By Deborah Jaremko

Canada’s relationship with the United States, as virtually its only customer for oil exports, has finally begun to break, according to a leading energy analyst.

More volumes than ever of Canadian oil are heading overseas, but many of the tankers aren’t leaving from Canada’s shores. The oil is being “re-exported,” that is, sent to the U.S. by pipeline or rail and then loaded for international markets from terminals on the U.S. Gulf Coast.

“It looks like Canada’s crude oil exports are finally showing off their stuff and stepping out on the town,” wrote Martin King, senior analyst with RBN Energy, in a recent report.

“This year, much stronger international demand has sent re-export volumes to record highs.”

Since the 1950s, Canada has been exporting crude oil to overseas markets through the Trans Mountain pipeline, but King notes those volumes have generally been “very modest” at under 100,000 barrels per day.

That’s expected to change with the completion of the Trans Mountain Expansion, adding up to 500,000 barrels per day of additional international export capacity, King said.

This will give Canadian oil producers something they’ve long been waiting for – options for sending their crude to growing markets overseas.

Citing U.S. Census Bureau data, King said that an average 130,000 barrels per day of Canadian heavy oil was re-exported from the U.S. Gulf Coast last year.

So far this year, re-exports averaged 200,000 barrels per day, topping 300,000 barrels per day in March, underlining strong demand from customers outside the U.S., including China, India and Spain.

The rise in Gulf Coast re-exports is thanks to increased pipeline access following the completion of Enbridge’s Line 3 Replacement Project in 2021, as well as additional access on other Enbridge and TC Energy pipelines, King said.

The Russia/Ukraine war and OPEC+ crude production cuts have also caused importing countries like China to “look further afield” for oil, he said.

According to data from the U.S. Energy Information Administration (EIA), total American oil exports have surged amid the shifting oil flows.

In 2021, the United States exported an average of 2.9 million barrels of oil per day. In 2022 this increased to 3.6 million barrels per day, and so far this year has averaged nearly four million barrels per day.

Despite increased investment in renewable energy sources, world oil consumption this year is at a record 102 million barrels per day, according to the International Energy Agency.

Deborah Jaremko is director of content for the Canadian Energy Centre, a Troy Media Editorial Content Provider Partner.

A spring season of unusual circumstances has presented a myriad of challenges for oil and gas companies in Canada’s Alberta and British Columbia provinces. Wildfires have ripped through both provinces and the industries that work there, forcing thousands of evacuations and disrupted production.

Alberta currently is facing 91 wildfires, with 27 burning out of control, and the government has declared a provincial state of emergency. About 38,000 Albertans have been asked to evacuate their homes because of the fires, while oil and gas firms have shut down production of at least 319,000 barrels of oil equivalent per day (boep/d) – about 3.7% of the country’s production. While all but 12,000 were allowed to return to their homes last week thanks to a cold front that helped firefighters, more abnormally hot and dry weather was set to return on the weekend, raising concerns about the next wave of problems. Wildfire concerns have pushed Canadian heavy crude prices to their highest levels in months and nearly 2.7 million barrels per day of Alberta oil sands production in May is at risk in the very high (40%) or extreme (60%) wildfire danger zones.

In B.C., fires raging in more than 50,000 hectares in the northeast quadrant caused the entire communities of Fort St. John and Fort Nelson, four hours drive north, to be placed on evacuation alert, along with Blueberry First Nation, impacting about 21,000 people – 1,800 of them driven from their homes. More than 60 active wildfires are burning across the province including the Stoddart Creek and Red Creek fires near Fort St. John, which are considered to be out of control.

“The Canadian Association of Petroleum Producers (CAPP) is monitoring wildfire developments as they unfold,” CAPP spokesman Jay Averill told Resource World Magazine. “Rapidly changing conditions make it very difficult to quantify the overall industry impact.”

Those conditions could see other areas in both provinces hit by wildfires as record temperatures continue. “I wouldn’t be surprised if alerts and orders shift out of the north and into the rest of the province,” said Cliff Chapman, director of wildfire operations for the B.C. Wildfire Service in a statement Tuesday, noting that a province-wide open burning ban will begin.

The blazes are not only hurting the oil and gas industry; they’re affecting everyone in northern Alberta and B.C. and that concern could broaden if the fires spread southward.

The Alberta government has asked public servants with firefighting experience to volunteer to battle the blazes, which stretch from the Rockies in the west to the Saskatchewan border, from above Fort McMurray south to Red Deer, with more than 600,000 hectares burned so far, prompting comparisons to 2016 when equally hot and dry weather sparked a mega-blaze known as The Beast, which forced the evacuation of all of Fort McMurray. The government already employs about 1,600 people to fight fires, and this year another 900 people have been brought in from other provinces, including 300 from the armed forces. But some have expressed concern that recent budget cuts to $102 million from $130 million in 2018-19 are hindering the province’s wildfire management efforts.

Some examples of the wildfires’ impact are:

Obsidian Energy Ltd. (OBE:TSX; OBE:NYSE) has curtailed 9,700 barrels of oil equivalent per day (boe/d) in the Peace River and Pembina regions of Alberta.

Athabasca Oil Corp. (ATH:TSX) has shut in two of its facilities at Kaybob, shuttering 2,300 boe/d production.

Crescent Point Energy Corp. (CPG:TSX; CPG:NYSE) has shuttered its Kaybob Duvernay production of 45,000 boe/d.

Vermillion Energy Inc. (VET:TO) has shut in some 30,000 boe/d of production in West Central Alberta.

NuVista Energy Ltd. (NVA:TO) shut in operations in the Grande Prairie, AB area, about 40,000 boe/d.

Pipestone Energy Corp. (PIPE:TO) shut in about 20,000 boe/d of production in the Grande Prairie area.

Baytex Energy Corp. (BTE:TO) shut in 20,000 boe/d of production in the Peace River and Peavine regions of northwest Alberta, and 4,000 boe/d in West Central Alberta.

Paramount Resources Ltd. (POU:TSX) has curtailed 45,000 boe/d in the Grande Prairie and Kaybob regions.

Kelt Exploration Ltd. (KEL:TSX) shut in about 5,000 boe/d in its operating region at Oak, 35 kilometres from Fort St. John, B.C.

Consequently, concerns about the wildfires and producers shuttering production have seen benchmark heavy crude prices tighten to multi-month highs. The Western Canada Select heavy crude discount to the benchmark West Texas Intermediate (WTI) has narrowed, last week ending nearly $13 a barrel below the WTI. Meanwhile global oil prices rose a dollar a barrel on the prospect of tightening supplies in Canada, although recession fears kept the market pressured. And the impact of the wildfires on production is expected to continue.

In recent days, some oil and gas producers in Alberta – Crescent Point Energy, Tourmaline Oil Corp. (TOU:TO), Paramount Resources Ltd., Obsidian Energy Ltd., Vermillion Energy Inc. and Pembina Pipeline Corp. (PPL:TO) – have restored production, at least to some extent, after cooler temperatures and some rainfall brought relief to some areas of the province. But the likelihood of more wildfires remains a reality as the forecast for both provinces contain predictions of hot and dry conditions, which will worsen the situation.

