STUDY NO. 187 JULY 2020 OPPORTUNITIES AND CHALLENGES FOR DISTRIBUTED ELECTRICITY GENERATION IN CANADA
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Canadian Energy Research Institute
OPPORTUNITIES AND CHALLENGES FOR DISTRIBUTED ELECTRICITY GENERATION IN CANADA
Opportunities and Challenges for Distributed Electricity Generation in Canada
Authors: Ganesh Doluweera, Victor Gallardo, Hamid Rahmanifard, Eranda Bartholameuz
Recommended Citation (Author-date style): Ganesh Doluweera, Victor Gallardo, Hamid Rahmanifard, Eranda Bartholameuz. 2020. “Opportunities and Challenges for Distributed Electricity Generation in Canada.” Study No. 187. Calgary, AB: Canadian Energy Research Institute. https://ceri.ca/assets/files/Study 187 Full Report.pdf
Recommended Citation (Numbered style): G. Doluweera, V. Gallardo, H. Rahmanifard, E. Bartholameuz, 2020 “ Opportunities and Challenges for Distributed Electricity Generation in Canada.” Study No. 187. Calgary, AB: Canadian Energy Research Institute. https://ceri.ca/assets/files/Study 187 Full Report.pdf
Copyright © Canadian Energy Research Institute, 2020 Sections of this study may be reproduced in magazines and newspapers with acknowledgment to the Canadian Energy Research Institute
Acknowledgments: The authors of this report would like to extend their thanks and sincere gratitude to all CERI staff involved in the production and editing of the material. The authors of this report acknowledge the following for providing helpful insights for this study. Responsibility for any errors, interpretations, or omissions lies solely with CERI.
• Abbas Ali Beg, ATCO • Richard Laszlo, Laszlo Energy Services (LES) • Rob Sinclair, EnerStrat Canada
ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE Founded in 1975, the Canadian Energy Research Institute (CERI) is an independent, registered charitable organization specializing in the analysis of energy economics and related environmental policy issues in the energy production, transportation, and consumption sectors. Our mission is to provide relevant, independent, and objective economic research of energy and environmental issues to benefit business, government, academia, and the public.
For more information about CERI, visit www.ceri.ca
CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: [email protected] Phone: 403-282-1231
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Table of Contents
List of Figures ...... vii List of Tables ...... ix Acronyms and Abbreviations ...... xi Executive Summary ...... xiii Chapter 1: Introduction ...... 1 1.1 Scope & Objectives ...... 3 Chapter 2: Review of Distributed Generation Programs, Policies and Regulations ...... 5 2.1 British Columbia...... 5 Electricity System ...... 5 Customer-owned and Central Energy Procurement DG Policy Framework ...... 7 Residential and Commercial Rate Structure ...... 8 2.2 Alberta ...... 9 Electricity System ...... 9 Customer-owned DG Policy Framework ...... 11 Residential and Commercial Rate Schedules ...... 12 2.3 Saskatchewan ...... 13 Customer-owned and Central Energy Procurement DG Policy Framework ...... 15 Residential and Commercial Rate Schedules ...... 16 2.4 Manitoba ...... 17 Customer-owned and Central Energy Procurement DG Policy Framework ...... 18 Residential and Commercial Rate Schedules ...... 19 2.5 Ontario ...... 20 Customer-owned and Central Energy Procurement DG Policy Framework ...... 21 Residential and Commercial Rate Schedules ...... 22 2.6 Quebec ...... 22 Electricity System ...... 22 Customer-owned and Central Energy Procurement DG Policy Framework ...... 25 Residential and Commercial Rate Structure ...... 26 2.7 New Brunswick ...... 26 Electricity System ...... 26
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Customer-owned and Central Energy Procurement DG Policy Framework ...... 28 Residential and Commercial Rate Schedules ...... 28 2.8 Nova Scotia ...... 29 Electricity System ...... 29 Customer-owned and Central Energy Procurement DG Policy Framework ...... 30 Residential and Commercial Rate Schedules ...... 31 2.9 Newfoundland and Labrador ...... 31 Electric System ...... 31 Customer-owned and Central Energy Procurement DG Policy Framework ...... 33 Residential and Commercial Rate Schedules ...... 33 2.10 Prince Edward Island (PEI) ...... 34 Electric System ...... 34 Customer-owned and Central Energy Procurement DG Policy Framework ...... 35 Residential and Commercial Rate Schedules ...... 36 2.11 Provincial Summary Tables ...... 36 Chapter 3: Assessment of Technology Options for Distributed Generation ...... 41 3.1 Selection of DG Technologies for the Assessment ...... 41 3.2 Solar PV for Distributed Generation ...... 42 Solar PV Assessment Procedure ...... 43 Solar PV DG System Assessment Results ...... 45 3.3 Biomass and Municipal Solid Waste for Distributed Generation ...... 51 Biomass & MSW based DG System Assessment Procedure ...... 52 Biomass and MSW based DG System Assessment Results ...... 53 3.4 Natural Gas Fired Micro Combined Heat and Power Systems for Distributed Generation ...... 55 Natural Gas Micro CHP Systems and DG Policies and Programs in Canada...... 56 Natural Gas Micro CHP Assessment ...... 57 Natural Gas Micro CHP Assessment Results ...... 60 3.5 Dependable Capacity Value of Distributed Generation Systems ...... 62 Chapter 4: Private and Public Cost-Benefit Analysis ...... 65 4.1 Private Cost-Benefit Analysis of Solar PV Systems ...... 65 4.2 Public Cost and Benefits Analysis of Customer-Owned DG ...... 69 Model Background ...... 69
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Total Resource Cost Test ...... 70 Illustrative Total Resource Cost Test ...... 72 Ontario & Nova Scotia ...... 79 Summary of Results & Discussion...... 80 Chapter 5: Conclusions ...... 83 Bibliography ...... 87
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List of Figures
Figure E.1: LCOE of a Small Commercial Solar PV System (50kWdc) ...... xiv Figure 2.11.1: Residential Customers Cost of Electricity Across Canada ...... 39 Figure 3.1: Solar PV DG System Production and Economic Assessment Process ...... 44 Figure 3.2 Population Centres for DG Assessment ...... 45 Figure 3.3: Monthly Production of a 1kW Solar PV System Installed in Different Population Centers ...... 47 Figure 3.4: LCOE of a Residential Solar PV System (5kWdc) ...... 48 Figure 3.5: LCOE of a Small Commercial Solar PV System (50kWdc) ...... 49 Figure 3.6: LCOE of a Large Commercial Solar PV System (150kWdc) ...... 50 Figure 3.7: A Typical Building-Integrated Micro CHP System ...... 55 Figure 3.8: Daily Demand Profile for a) residential building and b) commercial building ...... 58 Figure 3.9: Monthly Demand Profile for a) residential building and b) commercial building ...... 59 Figure 3.10: Electricity Production Profile of Natural Gas Micro CHP Systems ...... 61 Figure 3.11: Average Solar PV Capacity Value in Different Provinces ...... 63 Figure 4.1: DG Adoption Rate in BC (2020 – 2040) ...... 73 Figure 4.2: DG Adoption Rate in AB (2020 – 2040) ...... 76
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List of Tables
Table E.1: Customer-Owned DG Policies, Programs and Regulations ...... xiii Table E.2: Summary of Public Cost-Benefit Analysis ...... xv Table 2.1.1: Electricity Generation Mix in British Columbia ...... 6 Table 2.1.2: Electricity Generation Participant in British Columbia ...... 7 Table 2.1.3: Residential Rates Zone I ...... 8 Table 2.1.4: Commercial Rates Zone I ...... 9 Table 2.2.1: Electricity Generation Mix in Alberta ...... 9 Table 2.2.2: Electricity Generation Participants in Alberta ...... 11 Table 2.2.3: Transmission and Distribution Companies in Alberta ...... 11 Table 2.2.4: Residential Rates ...... 12 Table 2.3.1: Electricity Generation Mix in Saskatchewan ...... 14 Table 2.3.2: Electricity Generation Participants in Saskatchewan ...... 14 Table 2.3.3: Residential Rates ...... 16 Table 2.3.4: Commercial Rates ...... 16 Table 2.4.1: Electricity Generation Mix in Manitoba ...... 17 Table 2.4.2: Electricity Generation Participants in Manitoba ...... 18 Table 2.4.3: Residential Rates ...... 19 Table 2.4.4: Commercial Rates ...... 19 Table 2.5.1: Electricity Generation Mix in Ontario ...... 20 Table 2.5.2: Electricity Generation Market Participants in Ontario...... 21 Table 2.5.3: Top 5 Transmission and Distribution Companies in Ontario ...... 21 Table 2.5.4: Residential Rates ...... 23 Table 2.5.5: Commercial Rates ...... 24 Table 2.6.1: Electricity Generation Mix Quebec ...... 24 Table 2.6.2: Electricity Generation Participants in Quebec ...... 25 Table 2.6.3: Residential Rates ...... 26 Table 2.6.4: Commercial Rates ...... 26 Table 2.7.1: Electricity Generation Mix in New Brunswick ...... 27 Table 2.7.2: Electricity Generation Participants in New Brunswick ...... 27 Table 2.7.3: Residential Rates ...... 28
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Table 2.7.4: Commercial Rates ...... 28 Table 2.8.1: Electricity Generation Mix in Nova Scotia ...... 29 Table 2.8.2: Electricity Generation Participants in Nova Scotia...... 30 Table 2.8.3: Residential Rates ...... 31 Table 2.8.4: Small Commercial Rates ...... 31 Table 2.9.1: Electricity Generation Mix in Newfoundland & Labrador ...... 32 Table 2.9.2: Electricity Generation Participants in Newfoundland & Labrador...... 33 Table 2.9.3: Residential Rates ...... 34 Table 2.9.4: Commercial Rates ...... 34 Table 2.10.1: Electricity Generation Mix in PEI ...... 35 Table 2.10.2: Electricity Generation Participants in PEI ...... 35 Table 2.10.3: Residential Rates ...... 36 Table 2.10.4: Commercial Rates ...... 36 Table 2.11.1: Customer-Owned DG Policies, Programs and Regulations ...... 37 Table 2.11.2: Central Energy Procurement with DG ...... 38 Table 3.1: Solar PV Systems Assessed and Main Assumptions ...... 44 Table 3.2: Summary of Demographic Information and Solar PV Potential of Population Centers ...... 46 Table 3.2: Technologies for DG with Biomass and MSW ...... 52 Table 3.3: Summary of DG with Biomass and MSW Assessment Results ...... 54 Table 3.4: Summary of Costs and Technical Parameters of Commercially Available Micro CHP Systems . 56 Table 3.5: Main parameters used for natural gas micro CHP systems in Alberta ...... 60 Table 3.6: LCOE Analysis for Residential and Commercial Buildings in Alberta and Ontario ...... 61 Table 3.7: Capacity Value of Natural Gas CHP Systems by Season ...... 64 Table 4.1: Main Assumptions Made for Private Cost-Benefit Analysis of Solar PV DG Systems ...... 66 Table 4.2: Main Assumptions Made for Private Cost-Benefit Analysis ...... 67 Table 4.3: Macro-Level Benefits of Residential Solar PV ...... 68 Table 4.4: Cost and Benefits Derived from Distributed-Generation ...... 69 Table 4.5: Summary of Public Cost-Benefit Analysis...... 80
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Acronyms and Abbreviations
AD Anaerobic Digestion AUC Alberta Utilities Commission BCUC The British Columbia Utilities Commission BIMAT Biomass Inventory Mapping and Analysis Tool CBA Cost-Benefit Analyses CER Canada Energy Regulator CHP Combined Heat and Power DG Distributed Generation EDR Distributed Energy Resources EPA Electricity Purchase Agreements ESS Electricity Storage Systems ETS Electric Thermal Storage FAM Fuel Adjustment Mechanism FIT Feed-in Tariff FOM Fixed Operating and Maintenance Costs GA Global Adjustment ICE Internal Combustion Engine IPP Independent Power Producers IREC Interstate Renewable Energy Council IRR Internal Rate of Return LCOE Levelized Cost of Electricity LFG Landfill Gas LORESS Locally Owned Renewable Energy Projects That Are Small In Scale Program MEP Market Electricity Purchases MSW Municipal Solid Waste NB Power New Brunswick Power NFOM Non-Fuel Operations and Maintenance Expenses NG Natural Gas NIA Non-Integrated Areas NLH Newfoundland and Labrador Hydro NP Newfoundland Power NPV Net Present Value NREL Us National Renewable Energy Laboratory NS Power Nova Scotia Power Inc NSRDB National Solar Radiation Database O&M Operating and Maintenance Costs OEB Ontario Energy Board OPG Ontario Power Generation PGPP Power Generation Partner Program
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PUB Board of Commissioners of Public Utilities PURPA Public Utility Regulatory Policies Act PV Solar Photovoltaic REA Rural Electrification Associations RMI Rocky Mountain Institute RPP Regulated Price Plan RRO Regulated Rate Option SMP System Marginal Price SOP Standing Offer Program SRRP Saskatchewan Rate Review Panel ST Steam Turbine TFO Transmission Facility Owners TOU Time-of-use TRCT Total Resource Cost Test UARB Nova Scotia Utility and Review Board USEPA Us Environmental Protection Agency Wdc Direct Current Watts
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Executive Summary
Distributed generation (DG) sources are an important consideration in the investment and operations of electricity grids in Canada. The growth of distributed energy resources is increasing, and it is for this reason that CERI has developed an analysis regarding the economic consequences of these investments. Distributed sources are those connected to the electricity distribution system.
From a popularity perspective, solar photovoltaic (PV) systems are the majority of systems selected for investment. In terms of operational convenience and declining capital costs make solar PV a dominant DG investment choice in Canada. However, other systems could be included, such as natural gas combined heat and power (CHP) with natural gas coming from the natural gas grid or renewable natural gas for biodigesters or landfills. It also includes biomass or municipal solid waste (MSW) plants. Both natural gas CHP and biomass generation options can produce electricity during peak demand periods on the system. For solar PV, that would be the exception. Solar PV generation occurs coincident to system peak demand mainly in systems where peak demand is based on air conditioning load.
Given the popularity of distributed electricity generation options, an assessment of their economic impacts for investors and system operators is needed to understand how these technologies will affect the electricity grid. Most provinces in Canada have some form of policy or program promoting the growth of DG (see Table E.1).
Table E.1: Customer-Owned DG Policies, Programs and Regulations Customer Owned DG Nameplate Compensation Province Customer Owned Programs Capacity Technologies Mechanism Renewable Energy BC Net-Metering Program < 100kW Net-Metering Technologies All Technologies with AB Micro-generation Regulation < 5MW GHG intensity Net-Billing < 418kg/MWh Renewable & Carbon SK Net-Metering Program < 100kW Net-Metering Neutral Technologies Type I, II & III - Load < 100kW All technologies Net-Billing MB displacement and export Solar Energy Pilot Program < 200kW Solar PV Net-Billing Renewable Energy Micro-FIT (discontinued) <10kW Feed-in Tariff Technologies ON Renewable Energy Net-Metering Program <10kW Net-Metering Technologies Renewable Energy QC Net-Metering Program <50kW Net-Metering Technologies Renewable Energy NB Net-Metering Program <100kW Net-Metering Technologies Renewable Energy NS Net-Metering Program <100kW Net-Metering Technologies Renewable Energy NL Net-Metering Program <100kW Net-Metering Technologies Renewable Energy PEI Net-Metering Program <100kW Net-Metering Technologies
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There are two primary reasons for investing in these technologies 1) to create investor return opportunities, 2) to reduce overall costs to the system. Figure E.1 shows the private investors' perspective of a small commercial solar PV system. Residential systems will be more expensive per unit of energy.
Figure E.1: LCOE of a Small Commercial Solar PV System (50kWdc)
- LCOE is estimated assuming near-term (2020 - 2025) capital costs (CAD$2/Wdc) and medium-term (2025 - 2030) capital costs (CAD$1.5/Wdc). The numbers in the column head correspond to the nominal discount rate used for LCOE calculation. Project economic life is assumed to be 20 years. The inflation rate is assumed to be 2%. Red horizontal dashed lines correspond to the average retail price observed in respective
provinces in 2018.
Levelized cost of electricity or LCOE is used to assess the economic cost of DG. When compared to the system overall, if the LCOE is lower than the delivered electricity commodity, then the economic impacts for an investor are positive. The converse is also true. CERI’s analysis shows that the LCOE of small solar PV DG systems are lower than the current retail rates (see Figure E.1) in most cases except BC. In this analysis, when we consider retail electricity rates, that includes the commodity, transmission, distribution, and other system charges a distribution customer incurs on it.
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The dotted red line is the total retail electricity price. In jurisdictions where the policy allows for DG owners to be compensated for all system costs, the private perspective economic benefits are positive. In the case of BC, with its lower total system costs, even the compensation for the total system costs means that DG owners will not achieve a positive economic benefit.
Considering those system costs having already been incurred they need to be paid by someone, the question is whether the private sector benefits outweigh the total system costs. In Table E.2, we note that, in most cases, they do not. Nova Scotia is the exception.
Table E.2: Summary of Public Cost-Benefit Analysis BC AB ON NS Total PV Systems by 2040* 180,160 89,800 511,330 46,300 (million CAD$) (million CAD$) (million CAD$) (million CAD$) Energy Impact 124 154 348 94 System Losses 14 13 39 7 Environmental Impact 2 31 40 15 Reliability and Resiliency of Off-Grid and 6 - - - Remote Communities Aggregated Private Benefits 240 433 600 106 Total Benefits (Over 20 Years) 386 630 1027 221 Lost Revenues - Transmission 261 627 577 43 Network Lost Revenues - Distribution 294 128 106 94 Costs Lost Revenues - Global Adjustment N/A N/A 1551 N/A Total System Costs - (Over 20 Years) 555 755 2234 137 Net present value - (Over 20 Years) -169 -125 -1208 85 Net present value per system -937 -1392 -2362 1826 (CAD$/system over 20 Years) *Alberta only includes PV systems assumed to be installed within the ENMAX and FortisAlberta franchise areas.
To understand the total system costs, CERI considered all the key cost drivers, including a value of $30/tonne of CO2 emissions. The costs (or cost savings) include the reduction in system losses, lower variable operating costs and the potential for avoiding new infrastructure investments.
Avoided system investments are a matter of debate as it depends on the size, predictability and location of the DG options within the distribution system. Our analysis shows that, in general, there are no scenarios where system costs can be avoided. This means there is zero economic value given to such possibilities. We have noted that in unique areas where the system may be under stress, a concentration of DG options could delay or eliminate the need for new system investments. However, this is the exception, not the rule. Even in situations where DG has a penetration rate much higher than we have seen historically, the ability to avoid system investments is minimal.
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In BC, AB and ON, we have shown there are net public costs to the deployment of solar PV DG options. In NS, the higher percentage of energy costs as a percentage of system costs makes solar PV DG cost- effective from both a private and public perspective.
Again, it should be stressed that this analysis is based on average conditions in each of the jurisdictions. There may be net system benefits in targeted areas with targeted DG investments. However, in those situations, a case-specific analysis will be needed to confirm that assumption.
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Chapter 1: Introduction
• Growth of distributed energy resources is a growing trend in electric power systems.
• New research is required to gain insights into the opportunities and challenges of distributed generation.
Rapid growth in the integration of distributed energy resources (DER) is one of the most significant and important trends in the electricity industry around the world. DER encompasses electricity generation systems, storage systems, and controllable loads (i.e., demand response) that are connected to the distribution system at or closer to final consumers of electricity (Akorede, Hizam, and Pouresmaeil 2010; ETNO 2019). Distributed generation (DG) is a major and one of the well understood DER. DG refers to technologies that produce electricity at or near the final consumers of electricity (Ackermann, Andersson, and Söder 2001). DG may serve a single facility (e.g., house, commercial building, college campus), part of the microgrid, feed electricity to the distribution network, or a combination of the above.
In the traditional energy utility model, electricity is generated by large-scale centralized power plants. The primary energy source for these large-scale centralized plants varies by jurisdiction and is driven primarily by the available energy resources. The centrally generated electricity is transmitted through high voltage transmission lines over long distances to distribution centers. At the distribution centers, the voltage is decreased, and a distribution company delivers the electricity to the end-users. In the traditional model, the ownership of the three subsystems—generation, transmissions, and distribution—depends on the structure of the power systems, and that changes by the jurisdiction.
Distributed generation is gaining increased attention. Proponents attribute many benefits to distributed generation. These include increased reliability of supply, increased resiliency of the electricity system (Driesen and Katiraei 2008), not being exposed to electricity price volatility, lower overall electricity losses, and environmental benefits (Sullivan et al. 2014). The economic and environmental benefits resulting from being able to produce existing, cost-effective renewable energy sources at homes and businesses is one of the main benefits cited by the proponents of distributed generation. Another major driver of distributed generation is the advancement of new small-scale power generation technologies. The examples include more efficient solar Photovoltaic (PV) technologies, the advancement of small-scale incinerators and gasifiers, micro-hydropower plants, and natural gas technologies. Other technological advancements, such as the development of advanced battery storage systems and improved cogeneration technologies, have further strengthened the case for distributed generation. Technologies that can be used for DG may rely on locally extracted primary energy resources (for example, wind, solar, hydro, biomass, or geothermal) or locally purchased, such as natural gas.
Globally, many jurisdictions are promoting the implementation of DG (and DER in general) through supportive policies and programs. One of the seminal public policies that accelerated the growth of DG is the Public Utility Regulatory Policies Act (PURPA) of the United States (U.S.). Bypassing PURPA in 1978, the U.S. Congress began encouraging an alternative power generation and delivery model. Among other
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mandates, PURPA requires certain utilities to enter into agreements to purchase electricity from qualifying renewable energy or combined heat and power (CHP) facilities (Sullivan et al. 2014). Since PURPA, many policies and programs have been implemented in the U.S. both at the federal level and state level to support DG (Orrell, Homer, and Tang 2018). More recently, the California Energy Commission approved a solar roof mandate, requiring all new homes to have solar-powered electricity systems.
