Oilsands Down But Never Out

By David Yager, National Leader, Oilfield Services, MNP LLP

One of the biggest challenges the oilfield services (OFS) sector must face in the short and medium term is adjusting to the reality that construction of new or “greenfield” major oilsands exploitation projects has all but ground to a halt. This has been a major driver of investment, employment and expansion for OFS and myriad support industries for over a decade.

But as global capital expenditures on new oil and gas supply plummet worldwide, production of oilsands will grow by a third over a five-year period from 2.3 million barrels per day (b/d) last year to almost 3.1 million b/d in 2018. While the party appears to be over for Fort McMurray, Bonnyville, Cold Lake and other major bitumen mining and thermal bitumen support centres, there are many oil producing communities across North America who would love to have their problems.

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Growth in oilsands output is based on multi-year projects currently underway or near completion. Imperial Oil Limited's Kearl 100,000 b/d phase two, for example, came onstream earlier this year. Suncor Inc.’s massive Fort Hills project will be done in late 2017 and is designed to contribute 180,000 b/d to 2018’s output. ConocoPhillips at Surmont started injecting steam this year and this expansion will add 118,000 b/d when fully operational. Husky Energy Inc. Sunrise began producing this year and it will contribute another 60,000 b/d. Canadian Natural Resources Limited’s next expansion at Horizon which is currently underway will ramp up output well beyond the 137,000 b/d the first phase has already achieved.

These are big numbers. The 756,000 b/d in scheduled oilsands output growth is greater than the recent output of OPEC members Ecuador, Libya and Qatar.

As Canada’s oilsands ramps up to over 3 million b/d, the OFS support sector to keep it running must expand as well. The Canadian Association of Petroleum Producers operating costs (OPEX) statistics for 2014 show oilsands again led the way as the largest recipient of revenue spent by producers to keep production onstream.

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In 2014 oilsands operating costs were about $24 billion and this  expense is not included in capital expenditures (CAPEX). In the past 17 years oilsands OPEX has risen over 1,500% from $1.65 billion in 1998. OPEX includes expenses for operating company-owned facilities (there is no third-party field processing of mined or thermal bitumen), E&P production staff and major inputs like natural gas. There is no granularity provided on how much of this massive pie goes into the pockets of third party OFS vendors. However, oilsands is high cost production meaning more money is spent per barrel than most other crude types. While this may not be great for the producer, it’s good business for the support infrastructure.

The OPEX pie will grow. With output rising by one-third and even with market-driven vendor price reductions and continued low natural gas prices, it is not unreasonable to see oilsands OPEX heading for $30 billion a year by 2018.

There are three other positive elements to oilsands production.

The first is production decline rates. Oilsands output is flat relative to high-decline oil production such as light tight oil (LTO). Most oilsands projects will have the same output in 10 or 20 years as they have today. With efficiency gains and technological advancements, output could rise from the same plant. Most oilsands production is owned by larger producers with deep pockets. Many of the small, capital constrained outfits that have tried to play the oilsands game started having financial problems long before world oil prices collapsed.

The second is oilsands plants are not easy to shut-in, even temporarily. This was evident in the 1980s when Suncor and Syncrude Canada Ltd. lost money on every barrel they produced, which forced them to examine every facet of their operations to cut costs while waiting for prices to recover. Nobody is happy producing high cost (relatively speaking) oilsands at or near current low oil prices. Fortunately, North America’s low natural gas prices will likely protect oilsands producers from price pressure from this major input expense.

The third is sustaining CAPEX, money required to maintain facilities and de-bottleneck existing operations. The announced CAPEX declines and project cancellations are primarily for greenfield projects, not money spent to sustain or enhance current operations. In a research note to clients on September 1, 2015, ARC Financial VP Research Jackie Forrest wrote: “Even if the construction of greenfield oilsands facilities slows to a trickle, expenditures on sustaining capital projects should remain robust. By the end of the decade, oilsands production is expected to reach as much as $13 billion a year of sustaining capital spending. While this is a markdown from recent spending levels it is still a considerable sum and greater than all of the oil and gas capital spending in British Columbia and Saskatchewan combined.”

Adjusting to the new realities of low oil prices, intense competition, reduced capital spending, capped market access by pipeline and as-yet unknown Alberta royalty and climate change policies, is painful for all in OFS and will prove terminal for some. The OFS pie is shrinking significantly for some time and no area will be hit harder that the supply chain for building greenfield oilsands projects.

If the price of oil spiked tomorrow producers would be back drilling LTO as quickly as they could capitalize and mobilize. Even if oil prices rise significantly the challenges for new oilsands projects are much more complex, more uncertain and will take much longer to resolve.

But as the world’s oilpatch licks its wounds after what will soon be a year of collapsed prices, there are much worse places to be operating than Alberta’s oilsands.

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