ARCHIVED – Economics of Solar Power in Canada – Appendix A: Methods
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|Low cost future|
|Time of day|
Breakeven costs were examined for four types of arrays:
- Residential-scale of 5 kW, to model roof-top arrays supplying power to a home.
- Commercial-scale of 200 kW, to model medium-sized facilities providing power for large businesses.
- Utility-scale of 50 MW, to model large facilities providing power to the grid.
- Community-scale of 200 kW, to model medium-sized facilities providing power to a neighborhood or to a civic building, such as a recreation centre. Importantly, the facility is assumed to be a non-profit, which has tax implications, and is the reason why community-scale is modeled separately from commercial-scale.
Site selection and solar insolation
Natural Resources Canada’s Canadian Geographical Names Database was used to find sites that could be considered communities.Footnote 7 The latitude and longitude of each site was used to download the geographically closest, typical-meteorological year (TMY) solar-irradiation data from the U.S. Department of Energy’s National Solar Radiation Database (NSRDB).Footnote 8 For Yukon, the Northwest Territories, and Nunavut, Canadian Weather Year for Energy Calculation (CWEC) dataFootnote 9 from Environment and Climate Change Canada (ECCC) was used to determine the amount of hourly sunlight, which limited the number of communities that could be examined. Altogether, 21 546 communities were examined.
|Province-Territory||Urban, rural, and other communities||First Nation and Métis||Canadian Armed Forces||Generating stations and mines||Total|
|NS||2 202||41||23||2 266|
|NB||1 947||27||12||1 986|
|QC||3 329||55||10||144||3 538|
|ON||5 857||207||46||6 110|
|SK||1 174||747||8||1 929|
|AB||1 060||146||14||1 220|
|BC||1 088||1 564||40||2 692|
|Total||18 111||3 110||167||158||21 546|
Thus, for each community, typical, hourly solar irradiation for a calendar year was available to calculate incident light on a solar panel, where the sun’s position in the sky was determined from U.S. National Oceanic and Atmospheric Administration equations. Mild losses of power were assumed to occur in winter months because of snow cover, though some gains from reflected light were included, as estimated from the closest CWEC albedo data. Soiling was assumed to reduce output by 5% year round. The same NSRDB dataset includes hourly temperatures, which were also used in the model.
A typical solar panel Footnote 10 was used to determine the conversion of solar irradiance to electricity, as estimated from NREL models of panel performance. Panels were assumed to face due south to maximize sunlight received. Panel tilt for commercial-, community-, and utility-scale arrays was latitude minus nine degrees.Footnote 11 Rooftop panels were tilted at 27 degrees, a normal slope for Canadian rooftops.
Residential-, commercial-, and community-scale arrays were assumed to have fixed mounts (i.e., panels do not rotate as the sun moves in the sky). Utility-scale projects were modeled in two ways: one way with fixed mounts and the other with single-axis trackers (which could rotate a maximum of 90 degrees on their axes). Angles of incidence for arrays were estimated using NREL equations.Footnote 12
Small losses were included for early- and late-day shading. Small losses were also included for wiring (AC and DC), module mismatch, and inverter loss to convert DC to AC. Line losses for utility-scale arrays varied by province as based on provincial tariffs. Panel performance was assumed to degrade by 0.5% per year over the life of the project. NSRDB hourly temperatures were used to adjust panel performance.
|Utility (50 MW) – Fixed Mount||Utility (50 MW) – Tracker Mount|
|Initial Costs (C$/W)||Current||Near future||Low cost future||Current||Near future||Low cost future|
|Balance of System (Structural and electrical)||$0.211||$0.131||$0.090||$0.262||$0.162||$0.110|
|Commercial and Community (200 kW)||Residential (5 kW)|
|Initial Costs (C$/W)||Current||Near future||Low cost future||Current||Near future||Low cost future|
|Balance of System (Structural and electrical)||$0.326||$0.209||$0.148||$0.394||$0.272||$0.207|
Installation costs were based on a NREL study of 2017 solar-system costs. Three pricing scenarios were developed by projecting 2017 costs into 2018, 2023, and 2028 using historical trends (current, near future, and a low cost future, respectively). U.S. taxes were removed and the values converted to Canadian dollars with a C$1.25/US$ exchange rate. The three pricing scenarios were finalized after consulting with industry and adjusting estimates where necessary. The three scenarios include hardware costs (such as panels and inverters) and soft costs (installation and development).
Arrays were assumed to last 25 years. Halfway through the life of all types of arrays, new inverters were assumed to be installed. Half way through the life of utility-scale arrays with trackers, new trackers were assumed to be installed. At the end of 25 years, an additional capital expense of remediation was applied. The residual value of panels after 25 years was 25% of their original cost. The residual value of other equipment was assumed to be 15%.
Land costs for utility-scale solar arrays were based on Statistics Canada estimates of farm land and building values in each province.Footnote 13 Importantly, costs were increased in some areas (for example, Southern Ontario and the Lower Mainland of British Columbia) because of high demand for real estate. Land costs for commercial, community, and residential were assumed to be zero, because the systems would be installed on an existing rooftop or property already owned.
