Time for a switch in focus, from the philosophical yesterday to the prosaic today. It’s that time of the month for some hard numbers from “frack land”, i.e., the good old USA. What is more, I am going to stick my neck out today and call the top for US crude oil production.
The US government agency the Energy Information Administration (EIA) reports monthly crude oil production with a 2 month lag; January 2015 data were published on 30 March. January saw oil production averaging 9.2 million barrels per day, a rise of 14.8% year on year. Over the previous month, production was down slightly. Nonetheless, we did see a month-on-month decline in November only for production to power to a new record again in December.Yet I’m still calling the top.
True, growth has far exceeded what I expected when I started writing this blog. The production surge is indisputable (here, click for larger image).
The reason why I didn’t expect to see output rise so far so fast was due to the high production declines rates exhibited by tight oil plays, leading to what many call the ‘Red Queen’ syndrome: the need to run faster and faster just to stand still. So a mea culpa on my side: the US shale oil industry did run faster and faster. With global crude oil prices locked above $100 barrel for three long years, we got both a lot more rigs and, critically, more efficient rigs as fracking technology advanced. This was enough to overwhelm the naturally high depletion rates.
But behind this heartening story of US innovation, major fragilities still remain. First, note that the US tight oil-producing regions are dominated by the Big Four: Bakken, Eagle Ford, Permian and Niobrara. Everything else is a side show (click for larger images on all charts; source of this series of charts the EIA here).
The two most mature regions among the Big Four–Bakken and Eagle Ford–suffer from the highest depletion rates since they have more mature wells in aggregate. So if you want to keep production up in these regions, you have to continually introduce a lot of new, super-efficient rigs.
However, while the efficiency of new rigs is going up, the number of rigs is going down. Result: these regions have already topped out production-wise. Here is Bakken:
And here is Eagle Ford:
I won’t repeat the graphs for the smallest of the Big Four Niobrara, but they are also now witnessing a production decline. Which takes us to the Permian. In this region, the rig count has also headed south, but efficiency of new-well oil production has shot up.
The EIA points to the retirement of vertical rigs as the major reason behind this change (here).
Nonetheless, there is one key difference between the Permian on the one hand and the Eagle Ford and Bakken regions on the other. New well oil production per day is 700 barrels per day for Eagle Ford and 600 barrels per day for Bakken. By contrast, Permian is 250 barrels per day. In short, Permian is a lower quality play. And lower quality means more expensive.
This brings me to the second factor supporting my claim that we have reached the top. Tight oil production has been financed by a sea of easy money. In fact, everything has gone right. We have seen a low risk free rate (treasury bond yields) and compressed risk premiums (the treasury junk bond spread). We have also seen shale play related paper (equity and fixed income) come to market on the back of rosy net present value (NPV) calculations. But these NPVs were built on an oil price that was not only high but also lacking in volatility. In short, they were valuations bereft of risk. This has all changed. Now we are predicting not only lower cash flows but also riskier cash flows. Consequently, the ability to finance low quality wells is evaporating.
This is a huge head wind for the industry. Yes, technology is getting better, but geology isn’t. This is an industry which moves from the best prospects first to the lesser prospects second. Other things being equal, costs go from low to high. Technological progress may offset this, but it cannot also cope with the oil price going from high to low, and financing costs going from low to high.
Third, we are just about to see two safety blankets get ripped away. The industry has an inventory of existing wells with already sunk costs. These can justify their existence as long as the oil price remains higher than the operation and maintenance cost. But these sunk cost wells are depleting away over a time frame measured in months. At the minute, they are cash cows, but only for a short while longer.
At the same time, oil futures contracts are rolling off. The bulk of hedging takes place over relatively short time horizons of 18 months or so, since that is where the best liquidity exists. But a good finance manager will layer his contracts so they are maturing and opening in a smooth succession. At the minute, new contracts are theoretically being opened at $58 for April 2015 or so (although I expect that few actually are being opened) and old ones are being rolled off which were contracted at $100 or so. The old contracts provide a cash flow buffer. Over the course of this year nearly all this will be gone.
All in all, these factors have the potential to create a perfect storm. I wouldn’t like to manage a tight oil company at the present time.
I think it is still a little too early to call the US peak. It depends on how high oil prices go and how soon they get there again. If we see another oil price peak without an increase in production to exceed the present rate, then one can call the peak.
A fair number of folks were calling a peak after the financial crisis (undulating plateau and all that), but post-crisis high prices stimulated production to even higher levels.
My takeaway from the last ten years – a peak can only be called when prices have fallen after an extended period of high prices and the production rate did not exceed the rate from the previous price cycle.
Joe. I was really only calling the peak for the current cycle. That said, I would probably put money on this being the secular peak as well. Even if oil moves back up to $100 by year end, the hiatus in rig deployment coupled with Eagle Ford and Bakken moving into much deeper decline would make it a lot tougher to hit new production highs. Note that the EIA and IEA were both forecasting tight oil production would go into decline starting around 2019 even before the oil price collapsed