Experience RS

If It Hurts Too Much, Shut It In

Bio
Author

Ian Nieboer, P.Eng., CFA, Managing Director

Author Biography

Ian specializes in asset characterization and financial modeling, with a focus on offshore and international plays (both conventional and unconventional) and the companies pursuing those opportunities. In addition to publishing frequent research notes, Ian delivers conference presentations, television interviews and advisory mandates for corporate and institutional clients. Prior to joining RSEG, Ian progressed through a variety of field and development engineering roles at Canadian Natural Resources where his responsibilities included developing and executing drilling programs across multiple plays in Western Canada, evaluating acquisition opportunities, estimating reserves, designing completions, and optimizing production. Ian is a CFA charterholder and a registered professional engineer in Alberta. He holds bachelor degrees in engineering physics and applied economics from Queen’s University and an MBA from IESE Business School.

Oil prices fell below $25/bbl last week as the market grappled with impact of a price war between Russia and Saudi Arabia as well as rising expectations for COVID-19 oil demand destruction. The inconvenient overlap of a demand and supply shock means the oil market will be severely oversupplied in 2Q20, so much so that some fear overwhelming storage capacity and infrastructure. Prices may need to fall far enough to encourage operators to proactively shut-in production.

But how do you make that decision?

In the simplest economic terms, this is a cost avoidance exercise: At some threshold the cost of producing an additional barrel exceeds its value. Practically, this is more complicated. There is often a cost to restarting wells (cleanouts, etc.), so operators may choose to accept some short-term pain instead over incurring additional future costs. Recovery techniques such as steam injection or water-flooding may be irreparably disrupted if the well is shut-in for prolonged periods, permanently damaging an asset.

Then there is the sticky question of variable costs. What cash outlays do you really avoid by forgoing that incremental barrel? Not the surface lease rental (unless you abandon and reclaim), maybe the labor (if the operator becomes redundant), but certainly the cost of handling produced water. A lot of this depends on the expected duration of low prices and the operational setup.

Factors like these make the shut-in decision difficult and one operators are often reluctant to make. But sometimes prices fall far enough that they do.

Wells most at risk of shut-in are those with the highest costs. Wells that produce at low rates generally incur high unit operating costs due to a fixed cost associated with operating an oil well. Wells that RSEG tags as liquids-rich gas (producing 10-40% wellhead liquids) or oil (producing 40% wellhead liquids or higher) and producing less than 50 bbl/d flowed an estimated 2.8 MMbbl/d as of December 2019. Of this, 0.65 MMbbl/d came from wells producing 5 bbl/d or less. Another 0.39 MMbbl/d was associated with wells producing 5-10 bbl/d. Wells producing 10-20 bbl/d represented 0.58 MMbbl/d, and 0.58 was generated by wells producing 10-20 bbl/d (Figure 1). Wells in these groups accounted for a combined 1.6 MMbbl/d, and we believe they are among the highest risk of shut-in if prices fall far enough and stay there long enough.

FIGURE 1 |  US Oil Production Split by Well Rate

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Source | RSEG

 

 

 


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