Despite their own problems, some industry leaders have stepped up to provide help to communities affected by the raging wildfires. Cenovus Energy Inc. (CVE:TSX; CVE:NYSE) recently announced a C$200,000 donation to the Canadian Red Cross’ 2023 Alberta Fires Appeal to support relief efforts for the communities and people affected by the wildfires in that province. Plus, the company is matching employees’ individual donations to fire relief efforts made through Cenovus Cares, its giving and volunteering program.

“A number of upstream and downstream facilities remain impacted – some due to proximity to the wildfires and others indirectly as a precautionary measure for worker safety and to adhere to evacuation orders,” said Averill. “It is too early to assess any estimated overall costs as the situation remains fluid. We are continuing to closely follow the evolution of conditions and are engaging with the Province to provide support wherever possible to assist with the government’s ongoing emergency response.

“Industry’s top priority is the safety of our workers, and our thoughts are with the people and communities impacted by the wildfires.”

Canada has some tough decisions to make regarding Carbon Capture, Utilization and Storage (CCUS), and much is at stake for both the industry and the nation.

Already a world leader in the fight to reduce carbon emissions and stall global warming, Canada must act now to ensure it doesn’t get left behind as other nations scramble to initiate their own projects to capture the carbon dioxide produced by power generation or industrial activity, transporting it, storing it deep underground, a kilometre or more in depleted oil and gas reservoirs or saline aquifers, and then re-using it in industrial processes by converting it into, for example, plastics, concrete or biofuel. Along with increasing efforts to lower emissions, it’s considered vital to meeting the targets set out in the 2016 Paris Agreement in the fight against global warming.

Storing carbon is a proven technology that has been in safe operation for more than 45 years, and there are currently 194 large CCS facilities globally, compared to just 51 in 2019 – 80 in the U.S., 73 in Europe, 21 in the Asia-Pacific and six in the Middle East. The capture capacity of all facilities grew to 244 million tonnes per year in 2022, up 44% from the previous year.

Getting it right will not only create opportunities for Canada’s oil and gas sector, but it will also open the door to investment into critical minerals, hydrogen, small modular nuclear reactors, and other industries that will drive the nation toward a future, lower-carbon economy. Fifty-three CCUS projects, hubs and expansions have been proposed or are in various stages of development across Canada – 39 in Alberta, which has the highest emissions in the nation – representing billions of investment dollars. These plans include Enbridge Inc.’s (ENB:TO) Wabamun carbon hub – it’s partnering with Capital Power Corp. (CPX:TO) and cement manufacturer Heidelberg Materials AG (HEI:MI) – and a $16.5-billion CCUS development proposed by the Pathways Alliance of six oil and gas companies, connecting oil sands operations to a storage hub near Cold Lake, Alberta.

“CCUS is also going to help us increase the supply of oil and gas, hydrogen, critical minerals and, of course, low-carbon cement,” Alberta Liberal MP and associate finance minister Randy Boissonnault said recently at an announcement with Heidelberg about its carbon capture project in Edmonton. Heidelberg and the federal government have signed a memorandum of understanding supporting building the world’s first carbon-neutral cement plant at the company’s Edmonton facility. The $1.4-billion project would capture more than one million tonnes of CO2 a year, which would then be shipped to the Wabamun hub for storage.

Heidelberg officials have not yet made a final investment decision, but the company expects the project could be operating by late 2026.

Many emissions-curbing efforts are underway in Canada. The Pathways Alliance is advancing a bold and yet realistic plan to reduce absolute emissions from production by 22 million tonnes annually by 2030 and achieve net zero operational emissions by 2050.

With anticipated co-funding support from Canadian governments, the Alliance has announced plans to invest about $24 billion before 2030 in the first phase of its plan.

Of the $24 billion, approximately $16.5 billion, will support a proposed carbon capture and storage network in northeastern Alberta that, when constructed, will be among the largest facilities in the world. The remaining $7.6 billion investment is planned on major emissions reduction projects and technologies.

“We know of no other oil-producing jurisdiction where competitors have come together and done the work required to advance such an ambitious plan,” said Dilling.

Between 2012 and 2021, the Alliance’s six member companies invested more than $10 billion on research and development on various technologies in Canada’s oil sands. Some helped the industry reduce average per barrel CO2 emissions by about 22% between 2011 and 2019.

While Canada is making progress, the United States is making serious advancements in the CCUS arena. Their government has committed $3.7 billion to finance CCUS projects and meet its goal of net-zero emissions by 2050, and their Inflation Reduction Act (IRA) now offers air-capture projects a per-tonne credit of $180, up from $50. About 80 projects could be operational before 2030 and the U.S. could see CO2 capture capacity increase five-fold to more than 100 metric tonnes of CO2 annually. Canada, meanwhile, has around 15 projects in various stages of development.

Recently, the Canadian government’s budget outlined several minor changes made to investment tax credits, and also promised to take steps to accelerate the regulatory timelines facing major projects. Canada now is offering an investment tax credit for capital expenditures while the U.S. is providing a tax credit of $85 for each tonne of storage.

Canada’s plan at least represents “progress”, said Enbridge CEO Greg Ebel in a statement. “The one thing that obviously would be helpful is just some certainty on the permitting/approval time.”

“Canada’s oil and natural gas industry is currently a global leader in the development of carbon capture technology,” Jay Averill, spokesman for the Canadian Association of Petroleum Producers, told Resource World Magazine. “To remain a leader, Canada’s industrial policy related to CCUS must become more competitive.

“The U.S. has taken a dramatic step forward in terms of their tax framework for CCUS and is now on par with Norway. With global energy demand growing along with an imperative for effective GHG (greenhouse gas) emission reductions, there is an opportunity for the government to work collaboratively with the oil and gas sector on developing an approach that can accelerate the development of CCUS projects in Canada.”

Averill said the U.S.’s IRA is a “landmark piece of legislation” that has the very real potential of accelerating their leadership in carbon capture and GHG reductions technology. Canada’s oil and gas industry may be currently a global leader in this area but remaining among the leaders will require a co-ordinated and incentive-based approach similar to the IRA.

“There is still time for the federal and provincial governments, and the oil and natural gas industry, to work together on an enhanced made-in-Canada approach that can effectively compete to attract global investment capital at a time of a softening economic outlook,” Averill said.

Trillion Energy has been operating in Turkey since 2014 and has achieved significant success in the exploration and production of natural gas. The company’s strategy has been to focus on the Black Sea region, where there are substantial untapped reserves of natural gas. This strategy has paid off in spades, with Trillion Energy becoming one of the leading producers of natural gas in the region.

One of the key accomplishments of Trillion Energy has been its ability to thrive in the face of the global energy crisis. While prices have declined from their peaks, Trillion Energy is still producing natural gas in the highest-priced gas regime on the planet. In Turkey, gas prices are at $17 USD per cubic meter, compared to $4 USD per cubic meter in the United States, $12 USD per cubic meter in Europe and Asia, and $5 USD per cubic meter in South America. Despite these high prices, Trillion Energy has continued to increase its production levels, highlighting the company’s resilience and adaptability.

