New analysis commissioned by the Alberta Energy Regulator has increased the province’s natural gas reserves by 440 per cent, bumping Canada into the global top 10.

Alberta’s oil reserves – already fourth in the world – also increased by seven billion barrels.

The report was conducted by Calgary-based consultancy McDaniel & Associates. Executive vice-president Mike Verney explains what it means.

CEC: What are “reserves” and why do they matter?

Verney: ​​Reserves are commercial quantities of oil and gas to be recovered in the future. They are key indicators of future production potential.

For companies, that’s a way of representing the future value of their operations. And for countries, it’s important to showcase the runway they have in terms of the future of their oil and gas.

Some countries that have exploited a lot of their resource in the past have low reserves remaining. Canada is in a position where we still have a lot of meat on the bone in terms of those remaining quantities.

CEC: How long has it been since Alberta’s oil and gas reserves were comprehensively assessed?

Verney: Our understanding is the last fully comprehensive review was over a decade ago.

CEC: Does improvement in technology and innovation increase reserves?

Verney: Technological advancements and innovation play a crucial role in increasing reserves. New technologies such as advanced drilling techniques (e.g., hydraulic fracturing, horizontal drilling), enhanced seismic imaging and improved extraction methods enable companies to discover and access previously inaccessible reserves.

As these reserves get developed, the evolution of technology helps companies develop them better and better every year.

CEC: Why have Alberta’s natural gas reserves increased?

Verney: Most importantly, hydraulic fracturing has unlocked material volume, and that’s one of the principal reasons why the new gas estimate is so much higher than what it was in the past.

The performance of the wells that are being drilled has also gotten better since the last comprehensive study.

The Montney competes with every American tight oil and gas play, so we’re recognizing the future potential of that with the gas reserves that are being assigned.

In addition, operators continue to expand the footprint of the Alberta Deep Basin.

CEC: Why have Alberta’s oil reserves increased?

Verney: We discovered over two billion barrels of oil reserves associated with multilateral wells, which is a new technology. In a multilateral well, you drill one vertical well to get to the zone and then once you hit the zone you drill multiple legs off of that one vertical spot. It has been a very positive game-changer.

Performance in the oil sands since the last comprehensive update has also gone better than expected. We’ve got 22 thermal oil sands projects that are operating, and in general, expectations in terms of recovery are higher than they were a decade ago.

Oil sands production has grown substantially in the past decade, up 70 per cent, from two million to 3.4 million barrels per day. The growth of several projects has increased confidence in the commercial viability of developing additional lands.

CEC: What are the implications of Alberta’s reserves in terms of the province’s position as a world energy supplier?

Verney: We’re seeing LNG take off in the United States, and we’re seeing lots of demand from data centers. Our estimate is that North America will need at least 30 billion cubic feet per day of more gas supply in the next few years, based on everything that’s been announced. That is a very material number, considering the United States’ total natural gas production is a little over 100 billion cubic feet per day.

In terms of oil, since the shale revolution in 2008 there’s been massive growth from North America, and the rest of the world hasn’t grown oil production. We’re now seeing that the tight plays in the U.S. aren’t infinite and are showing signs of plateauing.

Specifically, when we look at the United States’ largest oil play, the Permian, it has essentially been flat at 5.5 million barrels per day since December 2023. Flat production from the Permian is contrary to the previous decade, where we saw tight oil production grow by half a million barrels per day per year.

Oil demand has gone up by about a million barrels a day per year for the past several decades, and at this point we do expect that to continue, at the very least in the near term.

Given the growing demand for oil and the stagnation in supply growth since the shale revolution, it’s expected that Alberta’s oil sands reserves will become increasingly critical. As global oil demand continues to rise, and with limited growth in production from other sources, oil sands reserves will be relied upon more heavily.

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There’s extensive discussion today about energy transition and transformation. Its primary focus is a transition from fossil fuels to lower-carbon energy sources.

But in Alberta, a fundamental but different energy transition has already taken place, and its ripple effects stretch into businesses and communities across the province.

The shift has affected the full spectrum of oil and gas activity: where production happens, how it’s done, who does it and what type of energy is produced.

Oil and gas development in Alberta today largely happens in different places and uses different technologies than 20 years ago. As a result, the companies that support activity and the communities where operations happen have had to change.

Regional Shift

For the first decade of this century, in terms of numbers of wells, most drilling activity happened in central and southeast Alberta, with companies primarily using vertical wells to target conventional shallow natural gas deposits.

In 2005, producers drilled more than 8,000 natural gas wells in these areas, according to Alberta Energy Regulator (AER) records.

But then, three things happened. The price of natural gas declined, the price of oil went up and new horizontal drilling technology unlocked vast energy resources that were previously uneconomic to produce.