Another major piece of legislation that supports DER is the European Union’s regulation on the Internal Market for Electricity (European Parliament 2019). Among other broader objectives, directives to support DER is a major part of the regulation. “In the past, electricity customers were purely passive, often buying electricity at regulated prices which had no direct relation to the market. In the future, customers need to be enabled to participate in the market on equal footing with other market participants and need to be empowered to manage their energy consumption. To integrate the growing share of renewable energy, the future electricity system should use all available sources of flexibility, particularly demand- side solutions, and energy storage, and should use of digitalization through the integration of innovative technologies with the electricity system,” the regulation reads. Through that as well as other policies, the EU is aiming to maximize the implementation of DER.
In Canada too, DER is being promoted through federal, provincial, and territorial policies and programs. Among other objectives, the federal and provincial governments are considering the promotion of DG technologies as a complementary policy tool to achieve GHG emissions reduction targets. In Canada, the growth of DG is also starting to scale. For example, in Ontario—the province with the most extensive set of policies to support DER—over 4000MW of DG has been installed and contracted in Ontario over the past ten years (IESO 2020a). As of May 2020, the number of sites with DG in Alberta was about 5,553 (AESO 2020b). Since 2004, over 1800 customers have invested in DG and joined British Columbia’s net- metering program.
Despite the growing interest and cited benefits, DG is not without challenges and criticism (Costello 2015). These challenges depend on the specific electric power system that hosts DG and the policies that support the incorporation of DG. One of the main challenges that is frequently cited is whether the compensation mechanisms for DG would lead to challenges for the utilities in recovering the cost of electricity generation and delivery assets. A related challenge is whether the utilities are under-recovering their costs from customers with DG and over-recovering them from non-DG customers (Costello 2015). The key question is, are there net economic benefits derived from the implementation of DG options?
For example, one of the main supportive policies for DG is net-metering, which many jurisdictions, including most Canadian provinces, have adopted. Net-metering effectively allows customers to receive compensation for DG at the full retail electricity price (Darghouth et al. 2016). Under current rate designs, the cost of generation, transmission, and distribution assets are recovered by setting appropriate retail rates. The current rate model and the presence of net metering have led to concerns that the possible under-recovery of fixed utility costs from DG owners may lead to increasing retail electricity prices. Another concern is whether costs associated with utilities revamping their distribution systems to accommodate DG may mean increases in retail electricity rates. These concerns have led to different jurisdictions changing their DG policies. For example, in 2016, Arizona cancelled its net-metering program and implemented a different compensation mechanism for DG (Pyper 2016). British Columbia amended
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its net metering program in 2019, limiting the DG capacity that can be implemented by a customer (Andrews 2019).
The diverging viewpoints about the benefits and challenges of DG may appear to be a conundrum to energy policymakers. In an analysis of distribution systems under a high DER future scenario, Martini & Kristov (2015) describe this challenge as:
“The growth in volume and diversity of distribution-connected, DER is driving an evolutionary process that is reshaping infrastructure planning, grid operations, energy markets, regulatory frameworks, ratemaking, and utility business models across the nation. To state regulators and policymakers trying to guide DER growth to maximize net benefits for ratepayers and society as a whole, these changes raise disparate issues that may appear to need to be addressed all at once.”
Electric power systems in Canada are at a pivotal juncture. They are expected to play a critical role in facilitating the nation’s economic growth while meeting public policy goals such as environmental sustainability and ensuring energy equity and affordability. The opportunities decentralized generation systems and DER in general in meeting those objectives must be assessed along with the associated challenges through new research and analyses. This CERI study is designed to provide insights into some of those opportunities and challenges. The study also intends to develop information and tools to facilitate future research on DER.
1.1 Scope & Objectives The main objectives of this study are:
1) Provide an in-depth review of current electricity infrastructure and regulatory set up across different provinces and a review of policies and programs that have been adopted by the provinces to facilitate the uptake of DG 2) Develop a techno-economic assessment of select DG technologies 3) Assess the economic feasibility of DG by developing a private and public cost-benefit analysis
As mentioned in the preceding section, DER is a broader set of technologies that can provide different services to the electric power system. While recognizing the value of all elements of DER, this study focuses only on DG. Other DER tools such as electricity storage systems and demand response services were excluded primarily to manage the scope of the analysis. This study forms a foundational piece to an overall broader DER assessment that is part of CERI’s long term research focus in this area.
Any assessment on DG must be made within the context of the host power system. In addition to aiding the analysis of this study, a review of provincial power systems and DG policies and programs is developed (objective #1) to provide a single source of those information to facilitate future DER research.
DG implementations may differ by ownership structure. For example, a DG system may be owned and operated by a single customer, leased, or operated by a utility while sited in a customer’s establishment,
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furthermore, rather than satisfying a single electricity user’s electricity demand a DG system may provide bulk energy services through a long-term contract or participating in energy markets.
This study focuses only on customer-owned and operated DG systems. DG systems assessed in this study primarily satisfy the host establishment’s electricity demand. Any electricity that is not produced is exported to the distribution network. For example, consider a residential solar PV system without a storage system. The solar PV system produces electricity during daylight hours, and the household will consume most of the electricity produced. If, at any given point, the electricity produced by the solar PV system is more than the household’s electricity demand, the excess electricity will be exported to the distribution network.
Economic returns for a DG system considered in this study may arise from two streams. First, any electricity that is produced and self-consumed by the host establishment will offset the electricity demand that is purchased from the utility, leading to an electricity bill saving. The magnitude of the bill saving depends on the prevailing retail price of electricity. Second, any electricity that is exported to the distribution network would be compensated as a bill credit. The magnitude and the frequency of the bill credit depend on the DG policy of respective provinces. For example, the bill credit may be the same as the full retail electricity price or a negotiated rate. Note that throughout this report, the term retail price refers to all in electricity prices that include energy charges, delivery charges, and any adminstrative fees. An in-depth review of retail electricity price structure and compensation mechanism for DG systems in deferent provinces are presented in Chapter 2.
CERI has also developed a comprehensive data portal for this study. The data portal provides resource and economic data of select DG technologies at different population centers in Canadian provinces. The development of the data portal is also done to facilitate future DER research. 1
1 The Portal can be found at https://ceri.ca/studies/ and will be available shortly after the release of the report
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Chapter 2: Review of Distributed Generation Programs, Policies and Regulations2
• Canada produces a higher percentage of its electricity from renewable sources compared to the average across OECD countries. Overall, Canada’s non-emitting sources of electricity are approximately 80%.
• Most provinces in Canada have some form of policy or program promoting the growth of DG.
• As DG technologies become more competitive, there needs to be more coordination between electricity system planners and provincial government agencies to successfully integrate DG successfully.
In this chapter, we offer an overview of the electricity sector across Canada to help the reader understand the differences that exist among provinces, in terms of the local electricity systems, and note the objectives of some of the provincial policies and programs promoting the growth of DG within each jurisdiction.
2.1 British Columbia Electricity System British Columbia’s easy access to abundant renewable sources of energy allows the province to have minimum reliance on fossil fuels to supply electricity for its residents. Based on data between 2014 and 2018, 97.5 percent of the electricity generated in the province came from renewable sources (Statistics Canada 2019).
Storage hydro and run-of-the-river are the most important sources of power generation in the province. As of 2019, 84 percent of the installed capacity was represented by hydroelectric source, followed by natural gas, wind, biomass, waste heat, diesel (& other fossil fuels), and a negligible percentage of solar. Table 2.1.1 summarizes the installed generation capacity and a five-year average (2014-2018) annual generation by source.
2 The Territories of Yukon, Northwest Territories and Nunavut are not included in this analysis. Those three jurisdictions have fragmented electricity grids which require a more in depth and case specific analysis to assess the economic costs and benefits of on-grid DG. This will be the subject of a future study.
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Table 2.1.1: Electricity Generation Mix in British Columbia Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2019 2014-2018 Capacity3 Generation (MW) (TW.h) Hydro 15643.8 83.7% 62.54 88.80% Natural Gas 1472.8 7.9% 1.23 1.75% Wind 703.7 3.8% 1.25 1.78% Biomass & Waste Heat 734.7 4.2% 4.86 6.91% Diesel & Other Fossil Fuels 58.8 0.3% 0.06 0.09% Solar 1.0 0.0% N/A - DG - Solar 13.1 0.1% N/A - Data source BC Hydro (2019c), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI *The percentage is calculated based on the total installed capacity (both transmission and distribution connected). Electricity is supplied to most consumers via the British Columbia Hydro and Power Authority (BC Hydro), a Crown corporation established in 1964. BC Hydro is the largest vertically integrated utility in the province, and it delivers electricity to customers connected to the integrated system, classified as Zone I, through 72,000 km of transmission and distribution lines. It also owns and operates the infrastructure dedicated to delivering electricity to some off-grid communities, classified as Zone II. The BC Ministry of Energy, Mines and Petroleum Resources and the Hydro and Power Authority Act governs this Crown corporation. The British Columbia Utilities Commission (BCUC) regulates all the utilities within the province.
Some small municipalities4 have chosen to provide energy utility services for their residents (electricity supply and natural gas), and FortisBC, an investor-owned utility, serves the south-central region of the province. In total, these small municipalities and the south-central region of the province account for about 5 percent of BC’s electricity consumers (Government of British Columbia 2020).
BC Hydro owns and operates about 70 percent of the total installed electricity generation capacity within the province. Columbia Power, a Crown corporation governed by the BC Ministry of Children and Family Development and the Business Corporations Act, owns 5 percent of the total generation capacity (Columbia Power 2020) while the remaining 25 percent is owned and operated by independent power producers (IPP’s). Table 2.1.2 lists the top five companies that own and operate electricity generation facilities as a percentage of total installed capacity. All other IPP’s, not included in the list, own less than 2 percent of BC’s installed capacity.
3 The percentage is calculated based on the total installed capacity (both transmission and distribution connected). 4 City of Nelson, City of New Westminster, City of Grand Forks, City of Penticton, and District of Summerland.
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Table 2.1.2: Electricity Generation Participant in British Columbia
Nameplate Percentage of Company Capacity Installed (MW) Capacity BC Hydro 13025 70.0% Columbia Power 940 5.0% Rio Tinto 790 4.2% Innergex 613 3.3% Capital Power 423 2.3% Data source BC Hydro (2019e). Table by CERI
Customer-owned and Central Energy Procurement DG Policy Framework In 2002, the provincial government launched the 2002 Energy Plan: Energy for our Future: A Plan for BC (Cohen and Calvert 2012), where the government directed BC Hydro to develop and implement policies that would enable the growth and promotion of DG. Included in these initiatives was the introduction of Net Metering Service (2004) to help promote BC Hydro’s voluntary goal of acquiring 50 percent of new electricity supply from renewable sources. Initially, the generating systems had a limit of 50kW of nameplate capacity with an attribute of being environmentally friendly; this limit was eventually increased to 100kW (2014)(BC Hydro 2017).
Under the Net Metering program, when a customer’s electricity generation, at any given time, is less than the electricity consumed, they buy the energy they need from BC Hydro as per their rate class. Whereas if the customer’s electricity generation exceeds their electricity needs, at any given time, then the surplus electricity (kWh) is banked in a Generation Account. The surplus is eventually credited to offset future consumption during periods when the customer’s consumption exceeds their electricity generation. At the end of a 12-month cycle, if customers have a surplus in their Generation Account, then these customers are eligible for a Surplus Energy Payment, which is equal to the remaining banked kWh paid out at the Energy Price (9.99 cents/kWh as of 2020)(BC Hydro 2019e).
Building on the 2002 Energy Plan, the government presented a revamped energy strategy in its 2007 BC Energy Plan outlining specific policies and targets including the procurement of at least 90 percent of electricity generation from renewable sources; making small power generation part of the solution; establishing the Innovative Clean Energy Fund and; implementing the BC Bioenergy Strategy to generate electricity from mountain pine beetle wood (biomass). In 2008, BC Hydro introduced the Standing Offer Program (SOP) to promote the growth of small-scale electricity generation (projects between 100kW and 15MW) by offering Electricity Purchase Agreements (EPA’s) to residents interested in participating in the program (BC Hydro 2008). Similarly, in 2014, BC Hydro offered EPA’s to First Nations communities through the Micro-SOP program (for projects between 100kW and 1MW) with the conditions that the community kept at least 50 percent ownership of the generation system under the EPA.
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The SOP and Micro-SOP programs were designed as central energy procurement programs. Thus, customers cannot directly offset the onsite electricity load. In 2018, the SOP and Micro-SOP programs were suspended due to concerns about the future costs associated with the oversubscribed contracted capacity and potential electricity rate increases (BC Hydro 2019a). Similarly, BC Hydro has applied to amend the Net Metering program to address a growing trend of customers installing generating facilities exceeding their annual load, resulting in significant annual payouts to these customers (BC Hydro 2019e).
As of 2019, BC Hydro had processed over 1,800 customers in its Net Metering program, adding up to approximately 13MW of installed nameplate capacity, with 98.16 percent of these customers opting for solar photovoltaics (SPV). By 2018, the province had contracted over 170MW of capacity under the SOP programs; the original target was 100MW (Ministry of Energy, Mines and Petroleum Resources 2018). In total, there are between 170 and 200MW of installed capacity connected to the distribution system.
Residential and Commercial Rate Structure BC Hydro is responsible for the electric power services of 94 percent of BC’s electricity consumers. The Crown corporation classifies its service areas into the Integrated Service Areas (Zone I) and Non-Integrated Service Areas (Zone II).
The residential service rate for customers in Zone I is laid out in the Rate Schedules 1101 and 1121 of the BC Hydro Electric Tariff (BC Hydro 2020). The rate is a two-step inclining block rate (Residential Inclining Rate - RIB) with a basic charge. The goal of applying a step rate is to provide price signals to encourage electricity conservation relative to what is achievable through a flat rate (BC Hydro 2019b). Table 2.1.3 shows the residential rate schedule for the 2020 fiscal year:
Table 2.1.3: Residential Rates Zone I Rate Class Rate 2020 Basic Charge ($/day) $0.21 Step-1 Energy Charge ($/kWh) $0.09 Residential - Step -2 Energy Charge ($/kWh) $0.14 Rate Schedule 1101 Deferral Account Rider 0% Customer Crisis Fund Rider ($/day) $0.00 GST 5%
The rates for commercial customers are differentiated based on their annual peak demand and are defined as follows: Small General Service Rate (annual peak demand less than 35kW); Medium General Service Rate (annual peak demand between 35 and 150kW, and use less than 550,000kWh of electricity per year); and Large General Service Rate (annual peak demand greater than 150kW or use more than 550,000kWh of electricity per year). The commercial customers have a basic charge, a demand charge for consumption above 550,000 kWh/year, and an energy charge for all levels of consumption.
Table 2.1.4 shows the general service business rate schedule for a Small General Service for the 2020 fiscal year.
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Table 2.1.4: Commercial Rates Zone I Rate Class Rate 2020 Small General Service - Rate Basic Charge ($/day) $0.36 Schedule 1300 Energy Charge ($/kWh) $0.12 Taxes for all commercial GST 5% customers PST 7%
2.2 Alberta Electricity System Alberta’s access to coal and natural gas resources has made the province highly dependant on fossil fuel electricity generation. Before 2016, at least 50 percent of the electricity generation in the province came from coal-fired electricity generation, with natural gas generation accounting for almost 40 percent and the remainder coming from renewable sources (Statistics Canada 2018). The introduction of a more stringent carbon offset regime in 2018, and the low natural gas price environment made natural gas generators in Alberta more competitive, displacing coal-fired generation, and allowing natural gas to become the main source of electricity generation in 2018 (Gallardo 2019). This economy-wide carbon tax was cancelled on May 30, 2019.
As of 2019, natural gas-fired generation represents about 46 percent of the total installed capacity, followed by coal at 34 percent and wind capacity at about 10.1 percent. All other technologies represent less than 6 percent each. Table 2.2.1 summarizes the installed generation capacity and the five-year (2014- 2018) average annual generation by source.
Table 2.2.1: Electricity Generation Mix in Alberta Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity5 Generation (MW) (TW.h) Natural Gas 7696.0 46.8% 32.69 41.61% Coal 5574.0 33.9% 37.75 48.05% Wind 1781.0 10.8% 4.19 5.33% Hydro 894.0 5.4% 1.96 2.50% Biomass 360.0 2.2% 1.81 2.31% Waste Heat 63.0 0.4% 0.15 0.19% Solar 15.0 0.1% 0.01 0.01% DG - Solar 67.8 0.4% N/A - DG - Other 2.3 0.0% N/A - DG - Wind 1.4 0.0% N/A - Data source AESO (2018), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
5 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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Alberta has a liberalized electricity system with a competitive energy-only wholesale electricity market. Alberta’s electric system is broken down by its different components (i.e., generation, transmission, distribution and retail), each component is subject to different regulations, market structures and industry participants. These components replace a provincial Crown corporation or a vertically integrated utility responsible for the generation and supply of electricity to consumers in the province,
Alberta’s wholesale electricity sector has been fully liberalized since 2001. Thus, electricity generators do not operate under natural monopoly structures. They compete among other generators (and different generation technologies). The price they receive for their output is determined by economic supply and demand forces in a competitive energy market (AESO 2020a).
Alberta’s transmission and distribution of electricity sectors also consist of a mix of entities. At the transmission level, Transmission Facility Owners (TFOs) are responsible for the design, operation, maintenance, performance, and integrity of their transmission assets. There are currently four TFO’s in Alberta, with the two largest being AltaLink and ATCO Electric (AUC 2017). At the distribution level, there are four large investor-owned utilities (FortisAlberta, EPCOR, ENMAX and ATCO), six municipally owned utilities and 32 Rural Electrification Associations (REAs). These utilities are usually referred to as distribution wire owners, wires service providers and distribution facility owners.
Given that investor-owned utilities provide a monopoly service within their franchised area, their operations, rates, tolls, and tariffs are regulated by the Alberta Utilities Commission (AUC). The AUC does not regulate municipally-owned utilities or any of the REAs (AUC 2020). Utilities that fall outside the AUC’s mandate are governed by their municipality or their elected board of directors in the case of the REAs.
Electricity retailing in Alberta also consists of a mix of entities that are split between regulated and competitive retailers. The latter offers electricity services to customers charged at competitive prices/rates, which are negotiated between the customer and the competitive retailer. The former, also known as Regulated Rate Option (RRO) providers, charge customers a monthly rate is governed by the Regulated Rate Option Regulation. Large electricity consumers in Alberta also have the option to become self-retailers, which gives them the opportunity to directly purchase their electricity needs from the Alberta power pool.
Table 2.2.2 lists the top 5 companies listed as power pool participants (AESO 2020d) with their associated total installed capacity (AESO 2020e). All other power pool participants have an associated installed capacity of less than 5 percent. Table 2.2.3 shows the main transmission and distribution companies in Alberta.
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Table 2.2.2: Electricity Generation Participants in Alberta
Nameplate Percentage of Company Capacity Installed (MW) Capacity TransAlta 4410 26.9% Capital Power 1868 11.4% Heartland Generation 1608 9.8% ENMAX 1588 9.7% Suncor 806 4.9% Data source (AESO 2020e; 2020d)
Table 2.2.3: Transmission and Distribution Companies in Alberta
Company Transmission Distribution
AltaLink Yes No FortisAlberta No Yes ATCO Electric Yes Yes ENMAX Power Yes Yes EPCOR Distribution & Transmission Yes Yes Data source (AUC 2017)
Customer-owned DG Policy Framework The Alberta government opened the door for all residents in the province to produce electricity for their consumption when the Micro-Generation Regulation was introduced in 2008. This regulation provides legal access to the distribution system to any customer who wants to offset some or all of their electricity drawn from the grid.
The Micro-Generation Regulation includes generating technologies that exclusively use renewable or alternative energy, and that is intended to meet all or a portion of the customer’s total annual energy consumption. Originally, the total nameplate capacity to qualify under this regulation was 1MW. The regulation was amended in 2016 to increase the size limit to 5MW and to allow DG systems to serve adjacent sites.
The Micro-Generation Regulation prescribes ‘net-billing’ as the methodology used to compensate customers for the electricity that they deliver to the distribution system. Thus, DG customers are billed for all the electricity that they draw from the grid over a billing period as all other customers in the same rate class, including energy and delivery charges, as well as all other administration and service fees. When the nameplate capacity of the system is less than 150kW, the retailer credits the customer at the customer’s rate class for the electric energy supplied to the grid over a billing period. For customers with DG systems with a nameplate capacity greater than 150kW and up to 5MW, the retailer must credit the
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customer for the electric energy supplied to the grid at the pool price for each settlement interval in the billing period. However, the regulation also allows the retailer and the customer to negotiate a compensation schedule that is different from the retail rate or the pool price.
Residential and Commercial Rate Schedules The absence of a single vertically integrated utility in Alberta allows for a transparent breakdown of the many costs that need to be recovered from the end-users of electricity each billing period, including transmission, distribution and energy charges, as well as other systems, administrative and municipal fees and charges.6 Retailers are responsible for collecting all these payments from their customers and transferring them to the corresponding recipients.
Table 2.2.4 shows the rate structure for residential customers across the four electricity service zones in Alberta. Table 2.2.5 shows the rate structure for commercial connections. In the absence of an explicit commercial rate class, we picked what we believed was the most appropriate given the average size of commercial connections.
