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Overview

This Fact Sheet analyzes the upstream oil industry’s record on flaring in Canada relative to other top oil-producing countries. Gas flaring is the burning off of the natural gas that is generated in the process of oil extraction and production. Flaring is relevant because it is a source of greenhouse gas emissions (GHGs) (see Appendix).

In 2022, 138,549 million cubic meters (m3) (or 139 billion cubic meters (bcm)) of flared gases were emitted worldwide, creating 350 million tonnes of CO2 emissions annually. Canada is a significant oil producer; it has the third-largest proven crude oil reserves and is the fourthlargest crude oil producer in the world (Natural Resources Canada, undated), and so contributes to flaring.

Flaring comparisons

This Fact Sheet uses World Bank data to provide international comparisons of flaring. It also draws on U.S. Energy Information Administration (EIA) crude oil production data to compare flaring among the top 10 crude oil producing countries.

Table 1 shows gas flaring volumes in 2012 and 2022. In absolute terms, Russia recorded more flaring than any other country at 25,495 million m3 (25.4 bcm) in 2022, which was 1,628 million m3 (7 per cent) higher than in 2012.

The four countries that are the top GHG emitters through flaring (Russia, Iraq, Iran, and Algeria) accounted for 50 per cent of global gas flaring in 2022.

At 945 million m3, Canada was the eighth lowest flarer in 2022 (23rd spot out of the top 30 countries). It decreased its flaring emissions by 320 million m3 from the 2012 level of 1,264 million m3, a 25 per cent drop.

In 2022, Canada contributed just 0.7 per cent of the global amount of gas flaring despite being the world’s fourth largest oil producer (see Table 1).

Sources: World Bank (undated)

Flaring declined worldwide between 2012 and 2022

Figure 1 shows the change in flaring volumes between 2012 and 2022. Nine countries flared more in 2022 than in 2012, while 21 countries flared less. In the last decade, the global flaring volume decreased by 3 per cent.

• The three countries that most significantly increased flaring between 2012 and 2022 were the Republic of the Congo (65 per cent), Iran (56 per cent), and Iraq (41 per cent).
• The three countries that most significantly decreased flaring between 2012 and 2022 were Uzbekistan (-76 per cent), Columbia (-75 per cent) and Kazakhstan (-74 per cent).
• As noted earlier, flaring fell by 25 per cent in Canada between 2012 and 2022.

Sources: World Bank (undated)

Comparing flaring to increased production

The decreases in flaring in Canada between 2012 and 2022 shown in Table 1 and Figure 1 understate the magnitude of the decline in flaring in the country. That is because Canada’s crude oil production increased by 45 per cent in that period, even as absolute flaring decreased by 25 per cent (see Table 2).

Canada compares very favourably with the United States, which increased crude oil production by 82 per cent and decreased flaring by 16 per cent.

Sources: World Bank (undated) and EIA (2023)

Largest oil producers and flaring intensity

To fully grasp how much more effective Canada has been than many other oil producers in reducing flaring, Table 3 compares both flaring intensity (gas flared per unit of oil production) and crude oil production among the top 10 oil producing countries (which account for 73 per cent of the world oil production).

Canada is the fourth-largest producer of crude oil, and its gas flaring intensity declined by 48 per cenft between 2012 and 2022. Four of the top 10 oil producers witnessed their flaring intensity increase between 2012 and 2022.

Sources: World Bank (undated) and EIA (2023)

Conclusion

Gas flaring contributes to greenhouse gas emissions. However, it is possible for countries to both increase their oil production and still reduce flaring. Canada is one noteworthy example of a country that has significantly reduced flaring not only compared to its increased production of crude oil, but also in absolute terms.

Appendix

Background

Flaring and venting are two ways in which an oil or natural gas producer can dispose of waste gases. Venting is the intentional controlled release of uncombusted gases directly to the atmosphere, and flaring is combusting natural gas or gas derived from petroleum in order to dispose of it.¹ As Matthew R. Johnson and Adam R. Coderre noted in their 2012 paper on the subject, flaring in the petroleum industry generally falls within three broad categories:

• Emergency flaring (large, unplanned, and very short-duration releases, typically at larger downstream facilities or off-shore platforms);
• Process flaring (intermittent large or small releases that may last for a few hours or a few days as occurs in the upstream industry during well-test flaring to assess the size of a reservoir or at a downstream plant during a planned process blowdown); and
• Production flaring (may occur continuously for years while oil is being produced).

To track GHGs from flaring and venting, Environment Canada (2016) defines such emissions as:

• Fugitive emissions: Unintentional releases from venting, flaring, or leakage of gases from fossil fuel production and processing, iron and steel coke oven batteries, or CO2 capture, transport, injection, and storage infrastructure.
• Flaring emissions: Controlled releases of gases from industrial activities from the combustion of a gas or liquid stream produced at a facility, the purpose of which is not to produce useful heat or work. This includes releases from waste petroleum incineration, hazardous emission prevention systems, well testing, natural gas gathering systems, natural gas processing plant operations, crude oil production, pipeline operations, petroleum refining, chemical fertilizer production, and steel production.
• Venting emissions: Controlled releases of a process or waste gas, including releases of CO2 associated with carbon capture, transport, injection, and storage; from hydrogen production associated with fossil fuel production and processing; of casing gas; of gases associated with a liquid or a solution gas; of treater, stabilizer, or dehydrator off-gas; of blanket gases; from pneumatic devices that use natural gas as a driver; from compressor start-ups, pipelines, and other blowdowns; and from metering and regulation station control loops.

1. Many provinces regulate flaring and venting including Alberta (Directive 060) British Columbia (Flaring and Venting Reduction Guideline), and Saskatchewan (S-10 and S-20). Newfoundland & Labrador also has regulations that govern offshore flaring.

Notes

This CEC Fact Sheet was compiled by Ven Venkatachalam and Lennie Kaplan at the Canadian Energy Centre: www.canadianenergycentre.ca. All percentages in this report are calculated from the original data, which can run to multiple decimal points. They are not calculated using the rounded figures that may appear in charts and in the text, which are more reader friendly. Thus, calculations made from the rounded figures (and not the more precise source data) will differ from the more statistically precise percentages we arrive at using source data. The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of an anonymous reviewer in reviewing the data and research for this Fact Sheet.

References (All links live as of September 23, 2023)

Alberta Energy Regulator (2022), Directive 060: Upstream Petroleum Industry Faring, Incinerating, and Venting <https://bit.ly/3AMYett>; BC Oil and Gas Commission (2021), Flaring and Venting Reduction Guideline, version 5.2 <https://bit.ly/3CWRa0i>; Canada-Newfoundland and Labrador Offshore Petroleum Board (2007), Offshore Newfoundland and Labrador Gas Flaring Reduction <https://bit.ly/3RhKpKu>; D&I Services (2010), Saskatchewan Energy and Resources: S-10 and S-20 <https://bit.ly/3TBrVGJ>; Johnson, Matthew R., and Adam R. Coderre (2012), Compositions and Greenhouse Gas Emission Factors of Flared and Vented Gas in the Western Canadian Sedimentary Basin, Journal of the Air & Waste Management Association 62, 9: 992-1002 <https://bit.ly/3cJRqPd>; Environment Canada (2016), Technical Guidance on Reporting Greenhouse Gas Emissions/Facility Greenhouse Gas Emissions Reporting Program <https://bit.ly/3CVQR5C>; Natural Resources Canada (Undated), Oil Resources <https://bit.ly/3oWWhW0>; U.S. Energy Information Administration (undated), Petroleum and Other Liquids <https://bit.ly/2Ad6S9i>; World Bank (Undated), Global Gas Flaring Data <https://bit.ly/3zXuxGX>.

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Overview

As news reports and interest about the Canadian oil sands continues, it is a good time to evaluate the sector’s progress in reducing carbon dioxide (CO2) emissions intensity.

In this CEC Fact Sheet, we use data on projected direct upstream CO2 emissions intensity drawn from Rystad Energy’s UCube and EmissionsCube to assess trends in the CO2 emissions intensity of Canada’s oil sands sector between 2000 and 2022.

