2022 Top Operators Report: Keeping A Cap On Costs


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.

Oil and gas operators have been successful the last five years in keeping supply costs in check, but it has come at some cost to oilfield service providers.

Now, as operators look to return to the field and increase production to profit from high prices, they are facing service cost inflation as suppliers pass on costs from further up the supply chain while trying to rebuild margins to invest in workers and equipment to meet growing demand.

Evaluate Energy full-cycle supply cost data on 37 publicly traded Canadian operators (excluding oilsands operators) reporting every year for the last five years shows average full-cycle costs across the group have remained in a range of $31-$35 per boe and averaged $32.75 per boe throughout the time period. In 2021, operators reported average supply costs of $34.13 per boe, the highest level in five years.

Three-year average finding and developing costs have trended downwards, reaching a low of $8.54 per boe in 2021 as operators continue driving productivity in drilling and completions.

Approaches to drilling and completions vary by resource play. Despite tens of thousands of horizontal wells with multistage hydraulic fracturing being drilled, some experimentation continues, said Rhonda Gravel, senior engineering advisor (drilling and completions), at geoLOGIC systems ltd.

In tight oil plays like the Saskatchewan Viking and Bakken development, operators are in manufacturing mode with a focus on keeping production at plateau levels and generating cash flow.

But in the huge gas plays in western Alberta and B.C. there is more diversity in well design. The trend throughout the history of the Duvernay shale is for longer horizontal legs and greater completions intensity. 

“When you plot production versus job size you see a linear trend showing the bigger the frac, the more production,” said Gravel. “So the trend has been for more sand, longer wells. But the ability to push the envelope relies on not just a bigger hammer, not just longer wells and bigger fracs,” she said, pointing to technologies like acid spearheads — high viscosity slick water systems to lower friction in stimulation treatments and allow for higher pumping rates.

Operators are also leveraging technology to better target horizontal legs and place fractures along the wellbore.

Data from the Montney formation shows there has been a slow and steady climb in completed length over the last five years, added Gravel. Proppant and fluid loads have been relatively consistent, with stage counts ranging from 35-45 stages. However, there have been some outliers including 70 wells designed with over 150 stages and 18 wells with over 200 stages.

“Unlike the Duvernay, which has seen increasing stage count in line with longer laterals, the Montney is seeing high stage counts in wells with the same completed length as before. High stage count wells are allowing operators to pump higher proppant and sand volumes. But are the increase sand volumes resulting in better wells? Results seem to indicate it depends on the area.”

Operating and transportation costs have also trended upwards. The rise in operating costs can be attributed to a number of factors including higher gas processing and transportation costs due to more liquids production and operators pushing into more remote locations, and a rise in oil production costs on a per barrel basis due to well shut-ins due to the pandemic along with additional costs to bring wells back onstream.

Corporate general and administrative costs have declined due to corporate consolidations while interest payments are also down as operators use free cash flow to pay down debt. The biggest increase in costs has come from royalties. After cratering to an average of $2.55 per boe in 2020, royalty payments jumped to $6.33 per boe in 2021.

Joel Armstrong, senior vice-president, production and operations at Whitecap Resources Inc., said cost pressures are trending to add 10 to 15 per cent to the company’s budgeted second half capital program.

“Inflationary costs started to creep up in the first quarter capital program, however we were able to mitigate our exposure by locking in key services for our winter drilling program,” he said. “Moving forward to the back half of the year, we expect these issues to persist.”

Armstrong noted that while operating and transportation costs of $15.83/boe realized in the first quarter were in line with expectations they, too, are rising.

“We continue to see inflationary pressure across our business and expect to see approximately a five per cent increase to our operating and transportation costs for the remainder of the year with the majority of those costs coming from chemicals, labour and fuel.”

Whitecap is currently sticking to its 2022 capital guidance of $510-$530 million, but there’s a chance that could change as the year plays out if inflation continues heading higher.