By 2015, the number of natural gas wells companies drilled in central and southeast Alberta was just 256. In 2023, the number dropped to only 50. Over approximately 20 years, activity dropped by 99 per cent.

Where did the investment capital go? The oil sands and heavy oil reserves of Alberta’s northeast and shale plays, including the Montney and Duvernay, in the province’s foothills and northwest.

Nearly 60 per cent of activity outside of the oil-rich northeast occurred in central and southeast Alberta in 2005. By 2023, overall oil and gas drilling in those regions had dropped by 30 per cent, while at the same time increasing by 159 per cent in the foothills and northwest.

“The migration of activity from central and southern Alberta to other regions of the province has been significant,” says David Yager, a longtime oil and gas service company executive who now works as a special advisor to Alberta Premier Danielle Smith.

“For decades there were vibrant oil service communities in places like Medicine Hat, Taber, Brooks, Drumheller and Red Deer,” he says.

“These [oil service communities] have contracted materially with the new service centres growing in places like Lloydminster, Bonnyville, Rocky Mountain House, Edson, Whitecourt, Fox Creek and Grande Prairie.”

Fewer Wells and Fewer Rigs

Extended-reach horizontal drilling compared to shallow, vertical drilling enables more oil and gas production from fewer wells.

Outside the oil sands, in 2005, producers in Alberta drilled 17,300 wells. In 2023, that dropped to just 3,700 wells, according to AER data.

Despite that massive nearly 80 per cent decrease in wells drilled, total production of oil, natural gas and natural gas liquids outside of the oil sands is essentially the same today as it was in 2005.

Last year, non-oil sands production was 3.1 million barrels of oil equivalent (boe) per day, compared to 3.4 million boe per day in 2005–but from about 13,600 fewer new wells.

Innovation from drilling and energy services companies has been a major factor in achieving these impressive results, says Mark Scholz, CEO of the Canadian Association of Energy Contractors. But there’s been a downside.

Yager notes that much of the drilling and service equipment employed on conventional oil and gas development is not suited for unconventional resource exploitation.

Scholz says the productivity improvements resulted in an oversupply of rigs, especially rigs with limited depth ratings and limited capability for “pad” drilling, where multiple wells are drilled the same area on the surface.

Rigs have been required to drill significantly deeper wellbores than in the traditional shallow gas market, he says.

“This has resulted in rig decommissioning or relocations and a tactical effort to upgrade engines, mud pumps, walking systems and pipe-handling technology to meet evolving customer demands,” he says.

“You need not go beyond the reductions in Canada’s drilling rig fleet to understand the impact of these operational innovations. Twenty years ago, there were 950 drilling rigs; today, we have 350, a 65 per cent reduction. [And] further contractions are likely in the near term.”

Scholz says, “collaboration and partnerships between producers and contractors were necessary to make this transition successful, but the rig fleet has evolved into a much deeper, technologically advanced fleet.”

A Higher Cost of Entry

Yager says that along with growth in the oil sands, replacing thousands of new vertical shallow gas wells with fewer, high-volume extended-reach horizontal wells has made it more challenging for smaller companies to participate.

“The barriers to entry in terms of capital required have changed tremendously. At one time a new shallow gas well could be drilled and put on stream for $150,000. Today’s wells in unconventional plays cost from $3 million to $8 million each,” he says.

“This has materially changed the exploration and production companies developing the resource, and the type of oilfield services equipment employed. An industry that was once dominated by multiple smaller players is increasingly consolidating into fewer, larger entities. This has unintended consequences that are not well understood by the public.”

More Oil (Sands), Less Gas

Higher oil prices and horizontal drilling helped change Alberta from a natural gas hotbed to a global oil powerhouse.

In the oil sands, horizontal wells enabled a key technology called steam assisted gravity drainage (SAGD), which went into commercial service in 2001 to allow for a massive expansion of what is referred to as in situ oil sands production.

In 2005, mining dominated oil sands production, at about 625,000 barrels per day compared to 440,000 barrels per day from in situ projects. In situ oil sands production exceeded mining for the first time in 2013, at 1.1 million barrels per day compared to 975,000 barrels per day from mining.

Today the oil sands production split is nearly half and half. Last year, in situ projects–primarily SAGD–produced approximately 1.8 million barrels per day, compared to about 1.7 million barrels per day from mining.

Natural gas used to exceed oil production in Alberta. In 2005, natural gas provided 54 per cent of the province’s total oil and gas supply. Nearly two decades later, oil accounts for 60 per cent compared to 29 per cent from natural gas. The remaining approximately 11 per cent of production is natural gas liquids like propane, butane and ethane.

Alberta’s non-renewable resource revenue reflects the shift in activity to more oil sands and less natural gas.

In 2005, Alberta received $8.4 billion in natural gas royalties and $950 million from the oil sands. In 2023, the oil sands led by a wide margin, providing $16.9 billion in royalties compared to $3.6 billion from natural gas.