Background on Rystad Energy’s UCube and EmissionsCube

Rystad Energy is an independent energy research company providing data, analytics, and consultancy services to clients around the globe.¹

UCube is Rystad Energy’s global upstream database. It includes production and economics (costs, revenues, and valuations) for more than 85,000 assets covering the portfolios of more than 3,500 companies. Policymakers use the UCube dataset to study all parts of the global exploration and production (E&P) activity value chain, including operational costs, investment (capex and opex), fiscal terms, and net cash flows for projects and companies, both globally and by country (Rystad, 2023b).

Rystad’s EmissionsCube enables the study of CO2e emissions from upstream activity down to the asset level.

Through the EmissionsCube, countries, companies, assets, basins, and fields can be compared with each other on their upstream emissions and emissions intensity. Specifically, EmissionsCube can help policymakers:

• Compare companies in order to understand their emission performance and assess risks.
• Understand the relative ranking of countries, operators, and companies (taking ownership into account) globally, and the changes or initiatives that will improve emission performance.
• Identify the high-emitting parts of an operation and, from that, develop ESG strategies to both meet increasing demands for disclosure and emission reduction goals.
• Assess the impact of emissions on various companies’ competitiveness (Rystad, 2023a).

1. The written content in this report was prepared by the authors at the Canadian Energy Centre (CEC) and does not represent the views of Rystad Energy

Examining oil sands CO2 emissions intensity

This Fact Sheet defines upstream CO2 emissions as those originating from on-site emissions, both extraction and flaring. Extraction includes production drilling; all emissions related to on-site processing; and gathering and boosting.

This Fact Sheet defines CO2 emissions intensity as the amount of CO2 emitted, expressed in kilograms (kg), per barrel of oil equivalent (boe) produced (i.e., kg CO2 per boe produced). A declining CO2 emission intensity figure means that less CO2 is being created per boe produced.

Focusing on emissions per boe produced is a realistic means of establishing a meaningful target for the oil sands industry in Canada.

Average CO2 emissions per oil sands barrel produced in Canada has declined by over 32% since 2000

Canada’s oil sands sector has made considerable progress in reducing its CO2 emissions intensity since 2000.

The overall rate fell from 101.7 kg CO2 per boe produced in 2000 to 68.7 kg CO2 per boe produced in 2022, a decline of 32.4 per cent (see Figure 1).

Source: Derived from the Rystad Energy UCube and EmissionsCube

Average oil sands (mining) CO2 emissions per barrel produced in Canada declines by over 40% since 2000

An examination of upstream oil sands CO2 emissions intensity by type reveals some interesting trends.

The average emissions intensity of oil sands (in-situ) fell from 89.2 kg CO2 per boe produced in 2000 to 72.9 kg CO2 per boe produced in 2022, a decline of 18.3 per cent.

Meanwhile, the average emissions intensity of oil sands (mining) fell from 107.0 kg CO2 per boe produced in 2000 to 63.8 kg CO2 per boe produced in 2022, a decline of 40.4 per cent (see Figure 2).

Source: Derived from the Rystad Energy UCube and EmissionsCube

Notes

This CEC Fact Sheet was compiled by Lennie Kaplan at the Canadian Energy Centre (www.canadianenergycentre.ca). The author and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the original data and research for this Fact Sheet.

References (All links live as of August 28, 2023)

Rystad Energy (2023a). EmissionsCube. Emissions Solution. <https://bit.ly/3eAyIAs>; Rystad Energy (2023b). UCube. Upstream Solution. <https://bit.ly/3JTk2JK>; S&P Global Commodity Insights (2023). Canadian Oil Sands Continue Their Trend of GHG Intensity Reductions in 2022 — Down 23% Since 2009. <https://bit.ly/3sobIeV>.

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Introduction

As one of the world’s largest producers of natural gas, Canada has the potential to capitalize on energy demand in the Asia-Pacific region through the export of liquified natural gas (LNG).

The question arises as to whether Canada’s natural gas production and processing sector is continuing to get cleaner on an CO2e per barrel of oil equivalent basis.

To answer this question, the CEC examined updated Environment and Climate Change Canada (ECCC) historical greenhouse gas (GHG) emissions intensity numbers, expressed as kilograms of CO2 equivalent (CO2e) per barrel of oil, for the Canadian natural gas production and processing sector between 1990 and 2021.

Tracking Canada’s natural gas production and processing sector production and emissions intensity

For measurement purposes, the natural gas production and processing sector is comprised of the following, as per Natural Resources Canada definitions:

The upstream gas industry is made up of several hundred companies that engage in activities such as exploration, drilling, and production of raw natural gas. Some upstream companies also own and operate gathering pipelines and field processing facilities. The midstream natural gas industry operates natural gas processing plants, which remove impurities and natural gas liquids (NGL), natural gas storage facilities, gathering pipelines, and NGL facilities (NRCan, undated).

Canadian natural gas production has gone through several peaks and valleys since 1990, responding to changes in natural gas prices.

Between 1990 and 2000, Canadian natural gas production rose from 683 million barrels of oil equivalent (boe) per year to nearly 1,153 million boe per year, an increase of nearly 69 per cent.

Then, over the next twenty plus years, Canadian natural gas production fell to 1,121 million boe per year, a decline of nearly 3 per cent.

In the decade between 2010 and 2021, Canadian natural gas production was on the rise — from 984 million boe per year to 1,121 million boe per year, an increase of nearly 14 per cent, the result of horizontal drilling and hydraulic fracturing techniques, notably in shale and other tight geologic formations.

Overall Canadian natural gas emissions intensity per barrel down over 8% since 2000 and nearly 30% since 2010

Emissions intensity is the emission rate of a given pollutant relative to the intensity of a specific activity or industrial production process. Emissions intensity is determined by dividing absolute emissions by a unit of output, such as GDP, energy used, population, or, in this case, barrel of oil equivalent produced.

Reducing CO2 emissions intensity means reducing the amount of CO2 emitted per unit of output.

Using ECCC numbers drawn from the 2023 National Inventory Report (NIR), between 2000 and 2021, the CO2 emissions intensity of Canadian natural gas production fell from 48.6 kilograms CO2e per barrel of oil in 2000 to 44.5 kilograms CO2e per barrel of oil in 2021, an overall reduction of over 8 per cent over two decades.

And, between 2010 and 2021, the CO2 emissions intensity of Canadian natural gas production fell from 63.5 kilograms CO2e per barrel of oil to 44.5 kilograms CO2e per barrel of oil, a decline of nearly 30 per cent.

Source: Derived from Environment and Climate Change Canada, 2023a and Environment and Climate Change Canada, 2023b.

According to the Canadian Association of Petroleum Producers, improved emissions management, particularly actions aimed at achieving methane emissions reduction targets and multi-well drilling pad approaches, are key drivers in emissions intensity reduction in the natural gas sector (CAPP, 2021).

Conclusion

Canadian natural gas production and processing continues to get cleaner. Between 2000 and 2021, the GHG emissions intensity of Canadian natural gas production fell from 48.6 kilograms CO2e per barrel of oil to just under 44.5 kilograms CO2e per barrel of oil, an overall reduction over those two decades of over 8 per cent.

And, between 2010 and 2021, the GHG emissions intensity of Canadian natural gas production fell from 63.5 kilograms CO2e per barrel of oil to 44.5 kilograms CO2e per barrel of oil, a decline of nearly 30 per cent.

Notes

This CEC Fact Sheet was compiled by Lennie Kaplan at the Canadian Energy Centre (www.canadianenergycentre.ca). The author and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the original data and research for this Fact Sheet.

References (as of May 1, 2023)

Canadian Association of Petroleum Producers (CAPP), 2020. Canada’s Natural Gas. <https://bit.ly/3Hv3B4O>; Canadian Association of Petroleum Producers (CAPP), 2021. Canada’s Natural Gas and Oil Emission: Ongoing Reductions, Demonstrable Improvement. <https://bit.ly/3k2URH8>; Government of Canada, 2023(a). Calculation of oil and gas emissions intensity. Custom tabulation; Government of Canada, 2023(b). National Inventory Report 1990 – 2021: Greenhouse Gas Sources and Sinks in Canada, 1990 to 2021., Environment and Climate Change Canada. <https://bit.ly/3LupL8C>; Natural Resources Canada (NRCan), undated, Natural Gas Facts. <https://bit.ly/40Skg9o>.

