Since the end of 2016, though, the Eagle Ford has shown signs of recovery. According to Dallas Fed’s most recent energy indicators report, Permian Basin output increased in August by 62,300 bpd to 2.52 million bpd. Eagle Ford’s production rose by 17,000 bpd to 1.28 million bpd.
“Eagle Ford production has been on an upward trend since it bottomed out in late 2016, although rig counts have been declining since reaching 86 on May 26,” Dallas Fed said, noting that the Eagle Ford output dropped in late August and early September due to curtailments amid Hurricane Harvey.
The EIA’s latest Drilling Productivity Report estimates the Eagle Ford oil production at 1.271 million bpd in October, revised down to reflect Harvey’s impact.
The Dallas Fed energy indicators report also highlighted that “Operators look to be moving rigs to more prolific counties within basins, such as Reeves County in the Permian Basin and Karnes County in the Eagle Ford.”
The number of all active oil and gas rigs in the United States fell last week by 1 rig. The total oil and gas rig count now stands at 935 rigs, up 424 rigs from the year prior. In the Eagle Ford, the number of rigs dropped to 68 from 71 last week, but is up by 31 rigs from the 37 rigs for the same week last year.
The Eagle Ford activity and oil production is inevitably tied to oil prices, which, after starting this year with WTI above $50 on the back of the initial enthusiasm over OPEC’s cuts, faltered in March and dipped to $47.
The Dallas Fed Energy Survey from Q1 2017 at the end of March showed that 62 executives from exploration and production firms said that the average breakeven price to profitably drill a new well in the Eagle Ford was $48 per barrel WTI.
Since then, the WTI price has faltered several times, entering a bear market in June, dipping to $43 and shedding more than 20 percent from recent highs. But earlier this week, oil returned to a bull market and WTI hit a seven-month high at $52.22, as sentiment turned bullish with growing evidence that the market is rebalancing, strong oil demand growth, and a supply concern over possible disruption of oil exports from Kurdistan.
At $51-52-per-barrel oil, U.S. shale drillers are hedging anew to lock in future production prices. Hedging activity has sped up since WTI broke above $50.
“There’s been more producer-hedging in the past two weeks than in the past four or five months,” one banker told the Financial Times.
Interesting post - higher oil prices will definitely get operators looking at resuming some drilling in the EF / AC trend. But I still think that an overriding factor in this whole issue is acreage expiration / lease term. If operators have acreage HBP, there is no necessity to drill more to "maintain the leases". And unless there is a shallow vertical Pugh clause, the Austin Chalk rights will be held by the deeper EF production - so no rush to "prove up" the AC as an economic target.
Assuming an HBP position, drilling will depend totally on the economics and cash flow associated with any new well. And the cost of capital of the various operators. Can they continue to drill out of cash flow? Or use borrowed money to drill (at high interest rates)?
Each company has their own unique financial situation to consider when looking at drilling. A company like EOG is drilling out of cash flow with a very streamlined operational effort that is tied to low costs and great long term contracts with contractors (e.g. rigs, frac crews, frac sand, etc.). Very few companies have this option.
And as oil prices go up, contractor costs will follow.
There are thousands of undrilled locations in the EF and AC trend - operators know what they have in place in these undrilled units and the financial planners are looking hard at the timing of how to monetize these proven assets.