In fact, Trillion Energy had a blockbuster year in 2022, almost tripling its proved reserves to 63 billion cubic feet (BCF) and increasing its reserves values by 700% to up to $500 million USD (discounted – NPV10) and $800 million USD undiscounted net cashflows after royalty, operating costs, and capital expenditures. Trillion Energy is now 4 for 4 for new wells, having made three new discoveries over the last six months and converting resources to reserves, which has significantly increased the reserve report values. The company plans to drill seven more new wells in 2023, demonstrating its continued commitment to growth and innovation.

Trillion is currently drilling well number 5 “Bayhanli” of a 15+ well program on the SASB. The program has been successful so far with strong production numbers in each well: NPV-10 increases by 426%: Estimated proven reserves increased slightly to 11.6 bcf, with 2.7 bcf of proven undeveloped reserves, reclassified as proven producing. Probable reserves increased by 330% to 37.1 bcf as three of the four successful wells drilled to date targeted contingent resources. Overall, 2P reserves increased by 130% to 48.6 bcf. An additional 35.7 bcf (218% increase) is in the possible reserves category. The before-tax net present value (“NVP-10”) of the 1P reserves value increased by 206% to US$123.8mm on the back of a higher natural gas price forecast. The NVP-10 of the 2P reserves value increased by 426%to US$431.5mm (C$1.50/sh) on new reserves additions and a higher price deck.

Additional highlights of Trillion include: recent Analyst reports from both “8 Capital” who put a 1.50$ price target on Trillion and “Mackie Research” who put a 1.35$ price target on Trillion and recently press released reconfirmation of the target. Trillion just announced the closing of a 15MM$ convertible debenture facility through 8 Capital as well. (Click here for the full news release) This additional funding is going to allow for working capital and capital expenditures related to the development of the company’s assets in Turkey.

TCF drilling campaign has been highly successful as the company has proven that long reach directional drilling technology is effective at targeting existing and new reserves directly from the production platform. We expect significant reserves additions as the company drills an additional 16 wells in the balance of 2023 and into 2024 and we expect stock price appreciation as the Company continues to build its production and cash flow base.

For more information about Trillion Energy, please visit www.TrillionEnergy.com or email: info@TrillionEnergy.com with any questions.

Canada’s British Columbia province is breaking ground on several fronts in LNG production. And the world is watching closely.

Canada is the world’s sixth-largest gas producer and the west coast liquefied natural gas (LNG) industry is being watched closely as the world seeks alternatives to the Russian gas supply after its invasion of Ukraine. But despite having 18 proposed projects over the past few decades, only one facility, LNG Canada in Kitimat, BC, is under construction. So, experts say it’s about time Canada rose to the challenge, as global demand for LNG is projected to grow 76% by 2040 and a dozen other nations have already expedited the development of their LNG industries.

“Natural gas is a transition fuel that can help other nations make the change from coal to cleaner energy while helping to lift populations out of poverty,” Karen Ogen, CEO of the First Nations LNG Alliance, said in a statement.

Any increase in LNG exports will be welcome news for nations such as Germany, Japan and South Korea who wanted Canadian gas but were forced to source it from other less responsible countries, such as Qatar. And it will be full of positives for Canada. By displacing coal-fired power in Asia, Canadian LNG can reduce emissions equivalent to taking 41 million cars off Canadian roads; pretty good since the nation only has 36 million registered vehicles. Also, a strong LNG sector in BC could generate more than $500 billion in economic activity, almost 97,000 more jobs per year, and $6 billion in wages for Canadians.

Others are certainly aware of the opportunities. The United States recently approved LNG exports from the Alaska LNG project as the United States competes with Russia to ship natural gas from the Arctic to Asia. The Alaska Gasline Development Corp. [AGDC-NYSE] project allows the export of gas to countries with which the United States does not have a free trade agreement.

The $39-billion Alaska LNG project is expected to be operational by 2030 if it gets all the required permits, with the exports going mainly to countries in Asia. The project includes a liquefaction facility on the Kenai Peninsula in southern Alaska and a proposed 1,300-kilometre pipeline to move gas stranded in northern Alaska across the state. The project has been opposed by environmental groups.

There are signs that Canada also is beginning to pay attention. While the Shell-led LNG Canada project is under construction, Woodfibre LNG has announced world-class goals, the Nisga’a First Nation is planning the Ksi Lisims LNG export facility north of Prince Rupert, BC, and the Haisla First Nation is partnering with Pembina Pipeline Corporation [PPL-TSX; PBA-NYSE] to create Cedar LNG, a floating LNG facility on Haisla-owned land near Kitimat, even as the provincial government has toughened emissions standards for new LNG projects.

The BC government has moved to toughen emissions standards for new LNG projects, creating a benchmark climate plan but setting a high hurdle for the industry – the requirement that any projects up for environmental assessment must have a realistic plan to have net-zero emissions by 2030. The new regulations also include an oil and gas emissions cap and plans to accelerate the electrification of the economy.

The $10-billion Ksi Lisims LNG project is designed as a floating facility which includes a pipeline to transport natural gas from the northeast corner of the province for export to Asia. The First Nation is partnering with a group of Western Canadian natural gas producers called Rockies LNG Partners and a Texas energy company, Western LNG. They have vowed to reach net-zero emissions within three years of beginning operations, which is anticipated to be in late 2027 or 2028, and export 12 million tonnes of LNG annually.

The backers of Woodfibre LNG, a $4-billion liquefied natural gas export facility due to go into operation in 2027 near Squamish, BC, have announced its Roadmap to Net Zero, a plan to achieve net-zero emissions by the time their plant starts operating in 2027 – 23 years ahead of government regulation. If successful, it will be the first LNG plant in the world to achieve net zero, with 14 times fewer emissions than a conventional LNG facility, while producing 2.1 million tonnes of LNG annually. Also, Woodfibre will offset emissions during the construction phase of the project, using carbon credits secured from others. The project is backed by Pacific Energy Canada Ltd., with a 70% share, and Enbridge Inc. [ENB-TSX], with a 30% stake.

“Woodfibre LNG’s roadmap prioritizes emissions avoidance and reduction opportunities, and we are proud to have a credible strategy in place that will make us the world’s first net-zero facility,” Woodfibre president Christine Kennedy said in a statement. “Alongside the leadership and vision set out by the province’s new Energy Action Framework, achieving net zero allows Woodfibre LNG to advance the global energy transition, furthering economic reconciliation and contributing to British Columbia’s standard of living.”

The company’s net zero roadmap commits to implementing certain GHG-reducing technologies and outlines incremental opportunities to reduce emissions further as technologies develop and become more affordable. The roadmap will be updated annually to include new technologies, efficiency improvements and new industry practices. Woodfibre LNG is also the first Canadian industrial project to recognize a non-treaty indigenous government, the Squamish Nation, as a full environmental regulator.

“Woodfibre LNG’s announcement comes at a time when global trading partners such as Japan are calling on the Government of Canada to provide a reliable, sustainable source of LNG to support global energy demands, said Pacific Energy president Ratnesh Bedi in a statement. “The Woodfibre LNG project has a critical role to play in demonstrating that British Columbia and its diversified portfolio of energy offerings can contribute to a low-carbon future, both at home and abroad.”

