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FreightWaves oil report: the numbers don’t lie; the market is getting tighter

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A weekly look at what occurred in the oil markets of the U.S. and the world this past week.

The monthly reports of the International Energy Agency and OPEC, both released this past week, reflect just how much the world’s crude oil markets have tightened.

The reports contain a massive amount of numbers, but in discussing balance, a few figures  stick out.

The first is what OPEC refers to as the “difference” and what the IEA refers to as the “call.” It’s the amount of crude oil that is needed to be produced by OPEC to keep the market from drawing or building inventories.

For 2019, the “difference,” according to OPEC, is an average of 30.3 million barrels/day (b/d). Quarterly estimates range from 29.46 million b/d in the fourth quarter to 30.94 million b/d in the second quarter.

After all the cutbacks implemented by its key members, and the reductions in output from those nations that are in various states of turmoil, like Libya, Nigeria and Venezuela, OPEC is already there, according to the organization’s report. S&P Global Platts estimated OPEC output at 30.23 million b/d in March. OPEC itself, by looking at what it calls secondary sources – drawn from organizations like Platts – said OPEC output in March was 30.022 million b/d. Both those numbers are less than what OPEC said is the 30.3 million b/d “difference” between global demand and the amount that non-OPEC countries (and OPEC will produce as NGLs) are expected to put on the market this year.

Then look at those amounts and compare them to what OPEC’s survey of secondary sources reported for the third quarter of 2018 (average production: 31.961 million b/d) and the fourth quarter (32.087 million b/d). The scope of what OPEC has done is impressive even if you don’t like the outcome. OPEC met in December, said it was going to reduce output by 800,000 b/d and instead is down almost 2 million b/d from the average fourth quarter supply.

OPEC also looks closely at global inventory levels in making its decisions. In its latest monthly report, it said stocks in the OECD nations – mostly what are considered the “western economies” – at the end of February were about 17 million barrels more than inventories a year ago and 7.5 million barrels more than the five-year average inventories of end-February. But inventories also can be counted in terms of “days cover,” defined as how many days consumption could be supplied solely by inventories. At the end of February, it was 60.6 days, 1.1 day less than the five-year average. The sum of all this is that OPEC has gotten output down to a level where inventories won’t be building and instead might draw, and the inventories are down at levels that would be considered normal.

These developments led this past week to a few hints that when OPEC meets in June – it already delayed its April meeting – that it and the non-OPEC group headed by Russia might claim some sort of victory. A report out of Reuters, datelined from three significant oil cities – London, Moscow and Dubai – said the organization might raise output beginning in July if production from Venezuela and Iran continues to decline.

The OPEC monthly report put Venezuelan average output at 732,000 b/d in March, down a little less than 400,000 b/d from February and down about 500,000 b/d from the average third quarter 2018 figure. U.S. sanctions are increasing that decline – and may largely have caused it –  which raises the question of what a government led by Donald Trump, tweeting regularly about oil prices being too high, will do on the issue of waivers from the sanctions imposed on Tehran.

Those waivers, granted last fall, are in the process of expiring. The fact that the waivers were granted is said to be one of the reasons why Saudi Arabia led the charge at the OPEC December meeting to implement cuts, the thought being that if President Trump was going to grant waivers for Riyadh’s regional foe to keep producing despite lots of anti-Iran talk, it would just ignore his tweets and cut production to stabilize the market.

Given those cuts and the ones that keep coming out of Libya and Venezuela, a CNBC story’s headline this past week summed up the dilemma the administration faces: “Trump wants to drive Iran’s crude exports to zero. The oil market is not cooperating.” The story discussed what everybody knows: to get Iranian output to zero – it produced about 2.7 million b/d in March – is going to effectively mean asking OPEC to reverse all the cuts it has made since December and then look for another 700,000 b/d of increased output somewhere else. Just about everybody would agree that this isn’t going to happen (and that assumes Venezuelan or Libyan output doesn’t get any lower).

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The Chevron (NYSE: CVX) acquisition of Anadarko (NYSE: APC),, announced Friday at a cost of $33 billion, is important on many fronts but one of them is the increasing investment by big companies in the U.S. shale play, particularly the Permian Basin.

Capital has flowed into shale players for years. But there often has been a gold rush frenzy about it, because after all these years, shale producers are generating enough cash flow to service their debts, keep producing but often not enough to provide capital for the next round of investment (or pay dividends). That means another trip to the banks, which have continued to provide funding despite repeated concern that the spigot may shut.

Anadarko – which has significant acreage in the portion of the Permian Basin known as the Delaware Basin, as well as assets in the Colorado area – is one of the biggest independent producers in the country and it was carrying a significant debt burden. According to Barchart, Anadarko’s debt to equity ratio was 1.41, while other independent producers with activity in the Permian were far less than that. Diamondback (NASDAQ: FANG) was 0.32 and Concho (NYSE: CXO) was 0.22. Chevron is 0.18.

The investment by companies with enormous access to capital is a trend in the Permian in particular and shale in general that has been ramping up over the past year. BP (NYSE: BP) made a $10 billion acquisition of shale properties from BHP (NYSE: BHP) last year and ExxonMobil (NYSE: XOM) has vowed to increase its spending and production in the Permian by enormous amounts.

These transactions will push aside the smaller companies that led the charge in the Permian these past few years but what comes after should be a steadier investment flow and streamlined operations that operate more like a normal business. The question going forward then for companies hoping that the shale will continue to provide a stream of oil to keep prices in check –   like transport companies – is whether the gold rush mentality eases and output slows, or whether this stable steady source of capital will provide longer, more sustainable output…or maybe both.

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John Kingston

John has an almost 40-year career covering commodities, most of the time at S&P Global Platts. He created the Dated Brent benchmark, now the world’s most important crude oil marker. He was Director of Oil, Director of News, the editor in chief of Platts Oilgram News and the “talking head” for Platts on numerous media outlets, including CNBC, Fox Business and Canada’s BNN. He covered metals before joining Platts and then spent a year running Platts’ metals business as well. He was awarded the International Association of Energy Economics Award for Excellence in Written Journalism in 2015. In 2010, he won two Corporate Achievement Awards from McGraw-Hill, an extremely rare accomplishment, one for steering coverage of the BP Deepwater Horizon disaster and the other for the launch of a public affairs television show, Platts Energy Week.

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