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Introduction

People are interested in the question of whether a barrel of oil produced by the Canadian upstream oil sector is becoming cleaner on an emissions per barrel basis.

To answer this important question, this CEC Fact Sheet examines historical emissions intensity numbers, expressed on a kilograms CO2 equivalent (CO2e) per barrel basis, from Environment and Climate Change Canada (ECCC). We look at Canadian upstream oil sector (defined as the sum of the oil sands subsector and the conventional oil subsector) over time.

Tracking the historical emissions intensity of Canada’s upstream oil sector

Emissions intensity is the emission rate of a given pollutant relative to the intensity of a specific activity or industrial production process. Emissions intensity is determined by dividing the amount of absolute emissions by some unit of output, such as GDP, energy used, population, or barrel of oil produced.

Reducing emissions intensity means reducing the amount of greenhouses gases (GHGs) emitted per unit of output. The aim in focusing on emissions intensity is to retain a meaningful target regardless of shifts across a company’s portfolio.

Overall Canadian oil emissions intensity per barrel down by over 13% since 2000

Using ECCC numbers, drawn from the 2023 National Inventory Report (NIR), between 2000 and 2021, the emissions intensity of the Canadian upstream oil sector fell from 75.1 kilograms CO2e per barrel to 65.2 kilograms CO2e per barrel, an overall reduction of over 13 per cent (see Figure 1).

Blending the oil sands subsector and the conventional oil subsector into a total emission intensity for the Canadian upstream oil sector masks some important trends for the two subsectors.

Oil sands emissions intensity down by over 29% since 2000

Oil sands subsector emissions intensity fell from 125.7 kilograms CO2e per barrel in 1991 to 79.3 kilograms CO2e per barrel in 2021, a decline of nearly 37 per cent.

And, between 2000 and 2021, the emissions intensity of the oil sands subsector fell from 111.8 kilograms CO2e per barrel in 2000 to just under 79.3 kilograms CO2e per barrel in 2021, a decline of over 29 per cent (see Figure 1)

Source: Derived from Government of Canada, 2023(a) and Government of Canada, 2023(b)

Notes: Intensities are based on total subsector emissions and relevant production amounts. They represent overall averages, not facility intensities.

Conventional oil emissions intensity down by over 32% since 2000

Since 2000, the emissions intensity in the conventional oil sector has fallen from 63.2 kilograms CO2e per barrel to 42.9 kilograms CO2e per barrel in 2021, a decrease of over 32 per cent (see Figure 1).

Summing Up: Canada’s upstream oil sector continues to become cleaner on an emissions per barrel basis

Clearly since 2000, the Canadian upstream oil sector is becoming cleaner on an emissions per barrel basis.

As emissions intensity in the Canadian upstream oil sector continues to decline, along with Canada’s highly rated ESG performance, the Canadian barrel of oil has the potential of becoming the barrel of choice on the world stage.

Notes

This CEC Fact Sheet was compiled by Lennie Kaplan at the Canadian Energy Centre (www.canadianenergycentre.ca). The author and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the original data and research for this Fact Sheet.

References (as of May 2, 2023)

Government of Canada, 2023(a). Calculation of oil and gas emissions intensity. Custom tabulation; Government of Canada, 2023(b). 2023 National inventory report: greenhouse gas sources and sinks in Canada, 1990 to 2021. <https://bit.ly/3KKyeUu>.

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Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

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Introduction

The Russian invasion of Ukraine is having an impact on the world’s natural gas markets. Natural gas supply security has become a key concern for governments and industries worldwide.

According to the International Energy Agency (IEA), natural gas is among the world’s fastest-growing energy sources, representing more than 23 per cent of global energy demand ( IEA, 2022). Natural gas is vital to the energy mix in many emerging economies, including countries in the Asia-Pacific region.

Recent forecasts from various sources predict a growing demand for natural gas in the short-term as developing countries move away from coal. In the last few years (2019-2023), the demand for and production of natural gas has fluctuated across regions. World demand for natural gas has increased by two per cent in that time, while world production has increased by just one per cent. Demand for natural gas in the Asia-Pacific region increased by 11 per cent while production in the region increased by only 7 per cent.

As the world’s fifth-largest producer of natural gas, Canada has the potential to capitalize on energy demand in the Asia-Pacific region.

In this CEC Research Brief, we explore North American natural gas price differentials, as well as prices for natural gas in significant Asian trading hubs, including Japan, South Korea, and the average in the region.

Source: Author’s calculations from IEA (2022)

Current Reliance on the United States and Prospects in Asia

In Canada, 98 per cent of natural gas production takes place in Alberta and British Columbia. Alberta’s gas production represented 63 per cent of total Canadian natural gas production in 2020.

All of the natural gas Canada exports is sent to the United States, though such exports have been decreasing in recent years. The emergence of shale gas in Western Canada and the United States has changed international natural gas market dynamics, increasing supply and decreasing prices.¹

In 2021, about 99 per cent of the total natural gas imported by the United States came from Canada, with nearly all transported to the U.S. by pipelines. In 2021, Canada exported 2.78 trillion cubic feet (tcf) to the U.S., down from its peak of 3.78 tcf in 2002. However, the expansion of shale gas production in Canada and the U.S. has also created an opportunity for both countries to supply new markets in Asia.

1. Beyond shale gas being lower cost, many other factors influence natural gas prices including demand and supply, production and exploration, storage and withdrawal, weather, and access to demand markets, such as the Asia-Pacific region.

Source: EIA (2023)

Natural Gas Price Differences Between Canada and the U.S.

Between 1990 and 2021, US Henry Hub and Canadian AECO-C natural gas spot trading prices closely tracked each other. However, short-term price differences can be significant and advantageous to the U.S. (see Figure 3).²

• For example, the prices were closest to each other in 2008 when U.S. natural gas sold for US$8.85 per million British thermal units (mmbtu), just 11 per cent higher than the US$7.99 per mmbtu that Canadian (AECO-C) natural gas fetched that year.
• In contrast, the price gap was widest in 2018 when U.S. natural gas sold for US$3.13 per mmbtu, 179 per cent higher than the US$1.12 per mmbtu average price for AECO-C natural gas that year.
• Between 2019 and 2021, the price gap between US Henry Hub and AECO-C natural gas fluctuated from a high of 98 per cent in 2019 to a low of 26 per cent in 2020. In 2021, U.S. natural gas sold for US$3.84 per mmbtu, 40 per cent higher than the US$2.75 per mmbtu average price for AECO-C natural gas that year.

According to Alberta’s Energy Regulator (AER), many factors cause the observed price differences between AECO-C and Henry Hub natural gas, infrastructure constraints being among the most significant. Other factors include demand and supply, the exchange rate, and transportation costs. The AER estimates that the AECO-C and Henry Hub price differential will increase to US$0.98 per mmbtu by 2031 (AER, undated)

2. According to the EIA, most of the spot price volatility in Canada’s AECO-C trading hub is due to regulatory changes for Western Canada’s pipeline operations.

 Sources: BP Statistical Review of World Energy (2022)

Natural Gas Prices in Asia and Comparisons with Henry Hub and AECO-C

In contrast to the relatively close tracking between U.S. and Canadian natural gas prices over time, the opposite is true when comparing the Canadian with the Asian average price over the years, and in country-specific comparisons with Japan and South Korea.

Natural gas prices skyrocketed worldwide in the last two years, and Asia was no exception. In 2021, the Asian natural gas price was US$18.60 per mmbtu, compared to US$4.40 mmbtu in 2020, an increase of 323 per cent (see Figure 4).

Historically, natural gas prices in Asia on average have been much higher than in Canada. The exceptions were in 2003, when Asian spot prices were just three per cent higher, and in 2005, when they were three per cent lower than in Canada. In most other years, the percentages and prices for natural gas sold in Asia have been significantly higher than in Canada.

For example,

• In 2021, natural gas sold for US$2.80 per mmbtu on the AECO-C trading hub and for US$18.60 per mmbtu in Asia; US$15.88 per mmbtu more, or 564 per cent higher.
• The trend since 2009 has been for Asian natural gas prices to be higher than Canadian natural gas prices by triple percentages, i.e., selling for between 122 and 775 per cent more in Asia than in Canada, depending on the year.