Tariffs, transmission, and operating costs
The analysis includes two scenarios for connecting utility-scale solar facilities into transmission systems: one with provincial open-access transmission tariffs (OATTs) applied, and another without them, to better understand tariff costs and how the economics of power-purchase agreements might differ from independent producers (or if large utility-scale arrays produce into local distribution systems instead of into transmission systems). Tariffs can be lower than indicated here if generation is part of a portfolio and the operating-reserve services, which pay for backup generation in the event of an outage, come from the portfolio rather than paying the transmission provider for them.
Yukon, the Northwest Territories, and Nunavut do not currently have tariffs, because they do not produce electricity into the North American market. Newfoundland and Labrador is currently developing an OATT. Alberta’s tariff is based on the Alberta Electric System Operator’s (AESO’s) connection costs, the AESO’s rate supply transmission service, and an estimate of the AESO’s construction and generator’s contribution financed over 25 years.
|Province/Territory||Assumed Utility-scale Tariff (C$/MW)||Line Loss|
Meanwhile, maintenance was assumed to be $15/MW. The connection line to attach utility-scale solar to the grid was assumed to cost $5/MW.h (as based on a 10 km line and a mid-size facilityFootnote 14).
ESPC estimates a project’s net-present value to model its economics. A 5.75% nominal discount rate was used for utility- and community-scale solar facilities, as based on the cost of capital for solar in Canada in 2017.Footnote 15 Commercial-scale facilities were assumed to have a 5.81% nominal discount rate, as based on the weighted-average cost of capital for all industries in the United States.Footnote 16Residential-scale solar was assumed to have a 5% nominal discount rate, because, if the residential system is intended to save the owner money, then it should be measured against other investment opportunities (where 5% annual returns would be reasonable for a low- to mid-risk balanced fund). Inflation was assumed to be 2% and all costs are in 2018 dollars.
The expected rate of return for utility-scale farms was assumed to be 10%. Otherwise, the rate of return for commercial, community, and residential systems were assumed to be 0%, because these are not profit-oriented systems, but only hope to recover their costs. Because Canadian electricity prices have been rising faster than the rate of inflation, it was assumed the real value of electricity generated would increase by 1.91% per year, the annual average from 2010 to 2017 (i.e., in 10 years, energy charges would be 19.1% higher than current, real prices, and in 25 years, energy charges would be 47.75% higher than current, real prices). Otherwise, prices were not increased over time to model additions of expensive electricity generation as the power sector reduces its carbon footprint.
Income taxes were subtracted from revenues as based on federal and provincial corporate-tax rates for utility-scale facilities. Residential-scale facilities paid sales taxes for the value of electricity returned to the grid for credits, because sales taxes are still paid on the electricity consumed in later months before any credit is applied. Community-scale facilities paid no income taxes, because they were assumed to be non-profit. Commercial-scale facilities paid no income tax, because it was assumed all electricity would be consumed on site. No carbon taxes were applied to any type of project.
|Sales Tax (Provincial or territorial plus federal)|
|Province/Territory||Corporate Income Tax (Provincial or territorial plus federal)||Residential||Commercial||Community||Utility|
Operating costs, interest payments (assuming 60% debt), and an accelerated capital-cost allowance (CCA)Footnote 17 were deducted from income taxes for utility-scale facilities. CCA deductions were not applied to commercial-scale facilities, because it was assumed all electricity would be consumed onsite, thus no income taxes were to be paid on electricity generated. For residential-scale and commercial-scale projects, sales taxes were applied to all capital costs. For utility-scale projects sales taxes were only applied to equipment and installation. No sales taxes were applied to the capital costs of community-scale projects, which were assumed to be non-profit.
Two pricing scenarios were used:
- flat pricing (i.e., with no hourly variation). Many residential, commercial, and community consumers pay flat rates for their electricity. Flat pricing was also examined for utility-scale facilities, because the difference between it and “time of day pricing” can help show the premium that time-of-day pricing earns.
- Time-of-day pricing, because solar generates electricity during daylight hours, when demand is highest and electricity has the most value. Time-of-day pricing helps show the premium that solar projects earn, including utility-scale. Meanwhile, provinces are increasingly rolling out smart meters to homes and businesses so that utilities can measure consumption by time of day and apply time-of-day rates to consumption.
