US Land Horizontal Rig Count Report, Week Ending October 16, 2020

Total U.S. land rig coun…

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COMPARATIVE INVENTORY & NATURAL GAS STORAGE REPORT OCTOBER 17, 2020 (2020-20)

PLEASE NOTE: I will be on vacation next week October 19-25 and will post only an abbreviated report summarizing highlights and showing a few key charts. Thanks for your understanding. 

Art

Highlights of this week’s report:

  • Spot natural gas prices increased sharply this week and recovered almost to late August levels.
  • Gas storage remains at record levels levels for early October.
  • Comparative inventory decreased -26 bcf. It was the largest decrease since February.
  • Temperatures are expected to be warmer than normal next week.

Comparative Inventory and Price Movements

Gas markets turned bullish this week as U.S. natural gas spot price rose +1.04 from $1.49 on October 8 to $2.53 on October 15 (Figure 1). Prices have now returned almost to late August levels.

Figure 1. U.S. natural gas spot price has increased almost to late August levels.
Price rose +$0.51 from $2.02 to $2.53.
Spot has increased +$1.20 (+90%) since August 24.
Source: EIA and Labyrinth Consulting Services, Inc.

Futures prices are rallying because they are based on November expectations whereas the spot market is based on the current cash transaction price. The futures contract for January closed at $3.39 on October 16.

Futures and spot general trends should be aligned but they are not.

Figure 2. Natural gas futures prices have increased +$0.93 (+51%) since September 22.
Price fell from -$0.11 from Monday’s high of $2.88 to $2.77 week ending October 16.
12-month spreads widened $0.18 (360%) from -$0.05 to -$0.23.
Source: EIA and Labyrinth Consulting Services, Inc.

U.S. natural gas comparative inventory fell -26 bcf to 309 bcf for the week ending October 9 (Figure 3). This was the second week in-a-row that C.I. has fallen.

This week’s C.I. vs Henry Hub spot price is shown by the yellow circle in Figure 3 . Last week’s data point is shown in light blue. 

C.I. vs Henry Hub price plots below the previous red yield curve for the week ending October 9. It is -$0.24 under-priced at $1.46 on the red yield curve and -$0.46 under-priced on the green yield curve.

Figure 3. C.I. vs Henry Hub price plots below the previous red yield curve week ending October 9.
It is -$0.24 under-priced at $1.46 on the red yield curve
and -$0.46 under-priced on the green yield curve.
Source: EIA and Labyrinth Consulting Services, Inc.

U.S. natural gas storage remains higher than 2016 record-high levels for the ninth week in-a-row (Figure 4). Storage decreased to +309 bcf more than 5-year average and moved down to +358 bcf more than a year ago for the week ending October 9. The addition of +46 bcf was -26 bcf smaller-than-average for this date.

Figure 4. U.S. natural gas storage fell to +309 bcf more than 5-year average
and moved down to 358 bcf more than a year ago week ending October 9.
Addition of 46 bcf was -26 bcf smaller-than-average for this date.
Source: EIA and Labyrinth Consulting Services, Inc.

Natural gas comparative inventory is at the lowest level since the week ending June 12 (figure 5).

Figure 5. Natural gas comparative inventory fell for second week in-a-row.
C.I. decreased -26 bcf to +3096 bcf week ending October 9.
Lowest level since mid-June.
Source: EIA and Labyrinth Consulting Services, Inc.

U.S. temperatures are expected to be twice as warm as last year and 69% warmer than the norm for the week ending October 16 (Figure 6). The week ending October 9 was 13% cooler than last year but 18% warmer than the norm.

Figure 6. U.S. temperatures are expected to be twice as warm as last year
and 69% warmer than the norm week ending October 16.
Week ending October 9 was 13% cooler than last year but 18% warmer than the norm.
Source: EIA and Labyrinth Consulting Services, Inc.

Supply and Demand

Natural gas consumption fell +2.2 bcf/d to 62.1 bcf/d for the week ending October 9 (Figure 7). Residential-commercial use fell -2.2 bcf/d after surging +4.4 bcf/d last week. LNG pipeline receipts fell -0.7 bcf/d after increasing +0.8 bcf/d last week.

