Chapter 2: Non-renewable energy supply, resources and revenue

Below is a summary of Chapter 2, which includes sections on oil and gas—including conventional oil, bitumen production (bitumen reserves and limitations on long-term bitumen production), the overall oil production outlook, pipeline requirements under the cap, and natural gas—and coal, as well as government revenue from oil, gas and coal production. You can download the full summary, the full chapter or the full study via the links on the right.


Canada is a mature exploration and production petroleum province. More than 800,000 wells have been drilled, of which 222,000 are still producing. The four western provinces and southern territories comprising the Western Canada Sedimentary Basin (WCSB) have produced most of the oil and gas along with some offshore production in Newfoundland. Key considerations for oil production include the following:

  • Conventional oil production in Canada peaked in 1973. Some 88% of the NEB’s estimate of conventional light- and heavy-oil reserves in the WCSB have been consumed. Including the East Coast, 85% of Canada’s conventional oil reserves have been consumed. Yet the NEB’s reference case forecast would see the production of nearly three times Canada’s known conventional oil reserves by 2040.
  • If as yet undiscovered resources in Canada’s northern and offshore frontiers are included, 49% of Canada’s ultimate potential conventional oil has been consumed. The NEB’s reference case forecast assumes that 55% of remaining discovered and undiscovered conventional oil as of year-end 2016 will be produced by 2040. Undiscovered resources are uncertain estimates at best, and recovering oil in northern and offshore frontiers is subject to additional environmental risks.
  • Maintaining conventional oil production requires continual drilling as individual well production declines from 32% to 90% over the first three years. Modern hydraulically fractured horizontal wells decline at 78% to 90% over this period, accelerating the need for continuous drilling. The average production of oil wells has declined from a high of 130 barrels per day in Alberta in 1973 to less than 20 barrels per day in 2015.
  • With 97% of Canada’s remaining oil reserves, the oil sands offer the only hope for substantially increasing Canadian oil production. But this is a low-quality unconventional resource that requires large energy inputs to extract, with resultant large emissions compared to conventional oil (well-to-tank emissions for diesel fuel are 89% higher for oil sands than Canadian conventional oil).
  • Raw bitumen extracted from in situ oil sands has a mean energy return on energy investment (EROI) of about 4:1 versus about 8:1 for surface mineable resources. This compares to an EROI of greater than 10:1 for most conventional oil. Although only 20% of oil sands reserves are shallow enough to be surface mineable, they constitute 89% of the oil sands reserves currently under active development. As production from in situ extraction grows relative to surface mining, net energy will decline and average emissions per barrel will increase.
  • Oil sands projects target the highest-quality, most economic resources first. Although the resource is large, the energy return on investment will decline and emissions per barrel will increase as extraction moves into lower-quality portions of the resource. About 90% of the resource is in deposits with a pay thickness of less than 15 metres, whereas resources currently under development have a pay thickness of greater than 25 metres.
  • Although oil sands projects under construction will be completed and production will rise, it is unlikely that new greenfield projects will be developed unless oil prices increase substantially.
  • Existing export pipeline and rail capacity is sufficient to move forecast production through 2040 under the NEB’s reference production scenario with Alberta’s oil sands 100-megatonne per year emissions cap. Although transporting diluted bitumen (dilbit) by rail is more costly than pipelines, diluent is not needed if bitumen is transported in heated rail cars. Transporting undiluted bitumen allows 42% more product to be shipped per unit volume, making rail competitive with pipelines while at the same time reducing risk in the event of an accident (given that undiluted bitumen does not flow like dilbit or crude oil and is not volatile).
  • Canadian oil sold in the US is not being unfairly discounted. The US Gulf Coast has the world’s largest concentration of coking refineries, which can optimally process heavy oil, and Canadian crude is optimally positioned to replace declining production from Venezuela and Mexico, which have been large suppliers to Gulf Coast refineries. (The increase in the price differential observed since November 2017 is a result of the temporary shutdown of the existing Keystone pipeline and a subsequent reduction in its capacity. This will be eliminated with the completion of Line 3 and the likely completion of Keystone XL.)*

Key considerations for natural gas production include the following:

