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What’s unfolding is a maturing shale system. The most productive acreage tends to be drilled first, and as prime locations are depleted, companies face higher costs and lower returns. When crude prices soften, drilling activity slows more quickly than it did during the boom years, said Jay Young, founder and chief executive officer of King Operating Corp.
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Stuff To Think About






This chart, created by Rystad and clearly endorsed by the API, is funky looking. It's on a BOE basis and suggests oil and condensate in Midland Basin wells is 80-85% of the production stream, associated gas less than 20%. I don't believe that is correct, I think new wells in the Midland Basin produce about 60% oil, 40% gas from the get-go.
The chart also implies the ratio of oil to gas stays constant over the first 3 years of well life. I don't believe that is correct either as pressure depletion is deeply entrenched in the Midland and GOR begins
to rise within 18 months, generally speaking.
Regardless, 90% decline in 36 months is different than just three years ago. The rate of decline seems to increase every year.
Midland Basin EURs, for any bench, tend to max out at 410-440K BO. With WTI at or near $65, that does not work economically. Full cycle, GAPP, money out vs. money returned tend to be around $20 net back. You decide for yourself if those sort of EURs will pay back drilling, completion and land costs, for instance for Exxon and Diamondback, who paid $4.5 million for new drilling locations in M&As.
90% decline in 3 years is only going to get worse.
And the sector in the Basin is drilling the last of its Tier 1 and 2 locations right NOW.
How is the sector going to pay all its debt back? Are they going to get all that forgiven?


Robert Flarherty Energy Landscapes



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