Sources: BP Statistical Review of World Energy (2022) and International Monetary Fund (2023)

Price comparisons between Canada and Japan generally follow the same pattern; since 2009, price differences between Canada and Japan have been substantial (see Figure 5).

• Price divergence between Japan and Canada began to increase in 2006. Every year after 2006, prices for natural gas in Japan were higher, from 22 per cent more (in 2006) to 751 per cent more (in 2018).
• In 2021, the dollar gap between prices in Canada and Japan was US$7.27 per mmbtu; natural gas sold for US$2.80 per mmbtu in Canada and US$10.07 mmbtu in Japan that year, or 260 per cent more.

Sources: BP Statistical Review of World Energy (2022)

In a comparison with South Korea, where data is available only from 2009 onward, prices for natural gas in that country have always been above those in Canada with the difference ranging from US$1.90 per mmbtu in 2009 to US$15.80 per mmbtu in 2021.

Sources: BP Statistical Review of World Energy (2022)

Natural Gas Pricing in Recent Years

Many factors influence global natural gas prices, including supply and demand, production and exploration levels, the location and size of storage facilities, weather patterns, and buyers’ and sellers’ views of future trends.

In the last two years, two factors have had a profound impact on gas prices. First, Russia’s invasion of Ukraine disrupted global gas supplies and resulted in skyrocketing global gas prices. Second, as the world economy opened up after the COVID lockdown, the demand for natural gas in both developed and developing countries increased.

Benchmark oil prices, such as Brent crude or West Texas Intermediate (WTI), are available for global markets. However, there are no comparable significant international benchmark prices for natural gas. Spot prices for natural gas are region-centric. For example, Henry Hub is the benchmark price for North American natural gas. In Alberta, it is AECO-C; in the U.K., it is the National Balancing Point (NBP); in the Netherlands, it is the Title Transfer Facility (TTF); and in the Asian-Pacific LNG market, it is the Japan/Korea Marker (JKM).

The AECO-C is the spot trading price for Alberta gas. The AECO-C hub is Canada’s largest natural gas trading hub, and the AECO-C price serves as a benchmark for Alberta wholesale natural gas transactions.

The AECO-C natural gas price is discounted compared to the benchmark price for natural gas in North America, the Henry Hub price. Henry Hub is the central pricing point for natural gas produced in the United States. The AECO-C and Henry Hub price differential increased in 2022 to more than US$2.00 per mmbtu (see Figure 7).

Source: Derived from the Rystad Energy UCube (2023)

The discount for Canadian natural gas relative to Henry Hub exists partly because Alberta and other western Canadian natural gas fields are further away from U.S. markets than American suppliers, and Canadian transportation costs are thus higher.

This, combined with the fact that the U.S. is currently the only market for Canada’s natural gas (Canada has yet to complete a single LNG export terminal, though one is under construction at Kitimat, British Columbia) means that AECO-C natural gas has traded at a discount of more than US$2.00 per mmbtu in recent years, or about 60 per cent of the Henry Hub price.

However, lower natural gas prices in Western Canada can benefit from upcoming liquefied natural gas (LNG) projects designed to transport natural gas to Asia-Pacific markets because they will reduce an LNG plants’ input costs.

As noted earlier, in recent years, a new benchmark has been developed for LNG in Asia-Pacific markets—the Platts Japan/Korea Marker (JKM)—which is now the benchmark price for LNG deliveries in Japan and Korea. Japan and Korea are among the largest global importers of LNG accounting for 41 per cent of the world’s LNG imports (see Figure 8).

Canada is a late entrant into the LNG market. At one point, 18 LNG projects were proposed. One, LNG Canada, is under construction in B.C. Four additional facilities are proposed in the province: Woodfibre LNG, Tilbury LNG, Cedar LNG and Ksi Lisims LNG.

Given that the demand for LNG in the Asia-Pacific market is currently being filled by traditional players such as Qatar and Australia, the entry of new players, such as Canada, will create a different dynamic in the coming years. The AECO-C benchmark natural gas price is lower than the Asia-Pacific benchmark LNG price, which could mean that buyers in the Asian-Pacific might turn to Canadian LNG for supply, assuming the near- to medium-term completion of LNG projects in Canada.

Source: BP Statistical Review of World Energy (2022)

Canada’s Natural Gas Advantage

Western Canada currently has a cost advantage over other LNG-exporting countries such as the U.S. and Australia.

• This is partly due to lower ambient temperatures in Canada’s western provinces (cooler temperatures help lower liquefaction costs). Specifically, British Columbia’s temperature is cooler than other major LNG-producing regions such as Qatar, Australia, and the U.S. Gulf Coast. British Columbia has an energy efficiency advantage of 34 per cent over Australia, 32 per cent over Qatar, and 26 per cent over the U.S. Gulf Coast for LNG liquefication.
• Qatari LNG is the most competitive from a cost perspective. However, LNG buyers have concerns about becoming overly dependent on one country. Shipping costs to Northeast Asia from Canada are estimated at about 96 cents per mmbtu. In comparison, shipping costs to Northeast Asia from the U.S. Gulf of Mexico are estimated at US$2.22 per mmbtu (see Figure 9). Further, Canada’s West Coast is closer to Japan than Qatar is to Japan; Qatar is 11,773 kilometres from the Japanese port of Himeji and 12,056 kilometres away from the port at Sodegaura. Meanwhile, Canada’s westernmost port (Kitimat) in British Columbia is 7,698 kilometres from Himeji and 7,322 kilometres from Sodegaura.

Source: Wood Mackenzie (2022)

• Canadian LNG going to Northeast Asia is also among the lowest emitting sources of LNG. Canadian LNG has fewer upstream and liquefaction emissions than the average Northeast Asia LNG supplier (see Figure 10).

These distinct advantages of Canadian LNG offer a compelling case for Canadian liquefied natural gas exports to the Asia-Pacific.

Source: Wood Mackenzie (2022)

Conclusion

Comparing the market for natural gas in the form of LNG between Western Canada and the Asia-Pacific shows that the price difference between Canada and Asia provides an opportunity for natural gas produced in Canada to be exported to Asia Pacific markets.

The Russian invasion of Ukraine and the after-effects of the COVID pandemic have rekindled the debate about global energy policies. The world is looking for energy security and every country wants to reduce its dependence on one country for the majority of its energy needs.

The lower liquefaction and shipping costs coupled with the lower cost of the natural gas itself in Western Canada translate into lower LNG prices in Canada. Those advantages will help make Canadian LNG very competitive and attractive to the Asia Pacific market.

The price differentials, along with Canada’s natural advantages, give Western Canada an excellent opportunity to supply natural gas to the Asia-Pacific markets at competitive prices while also bolstering energy security for countries such as Japan and Korea. Canadian LNG could be a strong competitor to the traditional natural gas exporting countries now serving the Asia-Pacific LNG market.

References (All links live as of February 25, 2023)

Alberta Energy Regulator (Undated), Natural Gas Prices, <https://www.aer.ca/providing-information/data-and-reports/statistical-reports/st98/prices-and-capital-expenditure/natural-gas-prices>.

BP (2023), Energy Outlook, 2023 edition, <https://www.bp.com/en/global/corporate/energy-economics/energy-outlook.html>.

BP (2022), Statistical Review of World Energy 2022 (71st edition), <https://www.bp.com/en/global/corporate/energy-economics/statistical-review-of-world-energy.html>.

Canadian Energy Regulator (2017), Market Snapshot: LNG Projects have an Energy Efficiency Advantage Compared to Other LNG Producers in Warmer Locations, Government of Canada, <https://www.cer-rec.gc.ca/en/data-analysis/energy-markets/market-snapshots/2017/market-snapshot-lng-projects-have-energy-efficiency-advantage-compared-other-lng-producers-in-warmer-locations.html>.

Claudio Steuer (2019), Outlook for Competitive LNG Supply, Oxford Institute of Energy Studies, <https://www.oxfordenergy.org/publications/outlook-competitive-lng-supply/>.

International Energy Agency (IEA) (2022), World Energy Outlook 2022 <https://www.iea.org/reports/world-energy-outlook-2022>.

IEA (2022), Gas Market Report Q4-2022, <https://www.iea.org/reports/gas-market-report-q4-2022>

International Monetary Fund (IMF) (2023), Global price of LNG, Asia (PNGASJPUSDM), Retrieved from FRED, Federal Reserve Bank of St. Louis, <https://fred.stlouisfed.org/series/PNGASJPUSDM>.