Table 2.2.4: Residential Rates
Residential 2019 ENMAX - D100 EPCOR - Residential FORTIS - Rate 11 ATCO - D11 Energy RRO Energy Rate (Capped at 6.8 ¢/kWh until Nov 2019) ¢/kWh 6.6348 ¢/kWh 6.8383 ¢/kWh 6.8217 ¢/kWh 6.643 Transmission Variable Transmission Rate ¢/kWh 1.9463 ¢/kWh 3.132 ¢/kWh 4.0104 ¢/kWh 3.90 Distribution System Usage Rate ¢/kWh 1.0475 ¢/kWh 0.951 ¢/kWh 2.2886 ¢/kWh 7.44 Distribution Distribution Service and Facilities Rate ¢/day 52.0781 ¢/day 65.211 ¢/day 81.24 ¢/day 104.95 Service Customer Rate ------¢/day 30.26 Municipal Franchise Fee % 11.11% ¢/kWh 0.85 % 12.70% % 7.75% Local Access Fees Municipal Assessment Rider - (A-1) - - - - % 0.85% % 1.71% Balancing Pool Allocation - Rider F ¢/kWh 0.2969 ¢/kWh 0.3 ¢/kWh 0.2988 ¢/kWh 0.305 Temporary Adjustment ------¢/kWh 0.334 Transmission Access Charge Deferral Account - Rider K ¢/kWh 2.82320 ¢/kWh 0.203 - - - - Rate Riders DAS Adjustment Rider % 2.08% ¢/kWh 0.399 - - - - Transmission Adjustment Rider - - - - % 3.95% - - SAS Adjustment Rider - - ¢/kWh -0.01 - - ¢/kWh 0.028 Rider Z ------$/day 0.172 Administration Charge RRO Provider Administration Rate $/day 0.2064 $/month 5.36 $/month 5.46 $/day 0.387 Tax GST % 5% % 5% % 5% % 5%
6 These requirements are set out in the Alberta’s Billing Regulation.
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Table 2.2.5: Commercial Rates
Commercial - Small 2019 ENMAX - D200 EPCOR <50kVA FORTIS - Rate 41 ATCO - Rate D21 Size Connection Energy RRO Energy Rate (Capped at 6.8 ¢/kWh until Nov 2019) ¢/kWh 6.6348 ¢/kWh 6.838 ¢/kWh 6.829 ¢/kWh 6.628 Variable Transmission Rate ¢/kWh 1.59050 ¢/kWh 3.274 ¢/kWh 0.5626 ¢/kWh 1.15 Transmission Fixed Transmission Charge $/kW/day 0.2407 ¢/kW/day 18.82 First 200kWh 4.46 / Distribution System Usage Rate ¢/kWh 0.8957 ¢/kWh 2.555 ¢/kWh 1.323 / balance 0.0 kWh (¢/kWh) First 2 kW / Distribution 53.738 / Distribution Service and Facilities Rate $/day 1.1931 $/day 0.3622 balance of KW of ¢/day 9.41 27.355 Load (¢/kW/day) Fixed Distribution Charge ¢/kW/day 23.68 Service Customer Rate ------¢/day 43.24 Municipal Franchise Fee % 11.11% ¢/kWh 0.85 % 12.70% %* 7.75% Local Access Fees Municipal Assessment Rider - (A-1) - - - % 0.85% %* 1.71% Balancing Pool Allocation - Rider F ¢/kWh 0.2969 ¢/kWh 0.3 ¢/kWh 0.3015 ¢/kWh 0.305 Temporary Adjustment ------¢/kWh 0.361 Transmission Access Charge Deferral Account - Rider K ¢/kWh 2.4286 ¢/kWh 0.188 - - - - Rate Riders DAS Adjustment Rider % 1.96% ¢/kWh 0.272 - - - - Transmission Adjustment Rider - - - - % 2.73% - - SAS Adjustment Rider - - ¢/kWh 0.029 - - ¢/kWh 0.012 Rider Z ------$/day 0.073 Administration Charge RRO Provider Administration Rate $/day 0.2009 $/month 4.99 $/month 5.76 $/day 0.393 Tax GST % 5% % 5% % 5% % 5%
2.3 Saskatchewan Due to abundant access to coal and natural gas, Saskatchewan’s electricity supply is primarily sourced from fossil fuels. Historically, coal has been the largest source; however, the share of electricity generation from coal has been decreasing since 2005, shifting towards a higher share of natural gas generation. For the first time, during the 2018 fiscal year7, the Saskatchewan Power Corporation (SaskPower, the main utility in the province) reported that natural gas generation became the main source of electricity produced, albeit by a negligible difference (10,603GWh from natural gas vs. 10,286GWh from coal) (SaskPower 2019a).
As of 2019, 40 percent of the installed capacity in the province was represented by natural gas generation, followed by coal, hydro, wind, and waste heat. Table 2.3.1 summarizes the installed generation capacity and the five-year (2014-2018) average annual generation by source.
7 March 31, 2018-2019
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Table 2.3.1: Electricity Generation Mix in Saskatchewan Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2019 2014-2018 Capacity8 Generation (MW) (TW.h) Natural Gas 1839 40.6% 7.97 33.35% Coal 1530 33.8% 11.33 47.41% Hydro 889 19.6% 3.77 15.77% Wind 241 5.3% 0.68 2.86% DG - Waste Heat & Other 20 0.4% 0.15 0.61% (Capacity >100kW) DG - Renewable (Capacity 12 0.3% N/A - < 100kW) Data source SaskPower (2019d), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Except for the residents of the city of Saskatoon and Swift Current, who receive their electricity services from local municipal utilities, most other residents in the province receive their electricity from SaskPower, a provincial Crown corporation with an exclusive franchise for electricity transmission and distribution across the province. The Power Corporation Act grants SaskPower the right to be the sole supplier of electricity in the province, and the Saskatchewan Rate Review Panel (SRRP) regulates the rates that the utilities can charge to their customers.
Out of the total installed generating capacity in the province, SaskPower owns and operates about 84 percent, followed by Northland Power and Stanley Energy (both IPP’s), which own and operate 8 percent and 5 percent of the installed capacity, respectively. Table 2.3.2 lists the top five companies that own and operate electricity generation facilities as a percentage of total installed capacity. All other IPP’s, not included in the list, own less than 0.5 percent of the province’s installed capacity.
Table 2.3.2: Electricity Generation Participants in Saskatchewan
Nameplate Percentage of Company Capacity Installed (MW) Capacity SaskPower 3816 84.2% Northland Power 375 8.3% Stanley Energy 228 5.0% Concord Pacific 26 0.6% Algonquin Power 23 0.5% Data source SaskPower (2019d), NACEI. Table by CERI.
8 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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Customer-owned and Central Energy Procurement DG Policy Framework While a Small Power Producer Policy had been in place in Saskatchewan since 1998, it was in 2007 when amendments to the policy restricted the participation of this program to renewable sources of electricity (Government of Saskatchewan 2007). Under the 2007 Small Power Producer program, SaskPower allowed individual customers and businesses to generate up to 100kW, from renewable generation sources, to offset the electricity that would otherwise be purchased from SaskPower or to sell excess generation back to the grid. Under this program, customers had to choose one of these two options.
The Small Power Producer program ran until 2018 when it was discontinued, but SaskPower introduced other options for DG: Power Generation Partner Program (PGPP) and a Net Metering Program (SaskPower 2018).
The Net Metering Program mimics the Small Power Producer program in that customers can generate up to 100kW, from renewable or carbon-neutral9 technologies, to offset future electricity bills with the excess electricity generated by the customer. The surplus electricity (kWh) sent to the grid is monetized at a pre-determined rate (7.5cents/kWh as of 2020), and this energy credit is subtracted from the dollar amount owed for the consumed electricity drawn from the SaskPower grid. Customers can carry forward excess credit amounts for the life of the service account at their location; however, any excess credits held at the customer’s account at the time of the program’s termination will expire and are non-refundable (SaskPower 2019b).
The PGPP was designed to promote electricity generation from small renewable and carbon-neutral non- renewable energy projects and the sale of this electricity back to SaskPower. The project size allowed for renewable systems is between 100kW and 1MW, while the project size for carbon-neutral non-renewable systems10 ranges from 100kW to 5MW. Under this program, residential and commercial customers cannot directly offset the supply of electricity coming from SaskPower. These DG systems are treated as stand- alone generating assets, and their electricity generation is paid at the energy price specified in each project’s application process through SaskPower.
As of 2020, SaskPower reports that 20MW of installed generating capacity from waste heat recovery systems, represented by four 5MW projects, which is in line with the Power Generation Partner Program guidelines. The company also reports that, since the inception of the Net Metering program in 2008, it has accepted 1,795 projects, representing a combined generating capacity of over 21MW. However, the company does not report how many of these accepted projects have been installed and are in service. We assume that the total DG capacity derived from the Net Metering Program is around 12MW11.
9 Waste heat recovery processes that transform usable energy into electric power. 10 Flare gas and waste heat. 11 SaskPower reports that the total available generating capacity coming from ‘Other’ sources is 32MW, with 20MW assumed to be waste heat recovery systems.
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Residential and Commercial Rate Schedules SaskPower residential rates are classified into three different categories: E01 (City); E02(Town, village and urban resort); and E03(Rural and rural resort). Rates E01 and E02 are identical, and these will be the focus of this section.
The rate has a basic monthly charge and energy charge for all levels of consumption. The basic charge covers the fixed administrative costs. In contrast, the energy charge covers the variable costs associated with fuel and electricity purchases, as well as a share of the fixed infrastructure costs associated with the generation, transmission and distribution systems. SaskPower also flows through the federal carbon tax to customers through this rate. Table 2.3.3 shows the residential rate effective for 2020 (SaskPower 2019c).
Table 2.3.3: Residential Rates Rate Class Rate 2020 Basic Charge ($/month) $22.79 Energy Charge ($/kWh) $0.14 Residential Federal Carbon Charge (¢/kWh) 0.5744 ¢ Municipal Surcharge Tax 10% GST 5%
The rates for commercial customers are differentiated based on their monthly metered demand and are defined as follows: Small Commercial Rate (monthly peak demand between 50kVa and 75kVa) and Standard Rate (monthly peak demand greater than 75kVa and up to 3,000kVa). These rates have a basic charge, a demand charge for metered loads, and a two-step declining block rate for the energy charge. The threshold between the two blocks for the energy charge for the commercial rate and the standard rate was set at 14.5 and 16.750 MWh/month, respectively. SaskPower also includes the federal carbon tax in these rates. Table 2.3.4 shows the commercial service rates for 2020:
Table 2.3.4: Commercial Rates Rate Class Rate Charge Basic Charge ($/month) $31.14 Demand Charge - Load Above $15.15 50kVa/Month ($/kVa) Energy Charge - First 14,500 kWh $0.1367 Small Commercial ($/kWh) Service Energy Charge - Balance of kWh ($/kWh) $0.0722 Federal Carbon Charge (¢/kWh) 0.5728 ¢ Municipal Surcharge Tax 10% GST 5% PST 5%
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2.4 Manitoba Manitoba’s electricity supply is virtually all sourced from renewable sources. Historical generation data between 2014 and 2018 indicates that, on average, 99.7 percent of the electricity generated in the province came from renewable sources, with hydroelectricity accounting for 97 percent (Statistics Canada 2019).
As of 2019, hydroelectric facilities accounted for 92.5 percent of the provincial installed capacity, followed by wind and natural gas. Table 2.4.1 summarizes the installed generation capacity and the five-year (2014- 2018) average annual generation by source.
Table 2.4.1: Electricity Generation Mix in Manitoba Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2019 2014-2018 Capacity12 Generation (MW) (TW.h) Hydro 5228.0 91.8% 35.61 97.03% Wind 258.0 4.5% 0.92 2.50% Natural Gas 132.0 2.3% 0.02 0.06% Biomass 22.0 0.4% 0.07 0.19% Diesel 9.0 0.2% 0.04 0.11% DG - Flare Gas 12.0 0.2% N/A N/A DG - Solar 31.0 0.5% N/A N/A Coal (retired as of 2018) - - 0.04 0.11% Data source Manitoba Hydro (2019), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Manitoba Hydro, a Crown corporation, has an exclusive franchise for generation, transmission, and distribution, and is responsible for the long-term planning of the overall electricity infrastructure within the province. The Manitoba Hydro-Electric Board and the Manitoba Hydro Act govern this crown corporation.
Residents across Manitoba receive electricity services from Manitoba Hydro, including the off-grid remote northern communities, which comprise what is known as the ‘Diesel Zone’ due to their reliance on diesel- generated electricity (PUB 2020).
Manitoba Hydro designs, owns and operates all hydroelectric facilities, as well as one natural gas and four diesel electricity generators. All wind and biomass facilities are owned and operated by IPPs. Table 2.4.2 lists all electricity generators in the province.
12 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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Table 2.4.2: Electricity Generation Participants in Manitoba Nameplate Percentage of Company Capacity Installed (MW) Capacity Manitoba Hydro 5369 94.5% Pattern Energy 138 2.4% Algonquin Power 120 2.1% Customer Owned DG 31 0.5% IPP 22 0.4% Data source Manitoba Hydro (2019), NACEI. Table by CERI.
Customer-owned and Central Energy Procurement DG Policy Framework Manitoba Hydro’s guide, Technical Requirements for Connecting Distributed Resources to the Manitoba Hydro Distribution System, (2003) sets the regulatory framework to allow consumers to produce their electricity using distributed generation system connected at 50kV and less, and a maximum nameplate capacity of 10MW. This guide includes the requirements for renewable and non-renewable generating technologies(Government of Manitoba 2003) and are all under the umbrella of non-utility generation options.
Residents of Manitoba who install non-utility generation can opt for one of four available categories:
1) Type I - Load testing of backup generation 2) Type II - Load displacement only intended for personal consumption 3) Type III - Load displacement plus excess generation exported to the grid 4) Type IV - Independent Power Producers intended for those who only want to sell their generation back to the grid
For the third option, customers sell excess generation back to Manitoba Hydro at the non-utility generation price (Manitoba Hydro 2020). The non-utility generation price is lower than the utility rate paid when the customers draw electricity from the grid, as the latter must recover delivery and administration charges. For the 2019 fiscal year, the non-utility price was $0.03949/kWh. Customers opting for this option are under a net billing rate mechanism. The compensation for those opting for the third option is through PPA contracts negotiated with the utility.
In 2015, Manitoba Hydro reported that it had about 12MW of non-utility generation contracts from flare gas technologies (Manitoba Hydro 2015). As of 2020, there is no updated information regarding the progress of their non-utility generation policy.
Manitoba Hydro launched a two-year pilot program called the Solar Energy Pilot Program in 2016, which offered financial incentives towards purchasing PV systems. The program was targeted at residential and small commercial customers with less than 200kW of electric load. Customers under the pilot program were under a net billing rate mechanism (Manitoba Hydro 2018a). The program ended as of April of 2018 (Manitoba Hydro 2018b). Manitoba Hydro reports that the initiative attracted 981 customers, which result
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in 14.8GWh of electric savings(Efficiency Manitoba 2019). The total installed capacity of solar distributed energy resources is 31MW.
Residential and Commercial Rate Schedules Manitoba Hydro offers three types of rates for residential customers based on their location: First Nations on-reserve, diesel zone customers, and all other regions. All these rates consist of a basic charge and an energy charge. The basic charge doubles for services over 200 amps, and it covers the fixed administrative costs, while the energy charge covers the variable costs associated with fuel and electricity purchases, as well as a share of the fixed infrastructure costs associated with the generation, transmission and distribution systems. Table 2.4.3 shows the residential effective for 2020 rate for all regions outside the diesel zone and First Nations on-reserve.
Table 2.4.3: Residential Rates Rate Class Rate Charge Basic Charge - Less than 200Amp ($/month) $8.62 Basic Charge - More than 200Amp ($/month) $17.24 Residential Energy Charge ($/kWh) $0.09 GST 5% PST 7% City of Winnipeg 2.5%
For commercial customers, Manitoba Hydro structures its rates based on the specific site kVA demand requirements, as well as the ownership of the transformation. The rates have a basic charge, a demand charge for metered loads, and a three-step declining block rate for the energy charge. Table 2.4.4 shows the commercial rates for utility-owned transformation.
Table 2.4.4: Commercial Rates Rate Class Rate Charge Basic Charge - Single Phase ($/month) $20.09 Basic Charge - Three Phase ($/month) $31.58 General Energy Charge - First 11,000 kWh ($/kWh) $0.09012 Service Rate Small - Energy Charge - Next 8,500 kWh ($/kWh) $0.06662 Demand < Energy Charge - Balance of kWh ($/kWh) $0.04211 50kVA GST 5% PST 7% City of Winnipeg 5%
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2.5 Ontario Ontario is one of the two remaining provinces in Canada that generates electricity from nuclear reactors. The Canadian Energy Regulator indicates that Ontario owns and operates 18 out of 19 nuclear reactors currently in operation in the country, and these contribute about 60 percent of all the electricity generated within the province. Renewable sources of electricity represent about 35 percent of total generation, and the remaining 10 percent comes from natural gas (Statistics Canada 2019).
In terms of the total installed capacity, nuclear represents about 35 percent, followed by 30 percent for natural gas and the rest represented by renewable sources(IESO 2019a). Table 2.5.1 summarizes the installed capacity and the fiver-year (2014-2018) average annual generation by source.
Table 2.5.1: Electricity Generation Mix in Ontario Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity13 Generation (MW) (TW.h) Nuclear 13009.0 30.9% 91.94 58.70% Natural Gas 11270.0 26.8% 15.32 9.78% Hydro 9065.0 21.6% 37.81 24.14% Wind 4486.0 10.7% 9.61 6.14% Solar 478.0 1.1% 1.53 0.98% Biofuel 295.0 0.7% 0.40 0.26% DG - Solar 2163.4 5.1% N/A - DG - Wind 590.5 1.4% N/A - DG - Hydro 280.2 0.7% N/A - DG - Gas 276.2 0.7% N/A - DG - Bioenergy 110.0 0.3% N/A - DG - Other 24.2 0.1% N/A - Data source IESO (2019b), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Like Alberta, Ontario liberalized and restructured its electricity market in the late 1990s, opening the doors for private companies to participate in the market. However, the provincial government remained highly involved in the industry throughout the electricity supply chain.
At the wholesale level, the government structured the industry as a competitive market where different suppliers compete to generate and supply electricity into the market. Ontario Power Generation (OPG), established under the Business Corporations Act, is the largest producer of electricity in the province, both in terms of installed capacity and total generation. While OPG is wholly owned by the Province of Ontario, the company is not considered a Crown corporation (OPG 2019). The rest of the installed generating capacity is distributed among private companies and corporations in partnership with local governments, such as Bruce Power, which operates under a lease agreement with OPG.
13 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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Table 2.5.2 lists the top 5 companies that own and operate electricity generation facilities as a percentage of total installed capacity. All other companies that own electricity generation have an installed capacity of less than 3 percent. Table 2.5.3 shows the main transmission and distribution companies.
Table 2.5.2: Electricity Generation Market Participants in Ontario
Nameplate Percentage of Company Capacity (MW) Installed Capacity
Ontario Power Generation 16245 46% Bruce Power 6276 18% Brookfield Renewable Power 1408 4% TransAlta 1070 3% Greenfield Energy Centre LP 1005 3% Data source IESO (2019b), NACEI. Table by CERI.
Ontario’s transmission and distribution of electricity also consist of a mix of entities. However, Hydro One’s transmission system, which was a Crown corporation before 2015, accounts for 98 percent of the provincial transmission capacity (Hydro One 2019). At the distribution level, Hydro One is also the largest distribution company based on customers. However, there are many other private and municipally owned distribution companies across the province. The transmission and distribution systems remain regulated, and the tariffs are regulated by the Ontario Energy Board (OEB).
In terms of electricity retailing, customers in Ontario also have a choice between retailing electricity from regulated utilities or competitive retailers. OEB lists nine companies that are licensed to retail electricity across the province.
Table 2.5.3: Top 5 Transmission and Distribution Companies in Ontario Company Transmission Distribution Hydro One Networks Inc. Yes Yes Alectra Utilities Corp. No Yes Toronto Hydro-Electric No Yes Hydro Ottawa No Yes London Hydro No Yes Note: In addition to these companies, there are over 60 distribution utilities that are currently in operation in Ontario.
Data source OEB (2019). Table by CERI.
Customer-owned and Central Energy Procurement DG Policy Framework The overall provincial policy direction has been to support the growth of DG within the province. In 2006, the Ontario government introduced the Renewable Energy Standard Offer Program (RESOP) to promote
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renewable DG with an installed capacity of less than 10MW. Participants in this program were offered a 20-year fixed-price contract to sell their output back to the province, and it was exclusive for systems connecting into the distribution system (Ontario Power Authority 2006).
The program was cancelled after the provincial government enacted the Green Energy and Green Economy Act in 2009, which resulted in the introduction of the Feed-in Tariff (FIT) program, promoting the growth of renewable generating systems with more than 10kW of capacity. The government also launched the Micro-FIT program to promote generating systems with less than 10kW of capacity. These programs were one of North America’s first comprehensive guaranteed pricing structures for small-scale renewable electricity generation. Customers who participated in the FIT and Micro-FIT programs were not able to use the generation to displace onsite loads. The FIT program eventually evolved to include three different categories:
1) Large-FIT program for systems greater than 500kW with the option of connecting into the transmission and distribution system. 2) Small-FIT program for systems with a generating capacity between 10kW and 500kW, exclusively connected to the distribution system. 3) Micro-FIT program for systems with less than 10kW of capacity.
The RESOP program resulted in 825MW of installed capacity, and the first round of FIT program brought 1,212MW, 580MW and 261MW from the Large, Small and Micro FIT programs, respectively. All connected into the distribution system (IESO 2019b).
As of December of 2016, the IESO stopped accepting applications under the FIT programs. Customers trying to offset electricity consumption from the grid have the choice of participating in the Net-Metering program, which allows them to send excess self-generation from renewable sources to the distribution system for a credit towards their energy charges.
Residential and Commercial Rate Schedules The absence of a single vertically integrated utility in Ontario allows for a transparent breakdown of the many costs that need to be recovered from the end-users of electricity each billing period, including transmission, distribution and energy charges and other systems, administrative and municipal fees and charges. Retailers are responsible for collecting all these payments from their customers and transferring them to the corresponding recipients. Ontario has time of use residential electricity rates. Residential customers in remote communities are supplied by Hydro One Remotes and 5 Nations Power Authority.
Table 2.5.4 shows the rate structure for residential customers across four distribution service areas in Ontario. Table 2.5.5 shows the rate structure for commercial connections.
2.6 Quebec Electricity System Quebec has the lowest reliance on fossil-fuel electricity generation in Canada. Hydroelectric power is the primary source of electricity in the province, followed by wind. Data between 2014 and 2018 indicate that
July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 23
99 percent of the electricity generated during this period came from renewable sources (Statistics Canada 2019). The total installed hydroelectric capacity in the province is 36.8GW. However, Hydro Quebec, the provincial Crown corporation, has access to almost all the output from the Churchill Falls generating station in Labrador, which is about 5.4GW (Hydro-Québec 2020). Thus, Quebec has access to more than 40GW of hydroelectric installed capacity in the region.
