The Fiscal Pulse of Canada’s Oil and Gas Industry

Executive Summary

Economists and analysts have been trying to find historical comparisons to the lengthy oil price downturn that began 21 months ago. As bad as 1998? 1985? Or even the 1890s? Regardless, the dual impact of oil and natural gas prices falling by more than 50% since late 2014 has led to a severe contraction in the Canadian oil and gas industry. In this report we examine the ongoing impact of the downturn on capital flows, production levels and field activity since our last review, one year ago. We assess the financial health of Canada Oil and Gas Limited (COGL) – a fictitious company that represents a financial consolidation of all upstream oil and gas companies operating across the country – through our model called the “Fiscal Pulse.” Trends in product volumes, prices, costs, money flows, profitability and capital efficiencies are tracked and analyzed. Data comes from many sources, but dominantly from information published by the Canadian Association of Petroleum Producers (CAPP) and company financial reports.

With the first quarter behind us, the highlights of our 2016 diagnosis are summarized below:

  • Nominal cash flow lowest since the 1990s – Cash flow is the dominant source of capital for investment in the drilling, completion of new wells, and requisite production infrastructure. In 2016 we expect a token $18.6 billion from all hydrocarbons. That’s down 30% from 2015, and a staggering 75% from 2014. On average, COGL runs at cash-flow-break-even at $30/B WTI – a level tested in Q1 2016. By the end of 2016, two years of low oil and gas prices will have taken $65 billion out of Canada’s oil and gas economy.
  • Investment reduced to legacy spending – COGL has two divisions: Oil Sands and Conventional Oil and Gas. Cash flow running at near break-even levels in early 2016 means that there won’t be much of a Fiscal Pulse for investment this year. Bankruptcies and 100,000+ layoffs validate the issue under a harsh light. Nominal CAPEX for the conventional side of the business will be as low as the mid-1990s, reducing field activity to a crawl. Like last year, the $30.5 billion in total CAPEX is largely being driven by spending on several late-stage oil sands projects, the last of which is expected to be completed by 2017 – 2018.
  • Declining production – The calculus in the oil and gas business is fairly simple: declining investment equals declining production. But there is a lag in the equation, which is one reason why production declines had not yet been recorded a year ago. In 2016, conventional oil as well as natural gas output is expected to drop. Light and medium grades of high-decline, tight oil are already off by 17% or 120,000 B/d from the 2014 peak. Western Canadian natural gas production is increasing in some prolific, low-cost regions, but on balance total volumes are expected to decline by the end of the year. In the absence of more clarity on the wildfire damage, oil sands production is expected to grow by about 85,000 B/d this year, a lagging consequence of late-stage projects coming to fruition.
  • Contracting oilfield service capacity – Rig activity is down to levels not seen in decades. Utilization of equipment this past winter was as low as the idle “spring breakup” period in normal years. By the end of 2015 the lack of an investment pulse on the conventional side of COGL began causing market death of oilfield service companies. Bankruptcies, layoffs and cannibalization of good equipment for spare parts all represent a contraction of field capacity that may be insufficient to serve COGL on a price rebound.
  • Falling costs (for now) – Declining investment continued to create a labour and service sur plus in 2016. As well, producing companies doubled their emphasis on improving logistics and innovating for operational efficiencies. The result was a further lowering of year-over-year capital and operating costs. Existing production is now costing 15 to 25% less than the peak of 2014. Drilling and completing new wells is 20 to 30% cheaper. Wages for Western Canadian oilfield workers are down between 10 and 15% from peak, though Alberta’s wages are stickier on the downside than BC and Saskatchewan. More cost reductions are unlikely. Service companies are running at or below breakeven. Com modities are showing some strength going into Q2. Any rebound in investment by COGL will be served by less equipment and fewer people.
  • Tighter capital markets – COGL was able to raise $17.1 billion in new debt and equity in 2015, a level that was surprisingly resilient to the downturn. However, much of that was in the first half of the year. By late 2015 capital markets were shunning the industry. Only $1.2 billion of external capital came into the business in Q1 2016, a trickle by historical standards. Rebound in financings will be wholly dependent on rising commodity prices; however new debt and equity will remain scarce until there is belief in the sustainability of a recovery. We expect only $8.5 billion of financings in 2016, half of last year.
  • Price arbitrage drives market access – Oil price discounts relative to global prices have historically plagued COGL, especially between 2010 and 2013 when rising production across North America began clogging up pipelines. But price discounts created market inefficiencies that represented opportunity for arbitrage. An aggressive build out of railroad loading/unloading facilities, combined with expansions of existing pipelines added over 1.0 MMB/d of oil transport to North American markets. It didn’t solve Canada’s “only-one-cus tomer” problem, but the added capacity to the US market has diminished both the size of the discount and price volatility.