US Land Horizontal Rig Count Report, Week Ending August 7, 2020

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Comparative Inventory & Natural Gas Storage Report August 7, 2020 (2020-10)

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Comparative Inventory & Oil Storage Report August 6, 2020 (2020-15)

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Art Berman Newsletter: July 2020 (2020-6)

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US Land Horizontal Rig Count Report, Week Ending July 31, 2020

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Comparative Inventory & Natural Gas Storage Report July 31, 2020 (2020-9)

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Comparative Inventory & Oil Storage Report July 30, 2020 (2020-14)

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The Decline and Fall of the Bakken: The Red Queen Collapses

The Bakken Play was described as The Red Queen by my colleague Rune Likvern almost eight years ago. Likvern meant that more and more Bakken wells have to be drilled just to keep production from falling.

“Now, here, you see, it takes all the running you can do, to keep in the same place.”

–The Red Queen, Through The Looking Glass, Lewis Carroll

http://theoildrum.com/files/fig01AlicerunningwithTheRedQueen.png
Figure 1. The Red Queen has to run faster and faster in order to keep still where she is. That is exactly what you all are doing!
Source: The Oil Drum

It now appears that ithe Red Queen has finally collapsed from exhaustion. There are only 10 active rigs in the Bakken today compared to 57 rigs in July 2018 and an average of 53 rigs in 2019.

Bakken production fell to a 7-year low of 827,000 barrels of oil per day in May (Figure 1). That is a drop of almost 550,000 barrels per day (-40%) since March. Most of the decrease in output is because more than 2,800 wells were shut in over the last two months.

This image has an empty alt attribute; its file name is image-84.png
Figure 1. Bakken output has decreased -635 kb/d (-43%) to 827 kb/d in May.
Number of producing wells has fallen -2,876 (-21%) since March.
-$8.83 discount to WTI at $31.75 vs $40.58 (WTI) average spot price week of July 13.
Source: North Dakota Department of Mineral Resources and Labyrinth Consulting Services, Inc.

The average wellhead price in the play is only $31.75—almost a $9 discount to WTI. That’s because of high transportation costs from the Williston Basin to the Cushing pricing point and to refineries.

Low price is not the worst of the Bakken’s problems. The sweet spot of the play has reached maximum infill development. That is clear from the normalized production plots shown in Figure 2. It is a classic example of rate acceleration but lower reserve addition.

This image has an empty alt attribute; its file name is image-85.png
Figure 2. 2019 Bakken wells out-perform 2017 & 2018 wells during first 10-11 months
but under-perform in later months. Rate acceleration for 2019 wells but no reserve addition compared with 2018 wells.
Source: Enverus and Labyrinth Consulting Services, Inc.

EUR and b-exponent

Estimated ultimate recovery (EUR) peaked in 2017 for top Bakken producers Continental, Whiting, Hess and Oasis (Figure 3). EUR for wells with first production in 2018 and 2019 was lower than in 2017.

More importantly, the b-exponent decreased for wells drilled after 2017.

Figure 3. Bakken estimated ultimate recovery (EUR) has declined since 2017
Lower b-exponents reflect boundary-dominated flow.
Source: Enverus and Labyrinth Consulting Services, Inc.

Figure 4 shows a series of idealized production decline profiles or type curves. It is a standard rate vs time presentation with rate on the y-axis and time on the x-axis. All three production history curves start at the same initial rate but depart from each other based on their decline rates. The slope of that decline rate is the b-exponent.

Figure 4. A smaller b-exponent results in dramatically lower estimated ultimate recovery
for a well with the same intial production rate & early production history
because of earlier onset of boundary-dominated flow and exponential terminal decline.
Source: Labyrinth Consulting Services, Inc.

The estimated ultimate recovery of each production history varies as a function of it’s b-exponent. Wells with high b-exponents describe a slower rate of decline and a correspondingly higher EUR than wells with lower b-exponents.

Lower b-exponents reflect increasing boundary-dominated flow whereas higher b-exponents suggest early flow rates that are relatively unconstrained by boundary conditions. At some point in every well’s production history, decline becomes boundary-dominated and that is known as its terminal decline rate.

The sweet spots of shale plays are characterized by high b-exponents and EURs.

Decreasing EUR and b-exponents in the Bakken are because the sweet spot or core area has reached full development. More wells are now being drilled outside the core. Here operators had hoped that new fracking technology would result in commercial well performance.

What has happened instead is that wells produce at high initial rates but exhibit boundary-dominated flow earlier than wells in the core. Wells outside the core are characterized by lower b-exponents and lower reserves than in core areas.

This signals the decline and fall of the Bakken play.

Core vs. Non-Core Areas

Figure 4 shows the $50 and $80 commercial areas of the Bakken in red outlines. It is based on EUR for all wells with 12 months or more production history.

The average well spacing within the $50 commercial area is 6.5 wells per 1280 acre spacing unit (197 acres per well surface location). The corresponding well density between the $50 and $80 commercial areas is only 2.7 well per spacing unit (482 acres per well).

In other words, there are plenty of locations left to develop outside the $50 core if commercial production levels can be achieved. The results of that experiment are not encouraging.

Figure 4. Bakken estimated ultimate recovery map with yellow-to-red colors showing the commercial areas at $50 and $80 wellhead prices.
Source: Enverus and Labyrinth Consulting Services, Inc.

Before the sweet spot was well-defined, more than half of all Bakken wells were drilled in marginal areas and average EUR was less than 350,000 boe per well (Figure 5). As drilling was increasingly focused in the core area, well performance improved to more than 400,000 boe in 2014.

This image has an empty alt attribute; its file name is image-107.png
Figure 5. Bakken well performance has declined since 2017
as driling has been increasingly outside of $50 commercial area.
Source: Enverus and Labyrinth Consulting Services, Inc.

