The last few weeks have been humbling for those of us who make prognostications about the direction the oil markets may take. Especially so for the bulls, folks who think for whatever reason, oil should go up in price. Since mid-2014 that notion, with a few brief respites that analysts often call a “sucker’s bounce,” has proven to be continuously false. Every “buy on the dip,” recommendation has turned to compounded losses for energy investors, particularly those who dipped their toes into North American shale.
The failure of OPEC+ (which we will discuss a little later in the article) to come to an agreement on further cuts was the breaking point for many investors resulting in a market looking for price discovery for oil and not finding it until the ~$30 level. On Monday, March 8thoil fell farther than it had ever done so before in a single day, dropping 24 percent before settling at $31.13/bbl.
There is much discussion in the market now as to what effect this will have on shale drillers who seemed to have been dancing a credit, and wells productivity tight-rope the last couple of years. This in a relatively benign market that saw prices in the $55.00-60/bbl, where most agreed they could thrive. Most had seen share prices decline since the heady days of 2017, so surviving on cheap credit to drill new wells is probably a more apt term than thrive. What holds for them now that oil is $25-30 a barrel less in the space of a couple of months?
Being an analytical sort of fellow I like to look back at past indicators of economic trends to help me understand the present and try and forecast the future. In this article we will review highlights of the last Dallas Fed Energy survey.
First a brief Introduction to the U.S. Federal Reserve System
Some background for international and lay readers. The Federal Reserve System is the chief instrument of regulating monetary policy in the United States of America, and is sometimes referred as the Central Bank. It was established in 1913 to control banking panics, by the congressional passage of the Federal Reserve Act. It has two primary remits. Promotion of maximum employment, and stabilizing prices.
It is comprised of twelve regional District Banks, and Region 11 monitors the geographic area that includes the Permian Basin. This region is known as the Dallas Fed.
As part of its remit, the Dallas Fed conducts a quarterly survey of energy executives that participate in the Permian and South Texas oil and gas markets. It is an anonymous exercise, so we don’t know who the cohort is that makes up the responses, but its broad enough (161 firms participating) that we can give some credence to it.
We spend time on this in part because of its focus on the Permian which I view as being the only shale play that matters. I’ve made this point previously due to the quality, extent, and oiliness of the Permian. All the others are gassier, thinner, and don’t have the logistical advantages of the Permian. This was discussed in a prior article in OilPrice a couple of months ago.
With this preamble, let’s dive in.
Price expectations for WTI
What this first chart reveals is there were some fairly rosy expectations for the crude price for the coming year in about half of the respondents. A lot that optimism was probably the result of the Phase-1 trade deal with China, which although not signed until late Jan, 2020, was pretty much in place by the time of the survey.
It didn’t take long for the professional analysts to begin revising their global growth forecasts higher.
On the positive side, market sentiment has been boosted by tentative signs that manufacturing activity and global trade are bottoming out, a broad-based shift toward accommodative monetary policy, intermittent favorable news on US-China trade negotiations, and diminished fears of a no-deal Brexit, leading to some retreat from the risk-off environment that had set in at the time of the October WEO. However, few signs of turning points are yet visible in global macroeconomic data.
As with all of these it’s sometimes funny to look back and see what was expected vs what turned out to be the case. “No Deal Brexit,” for example, remember that one? As it turned out that’s exactly what happened.
Of course, no sooner was the ink dry on that report than news of Covid-19 began to seep in the market, quickly washing away any benefit expectation from the trade deal with China. I imagine the IMF would like to bury this report.
With advent of the spat between the Saudis and Russia a new price era is in store for shale. Its early days and we will have to see how this plays out. There are arguments for and against the two countries patching up their differences. Both are persuasive. Time will tell.
Related: Crashing Oil Prices Force U.S. Oil Firms To Cut Budgets
Expectations for capital spending in 2020
As you might then expect from the price chart above, projections for capex devoted to shale were tilted to the bullish side, with 60 percent of respondents indicating they would hold firm or increases slightly. Only about 8 percent intended to plow big gobs of new capital into shale drilling.
I find this to be moderately encouraging. Most survey takers – 65 percent – were holding firm or decreasing capex somewhat. 22 percent planned to seriously rein in capex, indicating to me that even the near to low $50’s were getting for WTI just a few short weeks ago wasn’t delivery the kind of returns needed to stay in business long term.
With oil likely to rebound to the mid-$30s and stay there until shale production starts to decline (a topic we will address shortly), or there is some unexpected rapprochement in OPEC+ (something I am starting to doubt after initially leaning that way.)