  • Natural gas production in Canada peaked in 2001 and is now 14% below that level. Two-thirds of Canada’s production comes from Alberta and most of the remainder comes from BC. Future growth will increasingly come from unconventional tight and shale gas resources made economically viable with horizontal drilling and hydraulic fracturing technology. The NEB’s reference scenario projects that unconventional gas will be 76% of Canadian supply by 2040. Gas production in the rest of Canada outside of Alberta and BC is projected to fall in the NEB’s reference case from about 4% at present to 2.5% in 2040.
  • Proven gas reserves in Canada amount to 70.9 trillion cubic feet (tcf) according to the Canadian Association of Petroleum Producers (CAPP). This is about 12.8 years of supply at 2016 production rates. The NEB’s reference case forecast projects production of 135 tcf, or nearly double current known reserves, by 2040. Some 94% of the NEB’s estimate of 1,225 tcf of remaining natural gas resources is unproven in terms of economic and technical viability.
  • The NEB has increased its estimate of remaining Canadian gas resources by 116% since 2007, almost entirely as a result of vastly ramped up estimates for tight gas and shale gas, both of which require horizontal drilling and hydraulic fracturing technology to recover (the latter of which has been subject to widespread environmental opposition in the US and elsewhere). Tight gas estimates have been ramped up by 386% and shale gas by 351%, whereas conventional gas estimates have been reduced by 40%. Some of these estimated resources are extrapolated over broad regions, often with minimal amounts of drilling, and must therefore be considered highly uncertain.
  • Maintaining gas production requires continual drilling because the hydraulically fractured horizontal wells required to produce most of the remaining resources decline 70% to 83% over their first three years. The average production rate of gas wells has declined from a high of 3,900 mcf/day (thousand cubic feet per day) in BC in 1973 to 570 mcf/day in BC, 100 mcf/day in Alberta and 20 mcf/day in Saskatchewan, in 2015.

Thermal coal production is forecast by the NEB to decline 78% from 2016 levels by 2030, due to the phase-out of coal generation in Alberta, whereas the production of metallurgical coal used in steel-making is forecast to increase by 10% over the same period, mainly for export.

The energy sector has declined as a proportion of the Canadian economy over the past 20 years despite growing production:

  • Production and distribution of oil, gas and coal as a percentage of total Canadian GDP declined from 9.2% in 1997 to 7.4% in 2015. Construction related to oil and gas development added 0.72% and 0.86% in 1997 and 2015, respectively. During this same period oil production increased by 79% and combined oil and natural gas production increased by 33%.
  • In Alberta, which contributed 71% of Canadian energy sector GDP in 2015, the proportion of the province’s GDP derived from oil, gas and coal production declined from 40% in 1997 to 29% in 2015 (an additional 3% and 3.3% was derived from oil and gas construction in 1997 and 2015, respectively).

Revenues to governments from the sale of non-renewable oil and gas resources have been declining markedly since 2000, despite record prices over parts of this period and growing production. According to CAPP, royalty revenues paid to provinces have declined 63% between 2000 and 2015, from $11.1 billion to $4.1 billion (nominal dollars). Royalties as a percentage of total oil and gas sales revenues have fallen 74% over the same period, from 17.1% to 4.5%, as illustrated in Figure ES7. Meanwhile, oil production grew by 75% between 2000 and 2015, and combined oil and gas production grew by 27%.


In Alberta, Canada’s largest oil and gas producer, revenue from royalties and other resource revenue have declined from 80% of government revenue in 1979 to an estimated 3.3% in 2016 (see Figure ES8). This is in spite of a doubling of oil and gas production since 1980. In 2015 dollars, Alberta government revenue hit $14 billion in 1979 and spiked again to $17 billion in 2005. Estimated 2016 revenue of $1.4 billion is down 90% from 2005 levels, despite considerable production growth since then.


A similar decline in resource revenue has occurred in BC, the second-largest producer of natural gas. Despite the fact that gas production has doubled since 2005, royalty and other non-renewable resource revenue has declined by 84%, such that it was only 1% of government revenue in 2017 (see Figure ES9).


Oil and gas jobs are a relatively minor overall component of the Canadian economy: 2.2% of Canada’s workforce was employed in oil, gas and coal production, distribution and construction in 2015. Of these jobs, 52% were involved in construction, most of which were of a temporary nature. In Alberta, 6.3% of jobs were involved in fossil fuel production and distribution, and a further 6.6% in related construction. Newfoundland was the second-most important province in terms of jobs, with 1.5% involved in oil production and distribution and 5.1% involved in related construction in 2015.

Despite growing production, jobs in the extraction and distribution portions of the industry have remained relatively flat since 2006, and declined in 2015 with the downturn in oil price. The exception is construction, mainly in the oil sands. Construction jobs are short-term, however, and many will disappear with the completion of projects currently under construction.

If corporate tax revenue is added to royalties and other non-renewable resource revenue paid to governments, total revenue is down 41% since 2000 (as of 2015), while oil production is up 75% and combined oil and gas production is up 27%. Claims of higher revenues through “spin-off” jobs not directly related to the oil and gas industry (through income taxes, etc.) assume that these people would not otherwise be employed, which is unlikely. In short, Canada’s remaining non-renewable energy resources are being sold off in an environment of low prices with minimal and declining returns to governments.

* Acuña, R., February 9, 2018, Let’s share actual facts about the Trans Mountain pipeline,


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