EUR decreased through 2016 but maximum focus in the core area, increased lateral length and advanced fracking techniques resulted in a reversal of declining EUR to a new peak level of 412,000 boe in 2017. Well performance has declined since 2017 as driling has been increasingly outside of $50 commercial area.

Rise and Fall of a Shale Play

The Bakken is a case history of the rise and fall of a shale play. Production began in earnest after higher oil prices became the norm after 2008. By 2010, the Bakken became an important source of U.S. oil when production reached 200,000 barrels per day (Figure 6). Output fell after the price collapse in 2014 but recovered and reached a peak of almost 1.5 mmb/d in November 2019. Current production is about 800,000 barrels per day because of the recent oil-price collapse.

Figure 6. Bakken became a significant source of U.S. oil in 2010 when output reached 200 kb/d,
Higher oil prices were the main reason for expanded production.
Source: Enverus and Labyrinth Consulting Services, Inc.

The Bakken is at a severe cost disadvantage compared to other shale plays because of its remote location and high transportation costs to refineries and storage depots.

I have defined the sweet spot of the play within the 390,000 barrel of oil equivalent contour where wells break-even at $50 wellhead price per barrel, corresponding to about $58 WTI price. In fact, only about 46% of wells drilled from 2015 through 2019 made that cut-off (Table 1).

Moreover, prices were only at that level for about half of the time from 2015 through 2019 so really less than 25% of Bakken wells were commercial for much of those four years.

Even at WTI prices of $68, only 62% of Bakken wells broke even, and prices were at that level for just 3 months in the second half of 2018.

Table 1. Break-even WTI prices, estimated ultimate recovery for Bakken wells with first production from 2015 through 2019.
Source: Enverus and Labyrinth Consulting Services, In

At today’s wellhead price of about $30 per barrel at the wellhead, only 8% of wells are commercial (Figure 7).

Figure 6. Bakken commercial area at $30 wellhead pricing..
Source: Enverus and Labyrinth Consulting Services, Inc.

The Bakken play had a half cycle of about 10 years in which production growth generally increased. Unfortunately, fewer than half of the wells ever paid out their initial capital expenditure.

Until recently, analysts and journalists praised the success of the Bakken and other tight oil plays because of their substantial production growth and contribution to total U.S. output. Now the pendulum of public opinion has shifted. Investors lost their enthusiasm for the shale plays in 2018 because they finally learned the economic lesson that some of us were trying to explain a decade ago.

Bakken wells have impressive estimated ultimate recoveries if only the wells weren’t so expensive to drill and complete. The technology used to produce oil from shale reservoirs is remarkable but it’s not free.

The limiting factor for all oil fields is geology. No technology can transform a shale source rock into a high-quality sandstone or limestone reservoir. As Likvern said, There is no pass on the laws of physics or the history of play and basin developments.

“Technology and/or price cannot overcome the inevitable fact that field size and well productivity declines in most plays, whether in shale or any other plays. Put in a different way: shale plays do not get a pass on the laws of physics or the history of play and basin developments.”

–Rune Likvern (2012)

Most of the Bakken’s 3,800 shut in wells will be re-activated as long as oil prices continue to improve. I doubt that will happen until the Covid-19 epidemic is brought under some degree of control and oil demand recovers to 2019 levels. That means that production will languish at the lowest levels in many years.

I suspect that some investors will return to plays like the Bakken once the significance of oil to economic growth is more fully understood. Zero interest rates will motivate margin seekers to reconsider the risks of shale plays as they did after 2008. The immediate challenge is for oil companies to survive until that happens.

I doubt that the Bakken will ever return to 2019 levels. The play is not dead but the Red Queen has collapsed from exhaustion. No amount of running faster can make up for poor well performance outside the core area.

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US Land Horizontal Rig Count Report, Week Ending July 24, 2020

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Comparative Inventory & Natural Gas Storage Report July 24, 2020 (2020-8)

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Comparative Inventory & Oil Storage Report July 22, 2020 (2020-13)

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US Land Horizontal Rig Count Report, Week Ending July 17, 2020

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Comparative Inventory & Natural Gas Storage Report July 17, 2020 (2020-7)

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Comparative Inventory & Oil Storage Report July 15, 2020 (2020-12)

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Saudi Arabia Thinks OPEC+ Is Central Bank of Oil—Fire The Banker!

Saudi Oil Minister Prince Abdulaziz bin Salman recently said that OPEC+ is the central bank of oil, and that he feels good about the increase in oil prices since April.

I’m glad that someone feels good because the truth is that OPEC+ has done a dreadful job of managing world oil markets over the last three-and-a-half years. Markets have been over-supplied 79% of the time and there have been two major oil-price collapses since production cuts took effect at the beginning of 2017. 

If that’s how a central bank performs, I would fire the banker!

When OPEC+ announced production cuts in November 2016, inventories had already fallen about 25% from peak levels in March of that year (Figure 1). Markets were balancing themselves and didn’t need help from the central bankers of oil.

Because of anticipated cuts, prices increased 20% in November and December from about $45 to $54. Higher prices led to a production surge and inventory builds that contributed to much lower prices by June.

This image has an empty alt attribute; its file name is image-55.png
Figure 1. Oil over-supply 79% of time and 2 major price collapses
since OPEC+ production cuts took effect in 2017.
Over-supply had already declined 25% when cuts went into effect.
Source: EIA and Labyrinth Consulting Services, Inc.

To make matters worse, OPEC+ was responsible for much of the over-production that led to the late 2018 price collapse, and was at least partly responsible for the 2020 price collapse.

