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Last Updated: October 8, 2019
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Overview

  • Canada is one of the world’s top energy producers and is a principal source of U.S. energy imports.

  • Canada is a net exporter of most energy commodities and is a significant producer of natural gas, hydroelectricity, and crude oil and other liquids from oil sands. Energy exports to the United States account for most of Canada’s total energy exports.
  • Canada has abundant and varied natural resources, ranking fourth in 2018 among the top energy producers of petroleum and total liquids in the world, behind only the United States, Saudi Arabia, and Russia. Relatively energy intensive compared with other industrialized countries, Canada’s economy is fueled largely by petroleum and other liquids, natural gas, and hydroelectricity (Figure 1).

Figure 1. Total primary energy consumption in Canada by fuel type, 2018

# figure data


Petroleum and other liquids

Canada’s oil sands have significantly contributed to the recent and expected future growth in the world’s liquid fuel supply, and they comprise most of the country’s proved oil reserves, which rank third globally.

Reserves
  • The Oil & Gas Journal estimates that as of January 2019, Canada had 167 billion barrels of proved oil reserves, ranking third in the world.[1] Only Venezuela and Saudi Arabia hold higher reserves. In addition, Canada is one of only 3 countries among the top 10 proved reserves holders that is not a member of the Organization of the Petroleum Exporting Countries (OPEC).
Production and consumption
  • In 2018, Canada was the world’s fourth-largest petroleum and other liquids producer and was a net exporter of oil. Nearly all of its crude oil exports are destined for the United States because Canada lacks sufficient export capacity to send its liquids elsewhere.
  • Canada is a major producer of crude oil. Bitumen and upgraded synthetic crude oil produced from the oil sands of Alberta have driven recent growth in Canada’s liquid fuels production. Most of Canada’s proved oil reserves and the expected future growth in the country’s liquid fuels production will be derived from these resources.
  • Canada produced 5.3 million barrels per day (b/d) of petroleum and other liquid fuels in 2018, an increase of more than 300,000 b/d from the previous year. Crude oil (including condensate) accounted for 4.3 million b/d, and the remainder was produced as biofuels, natural gas, and other natural gas liquids (NGL) (Figure 2). Canada’s production is expected to grow modestly in 2019 and 2020 because of export capacity constraints and mandatory production curtailments set by the government of Alberta.

Figure 2. Canada liquid fuels production and consumption

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Refining
  • According to the Canadian Association for Petroleum Producers (CAPP), Canada has 17 refineries with a total crude oil processing capacity of 2.0 million b/d.[2] Eastern Canada’s eight refineries have 1.2 million b/d of capacity or about 60% of total crude oil refining capacity.[3] Because the eastern refineries are not as well connected to domestic crude oil production supplies, these refineries are more dependent on imported crude oil. Western Canada’s nine refineries have a total capacity of 748,000 b/d. In 2018, Phase One of the North West Redwater’s Sturgeon Refinery came online, which is the first refinery built in Canada since 1984.[4]
  • According to Natural Resources Canada, Canadian production of petroleum products reached 1.9 million b/d in 2018.[5] Most petroleum products are refined into motor gasoline (42%) and diesel fuel oil (30%).[6]
Exports and imports
  • Nearly all of Canada’s crude oil exports were sent to the United States in 2018 (see Figure 3). Currently, the largest regional market in the United States for Canadian crude oil exports is the Midwest where almost all Canadian crude oil exports originate from Western Canada.
  • Canada is the largest source of U.S. crude oil and refined products imports. Crude oil imports from Canada accounted for 48% of total U.S. crude oil imports in 2018, averaging 3.7 million b/d. Refined products imported from Canada accounted for 582,000 b/d, or 27% of total U.S. petroleum product imports.
  • Currently, producers face a complex set of market and logistical challenges. Oil supply in Western Canada exceeds the transport capacity of pipelines serving external markets. As export pipelines operate at full capacity and timing of new capacity remains uncertain, producers are increasingly relying on rail transportation to deliver incremental production to the market. The highest monthly volume imported to the United States from Canada was in January 2019 at 406,000 b/d, compared with a total average of 238,000 b/d in 2018.

