There’s been a quiet revolution in the North American oil and gas business in the last two years. Plunging oil prices have spawned headlines about Alberta’s poorest post-war recession, collapsing provincial government revenues and surging unemployment.

Cash flows have retreated, causing a dramatic retrenchment in capital investment. It has been a reckoning for the energy industry and Canada’s oil patch.

The OPEC cartel, and Saudi Arabia in particular, had kept the price of crude oil at US$93 per barrel from 2010 to mid-2014. The industry got used to this price environment, with plenty of economic rent to be shared between the producers, service companies, pipelines, midstream companies, and the labour pool. This came to an end after prices crashed, when OPEC abruptly altered its strategy from defending prices to protecting market share. It was a calculated gamble for OPEC’s influential, low-cost producers.

Two years into the commodity price rout, the oil business has adjusted to a lower price paradigm. One thing is clear for the Canadian industry: it is poised to rise from the ashes of US$26-per-barrel WTI crude oil, a 12-year low for the commodity reached in February. The business has demonstrated tremendous resilience and is becoming a leaner and meaner competitor on lower prices: US$60-per-barrel oil has become the new US$90.

More with less

Still early in the recovery, it is worth considering the dynamics that have led to lower break-evens across the sector. Service companies, which had enjoyed considerable pricing power for years, cut prices dramatically to keep its fleets active as capital spending dropped. Peak to trough, U.S. oil-directed rig counts fell over 80%. The decline has affected virtually all aspects of the services sector. Falling cash flows have meant producers are doing more with less.

This necessity has been a tremendous motivator for improvements in extraction. The lateral lengths of horizontal wells have become longer. The number of fracture stages to coax hydrocarbons has also risen. At the same time, the amount of proppant used to hold open fractures in the reservoir has grown.

Table 1: Half-cycle well economics by company and play

Raging River Exploration Inc. Viking (Tier 6, Crown)Whitecap Resources Inc. West Pembina Cardium (Extended Reach Horizontals)Spartan Energy Corp. Alameda Frac Midale (Crown)
May 2014July 2016May 2014August 2016June 2014July 2016
Edmonton Light Oil (C$/bbl)$90.00$58.97$99.40$54.20$92.64$66.35
Well cost (C$ million)$0.90$0.65$3.6$2.9$2.2$1.5
Initial production rate
(boe/day)
4960481476120160
Estimated ultimate recovery (000s boe)455030932678160
Internal rate of return (%)90%82%>200%>200%125%116%
Payout (months)1214761111
Net present value
(C$ million)
$1.1$0.7$7.6$6.7$2.2$1.7

Not all cost savings will be permanent. At July’s TD Securities Stampede energy conference in Calgary, the general view was that a return to higher commodity prices would likely renew upward pressure on services costs. The general view was that 30% to 50% of recent cost savings would be eroded if crude sustainably reached US$90. The corollary is that up to two-thirds of the sector’s new cost structure in North America likely represents a permanent shift. As we stand, CIBC estimates oilfield services pricing is down about 25% to 50% since year-end 2014, with select service lines fallen as much as 65% due to severe equipment oversupply. It’s benefited the competitiveness of producers in a big way: they’re leaner and meaner.

Canada’s new paradigm

Over the last decade or so, the Canadian oil and gas business has morphed into a model of unconventional resource extraction from tight reservoirs using as horizontal well technology. Well economics are usually presented to investors on a half-cycle basis. That would be in a manner that doesn’t include the cost of acquiring the land.

The economics are not usually encumbered with investments in infrastructure and facilities for the processing, storage and transportation of products. These half-cycle economics also don’t capture corporate costs of company staff and a head office. The most relevant numbers to investors—the corporate-level returns—are often absent from investor presentations. Despite these shortcomings, the half-cycle economics are very telling of the new paradigm.

It sounds absurd to suggest that sixty-dollar oil is the new ninety. But Table 1 is an excellent snapshot of the expected half-cycle economics of three highly regarded light oil producers in Western Canada. It shows the estimated economics in key plays before the oil price crash, and contrasts them with the economics after a two-year adjustment to the new reality of lower prices. Astonishingly, the anticipated returns and payback periods are very similar under a roughly US$30-decline in oil prices.

On average, the well cost assumptions for these producers have fallen by almost 25%. At the same time, the expected recovery per well has climbed by a similar amount. In other words, on lower costs and improvements in extraction, producers in these three light oil plays are spending almost 40% less, on average, to recover a barrel of oil.

Manufacturing rates of return shareholders

Investors are increasingly looking for the oil and gas sector to focus on delivering acceptable rates of return at a corporate level and on a per-share basis. Coming out of the energy price crash, the Canadian oil and gas sector can reinvent itself with a leaner, more competitive cost structure and highly repeatable drilling opportunities. We continue to believe that investors should focus on stronger companies with access to capital and sustainable cost structures as we emerge from this downturn. Whitecap, Raging River and Spartan, in Table 1, all fit the bill.

by D. Mason Granger, P.Eng., MBA, CFA, is a portfolio manager in Toronto.