Shaping a Portfolio for 2016: a data dump on oil

This time last year I was embarrassingly silent about oil, which I considered to have poor prospects–and still do.  So naturally I’m going to go overboard in the other direction now.

If there’s a method to my madness, it’s that  an interesting buying opportunity may emerge at some point during next year.  Especially so, if the current imbalance between supply and demand causes the price to fall significantly again.  That could happen as early as 1Q16.


Because many large oilfields are multi-decade projects that depend on a steady flow of output to the surface to maximize recovery of the underground oil, and because producers need the money to fund national spending or (in the case of small wildcatters) to service debt, the supply of oil into the market is relatively steady.

Not so demand.  We’re now in the high season for buyers, as the winter heating season in the northern hemisphere unfolds.  Late January through March are the lowest points of the year for demand.  Heating fuel has already been delivered to customers and driving is in its winter lull.  From April on, demand beings to build into the summer.  It plateaus from there until autumn heating demand causes the price to reach its yearly high point.

In a normal year, the oil price should be rising today.  But it’s falling instead–suggesting that the market could get ugly once the peak heating oil season is over.


What happens to the excess oil that’s now being produced?  It’s bought by arbitrageurs who store the stuff for future sale, while simultaneously entering into futures contracts to lock in a price.  The trouble is that, although no one has good numbers, global onshore storage appears to be getting close to being completely full.

There’s lots of offshore storage available–in oil tankers–but current rental rates imply crude would have to fall by $5 – $10 a barrel to make arbitrage trades economic.

the slow convergence of supply and demand

Ignoring seasonality, there’s probably on average 2 million barrels of excess crude oil now being produced each day.  That may rise by another 500,000 – 1,000,000 once Iranian sanctions are lifted next year.  Then there’s the temptation for government-owned producers to put a little extra on the market to help close the national budget deficit.  And there’s the creditor pressure on independent producers to continue to service their debt.

Demand is probably rising by about 1.2 million daily barrels annually.  The gradual removal of supply by high-cost producers is shrinking supply by maybe 500,000 – 1,000,000 daily barrels a year.  This would imply that we’d come back into supply-demand balance at the end of next year or in 2017.  Given all the moving parts–especially seasonality and Iran–it’s possible that there’ll be another price spike downward before we come back into equilibrium.  That’s where the buying opportunity thing comes in.

sensitivity to oil price changes

from low to high…

big international integrateds

smaller independent explorers

service companies–development and maintenance

service companies–new drilling

service companies–new drilling, offshore or hostile environments

Refiners don’t fit on this table.  They’re currently enjoying a field day because they’re not passing on all of the benefit of lower input prices to customers.  There are also non-energy companies, like steel producers, who may have important subsidiaries that make oilfield tools and supplies.

Two other important notes:

–integrateds aren’t quite in the favorable defensive positions that my table would imply.  That’s because for years they’ve been devoting large chunks of their massive cash flows to developing gigantic high-cost oil projects that may no longer have any economic justification

–some independents have enormous debt burdens.  While the most speculative may arguably have the highest return potential during a future selloff, that’s no good if they go into Chapter 11 before that potential can be realized.



oil: will falling prices reduce supply?

Ultimately, yes   …but only at lower prices than today’s., I think.

With any mining commodity, price declines normally end only when the highest-cost firms have to pay more to produce the commodity than they can sell it for.   Even then, if a production process is hard to restart or if the producers fear losing skilled workers permanently if they shut down, production often continues for a period even though cash flow is negative.

Petroleum has been an exception to this rule.  Oil had a period in the early 1980s when Saudi Arabia reduced its oil production dramatically in a vain bid to stabilize prices.  But its efforts were undone by other members of OPEC who agreed to cut production, too, but upped it instead to fill the vpoid left by Saudi cutbacks.  It took Saudi resumption of production and a consequent plunge in prices for the others to fall into line.  This time around Saudi Arabia has made it clear it won’t repeat its production-cutting mistake.

If cartel action won’t stop the current oil price decline, then we’re left with normal commodity forces to do the job.  The most likely production to shut down for cost reasons is output generated through hydraulic fracturing in North Dakota and Texas.  Estimates of cash production costs for fracked wells ranges from $40 – $60 a barrel.  In theory, therefore, production won’t be taken off the market until prices reach $60.  Even at that level, however, only a small amount of output will probably be lost–not enough for price stabilization.

One wild card:  bank loans.  Typically, smaller oil exploration companies of the type that have been successful with fracking try to boost their returns or speed their expansion by leveraging themselves financially.   Except in times of speculative excess, bank exploration companies contain restrictive covenants.  These normally mandate that the explorer must maintain reserves with a value of, say, 3x the amount of the loan.  If the value of reserves falls below a certain minimum, say 2x the value of the loan, the borrower is required to devote most or all of its cash flow to repaying its borrowings.  In other words, it can no longer pay a dividend to shareholders nor can it spend money on new drilling.  This last is potentially a big issue for frackers, whose wells tend to have relatively short productive lives.

My guess is that borrowings of the type I’ve just described will ultimately be the reason the oil price ultimately stabilizes, by halting the growth of fracking.  Two ways to gauge whether this is happening:  dividend cuts, and reductions in the number of new wells started.