OPEC+ members ramped up production beginning in April 2018 in anticipation of U.S. sanctions on Iran oil exports. When Donald Trump reneged on those sanctions, prices collapsed to the lowest level since June 2017.

The producer consortium was powerless against Covid-19 and its effect on the global economy, but the group’s failure to reach agreement to continue production cuts at its early March 2020 meeting is what sent oil prices into free-fall. Covid-19 finished the job later in the month.

It is absurd to call what followed a price war because no one was buying any oil with plummeting global demand. President Trump offered Saudi Arabia and Russia a convenient way to save face following this debacle. In April, OPEC+ announced “historical” production cuts of almost 10 mmb/d which formalized what markets had already done for them.

“When they look at prices over the quarter, when they look at green shoots of demand pick-up, I think they feel good.”

Helima Croft, head of commodity strategy at RBC Capital Markets

Prices have increased to about $40 per barrel since the historical cuts in April. So, the latest OPEC+ achievement is a return to the lowest price levels since the depths of the early 2016 collapse of world oil prices.

READ THE REST ON FORBES

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US Land Horizontal Rig Count Report, Week Ending July 10, 2020

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Comparative Inventory & Natural Gas Storage Report July 10, 2020 (2020-6)

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Comparative Inventory & Oil Storage Report July 8, 2020 (2020-11)

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Art Berman Newsletter: June 2020 (2020-5)

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US Land Horizontal Rig Count Report, Week Ending July 3, 2020

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Comparative Inventory & Natural Gas Storage Report July 3, 2020 (2020-5)

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Comparative Inventory & Oil Storage Report July 1, 2020 (2020-10)

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US Land Horizontal Rig Count Report, Week Ending June 26, 2020

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Comparative Inventory & Natural Gas Storage Report June 26, 2020 (2020-4)

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Comparative Inventory & Oil Storage Report June 24, 2020 (2020-9)

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US Land Horizontal Rig Count Report, Week Ending June 19, 2020

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Comparative Inventory & Natural Gas Storage Report June 18, 2020 (2020-3)

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Expect oil prices to move down, then up, then WAY up

U.S. Energy Dominance is Over

U.S. energy dominance is over. Output is probably going to drop by 50% over the next year and nothing can be done about it.

It has nothing to do with the lack of shale profitability or other silly memes cited by people who don’t understand energy.

It’s because of low rig count.

The U.S. tight oil or shale rig count has fallen 69% this year from 539 in mid-March to 165 last week. Tight oil production will decline 50% by this time next year. As a result, U.S. oil production will fall from more than 12.5 mmb/d earlier this year to less than 8 mmb/d by mid-2021.

What if rig count increases between now and then? It won’t make any difference because of the lag between contracting a drilling rig and first production.

The party is over for shale and U.S. energy dominance.

Energy Dominance is Over

Tight oil is the the foundation of U.S. energy dominance. The U.S. has always been a major oil producer but it moved into the top tier of oil super powers as tight oil boosted output from about 5 mmb/d to more than 12 mmb/d between 2008 and 2019 (Figure 1).

Conventional production has been declining since 1970. It fell from almost 10 mmb/d in 1970 to 5 mmb/d in 2008.

Figure 1. Tight oil is the foundation for U.S. Energy Dominance.
Conventional production has been in decline since 1970.
Tight oil boosted U.S. production to more than 12 mmb/d in 2019.
Source: EIA and Labyrinth Consulting Services, Inc.

Tight Oil Rig Count and Oil Production

Rig count is a good way to predict future oil production as long as the proper leads and lags are incorporated.

It takes several months between an upward price signal and a signed contract for a drilling rig. It takes another 9-12 months from starting a well to first production for tight oil wells. With pad drilling, usually all wells on the pad must be drilled before bringing in a crew to frack the wells.

Tight oil horizontal production reached 7.28 mmb/d in November 2019 when the lagged rig count was 613 (Figure 2). That corresponded to 12.9 mmb/d of U.S. oil production—tight oil is about 55% of total output. Approximately 600 rigs are needed to maintain 7 mmb/d of tight oil and 12.5 mmb/d of U.S. production.

The horizontal rig count is now 165 so it is unavoidable that production will fall. The considerable lags and leads mean that production decline cannot be expected to reverse until well into 2021 assuming that it starts to increase immediately. That won’t happen because of constrained budgets and low oil prices.

Figure 2. 600 tight oil rigs to maintain 7 mmb/d tight oil/12 mmb/d total U.S. output.
May tight rig count was 207 so U.S. decline to 8 mmb/d by Q2 2021 is unavoidable.
Production should increase this summer with shut-in re-activation then fall in Q4 2020.
Source: Baker Hughes, IEA DPR, Enverus and Labyrinth Consulting Services, Inc.

U.S. producers shut in most of their wells in May because oil prices had collapsed and storage had reached its limits. Tight oil production has fallen more than 1 mmb/d to 6.2 mmb/d and total U.S. output is around 10.5 mmb/d.

With the storage crisis now apparently averted and with somewhat higher oil prices, most tight oil wells are being re-activated. Production should increase until all shut-in wells are back on line and then, it will resume its decline.

Based on rig count analysis, U.S. oil production will probably be about 8 mmb/d by mid-2021 or more than 4 mmb/d less than peak November 2019 levels.

Killer Decline Rates Require Lots of Rigs

Lower U.S. crude and condensate production is unavoidable with rig counts where they are today. That is because tight oil decline rates are really high.

Figure 3 shows Permian basin shale play decline rates by year of first production. The average of all years is 27% per year. More recently drilled wells decline at higher rates because of better drilling and completion technology. The problem is that the wells don’t have greater reserves—they just produce the reserves faster. That means higher decline rates.