J. Peter Findlay (2019), Canadian LNG Competitiveness, Oxford Institute of Energy Studies, <https://www.oxfordenergy.org/wpcms/wp-content/uploads/2019/12/Canadian-LNG-Competitiveness-NG-156.pdf>.

Natural Resource Canada (Undated), Energy Facts, Government of Canada, <https://natural-resources.canada.ca/science-and-data/data-and-analysis/energy-data-and-analysis/energy-facts/20061>.

Rystad Energy UCube (2023), Upstream Solution, <https://www.rystadenergy.com/services/upstream-solution>.

U.S. Energy Information Administration (Undated), Natural Gas Imports and Exports, Natural Gas Explained <https://www.eia.gov/energyexplained/natural-gas/imports-and-exports.php>.

Wood Mackenzie (November 2022), The Role of Canadian LNG in Asia, Public Report (November), <https://www.canadianenergycentre.ca/wp-content/uploads/2022/11/WM-CEC-Role-of-Canadian-LNG-in-Asia-Public-Report.pdf>

CEC Research Briefs

Canadian Energy Centre (CEC) Research Briefs are contextual explanations of data as they relate to Canadian energy. They are statistical analyses released periodically to provide context on energy issues for investors, policymakers, and the public. The source of profiled data depends on the specific issue.

About the authors

This CEC Research Brief was compiled by Ven Venkatachalam, Chief Research Analyst, Canadian Energy Centre and Lennie Kaplan, Executive Director of Research, Canadian Energy Centre. The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the data and research for the initial edition of this Research Brief.

Creative Commons Copyright

Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

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Overview

There has a lot of discussion about the role that carbon capture, utilization and storage (CCUS) will play in reducing global greenhouse gas emissions.

In this Canadian Energy Centre (CEC) Fact Sheet, using the Rystad Energy CCUS Solution, we examine projected trends in global and Canadian carbon capture capacity and spending to date between 2023 and 2030.

The written content in this report has been prepared by the CEC and does not represent the views of Rystad Energy.

Background on the Rystad Energy CCUS Solution

The Rystad Energy CCUS Solution provides data covering carbon capture, transportation, and storage for both commercial and pilot projects, including analysis of such key indicators as carbon capture capacity and spending to date on CCUS.

These capabilities allow us to analyze short- and long-term CCUS capacity and spending to date under various global decarbonization scenarios, including net zero (Rystad Energy, 2023).

Potential for CCUS to capture 623 mtpa of CO2 globally through 2030

According to Rystad Energy, at the end of 2022, there were 65 commercial CCUS projects in operation globally capable of capturing nearly 41 million tonnes per annum (mtpa) of CO2 across various industries, including the oil and gas sector.

There are another 478 projects in various stages of development in the global pipeline that will be capable of capturing roughly another 559 mtpa. Some of these projects are currently in various stages of development, including in the feasibility stage, while others are in the concept and construction phases (Rystad Energy, 2023).

Figure 1 breaks down global carbon capture capacity by sector. By 2030, it is estimated that nearly 500 CCUS projects could be operation worldwide, having the ability to capture 623.0 mtpa of CO2, if all projects move ahead as scheduled (see Figure 1).

In fact, between 2023 and 2030, global carbon capture capacity could grow from 43.5 mtpa to 623.0 mtpa, an increase of over 1,332 per cent.

Oil and gas sector global carbon capture capacity will reach over 140 mtpa by 2030

Beyond carbon capture capacity that is still being evaluated, the sectors which are expected to experience the greatest growth between 2023 and 2030 are hydrogen production (5.5 mtpa rising to 98.7 mtpa); gas processing (24.7 mpta rising to 110.0 mtpa); and coal power generation (3.0 mtpa rising to 55.0 mtpa).

Carbon capture capacity in oil refining is anticipated to grow from 1.4 mtpa in 2023 to 30.4 mtpa in 2030, meaning that carbon capture capacity in oil refining and gas processing combined will grow from 26.1 mtpa to 140.4 mtpa (see Figure 1).

Source: Derived from the Rystad Energy CCUS Solution

Global spending on CCUS could reach over $256 billion to date through 2030

Projected spending to date on CCUS is set to expand significantly between 2023 and 2030, increasing from $4.7 billion in 2023 to $37.7 billion in 2030, an increase of about 702 per cent. In fact, cumulative spending to date on CCUS between now and 2030 is projected at over $256 billion (see Figure 2).

About 52 per cent of cumulative CCUS spending to date between 2023 and 2030 (about $133 billion) will go towards the CO2 capture segment. Spending on CO2 capture rises from $2.6 billion in 2023 to $14.4 billion in 2030, an increase of nearly 4,539 per cent (see Figure 2).

Source: Derived from the Rystad Energy CCUS Solution

Transport is the second largest segment of projected CCUS spending between 2023 and 2030, at about 28 per cent of total spending, or $72.5 billion cumulative.

The storage segment will see projected spending of 20 per cent, or $51.0 billion cumulative through 2030 (see Figure 2).

According to Rystad Energy, North America and Europe are expected to continue to dominate the global CCUS market through 2030 (see Figure 3).

Source: Rystad Energy research and analysis, CCUS Market dashboard

Implications for Canada

Global carbon capture capacity and worldwide spending to date trends underline the fact that the future is bright for Canadian investments in CCUS. Assuming that appropriate government policies and regulations are put in place, Canada can expect to see further project announcements and increased investment.

In fact, according to Rystad Energy, “Canada will likely emerge as a CCUS heavyweight given the prevailing policy environment and the existential need for oil sands players to decarbonize. Rystad Energy estimates that Canada alone could account for around 20 per cent of cumulative carbon capture demand between 2023 and 2030” (see Figure 4).

Source: Rystad Energy CCUSCube

Notes

This CEC Fact Sheet was compiled by Lennie Kaplan at the Canadian Energy Centre (www.canadianenergycentre.ca). The author and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the data and research for this Fact Sheet. 

The written content in this report was prepared by the Canadian Energy Centre (CEC) and does not represent the views of Rystad Energy.

References (links live as of March 8, 2023)

Rystad Energy (2023a). CCUS Solution. 2023. <http://bit.ly/3YT5Hlu>; Rystad Energy (2023b). Five key trends to watch in Canada’s upstream oil and gas sector in 2023. <https://bit.ly/3YT5Hlu>.

Creative Commons Copyright

Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

Asia’s demand for liquefied natural gas (LNG) is rising fast as countries look for cleaner alternatives to coal while their economies expand.  

To significantly reduce emissions, the LNG should come from Canada, according to a new report by global research consultancy Wood Mackenzie.  

If Canada increases its LNG export capacity to Asia, net emissions could decline by 188 million tonnes of CO2 equivalent per year – or the annual impact of taking 41 million cars off the road, analysts wrote. 

“It’s like taking all of the cars in Canada away, if we were able to build all of those projects,” said Matthias Bloennigen, Wood Mackenzie’s director of Americas upstream consulting. 

“It reduces emissions globally, so it’s for the good of everyone.” 

To reach global net zero emissions by 2050, the largest reductions will likely need to come from the power sector, analysts wrote.  

The heart of the opportunity is switching from coal-fired to gas-fired power plants, particularly in Asia. 

Natural gas – traded globally as LNG – produces less than half the emissions of coal when used in power generation.  

And it’s a so-called “baseload” reliable fuel that can help offset the intermittency of wind and solar as renewables take on a larger share of the global energy mix, analysts wrote.  

“Gas is also cost-competitive and there are large global reserves in many countries, including Canada,” the report said. 

“If Canada does not export as much LNG as anticipated to northeast Asia, the region would need to rely on LNG from elsewhere that has a higher emissions intensity.” 

If Canada limits its LNG exports to one or two projects, total emissions in northeast Asia would increase by 121 million tonnes of CO2 equivalent through 2050, analysts wrote.  

But if Canada significantly increases LNG capacity to help northeast Asia reduce its reliance on coal, net emissions would decline by 5,459 mtCO2e over the same period.  

“LNG from Canada going into northeast Asia has lower emissions than LNG coming from many other global LNG exporters,” the report said.  

