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Remember you read it here first. On January 17, 2015. Then several more times over the next 14 months. We’ve tagged bottom. Crude prices would quit falling and go the other direction. On January 20, 2016 this writer again analyzed all the oil market data under the title, “Of Course Oil Prices Will Rise, But When?” This piece concluded, “Therefore, oil prices will rise, once more people study the long-term dynamics of oil markets instead of trading on and exploiting the short term news.” It could be this has finally happened.
However, three weeks after this profound commentary, benchmark North American crude (West Texas Intermediate, or WTI) would hit a 13-year low of US$26.19 on February 11 (Energy Information Administration, EIA). For the past 19 months, world oil prices have been very cruel to those who have stuck their neck out and attempted to declare a basement for falling prices. When oil was still above US$100 a barrel in June of 2014, only a handful of completely ignored outliers had predicted crude would lose 75% of its value by early 2016; that high global crude prices were being supported more by history and tradition than the market forces of supply and demand.
Finally, on March 11 the International Energy Agency (IEA) of Paris – one of the world’s most respected researchers on global oil markets – weighed in, issuing its monthly report which carried a headline reading, “Light At The End of The Tunnel?” The main report (only available through subscription) indicates several factors which currently support higher prices, including a possible output cut or cap when major producers meet in April; material supply disruptions in Nigeria and Iraq; steadily declining non-OPEC production; no change in the forecast demand rise of 1.2 million barrels per day (mmb/d) in 2016 and a softening of the U.S. dollar. IEA wrote, “…there are signs that prices might have bottomed out.”
After recovering slowly for the past month and buoyed by the IEA report, on Friday March 11 WTI closed at US$38.50, 47% higher than a month earlier. Had the industry not already experienced prices on the wrong side of US$30, participants would have regarded US$38 WTI as awful. Instead, the business press was full of stories on how this could be the bottom. This caused Bloomberg News to release the following:
Bloomberg ran this chart below the headline, “A Short History of Unsuccessfully Calling a Bottom in Oil” followed by, “The International Energy Agency today said oil prices may have bottomed out. Several people have tried to call the oil’s floor since prices started falling in the summer of 2014. So far nobody has been right.” The oil price bears have mauled a lot of the bulls since mid-2014.
In February the IEA published the following global / supply demand chart which tracked forecast supply and demand through to the end of 2016. It shows the gap between supply and demand closing halfway through the year. On March 11 IEA wrote, “…comfort can be taken from our view that in the second half of 2016 the gap between supply and demand narrows significantly to 0.2 mmb/d in both 3Q and 4Q. For oil prices there may be a light at the end of what has been a long, dark tunnel, but we cannot be precisely sure when in 2017 the oil market will achieve the much-desired balance.”
The estimates for the third quarter of 2016 show the lowest spread between supply and demand since the first quarter of 2014, a full 2.5 years of a growing surplus of supply over demand. If, as the IEA says, this is truly light at the end, the world’s oil and gas industry would observe this has been an extraordinarily long tunnel.
The factors which are causing the IEA’s curves to cross have been pointed out by the oil bulls for months. U.S. light tight oil production declining another 750,000 b/d after already falling 530,000 b/d from its peak in April of 2015 is one factor. As noted above, low oil prices will stimulate demand growth of 1.2 million b/d in 2016, a figure the IEA says is looking stable despite well-publicized issues with the economy in many countries including China. Iran’s return to global markets as a major force is more hot air from Tehran than barrels of Iranian oil being loaded on tankers for export. Continued global capital expenditure reductions are starting to make everyone understand that “lower for longer” is not “lower forever.”
Meanwhile, real physical supply disruptions will help to solve the inventory overhang problem, should they continue. In the past month Iraq has lost 600,000 b/d and Nigeria over 250,000 b/d of oil output due to physical damage to oil delivery infrastructure that may take some time to repair.
As importantly, the short sellers who have owned the market since mid-2014 are heading for the hills. When oil prices began rising three weeks ago, there was speculation the main reason was short sellers covering their positions to minimize losses and therefore the price rally was unsustainable. Bloomberg Business reported March 13 that in reports to the U.S. Commodity Futures Trading Commission (CFTC) for the week ended March 8, net-long WTI positions gained 39,509 futures and options contracts to 174,949, the biggest increase since last April. Short positions fell by a similar amount, “the most in CFTC data going back to June 2006.”
What made the IEA report noteworthy was that it dealt with market fundamentals, not futures markets. While the IEA claims demand growth is strong, the supply side is under pressure. Even the continued growth in inventories in the U.S. and other countries cannot stop more people from believing the worst is over for crude oil prices for now.
But by Monday March 14, volatility had returned as WTI gave up a good portion of the gains of the previous week. The issue was once again Iran, for the umpteenth time since last July when an agreement on removing international sanctions was announced. On March 14, Iran said it wouldn’t be joining any output freeze until it recovered market share, something proponents of an output cap had already anticipated. Traders were again looking for a reason to sell and the long-promised but as yet non-existent Iranian oil market flood was blamed and the trade press dutifully carried the story.
