The U.S. Rig Count Is An Over-Rated Indicator of Future Oil Prices: Read Why HERE – David Yager – Yager Management
David Yager – Yager Management Ltd.
Oilfield Service Management Consulting – Oil & Gas Writer – Energy Policy Analyst
April 4, 2017
The Baker Hughes North American Rotary Rig Count wallowed in relative obscurity among the world’s business writers for decades. The Hughes in Baker Hughes is the original Hughes Tool Company, inventor of the tri-cone rotary rock bit. The company started accumulating this data because every operating drilling rig was a potential customer. That their weekly report might one day move the needle on North American oil prices with every vacillation was surely never anticipated.
The fact Baker Hughes still calls rigs “rotary” highlights its antiquity. Thanks in large part to Hughes bits, rotary drilling had rendered cable tool rigs all but obsolete by the 1940s. Today rigs drill horizontals with mud motors, not by rotating the drill string.
The first entry was July 17, 1987, utterly meaningless nowadays because of so many changes in rigs, bits and penetration rates. The U.S. Oil and Gas Split tab counts rigs drilling for oil. This number meant little to anyone but oilfield trade magazines, service stock analysts and OFS managers doing budgets until November 28, 2014, the day OPEC announced it would no longer support oil prices.
The price of WTI tanked immediately and would not “tag bottom” – as they say on the rigs – until February 2016. Today’s prices are almost double their records lows of last year, but are still under half of June 2014. What a mess. Misery for everyone but consumers for 29 months.
The number of U.S. rigs drilling for oil became widely publicized after the light tight oil (LTO) revolution put over 4 million b/d of new production on stream in the five years between 2010 and the peak in mid-2015. Bakken. Eagle Ford. Utica. Permian. Niobrara. In the same period rigs targeting oil rose from 427 in early 2010 to a peak of 1,601 in September 2014. Drill baby drill!! The amount of oil America could produce was only constrained by the number of rigs and how many wells they could drill.
And, as history would prove, the price of oil.
The downward trend was equally breathtaking. There was some momentum in early 2015 but the first noteworthy low was 628 in June, a 61% decline in eight months. There was 7% rise in August thanks to higher oil prices in June but when crude fell again, the downward trend continued to 316 in May 2016, the lowest since 2009. Rig activity languished at about 20% of 2014 peak levels for several months in mid-2016.
By mid-2016, the oil rig count had been big news for oil writers and analysts for over 1.5 years. That the there was a world oil surplus was understood. That U.S. LTO put on stream by all those rigs contributed to the surplus was also well unknown. With the dramatic drop in drilling, when would U.S. production start to fall? Decline rates for this new resource were not well understood. What was known, however, was it took a lot of rigs to create this production so greatly reduced drilling must have the opposite effect.
And decline it did. Because of the delay in completions, the Energy Information Administration (EIA) reports U.S. production didn’t peak until June 2015 at 9.610 million b/d. It would fall for 16 months until October 2016 when output was down to 8.450 million b/d. The drilling slump and decline rates helped take 1.160 million b/d of U.S. crude off world oil markets.
Supply exceeded demand in 2015 and 2016 by as much as 2 million b/d. Nobody shut in anything unless it was uneconomic. The surplus went into inventory. When OPEC and others decided to withdraw 1.8 million b/d from markets in late 2016, the U.S. had already eliminated half the overhang. With drilling and capital spending down worldwide, demand rising and natural declines rates continuously impairing deliverability, this was hardly a courageous move. In 1986, the Saudis shut in 5 million b/d to stabilize prices at US$18 a barrel.
That U.S. oil production and the number of rigs drilling for it are linked is clear. The issue is how much. A new term emerged from the shale gas and LTO boom called “rig productivity”, an analysis first published by the EIA October 15, 2013. It linked active rigs and production in the main LTO and shale gas producing areas: Bakken, Eagle Ford, Haynesville, Marcellus, Niobrara and Permian. The EIA connected rising output with active rigs by basin and used the calculations to forecast production. Being official EIA data, that many regarded this important is understandable.
By the fall of 2016, WTI was trading some US$20 a barrel higher than February lows and the rig count started to rise. The number of rigs drilling for oil was up 100, about 1/3. Crude continued to strengthen and then in December, thanks to OPEC, rose above US$50 a barrel for the first time last year. Baker Hughes says the U.S. exited the year at 525 rigs targeting oil, a 40% gain from May lows. Since oil prices had almost doubled from February lows, why not drill? Oil companies must replace reserves or they go out of business.
As higher prices held, the rig count continued to climb. Producers hedged future production and built budgets based on predictable cash flows. By March 31 there were 662 rigs drilling for oil, more than double the 2016 low. This fueled continued speculation that with all this drilling, it was only a matter of time before the U.S. LTO industry drilled itself into a new oil price collapse.
Typical coverage is a report that accompanied 10 more rigs on March 31 than a week prior, a 1.5% gain. The title blared “Oil Rig Count Soars” then continued, “The steady and sizeable jump in rigs signals an indifference by American shale producers towards warnings by the Saudi Arabian leadership against increased production…But cheap shale output from the United States is now threatening the effectiveness of the OPEC agreement, diminishing the likelihood of ending the supply glut”.
When was shale output ever “cheap”? If it’s cheap to develop why did the rig count collapse with oil prices? This never happened in the Middle East, the home of the world’s true low cost production.
On April 2nd, Reuters published an oil markets summary writing, “Adding to pressure on prices, energy services firm Baker Hughes said the U.S. rig count rose by 10 to 662 last week, making the first quarter the strongest for rig additions since mid-2011 and raising prospects for more U.S. shale oil”. While statistically this is true, what does it mean in 2017?
