Canadian E&P: Canada’s upstream on track to strengthen during 2023
If one was to examine market indicators, the Canadian oil and gas industry would appear to be poised for a monster year. Key indicators, such as spending plans, land sale revenues and drilling numbers, are all up, Fig. 1. The war in Ukraine has shined an unwavering spotlight on the world’s continued dependence on fossil fuels and how truly thin the supply margin is for importers of energy. Further, it is now abundantly clear that hydrocarbons must play a critical role in achieving carbon neutrality.
Given Canada’s history of supporting international partners, its constant pursuit of new technology, and its innovative approach to solving technical issues, the time is ripe for an export of Canadian hydrocarbons and technical innovation to a global market desperate for both.
FEDERAL POLICY FACTORS
And yet, rather than gear up for these opportunities, which should be attracting significant capital and ushering in a new, transformed, green energy boom in Canada, a malaise of uncertainty and doubt hangs over the market. The federal government’s dogged pursuit of environmental objectives that no longer align with global market fundamentals continues to suppress the very innovation that made Canada an energy superpower.
So, billions of investment dollars continue to be directed elsewhere, and oil from oppressive regimes with little or no environmental safeguards are shipped to refineries around the world, including the U.S. and Canada. Meanwhile, dictatorial regimes are propped up by the very policies that are supposed to be directing Canadians to a greener and more democratic global landscape.
Under siege by its own federal government, the Canadian industry remains in the same year-to-year limbo that it’s been under for almost a decade, with no end in sight, even as domestic energy prices have climbed to levels that are stretching taxpayers’ budgets to the breaking point.
Despite the lack of support federally, there is some support for industry’s efforts at the provincial level. Alberta has been leading the way on carbon capture and storage since the concept first arose, and Alberta Premier Danielle Smith recently stated that the province would be willing to increase tax credits in this area, provided Ottawa is willing to do the same.
Interest in hydrogen is also on the rise, and Alberta’s exiting use of the product and mature industry could enhance its potential to develop and ship it. However, there is a lack of infrastructure elsewhere, plus liquefying and transporting hydrogen is energy- intensive, and line loss can be a significant problem over distance.
Renewable diesel also has emerged as a potential step toward carbon neutrality in Canada. In January, Imperial Oil announced it would be spending C$720 million to develop a renewable diesel facility at its Strathcona refinery near Edmonton, Alberta. Imperial joins a long list of planned renewable diesel projects, including Federated Co-op Limited (Saskatchewan); Braya Renewable Fuels (Newfoundland); Covenant Energy (Saskatchewan); Tidewater Renewables (British Columbia), as well as Parkland Corporation’s expansion of its renewable diesel capacity at its refinery in Burnaby, British Columbia.
The Pathways Alliance, a consortium of Canadian oilsands producers with a target of net zero emissions by 2050, continues to make progress on plans to develop a carbon capture storage hub, plus a 400-km trunk line from Fort McMurray to Cold Lake, Alberta, to transport CO2 from the oilsands to the hub. The consortium, which is looking for more concrete support at the federal level, expects to spend upward of C$24 billion by 2030, provided they can secure the necessary provincial and federal approvals in a timely manner. Pathways consists of six companies: Imperial Oil Limited, Canadian Natural Resources Limited, Suncor Energy Inc, Meg Energy Corp., ConocoPhillips, and Cenovus Energy Inc. The group expects to spend C$70-75 billion over three phases, eliminating 68 megatonnes of oilsands emissions.
Canadian producers are still facing some of the classic obstacles, like market access and a shortage of skilled labor, which have been exacerbated by the years-long downturn that saw an estimated 150,000 jobs lost in the petroleum industry. But with strong prices in place, and Covid restrictions less and less likely to resurface, it appears that 2023 could see a resurgence not experienced in a very long time.
Market access remains one of the trickiest problems, as landlocked Alberta and Saskatchewan look for ways to get their products to market. Crude-by-rail is an adequate—albeit more risky and costly—method, but it doesn’t help reach the markets in Europe and Asia that would love to buy Canadian natural gas.
There was some fleeting optimism that when Canadian Prime Minister Justin Trudeau signed a non-binding MOU to explore shipping hydrogen to Germany, a policy change on LNG (and the pipelines needed to support its export) might follow. But true to form, late last year, Trudeau brushed aside questions about LNG, stating there was “no business case” for shipping Canadian LNG to Germany (supply/demand market realities notwithstanding). His response was similarly lukewarm to Japan when Prime Minister Fumio Kishida expressed interest in buying more Canadian energy.
The federal dogma, which not only ignores the economic, transportation, heating and geopolitical realities of the world’s energy landscape, has the federal liberals battling their provincial counterparts in Alberta and Saskatchewan, which launched court challenges to the federal Impact Assessment Act. Alberta’s Court of Appeal ruled the Act was unconstitutional last year, in a 4-1 ruling that called the IAA a "breathtaking pre-emption of provincial authority." The federal government has appealed, but no timelines have been announced for the case to be heard.
