How did this happen?

It basically comes down to three things. The first is that obviously more oil was found. For example, in 1965 Alaska’s Prudhoe Bay and its 25 billion barrels of oil had yet to be discovered.

The second is that technologies for recovering oil from existing fields improved. Shell geophysicist M. King Hubbert is often credited with correctly predicting in a 1956 paper that U.S. oil production would peak in 1970. What many don’t realize is that this was a secondary prediction. He actually predicted that U.S. oil production would peak in 1965, and qualified that prediction by stating that the peak could happen as late as 1970. But he was skeptical about the latter date because he said that would require the U.S. to find additional oil fields equivalent to “eight East Texas oil fields.” But those oil fields continue to be “found” by applying new recovery technologies to producing fields and increasing the recovery percentage.

The third factor comes down to the way proved reserves are defined. As I discussed in more detail in a recent issue of The Energy Letter, the U.S. Securities and Exchange Commission (SEC) requires that in order for reserves to be counted as “proved,” the oil must be “estimated with reasonable certainty, from the analysis of geologic and engineering data, to be recoverable from well established or known reservoirs with the existing equipment and under the existing operating conditions.” Undeveloped reserves can also be booked as proved provided the previous criteria are met and there is a development plan for drilling within five years.   

These three factors explain why oil production has far outstripped what expectations might have been given estimates of proved reserves in the past. Today’s R/P ratio in the U.S. of 12.1 years is really a reflection of the oil development that is in the pipeline at current prices. In recent years, U.S. reserves have gone up as higher prices made shale oil economical to produce, and resulted in lots of shale oil reserves being added to the proved reserves tally.

The reason that the world as a whole has a much larger R/P ratio is that other countries don’t have to abide by SEC rules in accounting for their proved reserves. As a result, there is a lot more uncertainty about the global reserves figure.

But it is safe to say that we will be using oil for decades to come, and when we do move on to something else there will still be plenty of crude left in the ground.

(Follow Robert Rapier on Twitter, LinkedIn, or Facebook.)

Portfolio Update

ConocoPhillips Output to Grow Despite Cuts

We have an early leader in what is sure to turn into a procession of capital spending cuts by drillers responding to the collapse in oil prices. ConocoPhillips may have more proven reserves than ever, but it’s not in a big hurry to extract them at a faster rate with Brent crude now down more than 40% in six months.

On Monday, the company unveiled a $13.5 billion capital spending plan for 2015 representing a 20% cut from this year’s budget. ConocoPhillips cited the reduced funding needs from several major projects nearing completion (notably in Australian liquefied natural gas and Canadian oil sands.)

The nearing start of these projects will also help ensure that the company’s 2015 oil and gas output rises 3% despite the spending cuts (and excluding Libya), ConocoPhillips forecast.

Still, the company is taking a big step back in North American shale development, where the development drilling budget has been reduced from $6.5 billion in 2014 to $5 billion next year.

The cuts primarily target emerging shale plays in the Permian, Niobrara, Montney and Duvernay, while proceeding with drilling in the sweet spots of the Eagle Ford and the Bakken, where Conoco’s full-cycle finding and development costs (including land acquisition) run at $20 to $25 a barrel.

The takeaway from this Conservative Portfolio Best Buy is that oil production gains won’t halt right away in response to the price collapse. Some of that is based on long-term projects entering service at precisely the wrong time, and some from sheer inertia.

The U.S. Energy Information Administration has just projected, for example, January growth matching December’s rapid output gains in the Eagle Ford, Bakken and the Permian, thanks to improving drilling rig productivity and new stimulation techniques. It will take time for the capital spending cuts to slow drilling enough so that  the decline of working wells can starts to offset the productivity improvements.

But while for ConocoPhillips the cuts were largely optional, they’ll be unavoidable for many smaller and more leveraged drillers facing higher production costs and now a significantly higher financing costs. By the reckoning of Plains All American Pipeline (NYSE: PAA) CEO Greg Armstrong, U.S. shale drillers in the aggregate spent some $100 billion drilling for crude in the major basins this year, far in excess of their cash flow from operations. Meanwhile, the oil price crash will likely cost them as much as $50 billion in annual revenue, before hedging offsets.

The numbers suggest drilling will inevitably slow with a lag of some months, and once it does the relatively fast decline rate of shale wells will ensure that output growth tails off as well.

Those months (at least) might as well be eons on the time scale favored by the fast-twitch futures traders, though, which explains why no one in the futures pits is much impressed by the inevitability of a price rebound.

Still, with sentiment in crude as bearish as it’s ever been, at least a dead-cat bounce should be near. Over the longer term, ConocoPhillips’ excellent assets, solid balance sheet and strong operating record should help it not only weather the storm but possibly capitalize on others’ misery along the way. COP is the #5 Best Buy below $78.     

— Igor Greenwald