Table 2.6.1 summarizes the installed generation capacity and a five-year average (2014-2018) annual generation by source.
Table 2.5.4: Residential Rates
London Hydro- Toronto- Alectra Residential Hydro One Hydro Brampton Electricity price On-Peak Rate $/kWh $0.208 for Regulated Mid-Peak Rate $/kWh $0.144 Price Plan (RPP) Time-of-Use Off-Peak Rate $/kWh $0.101 Customers Fixed Monthly Charge $/month $25.38 $33.57 $38.34 $20.92 IESO Smart Metering Entity Charge $/month $0.57 $0.57 $0.56 $0.57 "Distribution" Delivery Distribution Volumetric Rate Riders $/kWh $0.0019 $0.0030 $0.0164 $0.0040 Network Charge $/kWh $0.0070 $0.0087 $0.0074 Connection Charge $/kWh $0.0062 $0.0076 $0.0065 1.34 0.5 Charges $/month $/month Other Riders 3.03 0.0019 Credits $/month $/month Wholesale Market Service Charge $/kWh $0.0030 $0.0034 $0.0039 $0.0032 Regulatory Capacity Based Recovery $/kWh $0.0004 - $0.0004 Rural Rate Protection Charge $/kWh $0.0005 $0.0005 $0.0003 Other Charges Administration Charge $/month $0.25 $0.25 $0.25 $0.25 HST % 13% Government Ontario Electricity Rebate % 31.80%
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Table 2.5.5: Commercial Rates London Hydro- Toronto- Alectra Commercial - Less than 50kW Hydro One Hydro Brampton Electricity price On-Peak Rate $/kWh $0.208 for Regulated Mid-Peak Rate $/kWh $0.144 Price Plan (RPP) Time-of-Use Off-Peak Rate $/kWh $0.101 Customers Fixed Monthly Charge $/month $33.39 $25.59 $36.98 $25.35 IESO Smart Metering Entity Charge $/month $0.57 $0.57 $0.56 $0.57 Delivery Distribution Volumetric Rate Riders $/kWh $0.0135 $0.0301 $0.0342 $0.0169 Network Charge $/kWh $0.0066 $0.0068 $0.0154 $0.0066 Connection Charge $/kWh $0.0055 $0.0056 $0.0055 0.00167 0.64 Charges $/kWh $/month Other Riders 0.00484 0.0019 Credits $/kWh $/month Wholesale Market Service Charge $/kWh $0.0030 $0.0034 $0.0039 $0.0032 Regulatory Capacity Based Recovery $/kWh $0.0004 - $0.0004 Rural Rate Protection Charge $/kWh $0.0005 $0.0005 $0.0003 Other Charges Administration Charge $/month $0.25 HST % 13% Government Ontario Electricity Rebate % 31.80%
Table 2.6.1: Electricity Generation Mix Quebec Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity14 Generation (MW) (TW.h) Hydro 36831.0 90.1% 198.05 95.40% Wind 3508.0 8.6% 7.55 3.60% Natural Gas 411.0 1.0% 0.07 0.01% Diesel 131.0 0.3% 0.13 0.13% Data source Hydro Québec (2020), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Electricity is supplied to most consumers via Hydro Quebec, a Crown corporation established in 1944. Hydro Quebec is the largest electric utility in Canada. Like BC Hydro and Manitoba Hydro, Hydro Quebec is responsible for delivering electricity to off-grid communities across the province. It is here where Hydro Quebec makes use of its 24 diesel generation units.
The Hydro Quebec Act and the Act respecting the Régie de l’énergie are the two key pieces of legislation governing Quebec’s electricity market. The former governs Hydro Quebec, and the latter specifies the
14 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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mandate and authority that the regulator, Régie de l’énergie, has to establish, monitor, and enforce a mandatory regime of reliability standards for electricity transmission (NRCan 2015).
Outside of some small municipalities that provide electric utility services for their residents, Hydro Quebec serves most of the territory within the province. Hydro Quebec also owns and operates about 85 percent of the total installed generating capacity in the province and purchases all the electricity output generated within the province from 39 wind farms and small hydropower plants operated by IPPs, as well as most of the output from biomass and biogas cogeneration in Quebec (Hydro-Québec 2020). Table 2.6.2 lists the top five companies that own electricity generation in Quebec.
Table 2.6.2: Electricity Generation Participants in Quebec
Nameplate Percentage of Company Capacity Installed (MW) Capacity Hydro Quebec 37243 85.8% Rio Tinto Alcan 2687 6.2% Cartier Wind Energy 590 1.4% EDF Énergies Nouvelles 530 1.2% Invenergy 295 0.7% Data source Hydro Québec (2020), NACEI. Table by CERI.
Customer-owned and Central Energy Procurement DG Policy Framework In 2006, the Quebec government adopted the energy policy laid out in Using Energy to Build the Quebec of Tomorrow. The government’s energy strategy is to commit to set up clear guidelines for self-generators. There are some concerns regarding the allocation of water resources to generate electricity at a small scale, and the potential misuse of these resources by self-generators to profit from exports of electricity out of the province (Ministère des Ressources Naturelles et de la Faune 2006).
Stemming from this strategy, the government launched a Net-Metering program allowing customers to produce renewable electricity for their consumption and receive credits for the excess generation they supply back into the grid. The generating capacity under this program is limited to 50kW (Hydro Québec 2006). Customers who want to produce larger quantities of electricity, up to 50MW, using crown resources must follow the standardized application process with the Government of Quebec.
In 2015, the Ministère de Énergie et Ressources Naturelles released The 2030 Energy Policy (Government of Québec 2016) with the impetus to keep consumers at the forefront of impending initiatives such as DG, primarily through geothermal and solar energy. Under this policy, the provincial government states its support to authorize consumers to become electricity self-generators through the net metering rate option.
To the best of our knowledge, the total installed generating capacity that has resulted from the Net- Metering program is not reported publicly. Hydro Quebec reports that it has access to 1,056MW of capacity from other suppliers, though it does not specify the this electricity source.
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Residential and Commercial Rate Structure More than 4MM residential and around 300K commercial customers across Quebec receive electric power services from Hydro Quebec. For the former, the rate is a two-step inclining block rate with a system access charge per day. The rates for commercial customers have a two-step declining block rate but are further differentiated based on whether the customer is billed for power demand or not. The commercial rates are defined as follows: Rate G for customers with billing demand under 65kW and Rate M for customers with billing power demand of at least 50kW within the previous 12 months. Table 2.6.3 shows the residential rates applicable as of 2020. Table 2.6.4 shows the rate schedule for commercial customers under Rate G.
Table 2.6.3: Residential Rates Rate Class Rate 2020 System Access Charge ($/day) $0.406 First 40kWh/day Energy Charge ($/kWh) $0.061 Residential - Rate D Remaining kWh/day Energy Charge ($/kWh) $0.094 QST 9.975% GST 5%
Table 2.6.4: Commercial Rates Rate Class Rate 2020 System Access Charge ($/day) $12.330 First 15,090kWh Energy Charge ($/kWh) $0.0990 Commercial - Remaining kWh Energy Charge ($/kWh) $0.0762 Rate G Power Demand exceeding 50kW ($/kW) $17.640 QST 9.975% GST 5%
2.7 New Brunswick Electricity System Other than Ontario, New Brunswick is the other province in Canada where electricity is generated from nuclear reactors. A single nuclear reactor is the primary source of electricity for the province (New Brunswick has 1 out of 19 nuclear reactors in operation in Canada), and on average, it accounted for about 35 percent of the electricity generated in the province between 2014 and 2018. While hydro and other renewable sources of electricity account for almost 25 percent of total generation, fossil-fuel based generation (natural gas, coal and oil) still represents a sizeable percentage of the total electricity generation in the province (~40 percent)(Statistics Canada 2019).
In terms of the total installed capacity, carbon-based generation represents about 55 percent, followed by renewable sources at 30 percent and the 15 percent left represented by nuclear (New Brunswick Power
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2017). Table 2.7.1 summarizes the installed capacity and the five-year (2014-2018) average annual generation by source.
Table 2.7.1: Electricity Generation Mix in New Brunswick Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity15 Generation (MW) (TW.h) Nuclear 660.0 15.3% 4.77 33.03% Hydro 950.0 22.0% 2.79 19.37% Natural Gas 378.0 8.7% 2.46 17.07% Coal 467.0 10.8% 2.41 16.70% Wind 294.0 6.8% 0.79 5.48% Fuel Oil 972.0 22.5% 0.73 5.09% Biomass 77.0 1.8% 0.46 3.22% Diesel 525.0 12.1% 0.01 0.06% Data source New Brunswick Power (2017), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Most residents in New Brunswick receive electric utility services from New Brunswick Power (NB Power), a Crown corporation established in 1920. NB Power owns and operates 88 percent of the total installed generation capacity in the province. It is the sole developer and owner of the provincial transmission system (Government of New Brunswick n.d.), it functions as the local electric balancing authority and, other than three municipalities16, it is responsible for the distribution of electricity across the province. Table 2.7.2 lists the top five companies that own electricity generation in New Brunswick.
Table 2.7.2: Electricity Generation Participants in New Brunswick Nameplate Percentage of Company Capacity Installed (MW) Capacity NB Power 3803 88.0% TransAlta 150 3.5% Suez Renewable Energy 99 2.3% TransCanada 88 2.0% ACCIONA Energy 45 1.0% Data source New Brunswick Power (2017), NACEI. Table by CERI.
15 The percentage is calculated based on the total installed capacity (both transmission and distribution connected). 16 Edmundston, Saint John and Perth-Andover
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Customer-owned and Central Energy Procurement DG Policy Framework In 2015, the provincial government introduced the Electricity from Renewable Resources Regulation, which regulates the Locally Owned Renewable Energy Projects that are Small in Scale Program (LORESS) (Government of New Brunswick 2016). The LORESS program directed NB Power to endeavour to obtain up to 80MW of renewable energy through different sub-programs. Included in these sub-programs are the Embedded Generation and a Net Metering program (New Brunswick Power 2017). The regulation also includes the procurement of renewable energy generation through a Community Energy Program.
The Embedded Generation program allows locally owned small-scale renewable electricity generators (between 100kW and 3MW) to sell electricity to NB Power at a long-term fixed-price (FIT), with an initial maximum program allocation of 20MW. The Net Metering Program allows consumers to produce renewable energy from small-scale generators (less than 100kW systems) for their consumption with the option to sell excess electricity back to NB Power. Customers under this program are subject to a net metering rate structure (Government of New Brunswick, 2017).
In the 2017 Integrated Resource Plan, NB Power reported that the Embedded Generation program would bring 13MW of new renewable installed capacity by 2020, to fulfil the 20MW program allocation. There are no further references to the number of subscribers to the Net Metering program or the Community Energy Program.
Residential and Commercial Rate Schedules Residential customers are subject to a simple electricity rate structure that includes a service charge, an energy charge and provincial and federal taxes. For commercial customers, the energy charge is structured as a two-step declining block rate, and it also includes a demand charge. Table 2.7.3 and 2.7.4 show the rate structure for commercial and residential customers.
Table 2.7.3: Residential Rates Rate Class Rate 2020 Service Charge ($/month) $22.39 Residential Energy Charge ($/kWh) $0.112 HST 15%
Table 2.7.4: Commercial Rates Rate Class Rate 2020 Service Charge ($/month) $23.36
Commercial - First 5000 kWh/month - Energy Charge ($/kWh) $0.1345 General Service Balance of kWh - Energy Charge ($/kWh) $0.0954 (Standard) Demand exceeding 20kW ($/kW) $10.750 HST 15%
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2.8 Nova Scotia Electricity System Similar to Alberta and Saskatchewan, Nova Scotia’s access to coal and natural gas has resulted in a provincial electricity energy system dominated by fossil-fuel based generation. Between 2014 and 2018, coal and natural gas accounted for almost 75 percent of the total provincial generation. The split between coal and natural gas has remained constant throughout this period (58 percent and 16 percent, respectively). Renewable generation accounts for over 22 percent of the total output, with hydro and wind generation representing almost 10 percent each (Statistics Canada 2019).
As of 2019, fossil-fuel based generation represented about 65 percent of the total installed capacity in the province, with coal accounting for 40 percent. Table 2.8.1 summarizes the installed generation capacity and the five-year (2014-2018) average annual generation by source.
Table 2.8.1: Electricity Generation Mix in Nova Scotia Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity17 Generation (MW) (TW.h) Coal 1234.0 39.3% 5.91 58.92% Wind 443.1 14.1% 1.00 10.01% Hydro 405.9 12.9% 0.95 9.47% Fuel oil / Natural gas 318.0 10.1% 0.03 0.30% Natural gas 242.0 7.7% 1.65 16.46% Light Oil 198.0 6.3% 0.03 0.30% Biomass 116.0 3.7% 0.45 4.53% DG - Wind 154.2 4.9% N/A - DG - Other Renewables 30.4 1.0% N/A - DG - Biomass 6.4 0.2% N/A - DG - Solar 4.1 0.1% N/A - Data source NS Power (2019), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Nova Scotia Power Inc (NS Power), an investor-owned utility is responsible for most of the provincial electric system (NRCan2015a), provides electric utility services to all but six municipalities within the province. Six municipalities own and operate small electric grids[17] and service their residents directly. NS Power serves almost 525 thousand customers, owns and operates almost 95 percent of the provincial electricity system (Government of Nova Scotia 2014). The Nova Scotia, Public Utilities Act, provides the legal framework that NS Power operates within, and the Nova Scotia Utility and Review Board (UARB) regulates the electricity rates and tariffs.
17 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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Out of the total installed generating capacity in the province, about 85 percent is owned and operated by NS Power. Considering that NS Power owns most of the non-intermittent generation, the company controls just about all the firm capacity across the province (NS Power 2019). The company also has a minority stake in three wind farms operated by IPPs, and the market participants' data indicates that no single IPP individually owns and operates more than 2 percent of the installed capacity. Table 2.8.2 lists the top five companies that own and operate electricity generation facilities as a percentage of total installed capacity
Table 2.8.2: Electricity Generation Participants in Nova Scotia Nameplate Capacity Percentage of Company (MW) Installed Capacity Nova Scotia Power 2552 81.0% Oxford Frozen Foods / NS Power 102 3.2% Shear Wind 62 2.0% RMS Energy 51 1.6% Renewable Energy Services 32 1.0% Data source NS Power (2019), NACEI. Table by CERI.
Customer-owned and Central Energy Procurement DG Policy Framework As part of Nova Scotia’s 2010 Renewable Electricity Plan, the province introduced a community FIT program referred to as COMFIT (Government of Nova Scotia 2010). The COMFIT program’s objective was to support the development of renewable DG by municipalities, First Nations, cooperatives, and other communities. The program ran between 2011 and 2016, adding more than 150MW of renewable generation installed capacity, with projects ranging between 0.05 and 7.05MW, all community-owned and connected into the distribution system (Department of Energy and Mines 2019).
A significant change in the legislative framework happened in 2013 when the government introduced the Electricity Reform Act, which enables final consumers to bypass the utility companies and purchase energy directly from renewable energy providers.
Following the success of the COMFIT program, in their 2015 Electricity Plan: Our Electricity Future (Government of Nova Scotia 2015), the province introduced two new programs promoting DG: Solar for Community Buildings Pilot Program, and Enhanced Net Metering Program. The former offers long-term fixed-price contracts (20 years power purchase agreements) to those installing PV systems on buildings (capacity less than 75kW). The latter promotes small-scale renewable generation (capacity less than 1MW) by offering a net-metering rate structure to these customers. As of 2018, there were 532 residential solar installations and 49 in other customer classes in the net metering program, for a total installed capacity of about 4MW (NS Power 2019).
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Residential and Commercial Rate Schedules NS Power residential rates and commercial rates are presented in the NS Power Tariff (NS Power 2020b). For residential customers, there is one rate that applies for customers using electric-based heating systems utilizing Electric Thermal Storage (ETS) equipment and electric in-floor radiant heating systems. This rate is designed as a Time-of-day charge for the energy component (Rate Code 05 & 06) plus all other charges. Otherwise, all other residential customers are subject to a flat energy charge, plus all other charges (Rate Code 02, 03 & 04). Table 2.8.3 shows the residential rate structure under the former.
Table 2.8.3: Residential Rates Rate Class Rate 2020 Customer Charge ($/month) $10.83 Residential Energy Charge ($/kWh) $0.177 (Rate Code 02, 03 Fuel Adjustment Mechanism (FAM) - Credit ($/kWh) $0.019 & 04) HST 15%
The rates for commercial customers are differentiated based on their monthly metered demand and minimum energy consumption. Small Commercial Rate (annual consumption < 32,000kWh); Commercial Rate (annual consumption < 32,000kWh & billing demand < 1,800kW) and Large Commercial Rate (billing demand > 1,800kW). The energy charge is structured as a two-step declining block rate. Table 2.8.4 shows commercial service rates for small commercial customers.
Table 2.8.4: Small Commercial Rates Rate Class Rate 2020 Customer Charge ($/month) $12.65 First 200kWh/month - Energy Charge ($/kWh) $0.1635 Small Commercial Balance of kWh - Energy Charge ($/kWh) $0.1454 (Rate Code 10) Fuel Adjustment Mechanism (FAM) - Credit $0.017 ($/kWh) HST 15%
2.9 Newfoundland and Labrador Electric System About 95 percent of the electricity supply in the province comes from renewable sources, with hydroelectric generation accounting for 94.5 percent of it (Statistics Canada 2019). A small fraction of the generation comes from heavy fuel oil and diesel. As of 2019, close to 90 percent of total installed capacity was represented by hydroelectric generation, with fossil-fuel based generation accounting for almost 10 percent.
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Once the Muskrat Falls hydroelectric project is completed (824MW), the province expects the percentage of renewable sources to be 98 percent. Further, the second phase of the Lower Churchill River development at Gull Island could bring an extra 2,250MW of hydroelectric capacity (Government of NL 2015a). Table 2.9.1 summarizes the installed generation capacity and the five-year (2014-2018) average annual generation by source.
Table 2.9.1: Electricity Generation Mix in Newfoundland & Labrador Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity18 Generation (MW) (TW.h) Hydro 6977.7 89.1% 39.32 94.86% Fuel oil 490.0 6.3% 1.47 3.55% Natural Gas 160.0 2.0% 0.24 0.58% Diesel 128.5 1.6% 0.23 0.55% Wind 54.0 0.7% 0.19 0.46% Biomass 17.6 0.2% N/A - Wind, Diesel, Hydrogen 0.3 0.0% N/A - DG - PV & Wind 0.03 0.0% N/A - Data source NLH (2020), NP (2007), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
There are two electric utilities in the province, Newfoundland Power (NP) and Newfoundland and Labrador Hydro (NLH). NP is a vertically integrated utility that operates the electricity system throughout the island portion of the province. This area covers about 87 percent of the total customers within the province (~268,000). The rest of the territory is served by NLH, which includes the rural and remote areas that are not connected to the main electric system. NLH refers to these areas as Isolated Systems, which are mostly served with diesel generation or purchases from Hydro Quebec. Both electric utilities are regulated by the Board of Commissioners of Public Utilities (PUB).
The electric system market design allows for IPPs to participate in the wholesale electricity generation. Furthermore, a contract, dated back to 1969, grants exclusive access to Hydro-Quebec to almost all the output from the Churchill Falls generation station (5,428MW). This generating unit represents about 70 percent of the total installed capacity in the province. Thus, residents within the province depend on the 30 percent remaining of the installed generating capacity in the province, as well as imports. Table 2.9.2 lists the top five companies that own electricity generation facilities as a percentage of total installed capacity.
18 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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Table 2.9.2: Electricity Generation Participants in Newfoundland & Labrador
Nameplate Percentage of Company Capacity Installed (MW) Capacity Churchill Falls (Labrador) 5428 69.3% Corporation Newfoundland and 1782 22.8% Labrador Hydro Churchill Falls (Labrador) Corporation, Iron Ore 225 2.9% Company of Canada, Wabush Mines Kruger Energy 156 2.0% Newfoundland Power 139 1.8% Data source NLH (2020), NP (2007), NACEI. Table by CERI.
Customer-owned and Central Energy Procurement DG Policy Framework In 2007, the provincial government launched its Energy Plan: Focusing Our Energy (Government of NL 2015a), where the provincial environmental goals and energy policy were laid out. In this document, the government committed to developing a net metering policy to provide consumers with the regulatory support to install DG. In 2015 the government launched the Net Metering Policy Framework, which allowed customers to install DCG with a capacity of up to 100kW. This policy’s intention was not to increase the mix of renewable energy, but rather to allow customers to offset their energy usage (Government of NL 2015b). The Net Metering program has a total provincial limit of 5MW of generation installed (NLH 2019).
In the same year, the government introduced the Biogas Electricity Generation Pilot Program. This program included generating systems with less than 2MW of capacity; the compensation structure in this program is based on a variable rate, which is equal to 90 percent of the avoided system marginal cost. This program also has a cap of 5MW (NL Government, n.d.).
The latest report for this program indicates that there is a total of 419kW of installed capacity across the province. Newfoundland and Labrador Hydro reports that the company has one customer under this rate structure (NLH 2019). All other customers are in the NP service area.
Residential and Commercial Rate Schedules The rates for residential customers within the NP service are split between the level of amp services required (200-amp service threshold), with a flat rate for their energy use. Table 2.9.3 shows the residential rates for customers in the NP service area.
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Table 2.9.3: Residential Rates Rate Class Rate 2020 Service Charge - Less than 200-amp ($/month) $15.95 Residential - Service Charge - More than 200-amp ($/month) $20.97 Rate #1.1 Energy Charge ($/kWh) $0.122 HST 15% Data source NLH (2020), NP (2007), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
The rates for commercial customers are differentiated based on the type of connection required (unmetered, single phase and three phase) as well as the maximum demand within 12 months. Table 2.9.4 shows the commercial service rates for a commercial customer with less than 100kW of demand.
