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The numbers are sobering. Make that alarming. According to the folks at ARC Financial Corp. in their March 1 weekly macro-economic overview of Canada’s upstream oil and gas industry, revenue from the sale of produced oil and gas this year will be only $78.2 billion, the lowest since 2003. This is despite production being at a record 6.97 million barrels of oil equivalent (boe) per day, the highest in Canadian history. Noteworthy is this figure is $10 billion lower than the previous report issued February 23 as ARC redid the math based on lower average commodity prices for the year.
After-tax cash flow – the free cash exploration and production (E&P) companies have for reinvestment after paying all their bills – is estimated to be only $17.0 billion – the lowest number in the 15 years ARC covers, back to 2002. This is $12 billion lower than $29.4 billion in 2002. The figures for the past five years are summarized below.
It is early in the year and much could change. But in the simplest terms, total revenue from production this year is currently estimated to be $71 billion lower than in 2014, the all-time high water mark for the value of Canadian hydrocarbon production. Cashflow will be down nearly 76%, or $55 billion, from 2014, over three-quarters of the revenue reduction. That is because, despite valiant efforts to cut costs, there is a point at which operating costs can no longer be reduced. Shut in production and close the doors or produce oil and gas for practice, not profits. The missing cash flow is what is used to service capital and replace and / or grow reserves. Replacing reserves is the lifeblood of oilfield service (OFS) companies.
Most OFS managers now understand their clients are being mercenary with costs because they must. That’s why there are the fewest number of rigs drilling this winter anyone can remember. Oilsands projects are being cancelled or postponed. More production is being shut-in. Capital budgets are slashed. Compared to historical levels of activity, there is nothing going on because there is no money to pay for it.
The $70 billion puts a lot of other numbers into perspective. It was recently announced the federal government had found $251 million in emergency financial aid for Alberta. While every bit helps, this is under 4/10 of one percent of the missing $70 billion (assuming most of the pain is in Alberta, which it is). Apparently there are two other federal aid programs for Alberta totalling $950 million. Add them and federal assistance rises to only 1.7% of the absent revenue. Saskatchewan’s ask for $156 million to abandon wells works out to 2/10 of one percent of the reduced upstream cash flow. Again, great work for a few but the amount of money governments can and will inject to make the pain hurt less are not meaningful in big picture.
The devastation of the combined collapse of crude oil and natural gas prices has negative impacts beyond day-to-day operations. Below is a summary of the stock market values of 10 of the larger publicly-traded Canadian E&P and OFS companies. This, too, is extremely ugly.
Using this methodology, 10 of the top Canadian-headquartered E&P companies lost a combined $96.5 million in market value in the two years, from the end of February 2014 to the end of February 2016. Ten of the largest Canadian-headquartered OFS companies dropped $12.6 billion in market value, bringing the total to $109.1 billion, about double the revenue drop for the producers.
Since companies trade on a multiple of cash flow, these numbers are not out of line. At a valuation of five times after-tax cash flow, the companies producing all of Canada’s oil and gas had a theoretical market value of $350 billion in 2014 and only $85 billion today. That is $265 billion in disappeared wealth.
This is also somebody’s money. It is remarkable investors in these 20 companies could lose $109.1 billion in two years and many people figure the downturn in oil and gas is a regional problem. Some even believe former high flyers like Alberta and Saskatchewan deserve such punishment for being excessively successful in recent years. Others block pipelines which would provide tidewater access to western crude because they see their region taking all the risk and receiving none of the benefits.
Today most mutual funds and pension plans hold Canadian E&P and OFS equities as core holdings. Because overall stock markets aren’t doing well, perhaps the damage the oilpatch is causing is disguised. But a look at the Canadian equity holdings of the Canada Pension Plan at March 31, 2015 (last date available) indicates the federal government owned on behalf of all Canadians shares of 16 of the above 20 companies. The governments of Quebec, Ontario and B.C. do not disclose the equity investments of their various public sector pension plans with similar granularity.
So it’s awful. Everybody knows that. Now what?
The number one thing everyone in upstream oil and gas must get their head around is the severity of the revenue collapse and its implications. By now people realize it is extremely serious. The purpose of these figures is to demonstrate just how serious. How many managers and owners have truly streamlined their operations to market realities is unknown because the thousands of smaller and private businesses across the Western Canadian Sedimentary Basin (WCSB) must make thousands of independent decisions, based on their unique circumstances.