LNG from western Canada has average life cycle emissions intensity 12 kgCO2e/mmbtu, compared to 21 kgCO2e/mmbtu for projects in the United States.  

“With its high environmental standards and stewardship, Canada would be a great partner to fill the LNG demand gap in Asia,” Wood Mackenzie analysts wrote.  

The unaltered reproduction of this content is free of charge with attribution to Canadian Energy Centre Ltd. 

To sign up to receive the latest Canadian Energy Centre research to your inbox email: research@canadianenergycentre.ca

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Overview: Environmental spending in Canada

This Fact Sheet details spending on environmental protection by Canada’s oil and gas sector, other industries, and provincial governments. The comparisons are made using the most recent data from Statistics Canada. For provincial government spending, data are available from 2008 to 2020 on an annual basis.¹

As the data make clear, Canada’s oil and gas sector spent the most of any industry in the country on environmental protection—$6.6 billion during 2018 and 2019, accounting for 34 per cent of total environmental protection expenditures made by business across Canada in those years.

As for governments, Alberta spent $21.4 billion on environmental protection between 2008 and 2020. Measured per capita, Alberta’s spending on environmental protection was higher than the average of the other nine provinces every year, regardless of the party in power. For example, in 2020, the most recent year for which data are available, Alberta spent $327 per capita on environmental protection—112 per cent of the nine-province average of $293 per capita.

Comparison One: Environmental protection spending by industry

Figures 1 and 2 show that Canadian business spent $18.6 billion on environmental protection in 2018 and 2019.

• For total spending, i.e., when capital and operating expenses on environmental protection are combined, out of the $18.6 billion spent between 2018 and 2019:

º Over the two years 2018 and 2019, the oil and gas sector spent $6.6 billion or 34 per cent of the total over both years, while all other industries combined spent $11.9 billion or 64 per cent of the total during both 2018 and 2019 (see Figure 1).

1. Statistics Canada surveys companies only every second year, i.e., 2006, 2008, and so forth. This leads to an underestimate of environmental spending by companies, possibly by as much as 50 per cent, given that data for every second year is absent.

Source: Statistics Canada, Table 38-10-0130-01.

º In 2019, the oil and gas sector spent $3 billion in environmental protection expenditure, which constituted 34 per cent of all Canadian business environmental spending that year (See Figure 2).

º Those other major industries include mining and quarrying and primary metal manufacturing (each about $1.7 billion), electric power generation, transmission and distribution ($1.3 billion) and chemical manufacturing ($0.9 billion).

Historically, the oil and gas sector has spent a significant amount on environmental protection. Businesses in Canada spent $67.7 billion in total between 2006 and 2018 on capital and operating expenses on environmental protection. In that same period, the oil and gas sector alone spent $28.1 billion or 41 per cent on environmental protection, while all other industries combined spent $39.6 billion or 59 per cent.

Source: Statistics Canada, Table 38-10-0130-01.

Breakdowns by capital and operating

• Capital expenditure.² In 2018, the oil and gas sector was responsible for 41 per cent ($1.5 billion) of all capital spending on environmental protection compared with 59 per cent for all other industries ($2.2 billion). In 2019, the oil and gas sector spent $1.8 billion, accounting for 48 per cent of the all the industry spending on environmental protection (see Table 1); and
• Operating expenses.³ In 2018, the oil and gas sector was responsible for 34 per cent ($2 billion) of all operating expenditures for environmental protection compared with 66 per cent for all other industries combined ($3.8
  billion).

From 2006 to 2018, the oil and gas sector was responsible for 51 per cent ($15.2 billion) of all capital spending for environmental protection compared with 49 per cent for all other industries ($14.7 billion). Meanwhile, in that period the oil and gas sector was responsible for 34 per cent ($12.9 billion) of all operating expenditures for environmental protection compared with 66 per cent for all other industries ($24.9 billion).

2. Capital expenditure includes outlays on machinery and equipment and for the construction of non-residential facilities, among other expenditures.
3. Operating expenses include expenses incurred for labour, materials and supplies, and maintenance and repair, among others.

Source: Statistics Canada, Table 38-10-0130-01.

Comparison Two: Environmental spending by the provinces, 2008-2020

Not only industries but governments spend money on environmental protection. Table 2 shows that total provincial government spending on environmental protection between 2008 and 2020 was nearly $128.8 billion. (The federal government and the territories are excluded from this comparison.) Alberta spent $21.4 billion or 16.6 per cent of all provincial expenditures on the environment, while its proportion of the (10-province) population was 11.7 per cent as of 2020.

• Ontario spent $51.5 billion or 40 per cent of all provincial expenditures, while its proportion of the population was 38.9 per cent as of 2020.
• Nova Scotia and Saskatchewan also spent a higher proportion on the environment relative to their populations.
• Six provinces spent less on the environment than their share of the population: Quebec, British Columbia, Manitoba, New Brunswick, and Newfoundland & Labrador. Quebec’s government incurred just 18.6 per cent of all provincial environmental expenditures between 2008 and 2020, significantly below its 22.6 per cent share of the province’s population in 2020.

Source: Statistics Canada, Tables 10-10-0005-01 and 17-10-0005-01; and authors’ calculations

A per capita look at provincial spending on the environment

Table 3 lists all provincial spending on environmental protection between 2008 and 2020 inclusive.

Of note:

• Alberta spent more per capita on environmental protection than any other province in 2020, except for Manitoba and Prince Edward Island.
• When the annual average of the other nine provinces is compared, Alberta spent substantially more than the annual average of the other provinces on environmental protection every year.

Source: Statistics Canada, Tables 10-10-0005-01 and 17-10-0005-01.

Table 3 and Figure 3 also show the following:

• In 2020, Alberta’s spending on the environment at $327 per capita was 102 per cent of the amount spent by Ontario ($320); 105 per cent of that spent by British Columbia ($310); 112 per cent of the nine-province average ($293); and 127 per cent of what Quebec spent ($257).⁴

4. The spike in environmental spending in Alberta in 2016 was due to $1.1 billion in new spending from the province’s Climate Leadership Plan (Statistics Canada 2018.)

Source: Statistics Canada, Tables 10-10-0005-01 and 17-10-0005-01; and authors’ calculations.

Conclusion: Environmental spending highest by oil and gas industry, and highest by Alberta

In 2018 and 2019, the oil and gas sector spent $6.6 billion, or 34 per cent, of the amount spent by businesses on environmental protection.

Historically, when measured as a proportion of the $67.6 billion in all-industry spending on environmental protection between 2006 and 2018, not including years where there were “gaps” in Statistics Canada data, Canada’s oil and gas sector spent $28.1 billion, or 41 per cent. All other industries in Canada were responsible for $39.6 billion or 59 per cent of such spending.

When provincial government spending is examined using data available from 2008 to 2020, Alberta spent significantly more than its share of Canada’s population ($21.4 billion or 16.6 per cent of all provincial spending with a population at 11.7 per cent of provincial totals). This is also true of per capita spending: Alberta’s spending on environmental protection was significantly higher than the average of the other nine provinces for the entire 2008- 2020 period.

Notes

This CEC Fact Sheet was compiled by Ven Venkatachalam and Lennie Kaplan at the Canadian Energy Centre: www.canadianenergycentre.ca. The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the data and research for this Fact Sheet. All percentages in this report are calculated from the original data, which can run to multiple decimal points. They are not calculated using the rounded figures that may appear in charts and in the text, which are more reader friendly. Thus, calculations made from the rounded figures (and not the more precise source data) will differ from the more statistically precise percentages we arrive at using source data.

References (all links live as of Sept 5, 2022)

Statistics Canada (2022), Table 38-10-0130-01 <https://bit.ly/3OERIKi>; Table 10-10-0005-01 <https://bit.ly/2ZEkp2W>; and Table 17-10-0005-01 <https://bit.ly/3d03wV5>; Statistics Canada (2018), Government Expenditures in Alberta: A presentation to deputy ministers in Alberta by Anil Arora (February 12) <https://bit.ly/3svYAyP>; Statistics Canada (2020), Table 38-10-0042-01 <https://bit.ly/2Y65iQi>.

