Editor’s note: The last five years have been a hard ride for Canadian oil and gas producers.

Wild price volatility, a pandemic-induced price crash, ongoing market access issues, oil production curtailment, the rise of the ESG movement, and finally a geopolitical crisis are just some of the challenges industry faced.

The end result of this period of instability is a reinvigorated industry ready to take on the world as the commodity cycle turns once again.

The 2022 Top Operators Report examines the 2017-2021 timeframe, identifying key trends that shaped the present energy landscape and what lies ahead for the 62 Canadian headquartered public operators tracked this year.

To sort through these challenges we are once again leveraging the experience of professional services firm KPMG in Canada to provide insight into the last five years of change and what strategies operators could pursue to thrive in the inevitable turbulence ahead.

Data analysts from Evaluate Energy are providing context to the stream of information coming from corporate financial reporting and other relevant documents. Analysts from geoLOGIC systems ltd. offer context into trends in activity and technology to manage costs.

We’re also tapping into a broad swath of the insights and opinions from industry leaders gleaned from Daily Oil Bulletin coverage.

To download the 2022 Top Operators Report, click here.

Canada’s oil and gas producers have a wealth of growth opportunities in the next decade as new avenues open for oil and gas exports, but to take advantage they need to start investing cash flow back into reserves and production.

Both the short- and mid-term outlook for natural gas is positive, said Martin King, senior analyst with RBN Energy LLC.

Alberta’s current natural gas storage levels are well below average, said King. In April the province saw its first net gas withdrawal since 1995. By March 2023, natural gas in storage in Alberta could be at its lowest level since 2006. “This is quite a way back we’re going, about 16 or 17 years now, in terms of storage lows. And so, it is going to be a very interesting summer of injections, or slow injections, for Alberta.”

Longer term, King said internal demand for power and oilsands expansion will drive demand, as well as LNG expansion across North America. Hydrogen production could also add to that demand. “The supply growth here could be in the range of five bcf/d, or about 30 per cent, from 2021 to 2027. So it’s a pretty aggressive outlook.”

Natural gas producers need to start turning resources into reserves if the sector hopes to capture this opportunity, particularly in Alberta, said Darren Gee, president and chief executive officer of Peyto Exploration & Development Corp. “Alberta needs drillers. We talk about it as if we have unlimited reserves in this basin that we can do things with, but the reality is that the established reserve life in Alberta is the shortest that it has been in 40 years. It has less than eight years right now.”

New technologies have accelerated resource extraction without really extending the reserve life, he explained, as one reason for the shortened reserve life.

“If we could open up to new markets, we could really add new drilling rigs in the fleet, more people working in this industry, we could attract more people back to develop those resources that are going to feed those markets, and then we could really start getting after it here in Western Canada.”

Condensate and NGL supply is also tight and could get tighter with expected growth in the oilsands, added Terry Anderson, president and chief executive officer of ARC Resources Ltd. “We look at it as being very constructive going forward for the foreseeable future. I’d say the dynamics right now are very supportive.”

Natural gas well licensing and drilling activity has been strong in the major resource plays, said Alex Renaud, senior engineering advisor with geoLOGIC systems ltd. Almost 5,300 wells were licensed targeting the Montney from 2017-2021, with 743 licensed in the Duvernay, and over 1,000 in the Deep Basin targeting the Spirit River formation. Over 6,350 wells were drilled (1,250 wells averaged across the five years).

But the number of wells drilled could be higher, said Renaud. From the beginning of 2017 to the end of 2021, only 72 per cent of the wells licensed in the Montney have been drilled.

Activity on the Alberta side of the Montney has focused on the liquids-rich Elmworth and Kakwa areas, where over 1,000 wells were drilled. In B.C., the Heritage field continues to dominate but there is growing activity in the North Montney, said Renaud. Gas production is up over 62 per cent over the last five years in the Montney, with oil and liquids production up 49 per cent.

Recent acquisitions by Canada’s biggest gas operators have given them the scale to supply LNG exporters and grow NGL markets. ARC has deals in place to supply both LNG Canada and U.S. Gulf Coast exports.

Tourmaline Oil Corp. currently has 620 mmcf/d entering U.S. markets on long-term transport agreements. The company expects this to reach 905 mmcf/d by the end of 2023. In addition, Tourmaline has a 140 mmcf/d Gulf Coast LNG deal with Cheniere Energy Inc. that commences in January of next year.

With numerous development opportunities, operators are building out regional hubs with processing infrastructure in place then drilling to fill that infrastructure to meet demand while containing costs. An example of this is Tourmaline’s Conroy North Montney development, a planned 100,000-boe/d liquids-rich gas project. Tourmaline recently bought out the remaining 50 per cent interest in two gas plants that came with its Black Swan Energy acquisition as part of the Conroy build out.

“We are going to continue to grow Tourmaline in a meaningful way,” said Mike Rose, Tourmaline’s president and chief executive officer, adding Conroy North development is on track for full-project startup in 2025-2026, in-step with the launch of LNG Canada. “It was important for us to consolidate to 100 per cent in the North Montney facilities prior to embarking on a significant build out over the next few years.”

As LNG projects become operational there will be less gas supply for the rest of Western Canada and North America. This could result in two bcf/d no longer flowing on pipelines, said King. “It appears the market is structurally building towards strong pricing. We’ll see how it shakes out.”