Figure 3. Permian basin annual decline rate is 27% for horizontal tight oil wells
Decline rates generally increase for wells drilled in more recent years
because of higher initial production rates.
Source: Enverus and Labyrinth Consulting Services, Inc.

This is not a criticism of the plays or the companies. It’s just a fact.

And that’s why it’s critical to keep 500 or 600 rigs drilling all the time—to replace the 30% of output lost every year to depletion.

Production can be turned off and on as it was in May and June. Production cannot be increased without adding rigs and drilling new wells. Assuming there was infinite capital available to add rigs and drill wells, it would take several years to increase rig count to levels needed to maintain 2019 output levels.

Drilled, uncompleted wells (DUC) may be brought on to slow the rate of production decline somewhat. It is important to note, however, that completion accounts for at least 50% of total well cost. Capital constraints and low oil prices will affect the ability and enthusiasm of companies to complete DUCs.

After the last oil-price collapse, it took 2.5 years for tight oil rig count to increase from 193 in May 2016 to 618 in November 2018 (Figure 3). There were thousands of DUCs during the last oil-price collapse in 2014-2017 but they didn’t have much effect on production decline.

The current June rig count of 165 will continue to fall for several months because of low oil price & capital budgets.

Figure 3. It took 2.5 years for tight oil rig count to increase from 193 in May 2016 to 618 in November 2018.
June rig count of 165 will fall for several months based on oil price & capital budgets.
Source: Baker Hughes, IEA DPR, Enverus and Labyrinth Consulting Services, Inc.

Rigs Don’t Produce Oil, Wells Do

I’ve shown how rig count, lagged production and decline rates are used to estimate future levels of production. That approach is useful but the truth is that rigs don’t produce oil—wells do.

Another approach, therefore, is to compare the number of tight oil wells that were drilled and completed during each of the last 5 years to the corresponding average production rates for each of those years. Then, using year-to-date drilling and completion data, we can annualize and project what 2020 production is likely to be.

This approach suggests that 2020 tight oil production will be about 30% less than in 2019 (Figure 4). Since tight oil represented 56% of total U.S. output in 2019, we may then estimate that U.S. production will average about 8.7 mmb/d in 2020.

Figure 4.2020 U.S. production will be less than ~8.7 mmb/d vs 12.3 mmb/d in 2019.
Number of completed tight oil wells expected to be ~30% less than in 2019.
8.7 mmb/d is about 25% less than EIA U.S. forecast for 11.6 mmb/d in 2020.
Source: EIA and Labyrinth Consulting Services, Inc.

That is similar to the estimate obtained from the rig count approach. It is, however, about 25% less than EIA’s 2020 forecast for U.S. crude & condensate production.

Energy Dominance and Green Paint

Much lower U.S. oil production is bad for Trump’s Energy Dominance anthem and its corollary that the U.S. is energy independent. It’s even worse for oil prices and the U.S. balance of payments once demand recovers. We will have to import even more oil than we do today and it will cost more.

The idea of U.S. energy independence is ignorant at best and fraudulent at worst. The U.S. imported nearly 7 mmb/d of crude oil and condensate in 2019 and more than 9 mmb/d of crude oil and refined products. That’s almost as much as China—the world’s second largest economy—consumes.

The U.S. is a net exporter in the same way that shale companies are making huge profits—by accounting sleight-of-hand.

The U.S. imports other people’s crude oil, refines it and then, exports it. If a country imports unpainted cars, paints them green and then exports them, is it a net exporter of cars? No. It’s an exporter of green paint.

The U.S. is screwed when it comes to near- to medium-term oil production. It’s not because of Covid-19. U.S. rig count began to decline 15 months before anyone had heard of Covid-19. Even if the road to economic and oil-demand recovery is faster than I believe it will be, it will take a long time to get back to 12 or 13 million barrels per day of production.

There are good reasons to expect that much lower U.S. oil production will eventually lead to higher oil prices. That may result in renewed drilling and another cycle of over-supply and lower oil prices. That is how things have developed in the past.

But a new phase of economic reality and oil pricing is unfolding and no one knows where it will lead. Lower demand may mean that reduced U.S. oil output is appropriate. The only thing that seems certain is that the U.S. will not be the oil super power it was before 2020.

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Comparative Inventory & Oil Storage Report June 17, 2020 (2020-8)

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US Land Horizontal Rig Count Report, Week Ending June 12, 2020

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Comparative Inventory & Natural Gas Storage Report June 11, 2020 (2020-2) Early Edition

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Comparative Inventory & Oil Storage Report June 10, 2020 (2020-7)

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Comparative Inventory and Natural Gas Storage Report June 8, 2020 (2020-1)

Highlights of this week’s report:

  • Natural gas surplus greatest in 2.5 years.
  • Storage levels are higher than any previous year except for 2016.
  • Henry Hub correctly priced at $1.76/mmBtu.
  • Production is lower but so is consumption.
  • Cool weather has not helped prices but that is changing.

Comparative Inventory and Storage

Many analysts and investors believe that lower associated gas production should lead to higher natural gas prices. The data does not support that view so far.

Natural gas comparative inventory (C.I.) has been increasing since March 2019 and has been higher than the 5-year average throughout 2020 (Figure 1). The negative correlation between C.I. and gas price is strong so it is not surprising that gas prices have fallen since the maximum negative C.I. more than a year ago. For more on comparative inventory, please see this and other posts on my website.

This means that gas markets are more over-supplied than they have been in 2.5 years and that the over-supply is increasing for now. That is hardly a bullish signal for gas prices.

Figure 1. No bullish signal for U.S. natural gas price.
Comparative inventory has been increasing since March 2019
and has been more than the 5-year average throughout 2020.
Source: EIA and Labyrinth Consulting Services, Inc.