Creative Commons Copyright

Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

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Overview

There has been considerable discussion about Canadian upstream oil and gas CO2 emissions intensity but little attempt to benchmark intensity versus other peer oil and as producing countries. This is a crucial element towards evaluating the Canadian upstream oil and gas sector emissions intensity performance.

In this CEC Fact Sheet, we use custom data obtained from the Rystad Energy EmissionsCube to compare the average CO2 emissions intensity of the Canadian upstream oil and gas industry versus 29 other peer countries between 2010 and 2020.

The views expressed in this Fact Sheet do not represent those of Rystad Energy.

Background on the Rystad Energy EmissionsCube

Rystad Energy is an independent energy research company providing data, analytics, and consultancy services to clients around the globe.

Rystad’s EmissionsCube enables the study of CO2 emissions from upstream activity down to the asset level. Through the EmissionsCube, countries, companies, assets, basins and fields can be benchmarked when it comes to upstream emissions and emissions intensity.

Benchmarking CO2 emissions intensity

Upstream activities include exploration, drilling, and extraction. Upstream oil and gas CO2 emissions are defined as those originating from oil and gas combustion, which includes both extraction and flaring emissions.

CO2 emissions intensity is defined in this Fact Sheet as the amount of CO2 emitted (expressed in kilograms) per barrel of oil equivalent (boe) produced (i.e., kg CO2 per boe produced). A declining CO2 emission intensity figure means that less CO2 is being created per boe produced.

Focusing on emissions per boe produced is a realistic means of establishing a meaningful target for the upstream oil and gas industry in Canada. And benchmarking emissions intensity of the Canadian upstream oil and gas sector versus peer countries is a valuable tool for valuating and comparing performance over time.

Canadian average upstream oil and gas (including oil sands) CO2 emissions intensity remains steady over the past decade

Among the 30 major oil and gas producing countries examined, in 2020, the Canadian upstream oil and gas sector recorded a CO2 emissions intensity of 33 kg per boe produced.

Canada was closely followed by Thailand (32 kg per boe produced), Indonesia (31 kg per boe produced), Argentina (31 kg per boe produced), India (29 kg per boe produced), Algeria (28 kg per boe produced), Nigeria (27 kg per boe produced), Iraq (27 kg per boe produced), Oman (27 kg per boe produced), and Mexico (27 kg per boe produced). Meanwhile, Australia had an emissions intensity of 13 kg per boe produced, while the United States was at 14 kg per boe produced, both lower than Canada (see Figure 1).

Canada’s high CO2 emissions intensity among its peers is the result of a significant share of its upstream oil and gas production (an estimated 35 per cent in 2020) coming from the energy-intensive oil sands sector. Canada’s oil and gas production, with its high oil sands content, is therefore unique among peer countries. As we shall see, Canada’s oil sands sector has made considerable progress in reducing its CO2 emissions intensity over the past decade.

A key measure for benchmarking countries on upstream oil and gas emissions intensity is to focus on the rate of change, on a historical basis, in this case between 2010 and 2020. The rate of change measure tracks country performance in lowering emissions per boe produced over time.

During the period between 2010 and 2020, Canadian upstream oil and gas (including oil sands) kg CO2 emissions per boe produced increased by just 3 per cent. At the same time, Canadian upstream oil and gas production increased by 41 per cent, according to Rystad Energy data.

Source: Derived from Rystad Energy EmissionsCube

Canada’s rate of change in average upstream oil and gas kg CO2 per boe produced at 3 per cent was better than a number of peer countries, including Algeria (32 per cent), Angola (11 per cent), India (37 per cent), Iran (16 per cent), Iraq (16 per cent), Mexico (84 per cent), Oman (8 per cent), Russia (11 per cent), and the United Kingdom (5 per cent).

Peer countries that performed better than Canada on the rate of change in average upstream oil and gas kg CO2 per boe produced, included the United States (-26 per cent), Brazil (-17 per cent), Kazakhstan (-27 per cent), Kuwait (-8 per cent), Australia (-7 per cent), Saudi Arabia (-1 per cent), Turkmenistan (-15 per cent) and Norway (-0.4 per cent) (see Figure 2).

Source: Derived from Rystad Energy EmissionsCube

Canadian average upstream oil and gas (not including oil sands) CO2 emissions per barrel produced declined by nearly 12 per cent over the past decade

When we separate out the oil sands sub-sector and look at average upstream oil and gas emissions intensity performance, Canada’s CO2 emissions intensity was just 13 kg per boe produced in 2020.

This is lower than many peer countries, including Indonesia (31 kg per boe produced), Algeria (27 kg per boe produced), India (29 kg per boe produced), Nigeria (27 kg per boe produced), Mexico (27 kg per boe produced), Oman (27 kg per boe produced), the United Kingdom (22 kg per boe produced), and Iran (19 kg per boe produced). The United States was at 14 kg CO2 of boe produced, while Australia was at 13 kg CO2 per boe produced, better than Canada (see Figure 3).

Source: Derived from Rystad Energy EmissionsCube

When we focus on the rate of change during the same period, Canadian upstream oil and gas (not including oil sands) kg CO2 emissions per boe produced fell by nearly 12 per cent between 2010 and 2020, the six highest decline among 29 other peer countries, behind only the United States (-26 per cent), Kazakhstan (-26 per cent), Brazil (-17 per cent), Qatar (-13 per cent), and Turkmenistan (-15 per cent).

Canada at (-12 per cent) is followed by Australia (-7 per cent), Kuwait (-8 per cent), Malaysia (-4 per cent), Saudi Arabia (-1 per cent), and Norway (-0.4 per cent), among others.

Those countries whose rate of change in upstream oil and gas (not including oil sands) kg CO2 per boe increased between 2010 and 2020, including Algeria (32 per cent), Angola (11 per cent), India (37 per cent ), Indonesia (8 per cent), Iran (16 per cent), Iraq (16 per cent), Mexico (84 per cent), Nigeria (2 per cent), Oman (8 per cent), Russia (10 per cent), and the UAE (3 per cent) (see Figure 4).

Source: Derived from Rystad Energy EmissionsCube

Canadian average oil sands CO2 emissions per barrel produced declined by over 21 per cent over the past decade

Canada’s oil sands sector has made considerable progress in reducing its CO2 emissions intensity over the past decade, falling to 71 kg CO2 per boe produced (see Figure 5).

Source: Derived from Rystad Energy EmissionsCube

In fact, between 2010 and 2020, kg CO2 per boe fell by over 21 per cent, a significant improvement in performance (see Figure 6). At the same time, Canadian oil sands production increased by 114 per cent, according to Rystad Energy data.

As noted earlier, during the period between 2010 and 2020, Canadian upstream oil and gas (including oil sands) kg CO2 emissions per boe produced increased by just 3 per cent. At the same time, Canadian upstream oil and gas production increased by 41 per cent, according to Rystad Energy data (Figure 6).

Source: Derived from Rystad Energy EmissionsCube

Conclusion

The Canadian upstream oil and natural gas sector is making steady progress versus many peer countries on its CO2 emissions per boe produced.

Between 2010 and 2020, Canadian upstream oil and gas CO2 emissions intensity, expressed as kg CO2 per boe produced, remained relatively steady in a band between 32 to 34 kgCO2 per boe produced, settling in at 33 kgCO2 per boe produced in 2020. In fact, average upstream oil and gas emissions intensity rose by just 3 per cent over the past decade, a much better performance than a number of other peer countries. At the same time, Canadian upstream oil and gas production increased by 41 per cent, according to Rystad Energy data.

The Canadian upstream oil and gas emissions intensity is influenced by higher levels of emissions intensity found in the sands sector. When the oil sands is separated out, the emissions intensity of the Canadian upstream oil and gas sector falls to just 13 kg CO2 per boe produced, lower than many peer countries. And average upstream oil and gas (not including oil sands) fell by nearly 12 per cent over the past decade, the six highest rate of decline among 30 peer countries.

Canada’s upstream oil sands sector is making considerable process in reducing its emissions intensity. According to Rystad data between 2010 and 2020, Canadian average oil sands CO2 emissions per boe produced declined by over 21 per cent in the past decade, while production increased by 114 per cent.

Notes

This CEC Fact Sheet was compiled by Lennie Kaplan at the Canadian Energy Centre (www.canadianenergycentre.ca). The author and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the original data and research for this Fact Sheet.