Current high commodity prices have driven “a surge in profitability creating a generational opportunity,” said Mike Belenkie, Advantage Energy Ltd.’s president and chief executive officer. Advantage is planning for 10 per cent production growth annually going forward.

Advantage’s Montney Glacier dry gas assets and related infrastructure provide the base for future growth. “We’re drilling the best wells in company history and we’re not drilling all our best opportunities,” he explained. Advantage drilled 14 of the top 25 gas producing wells in the Alberta Montney in 2021.

The company continues its focus on low supply costs and combined with high production volumes it is having a massive impact on profitability. Since 2020, Advantage has seen payout ratios average between three and 12 months. “Cost control is part of our DNA. Our last 12 wells had a little over a four-month payout. It’s an unusual time with high prices but our low-cost structure is a key factor. In some cases we doubled our payout in less than a year.”

The company is diversifying its production into liquids-rich areas of the Montney. It is targeting oil production at Wembley and Progress, and liquids-rich gas and oil at Valhalla. “These areas are highly prolific,” said Belenkie. “They are the future of the company for decades to come.”

Canadian operators have chosen to focus on oil development rather than gas development, said geoLOGIC’s Renaud. “The vast majority of the wells spudded from 2017 to 2021 are now active oil producers numbering roughly 13,900, followed by active gas producers totaling 5,231 wells. Almost 660 water producing wells were also brought onstream over this period.”

Oil well licensing and drilling the last five years were driven by operators maintaining production plateaus in mature tight oil plays and exploration and development drilling in Alberta plays.

In Saskatchewan, 3,371 wells were drilled targeting the Viking tight oil play, with another 770 targeting the Bakken. Another 1,572 wells were drilled targeting the more conventional Frobisher and Midale Bed formations. Despite the ongoing developing drilling, oil production from these plays has yet to recover to pre-pandemic levels, outside of the Viking, said Renaud.

In Alberta, the Clearwater dominated activity with 2,477 wells drilled in the play in the last five years. Oil production rocketed from a little over 4,300 bbls/d in 2017 to exit 2021 at over 60,000 bbls/d.

The trend of targeting oil and liquids has been particularly strong in Alberta, said Renaud. Production growth from the Clearwater, Charlie Lake, Montney and Duvernay climbed by 114 per cent from 2017-2021, and exited the first quarter of 2022 at over 286,000 bbls/d.

Alberta bitumen and western Canadian crude production should get close to record levels over the summer, King said, with Alberta production in 2022 pushing though 3.5 million bbls/d. Industry recovery on the crude side has been oilsands related, with some light-oil wells shut-in during the pandemic yet to come back on production.

In terms of oil egress, King said delays in completion of the Trans Mountain pipeline expansion could result in pipe congestion in the mid-to-late 2023 timeframe.

David Hughes, vice-president, investor relations at Imperial Oil Limited, said the oil egress situation remains “relatively balanced” for the time being. “With the Line 3 expansion coming online, if you want to get barrels on a pipe, then you can get barrels on a pipe. But it doesn’t leave a lot of room for any material growth.”

While the Trans Mountain expansion is underway recent history has demonstrated that “a pipeline isn’t really a pipeline” until it is operational, he said. “And so, there’s certainly some uncertainty. When TMX comes on, it builds a nice, comfortable buffer for some significant growth in the near-term and medium-term, but we’re not there yet on that pipeline.”

Given this uncertainty the big oilsands players are taking a measured approach to growth.

“We’ve always taken the position that growth could be anywhere from zero to five per cent. It’s not about growing as much as adding value,” said Canadian Natural Resources Limited president Tim McKay. With its acquisition of Devon Canada’s thermal oilsands and heavy oil assets added to CRNL’s large existing asset base, the company has some easy to access growth opportunities.

“Because of the variety of facilities that we have at Wolf Creek [Primrose], Jackfish and Kirby North and Kirby South, we have the opportunity to do very economical pad adds. Today, we feel we have about 100,000 bbls/d of spare capacity from those facilities,” he said. “So, over the next few years you’ll see us doing the pad adds, which you’re seeing today, and we’ll basically fill up the SAGD facilities as well as Primrose Wolf Lake. It’s very much just focused on the very economical $10,000 a boe pad adds that are going to position us for the future there. They’re very economical and cost effective in terms of operating.” 

On the mining side, McKay said that while there’s nothing immediately on the horizon, in the future CNRL is looking to expand synthetic crude oil (SCO) production by 35,000-45,000 bbls/d and hopes the potential of Paraffin Froth Treatment (PFT) could also boost mining volumes.

Another area of potential oil production growth is the Clearwater heavy oil play in northwest Alberta. The Clearwater is currently producing 80,000 bbls/d at the play level, said Ed LaFehr, president and chief financial officer at Baytex Energy Corp.

“Many analysts are projecting that to go to 200,000 bbls/d production. We want to be builder, a developer, an aggregator in the area.”

The current challenge in the play is maintaining reservoir pressures to stem declines, said Renaud. Some operators are using waterflooding from the outset of production to manage pressures. 

“The issue here is that liberating gas in-situ can have detrimental impacts on effectively producing the remaining oil by reducing the energy it has to expand and drive itself to the surface. Operators should continue to implement good production practices in this area, including waterflooding and other pressure maintenance schemes.”

To download the 2022 Top Operators Report, click here.