But media reports of continued layoffs by the larger publicly-traded operators indicate many managers have delayed this element of fixed cost reduction as long as possible. In an industry so dependent on human capital for success, this not delinquent but strategic. One could consider the “glass is half full” approach. Even with revenues of only $78 billion this year, Canada remains the fifth largest hydrocarbon producing jurisdiction in the world, so oil and gas is hardly a sunset industry. At this reduced level, the oilpatch is still equivalent to the Canadian vehicle manufacturing industry was in 2013 when the government of Canada reported total revenues of $84.7 billion. There is work to be done, albeit at a lower level, with squeezed margins and fewer jobs. Keeping almost 7 million boe/day on stream will remains good business for many, even if production growth is not in the cards at current prices. And production will grow by another several hundred thousand barrels per day unless the current oilsands and offshore expansion projects are cancelled because of continued low prices.
Waiting for an upturn as a strategy only works if your company has the financial resources to do so. Many don’t. But as has been written by this newsletter many times, the current low price of oil is unsustainable. Even the futures markets agree. On futures markets, the price of WTI crude is about US$8 a barrel (nearly C$11 at current exchange rates) higher for April 2017 delivery than today’s price. Based on 4.5 million b/d of crude and liquids production this alone would add $18 billion a year to production revenue, a meaningful and measurable improvement.
But the reality is, for this industry to survive in any meaningful form it is time to regroup, retool, rethink, restructure and rebound. The industry is rife with stories about excessive compensation, egregious waste, poor procurement policies, engineering and design blunders and operational incompetence, all symptoms of an industry that has had it too easy for too long. Combined with seemingly unlimited supplies of cheap capital, too many E&P companies decided they had to spend the money now, regardless of labor and equipment availability, efficiency and productivity. In doing so, they ignored what the macro-economic impact of everyone trying to do too much with too few resources would have on costs. While the adjustment from 2014 is extraordinarily painful, the case can be made the industry was overheated two years ago and that business conditions were not normal nor sustainable. Perhaps 2013 was in the same category.
At the IHS CERA investment conference in Houston on February 23, Saudi Arabia’s oil minister Ali Al-Naimi told attendees the future of competing in the global market was to, “Let everybody compete. Follow the marginal cost curve.” He said it was not for the Saudis to make high-cost operators competitive by shutting in oil. In brutal words that received global attention, Al-Naimi said higher cost producers must, “lower costs, borrow cash or liquidate.” Simply put, Canada needs a better plan than OPEC saving our bacon by restricting supply. Ouch.
That said, the price of oil is gradually strengthening. At the Mar 1, 2016 close of US$34.40 WTI is 31% higher than the recent record low price of US$26.68 on January 20. This is caused by declining U.S. oil output and media reports of continued discussions among producing giants Saudi Arabia and Russia about capping output. As importantly, more people are realizing that having the world’s most important energy source trading at half of replacement cost is unsustainable in the long term. The ARC numbers for Canada in 2016 are likely to end up higher than the most recent report meaning at least part of the $70 billion hole will fill itself.
Nevertheless, reality has hit home with numbers no one could even imagine two years ago. No entrepreneur would ever start an E&P or OFS company and sell shares to investors while anticipating they could or would one day lose more than 90% of their value due to commodity price fluctuations. No entrepreneur starts an oil or service company and “stress tests” their income statement and balance sheet to survive a 50% to 70% reduction in revenue. If anybody thought business was going to get that bad, they wouldn’t bother. In some cases, current markets look more like a force majeure (French term for an unpredictable or unforeseen event often used in insurance contracts, sometimes compared to an act of God) than a vicious commodity price cycle.
But the $70 billion hole is real and will be the challenge of a generation. Filling in this massive hole with something is not a matter of if but how. This industry has reinvented itself before and in 2016 it is time to start doing it again.
A well-known fact repeated in the trade press is that oil prices should be low because oil demand in China is falling as that country experiences lower rates of growth. Except, in 2015 it grew at one of the fastest rates ever. According to an article in the
Financial Post February 23, China’s oil consumption grew by a whopping 8% in 2015, the second highest year of growth since 2010. That country imported 7.82 million b/d in December of last year and averaged imports of 6.72 million b/d throughout the year. Demand for natural gas and LNG also increased, though at lower levels than in past years.
Currently, coal makes up 70% of China’s energy mix as it is used to generate electricity. The country uses half the coal in the world. But the environmental impact is dreadful (think of the images when China hosted the 2012 Summer Olympic Games) and the government is committed to moving away from coal to renewables and natural gas. Meanwhile, as the economy transitions from exports to domestic consumption, you can’t run a car on coal; you need oil. Over the next three years, the government has allocated US$4.5 billion to close 4,900 coal mines and repurpose 1 million coal miners to other jobs.