References (as of September 20, 2022)

Rystad Energy, August and September 2022. EmissionsCube. <https://bit.ly/3eAyIAs>.

Creative Commons Copyright

Research and data from the Canadian Energy Centre (CEC) is available for public usage under creative commons copyright terms with attribution to the CEC. Attribution and specific restrictions on usage including non-commercial use only and no changes to material should follow guidelines enunciated by Creative Commons here: Attribution-NonCommercial-NoDerivs CC BY-NC-ND.

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Overview

This Fact Sheet analyzes the upstream oil and gas industry record on flaring and venting of gases in Canada relative to other countries. Flaring and venting, while technical in nature, is relevant because both are a source of greenhouse gas emissions (GHGs). For example, in 2021, 143,504 million m3 of flared gases were emitted worldwide, or 382.6 million tonnes of CO2 emissions. Canada is a major producer of oil and natural gas with the third-largest proven reserves of crude oil, the 17th largest reserves of natural gas, and is the fourth-largest producer of both commodities (Natural Resources Canada, Undated), and so contributes to flaring and venting.

Background

Flaring and venting are two ways in which an oil or natural gas producer can dispose of waste gases. Venting is the intentional controlled release of un-combusted gases directly to the atmosphere, and flaring is a disposal by combustion of natural gas or gas derived from petroleum.¹ As Matthew R. Johnson and Adam R. Coderre noted in their 2012 paper on the subject, flaring in the petroleum industry generally falls within three broad categories:

• Emergency flaring (large, unplanned, and very shortduration releases, typically at larger downstream facilities or off-shore platforms);
• Process flaring (intermittent large or small releases that may last for a few hours or a few days, as occurs in the upstream industry during well-test flaring to assess the size of a reservoir or at a downstream plant during a planned process blowdown); and
• Production flaring (which may occur continuously for years as the resource is being produced).

To track GHGs from flaring and venting, Environment Canada (2016) defines such emissions as:

• Fugitive emissions: Releases from venting, flaring, or leakage of gases from fossil fuel production and processing; iron and steel coke oven batteries; CO2 capture, transport, injection, and storage infrastructure.
• Flaring emissions: Controlled releases of gases from industrial activities from the combustion of a gas or liquid stream produced at a facility, the purpose of which is not to produce useful heat or work. This includes releases from waste petroleum incineration, hazardous emission prevention systems (in pilot or active mode), well testing, natural gas gathering systems, natural gas processing plant operations, crude oil production, pipeline operations, petroleum refining, chemical fertilizer production, and steel production.
• Venting emissions: Controlled releases of a process or waste gas, including releases of CO2 associated with carbon capture, transport, injection, and storage; from hydrogen production associated with fossil fuel production and processing; of casing gas; of gases associated with a liquid or a solution gas; of treater, stabilizer or dehydrator off-gas; of blanket gases; from pneumatic devices that use natural gas as a driver; from compressor start-ups, pipelines, and other blowdowns; and from metering and regulation station control loops.

1. Many provinces regulate flaring and venting including Alberta (Directive 060) British Columbia (Flaring and Venting Reduction Guideline), and Saskatchewan (S-10 and S-20). Newfoundland & Labrador also has regulations that govern offshore flaring.

Flaring comparisons

This Fact Sheet uses World Bank data to provide international comparisons of flaring only (given the limited international data on venting). It also draws on Enerdata data to compare flaring in major petroleum- and other liquid-producing countries. Table 1 shows gas flaring volumes in 2014 and 2021. In absolute terms, Russia recorded more flaring than any other country at 25,409 million m3 in 2021, 7,000 million m3, or 39 per cent higher, than in 2014. The four countries that were the top GHG emitters through flaring (Russia, Iraq, the U.S., and Iran) accounted for 48.3 per cent of global gas flaring in 2021.

At 1,077 million m3, Canada was the seventh lowest flarer in 2021 (in 24th spot out of top 30 countries). It recorded a decrease in flaring emissions of 986 million m3 from the 2014 level of 2,063 million m3, a 48 per cent drop. In 2021 Canada’s share of global gas flaring was just 0.8 per cent, despite it being the world’s fourth largest producer of oil and natural gas (see Table 1).

Source: World Bank (Undated) and Enerdata (2022).

More flaring worldwide in 2021 than in 2014

Figure 1 shows the change in flaring volumes between 2014 and 2021. In total, 19 countries flared more in 2021 than they did in 2014, while 11 countries flared less.

• The five countries that showed the greatest increase in flaring between 2014 and 2021 were Syria (168%) Libya (107%), Argentina (68%), Iran (42%), and Russia (39%).
• The five countries that showed the greatest decrease in flaring between 2014 and 2021 were Kazakhstan (-62%), Canada (-48%), Angola (-48%), Indonesia (-45%), and Turkmenistan, Brazil, and Malaysia (each -41%).

Source: World Bank (Undated).

Comparing flaring to increased production

The decreases in flaring for Canada shown in Table 1 and Figure 1 understate the magnitude of the decline in flaring in the country between 2014 and 2021. That is because Canada’s production of crude oil increased by 9 per cent and natural gas production rose by 16 per cent in that period, all the while decreasing flaring by 48 per cent (see Table 2).

Canada compares very favourably with the United States, which, over the same period, decreased crude oil production by 12 per cent, increased gas production by 33 per cent, and decreased flaring by 23 per cent.

Source: World Bank (Undated) and Enerdata (2022).

To fully grasp how much more efficient Canada has been in reducing flaring, Figure 2 compares both flaring and production for crude oil only. In Canada, gas flaring intensity (gas flared per barrel of oil produced) declined by 58 per cent between 2014 and 2021. Venezuela, which produces heavy crude oil similar to Canada’s, saw flaring increase by 250 per cent (see Figure 2). Only Kazakhstan, which recorded a per-barrel reduction in flaring of 65 per cent between 2014 and 2021, showed a decline steeper than Canada’s 58 per cent reduction.

Source: World Bank (Undated)

Conclusion

Global gas flaring and venting contribute to greenhouse gas emissions. But it is possible for countries to both increase their oil and gas production and still reduce flaring and venting. Canada is one noteworthy example of a country that has significantly reduced flaring not only compared to its increased production volumes of petroleum and other liquids, but also in absolute terms.

Notes

This CEC Fact Sheet was compiled by Ven Venkatachalam and Lennie Kaplan at the Canadian Energy Centre: www.canadianenergycentre.ca. All percentages in this report are calculated from the original data, which can run to multiple decimal points. They are not calculated using the rounded figures that may appear in charts and in the text, which are more reader friendly. Thus, calculations made from the rounded figures (and not the more precise source data) will differ from the more statistically precise percentages we arrive at using source data. The authors and the Canadian Energy Centre would like to thank and acknowledge the assistance of two anonymous reviewers in reviewing the data and research for this Fact Sheet.

References (all links live as of Sept 5, 2022)

Alberta Energy Regulator (2022), Directive 060: Upstream Petroleum Industry Faring, Incinerating, and Venting <https://bit.ly/3AMYett>; BC Oil and Gas Commission (2021), Flaring and Venting Reduction Guideline, version 5.2 <https://bit.ly/3CWRa0i>; Canada-Newfoundland and Labrador Offshore Petroleum Board (2007), Offshore Newfoundland and Labrador Gas Flaring Reduction <https://bit.ly/3RhKpKu>; D&I Services (2010), Saskatchewan Energy and Resources: S-10 and S-20 <https://bit.ly/3TBrVGJ>; Enerdata (2022), Global Energy and CO2 database <https://bit.ly/2QDPgJT>; Johnson, Matthew R., and Adam R. Coderre (2012), Compositions and Greenhouse Gas Emission Factors of Flared and Vented Gas in the Western Canadian Sedimentary Basin, Journal of the Air & Waste Management Association 62, 9: 992-1002 <https://bit.ly/3cJRqPd>; Environment Canada (2016), Technical Guidance on Reporting Greenhouse Gas Emissions/ Facility Greenhouse Gas Emissions Reporting Program <https://bit.ly/3CVQR5C>; Natural Resources Canada (Undated), Oil Resources <https://bit.ly/3oWWhW0>; World Bank (Undated), Global Gas Flaring Data <https://bit.ly/3zXuxGX>.

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