Figure 3. Canada crude oil exports by destination, 2018

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Natural gas

Canada is one of the world’s largest producers of dry natural gas and is the source of most U.S. natural gas imports.

Reserves
  • The Oil & Gas Journal,[7] Canada held 72 trillion cubic feet (Tcf) of proved natural gas reserves at the end of 2018. Most of Canada’s natural gas reserves are traditional resources in the Western Canadian Sedimentary Basin (WCSB), including those associated with the region’s oil fields. Other areas with significant natural gas reserves include offshore fields near the eastern shore of Canada (primarily Newfoundland and Nova Scotia), the Arctic region, and the Pacific coast.
Production and consumption
  • In 2018, Canada produced 5.9 Tcf of dry natural gas and was the fourth-largest producer behind the United States, Russia, and Iran (see Figure 4). Most of Canada’s natural gas production occurs in the prolific WCSB. Although Canadian production of conventional natural gas has been declining, the production of Canadian unconventional natural gas has been rising.
Exports
  • Almost all of Canada’s natural gas exports go to the United States. In 2018, 97% of all U.S. natural gas imports came from Canada. Most of Canada’s natural gas exports to the United States originate in Western Canada and are shipped to U.S. markets in the West and Midwest regions.

Figure 4. Canada's dry natural gas production and consumption

# figure data


Electricity
  • Canada generated an estimated 651 billion kilowatthours (kWh) of electricity in 2017, of which about 60% was hydroelectric. Only China and Brazil produce more hydroelectricity than Canada.[8] Fossil fuel and nuclear plants satisfy most of Canada’s electricity needs not met by hydroelectricity (see Figure 5).
Trade
  • The United States imported 52 million megawatthours (MWh) of electricity from Canada in 2018, primarily into the Northeast and Midwest, and exported 73 million MWh, nearly all of which was from the Pacific Northwest. Canada is a net exporter of electricity to the United States, which accounts for a small, although locally important, share of bilateral trade.

Figure 5. Electricity generation by fuel, 2018

# figure data


Coal

As government policy attempts to lower domestic coal consumption, up to 50% of Canada’s coal production is exported.

Reserves
  • Canada’s total proved coal reserves stood at about 6.6 billion short tons in 2018.[9] More than 60% of the reserves are anthracite and bituminous coal. The remaining reserves are subbituminous and lignite coal.[10] Coal resources are located across the country, but they are actively mined and produced in only Alberta, British Columbia, and Saskatchewan.
Production and consumption
  • In 2017, Canada produced 68 million short tons of coal, a slight increase compared with the previous year. About 50% of Canada’s coal production is consumed domestically, a significant departure from more than a decade ago when Canada consumed nearly all of its domestic coal production.
  • In 2018, 49% of coal consumed in Canada was metallurgical coal used for steel manufacturing, and 51% was thermal coal used for electricity generation. Coal generates 9% of total electricity in Canada. In 2018, the government of Canada announced regulations to phase out traditional coal-fired electricity by 2030.[11]
Trade
  • Canada exports about half of its coal production. In 2018, Canada was the world's third-largest exporter of metallurgical coal after Australia and the United States. [12] Most of Canada's coal exports go to Asia.

Canada EIA petroleum Reserves production consumption refining exports imports natural gas electricity coal
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M & A in the US Shale Patch

It is only 5 months into 2021, and already Bloomberg estimates that merger and acquisition (M&A) activity in the US shale patch has more than doubled over the equivalent period in 2020 to over US$10 billion. Given that Covid lockdowns sapped energy from shale drilling from March 2020 and what was left was decimated again in April 2020 when US WTI prices (briefly) collapsed into negative territory. From this point onwards, it may not take much to maintain this doubling of M&A activity in the US shale patch over the next 7 months. But don’t call this a new trend; call it what it is: the inexorable centralisation of US shale as the long freewheeling Wild West years give way to corporate consolidation.