Meanwhile, the Canadian rig count has fallen over 200, only 144 on April 3 compared to 355 nine weeks earlier, its annual seasonal correction. Unless oil prices rise sharply, Canada’s rig count won’t be at this level again until next January. In Canada, LTO and liquids plays like the Montney, rig productivity is every bit as high as in the U.S. One operator published the test rate of one of its better Montney wells as coming in at 3,580 boe/day consisting of 1,490 b/d of 40 degree API crude and 12.5 mmcf/day of natural gas. A whopper by any measure. The U.S. is not in sole possession of North’s America’s prolific LTO and shale gas reservoirs.
Baker Hughes reports the world rig count (including U.S. and Canada) is finally above 50% of what it was in 2014, 2,027 in February compared to an average of 3,578 in 2014. Strip out North America (not including Mexico) and the February total is 941. In 2016 it averaged 955, making it lower than last year. It was 1,337 in 2014. At 382 the Middle East is about the same as has been since 2013. Deduct the Middle East, U.S. and Canada, the rest of the world only had 559 rigs drilling in February compared to an average of 565 in 2016 despite higher oil prices. That is just over half the 2014 average of 931.
If a rising U.S. rig count is a signal oil should go down, why doesn’t the vastly reduced Canadian rig count and the flat drilling globally drive prices higher? More rigs have come off the market in Canada that have been added in the U.S. since November 2016. Isn’t this a global industry?
Besides the U.S. rig fixation, there has been continual speculation about quantum increases in drilling efficiency. The premise is the U.S. can to some degree duplicate the 2010 to 2015 LTO phenomenon with a fraction of the rigs. While walking rigs drillings from pads certainly has equipment spending more time drilling and less moving, the major gains have been primarily in the completion; advancements in multiple stage completion systems coupled with more fracs using more sand. This is straight mathematics in a tight reservoir. The more cracks the more reservoir exposed to the wellbore resulting in more production. The process is in its technological infancy. Improvement should be expected and will continue.
But the implication the U.S. LTO machine will soon be the author of its own failure and suppress world prices with only 41% of the rigs from the 2014 peak operating is, to this writer, difficult to accept.
A big reason this many rigs are drilling at US$50 a barrel is because of collapsed service prices, not operator genius or vastly improved efficiency. Arthur Berman, a geologist, analyst and frequent commentator on the U.S. industry published an article on industry website oilprice.com March 22 titled, “Tech Miracle In U.S. Shale Is A Media Myth”. He estimates if there are gains in efficiency, “The savings are real but only about 10 per cent is from advances in technology. About 90 per cent is because the oil industry is in depression and oil field service companies have slashed prices to survive”.
A Bloomberg News Article March 24 predicted pending oil price pressure because of a growing “fraclog” of DUC wells, drilled but uncompleted. In February there were 1,764 DUCs in the Permian Basin alone. Consultancy Wood Mackenzie was quoted as saying if all these wells were put on stream tomorrow they could add about 300,000 b/d to markets. The article stated a portion of the drilling was to hold leases and the completion was 70% of the total cost.
Part of the delay is availability of frac crews under the current pricing regime. So, when the operators run the math, they must calculate it is more cost effective to wait to put the well onstream than pay the frackers more money to hire the people they need and invest in activating equipment to meet demand. U.S. drilling activity responds positively to higher oil prices but appears capped by higher service costs. Which is inevitable if growth continues.
Indeed, the rising U.S. rig count is putting more oil on stream. The EIA reported March 24 U.S. production was 9.147 million b/d, up 679,000 b/d from the mid-2016 low. But the International Energy Agency is forecasting 1.4 million b/d in demand growth in 2017. CERI/IHSE studied 811 oilfields worldwide and estimated annual natural depletion at 4.5% which will take over 4 million b/d off the market this year. This is a 5.4 million b/d spread that must be dealt with in 2017 to avoid shortages.
Having the U.S. rig count rise by 10, 20 or even 200 is great news. People are going back to work. U.S. imports are down. Canada and the U.S. always do better economically when the oilpatch is active. Estimates are U.S. output might rise by 1 million b/d in the next year.
But to look at this number alone in the context of a global oil business is a highly over-rated indicator of future prices. And if the U.S. can significantly increase production again, the big picture math indicates the world is going to need it to prevent a price spike.
Canada is putting 700,000 b/d more crude on stream in the next three years from new oil sands production. That’s three times April 3 headline reports of 250,000 b/d back on line from Libya. Why isn’t that news? Why doesn’t Canada make oil markets tremble, either with its volatile rig count or new production on stream starting later this year?
Other factors perhaps? WTI is the most actively traded commodity in the world. The Chicago Mercantile Exchange reported that in the year 2016 the average trading volume for WTI crude futures and options was 1.4 million per day. At 1,000 barrels per contract, this is 1.4 billion barrels daily. Oil production in the U.S. and Canada priced off WTI is about 13 million b/d. “Dry” barrels produced by speculators and computers outstripped “wet” barrels extracted from the earth by over 100 times.
There are clearly other forces at play when WTI wiggles on the weekly rig count besides alleged massive advances in rig productivity or low oil prices forever because of increased U.S. drilling.
About David Yager – Yager Management Ltd.
Based in Calgary, Alberta, David Yager is a former oilfield services executive and the principal of Yager Management Ltd. Yager Management provides management consultancy services to the oilfield services industry in a number of areas including M&A, Strategic Planning, Restructuring and Marketing. He has been writing about the upstream oil and gas industry and energy policy and issues since 1979.