Table 2.9.4: Commercial Rates Rate Class Rate 2020 Basic Charge - Single Phase ($/month) $20.13 Commercial - First 3500 kWh/month - Energy Charge ($/kWh) $0.1206 Rate #2.1 Balance of kWh - Energy Charge ($/kWh) $0.0974 (<100kW) Demand exceeding 10kW - Dec through Mar ($/kW) $9.790 HST 15%
2.10 Prince Edward Island (PEI) Electric System PEI has the lowest reliance on fossil-fuel based generation in Canada. As a percentage of the total electricity generated within the province, between 2014 and 2018, PEI generated 98.8 percent of its electricity from renewable sources, mostly wind turbines and a negligible fraction from biomass. PEI is the only province in Canada that does not generate electricity from hydroelectric facilities (Statistics Canada 2019).
In terms of the provincial installed generating capacity, more than 50 percent is represented by wind turbines, followed by fuel oil, which accounts for about 28 percent of the installed capacity. However, these units are not used regularly. Currently, the majority of the electricity consumed in the province is imported from neighbouring provinces. Residential customers in Charlottetown pay an average utility rate of 16.83 ¢/kWh, which is the highest in Canada as of 2019 (Hydro Quebec 2019b).
Table 2.10.1 summarizes the installed generation capacity and the five-year (2014-2018) average annual generation by source.
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Table 2.10.1: Electricity Generation Mix in PEI Nameplate Annual Average Percentage of Percentage Capacity as Generation Source Installed of Total of 2020 2014-2018 Capacity19 Generation (MW) (TW.h) Wind 203.6 54.0% 0.61 98.50% Fuel oil 105.0 27.9% < .01 0.42% Diesel 67.0 17.8% < .01 0.66% Biomass 1.2 0.3% < .01 0.42% Data source Maritime Electric (2018), Government of PEI (2020), Statistics Canada (2018), Statistics Canada (2019), NACEI. Table by CERI.
Other than the City of Summerside residents, all other residents in PEI receive electric utility services from Maritime Electric, a privately-owned vertically integrated utility that operates under the provisions of the Electric Power Act and the Renewable Energy Act. Maritime Electric accounts for almost 90 percent of the island-wide electric system (NRCan 2015b).
The province also allows for private investors to participate in the market as IPPs. Table 2.10.2 lists the top five companies that own electricity generation facilities as a percentage of total installed capacity.
Table 2.10.2: Electricity Generation Participants in PEI
Nameplate Percentage Company Capacity of Installed (MW) Capacity Maritime Electric 147 39.0% Suez Renewable Energy 108 28.7% PEI Energy Corporation 74 19.5% City of Summerside Electric Utility 37 9.8% WEICan 10 2.7% Data source Maritime Electric (2018), Government of PEI (2020), NACEI. Table by CERI.
Customer-owned and Central Energy Procurement DG Policy Framework DG had been allowed since the 1970s. However, with the introduction of the Net Metering program in 2004, laid out in the Renewable Energy Act, the government officially set the regulatory framework supporting the growth of DG (Government of PEI 2004). Under this program, customers connecting DG with a capacity of less than 100kW were offered a net metering rate structure (Maritime Electric 2018). This act was amended in 2015 as the share of renewable generation grew from 86 percent to 99 percent between 2005 and 2015, as wind generation accounts for 98 percent of this generation.
19 The percentage is calculated based on the total installed capacity (both transmission and distribution connected).
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In the Energy Strategy, launched in 2016, the province states that it will address the high cost of electricity by focusing on promoting energy efficiency and conservation, reducing internal demand, and increasing utility-scale solar and wind generation. As of 2016, the province reported that 70 residential customers were participating in the Net-Metering program (Government of PEI 2017). There is no information regarding the type of technology or total DG installed capacity.
Residential and Commercial Rate Schedules The rates for residential customers in PEI are differentiated based on urban and rural settings. In terms of charges, the only difference comes in the customer service charge, slightly more expensive for rural residents. Otherwise, the rate is identical. The energy charge is a two-step declining block rate based on monthly energy consumption (kWh). Table 2.10.3 shows the residential rates for customers in urban centers within the province.
Table 2.10.3: Residential Rates Rate Class Rate 2020 Customer Charge ($/month) $24.57 Residential (Rate First 2000kWh/month - Energy Charge ($/kWh) $0.1437 Code 110) Balance of kWh - Energy Charge ($/kWh) $0.1142 HST 15%
The rates for commercial customers are all within one classification: General Service. The rate consists of a two-step declining block rate, a minimum customer charge and a demand charge. Table 2.10.4 shows the General Service Rate structure.
Table 2.10.4: Commercial Rates Rate Class Rate 2020 Customer Charge ($/month) $24.57 General First 5000kWh/month - Energy Charge ($/kWh) $0.1767 Service Balance of kWh - Energy Charge ($/kWh) $0.1154 (Rate Code Demand exceeding 20kW ($/kW) $13.430 232) HST 15%
2.11 Provincial Summary Tables Tables 2.11.1 and 2.11.2 provide a summary of the policies and programs that all provinces across Canada have put in place to either promote customer-owned DG or central energy procurement DG.
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Table 2.11.1: Customer-Owned DG Policies, Programs and Regulations Customer Owned DG Province Customer Owned Programs Nameplate Capacity Technologies Compensation Mechanism
BC Net-Metering Program < 100kW Renewable Energy Net-Metering Technologies
All Technologies AB Micro-generation Regulation < 5MW with GHG intensity Net - Billing < 418kg/MWh Renewable & SK Net-Metering Program < 100kW Carbon Neutral Net-Metering Technologies Type I, II & III - Load displacement < 100kW All technologies Net-Billing MB and export Solar Energy Pilot Program < 200kW Solar PV Net-Billing
Micro-FIT (discontinued) <10kW Renewable Energy Feed-in Tariff Technologies ON Net-Metering Program <10kW Renewable Energy Net-Metering Technologies
QC Net-Metering Program <50kW Renewable Energy Net-Metering Technologies
NB Net-Metering Program <100kW Renewable Energy Net-Metering Technologies
NS Net-Metering Program <100kW Renewable Energy Net-Metering Technologies
NL Net-Metering Program <100kW Renewable Energy Net-Metering Technologies
PEI Net-Metering Program <100kW Renewable Energy Net-Metering Technologies
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Table 2.11.2: Central Energy Procurement with DG Central Energy Procurement with DG Province Central Energy Procurement Nameplate Capacity Technologies Compensation Mechanism Renewable Electric Purchase BC Standing Offer Program between 100kW and 15MW Technologies Agreements AB No Special Program N/A N/A N/A
between 100kW and 1MW Renewable Technologies Purchase Agreements with SK Power Generation Partner Program SaskPower between 100kW and 5MW Carbon-Neutral Technologies MB Type IV - Export only between 100kW and 10MW All technologies IPP Agreement
RESOP <10MW Renewable Long-term fixed price ON Energy Small-FIT (discontinued) between 10kW and 500kW Technologies Feed-in Tariff Large-FIT (discontinued) > 500kW QC No Special Program <50MW All technologies IPP Agreement Renewable NB Embedded Generation between 100kW and 3MW Energy Feed-in Tariff Technologies Renewable NS COMFIT <5MW Energy Feed-in Tariff Technologies Biogas Electricity Generation Pilot NL <2MW Carbon-Neutral Variable Rate Structure Program Technologies PEI No Special Program N/A N/A N/A
Lastly, Hydro-Quebec publishes a yearly report where they compare the monthly bills that the residents across 21 major cities across North America pay for their electricity bills. Figure 2.11.1 presents an excerpt from Hydro-Quebec’s annual rate report and uses the city level information as a proxy for provincial information. This graph is for illustrative purposes, and the intent is to provide the reader with a perspective of the variability in electricity costs for residents across Canada. The data used to recreate this graph was not used for any other calculations in this study.
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Figure 2.11.1: Residential Customers Cost of Electricity Across Canada
Data source (Hydro Quebec 2019b). Figure by CERI.
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Chapter 3: Assessment of Technology Options for Distributed Generation
• The LCOE of residential and commercial solar PV DG systems are lower than the current retail rates. • Operational convenience and declining capital costs makes solar PV a dominant DG investment choice in Canada. • Biomass and MSW based DG systems can provide on-demand electricity and the economy of scale make them suitable for commercial or community size DG implementations. • Natural gas micro CHP systems have higher economic feasibilities at commercial scale implementations.
3.1 Selection of DG Technologies for the Assessment Many technologies can be used for DG developments in Canada and elsewhere. Technological advancements are one of the major drivers of the growth of DG. Technical developments made DG technologies straightforward to install and operate and have lowered their costs. In general, DG may rely on locally extracted primary energy resources (for example, wind, solar, hydro, biomass, or geothermal) or locally purchased, such as natural gas. This study assesses technologies that can be used for DG in population centers in Canada. The assessment in the report is limited to three generating technologies. The three technologies that are assessed in the report and the reasons for their selection are as follows:
• Solar photovoltaic (PV) systems: Solar PV is one of the fastest-growing electricity generation technologies in the world (REN21 2019). The majority of the DG systems installed in Canada under different provincial DG programs have been solar PV systems. Solar PV is a solid-state generation system and requires minimal user intervention during the operational phase, making it appealing for DG. Furthermore, the cost of technology is rapidly declining (IRENA, 2019). • DG with biomass and municipal solid waste (MSW): Biomass and MSW are essentially local resources that can be used for DG. One of the main advantages of this technology is its ability to provide on- demand electricity (i.e., dispatchable). Both biomass and MSW are being used for DG throughout the world. Several projects have been developed across Canada over the past decade. Well managed biomass is a renewable resource that can be used for electricity generation with minimal net GHG emissions. The use of biomass and MSW for DG can be combined with other objectives such as local waste management and managing GHG emissions from landfills. • Natural gas (NG) fired combined heat and power systems (CHP): CHP systems are one of the earliest DG technologies that saw widespread implementation (El-Khattam and Salama 2004). Recent technology developments have expanded the scalability of CHP from few kilowatts to even utility- scale systems. That had made CHP suitable technology for residential and commercial facility integrated DG. Canada has a widespread NG distribution network making widespread access to the
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fuel. NG fired CHP provides an efficient option to satisfy two essential end-use energy services (electricity and thermal energy) for residential and commercial buildings.
The decision to limit the analysis for three technologies was made primarily due to the popularity of these options. Throughout Canada, there is interest in other technologies such as wind, run-of-the-river hydro, and geothermal energy for DG. CERI intends to gradually add other DG potential technologies to the associated data portal.20
3.2 Solar PV for Distributed Generation Over the past two decades, rapid growth in grid-connected solar PV capacity is observed throughout Canada. For example, in 2000, the total installed grid-connected solar PV capacity in Canada was 0.31 MW21. This grew to about 3,095MW by 2018 (Baldus-Jeursen, Poissant, and Johnston 2019). Over the five years 2014-2018, the growth has been dominated by centralized systems, but the share of distributed solar PV systems remains about 35 percent of the national capacity, and the growth continues. The installation cost of all solar PV systems has declined in Canada. In the period 2008 to 2018, the capital cost of residential rooftop solar PV system cost has declined by about 55 percent to CAD$2.93/Wdc22. In the same period, the capital cost of commercial building integrated systems has declined to CAD$2.21/Wdc (63 percent reduction) for 10-100kWdc systems and CAD1.46/Wdc (75 percent reduction) for larger systems (capacity higher than 100kWdc). Most of the growth to date has been observed in Ontario, but other provinces are following suit.
This study assesses the electricity production potential and costs of residential scale and commercial-scale solar PVDG systems.23 The analysis is connected to population centers surveyed by Statistic Canada’s for the 2016 Census of Population (Statistics Canada 2017). This report presents the results for population centers in four provinces (Nova Scotia, Ontario, Alberta, and British Columbia). The results of other provinces are available in the study’s data portal.
A typical building-integrated solar PV DG system consists of an array of solar PV modules and mounting system, an inverter, and other electrical components that connect the PV system to the building electrical system and the grid. Solar PV modules convert solar irradiance to direct current electricity. The inverter converts direct current electricity to alternating current. The integration of electricity storage systems (ESS) into the unit can add more flexibility to solar PV DG systems. ESS allows the DG system to provide on-demand power and added benefits of making the system more flexible. CERI completed a report on
20 The data portal can be accessed via www.ceri/ca/research. 21 This does not include off-grid solar PV systems. Before and through the early 2000s, solar PV growth in Canada was dominated by off-grid system. The growth continues, but there are no official statistics available. The focus of this report is exclusively on grid connected solar PV systems. 22 The capital cost of solar PV systems is expressed in dollars (CAD$) per unit of rated capacity of installed solar PV modules. Solar PV modules produce direct current electricity and therefore, the rated capacity is measured in direct current Watts (Wdc). 23 A detailed assessment of utility scale solar PV potential and economics in all Canadian provinces was conducted in the CERI Study 168 (CERI 2018a).
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electricity storage as a stand-alone service in 2019 (available at www.ceri.ca). Assessment of ESS as a DER technology is excluded from this study and retained for future work.
Solar PV Assessment Procedure This study estimates the time-series production data of solar PV DG systems with different capacities at the population centers considered. Economic metrics such as the levelized cost of electricity (LCOE), the net present value of a solar PV DG investment, and simple payback time are also estimated.
The output of a solar PV system varies with the daily and seasonal variations of solar irradiance. The system’s overall production efficiency varies with solar PV cell temperature, which depends on the solar irradiance, ambient temperature, prevailing wind speeds, and the nominal efficiency of the solar PV modules. Solar irradiance and ambient weather data at all population centers are obtained from the National Solar Radiation Database (NSRDB) developed by the US National Renewable Energy Laboratory (NREL) (Sengupta et al. 2015).24 NSRDB dataset includes the time-series data required for solar PV assessments in most of North America, including all Canadian population centers considered for this analysis. To estimate the output of a solar PV system, we use the System Advisor Model (SAM) developed by the US National Renewable Energy Laboratory (NREL) (NREL 2020)25. Using the physical characteristics of a solar PV system, SAM can simulate solar energy conversion system’s output at designated locations by taking into account variations in solar irradiance and ambient weather conditions. The model is widely used for decision support analyses and empirically validated.
The overall analysis framework is depicted in Figure 3.1. The main solar PV systems assessed, along with the main assumptions, are listed in Table 3.1. The capital costs listed in Table 3.1 refers to full installed costs and includes equipment, procurement, and installation costs. For example, under the assumed conditions, the turnkey installation cost of a 5kWdc residential solar PV system would be CAD$12,500. It is assumed that the currently observed trend of capital cost reduction due to technology learning and will continue. Annual cost reduction rates are estimated using Canadian and international industry data (Baldus-Jeursen, Poissant, and Johnston 2019; IRENA 2019).
All systems are assumed to be building roof-mounted with fixed-tilt rack mounts. The tilt of the array was adjusted to maximize the production at a given location. Each system’s electricity production data is used to estimate different economic and financial metrics. The cost and financial assumptions made for the analysis are also listed in Table 3.1. The calculation of NPV and simple payback analysis requires the rates
24 We should point out that several other high-quality solar radiation datasets that can be used for robust solar PV assessments are available. Another most notable one is the Canadian Weather Energy and Engineering Datasets (CWEEDS) published by Environment and Climate Change Canada (ECCC). The most recent CWEEDS data set covers 492 locations across Canada. NSRDB dataset was used for this analysis as it provided a higher spatial resolution (4km x 4km grid cells across North America and South America) and data for all population centers could be obtained with minimal geographic approximations. 25 This analysis uses the SAM’s physical system simulator model implemented with Python programming language in the PySAM library. This allowed the automated estimation of larger number of population centers and system sizes.
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and structure of the compensation mechanisms. This data was obtained from the survey of provincial electricity rates and DG programs presented in Chapter 2.
Figure 3.1: Solar PV DG System Production and Economic Assessment Process
Table 3.1: Solar PV Systems Assessed and Main Assumptions Residential Commercial building- Commercial building-
rooftop integrated (Small) integrated (Large) Reference capacity 5kWdc 50kWdc 150kW Valid capacity range for cost Up to 10kW 10-100kW Larger than 100kW assumption Mounting system Fixed-tilt rack mount Module efficiency 19% Inverter efficiency 96% Other system losses 10% (electrical, soiling, etc.) Inverter DC-to-AC ratio 1.2 Implied AC capacity 4.2kWac 42kWac 125kWac Near term capital cost (up CAD$2.5/Wdc CAD$2/Wdc CAD$1.5/Wdc to 2025) Capital cost decline rate 4%/year 5%/year 7%/year Annual fixed O&M cost (primarily amortized cost CAD$6/kW-year CAD$5/kW-year CAD$4/kW-year for inverter replacement) System economic life 20 years Inverter life 10 years
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Discount rates (nominal) 2%, 3%, 5% 7%, 10%, 12% used for LCOE calculation Debt interest rate 5% 5% Debt fraction 50% 60% Subsides None Class 43.2 capital cost allowance
Solar PV DG System Assessment Results Figure 3.2 shows the distribution of population centers assessed in Nova Scotia, Ontario, Alberta, and British Columbia, along with the solar PV potential at each location.26 The same results are summarized in Table 3.2. Solar PV potential varies by region as well as by the time of the year. Table 3.2 also shows the average retail electricity prices observed in the respective provinces. Retail electricity prices are all in prices that include energy charges, delivery charges, and admirative fees.
Figure 3.2 Population Centres for DG Assessment
26 The metric used for the solar PV potential is the solar PV capacity factor (= estimated annual output/annual output at rated power) at each location under the assumed technical and resource conditions. Results of other provinces are presented in the study’s data portal.
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Table 3.2: Summary of Demographic Information and Solar PV Potential of Population Centers
Average retail electricity price Capacity factor (in 2018, ¢/kWh) * Number of Population range Number houses range (by Commercial Province population (by population (by population population Small (40kW) centers center) center) Residential center, %) Medium (500kW) 15.56 Nova Scotia 31 1121 - 316,701 437 - 150,284 12.8 - 14.8 15.0 17.26 12.4 Ontario 254 1022 - 5,429,524 382 - 2,059,207 13.0 - 15.4 12.5 17.5 15.0 Alberta 107 1039 - 1,237,656 414 - 489,271 11.7 - 15.7 16.7 18.6 British 11.9 88 1053 - 2,264,823 521 - 944,471 10.2 -14.6 12.4 Columbia 12.2
Data sources: Demographic information: Statistics Canada (2017); capacity factors: CERI estimations in this study; Residential electricity prices: Energy Hub (2020); Commercial electricity prices: Hydro Quebec (2019)
*Retail electricity price includes energy charges, delivery charges, and admirative fees. Residential electricity prices are for monthly consumption of 1000kWh; Commercial retail prices are shown for a customer with a maximum consumption rating of 40kW (top number) and 500kW (bottom number)
Figure 3.3 depicts the monthly production of a 1kWdc solar PV system installed at each of the assessed location, grouped by the province. In all provinces, monthly production varies by about 50% from summer months to winter months. As expected, the production in the summer months is twice as much as that of winter months.
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Figure 3.3: Monthly Production of a 1kW Solar PV System Installed in Different Population Centers
LCOE values of the three types of Solar PV DG systems are presented in Figures 3.4 - 3.6. LCOE is calculated under near-term (2020 – 2025) solar PV capital costs and capital costs in the period 2025 – 2030 (derived using capital cost decline rates presented in Table 3.1). LCOE was also estimated using different discount rates.
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Figure 3.4: LCOE of a Residential Solar PV System (5kWdc)
- LCOE is estimated assuming near-term (2020 - 2025) capital costs (CAD$2.5/Wdc) and medium-term (2025 - 2030) capital costs (CAD$2/Wdc). The numbers in the column head correspond to the nominal discount rate used for LCOE calculation. Project economic life is assumed to be 20 years. The inflation rate is assumed to be 2%. Red horizontal dashed lines correspond to the average retail price observed in
respective provinces in 2018.
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The LCOE refers to the average life cycle cost of owning and operating a solar PV system. Therefore, if the overall average economic return is higher than the LCOE, a specific solar PV investment is economically justifiable. Economic returns on a solar PV DG investment may arise from savings from not having to purchase electricity from the utility or any bill credits from electricity exported to the distribution system. Therefore, the economic return depends on the retail electricity rate paid by the DG system owner, retail electricity rate structure, and compensation rate and mechanism for the exported electricity. Chapter 2 reviewed the rate structure and compensation mechanisms for DG investments (including solar PV) in Canadian provinces. For comparison, the provincial average retail electricity prices in 2018 for different types of customers are also indicated in Figures 3.4-3.6.
It should be noted that the numbers shown here are for a single year and averaged across respective provinces. The exact retail rate varies across population centers, even within a province. Furthermore, in the case of commercial customers, any savings from not having to pay any demand charges due to self- generation is not fully captured through a mere comparison with average retail prices. Those values are fully captured in the private cost-benefit analysis presented in Chapter 4.
Figure 3.5: LCOE of a Small Commercial Solar PV System (50kWdc)
- LCOE is estimated assuming near-term (2020 - 2025) capital costs (CAD$2/Wdc) and medium-term (2025 - 2030) capital costs (CAD$1.5/Wdc). The numbers in the column head correspond to the nominal discount rate used for LCOE calculation.
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Figure 3.6: LCOE of a Large Commercial Solar PV System (150kWdc)
- LCOE is estimated assuming near-term (2020 - 2025) capital costs (CAD$1.5/Wdc) and medium-term (2025 - 2030) capital costs (CAD$1/Wdc). The numbers in the column head correspond to the nominal discount rate used for LCOE calculation. lf d b h fl d b
LCOE values of solar PV systems are influenced mainly by the local resource conditions (i.e., average capacity factor), technology cost (i.e., capital cost), and financing assumptions (primarily the discount rate).
LCOE of all PV systems in Nova Scotia, Ontario, and Alberta are in the same range. Of the four provinces presented in this chapter, solar resource availability is lower in British Columbia locations than in the other three. That has led to higher LCOE in British Columbia. Furthermore, the economics of solar PV appears to be lower due to lower retail prices observed in British Columbia.
Potential capital cost reduction over time makes the LCOE proportionally lower in all provinces and improves the economic viability of solar PV. For example, under assumed capital cost reduction rates, beyond 2025, the LCOE of all solar PV systems would be considerably lower than currently observed retail prices. However, the cost reduction would be to a lesser degree in British Columbia.
