The Permian Basin, as well as the Eagle Ford and Bakken shales, which today are considered the “big three” drivers of U.S. oil production, would remain economic at current costs if West Texas Intermediate (WTI) crude oil prices were to fall to $65/bbl, according to an analysis by Raymond James & Associates Inc. In fact, 13 of 20 onshore oil plays evaluated would breakeven below $65 using current costs, said analysts.
The huge surge in U.S. oil supplies is expected to force domestic producers to curtail their onshore activity, but it won’t be soon enough for 2013 prices, Raymond James analysts said last month (see Shale Daily, June 19). At that time analysts cut the 2013 WTI forecast to $65/bbl from a February forecast of $83. WTI prices are expected to average $80/bbl over the next decade, down from $90.
Analyst John Freeman and his team dug deeper into the exploration and production (E&P) data numbers to determine which onshore U.S. oil plays currently contribute to overall supply growth. The Utica and Tuscaloosa Marine shales were excluded because they are considered early stage with limited data; also excluded were “elusive stealth plays” that may contribute in the future. The unconventional plays examined were at least 40% weighted to oil by volume. The E&P industry in general pays “very little in cash taxes” because of intangible drilling credits and breakeven prices were calculated using pretax values, said Freeman.
What the Raymond James team determined was that 13 of the 20 onshore plays evaluated would be breakeven below $65/bbl using current costs. In addition, 18 of the 20 “will make at least a 10% internal rate of return if we assume a 10% reduction in service (well) costs…The data implies that for every 10% change to service costs, we can expect to see the average breakeven price for U.S. onshore plays to change by roughly $6.00/bbl.”
Basically, E&Ps “have become too good at extracting oil and gas,” Freeman wrote. “The unlocking of shale plays in recent years has jump-started the U.S. production curve after decades of declines. On the back of seemingly constant improvements in drilling efficiency and well productivity, we must ask ourselves, have we ‘drill, baby, drilled’ ourselves a little too deep?
“As a case in point, natural gas prices have traded below $6.00/Mcf for more than three years — and appear to be mired at sub-$4/Mcf levels for another three years. As we now turn our sights to the remarkable surge in domestic oil supply, we must ask ourselves, how low do prices need to go in order to really slow down drilling? Our analysis shows that the industry will continue to make economic returns at $65/bbl in the majority of onshore U.S. oil plays — well below the current WTI strip at $87/bbl.”
There’s no doubt that cash flows and subsequently, spending “will surely get squeezed in a $65/bbl environment,” said Freeman and his colleagues. “Ultimately, it remains to be seen whether the industry has learned its lesson from the gas-drilling frenzy, but we’re not counting on it.”
Natural gas drillers have kept some rigs operating at sub-economic prices and oil drillers likely will do the same — and for the same reasons, said the analysts.
“When companies craft their budget/plans for the upcoming year, economics certainly play a factor, which is why most companies budget for commodity prices that are 10%-plus below the price at that time. However, these plans also include the contracting of rigs, training of completion crews and securing pipelines just to name a few, not to mention that these plans encompass an entire year, not a one- to two-month outlook.”
When prices begin to reach a point where “rigs should get ‘whacked,’ E&Ps are more prone to ride out the storm for what could be perceived as a temporary price drop rather than risk losing efficiencies by dropping a rig and canceling an already-trained completion crew. This can become even more problematic if there are contractual obligations for the rigs and/or minimum volume commitments for third-party pipeline operators.” Hedging programs also will keep oil drillers in operation, as well as drilling to hold leases.
“We don’t expect a ‘Haynesville-esque’ type of phenomena where companies scrambled to drill expiring leases (most were signed as three-year lease terms), but plays that were heavily leased in 2009-2011, such as the Bakken and Eagle Ford, will require capital over the coming years,” said Freeman. “Plays like the Permian, Niobrara and Mississippi Lime likely have more cushion due to existing vertical well production holding the acreage, but with ‘stealth’ oil plays continuing to pop up around the U.S., we’d expect the overall trend to continue.”
Tudor, Pickering, Holt & Co. (TPH), which tracks several of the large rig count reports in its Weekly Rig Roundup, said Monday the top 30 operators “drove a drilling decline” for the week ending July 13 from July 6. The overall rig count had a “slight downward trend on two of three rig count sources we use (Smith Bits showing flat for three-plus quarters) and anecdotally feels right”
As important, “the horizontal rig count had the same slight downward tilt. Baker Hughes Inc.’s horizontal rig count was down 2% from its May peak (four-week average). This means flattening of service intensity (at same time as price pressure felt) after the tailwind of the horizontal rig count tripling this cycle.”
According to TPH, the largest week/week rig count changes as of July 13 were seen in the Eagle Ford Shale (plus nine, with the trailing four-week average up nine); Permian Basin of Texas (minus nine, trailing four-week average up eight); and the Rockies (minus seven, trailing four-week average up one).
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