New oil and gas drilling company launched by Indian Resource Council of Canada

From the Canadian Energy Centre

By Mario Toneguzzi and Deborah Jaremko

‘This is a great opportunity for our members to be on the ground floor of a First Nations-supported energy services company’

Indigenous ownership in Canadian oil and gas continues to grow with the launch of a new drilling company.

Along with industry heavyweights, the Indian Resource Council of Canada (IRC) is one of the founding partners of newly-formed Indigena Drilling. IRC’s aim is to provide economic benefits to its more than 155 member nations across the country.

“[This] is a great opportunity for our members to be on the ground floor of a First Nations-supported energy services company,” said Stephen Buffalo, Indian Resource Council CEO.

Gurpreet Lail, CEO of Enserva, a national trade association representing the service, supply, and manufacturing sectors of the Canadian energy industry, welcomes the new company.

“There are so many discussions happening around Indigenous economic reconciliation, but this actually is doing that instead of just talking about it,” she said.

“This kind of partnership is actually going to help all Nations, not just one.”

Indigena Drilling is an evolution of the relationship between Indigenous communities and drilling operators, says Mark Scholz, CEO of the Canadian Association of Energy Contractors (CAOEC).

“We see a lot of joint partnerships within the industry where it could be ownership or shared ownership of a rig, but I think this is a unique one coming from the lens of a company starting out with significant ownership from an Indigenous perspective would be quite new, at least in the last 10, 20 years,” he said.

Historically it has been more common for Indigenous partnerships on the service rig side of the industry, Scholz said. The main difference is that smaller service rigs conduct work on existing wells, versus drilling rigs that drill new wells.

“A service rig can actually stay very tethered to a particular area and doesn’t have to move long distances, so it’s actually quite conducive to a lot of First Nations communities that often want to stay in the community,” Scholz said.

The CAOEC forecasts approximately 6,400 wells will be drilled across western Canada this year, an increase of about 800 wells compared to 2022.

Scholz said he expects more Indigenous ownership examples like Indigena in the future, particularly in British Columbia, because of the tremendous drilling opportunities that are going to exist in supporting liquefied natural gas (LNG) exports.

“Obviously long-term, both Alberta and British Columbia have huge gas reserves. As we start talking about the energy transformation, gas is going to be incredibly important,” he said.

“I think we’re going to see more LNG takeaway capacity that’s going to have First Nations support and I do see additional opportunities for First Nations communities to have a very robust energy services sector within their communities that they’re going to be operating in.”

Lail said there are more Indigenous-owned energy services companies today than previously, but more need to come into the space.

“As an industry on the whole, I think we’ve done a really good job at moving the needle but there’s more movement that needs to happen,” she said.

“I think this is a good news story and I hope we get more of these into the future.”

Related Topics:#CanadianEnergyCentre #DeborahJaremko #IndianResourceCouncilOfCanada #IndigenaDrilling #MarioToneguzzi #StephenBuffalo

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Ottawa’s oil and gas emissions cap will hit Alberta with a wallop

Published on November 8, 2024

Todayville

From the Fraser Institute

By Kenneth P. Green

Even if Canada eliminated all its GHG emissions expected in 2030 due to the federal cap, the emission reduction would equal only four-tenths of one per cent of global emissions—a reduction unlikely to have any impact on the trajectory of the climate in any detectable manner or produce any related environmental, health or safety benefits.

After considerable waiting, the Trudeau government released on Monday draft regulations to cap greenhouse gas (GHG) emissions from Canada’s oil and gas producers.

The proposed regulations would set a cap on GHG emissions equivalent to 35 per cent of the emissions produced in 2019 and create a GHG emissions “cap and trade” system to enable oil and gas producers (who cannot reduce emissions enough to avoid the cap) to buy credits from other producers able to meet the cap. Producers unable to meet the cap will also be able to obtain emission credits (of up to 20 per cent of their needed emission reductions) by investing in decarbonization programs or by buying emission “offsets” in Canada’s carbon markets.

According to the government, the cap will “cap pollution, drive innovation, and create jobs in the oil and gas industry.” But in reality, while the cap may well cap pollution and drive some innovation, according to several recent analyses it won’t create jobs in the oil and gas industry and will in fact kill many jobs.

For example, the Conference Board of Canada think-tank estimates that the cap would reduce Canada’s GDP by up to $1 trillion between 2030 and 2040, kill up to 151,300 jobs across Canada by 2030, and national economic growth from 2023 to 2030 would slow from 15.3 per cent to 14.3 per cent.

Not surprisingly, Alberta would be hardest hit. According to the Board, from 2023 to 2030, the province’s economic growth would fall from an estimated 17.8 per cent to 13.3 per cent and employment growth would fall from 15.8 per cent to 13.6 per cent over the same period. Alberta government revenues from the sector would decline by 4.5 per cent in 2030 compared to a scenario without the cap. As a result, Alberta government revenues would be $4.5 billion lower in nominal terms in fiscal year 2030/31. And between 54,000 to 91,500 of Canada’s job losses would occur in Alberta.