Even before Covid had been unleashed upon an unsuspecting world, this consolidation was already in full swing. When the US shale revolution first began accelerating in the early 2010s – when crude oil prices were high and acreage was cheap – there were thousands, maybe even tens of thousands, of small independent drillers vying alongside medium and large upstreamers busy striking riches across American shale basins such as Bakken, Eagle Ford, Marcellus and, of course, the Permian. But too many cooks spoiled the soup. The US shale drillers who were acting capitalistically without concern for discipline incurred the wrath of OPEC and caused the oil price bust in 2014/2015. For larger players were deep pockets and wide portfolios, the shock could be absorbed. But for the small, single field or basin players, it was bankruptcy staring them in the face. The sharp natural productivity dropoff of shale fields after initial explosive output meant profits had to be made super quick and super fast; if debt kept mounting up, then drillers must keep pumping to merely stay alive. But there is another option: merge or acquire. And so those thousands of players started dwindling down to hundreds.

But it wasn’t enough. Even though crude prices began to recover from 2016, it never again reached the dizzying levels of the boom years. Debt accumulated turned into debt to be repaid. And the financial community got wiser. Instead of being blinded by the promise of shale volumes, investors and shareholders started demanding value and dividends. Easy capital was no longer available to a small shale driller. And because of that no new small shale drillers emerged. Instead, the big boys arrived. Because shale oil and gas still held vast potential, the likes of ExxonMobil, Shell and Chevron started moving in. ExxonMobil went as far as calling the Permian its ‘future’ (though this was in the days before its super discoveries in Guyana were announced). With consolidation came cohesion. Instead of a complicated patchwork of small plots, a US shale operator’s modus operandi was now to look to its left or right for land that someone else owned which could be stitched up into its own acreage forming a contiguous asset. And so those hundreds of players started becoming dozens.

In late 2020, this drive ratcheted up as the prolonged Covid-caused fuels depression freed up plenty of candidates for deep-pocketed players. ConocoPhillips bought Concho Resources for US$9.7 billion. Pioneer Natural Resources snapped up Parsley Energy for US$4.5 billion. Chevron closed its US$5 billion acquisition of Noble Energy (after failing to acquire Anadarko after being outbidded by Occidental Petroleum in 2019), while Devon Energy snapped up WPX Energy for US$2.56 billion. All four were driven by the same motive – to expand foothold and stitch up shale assets (particularly in the Permian). This series of M&As rejigged the power balance in the Permian, propelling the four buyers into the top eight producers in the basin, joining Occidental, EOG, ExxonMobil and Chevron. These top eight Permian producers now have output of over 250,000 b/d, accounting for nearly 60% of the basin’s 4.5 mmb/d output.

You would think that this trend would continue until the Permian Big Eight became the Permian Big Four for Five. And this could still happen. But the latest M&A activity from a major Permian player suggests that the ambition may well be too constrained. Cimarex Energy, the tenth largest player in the Permian with output of some 100,000 b/d, just entered into a merger to create a US$17 billion Houston-based shale driller. But its partner was not, say, fellow Permian buddy SM Energy (80,000 b/d) or Ovintiv (75,000 b/d). Instead, Cimarex chose Cabot Oil & Gas, a gas-focused player that operates almost entirely in the Marcellus shale basin in Appalachia, over 1500km away from the Permian.

In response to the merger, share prices of both Cimarex and Cabot fell. Analysts cited a dilution of each company’s core focus (along with the meagre premium) as concerns; implying that investors would be happier if Cimarex stayed and grew in the Permian, and Cabot did the same in Marcellus. But that’s a narrow way of thinking that both Cimarex and Cabot were happy to refute. “This is a long term move,” said Cimarex CEO Tom Jorden. “This combination allows us to be ready for those (swings in commodity prices)”.

