We have just come out of a period in which crude posted a modest recovery. Through close on Nov. 3, West Texas Intermediate (WTI) - the crude benchmark traded in New York - had improved to $47.90 a barrel, up 4.3% for the week. Dated Brent, the equivalent benchmark set in London, was at $50.52 - higher than at any point since Oct. 9.
WTI closed at $42.93 Wednesday, down 1.4% in the six intervening sessions. Meanwhile, Brent was at $45.83, down 9.3%. Both are sitting at two-month lows.
The "culprit" was another anticipated rise in oil production, primarily in the United States. Despite weekly declines in the number of working rigs in the American market (now at the lowest levels in some six years) and, as I noted earlier this week, rising cuts in capital commitments for new projects, the market surplus in oil is once again rising.
Crude oil prices are languishing in the face of what is projected to be another build in U.S. production stockpiles.
Given all that has been said about an oil glut, why is oil production continuing?
Field Technology Has Advanced at a Rapid Pace
There are two overriding answers.
First, as the surfeit of shale and tight oil production hit the market a year ago, and continued thereafter, developments in field technology advanced even quicker. When oil prices were north of $80 a barrel, operational costs were of little consequence.
True, well efficiency was not something entirely discounted. But the profit margins were so large that companies could provide nice returns by running more or less traditional operations.
Remember (as I have observed in Oil & Energy Investor on a number of occasions), most companies were cash poor during much of the last decade, with a ready and affordable debt market only too eager to make up the working difference.
When prices began the downward spiral, however, and continued descending by some 60%, efficient field operations became essential. The more expensive new projects were mothballed, but new approaches to drilling, pad design, well completion, and workovers were introduced, declining wellhead costs.
Added to the technological improvements one could see on the surface, advancements in enhanced and secondary recovery techniques downhole brought more oil up from each well. The average production, coupled with a greater amount of known reserves becoming accessible, began to rise.
More Efficient Field Operations Boost Surplus
Now, in the case of unconventional (shale/tight), horizontal, deeper, fracked wells, the primary production would still come up in the first 18 months or so. Extraction would continue longer than that but at an increasingly reduced rate.
Some of these wells could experience a short-term improvement via water flooding, natural gas injection, chemical treatments, or other secondary/enhanced techniques. Yet as the market price declined, for larger projects these techniques became cost ineffective. Companies would cream the easiest production from first flow.
Nonetheless, the aggregate amount of oil coming up significantly expanded. The primary reason for the current consistent surplus arises from the introduction of more efficient field operations, allowing cash-strapped companies to continue production even as the wellhead price (the producer's revenue from the first exchange of oil, always lower than the resulting market price) went down.
Debt Leads Producers to Pump More
That set the stage for the second factor. Given that 80% or more of overall project expenses are front loaded (that is, spent before anything comes out of the ground), a company will want to recover investment by a resulting oil flow... even if that flow is feeding into an oversupplied and lower-priced market.
This need to sell what comes up is accentuated by the intensifying fiscal squeeze now under way. Most operators are carrying heavy debt. Previously in a higher-priced market, companies would simply roll over that debt into new paper. Unfortunately, energy debt now occupies the most risky range of "junk bonds" (high-yield debt well below investment grade).
Even if new bonds can be obtained, they carry unsustainable interest rates with default risk increasing in a low crude pricing scenario.
The recent rise in companies being unable to operate in this squeeze has resulted in moving as much additional volume to market as possible in a desperate attempt to stay one step ahead of the sheriff.
Making Money Has Nothing to Do with Waiting for High-Priced Oil
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The combination of additional volume per well resulting from better applications and the dire straits of more companies trying to stay above water means every time a recovery in price is experienced, the market is likely to see additional oil for sale.
Of course, this is hardly a long-term effect. More bankruptcies, mergers, and acquisitions will ensue. Ultimately, the market will rebalance with fewer players and the price will drift higher.
But there is going to be some pain from the "creative destruction" under way.
Investors need to understand that making money in the current energy sector has nothing to do with waiting for oil to return to $100 a barrel. This is all about identifying those companies that are going to maintain and increase market share.
That will be taking place well before the price of oil begins to accelerate.
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Upheaval in the Oil Industry: As oil prices continue to languish, companies are cutting back on new project investments. That's not surprising, but the range of the spending pullback is. And this development is spurring a second, more extreme effect on the sector...
About the Author
Dr. Kent Moors is an internationally recognized expert in oil and natural gas policy, risk assessment, and emerging market economic development. He serves as an advisor to many U.S. governors and foreign governments. Kent details his latest global travels in his free Oil & Energy Investor e-letter. He makes specific investment recommendations in his newsletter, the Energy Advantage. For more active investors, he issues shorter-term trades in his Energy Inner Circle.