美國能源信息署（EIA）在其最新一期的《短期能源展望》報告中預測，到明年年底前，美國頁巖油產量將日增大約80萬桶  

這可能會成為現實，但在本文作者目前所查看的數據中并不明顯  

在本文中，作者將使用EIA生成的數據，討論其最近在這些方面的研究結果

據美國油價網8月8日報道，由于疫情對全球經濟的全面影響，在2020年3月結束的頁巖鉆井熱潮導致了原油庫存過剩，壓低了原油價格。在美國和全球供應充足的情況下，原油現貨交割價格降至前所未有的水平。2020年4月，原油現貨價格首次出現負值。

由于經濟的復蘇，原油庫存水平下降，在今年3月觸底，美國所有地區的原油庫存總量約為4.15億桶。 

在此期間，不僅庫存量下降，美國的原油產量也急劇下降，因為低油價使鉆井活動變得不經濟。 米德蘭市郊區的閑置鉆機堆積如山，截至2020年6月，在用鉆機數量下降至252部。進入第三季度，WTI價格突破每桶40美元，鉆機開始恢復鉆井作業。 在2021/22年期間，由于WTI價格在每桶80美元—120美元之間，盡管鉆機日費率仍然較低，但鉆井商開始利用這一優勢，新增了500多部鉆機，其中大約40%將在今年新增。這是一種并不經常出現的組合。

地緣政治沖突爆發以后，油價突破每桶100美元，導致汽油和柴油價格飆升，消費者在加油站遭受了巨大的痛苦。與此同時，經濟復蘇和對疫情限制的放松導致旅行人數激增，無論是在公路上還是在空中。監管機構和政界人士一直預計，石油公司將利用增加的收入，租用更多的鉆機來壓低油價。 

相反，現在更明智的頁巖鉆井公司采取了一種資本約束的做法，其目標是在略有增長傾向的情況下將產量維持在當前水平。去年6月，在休斯敦舉行的JP摩根能源會議上，先鋒自然資源公司CEO謝菲爾德在《石油與天然氣雜志》的一篇文章中談到了這個問題。  

謝菲爾德在6月22日的活動上告訴與會者：“我們（先鋒自然資源公司）每年的資本支出只會增長5%；每次會議都有人問我這個問題。”“我們不會增長7%，8%，9%，10%或12%。”

謝菲爾德如是說，并指出當政府要求增加產量時，先鋒自然資源公司對政府說了同樣的話。“我們也拒絕了他們，”謝菲爾德繼續說道，“我們試圖讓他們理解這個模式，以及模式改變的原因。”他在討論過去的一個“繁榮—蕭條”周期模式時說，在這個模式中，石油和天然氣行業通過提高產量來應對，最終導致供應過剩。

其他CEO也做出了類似的評論，強調他們的資本配置重點不是產量增長，而是資本回報給股東。 美國另一家大型頁巖鉆井公司德文能源公司也做出了同樣的承諾。德文能源公司首席執行官里克·蒙克里夫在接受彭博社記者采訪時指出，該公司將繼續嚴格控制資本配置，今年的資本支出增長目標為-5%。  

但外界對頁巖產量增長的自然限制卻沒有引起太多關注。 在經濟不景氣的時候，頁巖鉆井公司會選擇開發他們最好的地點，以確保回報的收入超過鉆井成本。

總而言之，按照2020年的預期速度，庫存規模相當于18到25年的鉆井量。如果一級鉆井活動恢復到2019年的創紀錄水平，那么鷹福特和巴肯頁巖盆地的鉆井能力可以維持68年，DJ盆地和二疊紀盆地的鉆井能力可以維持11到15年。在二疊紀盆地，如果當前的井距策略沒有改變，那么剩余的一級庫存的總規模約為33000個地點。

數據顯示，在過去一年的大部分時間里，美國所有關鍵盆地的產量都相對持平，尤其是2022年。由于墨西哥灣也包括在內，一些天氣異常會暫時影響整體數據，冬季陸上生產也是如此。

根據EIA短期能源展望報告的建議，到明年年底，美國可能還會日增80萬桶油當量。 

這對油價的影響在短期內仍不明朗，因為在過去6周內，對經濟可能衰退的擔憂已使WTI和布倫特原油的價格每桶下跌了大約20美元。從長遠來看，如果這種降低井產能的趨勢得到證實，由于頁巖產量的下降，我們可能會看到一個急劇的反轉。 

許多分析公司已把今年的退出價格目標維持在當前水平之上，高盛公司最為看好布倫特原油價格，認為布倫特原油價格在每桶135美元。如果所有這些因素加在一起，消費者的錢包可能會更痛苦，因為供應緊張導致價格上漲。

李峻 編譯自 美國油價網

原文如下：

How High Can U.S. Shale Production Climb?

