Now, I should start by confessing to being totally wrong on this type of occurance happening. While I'm not quite convinced that I need to scrap my overwall Peak Oil Dynamic world view (explained here), this certainly has caught me by surprise.
One of the key factors of the Peak Oil Dynamic world view was that the conventional cheap oil is shrinking both in aggregate and proportionally to expensive and/or unconventional sources. That logic led me to believe that the offshore oil market would be strong going forward and we'd see oscillating prices around that $100 mark for awhile but likely a steady secular rise in prices until someone figured out renewables.
Obviously, the oscillation didn't happen. Why? This is a supply side phenomenon.
|From the IEA|
So the collapse in price must be supply side.
Where that supply is coming from is interesting. I'd think about this 'new oil' in two seperate categories: expensive oil and cheap oil. Basically, expensive oil is the oil that was made available due to the $100+ price of oil (and SOME technological improvements, but don't kid yourself it was mostly the price), and the cheap oil is the production that is from conventional legacy sources that for political reasons have not operated at or near full capacity in some time. Think Libya, Iraq, Iran, etc.
Now, price certainly has an impact on cheap, politically sensitive oil production levels. But those effects are typical complex and to entangled in secondary and tertiary political/social/economic effects and so I will leave them be.
The more interesting of these two sub-sections of 'new oil', the expensive stuff, are where things will get interesting and where marginal barrells will be taken off the market if an exogenous supply reduction is not imposed.
In terms of simple Econ 101, suppliers will either make due at the lower price level, or we would expect the marginal producers (those requiring $70-$100+ oil to maintain operations) will drop off.
In oil's case, things are complicated by the wide divergence in a number of factors, a few of which are: 1). the sunk cost of different production methods, 2). the decline rates of different production methods, 3). what market the oil is sold into, 4). the firm's fiscal health, 5). the firm's hedging strategy.
Again, mix, oil, politics, and big business, and all you can do is make guesses. Popular opinion seems to be fairly mixed, with a number of folks suggesting that the wheels will fall off the shale boom and other suggesting they've all hedged out any risk.
This piece in the Telegraph has a few interesting items:
US producers have locked in higher prices through derivatives contracts. Noble Energy and Devon Energy have both hedged over three-quarters of their output for 2015.
Pioneer Natural Resources said it has options through 2016 covering two- thirds of its likely production. “We can produce down to $50 a barrel,” said Harold Hamm, from Continental Resources. The International Energy Agency said most of North Dakota’s vast Bakken field “remains profitable at or below $42 per barrel. The break-even price in McKenzie County, the most productive county in the state, is only $28 per barrel.”So those are the headline numbers, but this of course begs the questions: how do you determine the break even cost? Is that break even on existing production? Is that break-even to maintain current production levels? Is that break even to maintain current growth rates in production levels?
And all credit to this article for taking the time to wade into this discussion but I have to disagree with the following quote from Ed Morse at Citigroup:
Mr Morse says the “full cycle” cost for shale production is $70 to $80, but this includes the original land grab and infrastructure. “The remaining capex required to bring on an additional well is far lower, and could be as low as the high-$30s range,” he said.
Critics of US shale may have misunderstood its economics. There is a fast decline in output from new wells but this is offset by a “long-tail phase” for a growing number of legacy wells. The Bakken field has already reached 1.1m bpd, and this is expected to double again over the next five years.I don't believe we know too much about how these legacy wells will behave. Also, we need to remember that these growth rates, in the context of fast production decline, are necessarily the result of increased drilling.
Now, to maintain drilling, you need to maintain acerage and the expansion of infrastructure IF prices remain depressed beyond what drill sites have been allocated. Beyond that then the full cycle cost is back in play.
Another items to consider is that the best portions of an oil play typically get drilled up first. Of course, a play isn't known in it's entirety from the get go, but it's not unrealistic to expect that the 'sweet spots' are more likely have played a starring role in the ramp up in production.
Also, remember that when companies are talking about break even costs in the media they also have stock prices to maintain. Any highly leveraged play gets increasing leveraged when stock prices dip. That combined with a reduction in cash flow (even if most of it's hedged) is a dangerous game to play.
So you want to watch for a couple of items: a reduction in drilling activity and a reduction in the per well production rates.
This article in Reuters showed a reduction in drilling permits issued dropped over 40% in November, which is a bit of an eye opener. But to be honest with you, I don't have a clue about the typical fluctuations in permits so I took it with a grain of salt.
The author also cites Allen Gilmer at Drilling Info who suggested that this was mostly due to companies wishing to avoid tapping new sweet spots in this depressed price environment. So the exact opposite of what I said above.
Who the hell knows. But it should be interesting to watch.