To model time-of-day pricing, typical off-peak, mid-peak, and on-peak price discounts and premiums were determined by comparing hourly prices to average, daily prices for winter and summer days and on a wholesale-price and residential-price basis. However, only two provinces (Ontario and Alberta) have wholesale markets from which to make these estimates. Meanwhile, only Ontario and Nova Scotia have time-of-day residential rates. Thus, because of the lack of data, the hourly discounts and premiums from some provinces were applied to others.
|Province/Territory||Residential time-of-day discounts and premiums||Commercial and Community time-of-day discounts and premiums||Utility time-of-day discounts and premiums|
|NL||Nova Scotia - residential time of day||Nova Scotia - residential time of day||Nova Scotia - residential time of day|
|PEI||Nova Scotia - residential time of day||Nova Scotia - residential time of day||Nova Scotia - residential time of day|
|NS||Nova Scotia - residential time of day||Nova Scotia - residential time of day||Nova Scotia - residential time of day|
|NB||Nova Scotia - residential time of day||Nova Scotia - residential time of day||Nova Scotia - residential time of day|
|QC||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
|ON||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
|MB||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
|SK||Alberta - wholesale||Alberta - wholesale||Alberta - wholesale|
|AB||Alberta - wholesale||Alberta - wholesale||Alberta - wholesale|
|BC||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
|NU||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
|NT||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
|YT||Ontario – residential time of day||Ontario - wholesale||Ontario - wholesale|
Importantly, high penetrations of solar power into Canada’s electricity mix are expected to depress mid-day premiums and flatten daily price peaks. Thus, this analysis should be considered for low penetration of solar only.
Residential demand for electricity in each province was assumed to be, at minimum, the national average.Footnote 18 Provinces with higher residential consumption than the national average used their provincial estimate. Provinces were lifted to the national average, because solar generation could lead to higher electrification of some home appliances, such as water heaters and stoves, and may add other electrified appliances, like air conditioning.
|Geography||2015 Consumption (GJ)||2015 Adjusted Consumption (GJ)|
Generation from a residential array that was excess to residential consumption was assumed to be returned to the grid for a credit, which was then used to offset electricity consumption of equal value when the solar array wasn’t producing as much electricity, such as in the winter. The values of credits were based on estimates of current, variable energy charges in each province, and were modified by hourly discounts and premiums in time of day scenarios.
Commercial and community sites were assumed to consume all the electricity they generated. Utility-scale projects were assumed to have no on-site consumption (i.e., consumption would be covered by their operating costs).
Comparable electricity prices
Comparable electricity prices for residential-scale solar were determined from residential energy charges and other variable charges published by provincial and territorial utilities and electricity providers. In Ontario and Alberta, multiple cities were averaged to determine the comparable electricity price. These prices do not include fixed charges, which stay the same on every bill no matter how much electricity is consumed. Thus, buying residential electricity from local utilities is slightly more expensive than indicated here.
Because commercial-scale demand of electricity can be so variable from sector to sector, estimates from Manitoba Hydro’s Footnote 19 and Hydro Quebec’s Footnote 20 electricity-price surveys were averaged for each province. It was assumed 200 MW.h of electricity is assumed monthly at 500 kW of peak demand. It was also assumed that transformation was utility owned. For the territories, energy charges published by local utilities were used.
For utility-scale projects, the average, annual wholesale electricity price was used for the comparable electricity price in Ontario and Alberta, the only two provinces with wholesale markets. Otherwise, reseller rates or large industry energy charges were used, because these would be the next best estimate of what wholesale pricing is, though could still be higher than the real cost of generation.
|Province/Territory||Residential||Commercial and Community||Utility-scale|
|NL||Newfoundland Power domestic energy charge||
Average of per MW.h total-bill costs for cities listed in Manitoba Hydro and Hydro Quebec electricity-price surveys.
Assumed 200 MW.h monthly consumption at 500 kW, utility-owned transformation
|Newfoundland Power industrial firm base rate energy charge|
|PEI||Maritime Electric residential energy charge||Maritime Electric large industrial rate schedule energy charge|
|NS||Nova Scotia Power average, daily, time of use rate||Nova Scotia Power large industrial tariff (average firm and interruptible energy charge)|
|NB||NB Power residential energy charge||NB Power large industrial service energy charge|
|QC||Hydro Quebec residential energy charge||Hydro Quebec large industrial (rate L) price of energy|
|ON||Average Toronto Hydro, Ottawa Hydro, London Hydro, and Hydro One residential energy charges plus other variable rates||Average, annual wholesale price|
|MB||Manitoba Hydro residential energy charge||Manitoba Hydro general service large (exceeding 100 kV) energy charge|
|SK||Average SaskPower and City of Saskatoon residential energy charges||SaskPower reseller rate (average of E31, E32, and E33)|
|AB||Average Enmax and Epcor energy charges and other variable charges||Average, annual wholesale price|
|BC||BC Hydro residential energy charge plus a 5% rate rider||BC Hydro transmission rate – energy charge 1823A|
|NT||Northland Utilities Yellowknife residential energy charge||Northland Utilities Yellowknife commercial energy charge||Northland Utilities General Service (Yellownife)|
|NU||Iqaluit domestic energy charge, Qulliq Energy Corporation||Iqaluit commercial energy charge, Qulliq Energy Corporation||Iqaluit commercial energy charge, Qulliq Energy Corporation|
|YT||Average Yukon Energy government and non-government rates for residential service||Average Yukon Energy government and non-government rates for commercial service||Yukon Energy Whitehorse industrial rate|
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