But by March 16 when it was announced Saudi Arabia, Russia and some other OPEC members would be meeting to discuss oil output in Qatar April 17, crude prices regained most of the losses of the two previous trading days.
What does this mean for Canada’s battered oilfield services (OFS) sector? Not much for the very short term, meaning the next few months. The winter drilling season is what it is, with its main characteristic being it is over, with the fewest wells to be drilled in the first quarter of this year than in decades. However, as prices improve so do the number of prospects that make sense to drill. Exploration and production (E&P) companies which continue to produce without drilling are effectively going out of business by liquidating their inventory without replacing it. The term coined in the nuclear winter of the late 1980s when nobody could afford to drill was, “Grocery stores are very profitable when they don’t stock the shelves. But they don’t stay in business very long.”
E&P companies can take a few quarters or even a year off from drilling before inflicting permanent damage on themselves. More producers are guiding their investors toward lower production in 2016 if nothing changes. But things are changing. If the crude oil price recovery continues operators with available cash will fire up rigs as quickly as they can, but unfortunately not at the same pace at which they have proven they can and will lay them down.
It might be impossible to be optimistic considering what the oilpatch has been through. The workforce has been decimated. Balance sheets and credit lines are strained. Equity investors are bruised.
But if the IEA is right and the light at the end of tunnel is not a train, things will gradually get better instead of getting worse.
The headline in The Globe and Mail March 10 was powerful. “Trudeau vows to clamp down on methane emissions,” one of the outcomes of a well-publicized visit to Washington, D.C. by Prime Minister Justin Trudeau as a guest of U.S. President Barack Obama. The National Post carried a full-page photo of the two leaders hugging. A new era of Canada / U.S. relations was upon us, thanks to an outwardly friendly — if short-lived — relationship between Canada’s new prime minister and a U.S. president in the last few months of an eight-year stretch in office.
The two professed environmentalists and climate change activists got down to business and agreed both countries would take action to reduce methane emissions, the largest source of which is a by-product of oil and gas production. Trudeau committed Canada to a 45% reduction from 2012 levels by 2025. This is so similar to a proposal included in Alberta’s climate change policy last November that Premier Rachel Notley publicly claimed much of the credit, even though she wasn’t invited to the meeting. When it comes to loading up the oil and gas industry with new targets, regulations and restrictions, many of the current crop of politicians in North America are eager to jump in front of the camera to take credit.
The problem is compliance will be expensive and difficult. Methane in its purest form is natural gas. It is found in quantities ranging from small in bitumen to 100% in dry, sweet gas. It is a by-product of crude oil production. It has a varying value depending upon volume and location. For years the Canadian oilpatch was powered by natural gas, but due to lingering low prices the focus has moved to crude oil. While producers would love to capture and sell every molecule of methane they encounter, it doesn’t always make economic sense.
The above satellite image of the Bakken oilfields of North Dakota was taken several years ago. The problem with light tight oil (LTO) or shale oil is virtually every well contains natural gas but often not in sufficient quantities to justify capturing it all and building the necessary flowlines and gathering systems to ship it to market. Many of the new LTO wells in Canada are what are called “single well batteries,” meaning they are not tied into a gathering system. The oil is trucked and the methane is flared. Theoretically it is all burned, but it never works out that way.
Other sources of methane associated with oil and gas production are leaks or “fugitive” emissions, where the plumbing between the well and the sales line contains tiny but collectively meaningful opportunities for methane to escape from valves, fittings, connections and tanks. The latest technology employed to detect fugitive emissions is infrared cameras which can detect small amounts of escaping methane through atmospheric temperature changes in quantities otherwise undetectable using conventional measurement and instrumentation.
Unlike spilled oil, methane is not visible to the naked eye. It also is odorless until mercapten is added, the chemical that gives natural gas a distinctive smell so consumers can uses their noses to detect leaks in their homes.
The other main source of methane emissions is Surface Casing Vent Flows, or SCVF. Here the cement seal on the outside of the production casing leaks tiny-to-significant quantities of methane all the way to the surface and ultimately into the atmosphere. These are quantities of methane uneconomic to capture and sell or burn, yet often are extremely expensive to contain. Well operators in Alberta are required to regularly test and report the existence of SCVF. However, stopping them completely is entirely another issue.
When Alberta announced its new targets for methane reduction last November, the Canadian Association of Petroleum Producers (CAPP) was supportive but concerned. CAPP was supportive in the sense it is political suicide to not agree containing methane emissions is a good idea. However, in a November 24, 2015 article in the Financial Post, CAPP CEO Tim McMillan said, “We know for certain to meet the 45 per cent reduction in methane there will be real costs in the tens or hundreds of millions of dollars over the next five years.” While industry admits methane is said to be a more serious greenhouse gas than carbon dioxide and therefore efforts should be made to contain it, commitments by Edmonton, Ottawa and Washington about what must be done are long on noble intent and short on how to pay for it.
Which is the problem for Canadian oilfield services. If clients decide to spend the cash to fix these things, OFS will be employed to do testing, fixing, repairing and monitoring. Like well decommissioning or anything else E&P companies spend their money on, it is good for business for OFS, at least for now.