In the meantime, spending plans are on the rise. But industry analysts are projecting a relatively modest overall increase—in the 5-6% range—as the continued uncertainty on the political and regulatory side has made producers more cautious than they have been in the past. Many producers are also looking to pay down debt in the current price environment.
Individual spending plans for this year include Suncor, at C$5.4–$5.8 billion, an increase of more than 10% from its estimated 2022 spending of $4.9-$5.2 billion; CNRL, at $5.2 billion, up almost 24% from $4.2 billion in 2002; Cenovus, with a projected spend of $4.0-$4.5 billion, an increase of more than 21% over last year’s $3.3-$3.7 billion; and Imperial Oil has announced a capital budget of $1.7 billion, up more than 20% over $1.4 billion in 2022.
Total mergers and acquisitions value in 2022 was approximately C$15.6 billion, down almost 14% from $18.1 billion in 2021, according to Calgary-based Sayer Energy Advisors. Seven transactions came in at over a billion dollars, and the top three made up more than one-third of total M&A value in 2022. In August, Strathcona Resources Ltd. picked up Serafina Energy Ltd. for $2.3 billion; in June, Whitecap Resources Inc. acquired XTO Energy Canada for $1.9 billion; and in September, Tamarack Valley Energy Ltd. purchased Deltastream Energy Corporation for just over $1.5 billion. Sayer is forecasting similar M&A activity in 2023.
Producers continue to benefit from the low Canadian dollar, which continues to hang around the US75-cent mark this year versus the U.S. dollar. A low Canadian dollar provides a buffer for the export-driven oil and gas industry, which ships substantial volumes of oil and gas south to U.S. customers. Preliminary data from the Canadian Association of Petroleum Producers (CAPP) indicate that the country’s crude and condensate production was up about 2% from 2021’s level.
Drilling numbers increased as expected in 2022, with 6,022 wells drilled, a 25% increase over 4,836 in 2021, according to Daily Oil Bulletin (DOB) records. Just over 81% of the wells targeted oil.
In Alberta, DOB said there were 3,623 wells drilled, up 38% from 2,632 in 2021. In Saskatchewan, drilling increased 11% to 1,511 wells, compared to 1,358 wells drilled. British Columbia saw 374 wells drilled last year, a 20% decrease from 465 wells in 2021. And Manitoba had 215 wells, an increase of 37% from 157 in 2021.
For 2023, the Canadian Association of Energy Drilling Contractors (CAOEC) is predicting that drilling will increase 14.8%, to 6,409 wells from 5,582 in 2022, with a slight increase in employment levels. Labor shortages remain a major issue for the drilling sector.
World Oil survey results are similar. Based on data and projections from the Canadian Association of Petroleum Producers, World Oil estimates that 6,190 wells were drilled across Canada during 2022, Fig. 2. Given that number, and taking into account capital spending projections and other industry estimates, World Oil forecasts that 7,050 wells will be drilled during 2023, for a nearly 14% increase.
Saskatchewan’s Ministry of Energy and Resources reported that 1,484 new wells were drilled in the province during 2022. Officials project 2,000 wells for 2023, which would be a 34.8% increase. Over in British Columbia, the BC Oil and Gas Commission said that 381 wells were drilled onshore the province during 2022. While they did not furnish a forecast for 2023, World Oil believes that activity should rise 10%, perhaps a bit more.
The Alberta Energy Regulator (AER) provided links to some of their data. According to AER’s data, from January through November 2022, the province recorded 7,883 wells, which would be considerably higher than numbers reported by other sources. But keep in mind that this total is not necessarily just new wells spudded. It can reflect re-entries, stratigraphic tests and late reports of completions from wells drilled earlier. In fact, AER acknowledges in its explanation of the data that “The information contained in this report is obtained from well licence applications submitted to the AER…” That having been said, AER’s raw number was up about 50% from the 2021 figure.
In Alberta, spending on land sales continues to rebound from the depths of 2020, with $459.37 million collected, an increase of more than 304% over the 2021 total of $113.8 million ($637.94/hectare). That’s still a far cry from the record high of $5 billion in 2008.
British Columbia’s land sales have not resumed since the 2021 Supreme Court ruling on the Blueberry River First Nation’s challenge to BC’s resource development policies, although B.C. did announce it had reached an agreement with Blueberry this January. When, and how, land sales may restart in the province has not been determined.
Saskatchewan, after resuming its monthly land sale schedule in 2022, collected $52.25 million, up more than 470% over $9.1 million in 2021. Manitoba took in $687,740 in 2022, bouncing back with an increase of 230% over the $207,970 garnered in 2021.
The recovery of land sales—and the two-year trend upward—is a very positive sign for future oil and gas development in Canada.
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