While pursuing in-basin opportunities could make shareholders happy in the short-term, a multi-basin deal might be a surprise but is also a canny long-term move. After all, at some point the Permian will run out of oil. And so will gas in Marcellus. Or the US government could accelerate its move away from fossil fuels. If an energy company puts all of its eggs into one basket – or basin, in this case – then when the river runs dry, the company’s profits evaporate. It is a consideration that other single-basin focused players like Pioneer, EOG and Diamondback will need to start thinking about, which is a luxury that other integrated players with Chevron and ExxonMobil already have. Consolidation in American shale basins is inevitable. But what is far more interesting is the new potential of cross-basin consolidation.

Market Outlook:

  • Crude price trading range: Brent – US$67-69/b, WTI – US$64-66/b
  • Global crude oil prices remain locked in their current ranges, with bullish signs of fuels demand recovery in North America, Europe and China offset by signs that the Iranian nuclear deal could be revived, which would lead increase OPEC supply
  • Iran, if reports are accurate, has already been preparing for this, establishing contact with former clients to gauge interest and pave way for its re-entry to the global oil markets, which could swell OPEC production by nearly 4 mmb/d
  • This will be a point of contention within the OPEC+ supply deal framework, since Iran would argue for exemptions (as Russia, Kazakhstan and Libya have) from official quotas; although the latest rhetoric from Iran suggests there are still plenty of gaps to restore the original 2015 nuclear agreement, allaying fears of a quick ramp-up
June, 08 2021
The Power of the Shareholders in Climate Change

The battle for the future of humanity is moving from the oceans and the rainforests of the world into the board rooms of the world’s largest energy companies. On a single day in late May, shareholders and courts delivered a decisive twist in the drive for the oil and gas industry to ‘go green’. Shell was ordered to cut its emissions by far more than it already plans to. Chevron’s stock holders defied the company’s recommendation by directing it to slash emissions. And ExxonMobil’s CEO went head-to-head with a small activist investor, which resulted in an embarrassing show for Darren Woods as he lost two seats on the Board of Directors. Serious and stoic newspapers called it ‘Black Wednesday for Big Oil’, representing a shift in the way the industry engages climate change: doing something just isn’t enough, and activists are ready to use the world’s courts and the companies’ own AGMs to force a change if none is coming.

In the Netherlands, a court ruled that Shell must slash its greenhouse gas emissions by 45% by 2030 (compared to 2019 levels) to bring it in line with the goals of the Paris Agreement. The case, by Friends of the Earth Netherlands, argues that Shell violates fundamental human rights by not accelerating its plans to slash emissions, jeopardising the Agreement’s target of limiting the average increase in global temperatures to less than 1.5 degrees Celsius. Not that Shell was a laggard in that arena. Like its other European energy peers, Shell has embarked on a strategy to reduce net emissions by 25% through 2030, and then to net-zero by 2050. That, the court said, is not enough. Shell needs to slash its emissions harder and faster than planned. And not just in the Netherlands, since the ruling applies to the entire Royal Dutch Shell Group, from Mexico to Malaysia. Shell will be appealing the ruling, potentially dragging the case through years of continued litigation, but the landmark decision will embolden more environmental groups to push for judicial action. There are currently some 1800 lawsuits related to climate court pending globally; prior to the Shell ruling, many were ruled in favour of energy companies, but this case could have a powerful ripple effect. At risk will be oil and gas companies in North America and Europe, but even national oil firms or players in developing countries are not safe, with cases also being filed in India, South Africa and Argentina.

However, the judicial process is a long and complicated one. Sometimes, it is faster than change things from the inside. And that is exactly what Chevron’s shareholders did at its recent AGM. Going against recommendations by Chevron’s own board, some 61% of investors voted for a proposal to reduce its Scope 3 greenhouse gas emissions – which is pollution caused by third-party use of its products. A sober CEO Mike Wirth went on Bloomberg to state that ‘interests in these (climate change) issues has never been higher and I think the votes reflects that.’ He shouldn’t have been surprised; a week earlier, 58% of ConocoPhillips shareholders also rejected company recommendations to vote for a similar full-scope emissions reduction target.