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The electricity rate structure of a commercial establishment is more complicated. It depends on the electricity consumption rate, demand charges, location, connection interface (e.g., whether or not the commercial facility owns a connecting transformer), power purchase contracts, etc. Therefore, facility- level assessments are needed for a more informative assessment. On the other hand, for small commercial customers, the rate structure can be generalized. Thus, the interpretation of commercial systems must be made while taking the above factors into account. In the case of commercial systems, the assessment results show that low LCOE is observed due to lower capital cost per unit capacity. As observed in Figures 3.5 & 3.6, the lower capital cost advantage of commercial systems is off-set to some degree by the higher discount rates.
It is required to use an appropriate discount rate to calculate economic metrics such as LCOE and net present value (NPV). The discount rate represents the opportunity cost of capital, which is foregone elsewhere by committing for solar PV investment. Generally, the choice of a discount rate depends on the level of prevailing inflation rates, the level of risk of the project, level of risk aversion of the investor, and risk-free return of other investment options. In the case of commercial facilities, it is plausible the discount rates used for investment assessments will generally be higher. However, in the case of residential solar PV investments, it is challenging to select a generalizable discount rate as the decision for solar PV investments may be influenced by both economic and non-economic factors. For example, a decision to invest in solar PV by an individual household may be driven by altruistic choices such as environmental stewardship. Other macroeconomic factors such as public policies, availability of formal procurement programs, availability of different subsidy programs may also influence the investment decision (Oxera 2011). Due to these factors, this assessment calculates the LCOE values using several discount rates.
3.3 Biomass and Municipal Solid Waste for Distributed Generation Over the years, the biomass usage to produce both electricity and heating has significantly increased (REN21 2019). Also, biomass conversions are considered as a carbon-neutral source of electricity. The conversion of MSW for electricity also helps for waste management at population centers. Biomass and MSW electricity conversions are based on thermal methods such as incineration and gasification. Recovery of Landfill Gas (LFG) and using anaerobic digesters are also technically viable alternatives to develop energy from biomass and MSW.
Overall, biomass and MSW contributes to around 1.9 percent of Canada's electricity generation and has seen a growth of 54 percent between the years 2005 and 2015. According to the Canada Energy Regulator (CER), as of 2014, Canada had about 70 biomass generating power plants with a total installed capacity of 2,408MW (CER 2019b). Most of the existing biomass to electricity conversion facilities are transmission system connected utility-scale power generating systems. Over the past decades, several DG facilities that produce electricity using biomass and MSW have been developed across Canada (Stephen and Wood- Bohm 2016; Future Energy Systems 2020).
This study assesses the potential and cost of utilizing biomass and MSW for DG in Canada. As mentioned above, one of the main advantages of biomass and MSW for DG is the ability to produce on-demand electricity using local resources. The assessment is conducted at the population center level. However, the assessment excludes population centers with low feedstock capacity and those with unreliable
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biomass and MSW resource data. The study focuses on biomass and MSW DG systems with capacities up to 5MW.
Biomass & MSW based DG System Assessment Procedure The supply of biomass and MSW in a given population center varies significantly by type and supply. For example, biomass supply may include agricultural waste, residues from forestry operations, mill residues, etc. Different types of biomass vary by their heating value (measured in GJ/Mt) and moisture content. Those factors, along with the annual supply, determines the overall biomass energy available for DG.
The primary data set used to estimate the biomass resource availability at a given population center is the Agriculture Canada’s Biomass Inventory Mapping and Analysis Tool (BIMAT) (Agriculture and Agri-Food Canada 2020). Using BIMAT, biomass availability within a given population center boundary and a collection area with 25km of the population center boundary is estimated. The main biomass types captured by the analysis includes different straw types (barley, wheat, and corn), forestry residues, mill residues, urban wood residues. For each location, the total annual supply of biomass is estimated. Typical heating values are assigned for each type of biomass.
In the case of MSW to DG potential assessment, waste generation and diversion information of each of the population centers are used (Conference Board of Canada 2016). Where specific information is not available national and provincial averages are used. A constant waste diversion27 percentage of 20 percent is assumed for the analysis.
Several thermal electricity generation technologies are available to convert biomass and MSW into electricity (Ruiz et al. 2013; Patel, Zhang, and Kumar 2016). I this assessment, four technologies are assessed for DG with biomass and MSW. For each technology, the LCOE is calculated for different installed capacities. These technologies differ by the combustion process and the prime mover. The selection of different technologies to produce electricity from biomass and MSW is summarized in Table 3.3.
Table 3.2: Technologies for DG with Biomass and MSW Technology Resource Combustion/chemical Capacities assessed (kW) Prime mover conversion process Incineration in stoker burners Steam turbine (ST) 500, 5000 Biomass Internal combustion Gasification 50, 500, 5000 engine (ICE) Incineration in stoker burners Steam turbine (ST) 500, 5000 MSW Internal combustion Anaerobic digestion (AD) 50, 500 engine (ICE)
Consideration of the distributed electricity generation potential of biomass and MSW at different population centers includes the main technology costs (capital cost, fixed operating and maintenance costs (O&M) any variable O&M costs including any applicable fuel transportation costs), financing assumptions, and conversion efficiencies. For each of the resource, technology, and capacity
27 Waste diversion rate refers to the amount of MSW diverted for DG instead of disposing in landfills.
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combinations, the LCOE is estimated. Since all capacities assessed are generally in commercial DG size, a nominal discount rate of 12 percent and project economic life of 25 years is used for LCOE calculation.
Biomass and MSW based DG System Assessment Results Electricity generation potential and LCOE of different options for DG with biomass and MSW in Nova Scotia, Ontario, Alberta, and British Columbia are summarized in Table 3.4. In the case of DG with biomass, all population centers in Nova Scotia and all but three population centers in British Columbia were excluded from the analysis due to insufficient resource data. In the case of MSW, the amount of energy availability in a given population center depends on the population. Locations that do not have sufficient resources to sustain a capacity factor of 40 percent are excluded from the analysis. Several population centers assessed in each province are also indicated in Table 3.4.
In Ontario, the average electricity generation potential of biomass-fueled DG is 740GWh/year with Gasification + ICE option and 1,130GWh/year with Incineration + ST option. The latter option has a higher potential as the overall conversion efficiency is higher (30-35 percent) compared to gasification + ICE conversion efficiencies (20-25 percent). Depending on the geographic area of the population center, the potential varies significantly. The power generation potential is similar in population centers in Alberta.
The LCOE of DG with biomass is in the range of about 15 – 30 ¢/kWh in all assessed locations. The LCOE reduces with higher installed capacity indicating the economy of scale. Gasification + ICE options at all capacities have lower LCOE than incineration + ST options due to lower capital cost. In Alberta, Gasification + ICE based DG with biomass options has LCOE that is comparable to current retail electricity prices. Incineration + ST options seem to be less competitive at the range of capacities considered. It should be noted that at higher capacities (e.gg, tens of MW capacity range), incineration + ST based biomass systems will likely have lower LCOE. The observations made here are valid only for the capacities assessed.
In the cases of DG with MSW, anaerobic digestion + ICE options have the lower LCOE in all provinces. The overall electricity generation potential is lower and expectedly, proportional to the population in a given location. The LCOE is of DG with MSW is generally higher than current retail prices (see Table 3.2 for retail prices in 2018). The LCOE estimation procedure, however, does not take into account any economic value assignable for the ability of DG with MSW to contribute to local waste management at population centers. Furthermore, diverting MSW for power production can reduce the overall GHG emissions from landfills. The decomposition of organic matter in landfills produces landfill gas (LFG) that primarily consists of methane. Electricity production from MSW can significantly avoid methane emissions associated with landfills.
Most landfills do not produce LFGs in large rates or quantities; in these landfills, venting is the most common method used with a few exceptions where biological or chemical filters are being used. LFG is a free resource with considerable electricity generation potential. According to the Canadian Biogas Association, around 170MW of energy can be produced from LFG in Canada, contributing to around 0.3 percent or electricity demand and reducing around 7 million tonnes of CO2e GHGs (Canadian Biogas Association 2013). Most of the above-estimated potential is not currently utilized. As noted, LFG also remains a free resource where Landfills are unavoidable costs. This reduces the front-end capital
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investment converting the resource to the combustible gas Based on a study by the Canadian Biogas Association, the LCOE of LFG to electricity generation is estimated to be 13 ¢/kWh. However, the overall annual electricity generation potential is low and viable only in centers with a higher population.
Table 3.3: Summary of DG with Biomass and MSW Assessment Results
- For Annual electricity potential, Capacity factor, and LCOE, both the average value and the range observed in respective provinces across the population centers assessed are given in the table. Population centers with low resource supply and those without sufficient data are excluded from
The capacity factor of DG with biomass and MSW is high (over 50 percent) in most locations, summarized in Table 3.4. Confirmed by the higher average capacity factor, the ability to produce on-demand electricity is one of the main advantages of DG with biomass and MSW. A disadvantage of this option is the required fuel handling and preparation can increase the overall cost. The economics of the option is cost-effective
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only at higher capacities. These factors would make biomass and MSW more suitable for large commercial or community scale DG. It would also be suitable for remote communities that already see higher costs of electricity.
3.4 Natural Gas Fired Micro Combined Heat and Power Systems for Distributed Generation The combined heat and power (CHP) systems are heat engines that generate power and harness the wasted heat from the process for the thermal energy demand, including space heating and hot water (Conservatory Hub 2020). The energy (electricity and heat) generated from a typical CHP system is much more efficient than the conventional ways of energy generations in the industry (60-80 percent versus 51 percent, respectively) (EPA 2015). These systems have been successfully applied to the industry since 1970. A recent decades group of lower capacity CHP systems called micro CHP systems have been introduced for residential and small to medium-sized commercial building applications (Conservatory Hub 2020).
Figure 3.7 shows a block diagram of a typical micro CHP system integrated into a residential or commercial building. As indicated, the system fully or partially satisfies the electricity demand and thermal energy demand (a combination of space heating and hot water demand) of the building. Typical micro CHP systems have an electricity generation capacity in the range of a few kilowatts to about 1,000 kW. Most commercial micro CHP systems can be procured in factory-assembled prepackaged systems, lowering the overall capital costs. Pre-packaged systems also simplify the operations and maintenance, lowering the user intervention. They can be operated with gaseous (natural gas, biogas) or liquid fuels (e.g., diesel, heating oils). Some of the benefits of micro CHP systems are reduced energy-related costs, increased reliability, higher overall energy efficiency, reduced emissions, and increased energy resource adequacy. This study focuses only on natural gas-fired, building integrated micro CHP systems.
Figure 3.7: A Typical Building-Integrated Micro CHP System
Source: Adapted from (Conservatory Hub 2020)
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A typical CHP system (including micro CHP systems) consist of three main parts (Tan 2018):
• Heat engine (prime mover) that generates high-temperature thermal energy by combusting the fuel (e.g., natural gas), • Electricity generator that produces electricity by using the high-temperature thermal energy, • Heat recovery unit that captures and uses the low-temperature thermal energy for different applications (space heating and hot water).
Based on the technology that drives the heat engine, there are different types of micro CHP systems, including reciprocating engines (internal combustion), gas turbines, microturbines, and fuel cells, which are discussed below in further details (Tan 2018; EPA 2017). Table 3.5 summarizes the costs and technical parameters of micro CHP systems that are commercially available.
Table 3.4: Summary of Costs and Technical Parameters of Commercially Available Micro CHP Systems Technology Recip. Engine Gas Turbine Microturbine Fuel Cell Electric efficiency (HHV) 27-41% 24-36% 22-28% 30-63% Overall CHP efficiency (HHV) 77-80% 66-71% 63-70% 55-80% Effective electrical efficiency 75-80% 50-62% 49-57% 55-80%
Typical capacity (MWe) .005-10 0.5-300 0.03-1.0 200-2.8 Typical power to heat ratio 0.5-1.2 0.6-1.1 0.5-0.7 1-2
CHP Installed costs ($/kWe) 1,500-2,900 1,200-3,300 2,500-4,300 5,000-6,500
Non-fuel O&M costs ($/kWhe) 0.009-0.025 0.009-0.013 0.009-.013 0.032-0.038 Availability 96-98% 93-96% 98-99% >95% Hours to overhauls 30,000-60,000 25,000-50,000 40,000-80,000 32,000-64,000 Start-up time 10 sec 10 min - 1 hr 60 sec 3 hrs - 2 days natural gas, biogas, LPG, natural gas, hydrogen, sour gas, synthetic gas, natural gas, sour natural gas, Fuels industrial waste landfill gas, and gas, liquid fuels propane, gas, fuel oils methanol manufactured gas space heating, hot water, heat, hot water, hot water, chiller, hot water, LP- Uses for thermal output cooling, LP LP-HP steam heating HP steam steam Thermal Energy Qualities Low High Medium to low Low to High Sources: (EPA 2017; Tan 2018)
Natural Gas Micro CHP Systems and DG Policies and Programs in Canada If eligible under provincial DG programs and policies, natural gas micro CHP systems can earn revenue by exporting any excess electricity production to the local distribution grid. Currently, only Alberta allows natural gas micro CHP systems to self-supply electricity under the provincial DG policy (i.e., Alberta’s Micro-generation Regulation). As summarized in Chapter 2, in other provinces, natural gas-fired systems
July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 57
are not eligible for DG programs (Clean Energy Act 2010; OEB 2020; NSPower 2020).28 In Alberta, the Micro-generation Regulation allows generating units with GHG intensity less than 418 kgCO2/MWh to participate, making natural gas micro CHP an acceptable option (Alberta Government 2020). Several natural gas micro CHP projects are either in operation or being developed in Alberta (CHP Magazine 2020; Enbridge 2020).
Natural Gas Micro CHP Assessment To gain insights into the potential and economics of natural gas micro CHP, an analysis based on representative buildings is developed in this study. Specifically, a typical residential building and a commercial building with natural gas micro CHP systems are assessed. The assessment is developed using the US Environmental Protection Agency (EPA) CHP Screening Tool (EPA 2019a). This tool is designed to use historical annual energy consumptions (heat and electricity) in terms of average monthly figures to estimate the potential of micro CHP size and assess its economic feasibility (EPA 2019b). For this purpose, it first calculates the capacity for the micro CHP system according to the average thermal load and electric load. Then, it identifies two commercially available CHP systems from the default technology options:
• the one with less kW output than the size of the CHP system defined by the tool (option#1), • the next largest kW output as compared to the size of the CHP system defined by the tool (option#2).
In this study, to ensure that the considered option covers the energy demand load, we only report the numbers from option#2. Note that as the revised version of the EPA CHP Tool was issued in 2019, we assume that all costs are in 2019 US dollars, and therefore all costs are converted to Canadian dollars using the exchange factor of 1.3269 (Bank of Canada 2020).
Figure 3.8 & Figure 3.9 shows the daily and monthly profiles of the heat load29 and electric load for a typical single-detached house and an office building using the average areas from the database of RETScreen Expert software (NRCAN 2019).
28 It should be noted that natural gas fired CHP units can still sell electricity through a negotiated contract with electric utilities and there are many precedents. For smaller capacity CHP systems (e.g., micro CHP systems), however, ineligibility to participate in DG programs (e.g., net-metering programs) is a significant disadvantage. 29 Heat loads include the thermal energy required for space heating and domestic hot water.
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Figure 3.8: Daily Demand Profile for a) residential building and b) commercial building
Source: CERI
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Figure 3.9: Monthly Demand Profile for a) residential building and b) commercial building
Source: CERI
Under the assumptions made (including the system-specific parameters and building energy profiles), the electricity generation capacity of the residential micro CHP system, and commercial micro CHP system, as determined by the EPA CHP analysis tool, is 5kW and 285kW respectively. Both are based on reciprocating engine-based systems. The main assumptions made for the economic assessment in Alberta are listed in Table 3.6. The assessment was also repeated for Ontario, and the price of natural gas and electricity were revised accordingly.
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Table 3.5: Main parameters used for natural gas micro CHP systems in Alberta Input parameter Residential Commercial
operation hours (hours) 8760 8760 Micro CHP system capacity (electric) 5kW 285kW the fuel price for on-site thermal equipment ($/GJ) $5.01 $2.49 Natural gas price ($/GJ) $5.01 $2.49 Electricity price ($/kWh) $0.13 $0.16 the efficiency of thermal equipment that CHP output would displace 85% 85% the CHP equipment service life (years) 25 25 incentive No No real discount rate 5% 10% inflation 2% 2% Note: The fuel (natural gas) and electricity prices, for residential buildings, are extracted from ATCO-S and ENMAX 2018 marginal prices in (Alberta MSA 2019), while for commercial buildings, they are derived from (CER 2019a; Hydro Quebec 2019a), respectively.
Using the demand profiles shown in Figures 3.9 and 3.10, the average monthly energy demand for a typical detached house and a large office building is estimated. Generally, it is assumed that the micro CHP system is operated primarily to satisfy the thermal demand of the host building and produce electricity according to the system configuration.
Natural Gas Micro CHP Assessment Results Figure 3.10 shows the electricity production profile of residential and commercial micro CHP systems. Since the micro CHP system follows the host facility's thermal demand, a lower amount of electricity is produced in summer months than in other seasons. Under the assumed operating rules, residential systems produce a higher proportion of electricity, and the majority of the produced electricity is available for exporting to the grid. In the case of commercial systems, most of the produced electricity is consumed on-site.
The LCOE is estimated for the natural gas micro CHP systems we assessed for residential and commercial buildings in Alberta and Ontario. When estimating the LCOE, a credit was assigned for the thermal energy produced by the system. The credit is assumed to be the average cost of thermal energy produced by a typical natural gas-fired furnace and a hot water production system. The estimated LCOE values of all systems and provinces considered are summarized in Table 3.7. Because of the lower fixed costs of the technology utilized for the commercial building (285kW reciprocating engine) as compared to the residential building (5kW reciprocating engine), lower LCOE values are observed for the commercial
July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 61 building in Alberta and Ontario. On the other hand, because of the cheaper fuel prices in Alberta, lower LCOEs were obtained in both building types for Alberta despite receiving less thermal credit.
Figure 3.10: Electricity Production Profile of Natural Gas Micro CHP Systems
Table 3.6: LCOE Analysis for Residential and Commercial Buildings in Alberta and Ontario AB AB ON ON Description (Residential) (Commercial) (Residential) (Commercial)
Fixed costs (Capital + FOM) (¢/kWh) 21.5 8.4 21.5 8.4
Fuel cost (¢/kWh) 7.2 2.7 11.8 7.8
Thermal energy credit (¢/kWh) -4.2 -1.4 -6.9 -4.1
LCOE (¢/kWh) 24.5 9.7 26.4 12.1
The residential natural gas micro CHP systems assessed have higher LCOE than current retail electricity prices. Judging only by the LCOE analysis, for residential micro CHP systems to be economically competitive, the retail electricity price needs to be significantly higher than current values. It should be
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noted that in Ontario, natural gas micro CHP is not eligible for the net-metering program making the system economically worse off.
On the other hand, the commercial micro CHP system appears to be economically competitive. A cash flow analysis was also conducted, and the commercial micro CHP system assessed was observed to have an internal rate of return of 23 percent. However, this assessment considered only one type of commercial building. This assessment also shows that the economics of micro CHP systems are favourable when there is a based load demand for both electricity and heat, or their intermittent demand is coincident. Further work is required, considering different types of commercial buildings in a given province to assess the full potential of natural gas micro CHP systems.
3.5 Dependable Capacity Value of Distributed Generation Systems One of DG’s benefits is the reduction in overall electricity generation and delivery system capacity that needs to be centrally built and maintained. The addition of DG is expected to reduce the net demand seen by central electric power systems leading to an implied capacity value. The capacity value of a power generating asset refers to its ability to satisfy the load when demanded by the power system. Under normal operating conditions (i.e., no contingencies), a power system is strained for supply during peak demand periods. Therefore, in practice, the capacity value is associated with an electric generating unit’s ability to satisfy the load during peak demand periods. In this section, we estimate the capacity value of the DG technologies assessed in this study.
DG systems based on biomass and MSW are dispatchable units that can produce on-demand electricity. Therefore, their capacity value is only limited by their forced outage rates. The forced outage rate of the biomass and MSW based DG systems is in the order of 5 percent. Therefore, the capacity value of those units is about 95 percent of their installed capacity.
Variable renewable generating sources such as solar PV are unable to provide power on demand, and their production follows the resource availability patterns. Therefore, the capacity value of those units should be assessed by taking their observed availability into account. In this study, the average electricity production potential during the periods where the host electric power system experience peak demand conditions are used as a metric of the capacity value of solar PV systems. Similar statistical methods are being employed for capacity value estimation of variable renewables in larger power systems such as Ontario’s electricity system, PJM30 interconnection, and power system of the state of New York (NYISO) (AESO 2017; IESO 2020b).
The capacity value of solar PV systems is estimated for different months in a given year. It is done by estimating the average output over three contiguous hours centred around the monthly peak demand observed in a given province in 2019.31 The capacity value of solar PV systems in all population systems is
30 PJM Interconnection is a regional transmission organization in the United States. It is part of the Eastern Interconnection grid operating an electric transmission system serving all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia. 31 2019 is the most recent year where full demand data is available for a period of one year.
July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 63 estimated using the hourly time-series production data developed in this study. Figure 3.11 shows the monthly average solar PV capacity values observed in Nova Scotia, Ontario, Alberta, and British Columbia.
Figure 3.11: Average Solar PV Capacity Value in Different Provinces
As seen in figure 3.11, there is no capacity value for solar PV during winter months (November – February). This is because the peak demand conditions are observed in the evening, where there is no solar PV production. In summer months (May-August), the average solar PV capacity value in Alberta and Nova Scotia are around 40 percent. Despite the higher solar resources and being a summer peaking power system, the summertime solar PV capacity value in Ontario is low (around 15 percent). According to the IESO, the main reason for this is the embedded solar PV systems already in the system have moved the summer peak towards the late afternoon to early evening hours. This demonstrates the ability of solar PV systems’ ability to contribute to central system resource requirements. Ontario’s is a summer peaking electricity system and lowering the coincidence peak demand reduces the peaking capacity requirements.