The article concludes, “This may not be good news for the coal producers in China or coal exporters around the world. But China’s emerging new energy structure, while less dependent upon coal, is good news for oi land gas producers as well as non-fossil energy sources: China is by far still the fastest-growing market for all these energy products.”?
As Canada and the world’s largest suppliers of pressure pumping services for hydraulic fracturing release their 2015 financial results, the news is much worse than the dollars and cents.
On February 24, Calfrac Well Services Ltd. announced it had reduced its North American workforce by about 1,700 workers in the past 14 months. This includes more than 600 in Canada and over 1,000 in the U.S. Revenue for the three months ended December 31, 2015 was $286 million, 62% lower than the same period in 2014 when revenue was $749 million.
Trican Well Service Ltd. has made massive reductions in total employment but much of that came from exiting markets in Russia and the U.S. by selling these divisions. Once the U.S. sale closes, Trican will have only about 1,700 employees compared to over 6,700 at the peak. Trican has also shut down operations in Australia, Algeria, Saudi Arabia and Columbia. Revenue for the Canadian division (the most relevant figures, considering the restricting) was $159 million in the three months ended December 31, 2015, compared to $343 million for the same period in 2014.
Global pumping services Halliburton Co. announced February 25 it would be cutting its global workforce by another 8% or 5,000 workers to better match the company’s human resources to market demand. The total job reduction by Halliburton alone is now nearly 29,000 in all markets. An article in
Bloomberg News now estimates total job reductions in oil and gas exceed 250,000. If Halliburton has reduced head count by more than 10% of this figure alone, the total is likely low.
Halliburton’s intended acquisition of Baker Hughes announced in November of 2014 is moving at glacial speed. While the shareholders of both companies have ratified the deal, the merger of OFS giants has now caught the eye of regulators in the European Union (EU). In mid-January, the EU announced a formal review because the deal had, “indicated serious potential competition concerns” involving no fewer than 30 products and services offered by both companies.
On February 25, the federal Export Development Canada (EDC) bank announced it would be providing an additional $750 million in loans and loan guarantees to smaller oil and gas operators trying to survive the current downturn.
EDC is normally thought of as an agency which helps finance exporters in offshore markets. But according to a
Globe and Mail article, the companies need to be only “export minded” or make up some component of the OFS supply chain. As rationale to E&P companies, an EDC official noted most produced oil is exported. All OFS products and services could be exported.
EDC spokesperson Phil Taylor said, “The difference here is we realize that if you’re a smaller company in the oil and gas sector, particularly on the supply and services side, your balance sheet is probably stressed right now. We’re going to have to be a little more creative and a little more flexible with all of our offerings to be able to help these companies in a meaningful way.”
The Globe article said the focus of EDC funding will be on companies servicing four areas: infrastructure improving market access, new technology with applications in other markets, increased productivity and environmental sustainability.
You read the most amazing things about the global impact of collapsed oil prices. On February 28, Reuters carried a story where the head of France’s central bank is reported to have recommended the ECB “extend money printing” to boost inflation and revive an economic recovery. The suggestion is that low oil prices dampen already low inflation rates thus reducing wage growth. If oil prices stay low, the ECB will have to continue “quantitative easing” to ensure people will buy more government bonds, permitting governments to continue to spend money to stimulate inflation and therefore boost the economy.
There can’t be a subject on which more misinformation has been disseminated than the ability of U.S. light tight oil (LTO) producers to make money at current prices.
This became apparent February 25 when U.S. LTO pioneer and leader Whiting Petroleum announced it would not have any rigs drilling in the Bakken of North Dakota as of 2016 and expected production to decline of 15% to 20% this year. Capital expenditures would be cut by 80%.
The same day, major LTO player Continental Resources announced its production would fall by 10% this year. That company has an inventory of drilled but uncompleted wells, the so-called “fraclog,” it will complete as cashflow and prices permit. It will be cutting its capital expenditures this year by 64% from 2015 but will still invest US$920 million. By running some but fewer rigs, Continental will have a DUC (drilled uncompleted) inventory of 415 wells exiting 2016 if no new wells are put on stream this year.
The number of active rigs drilling in three selected markets continues to plunge. Canada’s rig count during the winter drilling season is 40% lower than the peak in mid-January. The U.S. figures for rigs drilling for oil is the lowest since the last slump in 2009 and pre-dates most of the American light tight oil shale drilling revolution. Drilling in North Dakota can only be described as terrible compared to prior years.
FOR FURTHER INFORMATION ON OILFIELD SERVICES CONTACT:David Yager, National Leader, Oilfield Services
Client Groups:Oil ＆ Gas
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