Ontario s marginal source of electric energy, a natural gas in a combined cycle generating station. It was shown in Section 1.1 that natural gas fired generation is regularly on the margin and will be relied upon even more in the future. Therefore, increased CHP adoption will lower overall provincial emissions. There are also significant locational benefits from CHP s ability to provide targeted distributed generation, as a DER and part of the NWAs discussed previously. For example, if a constrained part of the electricity system requires an infrastructure (transmission or distribution level) upgrade to meet a growing Ontario Energy Association 27