In fact, working gas in storage is at a higher level for this date than it has been since 2016 (Figure 2). Stocks increased to 303 bcf more than the 5-year average the week ending May 29 on a slightly larger-than-normal addition of 102 bcf. That is a stunning 728 bcf more than during this week a year ago. Total storage is 2.7 tcf which represents 56% of working capacity.

Figure 2. U.S. natural gas storage increased to +303 bcf more than 5-year average
and is 728 bcf more than a year ago week ending May 29.
Addition of 102 bcf slightly more than the average 100 bcf addition for this date.
Source: EIA and Labyrinth Consulting Services, Inc.

Cross-plotting C.I. and Henry Hub spot price results in the red yield curve in Figure 3. The C.I. – price point for the week ending May 29 (shown in yellow) plots essentially on the yield curve meaning that gas is priced correctly at $1.77.

The yield curve suggests that gas price at the 5-year average should be about $2.20/mmBtu. Yield curves change as markets perceive different levels of supply urgency but for now, it seems unlikely that winter gas prices should be very different than during the previous winter. The future strip shows the January 2021 contract price at less than $3 which is consistent with winter C.I. levels less than the 5-year average.

Figure 3. U.S. natural gas market sees no uplift from lower tight oil-associated gas production.
Comparative inventory data has not moved from $2.20 mid-cycle price green yield curve.
Gas is correctly priced at $1.77 on larger-than-average +109 bcf addition.
Source: EIA and Labyrinth Consulting Services, Inc.

Supply and Demand

U.S. gas production has fallen more than 3 bcf/d from the November 2019 peak of 96 bcf/d to 93 bcf/d in April (Figure 4). It is expected to decrease another 7.7 bcc/d by December to 85 bcf/d so some see that as support for higher gas prices later in 2020.

Figure 4. U.S. natural gas production has decreased -2.3 bcf/d from November 2019 peak
to 93.1 bcf/d in April and is expected to fall to 87.5 bcf/d by December 2020..
Source: EIA and Labyrinth Consulting Services, Inc.

The problem with that thinking is that it ignores consumption. Gas consumption decreased in the first quarter of 2020 because of the coronavirus economic closure (Figure 5). Industrial use remains depressed while other sectors have improved but have not recovered to pre-closure levels.

Figure 5. U.S. natural gas consumption growth decreased in Q1 2020 with economic closure
Industrial use remains depressed while other sectors have improved.
Source: EIA and Labyrinth Consulting Services, Inc.

Consumption is expected to decrease by about 3.3 bcf/d in 2020 compared to 2019 based on EIA forecasts (Figure 6). Forecasts are always wrong but are worth our attention because they summarize current thinking based on credible modeling assumptions.

Figure 6. U.S. consumption is expected to decrease -3.3 bcf/d in 2020.
8 bcf/d production-consumption surplus expected
greater than 7 bcf/d surplus in 2019.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

Weather

May temperatures were cooler than last year but were slightly warmer than last year for the week ending June 5 (Figure 6). If that trend continues, it will be less negative for gas prices which fell $0.06 despite demand for more space cooling. Temperatures were substantially cooler than the 10-year norm.

June through August weather forecasts indicate warmer-than-normal summer weather for the U.S. so weather may provide some upward pressure on prices in coming weeks.

Figure 7. U.S. temperatures were 11% warmer than last year
but -41% cooler than the 10-year norm week ending June 5.
Henry Hub spot price decreased -$0.06 to $1.70.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

Discussion

Natural gas pricing for the next 6 months should be similar to the last 6 months. The economic slow-down from Coronavirus has affected gas as well as oil consumption.

Despite lower production levels, storage is well above the 5-year average and continues to increase. Over-supply is at the highest levels in more than two years.

Futures prices rallied to $2.13 in early May but then collapsed to $1.62 by mid-month (Figure 8). This was a classic example of price discovery based on sentiment that lower associated gas might result in tighter gas supply. The answer was discovered and prices have been in the $1.70-range since then as I expect they will remain for awhile.

Figure 8. U.S. natural gas price decreased -$0.07 from $1.85 to $1.78 week ending June 5
Price is -$0.05 less than 1 standard deviation below the 18-month mean of $2.49.
Source: Quandl & Labyrinth Consulting Services, Inc.

Managed money has been short on U.S. gas since May 2019. That is clear from falling net long positions which paralleled declining futures prices from late 2018 through January 2020 (Figure 9). During the first quarter of the year, that trend reversed but peaked in May and is now moving in the opposite direction. Traders continued to unwind their long bets through the latest commitment of traders report last week.

Figure 8. Futures markets have been short on U.S. natural gas markets since May 2019.
Momentum toward a reversal of that trend appears to have peaked in early May 2020.
Source: CFTC, Quandl & Labyrinth Consulting Services, Inc.

I am not saying that there is no possibility of a gas-price play in late 2020 and 2021. There is always considerable uncertainty about weather and the pace of economic recovery from coronavirus shutdowns. These could surprise either to the positive or to the negative for gas supply and demand. The point is that lower production of associated gas does not logically result in a supply deficit. Markets are more complex than that. 

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US Land Horizontal Rig Count Report, Week Ending June 5, 2020

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Art Berman Newsletter: May 2020 (2020-4)

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Comparative Inventory & Oil Storage Report June 3, 2020 (2020-6)

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A Natural Gas Price Play is Wishful Thinking

Lower tight oil production should mean lower associated gas production so U.S. natural gas prices should rise, right? That is the conventional wisdom. Too bad it is mostly wishful thinking.

U.S. gas production has already fallen more than 2 bcf/d from the November 2019 peak of 96 bcf/d to 93 bcf/d in April (Figure 1). It is expected to decrease another 7.7 bcc/d by December to 85 bcf/d so that sounds like there might be a supply deficit and higher gas prices.