Price needed to generate Net Positive Cash Flow
This is a little stunning to be honest. 60 percent of the firms that replied to this question need prices higher than $50/bbl. 38 percent need prices over $55.
Only about 13 percent said they could make money in the most likely price scenario for WTI, with a bare 5-ish percent below cash flow positive at the present $34-ish price.
My conclusion would be that many of those in the upper 60 percent will be reducing activity dramatically in this new price era. I will have more commentary on this in the “Your Takeaway” section.
Drilled but UnCompleted wells have helped to grow production over the last year, even as new drilling has declined. This chart from Rystad suggests that one reason for this is it substantially cheaper to bring these on than drill new wells.
To be honest here, the logic of this graph escapes me, although its point is plain-many DUCs are uneconomic at today’s crude price. It suggests that for 80 percent of DUCs breakeven pricing is around $25/bbl. That seems awfully low. Perhaps if they are talking about DUCs that have already been fracked, then that might make sense.
One problem with DUCs is how they are classified. The EIA (the main semi-reliable source of hard data pertaining to oil) doesn’t provide information on just what was done to a well before P&Aing (Plugging and Abandoning). There is reasonable cause to question whether a completion was actually installed prior to P&Aing. That’s because ~70 percent of the cost of the well lies in the completion.
Related: Saudi Arabia Strikes Back At Russia In Key Oil Market
If you were operating wells, would you spend ~$6 mm to install a completion and then put into DUC storage? There might be reasons for you to do just that-perhaps the pipeline connection isn’t ready for example. There may be others that escape me now. But, more often than not if you’ve got $6-8 mm tied up in a well, you’d like to turn it around as quickly as possible.
Notions that DUCs will keep the monthly EIA daily oil production tally rolling higher are probably misplaced. Why spend money to lose money? (Although I could be chided for asking this questioning of folks who collectively have managed to never have produced free cash flow, while accumulating 200 bn in debt.)
Food for thought.
What the Dallas Fed Survey reveals is there was quite a bit of exuberance in the minds of the oil company execs in December, of 2019. Perhaps it was because it was close to Christmas, and no one had heard of Covid-19 yet.
No article on shale production would be complete these days, since OPEC+ fell apart anyway, without a comment on that stalemate. Cutting the way to higher prices was always doomed to failure with shale roaring ahead. What’s puzzling is that it took so long to figure this out. After all they’d been doing this for a couple of years, while shale production…just ate their lunch. The point of another cut escaped the Russians who have a bit of a chip on their shoulder toward America to begin with thanks to sanctions on some of their key oil players, like Rosneft and its Nord Stream II pipeline. Now it appears the Saudis are catching on that it’s time to apply some tough love to their American shale counter parts.
My bet over the short haul is this is going to happen. Both countries understand who the real enemy is and are taking direct aim at “Bubba” in the Texas oilpatch.
Longer term, fair questions have to be asked. Do the Russians really want to spend down their ~$570 bn cash reserves selling cheap oil? They’ve been making a killing off relatively high oil prices the last decade, and there’s no guarantee they can amass a fortune like this again. On the flip side, can the Saudis maintain this for very long, given their own funding shortfall. They too have a bunch of cash, but are in the same pickle as the Russians, when it’s gone, it’s gone.
The answer may lie in just how fast shale production falls.
Taking all of this information into account what can we expect from Permian operators post the OPEC+ debacle?
Drilling will fall off a cliff. The last Baker Hughes survey reported a Permian count of about 404 rigs last week. I think this week it will be down another 50 and likely be cut in half over the next month. Using simple sums a 200 rig drop would take 160 K bopd off the market.
DUCs will remain stagnant if we can believe the Rystad chart noted above. When the decline in drilling, and DUCs remaining in inventory, are added to the natural decline rate for shale it means we might see another half million barrels a day fall in production over the next month or so. Conceivably about -800 K BOEPD in a very short period.
In short low prices, the thing that will kill off about half the shale industry will be the very thing that the rest of shale producers need to get the price back to levels where they can make money.
As I stated in my last article for OilPrice, “What’s Next For North American Shale,” the future of shale belongs to big companies with; Great rock, naturally advantaged oil-prone reservoirs, Superior technology, the ability to frac in 4D as an example, Logistical advantages, raw material supply chain in basin, Low cost of production, relates to naturally advantaged reservoirs, but includes the ability to drill more wells with less money than competitors, Economy of scale, massive acreage positions that enable multi-well pads for efficient draining of the reservoir.
I think better days lie ahead for the survivals, but expect rough times in the interim.
By David Messler for Oilprice.com
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