Innovation and Emerging Resources

As Alberta’s oil and gas industry continues to evolve, another shift is happening as investments increase into emissions reduction technologies like carbon capture and storage (CCS) and emerging resources.

Since 2015, CCS projects in Alberta have safely stored more than 14 million tonnes of CO2 that would have otherwise been emitted to the atmosphere. And more CCS capacity is being developed.

Construction is underway on an $8.9-billion new net-zero plant producing polyethylene, the world’s most widely used plastic, that will capture and store CO2 emissions using the Alberta Carbon Trunk Line hub. Two additional CCS projects got the green light to proceed this summer.

Meanwhile, in 2023, producers spent $700 million on emerging resources including hydrogen, geothermal energy, helium and lithium. That’s more than double the $230 million invested in 2020, the first year the AER collected the data.

“Energy service contractors are on the frontlines of Canada’s energy evolution, helping develop new subsurface commodities such as lithium, heat from geothermal and helium,” Scholz says.

“The next level of innovation will be on the emission reduction front, and we see breakthroughs in electrification, batteries, bi-fuel engines and fuel-switching,” he says.

“The same level of collaboration between service providers and operators that we saw in our productivity improvement is required to achieve similar results with emission reduction technologies.”

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It’s massive, recognized to have low emissions, and has some of the most competitive energy economics in North America.  

The Montney play in northern B.C. and Alberta has become the driving force of Canada’s natural gas industry. It’s also the foundation of Canada’s emerging liquefied natural gas (LNG) exports, and new deals signal it will continue to pick up steam.  

“This immense resource remains the primary focus of most Canadian gas producers,” RBN Energy analyst Martin King wrote recently, describing the Montney as having “inexhaustible energy.”  

The play has grown from next to no production in 2005 to just over half of all the natural gas produced in western Canada as of September 2022, he said. Growth is expected to continue in the years ahead given the play’s “gargantuan reserves and prolific wellhead productivity.” 

Canada’s natural gas powerhouse 

The Montney holds about half of Canada’s natural gas resources, according to the Canada Energy Regulator (CER). This year it is also expected to offer the highest investment payback of any natural gas play in North America, according to Rystad Energy. 

“Even during years of really bad natural gas volatility, particularly between 2017 and 2019, the Montney still performed on par with the U.S. gas plays, so those returns are quite resilient,” said Tom Liles, Rystad’s vice-president of upstream research.  

Driving the expected strong results in 2023 is the Montney’s presence of higher value “liquids” like condensate and pentanes-plus – used to dilute bitumen for pipeline transportation – in addition to dry natural gas, Liles said.  

Producers are also finding innovative ways to reach customers, including LNG contracts in the U.S. and Canada. 

Montney natural gas will feed west coast LNG projects including the LNG Canada terminal under construction and the Woodfibre LNG project that is expected to start building this year. And more activity is taking shape. 

Montney deals and LNG 

On Mar. 14, provincial and federal regulators issued approval to the Indigenous-led Cedar LNG project to proceed. At the same time, partners Haisla Nation and Pembina Pipeline announced a 20-year supply deal with Montney producer ARC Resources.  

On Mar. 28, long-time Saskatchewan operator Crescent Point Energy announced a $1.7 billion Montney acquisition giving it 600 drilling locations in the play, or enough to keep busy for the next 20 years.  

The CER projects Montney natural gas production will “grow significantly” through 2050, along with increases in Canada’s LNG exports, even under more aggressive climate policies. 

Driven by growing Asian economies looking to get off coal power, world LNG demand is projected to nearly double to reach 700 million tonnes per year by 2040.  

Reducing emissions 

Once Montney natural gas reaches terminals built on the B.C. coast, it has the potential to reduce world emissions to help fight climate change. 

According to Wood Mackenzie, LNG from Canada could reduce Asia’s net emissions by 188 million tonnes of CO2 equivalent per year through 2050 – or the annual impact of taking 41 million cars off the road.   

A smaller LNG footprint 

LNG projects on Canada’s west coast are expected to have emissions intensity that is less than half the global average.   

“Not all LNG is created equal,” researchers with the University of Calgary and University of Toronto wrote in 2021.  

They found the emissions intensity of the LNG Canada terminal to be lower than U.S. competitors. It’s a result of Canada’s colder climate, shorter shipping distances to Asia, the use of hydroelectric power, and success in methane emissions reduction.  

The findings affirmed a 2019 regulatory permit in Washington state requiring natural gas supply for the Tacoma LNG project to come from B.C. or Alberta.   

The Puget Sound Clean Air Authority found natural gas produced in western Canada to be cleaner than natural gas produced in the United States, stating that methane emissions in the U.S. “may be as much as five times higher than those from Canada.”   

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