Figure 1. U.S. natural gas production has decreased -2.3 bcf/d from November 2019 peak
to 93.1 bcf/d in April and is expected to fall to 87.5 bcf/d by December 2020.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

The problem with that thinking is that it ignores consumption and the resulting supply-demand balance.

Consumption is expected to decrease 3.3 bcf/d in 2020 compared to 2019 (Figure 2).

Figure 2. U.S. consumption is expected to decrease -3.3 bcf/d in 2020.
8 bcf/d production-consumption surplus expected
greater than 7 bcf/d surplus in 2019.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

That is not, however, the whole picture because the U.S. became a net exporter of gas in 2016 and these volumes are part of demand. LNG (liquefied natural gas) and pipeline exports fell about 1 bcf/d in April from the March 2020 peak of 8 bcf/d (Figure 3). Exports are expected to continue to decrease to about 5.6 bcf/d in July before increasing again. This is because of low foreign gas prices from decreased demand from Covid-19 economic slow-downs.

Decreased exports mean more domestic supply.

Figure 3. U.S. net natural gas imports fell almost 1 bcf/d in April
and are expected to fall -2.6 bcf/d by July compared to the March peak of 8.2 bcf/d.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

Production minus exports is “net supply.” Net supply differs only slightly from demand because it does not include movements into and out of primary storage.

A supply surplus of about 1.5 bcf/d is expected in 2020 based on the difference between net supply and consumption (Figure 4). The forecast for 2021, however, appears to be a very different story with an implied supply deficit of about 2 bcf/d.

Figure 4. A 1.5 bcf/d net supply surplus is expected for 2020
followed by a 2 bcf/d deficit in 2021.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

That suggests that a long bet on natural gas for 2021 might be a reasonable play. The problem is that 2021 is a long time from now and I have little confidence in EIA’s forecast that far into the future.

I believe that its consumption and net export forecasts are optimistic. Gas prices have collapsed in Europe and Asia and the effect of Coronavirus on the global economy is far from certain.

Figure 5 shows gas production, net supply and seasonally-adjusted consumption. This is important because seasonal variation in gas usage storage changes is extreme.

Looked at from this perspective, it is clear that any potential net supply deficit occurs in the second half of 2021. Most of that period is during the summer and fall when gas demand is typically low. Only November and December 2021 fall into the winter heating season and the gap between supply and consumption decreases with increased production levels.

Figure 5. Ample U.S. natural gas supply at least until winter 2021-2011.
Any supply deficit easily resolved by decreasing export allowables.
Source: EIA STEO & Labyrinth Consulting Services, Inc.

U.S. Department of Energy (DOE) approvals for gas export are provisional. Approvals are subject to review and may be revoked if export “will not be consistent with the public interest.” In the unlikely event that domestic supply became tight, relatively small adjustments of export allowable volumes would provide a simple remedy.

My guess is that market forces will minimize or eliminate any gas supply deficit without DOE intervention. Despite my implied criticism of the far end of EIA’s gas forecast, spot gas prices never reach $3.10 in any month of the forecast. That hardly reflects concern about adequate supply.

I am not suggesting that there is no possibility of a gas-price play in 2021. There is always considerable uncertainty about weather and the pace of economic recovery from coronavirus shutdowns. These could surprise either to the positive or to the negative for gas supply and demand.

The point is that lower production of associated gas does not logically result in a supply deficit. Markets are more complex than that.

Conventional wisdom is, after all, called conventional for a reason.

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US Land Horizontal Rig Count Report, Week Ending May 29, 2020

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Comparative Inventory & Oil Storage Report May 28, 2020 (2020-5)

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Oil Prices and Demand are not Returning to Normal

Oil prices and demand are not returning to normal.

Prices have increased since late April because there was no place to go from a negative price but up. We are near the end of a rally whose ceiling will be in the low $40-range for the foreseeable future.

The Big Short

WTI price fell to -$37 on April 20 and has recovered to $34 over that last 5 weeks (Figure 1). Negative prices resulted from a one-day short squeeze. The May contract was expiring & no oil storage was available. Those who waited to sell their contracts had to pay those who held storage to take physical delivery of the oil.

Prices are approaching 75% recovery to the $58 mean before the price collapse in March. That calculation starts at $12.34 since the negative price was an anomaly and gives a false measure of the recovery.

The rate of price increase has flattened and price has fallen more than $1.50 from yesterday’s settle of $34.35 at this writing. The rally is nearing its end.

Figure 1. WTI price has reached 75% recovery to mean before price collapse.
Rate of increase has flattened suggesting that price rally is nearing its end.
Source: Quandl and Labyrinth Consulting Services, Inc.

Negative prices were the headline in April but the negative spread was the story.

WTI 12-month spreads reached the most negative levels in history between March 31 and April 21 (Figure 2). Shorting oil after the OPEC+ meeting disaster in early March was some of the easiest free money ever made. The short-covering rally that followed negative oil prices was a classic no-brainer, not to be mistaken with something meaningful. Been down so long, it looks like up to me.

Figure 2. The Big Short: March 31 and April 22, 2020
Largest WTI negative spreads in history
April 21, the day after negative futures price, was the lowest open interest in history.
Source: Quandl and Labyrinth Consulting Services, Inc.

There’s been a lot of discussion about negative oil prices and whether there was some sort of manipulation that led to it. Investors noticed.

WTI open interest the day after negative prices was the lowest in history. Weak open interest and trading volumes have characterized the futures market since then. Investors are voting no confidence with their feet. I hope the Chicago Mercantile Exchange is paying attention.