The problem is the more E&P cash flow diverted away from reserve replacement through exploration, drilling and development, the less attractive the future looks for the OFS client base. As mentioned above, E&P companies have to replace reserves to stay in business. Cash is finite. Moving capital from drilling new wells to controlling methane emissions may be good for the environment but it is not necessarily good for the future of the industry, certainly not at current commodity prices.
Fortunately, after the politicians make their headlines and photo opportunities, the dirty business of turning public announcements into workable policy takes much longer and is more complex than the policy wonks and speech writers ever imagined. Reduce methane emissions? Good idea. Can OFS help and benefit? You bet. Should the regulators jump full bore onto writing and enforcing this new policy initiative? Be very careful.
The Calgary Herald headline March 10 was impossible to ignore as is blared, “Oilfield services being offered for free as downturn worsens, charges CEO.” The title was based on a conference call with Total Services Ltd. CEO Dan Halyk as he released Total’s 2015 financial results. The first paragraph contained a summary of the current state of OFS stating, “Oilfield services providers are cutting rates to less than cost, renting equipment for nothing and extending credit to customers who aren’t likely to pay to maintain market share charged (the Total CEO).”
There is no question OFS operators are operating below cost on virtually every job, when the full cost of capital is taken into consideration. Whether it is drilling rigs, frack spreads or coiled tubing units, the current market rates aren’t high enough to justify the original investment. They may not be below cash operating cost but they are certainly below total full-cycle return on invested capital cost.
Renting equipment for nothing? The term “renting” implies the collection of rent so this is impossible. However, for low- or zero-maintenance items such as tanks or matting, it could be some vendors are “storing” them on a client’s location at no cost to win some favors or friends on other or future work. This is likely occurring but one would hope the client is at least paying for the trucking. If there is some sort of package on location, having one or more items supplied at no charge as a loss leader to get the business happens in good times as well as bad.
As for working for clients who won’t or can’t pay their bills, reckless management is not restricted to severe downturns in activity. There have been lots of E&P companies which drill, complete and service wells on credit with no ability to pay. This is not new.
That said, Halyk’s outfit carries nominal debt compared to many OFS companies and is in a good position to lecture the world on how OFS companies ought to operate. He said, “Price competition has been fierce, with some competitors literally offering certain of their equipment and service for free… We cannot and will not compete with free. Our refusal to pursue unprofitable work and recklessly extend trade credit has undoubtedly had a negative impact on near-term equipment utilization and revenue.”
Total has a solid reputation for financial management in the public OFS community. The main business units are drilling rigs, rental equipment and gas compression. When Total reported it lost money in the fourth quarter of 2015, veteran OFS analyst John Bereznicki from Canaccord Genuity wrote, “You know times are tough when Total loses money.” But even the mightiest salmon cannot swim upstream in a river without water. Bereznicki wrote, “We nonetheless expect the company to post a modest loss in 2016, which would make it the company’s first year of negative net income since 1999.” It’s that kind of year.
Meanwhile, another E&P company reported it was still looking to its vendors to help reduce costs. Crescent Point Energy Corp. announced its earnings on March 9 and a Financial Post article wrote, “Smith (COO Neil Smith) said Crescent Point has also approached the oilfield services companies working for the company and asked to see their books, in an effort to further drive down costs through its own supply chain and those of its service providers.”
Saskatchewan’s largest oil producer and top operator in both the southeast and southwest regions of the province was one of the first out of the gate to demand and receive significant vendor price reductions when oil started to fall in late 2014. Sharing open books among E&P and OFS companies has in the past been an agreed business model, but generally it has been on a cost-plus basis in the booming oilsands. Clients would agree to cash costs plus a negotiated margin to cover fixed costs, capital and administration.
Unfortunately, with Crescent Point vendors may be justifiably concerned their client wants to see the books to make sure they aren’t making too much or any money whatsoever. The newspaper article did not disclose what Crescent Point believes is an acceptable margin or return. The problem with E&P and OFS when money gets tight is while the relationship may be symbiotic – one cannot exist without the other – every nickel that shows up on the bottom line of client or vendor comes directly off the bottom line of the other party.
Not everybody is going to make it through this slump, even if oil prices continue to improve. OFS operators are right to be angry many oil companies have a purchasing policy that says, “Feel free to go broke on my lease.” On the other hand, too many desperate vendors respond with, “May I please have the next job so I can go broke on your lease?”
At 480 units on March 11, the total number of rigs drilling in the U.S. is reported to be the lowest since oilfield services giant Baker Hughes began keeping records, according an article in the March 11 edition of The Maritime Executive. Anecdotally, the article claimed this was “probably” the lowest figure since the late 1800s, although there was no data source quoted, only the comments of an oil analyst.
In Canada, you can call it spring break-up (or what happens after 15 months of low oil prices), but there were only 77 rigs drilling on March 15. And the rig count in North Dakota continues to fall.
The only good news in the continued decline of North American drilling is it will result in crude oil production declines, which will help prices recover. This will eventually put many of the idled rigs back to work again.
FOR FURTHER INFORMATION ON OILFIELD SERVICES CONTACT:David Yager, National Leader, Oilfield Services
Client Groups:Oil ＆ Gas
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