The $3.2-billion Cedar LNG project, the first in Canada to have an indigenous majority owner, will use electricity to operate the LNG facility and export terminal, which will be supplied with natural gas by the Coastal Gaslink pipeline, which is under construction. It’s expected to have an export capacity of three million tonnes of LNG a year and will employ 500 people during its construction and 100 people when it’s in operation. With environmental approvals in place and a final investment decision expected in the third quarter of this year, it’s viewed as an historic step toward economic self-determination for the Haisla people. Cedar LNG has entered into a memorandum of understanding with Montney play producer ARC Resources [ARX-TSX] for a 20-year liquefaction services agreement that could cover 1.5 million tonnes of LNG per year, approximately half of Cedar LNG’s production.

“This agreement is an important step forward in delivering our low-cost, low-emission natural gas to key demand markets, and increasing ARC’s exposure to LNG-linked natural gas prices,” ARC president and CEO Terry Anderson said.

In the coming months Cedar LNG’s proponents will be focusing on advancing work across four key streams – engineering, regulatory, commercial discussions and financing to enable the project to go forward.

“Together with our partner Pembina Pipeline we are setting a new standard for responsible and sustainable energy development that protects the environment and our traditional way of life,” Haisla Nation chief councilor Crystal Smith said in a statement.

A highly anticipated liquefied natural gas export facility planned for Canada’s east coast won’t be going forward due to a lack of affordable supply.

But two others might.

Repsol S.A. (REP:BE), which had planned to develop an LNG export facility in Saint John, New Brunswick, to supply European markets, recently announced that the cost of transporting natural gas to the terminal was too high. The gas would have to travel thousands of kilometres from western Canada but the pipeline capacity does not currently exist for it to do so.

“. . . following a study carried out by the company, it was determined to not continue with the Saint John liquefaction project as the tolls associated to it made it uneconomical,” Repsol spokesperson Christi Shafer told Resource World Magazine. She declined to answer further questions.

The Energy East pipeline proposed by TC Energy Corporation (TRP-TSX; TRP-NYSE), formerly TransCanada, in 2013 would have carried 1.1 million barrels per day to the East Coast, which spends more than C$3.5 billion annually on oil from Saudi Arabia. But objections from Quebec along with a change in the federal government, regulatory delays and a decline in global oil prices resulted in TransCanada abandoning the project in 2017. In 2018 the federal government purchased the Trans Mountain pipeline which rekindled interest in a pipeline to the East Coast, but government bureaucracy and continued objections from Quebec (which ironically has no problem receiving more than half its crude oil from western Canada) continue to make a pipeline to the east merely a dream.

However, the company that scrapped plans to build a C$13-billion land-based LNG facility in Goldboro, Nova Scotia due to cost pressures and difficulty getting financing, considered a floating alternative to meet overseas demand but has returned to its original plan, shelved in 2021.

Calgary-based Pieridae Energy Ltd. (PEA-TSX) was going to build a facility on a floating barge to meet the demand created as European countries seek to impose sanctions against Russia and isolate it in response to the conflict in the Ukraine. The company viewed this as a way to provide natural gas overseas for 20-30 years, removing the threat of Russia shutting off its supply, while capitalizing on rising prices.

But now Pieridae is in discussions with the federal government about how to move the project forward.”The world has changed a lot since then, Pieridae CEO Alfred Sorensen told CBC News. “We have to take advantage of all the work we’ve done already and try and see if we can move the project forward very quickly.”

The land-based project is favoured because it could produce more gas than a barge-based facility, and the federal government is now interested in maximizing output and could offer a combination of regulatory and financial support, he said. Three significant hurdles remain, Sorensen said: indigenous reconciliation issues; finding a new engineering, procurement, construction and commissioning partner; and achieving the needed upgrades to existing pipelines. He said the best outlook would have gas flowing from a Goldboro facility starting in January 2027.

Meanwhile the Bear Head Energy LNG project in Point Tupper, N.S., recently acquired by Texas Energy company Buckeye Partners LP, could have a new lease on life, after being mothballed after 15 years of planning due to difficulties getting gas suppliers and customers on board.

“Nova Scotia’s unique geographical characteristics give the region the potential to become one of the most productive renewable and green energy development areas in the world,” Buckeye CEO Todd Russo said in a news release at the time of the acquisition. “Via this acquisition, it is our intention to develop a large-scale energy production, distribution and export hub that will offer our customers lower-carbon energy solutions, including LNG or other green fuels.”

The time is right for Canada to make the most of its natural gas riches as a viable alternative to coal, says a recent Canadian Chamber of Commerce report, which urges the federal government to finally get serious about building the infrastructure needed to fast-track the extraction and export of LNG. The carbon credits clause of the 2015 Paris climate accord could drive such growth, with Canadian natural gas poised to become a viable alternative to coal-fired power plants around the world, the report says.

“This initiative could not only support natural gas exports but an array of services, technology, and materials exports,” wrote Eric Miller, president of the D.C.-based Rideau Potomac Strategy Group, the report’s author.

“Canada should use the global carbon market framework to build a stronger Canadian natural gas sector and a cleaner world.”

Canadian natural gas has distinct advantages. It’s plentiful, cleaner than coal, and it’s produced under Canada’s carbon-price regime which could create a market premium as demand for cleaner fuel sources continues to rise. It could support the switch from coal to gas around the world, but there are many challenges. Canada lacks the necessary infrastructure such as pipelines and export terminals, especially on the east coast. Since 2008, 18 new LNG terminals have been proposed – three in Nova Scotia, 13 in B.C. And two in Quebec. – but only one, in Kitimat, B.C. Is anywhere near completion. The report says that’s due to government’s “lack of decisiveness” on energy policy.

“Had Canada supported the construction of even a fraction of these terminals, it would have been at the centre of support for growing Asian and European markets that are in desperate need of LNG and would be actively contributing to the displacement of coal,” Miller said.

The report also identifies the need for a better pipeline network, which would also be adaptable to the future use of hydrogen as a modern low-carbon alternative to fossil fuels. It also notes that in addition to investing in hydrogen research, the federal government should examine what would be involved and what the cost would be in converting gas infrastructure to hydrogen.

Nova Scotia is ready, according to the government.

“Nova Scotia is open for business,” Patricia Jreige, spokesperson for the Department of Natural Resources and Renewables, told Resource World. “We are well positioned to export energy like natural gas or green hydrogen to Europe given our proximity to markets and our deep, ice-free ports. Green hydrogen is a clean-burning fuel and natural gas is cleaner than coal so it can help with the transition to clean energy.

“Both can help Nova Scotia and other countries achieve their climate change goals. We welcome companies that want to invest in these areas in Nova Scotia.”

The Canadian Association of Petroleum Producers (CAPP) says conventional oil and natural gas investment for 2023 is expected to reach $28.5 billion while oil sands investment should reach $11.5 billion. That’s 11% higher than last year and is also above pre-pandemic levels. And that’s not counting offshore opportunities such as Newfoundland and Labrador’s Bay Du Nord, which is awaiting a final investment decision, and West White Rose, which has been reactivated.