? The U.S. Energy Information Agency (EIA), has forecasted in their most recent edition of the Short Term Energy Outlook-STEO, a rise in U.S. production of about 800K BOEPD by the end of next year.

? This may well come to pass, but it is not evident in the data I’ve reviewed so far.

? In this article, I discuss the results of my recent research along these lines using EIA-generated data.

The shale drilling boom that ended in March of 2020, as the full effects of the pandemic hit the economy, contributed to a surplus of oil in storage that kept prices down. Richly supplied both in the U.S. and globally, the market took the spot delivery prices down to unprecedented levels. In April 2020, the spot price actually went negative for the first time ever.

As the economy recovered, inventory levels declined, bottoming out in March of this year, at about 415 mm bbls across all PADD districts.

Not only did storage decline, but U.S. production declined sharply in this period as the low prices made much of it uneconomic to drill. Rigs were stacked like cordwood in the outskirts of Midland, with the active rig count falling to 252 by June 2020. As we moved into the third quarter, WTI prices surpassed $40 and rigs began to go back to work. Over the course of 2021/22, another 500+ rigs were added with about 40% of that coming this year as drillers moved to take advantage of still low rig rates and WTI prices in the $80-$120 range. A combination that doesn’t often present itself.

The war sent oil above $100 per barrel, causing gasoline and diesel prices to soar and consumers to suffer a lot of pain at the pump. At the same time, the recovering economy and the loosening of Covid restrictions created a surge in travel, both on the open road and in the air. There has been an expectation from regulators and politicians that oil companies would take their increased revenues and hire more rigs to bring down prices. A practice that would have fit their former model of compound annual growth rate - CAGR, using borrowed capital, and nearly brought many of them to ruin in the years leading up to 2020. 

Instead, the shale drillers, now wiser, have adopted a practice of capital restraint that has the objective of maintaining production at current levels with a slight bias to growth. Attending the JP Morgan Energy Conference in Houston last June, Pioneer Natural Resources, (NYSE:PXD) CEO was quoted addressing this issue in an Oil and Gas Journal article.

“We’re [Pioneer] only going to grow 5% per year; I’ve been asked that in every meeting today,” Sheffield told attendees at the June 22 event. “We’re not going to grow 7, 8, 9, 10, 12%," he said, noting that the company told the Administration the same thing when asked to increase production. "We said no to them also," Sheffield continued. "We’re trying to get them to understand the model and the reasons the model changed," he said, in discussing a past model of boom-bust cycles in which the oil and gas industry responded by ramping up production that ended in oversupply.”

Other CEOs have made similar commentary, stressing that their priority for capital allocation is not production growth, but the return of capital to shareholders. Another large shale driller, Devon Energy, (NYSE:DVN) has made the same commitment. Devon CEO, Rick Muncrief noted in a Bloomberg interview that the company would continue to be disciplined in capital allocation with a growth target for 2022 of ~5%.

What hasn’t gotten a lot of attention is an external, natural limit to growth in shale production. Shale drillers in the lean times chose to develop their best locations to ensure payouts that would return more revenue than they cost to drill. (I discussed this trend in an earlier Oilprice article last May.) The industry calls these Tier I locations. The linked Rystad article notes the following in regard to remaining Tier I locations.

“Taken together, the inventory size corresponds to 18-25 years of drilling at the pace expected in 2020. If Tier 1 activity returns to the record level of 2019, then we can have six-eight years of drilling capacity in the Eagle Ford and Bakken, and 11-15 years in the DJ Basin and Permian. In the Permian Basin, the total size of the remaining Tier 1 inventory is about 33,000 locations, assuming there are no changes in the current well spacing strategies.”

The orange line, representing the Permian basin, follows the same trajectory, with daily production declining per well by about 120 bbl per day over this time.

What it shows is that across all key basins production has been relatively flat for most of the past year, and in particular for 2022. Since the Gulf of Mexico is included in this total there are some weather anomalies that can skew the overall data temporarily, with the same being true for onshore production in wintertime.

We may yet add another 800K BOEPD by the end of next year as the EIA Short Term Energy Outlook-STEO suggests we may. 

What this means for oil prices is yet unclear in the short term as for the last six weeks concerns about a possible recession have trimmed roughly $20 per barrel from the price of WTI and Brent. Longer term, if this trend toward lower well productivity bears out, we could see a sharp reversal higher, as shale output declines.

Many analyst firms have kept a YE-2022 exit price target above current levels, with Goldman Sachs the most bullish of all at $135 for Brent. If all of these things come together consumers could be in for more pain in the pocketbook, as tight supplies result in higher prices.