Canada's Emission Trends 2014: annex 2


Annex 2: Baseline Data and Assumptions

Baseline Data and Assumptions

Many factors influence the future trends of Canada’s GHG emissions. These key factors include the pace of economic growth, as well as Canada’s population and household formation, energy prices (e.g., world oil price and the price of refined petroleum products, regional natural gas prices, and electricity prices), technological change, and policy decisions. Varying any of these assumptions could have a material impact on the emissions outlook.

In constructing the emissions projections, Environment Canada developed alternative views of changes in certain key drivers (e.g., world oil price, the pace of economic growth) that result in a range of plausible emissions growth trajectories. The baseline emissions projections scenario represents the mid-range of these variations but remains conditional on the future path of the economy, world energy markets and government policy. The assumptions and key drivers are listed in this annex. Alternative cases are explored in the sensitivity analysis in Annex 3.

The emissions projections baseline scenario is designed to incorporate the best available information about economic growth as well as energy demand and supply into the future. The projections capture the impacts of future production of goods and services in Canada on GHG emissions.

Historical data on Gross Domestic Product (GDP) and disposable personal income are provided by Statistics Canada. Consumer price index and population demographics are also produced by Statistics Canada, while historical emissions data are provided by the 2014 NIR. The economic projections to the year 2018 are calibrated to Finance Canada’s June 2014 Private Sector Survey.Footnote 20 The outer years (2018 to 2020) are based on Finance Canada’s longer-term fiscal projections included in their Economic and Fiscal Implications of Canada's Aging Population report.Footnote 21

Forecasts of major energy supply projects from the National Energy Board’s 2013 projections were incorporated for key variables and assumptions in the model (e.g., oil sands production, large hydro-capacity expansions, nuclear refurbishment and additions). The National Energy Board is an independent federal agency that regulates international and interprovincial aspects of the oil, gas and electric utility industries. The U.S. Energy Information Administration’s outlook on key parameters is also taken into account in the development of energy and emissions trends.

Economic Growth

The Canadian economy grew by 1.5% per year over 2005 through 2012, a period that includes the 2009 global recession. Real GDP growth is expected to average 2.2% per year from 2012 to 2020. In line with the Bank of Canada’s target, the annual inflation rate is expected to be approximately 2% per year throughout the projection.

Table A.1: Macroeconomic Assumptions, 1990-2020 Average Annual Growth Rates
Assumption 1990-2012 2012-2020
Average Annual GDP Growth Rate 2.4% 2.2%
Average Annual Population Growth Rate 1.0% 1.1%
Average Annual Labour Force Growth Rate 1.3% 0.6%

The growth in the labour force and changes in labour productivity influence the changes in Canada’s real GDP. Labour productivity is expected to increase by an average of 1.0% annually between 2012 and 2020, an improvement over the 0.4% average annual growth during the period between 2005 and 2012. The increase in productivity is attributed to an expected rise in capital formation and contributes to the growth in real disposable personal income, which is expected to increase by an average of 1.8% per year between 2012 and 2020.

Population Dynamics and Demographics

The population size and its characteristics (e.g., age, sex, education, household formation) have important impacts on energy demand. Canada’s overall population is projected to grow on average at an annual rate of 1.1% between 2012 and 2020.

Major demographic factors that can have measurable impacts on energy consumption are summarized below:

  • Household formation: This is the main determinant of energy use in the residential sector. The number of households is expected to increase on average by 1.4% per year between 2012 and 2020.
  • Labour force: This is expected to have a decelerating growth rate, reflecting the aging population. Its annual average growth rate was 1.3% per year between 2005 and 2012, and is projected to slow to 0.6% per year between 2012 and 2020.

World Crude Oil Price

A major factor in projected GHG emissions is the assumption about future world oil prices, since this drives the level of production of oil. Canada is a price taker in crude oil markets, as its shares of world oil production and consumption are not large enough (4% and 2%, respectively) to significantly influence international oil prices. West Texas Intermediate (WTI) crude oil is used as an oil price benchmark. North American crude oil prices are determined by international market forces and are directly related to the WTI crude oil price at Cushing, which is the underlying physical commodity market for light crude oil contracts for the New York Mercantile Exchange. The increase in North American supply and the resulting transportation bottleneck at Cushing have created a disconnect between the WTI price of crude oil and the Brent price of crude oil. As such, the North American oil market is currently being priced differently from the rest of the world.

