As we have witnessed in the crude oil market over the past handful of years, the law of gravity also applies to commodity markets. While gravity is a measurement of how light or heavy a particular batch of crude oil is compared with water, the scientific principle may also provide a helpful analogy for the current state of affairs in the marketplace. Indeed, the last few quarters in crude markets have provided a deluge of information to process. From the lifting of the 40-year-old export ban on U.S.-produced crude oil, to headline-grabbing growth in global crude inventory levels, to secretive OPEC meetings we seem to hear about every month or so – an article could be written about any of these topics. But amid all of the media’s white noise, a central question of market fundamentals rises to the fore: When will the crude oil market finally rebalance? We don’t have all of the answers, and nobody does. In this article, we address four key questions affecting future crude supplies and aim to answer them.

The 40-year-old congressional ban on U.S.-produced crude oil exports was lifted in December 2015. How will this affect global crude oil physical flows?

Let’s start with the historical context of this legislation. In October 1973, in response to the Arab oil embargo, Congress banned U.S. companies from exporting U.S.-produced crude oil. Following the embargo’s announcement, domestic gasoline rations were quickly implemented, and lines across the country to refill gas tanks grew long: Domestic energy security raced to the forefront of the collective American consciousness. Congress had two policy objectives in mind when implementing the export ban: to conserve domestic reserves of crude oil, which were then believed to have “peaked,” and to replace U.S. imports of foreign-produced oil with consumption of domestically produced oil.


At the time, those objectives were hardly misplaced. For the first time in 50 years, domestic oil production was falling, and policymakers were preparing for a “new normal” of U.S. dependency on foreign-produced oil. During the five decades preceding 1970, U.S. oil production grew at an annualized rate of roughly 4.5%. In October 1970, U.S. crude oil field production peaked at slightly above 10 million barrels (bbls) per day before beginning to contract. Over the three years following the peak, field production fell at an annualized rate of just under 3%; in this short time frame, the United States’ perception of domestic energy security shifted dramatically. This exacerbated the embargo’s impact and magnified the legislative response to it. In connection with falling domestic production and OPEC wielding a strong fist, Congress banned the free export of U.S.-drilled crude. This was perhaps an appropriate legislative response to the market and geopolitical environment of the early 1970s, but as we fast-forward to 2016, the trends could not be more different.

Over the past six years, domestic exploration and production (E&P) companies have essentially drilled their way out of the ban. The advent of hydraulic fracturing technology led to a nearly 10% annual growth rate in U.S. crude oil (and lease condensate) production volumes between January 2010 and December 2015. This has resulted in a remarkable shift in U.S. dependency on foreign-produced oil, highlighted by the following chart, which compares U.S. field production to net imports of crude oil. As such, public sentiment around U.S. energy security has shifted perhaps as dramatically as it did during the early 1970s, albeit in the direction of less anxiety. As sentiment has changed course, legislators have come to see the export ban as an anachronism.


As early as spring 2015, we heard rumors that the ban would “soon” be lifted. By March 22, 2016, the difference between WTI1 and Brent prices had collapsed to roughly 20 cents per bbl. It thus appears that while a headline-grabbing regulatory change now allows companies to freely export U.S.-drilled crude oil, its near-term impact on global energy trade flows will be negligible. Recent data from ClipperData supports this view; according to the cargo analytics firm, year-over-year daily export volumes of waterborne U.S. crude oil declined 5% during the first three months of 2016. Congress’ lifting of the export ban appears to have anchored WTI prices to the global market, but there is simply too much oil stockpiled worldwide for U.S. crude to be attractive – especially when WTI costs virtually the same on a per barrel basis (before shipping costs) as its “competitor,” Brent crude.

The global crude oil supply and inventory glut – addressed in our next question – has resulted in slim demand for U.S.-drilled crude. This has been compounded by sheer chemistry, taking into consideration the global refining industry is mostly hardwired to process the more sulfurous, heavier crude oils produced by the Middle East, whereas North American shale oil is light, sweet crude that is arguably ill-suited for processing by non-U.S. refineries. In conclusion, while the lifting of the export ban will likely keep WTI, LLS2 and Brent prices in a reasonably tight range over the medium and long term and is unlikely to alleviate the U.S. supply glut, it will likely mean any temporary differences between those various pricing mechanisms will be arbitraged away by physical traders more quickly.


Will U.S. production cuts reverse the global storage buildup?