Another study by Deloitte estimates that, due to the federal cap, Alberta will see 3.6 per cent less investment, almost 70,000 fewer jobs, and a 4.5 per cent decrease in the province’s economic output (i.e. GDP) by 2040. Ontario would lose more than 15,000 jobs and $2.3 billion from its economy by 2040. And Quebec would lose more than 3,000 jobs and $0.4 billion from its economy during the same period.

Overall, according to Deloitte, Canada would experience an economic loss equivalent to 1.0 per cent of GDP, translating into lower wages, the loss of nearly 113,000 jobs and a 1.3 per cent reduction in government tax revenues. (For context, Canada’s economic growth in 2023 was only 1.1 per cent.)

And what will Canadians get for all that economic pain?

In my study published last year by the Fraser Institute, I found that, even if Canada eliminated all its GHG emissions expected in 2030 due to the federal cap, the emission reduction would equal only four-tenths of one per cent of global emissions—a reduction unlikely to have any impact on the trajectory of the climate in any detectable manner or produce any related environmental, health or safety benefits.

Clearly, the Trudeau government’s new proposed emissions cap on the oil and gas sector will impose significant harms on Canada’s economy, Canadian workers and our quality of life—and hit Alberta with a wallop. And yet, as a measure intended to avert harmful climate change, it’s purely performative (like many of the government’s other GHG regulations) and will generate too little emission reductions to have any meaningful impact on the climate.

In a world of rational policy development, where the benefits of government regulations are supposed to exceed their costs, policymakers would never consider this proposed cap. The Trudeau government will submit the plan to Parliament, and if the cap becomes law, it will await some other future government to undo the damage inflicted on Canadians and their families.

Author:

Kenneth P. Green

Senior Fellow, Fraser Institute

Alberta

For second year in a row, Alberta oil and gas companies spend more than required on cleanup

Published on November 7, 2024

Todayville

From the Canadian Energy Center

By Grady Semmens

$923 million spent cleaning up inactive wells, sites and pipelines in 2023

As a business owner, Ryan Smith values few things more than predictability when it comes to the oil and gas market and the demand for his company’s services.

That’s why knowing that next year in Alberta, the regulator requires at least $750 million worth of work cleaning up inactive oil and gas wells and other legacy energy infrastructure is tremendously helpful for the CEO of Calgary-based 360 Engineering & Environmental Consulting.

“Having a minimum spend in place for the province makes the market more predictable and consistent, which in turn helps our clients and our business plan for the future, which is a good thing,” says Smith, whose company has completed more than 5,000 site closure activities in Canada and internationally since 2015.

“Site closure has really emerged as a growth market over the last decade, especially in Western Canada where the regulatory systems for oil and gas are more advanced than anywhere else we are exposed to. It is an integral part of the energy lifecycle, and if it is done well it adds a lot of value to the industry.”

The Alberta Energy Regulator (AER) introduced an industry-wide minimum “closure” spending requirement in 2022, part of Alberta’s Inventory Reduction Program to accelerate the remediation of inactive oil and gas wells, facilities and pipelines across the province.

The mandatory quota determines the minimum level of work a company must conduct primarily to decommission and reclaim a proportion of its inactive inventory.

Inactive wells are defined as those that have not been used for six months or a year, depending on what they are being used for. When a company decides that they will not reactivate an inactive well they decommission it through a process called abandonment.

A well is considered successfully abandoned after it is cleaned, plugged with cement, cut to a minimum of one meter below the surface and covered with a vented cap. After abandonment comes remediation and reclamation, where the land around the well is returned to the equivalent of its original state.

The first two years under the new rules saw Alberta’s energy industry significantly exceed the minimum closure requirements.

In 2022, companies spent more than $696 million, about 65 per cent more than the initial threshold of $422 million. The AER increased the minimum spend to $700 million in 2023, which producers surpassed by 22 per cent with total expenditures of $923 million.

The 2024 minimum remains at $700 million, while in July the regulator announced that the minimum spend for 2025 was raised to $750 million.

This closure work does not include remediation of oil sands mining sites, which is handled under the Mine Financial Security Program, nor does it include the closure of orphan wells (wells without a legal owner) managed by the industry-funded Orphan Well Association.

Gurpreet Lail, CEO of Enserva, an industry association representing energy service companies, suppliers and manufacturers, says there was an initial rush of closure work when the quotas were first put in place, but activity has since become more even as companies develop long-term closure plans.

“A lot of the low-lying fruit has been taken care of, so now companies are working on more complex closure files that take more time and more money,” Lail says.

Facility owners say that Alberta’s rules provide direction for planning closure and remediation work, which in the past may have been put on hold due to the ups and downs of the oil and gas market.

“When commodity prices are up, everyone is focused on drilling more wells and when prices are down, budgets are strained for doing work that doesn’t bring in revenue. Having a minimum spend makes sure closure work happens every year and ensures there is longer-term progress,” says Deborah Borthwick, asset retirement coordinator for Birchcliff Energy, an oil and natural gas producer focused in Alberta.

Over the last few years, Birchcliff has budgeted more than $3 million for annual facility closure work, far above its required minimum spend.

The company completed 11 well abandonments and decommissioned 23 facilities and pipelines in 2022, according to its latest environmental, social and governance report.

Borthwick says having the closure quota for 2025 already set has allowed it to plan ahead and line up the necessary service companies well in advance for next year’s remediation work.