The emissions outlook’s reference case is anchored by the world oil price assumptions developed by the National Energy Board (NEB). According to the NEB, the world crude oil price for WTI is projected to increase slightly from about $96 Canadian dollars (2012 C$) per barrel of oil (bbl) in 2012 to about C$102/bbl in 2020. The NEB’s higher price scenario, in which 2020 prices are C$132/bbl, is used for the sensitivity analysis in Annex 3.

Figure A.2: Crude Oil Price: WTI and Alberta Heavy (2012 C$/bbl)

Figure A.2 (see description below)

Text description of Figure A.2

Figure A.2 presents two time series line graphs on a chart spanning the years 1990 through 2020. The vertical axis is $2012 per barrel in C$ spanning the values from 0 to 120 in increments of 20. The lines on the graphs are solid for the historical price. For the projected years of 2013 onwards, the lines become dotted to represent projected prices. The top line is the WTI price for crude oil and the bottom line is the Alberta Heavy price. WTI History begins in 1990 at $37 and ends in 2012 at $96. The projected price for WTI in 2020 is $102. Alberta Heavy (Hardisty) History begins in 1990 at $28 and ends in 2012 at $72. The projected price for Alberta Heavy (Hardisty) in 2020 is $81.

Figure A.2 shows crude oil prices for light crude oil (WTI) and heavy oil. Historically, the price of heavy oil/bitumen (Alberta Heavy) has followed the light crude oil price (WTI) at a discount of 50% to 60%. However, in 2008 and 2009 the differentials between the prices of light and heavy crude oils (“bitumen/light-medium differential”) narrowed significantly owing to a global shortage of heavier crude oil supply. The bitumen/light-medium differential averaged 22% over the 2008 to 2009 period, compared with 44% over the five-year average from 2003 to 2007.

Alberta’s Energy Regulator expects the bitumen/light-medium differential to average 26% over the forecast period, compared with the five-year average of 36% and the 2009 average of 17%.Footnote22

As shown in Figure A.3, the Henry Hub price for natural gas in Alberta (the benchmark for Canadian prices) declined in 2010 to about four Canadian dollars per gigajoule (GJ). In the projection, it begins to recover to reach about C$4.72 per GJ by 2020, well below its peak of over C$9 in 2005. This reflects the National Energy Board’s assumption that major pipeline expansions such as the Mackenzie and Alaska pipelines may not occur before 2020 due to low natural gas prices.

Figure A.3: Henry Hub Natural Gas Price (2012 C$/GJ)

Figure A.3 (see description below)

Text description of Figure A.3

Figure A.3 presents a time series graph on a chart for the Henry Hub price of natural gas spanning the years 1990 through 2020. The vertical axis is $2012 per GJ in C$ and spans the values 0 to 10 in increments of 1. The historical period is represented by a solid line ending in 2012 and the projected price is represented by a dotted line continuing to 2020. The 1990 value is $2.36, with a peak in 2005 at $9.11 and a secondary peak in 2008 at $8.56. The historical period ends in 2012 at $2.63, and the projected price in 2020 is $4.72.

Energy and Electricity Production

Oil and Gas

NEB projections show that both natural gas and conventional oil production will decrease over time as a result of declining supply, although the projected increase in production from oil sands operations will more than compensate for this decline. As such, under assumed prices and absent further government policy actions, it is expected that from 2012 to 2020 oil sands in situ production will more than double (see Table A.2).

Table A.2: Crude Oil Production in Thousands of Barrels per Day
Thousand Barrels per Day 2005 2012 2020
Crude and Condensates   1532 1462 1405
Conventional Heavy
524 451 431
Conventional Light
511 649 612
C5 and Condensates
173 150 103
Frontier Light (offshore + northern)
324 211 259
Oil Sands 1064 1921 3418
Oil Sands: Primary
150 245 249
Oil Sands: in Situ
286 750 1731
Steam-assisted Gravity Drainage
82 491 1406
Cyclic Steam Stimulation
204 259 325
Oil Sands Mining
628 925 1438
Total Production (gross) 2596 3382 4823

Note: Numbers may not sum to the total due to rounding.

Table A.3 illustrates oil sands disposition. There are two main products from oil sands production: synthetic crude oil (or upgraded bitumen) and non-upgraded bitumen, which is sold as heavy oil. Synthetic crude oil production is projected to increase from about 959 000 barrels per day (bp/d) in 2012 to about 1.3 million bp/d by 2020. Non-upgraded bitumen will increase from 851 000 bp/d in 2012 to 1.9 million bp/d by 2020. This non-upgraded bitumen is either sold as heavy oil to Canadian refineries or transported to U.S. refineries for upgrading to refined petroleum products.