We are in the thick of a well-publicized global crude oil inventory glut, driven by several years of production growth supported by free-flowing capital markets. Over the course of the past decade, E&P companies worldwide have issued $121.7 billion of high-yield debt. Issuance has been concentrated to U.S. shale; of the entire amount, 75% – or $91.1 billion – was issued by junk-rated U.S. E&P companies during the past five years. As the following chart indicates, capital markets have been extremely accommodative to sub-investment grade U.S. shale producers, particularly since 2010. This convergence of capital and technology in the oil patch resulted in supply growth outpacing demand growth, with excess production placed in storage. Before the supply/demand equation can return to equilibrium, excess inventory needs to be consumed, and production must slow. Prices and access to capital will drive the latter. This will take time – perhaps longer than many expect.


Recent U.S. Energy Information Administration (EIA) estimates indicate that in fourth quarter 2015, global crude production still outpaced demand by nearly 700,000 bbls per day, which implies a global inventory build of about 63 million bbls during the quarter.


Excess production continues to plague the market despite a substantial cutback in E&P investment, particularly by U.S. shale producers, where consensus 2016 capital expenditure estimates across a representative basket of 13 investment grade E&P companies fell 45% year over year for 2015 and projected an additional 26% decline during 2016. This has resulted in domestic crude production dropping nearly 5% – or between 400,000 and 500,000 bbls per day – from its peak of just below 9.7 million bbls per day in April 2015 to roughly 9 million bbls per day currently. More cuts must be made to address the remaining imbalance.

Using the EIA forecast, U.S. shale producers would need to cut between 7% and 8% more from current production volumes in order to single-handedly take EIA’s estimated daily surplus out of the global market. While they may continue to cut if prices return to the $30s, supply discipline cannot come from U.S. producers alone, particularly with financial leverage near historic levels. This leads to our third driving question on crude supplies.


When will conventional capital stop flowing?

Break-even crude oil prices vary widely across drilling regions – from as low as 25 cents per bbl in some areas of Saudi Arabia to as high as $100-plus per bbl in Arctic and certain offshore drilling projects. In North America, drilling costs typically range from $30 or less per bbl on the low end to $80 or more per bbl on the high end. It stands to reason that higher-cost production is “shut in” – the pump is turned off – when barrels come out of the ground at a loss, but the decision is not as intuitive as “when production costs exceed the price of oil, stop pumping.” Part of this phenomenon can be explained by the amount of financial leverage in the sector. In order to pay down debt, the industry must keep producing oil and generating cash flow – even in environments where it may not produce an attractive return for investors. This can delay the inevitable reckoning. Having said that, a can may only be kicked so many times before it turns into a square and stops rolling.

Nowadays, E&P companies’ balance sheet debt loads remain heavy, and industry access to capital markets will play a large role in the length of time it takes for them to restructure their more onerous obligations. An examination of 13 investment grade integrated oil companies’ financial statements indicates that even the highest quality balance sheets in shale show signs of weakness.


The nearby chart depicts median total debt against median last-12-month (LTM) EBITDA for a basket of North American investment grade integrated oil companies. This reflects only a (relatively speaking) high-quality subset of domestic E&P companies that are investment grade, so it may be seen as an optimistic view of the broader shale industry. After years of growing profits and typical EBITDA leverage of about 1x, industry earnings have fallen into negative territory. Equity markets have thus become more expensive – if they can even be accessed – due to the increased risk in the sector. Fixed income markets, too, have become more difficult to access as cash flows have fallen and leverage has increased. The combination of falling cash flows and growing leverage has led to a classic “debt spiral” where producers at times must choose to drill at loss, sacrificing near-term profit for the simple cash flow required to service debt and prolonging and compounding the supply problem.

The debt spiral phenomenon highlights the perils of using significant leverage in a cyclical sector where the borrowers are price takers selling a commodity. While deleveraging can occur quickly in a rising price environment, this environment tends to promote investment and production growth as opposed to deleveraging. As production grows and capital flows freely, supply tends to overshoot demand; prices fall, and producers are stuck holding significant debt at the very time when cash flow is lower – and as a result, the ability to service that debt is shrinking. Many producers are facing this exact environment today. While there are certain factors delaying this inevitable reckoning, the process has already begun and – unless prices start to rise – should result in a continued decline in U.S. production.

Can we look to OPEC for the necessary production cuts?

Here we turn the page from domestic to global crude markets. Domestically, we have already seen some production restraint, but falling North American production may not be sufficient to address the supply imbalance. Turning to the global supply outlook, OPEC does not appear to be cutting. Hardly a week goes by without news of an OPEC meeting taking place, and the media is usually quick to draw conclusions from attendance and outcome. Most of these meetings have indicated that OPEC members (excluding Iran) have agreed to freeze production at current levels. Even if Iran joined its OPEC counterparts in freezing production, failing a unified commitment to cut production by all members, we have a difficult time painting a picture where the crude oil market rebalances in the near future. Perhaps, though, we can try to draw a silver lining on an otherwise cloudy outlook.