But even this pales in comparison to the drama that took place in the (virtual) boardroom of the world’s largest supermajor. It was a drama that began back in December 2020, when a small activist investor with only a 0.02% stake in ExxonMobil began lobbying the firm to take the fight against global warming more seriously. Initially dismissed, Engine No. 1 eventually proposed four of its own candidates to sit on ExxonMobil’s 12-strong Board of Directors, which includes CEO Darren Woods. ExxonMobil reportedly refused to meet with any of the 4 nominees, calling them ‘unqualified’ and that the activist’s goals would ‘derail our progress and jeopardise your dividend.’ That imperious approach rankled. Two prominent shareholder-advisory firms – Institutional Shareholder Services Inc and Glass Lewis & Co – then provided the activist partial support. ExxonMobil retaliated by stating that it would name two new directors, one with energy industry and one with climate experience, to quell dissent.

It was not enough. With ExxonMobil’s top three investors (Vanguard Group, BlackRock Inc and State Street Corp, collectively holding more than 21% of shares) wavering, the company made an unprecedented last-ditch attempt to prevent a defeat. Individual calls were made in a targeted manner to persuade a changing of votes, up until the virtual meeting started. After the AGM began, there even was a 60-minute pause citing volumes of votes incoming, during which some shareholders were contacted again to change their votes. In the words of one major executive, the move was ‘unprecedented’. Engine No. 1 publicly complained of the ‘banana republic tactic’ on television. But, in the end, two of its nominees – former CEO of refiner Andeavor Gregory Goff and environmental scientist Kaisa Hietala – were nominated to the Board. Two seats remain undecided, potentially granting Engine No. 1 a third director.

This rebuff was particularly painful for ExxonMobil and Chevron, who (along with other American majors) have been dragging their feet on climate change. Their gamble to focus on shorter-term profits generated by higher crude prices and prodigious production, while only evolving their sustainability position gradually, had long been thought to please shareholders. Apparently not. Climate change affects all, including some of the world’s largest investors like BlackRock Inc, which has been very vocal about its climate position. So if ExxonMobil’s executives won’t take climate change seriously, then change must be forced at the Board level. This may put Darren Woods in a wobbly position; but so far Engine No. 1 has not shown signs of wanting to oust Woods, they just want climate change to be a stronger item on his agenda.

But even if climate change is already a major item, that might not be enough, as seen in the ruling against Shell. Even the most ambitious of the supermajors like BP and Total (which was just rebranded to TotalEnergies) might not be safe from litigation, even though their decarbonisation plans were rated as the best by financial thinktank Carbon Tracker. Which could be the reasoning behind some recent moves by the supermajors to start shedding traditional assets and acquiring renewable ones: ExxonMobil has decided to pull out of a deepwater oil prospect in Ghana, Shell has decided to sell its Mobile Chemical LP refinery in Alabama to Vertex Energy Operating and its Deer Park Refining stake to Pemex, while BP has just acquired 9GW of renewable energy capacity in the USA from 7X Energy as its chases a global 50GW goal by 2030. Taken together, these moves are creating a narrative. Boardrooms and AGMs are generally safe places for energy executives, but not anymore. The new era is upon the energy industry. And the definition of ‘good enough’ has just changed.

End of Article

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Market Outlook:

  • Crude price trading range: Brent – US$69-71/b, WTI – US$66-68/b
  • Brent crude prices topped the US$70/b mark, signalling strength in oil with consumption in the US, Europe and China rebounding strongly and OPEC+ signalling that the supply side was beginning to tighten
  • That declaration by OPEC+ will undoubtedly lead to a further easing of the club’s supply quotas from July onwards, as it aims to balance stable oil prices with steady supply that will not overwhelm the market, even with Iran’s possible return
  • The timeline and momentum for Iran to restore production – potentially to 4-5 mmb/d from a current 2.5 mmb/d – will depend on ongoing talks to revive the 2015 nuclear accord, but Iran has already started laying the groundwork for an inevitable return 

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June, 02 2021
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May, 25 2021