Open interest rises and falls with every contract expiration. Open interest in 2020 peaked around April 3 (Figure 2). The June contract roll on April 22 was characterized by a lower net interest-bounce than in the previous month. The boost from the July roll on May 20 was even lower. This combined with lower trading volumes, and the flattening of prices are evidence that this price rally is almost over.

Figure 2. WTI oil-price rally is weakening.
Boost from July contract roll was underwhelming.
Insufficient open interest and volume for a sustainable rally.
Source: Quandl and Labyrinth Consulting Services, Inc.

Comparative Inventory is the Key to Price Formation

Comparative inventory (C.I.) is the key to understanding price formation. It is the best way to identify price trends and to anticipate future price movements.

C.I. is the difference between current storage levels of crude oil plus a select group of refined products, and their 5-year average for the same weekly time period. Because it is a year-over-year calculation, it normalizes seasonal variations in production, consumption and refinery utilization.

The yield curve that results from cross plotting C.I. vs oil price offers a structure for organizing seemingly random variations in oil prices. The yield curve has provided a useful solution for the complex market forces that determine price formation since inventory data was first published by the EIA in the 1990s.

Supply drives oil markets and price is the signal to producers to increase or decrease drilling to ensure adequate supply. Demand matters but supply can be adjusted relatively quickly. We have seen that in recent weeks as producers have shut in wells in response to extraordinarily low oil prices. The storage crisis that most analysts believed was certain did not happen. Markets are not always right but they are ruthlessly efficient.

The present yield curve shown in green below in Figure 3 is tentative since prices are still in considerable flux. It assumes the lowest possible supply urgency based on the lowest price signals the market has ever sent. Because the yield curve is nearly flat, price will not change much with inventory fluctuations. That is why prices fell so far, so quickly. It is also why they are unlikely to rise much farther.

WTI will probably not exceed $40-$45 per barrel until markets re-price oil upward because of an increased sense of supply urgency. As long as prices are below the yield curve, there is little potential for a return to pre-collapse prices in the mid-$50 range.

Figure 3. Comparative inventory suggests $40-$45 WTI price ceiling in foreseeable future.
Green yield curve is tentative but reflects lowest possible supply urgency.
Inventory changes will have limited affect on price going forward.
Source: EIA and Labyrinth Consulting Services, Inc.

An L-Shaped Recovery

I don’t believe that most people have come to terms with the reality of oil markets going forward. The Covid-19 economic shut-down was not a switch that was turned off and now is turned on as economies begin to open.

Almost 40 million Americans have filed unemployment claims since the end of February. The Chairman of the U.S. Federal Reserve Board expects that to increase and for GDP (gross domestic product) to fall as much as 30% in the second quarter of 2020. Jobs and economic output will not return quickly. A profound re-structuring of the economy must happen first.

U.S. unemployment benefits will expire in July unless Congress extends the payment period and this will mean greater hardship and less spending.

“Seventy-five percent of Americans have seen their income cut by at least 25%. These are the seeds of social unrest.”

Danielle DiMartino Booth, Quill Intelligence

DiMartino Booth’s comment seems exaggerated but it notionally reflects the reality that recovery optimists appear to ignore; namely, that even people with jobs probably aren’t making the same amount as they were before the Covid-19 shutdowns. Only about 40% of Americans have enough savings to cover 3 months of living expenses.

U.S. oil consumption has improved since mid-April but remains about 20% less than normal for this time of year. Most of that increase is from gasoline use and that is skewed by the fact that almost no one is using public transportation.

The harsh truth is that if tens of millions of people have no jobs to go to, gasoline consumption cannot recover to early 2020 levels. The latest Apple mobility data indicates that global driving is about 32% less than the early 2020 baseline.

The world has been on OPEC+ life support since production cuts began in late 2016. That is why when Saudi refineries were bombed in August 2019, prices only spiked for a few days. Markets yawned because there was plenty of spare supply.

Now, OPEC+ has had to cut almost 10 mmb/d and prices have barely recovered into the $30 range. Markets know that the world has plenty of oil supply and that any talk of a balanced market or physical shortages are completely artificial.

With somewhat higher oil prices, U.S. tight oil producers are talking about reactivating shut in wells. Russian leaders are looking forward to the July end of the latest OPEC+ production cut agreement. Floating storage is estimated at around 200 mmb and term structure no longer justifies the cost of storage.

The International Energy Agency and OPEC expect 2020 world demand to be about 9 mmb/d less than in 2019. Those forecasts feature a V-shaped demand recovery that strikes me as either naively optimistic or wantonly patronizing to its funders’ expectations.

Neither agency forecasts supply but EIA data indicates supply will average about 5.5 mmb/d less than in 2020. It at least suggests more of a U-shaped supply recovery.

Considering all of the facts and reasonable extrapolations summarized in this post, I expect an L-shaped recovery in oil supply and demand (Figure 4). This is more of a thought experiment than a forecast because uncertainty is extreme. The supply and demand lines in the figure are meant to be probabilistic trend lines. I expect a most-likely case for 2020 in which supply will fall by about 8 mmb/d and demand, about 16 mmb/d.

Whether you accept my hypothesis or prefer one of the international agencies’, the differences are only a question of degree. The world will be over-supplied with oil in 2020.

Figure 4. 2020 global demand may average 16 mmb/d lower than in 2019
Producers will be forced to cut production because of low price and low demand
Supply-demand balance will follow L-shaped trajectory as markets remain over-supplied

Many of you have written saying that my observations and data are compelling but that you are more optimistic than I am.

I appreciate those comments and will close this post by saying that science and scientific analysis are about neither optimism nor pessimism. Science is founded on observation and description. Patterns are identified and questions are asked to provoke a hypothesis that can be tested with further observation and description.