Natural gas micro CHP systems are thermal generating units that are seemingly dispatchable. However, their power output is constrained by the host facility’s thermal demand. The capacity value of the natural
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gas micro CHP system is estimated by following a similar method as solar PV (i.e., average production during peak demand periods) and production profiles (summarized in Figure 3.10) estimated in the study. The capacity values of residential and commercial micro CHP systems are summarized in Table 3.8. The capacity values presented in Table 3.8 depends on the system and host facility demand profiles assumed for the analysis generalization of the numerical values that must be avoided. However, a CHP system that follows the host facility’s thermal demand can be expected to have a high winter capacity value.
Table 3.7: Capacity Value of Natural Gas CHP Systems by Season
Nova British Season CHP System Type Ontario Alberta Scotia Columbia Winter Residential (5kW) 81% 62% 79% 73% Spring Residential (5kW) 34% 59% 34% 66% Summer Residential (5kW) 10% 24% 7% 14% Fall Residential (5kW) 40% 41% 39% 44% Winter Commercial (285kW) 77% 81% 80% 95% Spring Commercial (285kW) 69% 85% 67% 72% Summer Commercial (285kW) 36% 30% 34% 27% Fall Commercial (285kW) 49% 73% 46% 52%
The capacity values estimated in this section are for individual systems. The capacity value of a single DG system may be insignificant for a given electric power system. However, with increased DG penetration, the aggregated capacity factor can contribute to reducing overall resource requirements. This is an added value that should be recognized by provincial utility policymakers.
July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 65 Chapter 4: Private and Public Cost-Benefit Analysis
• The economic viability of solar PV DG systems depends on local factors such as resource conditions, electricity rate structure, and compensation mechanism for DG systems. • There are net public costs associated with the implementation of DG.
4.1 Private Cost-Benefit Analysis of Solar PV Systems The LCOE of different DG technologies is a screening metric of the life-cycle average economic return required to justify a DG investment by the investor. As mentioned in Chapter 3, having a lower LCOE value than the prevailing retail electricity rate does not necessarily guarantee a justifiable average economic return. The total and, by extension, the life-cycle average economic return, depends on the DG system owner's electricity bill savings due to DG investment and compensation rate and mechanism for any electricity exported to the distribution system. The electricity bill saving depends on the DG investor's retail electricity rate and structure throughout the DG system’s economic life.
Here, we conduct a private cost-benefit analysis for a DG investor by estimating the net present value (NPV), the simple payback period, annual electricity bill saving, and the internal rate of return (IRR). The analysis is limited to solar PV as it is the DG option with the highest growth rate, and according to the analysis in Chapter 3, the one with the most favourable economic potential for both residential and commercial customers. Table 4.1 summarizes the main assumptions made for this assessment. The electricity rate structure and DG compensation mechanism varies by province, as summarized in Chapter 2. Near term, solar PV capital cost was used for the assessment. System technical parameters are assumed to be the same as the values in Table 3.1. No subsidies are assumed for the analysis, except Class 43.2 capital cost allowance for commercial customers.
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Table 4.1: Main Assumptions Made for Private Cost-Benefit Analysis of Solar PV DG Systems
Residential Commercial Parameter system system
Capacity (kWdc) 5 50
Solar PV normalized capital cost (CAD$/Wdc) 2.5 2 Solar PV system capital cost (CAD$) 12,500 100,000 O&M cost (CAD$/kW-year) 6 5 Project economic life (years) 20 20 Nominal discount rate (%) 5 12 Debt fraction (%) 50 50 Debt interest rate (%) 5 5 Monthly electricity consumption range (kWh/month) 750-1000 14,000-15,750 Retail electricity rate Depends on the province. Values DG compensation rate and mechanism are summarized in Chapter 2 Electricity price escalation rate (%) 1 Inflation rate (%) 2
The estimated parameters are summarized in Table 4.2. The analysis was conducted for a single location in a given province. Table 4.2 also shows the LCOE and implied average compensation received for solar PV produced electricity. The average compensation is a combination of any savings due to reduced electricity purchases and credits received for exported electricity. For commercial customers, any savings due to reduced demand charges are also included.
As seen in Table 4.2, higher implied compensation than the LCOE lead to positive NPV. In Ontario, both residential and commercial systems have positive NPV. The time-of-use (TOU) pricing in Ontario leads to higher compensation for solar PV systems. Generally, the electricity price is higher in Ontario during the hours with higher solar PV production, particularly in the summer months.
In Alberta, despite the lower LCOE, the NPV of residential systems is negative due to lower compensation received under the net-billing mechanism.32 However, the NPV was positive for commercial systems in Alberta. In this case, the self-consumption of solar PV produced electricity was higher for commercial customers, which lead to a higher implied compensation rate. The lower capital cost of commercial PV is also a contributing factor.
32 We assumed that the compensation rate (i.e., bill credit) for exported electricity to be 6.5 cents/kWh, which is the price of energy under the regulated rate option (RRO).
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Table 4.2: Main Assumptions Made for Private Cost-Benefit Analysis
Implied DG Internal rate Simple Annual bill Levelized cost Population Net-present average Province Compensation of return payback saving of electricity Center value (CAD$) compensation mechanism (nominal) (%) period (years) (CAD$/year) (cents/kWh) (cents/kWh) Residential solar PV (5kWdc) Nova Scotia Hallifax Net-metering 2,423 8.2 12.4 986 13.8 15.3 Net-metering Ontario Toronto 2,255 7 12.5 972 13.1 14.4 (TOU pricing) Alberta Calgary Net-billing* (1,938) 2.01 16 709 12.6 10 British Columbia Penticton Net-metering (3,866) -1.2 19 590 16.9 9.4 Commercial solar PV (50kWdc) Nova Scotia Hallifax Net-metering (9,509) 6.9 14 6,085 10.5 9.5 Net-metering Ontario Toronto 25,750 22.4 8 11,390 10.1 16.9 (TOU pricing) Alberta Calgary Net-billing* 3,670 13.5 11 3,670 10.1 12 British Columbia Penticton Net-metering (10,417) 6.2 14.2 6,197 11.13 9.8
*In Alberta, the electricity sell rate for exported electricity under net-billing is assumed to be 6.5 cents/kWh, which is the price of energy under current regulated rate option (RRO)
In Nova Scotia, relatively high retail electricity prices, and higher solar resources lead to positive NPV for residential customers. However, commercial systems see negative NPV for two reasons. Commercial customers pay a relatively lower retail price for energy (about 9 cents/kWh), which is lower than the LCOE of solar PV. They also pay a demand charge that the solar PV system is unable to avoid. However, it should be noted that the result may be different for a commercial customer with a different demand profile. In British Columbia, the lower electricity prices and lower solar resources lead to negative NPV for both residential and commercial customers. In all cases, the solar PV DG system owner sees a significant level of electricity bill saving. For residential customers, depending on the province, the bill saving is in the range of 55-65 percent. For commercial customers, the saving is in the range of 38 percent-65 percent.
All systems assessed here see positive NPV after 2025 with the solar PV capital cost reductions assumed in Chapter 3, Table 3.1. One exception was residential systems in British Columbia that required the residential solar PV capital cost to be about CAD$1.9/Wdc to have a positive NPV under a nominal discount rate of 5 percent. Also, note that no subsidies are assumed for the residential systems. Commercial systems receive a tax benefit under Class 43.2 capital cost allowance (Canada Revenue Agency 2019).
The main observation from this analysis is that the economic viability of solar PV DG systems depends on local factors such as resource conditions, electricity rate structure, and compensation mechanism for DG systems. All systems are expected to be economically feasible from the DG investors' point of view, assuming the current DG programs and policies continue. That leads to the question of whether there is a net public benefit attributable to higher penetration of DG.
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Table 4.3: Macro-Level Benefits of Residential Solar PV
Parameter 2025 2030 2035 2040 Nova Scotia Number of residential solar PV systems 3,087 15,368 36,857 46,354 Annual energy production (GWh) 19 95 229 288 Avoided transmission and distribution losses (GWh) 1.4 7 17 22 Potential summer capacity value (MW) 4 20 48 60 Avoided GHG emissions (ktCO2eq) 8.0 37 79 96 Ontario Number of residential solar PV systems 34,050 169,525 406,562 511,329 Annual energy production (GWh) 217 1,081 2,592 3,260 Avoided transmission and distribution losses (GWh) 24 120 288 362 Potential summer capacity value (MW) 12 59 142 179 Avoided GHG emissions (ktCO2eq) 17 84 202 303 Alberta Number of residential solar PV systems 6,806 33,885 81,265 102,206 Annual energy production (GWh) 43 213 511 642 Avoided transmission and distribution losses (GWh) 3 17 41 52 Potential summer capacity value (MW) 18 91 219 276 Avoided GHG emissions (ktCO2eq) 17 85 182 229 British Columbia Number of residential solar PV systems 11,997 59,730 143,247 180,160 Annual energy production (GWh) 61 302 725 911 Avoided transmission and distribution losses (GWh) 7 35 84 105 Potential summer capacity value (MW) 10 49 116 146 Avoided GHG emissions (ktCO2eq) 1.1 5 12 16
In the assessment summarized in the table, it is assumed that 10% of the residential customers would have a 5kWdc solar PV systems installed.
To estimate the net societal benefits of DG, a detailed cost-benefit analysis should be conducted by quantifying all costs and benefits. The perceived benefits of DG include its ability to reduce fuel cost, reduce emissions, increase reliability, and avoid or defer new generation and network assets. In Table 4.3, we estimate some of the benefits of higher penetration of solar PV DG systems with macro-level information. Here, we assume that by 2040, 10 percent of the residential customers would have solar PV DG systems. We assume that the capacity of a single system to be 5kWdc.
Expectedly, reduction in transmission and distribution losses is consistently observed in all provinces. Reduction in losses can potentially lead to the overall cost and primary energy savings in a given province. The GHG emissions saving, on a per system basis, varies by the province as the GHG intensity of electricity generation system is significantly different. For example, due to the fossil fuel dominant generation mix (currently as well as over the analysis period), the GHG intensity of electricity generation in Alberta and Nova Scotia (about two tCO2eq per system per year after 2030) are about two orders of magnitude higher than that of British Columbia. The capacity value contributions in summer months are calculated by using the values estimated in Chapter 3.
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At a lower penetration level of 10 percent and a smaller system size of 5kWdc, the capacity value is smaller. However, depending on the distribution of residential solar PV systems in a given province, the aggregated capacity contribution can contribute to managing system reinforcements required to satisfy the peak demand. For example, in Alberta, the Calgary region is the largest population. The electricity demand in the Calgary region peaks in summer.
Furthermore, the Calgary region has the lowest in-region generation capacity. According to AESO (2019), by 2035, the Calgary region’s peak demand will be 1856MWh. If 50 percent of the solar PV systems of Alberta (from Table 4.2) are in the Calgary region, the aggregated summer capacity value would be about 6 percent of the peak demand.
4.2 Public Cost and Benefits Analysis of Customer-Owned DG Model Background In 2013, the Rocky Mountain Institute (RMI) compiled a literature review of sixteen studies assessing the cost and benefits associated with the increased penetration of solar PV connected to the distribution systems across different regions in the United States (Hansen, Lacy, and Glick 2013). In this study, RMI identified seven categories that had been included in those cost-benefit analyses (CBA) studies, as summarized in Table 4.4.
Table 4.4: Cost and Benefits Derived from Distributed-Generation Category Definition Energy Cost and amount of energy that can be displaced by DG Deferring or avoiding major investments in infrastructure due to the growth of Capacity DG Grid Support Services Services required to balance supply and demand in the presence of DG Financial Risks Impact on market prices as centrally supplied electricity is displaced by DG Security Risks Impact on reliability and resiliency of the grid as DG capacity increases Environmental Reduction of emissions and other pollutants as DG displaces carbon-based Impact generation Social Impact Impact on local jobs and economic development
Building on RMI's findings, the Interstate Renewable Energy Council (IREC) (Keyes and Rabago 2013) and the National Renewable Energy Laboratory (NREL) (Denholm et al. 2014), independently proposed some methodologies to standardize the evaluation of the cost and benefits associated with the penetration of DG within the electric systems.
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Denholm et al. (2014) proposed methodology illustrates, at different levels of sophistication, how the costs and benefits could be calculated at the margin given the type and quality of data readily available33.
Keyes and Rabago (2013) highlight the importance of incorporating the impact that DG can have on the local electric utility companies in the form of lost revenues, which the NREL methodology ignores. This point is supported by the work of Duthu et al. (2014), who found that customer-owned DG creates quantifiable losses for the electric utility stakeholders. The lost revenues for electric utilities need to be quantified and carefully considered as these lost revenues can trigger rate increases to all customers served by the utility, including DG customers. There is also a risk of other unintended consequences, such as decreased quality of the service provided or an indirect form of a regressive tax. Usually, more affluent households that can afford the capital needed to install DG, and these households are triggering higher costs for less affluent families.
Quantifying the impact on the electric utilities is in line with the research done to assess the impact of demand-side management programs. What was formally labelled Total Resource Cost Test (TRCT), which attempts to measure the economic efficiency implications of the total energy supply system (Clark, Sowell, and Schultz 2001). The TRCT is the basis for the cost-benefit analysis included in this study.
Total Resource Cost Test The model that we are using includes the following components:
a) Energy Impact
In most electric utility networks, large-scale grid-connected generating units are dispatched by a centralized balancing authority as the system demand changes. While the process of optimizing the network can follow different principles, in general, balancing authorities dispatch generating units based on the lowest possible cost for the entire network, and this is a function of the unit-specific variable cost of production (i.e., fuel costs, O&M and costs of emissions). Thus, as large-scale generators are displaced by DG, the avoided variable costs of running those units constitute the energy impact (Denholm et al. 2014).
b) System Losses
A fraction of the electricity that is centrally produced at large-scale generating units is lost in the form of heat during its transportation along with the transmission and distribution systems. As DG serves onsite load and can export any surplus generation back into the grid to partially serve the demand of adjacent customers within the same circuit, a fraction of the overall system losses can be avoided (Keyes and Rabago 2013).
33 Assessing the cost and benefits at the margin offers a more accurate estimation when analysing the impact of DG retrospectively. This methodology was applied to study the cost and benefits of the Micro-Generation regulation in Alberta during 2017 and 2018 (Gallardo 2019).
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c) Environmental Impact
For environmental impacts, we only consider GHG emissions. DG with renewable and GHG emissions-free technologies can avoid GHG emissions associated with electricity generation with fossil fuel fired power plants. To estimate the GHG emissions benefits, we assume the average GHG intensity of the power generating system in the respective provinces. The carbon pricing system varies by province in terms of choice of policy instrument (e.g., direct carbon levy or cap-and-trade system) and the stringency (e.g., carbon price, price of emissions certificates). However, the federal government has indicated that the provinces may use an output-based allocation system to price carbon emissions from the electricity sector (ECCC 2018). Under this system, only the emissions above a benchmark intensity would be subjected to carbon pricing. Assuming a benchmark intensity to be that of a best in class natural gas combined cycle power plant (0.37 tCO2e/MWh) and a carbon price of $50/tCO2e, we estimated the value of avoided GHG emissions.
d) Generation Capacity
The reliability of electricity supply needed during high system-demand periods can only be achieved by maintaining enough system reserve margins, which dictate the total available generation capacity in the system that is required at any given time. The decision to invest in a new large-scale generation is usually driven by the reserve margin target imposed for the entire network. Theory suggests that as the penetration of DG increases, the aggregated capacity factor of all DG in a region can decrease the reserve margin needed to achieve an acceptable reliability supply level, potentially avoiding or delaying the need of new large-scale generation (Reimers, Cole, and Frew 2019; Perez et al. 2008).
e) Transmission and Distribution Capacity
Two of the DG attributes mentioned earlier, mainly load displacement and excess supply serving adjacent loads within the same circuit could defer or avoid the need for transmission and distribution system changes or upgrades, as the wear and tear of the overall transmission infrastructure decrease with higher DG penetration levels (Keyes and Rabago 2013). However, it is also argued that the intermittency of non- hydroelectric renewable generation, a characteristic of DG, increases the need for new types of upgrades to maintain appropriate reliability levels across the network (Hansen, Lacy, and Glick 2013).
f) Reliability and Resiliency of Off-Grid and Remote Communities
Outside of some remote communities in Canada that have access to local hydroelectric resources, the vast majority of these communities rely on diesel generation for the production of electricity (NRCan 2011). These communities experience an over-reliance on imports of fuel to meet their energy demands, are subject to commodity price volatility, and are at risk of supply interruptions caused due to infrastructure constraints (Bird et al. 2005). Furthermore, the overall costs of servicing these communities are shared across all customers who are serviced by the same electric utility company (BC Hydro 2016). Thus, the use of DG could decrease the over-reliance on fossil fuel-based generation and fuel imports for those remote communities and decrease the overall operating cost of the utilities serving these communities.
g) Aggregated Private Benefits for DG Owners
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While environmental concerns among residential customers appear to initially spark interest in purchasing and installing DG, financial considerations tend to become the deciding factor before customers fully commit to taking on these investments (Rai 2015). There are costs associated with the initial investment in equipment, installation, and future maintenance, but there are also benefits in the form of future electricity bill savings. Thus, we consider that the aggregated financial benefits of all customers installing DG can serve as a proxy of the overall net economic value (sum of the private benefits) derived from DG ownership (Duthu et al. 2014).
h) Lost Revenues for the Electric Utility
As DG customers realize the financial benefits derived from their electricity bill cost reductions, the electric utility companies lose the revenues that they would have received from these customers. This creates a shortfall in the overall revenues that the utility companies expect to receive to cover their costs and realize the reasonable return allowed to them by the economic regulation.
Illustrative Total Resource Cost Test In this section, we conduct an illustrative assessment by applying a TRCT for solar PV DG growth in British Columbia, Alberta, Ontario, and Nova Scotia. We selected these provinces because the differences that exist between their electricity systems can offer insightful results in terms of the impact that DG could have under different conditions. We gathered market and electric utility-specific data for those provinces.
We modelled the features of PV systems to assess the provincial impacts as this technology is overly represented by those customers who have already committed to offset onsite load through the use of DG and take advantage of some provincial programs. The average size of the assumed PV system is 5kW. We extrapolated historical data 20 years out, which is the average PV technology system life, and applied a yearly cash flow analysis to quantify the different impacts. For consistency, we are assuming that 10 percent of the total residential customers, as of 2020, in each utility's franchise area will adopt a 5kW PV system by 2040. The penetration rate is mathematically modelled as an S-curve.
British Columbia BC Hydro estimated that by 2020, the utility would be servicing a total of 1.86MM residential customers across the province (BC Hydro 2019c). As mentioned above, we are assuming that 10 percent of these total customers (roughly 180,000) will have a 5kW PV system, partially offsetting their onsite electricity demand by 2040. Figure 4.1 depicts the DG penetration rate assumed for BC.
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Figure 4.1: DG Adoption Rate in BC (2020 – 2040)
Energy Impact The electricity purchases to meet the BC Hydro's load requirements are defined as Market Electricity Purchases (MEP) (BC Hydro 2019c). We are using the cost of these MEP ($/MWh) as a proxy of the energy savings across the system as DG displaces electricity supply that would be supplied from the grid otherwise34.
Our estimates suggest that the population-weighted average capacity factor35 of PV systems in BC is about 11.5 percent. Thus, a 5kW PV system yields an annual average energy output of about 5,053kWh/year. This means that each customer who installs PV systems in BC, on average, could displace 5.053MWh of market electricity purchases every year36. The total energy that is displaced by these customers (MWh/year) is valued at the estimated MEP price ($/MWh).
The PV of the total energy cost savings between 2021 and 2040 is estimated to be $124MM (2020 CAD). The discount rate used for the calculation was 6 percent.
System Losses Impact Using historical system losses data for BC, we estimated that the total annual system losses are about 10.3 percent. Thus, an extra 10.3 percent of the energy that is displaced each year by DG systems is accounted for as avoided system losses. We use the same MEP price estimates to monetize the impact.
The estimated PV of the avoided system losses between 2021 and 2040 is $13.7MM (2020 CAD). The discount rate for the calculation was 6 percent.
34 For 2020 and 2021, the MEP are $26.6 and $28.1, respectively. For the years between 2022 and 2040, the MEP was extrapolated using a linear approximation of the MEP prices between 2012 and 2021. 35 The capacity factor is defined as the ratio of total actual output to the maximum possible output (nameplate capacity) over a year. 36 The estimated output of a 5kW PV system per year in British Columbia (5,053kWh/year) is about 50 percent of the average energy use per residential account of about 10,000kWh/year (BC Hydro 2019c).
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Environmental Impact As it was shown in Chapter 2, about 98 percent of the total electricity produced in BC comes from renewable sources. Thus, total GHG emissions linked to electricity generation in the province are negligible. Historical data of system-wide electricity generation GHG emission intensity for BC has been about 0.0175 tCO2eq/MWh between 2005 and 2019. Going forward, we estimate that the system-wide emissions intensity will decrease to 0.0157 tCO2eq/MWh (CERI 2018b), and this value is used to estimate the avoided emissions impact. We are using the current BC carbon tax ($40/tonne as of 2020) to monetize the impact of these avoided emissions each year.
The NPV of the avoided emissions is $2.3 MM (2020 CAD). We used the Social Discount Rate for Emissions of 2 percent.
Generation Capacity Impact BC Hydro indicates that, given the current and planned available resources, the energy load resource balance within the province will be in a surplus (total supply > total demand) up until the year 2037 (BC Hydro 2019g). Thus, the province is not planning on investing in any new large-scale generator in the foreseeable future.
However, BC Hydro indicates that, if necessary, the next generation investment project would be the installation of a 500MW unit in their Revelstoke generation facility (Revelstoke Unit 6). The 500MW upgrade would cost between $317 and $569MM. For illustration purposes, assuming a total cost of $450MM and that the project could require five $90MM investment installments before completion, we estimate that delaying a generation project like this by one year could offer value, in NPV terms, of $12.8MM.