CAPP says much of this year’s increased spending will go towards maintenance and incremental growth projects, as well as managing inflationary pressures. Spending is also expected to go toward emission reduction technologies such as advancing the development of carbon capture utilization and storage. Upstream oil and gas investment in Canada hit a low of $22 billion in 2020 as prices collapsed due to the COVID-19 pandemic.

“There are some positive signals for Canada’s offshore which the decision to restart the West White Rose offshore project which will see over $2 billion of investment through the project completion,” CAPP spokesman Jay Averill told Resource World Magazine.

“There remains significant opportunity for Canada’s offshore industry, and it will take continued collaboration between industry and governments to ensure it is best positioned to capture a larger portion of global investment.”

ΓÇÿConventional’ includes petroleum found in liquid form, flowing naturally or capable of being pumped without further processing or dilution, as well as natural gas and natural gas liquids, liquids obtained during natural gas production including ethane, propane, butanes and condensate. ΓÇÿOil sands investment’ identifies investments in the end product derived from bitumen – crude oil located mainly in Alberta. British Columbia and Saskatchewan are both fully conventional oil and natural gas, while the offshore investment is exclusively Newfoundland and Labrador this year.

Averill said that in Alberta, investment is expected to reach $28 billion in 2023, representing about 70% of all upstream oil and natural gas investment nationally. This growth in investment is being driven both in the conventional and oil sands sectors. Saskatchewan is expected to maintain investment of about $2.7 billion, compared to about $2.6 billion in 2022.

Given that changing and growing global markets for natural gas have translated into strong prices over the past year, British Columbia producers are expected to grow investment by about $1 billion in 2023, reaching a total of about $7.2 billion. “Investment in the province is expected to be helped by the recent agreements signed by the province of British Columbia with several indigenous nations, which satisfies the courts, establishes a process to manage cumulative effects and provides for resource development authorizations and a path towards long-term development,” said Averill.

In Newfoundland and Labrador, offshore investment is expected to remain relatively flat at $1.3 billion in 2023. Last year, Canada’s offshore development showed positive signs with the federal government’s environmental assessment approval of the potential Bay du Nord project as well as the announced restart of the West White Rose project.

“Offshore investment in Canada is not growing at the same pace as the broader Canadian oil and natural gas industry or the global offshore industry,” Averill said, “although Canada’s offshore holds significant potential with some of the lowest-emission oil in the world as well as its proximity to global markets. The pending investment decision on the Bay du Nord project and upcoming exploration programs will be critical to the future of Newfoundland and Labrador’s offshore industry.”

Canada is approaching record oil production, thanks to the additional export capacity brought on by Line 3, which started in late 2021 moving record high exports to the United States. The expected completion of the TMX expansion toward the end of this year will offer additional transportation capacity of 590,000 barrels per day, which represents significant export growth.

And when the oil and gas industry is active and strong, the benefits spill over into many other sectors of society. For example, a study done for CAPP by iTotem Analytics found that from 2018-2021 the industry spent more than $4.7 billion in 140 municipalities and indigenous nations in British Columbia through the procurement of goods and services from over 2,400 B.C.-based businesses involved in engineering, construction, transportation, environmental consulting and business services. The industry spent around $540 million with some 100 indigenous-affiliated businesses and organizations – 11.5% per cent of the total supply chain spend. The spend with indigenous-affiliated businesses has been increasing, with the 2021 spend 149% higher than 2018, while the overall supply chain spend increased by $90 million, or 7.2% from 2018 to 2021. While much of the spend was in northeastern communities like Fort St. John, Dawson Creek and Pouce Coupe, significant benefits were realized across the province, with $337 million spent in Vancouver.

“A strong upstream natural gas and oil supply chain, as demonstrated by the thousands of businesses working in B.C. Between 2018 and 2021, can help us achieve our collective goal of a decarbonized future,” the study concluded. “B.C.’s natural gas and oil supply chain is comprised of businesses from indigenous communities and municipalities from across the province. Citizens who care about their community’s infrastructure and services; indigenous people with traditional knowledge and who care about reversing climate change; and residents who care deeply about advancing social progress in their schools, worksites and neighbourhoods.”

“As global demand for oil and natural gas will remain strong for decades, major energy infrastructure projects under construction, like the Trans Mountain expansion, are incredibly important to Canada reaching its potential as a provider of secure energy to our trading partners,” Averill said. “Canada has a role to play in providing safer and lower-emission resources to the world’s energy mix.”

Meeting these challenges and opportunities could result in suppliers like B.C. becoming a major export energy hub, CAPP president and CEO Lisa Baiton said in a statement. “As the iTotem study shows, the industry has been built on a foundation of respectful partnerships with indigenous nations and local municipalities, benefiting citizens right across the province.

“The emerging liquefied natural gas industry on the West coast is a generational opportunity that will help reduce global greenhouse gas emissions by providing some of the lowest-emission natural gas on the planet while being a source of prosperity for British Columbians and indigenous nations for decades to come.”

There is much at stake – and some controversy – as the Alberta government studies how oilsands companies can best clean up after their work in the field.

For a year, after two highly critical reports from the Alberta auditor general, the government has held consultations on potential reforms to the Mine Financial Security Program (MFSP), which is designed to protect Albertans from oilsands closure costs while maximizing the industry’s opportunities for resource development. The MFSP manages liabilities by collecting financial security from project owners and protects the public from paying for project closure costs instead of the companies that own them.

The MFSP dictates that, at the end of a project’s life, the company that owns the operation must remove all infrastructure and return the land to how it looked and how it was used before development took place. Companies must provide a full security deposit based on the estimated liabilities at the beginning of the project that guarantees that this work will be done.

The Alberta government began considering implementing some reforms in January 2022, after the auditor general’s reports, and held a series of meetings with industry representatives and area First Nations, but no public hearings were held, and no public input was sought. Government has said it expects to complete the program review in 2023 and any changes deemed necessary would be implemented starting in 2024.

“The Pathways Alliance appreciates the opportunities provided by Alberta Environment and Protected Areas (AEPA) to participate in the Mine Financial Security Program review and to hear from indigenous communities as part of that engagement,” Mark Cameron, vice-president of external relations at Pathways Alliance, told Resource World Magazine. “We understand that AEPA is currently finalizing reporting relative to the MFSP review, and we are awaiting that information.”

Oilsands cleanup costs have long been a concern. Official estimates say current cleanup costs would total $33 billion, while estimates from the Alberta Energy Regulator suggest it could be as much as $130 billion. Thus far, industry has reportedly only put up 4% of the lower figure, and that percentage is shrinking as the liability grows. Recently the Alberta Energy Regulator began accepting a type of demand bond issued by an insurance company instead of cash reserves or a line of credit, although it’s not clear how many companies are using such bonds. But some experts say that only allows producers to delay reserving the billions of dollars required for oilsands cleanup, and others say it mars the integrity of the entire review process.