“We’re doing everything we can to mitigate that through strong vendor relationships, key service providers and suppliers,” said Armstrong. “In some cases we’re reducing suppliers ... to leverage our scale and improve service and efficiency and just the overall optimization of our drilling and completion designs. Overall, we’re estimating a 10 to 15 per cent impact.”

In situ oilsands operators have seen cash costs and overall supply costs rise sharply in 2021, due to higher natural gas prices and higher royalties. Average cash costs for the three large producers that provide breakdowns were $26.09 per bbl in 2021. Including estimated initial and sustaining capital costs, interest, and general and administration costs, supply costs for this group averaged around $39.80 per boe in 2021.

In situ operators continue using a variety of strategies to maintain or lower sustaining capital costs, said Tanya Fagnan, business development manager at geoLOGIC.

“The industry has taken a hit over the past decade and producers have to keep coming up with innovative ways to produce more, with less capital investment, and on top of this, reduce impact to the environment,” she said. “Over the years, I’ve seen companies working to enhance production with methods such as solvent injection, to increasing the number of wells per pad, adding infill to old and new pads and now increased length.”

Using TOP Analysis, Fagnan examined the impact of longer productive lateral lengths on SAGD production. She found that longer productive zones resulted in less production per metre but a significant increase in overall well production. She pointed to a recent pad drilled by Cenovus Energy Inc. at Christina Lake.

“It has the longest wells producing to date. There are six active well pairs, no infills, with an average length over 1,600 metres. At seven months in, the calendar day average for the pad is at 7,000 bbls with an SOR of 1.6. That’s over 1,000 bbls/d for each producer.”

Oilsands operators are also battling inflation, said Brad Corson, president and chief executive officer at Imperial Oil Limited.

“We are seeing some of the same inflationary pressures that others in the industry, and really all sectors, are experiencing right now. I would characterize it year-to-date as being very moderate for us. The main place we see it is in energy costs, because we do consume a fair amount of natural gas in our operations. It’s very difficult to offset the energy costs. But again, when we see higher energy costs on the expense side, it also translates into higher revenues for us on our production side.”

Having a steady development program and continuously learning from well pad to well pad is helping Canadian Natural Resources Limited manage inflation, said Tim McKay, company president.

“We haven’t really seen what I would call major inflationary pressures because we’re basically being offset by efficiency gains. The way we structured our program is some of those same crews, for example in the thermal side, are moving from one pad to the next pad to the next pad. So by doing it that way, we’re taking the learnings and efficiencies and we’re basically taking them to the next pad. So each and every well pad we’re finding ways to do it better and offset inflationary pressure.”

From a “physical inflationary pressure” standpoint, McKay said CNRL has “obviously” seen an increase in labour costs. But it’s the cost of steel that is having a more dramatic impact.

“Steel prices are up. The knock-on effect of steel is also we’re seeing what I would have to say is a 20 to 25 per cent increase on let’s say physical vessels — separators and some manufactured vessels. So, we are seeing that inflationary pressure there.

“Where it all levels off is always difficult to say, but the key for us is if we can keep that momentum going in terms of finding those efficiencies as we move to the next pad, we can offset a lot of these costs. And that’s what we’re doing today and it’s working very well.”

On the royalty front, McKay said having to pay higher royalties is a nice problem to have. “In terms of royalties, obviously with the structure of not only the conventional side but also the oilsands, as prices move up the royalties kind of move with it. It’s always difficult to say where the royalty piece will end up, depending on your price forecast. But it’s the same for all of us operators — as the prices change, the royalties kind of go in concert with them.”

No one in the industry minds paying more royalties given the obvious corporate benefits of surging prices and the impact on the bottom line, he added, especially after price drops during the pandemic.

“It’s good to see. When you look back at 2020 and where the industry was at and where it is today, it’s kind of the complete opposite.”

To download the 2022 Top Operators Report, click here.

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