Transmission and Distribution Capacity Impact The Fraser Valley and West Kelowna regions are creating some concerns for BC Hydro, as load within these areas continues to grow at a fast pace, and the current transmission and distribution infrastructure is inadequate to cope with this growth. According to BC Hydro, the infrastructure investments that might ease these system constraints are a series of substation upgrades in both areas.
For the Fraser Valley region, BC Hydro is exploring the options of upgrading the substations at Mount Lehman and Clayburn. Whereas in the West Kelowna region, the utility is exploring the option of upgrading their West Bank substation (BC Hydro 2019c).
These two projects are still in the exploratory phases. However, information regarding previous substation upgrades indicates that the costs of similar projects have been about $75MM per substation. Similar to the generation capacity example, assuming that these three projects get approval and that the project investments happen in equal installments at different times before completion, delaying the need for these upgrades by one year could bring a benefit of about $14MM, on an NPV basis.
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Reliability and Resiliency of Off-Grid and Remote Communities Fifteen remote communities in BC are not connected to the main network, and they are referred to as Non-Integrated Areas (NIA). Twelve of these communities use diesel generation units either as their main source of electricity or as co-generation with small hydroelectric units37.
The energy cost for the NIA has been about $240/MWh. BC Hydro estimates that the energy costs for these communities for the 2020 and 2021 fiscal years are $268 and $281/MWh, respectively. Furthermore, GHG emissions data indicate that, on aggregate, the GHG emissions rate per MWh of these diesel generators is about 0.83 tCO2eq/MWh.
We estimate that a 10 percent penetration of DG between 2021 and 2040 in these communities could offer a benefit of about $6.25MM (2020 CAD). This calculation includes the energy cost savings and the avoided GHG emissions. The discount rates used for the energy cost savings and the avoided GHG emissions were 6 percent and 2 percent, respectively.
Aggregated Benefits for DG Owners To estimate the aggregated private benefits of all the residential customers that make up the 10 percent of customers installing DG between 2021 and 2040, we calculate an aggregated 20-year NPV of the annual cash flows that each group would realize from the year that they adopt DG. These cash flows include the life-cycle costs of the PV systems as well as the realized electricity bill savings once these customers displace onsite load with the use of DG. The electricity bill savings are calculated using the actual Rate Schedule for residential customers.
The NPV of the aggregated cash flows that make up 10 percent of customers adopting DG is $240MM (2020 CAD).
Lost Revenues for BC Hydro Lastly, the savings realized by the residential customers each year represent the lost revenues that BC Hydro would experience as more customers adopt DG, and they successfully displace electricity supply from the grid. Using the current Rate Schedule (energy component in Rate Schedule 1101), we estimate that the PV of the lost revenues for BC Hydro is $1,634MM (2020 dollars).
This $1,634MM includes system network costs as well as all other administration, riders, and miscellaneous charges that BC Hydro recovers from residential customers. A Cost by Function benchmark study done by The Battle Group indicates that BC Hydro's power production, transmission, and distribution cost categories represent approximately 18 percent, 16 percent, and 18 percent of the non- fuel operations and maintenance expenses (NFOM), respectively. These estimates are for the years between 2013 and 2015 (BC Hydro 2019c).
37 Communities served exclusively by diesel: Masset, Anahim Lake, Tsay Keh, Telegraph Creek, Hartley Bay, Good Hope Lake, Toad River and Elhateese. Communities with diesel cogenerating with renewables: Sandspit, Nuxalk, Kwadacha.
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Using these cost percentages, we estimate that out of the total lost revenues, the network cost impact (i.e., transmission and distribution) is between $500 and $600MM.
Alberta As it was mentioned in Chapter 2, Alberta does not have a single vertically integrated utility servicing residential customers across the province. Instead, investor and municipally owned utilities are servicing different regions within the province. For the CBA, we selected the two largest distribution franchise areas/zones in terms of the number of residential customers to conduct the assessment. These are the ENMAX and FortisAlberta zones. ENMAX’s service area is primarily urban, whereas FortisAlberta’s service area is primarily rural.
As of 2019, ENMAX and FortisAlberta reported a total of 477,476 and 424,988 residential customers, respectively (MSA 2019). Thus, for this analysis, we are assuming that roughly 45,000 customers within the ENMAX zone and 42,000 within the Fortis Alberta zone will install a 5kW PV system by 2040. Figure 4.2 below depicts the DG penetration rates in each zone.
Figure 4.2: DG Adoption Rate in AB (2020 – 2040)
Energy Impact Electricity generators in Alberta are called upon or dispatched, in order of their variable cost as the system demand changes. The last unit that is called upon to meet the system demand is the marginal unit, and the price that this generating station offers its output to the market becomes the system marginal price (SMP). Thus, the SMP is a proxy for the system’s energy cost savings as these marginal units are displaced by DG.
On average, since 2012, the monthly average SMP has been around $47/MWh. However, the increased carbon tax in 2018 and the high reliance on coal-fired generation in Alberta, which is of high GHG intensity,
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has increased the SMP average to about $53/MWh. We are assuming a $55/MWh average price to calculate the energy impact.
The population weighted average capacity factor of PV systems in Alberta is about 14.3 percent. Thus, a 5kW PV system yields an annual average energy output of about 6,282kWh/year. The total energy that is displaced by these customers (MWh/year) is valued at the estimated Alberta SMP ($/MWh).
The NPV of the total energy cost savings between 2021 and 2040 is estimated to be $154MM (2020 CAD). The discount rate used for the calculation is 6 percent.
System Losses Impact Using historical system losses data for AB, we estimated that the combined transmission and distribution losses are about 7.5 percent. Thus, an extra 7.5 percent of the energy that is displaced each year by DG systems is accounted for as avoided system losses. We use the same SMP assumption to monetize the impact.
The estimated NPV of the avoided system losses between 2021 and 2040 is $12.5MM (2020 CAD). The discount rate used for the calculation is 6 percent.
Environmental Impact Alberta's carbon-based electricity generation dependency has made the province the highest GHG emissions contributor in Canada. Based on the 2017 GHG emissions inventory report, Alberta’s electricity sector was responsible for 40.4 MtCO2eq (CER 2019). Gallardo (2019) found that 97 percent of the total daylight hours between 2017 and 2018 had a carbon-based generator at the margin. The introduction of a more stringent carbon tax in 2018 increased the percentage of hours that coal-fired electricity generators were at the margin to 82 percent, compared to 65 percent of the hours in 2017.
Historical data of system-wide electricity generation GHG emission intensity for AB has been about 0.675 tCO2eq/MWh between 2005 and 2019. We are using the AESO's system-wide38 GHG emissions intensity in over the analysis period for our estimation.39 The annual average intensity of each year of the analysis period is estimated using the generation outlook by AESO (2019).
The NPV of the avoided emissions is $30.6MM (2020 CAD). We used the Social Discount Rate for Emissions of 2 percent.
38 Using marginal emission factors, as opposed to system average emission factors, would provide a more accurate account of the total GHG emissions that could be displaced by using DG. However, the use of marginal emission factors requires highly accurate assumptions on the units that would be at the margin between 2021 and 2040, which is beyond the scope of this study. 39 Coal-fired generation will be phased-out after 2030. This decreases the GHG emissions intensity to 0.33 tCO2eq/MWh from 2030 and on. For the period between 2021 and 2029, the GHG emissions intensity is assumed to be 0.405 tCO2eq/MWh, which reflect the current situation.
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Generation Capacity Impact The decrease in global oil prices has brought considerable uncertainty regarding the economic growth that Alberta will experience. This uncertainty, combined with a decrease in the industrial load due to slower economic activity, is creating a generation capacity surplus in the province.
Furthermore, as mentioned in Chapter 2, companies participating in the Alberta market receives compensation for the electricity they produce based on the market price, which is subject to supply and demand forces. Thus, the decisions on the type of generation and the location of the facilities are determined by private investors, as opposed to being centrally planned (AESO 2020a). Economic and market factors, including the future level of DG penetration in the province, dictate the changes in generation capacity that the province will experience. We consider that DG, at the assumed penetration levels, will have a negligible impact in terms of generation capacity decisions in Alberta.
Transmissions and Distribution Capacity Impact The AESO assessed the impact that the integration of distributed energy resources (DERs) in key urban areas in Alberta would have on the transmission system as it currently exists. They found that for every 100MW of DER added to the City of Calgary region, there will be a reduction of 60MW in transmission system capability across the south and central east regions of the province. For the cities of Red Deer and Edmonton, the integration of DER has no impact on the transmission system, as these two cities are located near strong transmissions hubs (AESO 2020c).
However, the current plans to add transmission system capability for the south and central east regions of the province would address these concerns and allow more DER to develop (AESO 2020c). Thus, the impact that the penetration of DG could on the transmission system is negligible.
In terms of distribution system impacts, there is conflicting information as to the level of DG penetration that the system needs to experience before the variability of load on the distribution feeders starts deviating outside of the normal ranges of operation. However, there is consistency among market participants that the current distribution system can handle up to 15 percent of DG penetration before major upgrades are needed (AUC 2017). Thus, at a 10 percent penetration, DG has a minimal impact on the distribution system.
Reliability and Resiliency of Off-Grid and Remote Communities Alberta has the second-lowest number of remote communities, both in terms of the number of sites/communities and the number of people living in those communities (NRCan 2011). Thus, DG offers negligible benefits in Alberta, compared to the benefits it brings in provinces with a higher number of communities not connected to the main network.
Aggregated Benefits for DG Owners To estimate the aggregated private benefits of all the residential customers that make up the 10 percent of customers installing DG between 2021 and 2040 in the two distribution zones, we calculate an aggregated 20-year NPV of the annual cash flows that each group would realize from the year that they adopt DG. These cash flows include the life-cycle costs of the PV systems as well as the realized electricity
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bill savings once these customers displace onsite load with the use of DG. The electricity bill savings are calculated using the actual Rate Schedule for residential customers in each zone.
The NPV of the aggregated cash flows that make up the 10 percent of customers adopting DG is within the ENMAX zone is $94MM (2020 CAD). Likewise, the NPV for customers within the FortisAlberta zone adopting DG is $339MM (2020 CAD).
The difference in the aggregated private benefits between the two zones is due to the higher cost of electricity for residential customers within the FortisAlberta zone, as well as a higher assumed annual rate increase for the transmission component charge within this zone going forward40. i.e., customers in the ENMAX zone had paid a lower electricity rate than customers in the Fortis Alberta zone, and we assume that this difference will continue going forward.
Lost Revenues for ENMAX and FortisAlberta Lastly, each year, the savings realized by the residential customers represent the lost revenues for both utilities included in this analysis. The breakdown of the different electricity bill components allows us to assess the lost revenue that each layer of the electricity supply chain would experience as the penetration of DG increases.
In the ENMAX zone, the NPV of lost revenues is as follows:
Transmission: $188MM (2020 CAD) and distribution: $58MM (2020 CAD).
In the FortisAlberta zone, the NPV of lost revenues is:
Transmission: $439MM (2020 CAD) and distribution: $70MM (2020 CAD).
Ontario & Nova Scotia Following a similar procedure as that for Alberta and British Columbia, we assess private benefits and lost revenues for the utilities in Ontario and Nova Scotia. The results are summarized in the following section. Lost revenues for the utilities are estimated by assuming variable components of transmission and distribution charges in residential rates obtained from the review of rates presented in Chapter 2.
In Ontario, the value of reduced transmission and distribution losses was estimated by multiplying the energy saved (in MWh) by the average hourly price of electricity (in CAD$/MWh) for 2018 and 2019. For Nova Scotia, the average fuel cost of generation was used to monetize the value of avoided losses (NS Power 2020a).
In Ontario, the electricity rates include a charge called the “Global Adjustment Charge,” which, for the most part, accounts for the difference between the guaranteed contracted commodity price for generators versus the market-clearing price. The Global Adjustment (GA) also covers the cost of ensuring
40 Between 2012 and 2019, the transmission component of the electricity rate in the ENMAX zone had seen a 4.1 percent increase on average every year. In the FortisAlberta zone, the transmission component had increased at a 9 percent each year on average.
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the supply reliability and costs of some conservation programs (IESO 2018). The estimated GA charge for residential customers is incorporated in the residential time of use of electricity price. Residential customers with solar PV will not pay the GA charge for the self-generated electricity. Therefore, the uncollected GA charges will become a cost for Ontario’s electricity system. We estimate the GA charge for the residential customers as the difference between the average time of use energy price and the hourly average electricity price in Ontario in the period 2018-2019. The estimated average residential GA charge, which is about CAD$0.078/kWh, is used to estimate the unrecovered cost for the overall Ontario power system. For example, for a given residential solar PV system, the unrecovered GA charges are the total energy production (in kWh) times the average residential GA charge.
Summary of Results & Discussion Table 4.5 summarizes the results of the TRCT assessment. While the number of solar PV systems in British Columbia is higher, the higher cost of energy in Alberta is reflected with higher energy cost savings. The environmental impact is also drastically different between the two provinces as Alberta has a fossil fuel dominated generation system. Based on the impacts summarized in Table 4.5, at a 10% penetration level, the benefits of residential solar PV DG are outweighed (by about CAD$100 million over 20 years) by the unrecovered network cost due to lowered electricity sales.
Table 4.5: Summary of Public Cost-Benefit Analysis BC AB ON NS Total PV Systems by 2040* 180,160 89,800 511,330 46,300 (million CAD$) (million CAD$) (million CAD$) (million CAD$) Energy Impact 124 154 348 94 System Losses 14 13 39 7 Environmental Impact 2 31 40 15 Reliability and Resiliency of Off-Grid and 6 - - - Remote Communities Aggregated Private Benefits 240 433 600 106 Total Benefits (Over 20 Years) 386 630 1027 221 Lost Revenues - Transmission 261 627 577 43 Network Lost Revenues - Distribution 294 128 106 94 Costs Lost Revenues - Global Adjustment N/A N/A 1551 N/A Total System Costs - (Over 20 Years) 555 755 2234 137 Net present value - (Over 20 Years) -169 -125 -1208 85 Net present value per system (CAD$/system -937 -1392 -2362 1826 over 20 Years) *Alberta only includes PV systems assumed to be installed within the ENMAX and FortisAlberta franchise areas.
In Nova Scotia, the total benefits are higher than the total system cost. The main reason for the higher private benefits is higher bill savings. In Nova Scotia, the bill saving for a typical customer is about 34 percent higher than Alberta and British Columbia (see Table 4.1).
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In the case of Ontario, unrecovered GA charges significantly outweigh the benefits and leads to a net negative NPV. Changes to market conditions such as the future hourly average electricity prices in Ontario may change the GA charges, and further analysis is required to assess the robustness of the result.
The cost of lost revenue for the generation system is not included in the summary for a few reasons. The main reason is the unused generation can be used elsewhere in the system or be exported. For example, from 2020 to 2040, the electricity demand in Alberta and British Columbia is expected to grow by about 700GWh/year and 500GWh/year, respectively. At the assumed penetration level, the residential solar PV supply is considerably lower than the growth rate. Therefore, it is unrealistic to assume that surplus generation in the central system will not be resold, at least in part.
For the transmission and distribution networks, the revenue losses will be more impactful. However, the reduction in net demand has not been shown in this analysis to suggest delay or deferment of new investments. There may be case-specific examples where the concentration of DG may provide such a delay; however, in general, and with a wide distribution of PV units, this is not the case.
The TRCT analysis assessment developed here is conducted at the macro level and can vary with site- specific applications. Furthermore, the technology focus of the TRCT analysis is limited to residential solar PV. The inclusion of other DG technologies or a combination of technologies may reveal additional values. For example, as estimated in Chapter 3, the capacity value of DG with biomass, MSW, and micro CHP can provide a higher dependable capacity value during peak demand hours throughout a year. In the case of solar PV, the main disadvantage is its variability, which can be mitigated by the incorporation of electricity storage systems.
As the level of DG penetration increases, cost-shifting from DG customers to non-DG customers will inevitably occur in the form of rate impacts.
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July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 83 Chapter 5: Conclusions
• Implementation of distributed generation is an opportunity for electricity consumers to make a reasonable return. • In general, there are no demonstrable electricity system net public benefits with the development of DG options.
In this study, CERI has examined the opportunities and challenges for distributed electricity generation in Canada. The study provided an in-depth review of policies and programs that have been adopted by the provinces to facilitate the uptake of DG, developed a techno-economic assessment of three DG technologies, and examined private and public economic perspectives of investment in DG.
All Canadian provinces in Canada have some form of policy or program promoting the growth of DG. However, there needs to be more coordination between electricity system planners and provincial government agencies for optimal DG integration.
In terms of technologies assessed, operational simplicity, scalability, and declining capital costs make solar PV a dominant DG investment choice in Canada. In many populations centers across the country, the average cost of electricity produced by residential and commercial solar PV DG systems are lower than the current retail rates.
DG technologies are varied and continue to benefit from innovation and reduction in capital cost and improvements in performance. The principle challenge in understanding the net economic impacts of these technologies is on their impact on Canada’s provincial electricity grids.
The provinces operate their own grids with the majority of the cost drivers for the generation, transmission and distribution systems is intra-provincial. As such, to understand the impact in each province, a specific analysis including, an understanding of the long-term demand for electricity must be conducted. In this case, CERI undertook to do this work for four provinces, Nova Scotia, Ontario, Alberta and British Columbia. Analogous provincial networks can use this information as a basis for their own situations.
There has been a great deal of research conducted on the economics or financial impacts of individual investments. For the majority of those investments, the private sector owner can be shown a positive business case to invest. However, cost-effectiveness is directly impacted by the compensation mechanisms in place.
There are numerous approaches to setting up the metering approach for these generation options, but the most significant element is who pays for the existing distribution and transmission system costs. These costs do not disappear if the private DG owner is not required to pay for them. The costs would, by necessity, be visited on the other electricity customers.
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Arguments have been made that there is a system benefit, and if so, payments to the DG owner should reflect those benefits.
However, our analysis shows that there are no net benefits to the system in British Columbia, Alberta, and Ontario. In Nova Scotia, we note that with a relatively high percentage of the overall bill coming from the generation component, that there are net system benefits. We note that there are avoided transmission and distribution line losses. For carbon-intensive generation systems, there are also avoided GHG emissions that we have valued at either provincial or federal carbon tax rates. However, our analysis shows that at the macro level, the ability to influence the timing and scale of transmission network or distribution upgrades is negligible.
It may be shown that in specific cases, mainly dealing with distribution systems, that there are examples of where concentrated DG penetration can create delays or complete deferment of distribution system upgrades. However, for the majority of cases, dealing with distributed generation impacts on Canada’s transmission and distribution systems, there is no deferment or delay in system investments.
For photovoltaic systems at the commercial and residential levels, this conclusion is clear. For commercial level natural gas combined heat and power, the size of the unit may have some distribution benefits. However, CHP systems are optimized for their heat production and not for electricity. As such, those systems follow the private DG owner’s demands and not the peak requirements on the electricity grid. How then might system planners depend on those assets for peak load?
Similarly, MSW projects are limited in their capacity due to the amount of resources available. Scalability is a challenge for these options, and as such, it is unlikely there will be sufficient capacity to help manage peak requirements for the system in general.
One caveat to this observation is the use of electricity storage in conjunction with photovoltaic systems and placing the generators under a central controlling entity. PV systems have the advantage of portability, modularity, scalability and simplicity. The disadvantage is predictability and reliability. These disadvantages can be overcome through storage, adopting better forecasting methods, and central control. For example, in 2015, Alectra Inc., in coordination with the IESO, has completed a feasibility study for higher adaptation of residential solar PV and storage systems in the York region of Ontario (Aectra Utilities 2017). The demonstration project found that residential solar PV and storage systems have the potential to defer longer-term infrastructure needs in the region by at least two years.
Regardless of the different objectives, society demands of its electricity grid, peak demand must be serviced. A high level of photovoltaic generation paired with storage is a viable option.
CERI has previously conducted an assessment of electricity storage business cases for different commercial applications. While the private sector business case is negative for storage investments, we did not consider the net benefits to the electricity grid. Compartmentalized, DG and storage do not maximize their most significant contribution to the electricity grid management. Together they could provide significant value and it is something that CERI may assess in the future.
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How do electricity gird control organizations ensure that the resources they plan for are reliable? In the case of most of Canada’s grid operators, this is done either through ownership, contracts or conditions of service. There are no contracts for DG. There is no central ownership of DG. That leaves conditions of service. Can private investors of DG operate under conditions of service of the central controller to allow that controller to rely on their input to the system when needs arise?
As with any economic assessment of a market, the conditions under which that market operates is vital to assessing the value between buyers and sellers. Can private investors in DG, either commercial or residential, internalize the system demands? If so, how does that change their risk profiles and impact on their own operating conditions? Centrally planned major generation investments go through a rigorous process such that both the investor and the grid operator have clear expectations of what is expected of them. Can this be applied to small DG owners?
Several economic conditions rely on answering these questions. In this report, CERI has assumed operating conditions based on current practices. These current practices do not obligate DG owners to generate power, or an amount of power, or at a particular time. These are all concerns that system planners obsess over their entire careers.
There is yet to be demonstrated a model that allows for the freedom that distributed generation investments profess to be accommodated into a centrally planned system. Planners are unable to assume additional risk to grid operations given the significant economic impact that grid failures incur.
Under current conditions, in many provinces, an adaptation of DG is an opportunity for electricity consumers to make a reasonable return. Furthermore, as estimated in this study, DG can provide some electricity systems level benefits. As benefits of DG will result from the aggregated contribution of a larger number of individual systems. Individually compensating dispersed DG systems for their own public benefit contribution will be administratively costly. Energy and utility policymakers in different provinces should recognize the aggregated value of DG and must be taken into account when designing DG compensation mechanisms.
At the same time, at higher level of DG penetration, cost shifting from DG customers to non-DG customers will inevitably occur in the form of rate impacts. Regulators must strike a balance between the capitalizing value of DG to achieve public policy objectives and avoiding unreasonable impacts on non-DG customers.
The adoption of distributed generation is still maturing. These questions should be addressed in terms of understanding the optimal value that DG can bring to our electricity systems. CERI has identified and highlighted some of the issues that need to be addressed.
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July 2020 Opportunities and Challenges for Distributed Electricity Generation in Canada 87 Bibliography
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