The question of reforming the MFSP has sparked controversy from various sectors in the province who feel the effort will not result in meaningful reform. Some have said the program is not designed for an increasingly low-carbon world and that assumptions used in the government’s modelling of the industry’s future were unconvincing and simplistic. After government held a series of meetings with industry and area First Nations, four First Nations submitted their concerns to government in a document.

“There’s no signal to me from this government that they are going to hold industry accountable for cleanup costs,” said Mikisew Cree First Nation’s Melody Lepine. She said the stakes could not be higher, with taxpayers having billions of dollars on the line and First Nations even more.

“We’ve got nowhere else to go, it’s been our home for thousands of years,” she said. “But if it becomes a toxic wasteland, will we be forced to leave? I don’t know.”

The cost of cleanup isn’t the only problem facing the oil patch. The oil and gas sector is experiencing a skills shortage, with the current workforce now 18% smaller than it was at its peak of 225,900 in 2014. But think tank Clean Energy Canada estimates there could be 200,000 clean energy jobs created by 2030. The federal government, meanwhile, is expected to table a ΓÇÿworkforce transition’ bill in the spring which Ottawa says is meant to deal with economic changes expected on the heels of their ambitious goals to slash climate-warming emissions. That doesn’t sit well with the Alberta government, which says the legislation, if approved, will dismantle the oil and gas industry.

But amid those concerns, others welcome the Alberta government’s efforts to at least provide some certainty around the issue of oilsands cleanup.

“There has been a dramatic acceleration in retiring inactive oil and gas infrastructure in Western Canada,” Brad Herald, senior special advisor for the Canadian Association of Petroleum Producers, told Resource World.

“Industry, orphan well funds, the federal government and provincial governments have all played key roles in updating liability management policies and policy supports to make this happen. We look forward to the consultation process with the Alberta government on their proposed Liability Management Incentive Program and will work to ensure the momentum built in the reclamation of legacy sites in Alberta continues.”

Meanwhile, the industry must wait and see.

By Bruce Lantz

The jury is still out on whether an agreement between the British Columbia government and several First Nations on resource management is a positive step or just politicking.

Recently the B.C. Government signed deals with the Fort Nelson, Saulteau, Halfway River and Doig River First Nations that are expected to restart stalled oil and gas development in the Montney shale gas play in northeastern B.C. Those agreements follow on the heels of a similar agreement inked with the Blueberry River First Nation. The agreements offer a consensus on the management of land, wildlife and restoration in the area, along with a revenue-sharing deal which will support First Nations communities. The Blueberry River agreement goes even further, placing an annual cap on land that can be used for oil and gas development. The negotiations started in 2021 when the B.C. Supreme Court ruled that decades of natural resources extraction and industrial development had infringed on indigenous rights.

“Doig River First Nation has been advocating for a meaningful role in decision-making in natural resource development in our territory for many years and we are looking forward to working with the province in the months ahead to make this a reality,” said Doig River Chief Trevor Makadahay in a statement.

The Montney is a 38,000-kilometre (23,612 square miles) stretch of land that lies in the heart of Canada’s top gas-producing play. Part of the new deal exclusive to the Blueberry River First Nation puts an annual cap of 750 hectares (1853 acres) on new land that can be disturbed by oil and gas activity and protects from resource development 650,000 hectares of land that is highly valued by Blueberry River.

The agreement stipulates that Blueberry River First Nation will receive a C$87.5 million financial package over three years, with the opportunity to receive increased benefits from oil and gas revenue sharing and provincial royalty revenues in the next two fiscal years.

The province also agreed to reduce timber harvesting, put C$200 million into a land restoration fund by 2025, and work with First Nations on wildlife protection.

There is no limit on production or other activity on land that has been already disturbed by the approximately 25 companies that operate in the Montney area. And while the industry is seeking more clarity on how the land deemed available for new activity will be allocated, most leaders are cautiously optimistic.

“Anytime you change the rules there’s always some concern, but I think it’s possible to adapt,” said Tristan Goodman, president of the Explorers and Producers Association of Canada. He said he expects the B.C. Energy regulator now will be able to approve the 150-200 new oil and gas permits companies are waiting for this year.

The oil and gas industry will need to innovate to find ways to work with less land, said B.C. Premier David Eby in a statement. “It’s not a cap on production, it’s a cap on land disturbance,” he said.

The agreement has the support of the Canadian Association of Petroleum Producers (CAPP), which sees it as a joint effort by industry, the federal and B.C. governments who are aligned on key issues such as indigenous reconciliation, economic prosperity for Canadians and the need to address climate change.

“This interim agreement is a welcome step to chart a path which enables the responsible development of B.C.’s rich natural resources in a way that ensures mutual benefits for industry, indigenous nations and British Columbians across the province,” CAPP president and CEO Lisa Baiton told Resource World Magazine.

Baiton said the agreement “could provide a solution that creates certainty for companies to make their investment decisions, which would bring economic growth to the province and provide responsibly produced energy to meet a growing demand in the longer term.”

Petronas Energy Canada [PECL:TSX] CEO Izwan Ismail told a news conference, the agreement would help secure a gas supply to Canada’s first liquefied natural gas (LNG) terminal being built on B.C.’s Pacific coast.

“It is our expectation that the necessary work can now proceed to ensure that the gas Petronas Canada delivers to the LNG Canada project is responsibly produced right here in B.C., benefiting the entire province and country,” said Ismail, whose company holds a stake in the LNG export terminal being built at Kitimat, B.C.

CAPP’s Baiton said they expect investments in natural gas and LNG to grow through 2023 as LNG construction continues towards completion, along with other projects which are progressing. One of the fastest ways Canada can contribute to significantly lowering global greenhouse gas emissions is by exporting lower emission liquefied natural gas to countries who are looking to reduce their reliance on coal or Russian natural gas.

“Global demand for energy will remain strong for decades and Canada has a role to play in providing safer and lower emission resources to the world’s energy mix,” Baiton said. “Working collaboratively with government and indigenous peoples, the oil and natural gas industry can be a significant part of the solution to many of the challenges we are facing today.”

In the topsy turvy world of the oil and gas sector, turbulence is almost a way of life. And 2023 promises to be no different, especially if fears of a mid-year global recession become a reality.

In the recent Covid-filled years the industry has seen more than its share of value fluctuations, and the conflict in Ukraine added to that. In addition, ongoing concerns about climate change and the best way to deal with it – can anyone say ΓÇÿelectric vehicles’? – have had some pundits suggesting the energy industry is changing and oil and gas will soon be a thing of the past.

Of course, there were bright spots, as some companies registered record profits, thanks to shortages prompted by the Russia-Ukraine conflict, the global Covid pandemic, and political forces such as President Joe Biden’s anti-fossil fuels stance and Canada’s seeming abandonment of oil and gas in favour of more climate-friendly resources. But oil prices slumped for seven years from 2014-2022 as OPEC abandoned supply management to support oil prices, reaching an all-time low of US$3.50 a barrel in April 2020 but rising last May to US$101.17 – the highest in 14 years.

Amid all the turmoil and uncertainty and fears of the looming recession, the Canadian Association of Petroleum Producers (CAPP) is confident 2023 will be a good year for its members.