Table A.3: Oil Sands Disposition in Thousands of Barrels per Day
Thousand Barrels per Day 2005 2012 2020
     Synthetic 611 959 1347
     Non-upgraded Bitumen                         370 851 1904
Oil Sands (net) 981 1810 3250
     Own Use 83 111 168
Oil Sands (gross) 1064 1921 3418

Note: Numbers may not sum to the total due to rounding.

Projections show gross natural gas production will decline to some 4.9 trillion cubic feet (TCF) in 2020, as new production and non-conventional sources such as shale gas and coal-bed methane come to market but do not quite offset conventional declines.Footnote 23

Table A.4: Natural Gas Production in Billion Cubic Feet
Billion Cubic Feet 2005 2012 2020
Supply      
       Gross Production 6834 5826 4861
       Own-use Consumption 618 718 605
Marketable Gas 6215 5108 4256
Imports 332 1106 1231
Total Supply 6547 6213 5487
Liquid Natural Gas Production 0 0 548

Note: Numbers may not sum to the total due to rounding.

Electricity

The projections in this report reflect plans by provincial and territorial utilities with respect to key electricity capacity expansions. In addition, additional units are built endogenously by the model to meet growth in electricity demand. Aggregate electricity generation is expected to increase, by 6.7% from 2012 to 2020, with fuel mix changes as generation increases. As Table A.5 illustrates, the proportion of generation coming from wind power and other non-hydro renewable sources is expected to increase from 2005 to 2020, starting at only about 0.3% in 2005 and reaching 7.5% of total generation by 2020.

Government actions, such as the introduction of the Electricity Performance Standard, will cause fuel switching in the overall electricity generating portfolio. As noted above, it is expected that natural gas-fired generation will continue to increase because of its appeal as a relatively cleaner source of power generation and a reliable means to cover peak loads. The lower price of natural gas also makes it an attractive choice. Coal and petroleum coke generation are projected to fall from 18% of the generation in the Canadian portfolio in 2005 to 9.0% in 2020.

Table A.5: Utility Electricity Generation by Fuel, Terawatt-hours
Terawatt-hours (TWh) 2005 2012 2020
Coal and Petroleum Coke 98 64 53
Refined Petroleum Products 12 3 2
Natural Gas 28 40 33
Hydro 327 345 379
Nuclear 87 89 79
Other Renewables 2 12 44
Total Generation 553 553 590

Note: Numbers may not sum to the total due to rounding.

Emissions Factors

Table A.6 provides a rough estimate of CO2 eq emissions emitted per unit of energy consumed by fossil fuel type. These numbers are estimates based on latest available data based on IPCC methodology. Specific emission factors can vary slightly by year, sector and province.

Table A.6: Mass of CO 2 eq Emissions Emitted per Quantity of Energy for Various Fuels
Fuel CO2 eq Emitted
(g/MJ)
Aviation Gasoline 73.37
Biodiesel 8.31
Biomass 4.59
Coal 90.87
Coke 6.82
Coke Oven Gas 36.79
Diesel 74.08
Ethanol 2.81
Gasoline 68.50
Heavy Fuel Oil 74.58
Jet Fuel 68.82
Kerosene 67.41
Landfill Gases/Waste 65.92
Light Fuel Oil 70.43
Liquified Petroleum Gas 60.61
Natural Gas 49.88
Natural Gas Raw 66.03
Petroleum Coke 84.35
Still Gas 47.86

Federal, Provincial and Territorial Measures

Table A.7 identifies the major federal, provincial and territorial measures that are included when modeling the reference case. This includes federal measures that have been implemented or announced in detail as of May 2014. Where program funding is set to end, the projections assume that the impacts of these programs, other than those embodied in consumer behaviour, cease when the approved funding terminates.

The analysis also includes existing provincial and territorial measures. Environment Canada involves provinces and territories in extensive consultations to ensure their initiatives are accounted for in analysis and modeling of emissions trends. For the purposes of this report, provincial/territorial measures announced and fully implemented as of May 2014 have been included wherever possible.

Although the reference case includes existing measures that have been implemented or announced in detail, it does not take into account the impact of broader strategies or future measures within existing plans where significant details are still under development. Policies still under development will be included in subsequent projections as their details become finalized.