People naturally want to know what caused things to be the way they are. That is not, however, the aim of science. Science seeks to anticipate the most probable future configuration of things based on patterns identified and tested in the present. That may disappoint some of you whose conception of science is from television or movies.

You have told me that the patterns that I observe and describe seem right to you. You just don’t like the consequences of my explanations.

We are witnessing a momentous transformation of the world economy. Covid-19 was the trigger but the forces it is disrupting have been developing for a long time. Chief among those is the debt undertaken to perpetuate economic growth when common sense indicated it should have slowed or ended decades ago.

Energy is the economy and oil is the most important part of energy today. It is not surprising that oil should be the proverbial canary in the coal mine for the rest of the economy.

Oil prices are not returning to normal. Neither is the economy.

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WEBINAR – THURSDAY MAY 28TH AT 1:30 PM CENTRAL TIME

You will not want to miss this opportunity to interact with Art in a group setting!

Art will be hosting a webinar on Thursday May 28th at 1:30 PM central time. After his presentation you will be able to ask Art questions and have a dialogue about the shocking value of oil and why it is the economy.

Click here to buy a seat at this new, exciting event and become a part of a select group of clients that will interact with Art.

Art hopes to see you at his webinar next Thursday! Remember May 28th at 1:30 pm central time.

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US Land Horizontal Rig Count Report, Week Ending May 22, 2020

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Comparative Inventory & Oil Storage Report May 20, 2020 (2020-4)

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Why Is Anyone Celebrating $33 Oil?

Oil prices have recovered to almost $33 and already some analysts are declaring this a “relentless oil price rally.” Reality check: that is $3 more than the WTI weekly average at the bottom of the last price crash in 2016.

Permian basin independents Concho, Diamondback and Pioneer need about $60 to break even according to their recent SEC 10-K filings. Hedging doesn’t offer anything more than about $37 two years out.

I don’t know about you but I’m going to leave the champagne in the refrigerator for awhile.

Some of the current optimism comes from a slightly less pessimistic forecast for world demand destruction by the International Energy Agency than they had a month ago. Instead of demand growth falling 9.3 mmb/d in 2020, IEA now thinks it may only fall 8.6 mmb/d.

I will try to curb my enthusiasm.

For IEA’s forecast to happen, global demand must continue to rise from ashes and supply must continue to drop. That’s a pretty tall order for a world that is locked in an economic depression that will almost certainly last beyond 2020.

“We are in an outright depression & won’t recover for a long time…Those who expect recovery this year are delusional because many of the job losses will be permanent & probably half of small businesses will fail.”

—Dave Rosenberg, Chief Economist & Strategist, Rosenberg Research & Associates, Toronto

U.S. Consumption is Recovering

Now the good news : U.S. consumption has increased 2.1 mmb/d from its lowest level in mid-April (Figure 1). Most of the increase is in gasoline consumption. Activity is increasing and people are driving more. Diesel use is also rising and that’s encouraging because it suggests that more goods that require truck, train or ship transport are being ordered. Kerosene-jet fuel use, however, has never been lower than the week ending May 8.

Figure 1. U.S. oil consumption has increased +2.1 mmb/d since week ending April 17.
Source: EIA and Labyrinth Consulting Services, Inc.

I have to wonder what the increased gasoline is being used for with so many stores and businesses closed. My guess is that people are using their cars to go everywhere. Buses, trains and subways are operating on a limited basis and who wants to take the risk of getting sick on public transportation?

Diesel use has increased half as much as gasoline as a percent and that suggests that half of the gasoline increase is just people avoiding public transport and not really a sign of an exuberant economic re-opening.

The bad news about the consumption increase is that it’s still 4 mmb/d (20%) less than the 5-year average for the first week in May.

And that is the problem for the economic recovery. Unemployment is probably 20% when the official 15% is adjusted for those not looking for work or who just haven’t filed a claim. The economy may be officially open but the number of people losing their jobs is increasing. We’re operating on an 80% economy and that may seem optimistic by the end of the year.

Why Is Anyone Celebrating $33 Oil?

Whenever a rally’s growth is strong regardless of its starting point, it tells you that the market was short—really short. Brent and WTI net long positions confirm that.

Thirty-five percent of WTI + Brent net long increase in April and May was from short-covering (Figure 2). Brent accounted for most of the increase in short positions since late March and most of the increase in long positions was from WTI.

Why are markets more pessimistic about Brent price upside than they are about WTI? Some of it is probably because WTI prices fell so much lower than Brent in April.

It is worth remembering that OPEC’s basket price is less than $25 at this writing.

Figure 2. Thirty-five percent of WTI + Brent net long increase in April and May was from short-covering.
Source: CFTC, Quandl and Labyrinth Consulting Services, Inc.

The main reason for celebrating $33 WTI is because that price is almost three times higher than the $11 average futures price in the second half of April. The comparative inventory yield curve indicates that WTI should be priced at about $42 based on last week’s oil storage volumes so there’s room for the rally to continue.

But to what end? The top independent producers in the Permian basin need more than $60 wellhead price to break even (Table 1). This is based on their own future cash flow statements in their latest 10-K filings with the Securities and Exchange Commission.

Figure 2. Weighted average break-even price for Diamondback (FANG), Concho (CXO) and Pioneer (PXD) is more than $60 per barrel based on their own discounted future cash flows.
Source: Company 10-K filings for 2019 and Labyrinth Consulting Services, Inc.

Analysts can use all the sleight-of-hand available to show that somehow these companies are cash flow positive on a point-forward basis. The data in Table 1, however, is the reality that they told the U.S. government in February.

Anyone who is enthusiastic about $33 oil needs to think about that.

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US Land Horizontal Rig Count Report, Week Ending May 15, 2020

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