“CAPP is seeing some early positive indications in terms of capital investment in 2023,” CAPP spokesman Jay Averill told Resource World, adding that the industry generated nearly C$40 billion in domestic capital investment in 2022, with C$50 billion paid to Canadian governments.

“Canada’s oil and gas industry is proud to be a foundational pillar of the country’s economy and a source of opportunity and prosperity for all Canadians.”

But China’s move away from its zero-Covid policy, plus the continuing war in Ukraine, will add to the existing tension between supply and demand in 2023, says Deloitte in an outlook report. Additionally, OPEC-plus production cuts and moves to cap the price of Russian crude could lead to disturbances in global supply. The Deloitte author Andrew Botterill said although a windfall from higher energy prices normally would lead companies to increase their budgets and invest in larger projects, in 2023 companies likely will focus on shoring up their balance sheets and bracing themselves for continued volatility. He said companies may focus more on piloting and policy development this year before masking multibillion-dollar investments in longer-term projects.

Certainly, the world wants more Canadian oil and gas, and even government is beginning to recognize that voter priorities have shifted as people face energy shortages, war, inflation, and rising interest and mortgage rates. Even banks and institutional investors are reviewing their anti-oil investment policies now that fossil fuels are making money while many other sectors don’t.

The International Energy Agency (IEA) expects world oil demand will rise by 1.7 million barrels per day (bpd) in 2023, up to a total average of 101.3 million bpd. And other reports predict that by 2050 the global energy demand will increase by 47%, driven by both population and economic growth, with increasing demand for fossil fuels and natural gas as sources for energy. But experts warn that as these non-renewables may well run out one day, the oil and gas sector is looking to a mix of renewable and non-renewable energy sources. The U.S. Energy Information Administration (USEIA) projects that from 2020-2050 renewables eventually will make up 90% of the electric energy generated in developing countries, and worldwide shares in natural gas will drop slightly while coal-fired generation will decline through 2030 but will still be used to help support other energy sources. However, the IEA says that the efforts being made to decarbonize and live more sustainably are not enough.

The Canadian Association of Energy Contractors (CAOEC) sees a future rife with opportunity and plans to work drilling for the new energy mix, which will include oil, natural gas, LNG, geothermal, helium, lithium, hydrogen, and carbon capture and storage.

“We will carry on with our essential work of providing energy security while being champions of the energy transition,” CAOEC president and CEO Mark Scholz says in their State of the Industry Report. “The future of energy runs through our workforce, and we will proudly lead the way forward to be the world’s most carbon-efficient energy services industry.”

That way will require investment and “a renaissance” in the energy sector, says Tristan Goodman, president and CEO of the Explorers and Producers Association of Canada. He said “increased competitiveness in government policy and balanced, realistic policy discussions” are essential to attract investment.

“For this to happen, international investors need to stop seeing Canada as a hostile environment where projects take far too long to get approved and built and where regulatory goalposts are uncertain,” he said.

“A Canadian energy renaissance is poised to occur in a manner that all Canadians can support. There is enormous opportunity ahead as the world increasingly recognizes Canadian energy production can be a solution to climate challenges and energy security. The key to realizing this opportunity is making Canada the most competitive jurisdiction for investment.”

The industry and the federal government are aligning on key issues like indigenous reconciliation, economic prosperity, energy security and the need to address climate change, and Canadian oil and gas producers are positions as both secure suppliers of sustainable energy and global leaders in GHG emission reduction innovation and technology to address all of these issues concurrently, including meeting Canada’s climate change commitments.

“Global demand for energy will remain strong for decades and Canada has a role to play in providing safer and lower emission resources to the world’s energy mix,” said CAPP’s Jay Averill. “Working collaboratively with government, the oil and natural gas industry can be a significant part of the solution to many of the challenges we are facing today.”

Canada, and especially its western province of Alberta, is poised to become a world leader in the development of hydrogen power.

Alberta launched the Hydrogen Roadmap in 2021, identifying five leading markets for the province’s clean hydrogen in these sectors: Heating, where hydrogen is blended with natural gas or burned directly and used for residential and commercial heating; Power Generation and Storage, which includes generating electricity using hydrogen turbines and fuel cell generators and producing hydrogen via electrolysis from intermittent renewables for energy storage; Export Markets, which considers Alberta’s future energy competitiveness while meeting growing international demands for clean hydrogen; Transportation, which include hydrogen fuel cell vehicles, trains and aviation equipment, and co-combustion engines for heavy duty applications; and Industrial Processes, which includes fossil fuel refining and bitumen upgrading, ammonia and fertilizers.

The provincial government has invested more than $1.8 billion into CCUS-related projects and programs. And through the Alberta Petrochemical Incentive Program it committed $161 million to support the Air Products $1.6 billion net zero hydrogen complex, which will capture 95% of the carbon which will then be transported and safely stored underground.

“Our government is embracing a low-carbon future while ensuring that both hydrogen and carbon capture and sequestration are deployed safely, responsibly and strategically in the best interest of Albertans,” said Gabrielle Symbalisty, ministerial assistant to Energy Minister Pete Guthrie.

“Alberta is a global leader in responsible energy development with a proven track record in employing carbon capture on a commercial scale and a rapidly-growing hydrogen economy,” she said. “With these two strengths, we can continue diversifying our energy sector to support well-paying jobs and economic growth in Alberta for decades, while also reducing emissions.”

But a myriad of mind-boggling regulatory delays could well provide an almost unsurmountable hurdle that could send potential investors seeking safer opportunities.

Certainly, carbon capture and storage (CCS) project developers are expressing concern about regulatory restraints which are so cumbersome it can take more than five years to get approval for a project. In a recent webcast, TC Energy Corporation (TRP:NYSE) president and CEO Francois Poirier called hydrogen “a very interesting asset class for us over the course of the next decade”. But he called for accelerated regulatory processes to get projects sanctioned more quickly and said regulatory constraints present an unwelcome challenge. He said they would work with all levels of government to accelerate the regulatory process.

Regulatory constraints and the need for clarity on a path forward from a regulatory perspective are time consuming for projects. Project developers dealing with the provincial government need clarity on what’s required in terms of environmental assessment requirements, for example, along with a clear understanding of indigenous and stakeholder consultation requirements.

“In addition, the safety and regulatory standards that are required in this sort of expanded hydrogen economy are still under development,” said Jodi Anhorn, president and CEO at GLJ Ltd. (GLJ:DE) “Obviously safety and regulatory standards exist for today’s hydrogen economy and the relatively limited industrial uses that we have for hydrogen today. But if we’re going to start piping pure hydrogen across the province or cross-country and if we’re going to start using hydrogen at a refueling station, there’s a whole new set of safety and regulatory requirements that need to come out.

“Development of the safety and regulatory standards that need to be associated with expanded hydrogen economy is a big task.”

