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U.S. oil production is probably peaking right now: Kemp

(John Kemp is a Reuters market analyst. The views expressed are his own)

LONDON – U.S. crude production will peak this month, according to revised forecasts published by the country’s Energy Information Administration (EIA).

Output will average 9.37 million barrels per day (bpd) in April and the same in May before falling to 9.33 million bpd in June and 9.04 million bpd by September, the EIA predicted in the April edition of its Short-Term Energy Outlook (STEO).

Production is expected to peak a month earlier and 10,000 bpd lower than the EIA forecast in the January STEO, reflecting continued low wellhead prices and a sharper-than-expected slowdown in new well drilling.

Production is forecast not to exceed this month’s level for another 18 months. The EIA has cut its forecast for the end of 2016 by 230,000 bpd compared with three months ago.

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While the EIA’s Brent price forecast is largely unchanged, prices for West Texas Intermediate crude have been marked down through the rest of 2015 and 2016, reflecting the build-up of crude stocks and persistent weakness of U.S. grades.

The number of rigs drilling for oil has fallen further and faster than was anticipated last year. Baker Hughes reported there were 802 rigs drilling for oil last week, down exactly 50 percent since early October.

It is unlikely a halving of the rig count can be completely offset by greater target selectivity and other efficiency improvements such as employing only the most powerful rigs, drilling longer laterals and reaching target depth faster.

Drilling data points to a strong probability that production from new wells will soon start to fall – if it is not falling already. Given the rapid declines in output from wells drilled in 2013 and 2014, total output from new and legacy wells should start to fall soon.

Related: Iran’s oil exports likely to rise in 2016: Kemp

DATA DELAYS

The most common question I am asked at the moment is: if the rig count has fallen by 50 percent, why is output still rising?

The simple answer: there is a delay of six months or more between changes in the number of new wells being drilled and reported changes in production.

It can take 20-30 days for a rig to drill a new well and then another 60 days or more for the well to be fractured and all the above-ground equipment put in place before the well flows its first oil.

Most major oil-producing states require well operators to submit a monthly report on the amount of oil and gas produced, but the first report is not usually due for up to two or three months after a new well has begun flowing.

Even then, the first report may not be representative of a full month’s production because the well may have started flowing part way through the month in question.

Once production reports are submitted they have to be compiled and published by state regulators, adding a further delay.

Then there are late filings (“delinquent wells”) from operators submitting after the formal legal deadline has passed, which means the initial production totals can be revised, sometimes substantially, especially in Texas where there are lots of small owners and operators.

The EIA includes estimates for U.S. production in its weekly and monthly publications. However, these are based on extrapolating from limited data and subject to estimating errors, which are likely to be especially large when the production trend is changing.

Rig counts are a leading indicator of future production trends (albeit a very imperfect one), while production reports are a lagging indicator.

Trying to predict future production based on current production reports is like attempting to drive by looking in the rear-view mirror.

Even if production peaks this month or next, it will not be visible in the statistics until at least July or August, and maybe later.

But by the time the production peak becomes visible, output will likely have been falling for several months.

 

This article was from Reuters and was legally licensed through the NewsCred publisher network.

20 comments

  1. Is the US oil independent at this peak?

    • Thad, you know we still import about 25% of the oil needed to run our country. We could be independent if the government allowed it.

    • Saw the latest number from EIA under 20% but can’t find now. Whatever – with the glut in the US and storasge almost filled the US should not be importing a single drop

    • Until we redesign our existing refineries, or build new ones, we will have to import oil to blend with our high gravity “sweet” oil. Keystone XL would have helped a lot in that area.

    • Kris don’t buy in to the light crude refinery shortage propaganda. When the oil boom started 7 yrs ago and the increasing amount of light crude being available refineries started expanding to refine light crude– Simple if it is not refined it can’t be used , sold in the US or exported- Have you not notice over the last 7 yrs there was no problem- but now wanting to export it suddenly is.
      Three refineries within 22 miles of my home : Motiva PtArthur TX expanded to 640,000 bpd now the largest refinery in the US can refine light crude, neighboring refinery Valero same type expansion 440,000bpd and EXXON Beaumont in the midst of expainding to 400,000 bpd.
      Mixing Alberta tar crude with light to refine-nonsense -two different refining processes-. And there are some 18 formations in the US that produce heavy crude- namely California, Texas, Utah and Oklahoma-
      the K-XL is nothing more than a canadian export scheme- Canada production has exceeded what the US would import and US imports from Canada will continue to decrease as US production increase.. Major problem for Canada as there is only one customer that they can deliver to– the US.

    • Finally! Thad I’m glad to see someone call the keystone pipeline what it actually is, it’s more for the tar sand than Bakken crude and I don’t think we owe Canada anything!

    • Tim- not a ingle producer of Bakken crude has signed a contract of intent with TransCanada— instead they signed wioth “Energy Transfer” for a direct west to east pipeline to Illinois-

    • If the federal government wanted energy independence they would price fix US oil at $75-$85 barrel. That would stabilize our production and get us off a global market controlled by Saudi/OPEC. Keep our crude here and worry about the world later.

    • Luke oil is a commodity on the global market – price set by supply and demand–OPEC controls the supply and has dropped the price below US production cost
      Oil companies are not the only users of oil– the users will buy the cheapest, OPEC. So that is the price US oil producers have to match-
      To achieve what you suggest would require nationalizing US oil- and price fixing- never happen

    • Light sweet domestic crude is artificially under-priced because it is landlocked. But heavy sour crude is an even better bargain. Today’s modern refineries are configured for heavy sour crudes because they are more profitable. Most heavy sour now comes from Canada not OPEC.

    • Paul do you know what sour crude is? It is crude with a high sulfur content which has to be removed before refined products can be used for fuel–Sour crude is never the preferred feed stock.
      Tar crude is not oil, it is bitumen tar aka asphalt. And one problem is a 20% or more residual pet coke left over when refined. This pet coke can not be used in the US because of the sulfur content– there are mountains of it stored at refineries and there nothing they can do with it-
      http://www.bing.com/images/search?q=pet+coke+mountains+at+refineries&qpvt=Pet+coke+mountains+at+refineries&qpvt=Pet+coke+mountains+at+refineries&FORM=IGRE

    • Thad, have you ever worked at a refinery? I have. You don’t know what you’re talking about. Heavy sour crude from Canada is much prefered. It has backed out some Saudi and Ven heavy crudes. OPEC has lost much market share in US thanks to greatly increased imports frok Canada. Pipelines from Canada are full especially the new Keystone (original not XL). Coke and sulfur could be given away for free and heavy crudes would still be more profitable than light sweet.

    • Thad, you are also mistaken that today’s crude prices don’t support continued domestic production. Note that some shales only cost $40/b to extract. US production has increased 10% since July. Depletion will take its toll but it has not yet happened.

    • Paul that is well head cost not full production cost. Read the foot notes of the pic you posted about the ‘excluded cost’.
      Fall 2014 and the lowest cost is $46 / bbl

    • Not true. Look at third bar from left. The average is $50 (top of bar). But the range is $40-60 (inside bar). But costs are only part of the story. Most crude is sold based on WTI futures contracts. This cost curve is rising with time. This encourages production even close to break-even costs.

    • Increased production without drlg is just increasing out put from existing wells

    • Once a well is drilled, it’s well head cost that counts. What has gone before is sunk and irrelevant. That’s why US production has continued to increase although drilling new wells has decreased. The peak in production will arrive someday but no one knows exactly when.

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