Seasonal Saudi crude production levels may provide a glimmer of hope. As the nearby chart depicts, Saudi Arabia has historically increased daily production volumes in order to meet additional “cooling days” demand arising from the increased use of air conditioning throughout the arid Middle East. If the country keeps its pledge to hold production volumes flat to January levels, it will have the net effect of taking about 45 million bbls of total supply offline for the final three quarters of 2016. Unfortunately for oil bulls, this relative cut in Saudi production equates to a reduction of about 166,000 bbls per day to the current global crude surplus of 700,000 bbls daily, which still leaves the market in a net surplus of more than 500,000 bbls per day. We are left hoping for supply restraint and are facing some producers who want anything but.

As noted, while Saudi Arabia and the rest of its OPEC brethren have pledged to freeze production levels, Iran has not joined the crowd, and Iraq is waffling as a result. Following the lifting of sanctions, Iran in late February 2016 expressed a commitment to return its sovereign crude oil production to pre-sanction output levels of 4 million bbls per day. Current Iranian production totals roughly 3 million bbls a day, meaning the country has telegraphed to the market a targeted production increase of roughly 1 million bbls of daily output. Iraq’s oil minister, Adel Abdul Mahdi, was soon to respond: “If some people freeze and others raise, then this is not a good policy. … [W]e have to reach a complete agreement.”

Complete agreement seems nearly off the table at this point. Iran has pledged to increase production, so it seems neither Iraq nor Saudi Arabia is likely to commit to a cut.


There are, of course, several OPEC producers other than Saudi Arabia, Iran and Iraq, each of which competes in its own interest of balancing sovereign social obligations with the ability to fund them. While we see a complete and unified agreement of OPEC members as unlikely in the near future, members do share a common goal of preventing social unrest. A recent International Monetary Fund (IMF) report published in October 2015 (when crude prices were closer to $50 per bbl) suggested that low oil prices would wipe out $360 billion in sovereign revenues from the Middle East during 2015 alone. Massive surpluses have turned into growing deficits, and “oil exporters will need to adjust their spending and revenue policies to ensure fiscal sustainability.” After years of huge budget surpluses, Saudi Arabia’s cash reserves are still substantial at $700 billion but are dwindling fast. At this rate, the IMF estimates the kingdom has enough of a rainy day fund to survive five years of $50 oil. The country responded with a plan to free its economy from oil dependency over time. There is still a day of reckoning approaching in global oil markets too – when it comes is anybody’s guess. Whereas U.S. shale producers appear to be in a game of chicken with capital markets, OPEC producers seem to be in a game of chicken with themselves. There will be winners, and there will be losers – and we are watching closely.



In conclusion, the past few years have shown that crude, along with most commodities, is bound by the laws of gravity. Now more than ever is a reminder that commodities are cyclical and that what goes up most often comes down. We balance this view with the age-old adage that the best cure for low prices is often – you guessed it – low prices. Although many factors point to a “lower for longer” environment, we cannot ignore the influence of geopolitics on short-term oil prices. Short-lived spikes aside, the market remains bound by its fundamentals, which currently tell us this:

  • We have likely already seen the eye of the hurricane. The storm will pass, but that will take time. There is a global crude inventory glut that took well over two years to build, and it will probably take a similar amount of time to dissipate. While we don’t see lifting the U.S. crude oil export ban as adding the time it will take for demand to work through global crude stocks, we also see very few things as reducing this time frame. A coordinated OPEC production cut would be one of them. Unfortunately, we believe that is unlikely to take place given the social welfare requirements of Middle East sovereigns.
  • Looking closer to home, between 2010 and 2015, U.S. shale companies took on massive debt loads in accommodative capital markets. The cash flow required to service these obligations in the short term now incentivizes E&P companies to continue pumping crude into the market, even when doing so at a net loss. This leverage issue can only be resolved by a combination of industry deleveraging and restructuring – a process that by its very nature requires higher prices or restructuring/capital losses, meaning it will likely happen over the course of years. Having said that, the amount of time over which deleveraging takes place is largely a function of when capital markets grind to a complete halt. Only then will prices recover, improving cash flow, debt service and setting the stage for the next phase in the price cycle.   

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1 West Texas Intermediate.
2 Louisiana Light Sweet.