With many jurisdictions – and the corporations that operate in them – around the world seeking to develop hydrogen, especially ΓÇÿgreen’ hydrogen, as an energy source, experts say the way forward must be streamlined to ensure a speedy transition from project design to operational status. CCS projects are advancing in Norway where Equinor ASA (EQNR:NYSE) and RWE AG (RWE:HA) partnering on blue and green hydrogen production and transportation to Germany, Abu Dhabi National Oil Co. (ADNOC:AE) has earmarked $15 billion for lower-carbon efforts in that country which include hydrogen production and CCS, and Denbury Inc. (DEN:NYSE) is expending its CCS network along the United States Gulf Coast, along with many more projects worldwide.

In Alberta, the provincial government has entered into a carbon sequestration evaluation agreement with the Pathways Alliance, which represents Canada’s largest oil sands producers. The testing will help shape field development plans to support the final application for a storage agreement and further regulatory approvals for a storage hub in the Cold Lake, Alberta area and a 400-kilometre pipeline that would gather captured carbon dioxide from an anticipated 14 oil sands sites. While Alberta has a well-developed regulatory environment for oil and gas, getting the pore space for CCS is currently a challenge.

“Alberta’s government is committed to reducing red tape while keeping effective regulatory processes in place to protect environmental safety and the long-term interests of Alberta,” Symbalisty said. She said there are currently 25 proposals that are exploring the development of carbon storage hubs and are moving along the process to assess the suitability and safety of their locations.

“We are moving quickly to see these projects progress while still ensuring high safety and environmental protection standards.”

Symbalisty said that Alberta’s government is looking for ways to reduce red tape and unnecessary process on industry while maintaining high safety standards. To that end, this year they established a Designated Industrial Zone Pilot Program in the province’s industrial heartland – where most of the key petrochemical investments in the province are planned – to streamline regulatory approvals and improve competitiveness. Additionally, since 2019 the Alberta Energy and Alberta Affordability and Utilities ministries have cut more than 23,000 pieces of red tape on the advice of industry and have made more than 7,600 reductions to regulations across the energy sector, she said.

Equally important is making headway with cumbersome federal regulations, said Symbalisty.

“Regulatory certainty from all levels of government is key for industry and potential investors,” she said. “Alberta’s government is doing its part to improve regulatory delays, but we need to see a matching effort by the federal government to ensure our industries can compete on an international scale for these projects that will drive job creation and economic growth.”

According to pronouncements from the world’s environmentalists and climate change aficionados, we are quickly moving towards a fossil-free planet. Oil and gas, along with coal and other nonrenewable energy sources, will soon be a thing of the past, they say.

And there is some truth to their claims. For example, Nova Scotia, sitting on Canada’s East Coast, faces more warmth and rain with increased risk of floods, wildfires and crop-killing intense heat due to climate change, according to a risk assessment – using high carbon emissions scenarios because it says that’s the path the world is on – released by the provincial government this month.

“Climate change is having an impact on the health and well-being of our province,” said Alex Cadel, a climate specialist with the Nova Scotia Department of Environment and Climate Change, in a statement.

The report predicts that the province will see that temperatures above 29C will increase to two weeks annually, up from just two days in the 1990s, while the number of snowy days annually will drop from 39 in the 1990s to 25 by 2050 and just 17 in the 2080s. Rain will increase, sea level will rise a metre by the end of the century and sea surface temperatures will rise nearly three degrees, the report predicts. Peak winds will rise by 7 kilometres an hour by the end of the century, the assessment predicts, and sea levels will rise a metre by that time. It says flooding will be the greatest concern in the 2030s, wildfires will be the biggest threat by 2050, and by the 2080s extreme temperatures that could disrupt food production, human health, infrastructure and ecosystems will be the major concern.

“The climate crisis demands urgent attention from all of us,” the report concludes.

“We’re already past the point of pushing it down the road,” said Will Balser of the Ecology Action Centre in Halifax, NS. “We’re already feeling the effects of this. And so, I think going forward we just need to be very clear on what we value most and what we’re preparing to protect.”

In the wake of the recent pandemic, the Russia-Ukraine conflict and record-high oil and gas prices, the world is in a “critical decade” for delivering a more secure, sustainable and affordable energy system, according to the World Energy Outlook 2022 report by the International Energy Agency (IEA). Today’s situation underlines the benefits of greater energy efficiency and are prompting behavioural and technology changes in some countries to reduce energy use, the report says, but net zero emissions by 2050 won’t be achieved without a huge increase in energy investment.

“The potential for faster progress is enormous if strong action is taken immediately.”

But that wariness about the future doesn’t mean the use of fossil fuels must end, at least not immediately. The IEA said in a recent report that oil and gas will remain critical long into the future. The world uses oil and gas on a massive scale, more than just fuel for vehicles, the report said.

“Even in the net zero carbon scenario . . . oil and gas are still significant energy resources,” said energy analyst Daniel Yergin in a recent podcast hosted by the Washington, D.C.-based Brookings Institute think tank. Yergin cited oil-based polyurethane nylon clothing, airplane bodies which are carbon products and even Tylenol, another oil product, as examples.

The IEA forecasts that oil and gas will remain central to the global energy system through 2050. In 2021 it supplied 52% of the world’s energy needs and the IEA predicts it will still provide 47% in 2050. Meanwhile, renewable energy’s share of global supply will increase to 20% in 2050 from 12% in 2021, and coal’s share will decline to 15% in 2050 from 27% in 2021.

Significantly, the U.S. Energy Information Administration (EIA) recently raised its forecast for this year’s crude output growth marginally, while petroleum demand is likely to rise less than previously expected. The EIA projected that crude production would rise to 11.87 million barrels per day (bpd) in 2022, compared with its previous estimate of 11.83 million bpd. Petroleum and other liquid fuels consumption would rise to 20.36 million bpd in 2022, lower than the prior forecast of 20.38 million bpd. For 2023, the EIA projected that crude production would rise to 12.34 million bpd. That compares with a record 12.29 million bpd in 2019. Next year, petroleum and other liquid fuels consumption is expected to rise to 20.51 million bpd, from a previous estimate of 20.48 million bpd.

Canada could become the world’s leading supplier of oil and gas. Its oil sands are the only major oil basin where producers have jointly committed to reach net zero emissions by 2050, while its liquefied natural gas (LNG) will have among the lowest emissions per tonne, which will help the world reduce its reliance on coal.

The IEA projects that oil demand will grow to 102 million bpd from 94.5 million bpd in 2021 and will hold at 102 million bpd in 2050. Similarly, natural gas is projected to grow to 4.4 trillion cubic metres in 2030, from 4.2 trillion in 2021, and stay there through 2050. Even if the IEA’s net zero scenario comes true, in 2050 oil and gas would still supply 15% of the world’s energy needs. Achieving that 2050 goal is unlikely, given that two of the world’s largest emitters, China and India, have only pledged to reach net zero by 2060 and 2070, respectively.

So, maintaining investment is oil and gas is important even as the world strives to reduce emissions, Yergin said.

“The reality is that the world still uses 80% of its energy from hydrocarbons. Just to maintain production you need new investment,” he said.

“For those who say we shouldn’t invest anything in fossil fuels now, I remind you that we have to feed the system we have today while we’re moving toward the new system. This will be a difficult tightrope to walk. But it’s where we are.”