Economic modeling only accounts for measures that have been fully funded, legislated or where sufficiently detailed data exists that make it possible to add to the modeling platform. In addition, due to the interactive effects between federal and provincial/territorial measures, it is not possible to accurately split aggregate emissions reductions into federal, provincial or territorial measures.

Table A.7: GHG Measures Reflected in Projections (in place May 2014)

Provincial/Territorial Measures

Alberta

  • Specified gas emitters regulation (assumed to be renewed)

British Columbia

  • B.C. carbon tax
  • Renewable fuels tax exemptions for minimum ethanol and biodiesel content
  • B.C. emissions offsets regulation
  • Landfill gas management regulation

Manitoba

  • Renewable fuels provincial tax credit/exemption for minimum ethanol content

Nova Scotia

  • Renewable portfolio standard for electricity generation
  • Electricity demand-side management policies
  • Solid waste management resources management strategy
  • Capping GHG emissions from the electricity sector

Ontario

  • Ontario residential electricity peak savings (time-of-use pricing)
  • Ontario feed-in tariff program
  • Provincial commercial building code changes for process efficiency improvements
  • Landfill gas regulation (O. Reg. 216/08 and 217/08)
  • Ontario coal phase-out program
  • Ontario Power Authority contracted capacity (March 2014)
  • Ontario's greener diesel mandate (April 2014)

Quebec

  • Renewable fuels tax reimbursement/income tax credit
  • Quebec and California cap and trade system
  • Quebec’s carbon levy
  • Landfill gas regulation

Saskatchewan

  • Renewable fuels distributor tax credit for ethanol produced and consumed in the province

Federal Measures

  • Electricity performance standard for coal-fired generation
  • Residential building code changes to incorporate energy efficiency for adoption by provinces across Canada
  • Renewable fuel content regulation
  • Adoption of the National Energy Code for Buildings of Canada 2011 or its equivalent, by all provinces and territories, except Northwest Territories, by 2016
  • Commercial appliance efficiency improvements (excludes lighting)
  • Residential appliance efficiency improvements, includes refrigeration, freezers, ranges and dryers
  • Industry expansion of Canadian industry program for energy conservation including International Organization for Standardization (ISO) and Canadian Standards Association (CSA) certification programs
  • Light duty vehicles 1 (LDV-1) GHG emissions standards for the light-duty vehicle model years 2011 to 2016
  • Light duty vehicles 2 (LDV-2) GHG emissions standards increases stringency for model years 2017 to 2025
  • Heavy duty vehicles (HDV) GHG emissions standards for heavy-duty vehicle model years 2014 to 2018
  • The pulp and paper green transformation program, to improve environmental performance of mills including GHG emissions reductions; the program ended in 2012 but will result in ongoing emission reductions
  • Public transit subsidy income tax credit for transit passes and subsidy to all levels of government to improve public transit service in communities, includes standards for renewable fuels
  • Incandescent lighting phase-out

Canadian provinces and territories have committed to taking action on climate change through various programs and regulations. Environment Canada’s emissions reduction modeling does not take these generalized targets into consideration in the emissions projections modeling within this report. Instead, individual policies that are brought forward as methods to attain the provincial targets may be included in the modeling platform if they meet the criteria discussed above. Table A.8 lists the emissions reductions targets announced by each province or territory.

Table A.8: Announced GHG Reduction Targets of Provincial/Territorial Governments
Province/Territory Target
Newfoundland and Labrador 20% below 2005 by 2020 and 75% to 85% below 2001 by 2050
Prince Edward Island 10% below 1990 by 2020 and 75% to 85% below 2001 by 2050
Nova Scotia 10% below 1990 by 2020 and 80% below 2009 for emissions from human sources
New Brunswick 10% below 1990 by 2020 and 75% to 85% below 2001 by 2050
Quebec 20% below 1990 by 2020
Ontario 15% below 1990 by 2020 and 80% below 1990 by 2050
Manitoba 15% below 2005 by 2020 and 80% below 2005 by 2050
Saskatchewan 20% below 2006 by 2020
Alberta 50 Mt below business-as-usual by 2020 and 200 Mt below business-as-usual by 2050
British Columbia 33% below 2007 by 2020 and 80% below 2007 by 2050
Yukon Government operations are carbon neutral by 2020
Northwest Territories Cap emissions increase at 66% over 2005 by 2020
Nunavut No territorial target announced
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