Figure 7. Natural gas consumption fell +2.2 bcf/d to 62.1 bcf/d week ending October 9.
Residential-commercial use fell -2.2 bcf/d after surging +4.4 bcf/d last week.
LNG pipeline receipts fell -0.7 bcf/d after increasing +0.8 bcf/d last week.
Source: EIA and Labyrinth Consulting Services, Inc.

Supply decreased -1.6 bcf/d and demand decreased -2.7 bcf/d as the surge in residential-commercial space heating last week subsided with more normal weather in the northern part of the country (Figure 8). Dry gas production fell -1.2 bcf/d from 87.1 bcf/d last week to 85.9 bcf/d for the week ending October 9. Some of this was because U.S. oil production fell from 11 to 10.5 mmb/d with lower associated gas output. Canada gas imports fell -0.3 bcf/d to 4 bcf/d.

The supply-demand balance was +8.7 bcf/d for the week ending October 9. That was -3.2 bcf/d less than the +11.9 bcf/d 5-year average surplus for October. This lower-than-normal supply surplus may be part of the reason for higher prices.

Figure 8. The supply-demand balance was +8.7 bcf/d week ending October 9.
That was -3.2 bcf/d less than the +11.9 bcf/d 5-year average surplus for October.
Source: EIA and Labyrinth Consulting Services, Inc.

Discussion

Nothing about natural gas markets is normal right now. They have been on a roller coaster of price discovery excursions since April. Mid-October prices are higher than peak levels last winter. Spot and futures prices are largely disconnected.

Futures prices fell from a November 2019 high of $2.86 to $1.55 by early April (Figure 9). That was normal. The three price discovery excursions that followed during the Spring and Summer fill season were not normal. These departures can be explained but their magnitude cannot.

Figure 9. Natural gas markets on a roller coaster of price discovery excursions since April.
October prices were higher than peak levels last winter.
Source: Quandl and Labyrinth Consulting Services, Inc.

I can find no measure of supply, demand or storage that accounts for observed price fluctuations. Storage is at record levels. That should mean lower not higher prices. The supply-demand balance has been lower than the five-year average in October but does not signal supply urgency. Comparative inventory has fallen for two weeks but is far above levels that should indicate higher prices.

The only explanation is uncertainty. The pandemic and economic depression have put everything into question. Oil and gas production cannot be maintained with rig counts at record low levels. Companies have limited capital and cannot drill more wells from cash flow. Investors have sent the strongest signals possible that they want to see fiscal discipline before returning with cash. Fossil energy has never been more out-of-favor in world opinion.

Yet the economy cannot function much less grow without energy. The result is a heightened sensitivity to otherwise ordinary events. I see little chance that this will change until we get through winter heating season. If supply proves adequate, as I believe it will, price discovery will end or modulate. If not, markets will continue to use price leverage to increase supply.

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COMPARATIVE INVENTORY & OIL STORAGE REPORT OCTOBER 16, 2020 (2020-25)

PLEASE NOTE: I will be on vacation next week October 19-25 and will post only an abbreviated report summarizing highlights and showing a few key charts. Thanks for your understanding.

Art

Highlights of this week’s storage report:

  • Comparative inventory fell for the twelfth consecutive week. It was the largest decrease since February 2019.
  • Comparative inventory fell for all products except residual. Distillate C.I. decreased the most in three years.
  • Crude oil storage decreased -3.8 mmb.
  • WTI futures are at about $3.00 under-priced at $40.89.
  • Weekly consumption rose +1.1 mmb and the 4-week average increased +0.6 mmb.
  • An SPR withdrawal of 1.8 mmb and unaccounted oil of -5.5 mmb were factors in the crude oil supply balance.

Comparative Inventory

Comparative inventory decreased -3.96 mmb this week. C.I. has decreased for twelve consecutive weeks but his week’s decline about twice as large as the -7.1 mmb average for those three months. 

A crude oil withdrawal of -3.82 mmb when the average is a +2.47 mmb addition led to a -6.29 mmb decrease in crude C.I. (Figure 1). Similarly, gasoline stocks fell -1.63 mmb when a -0.76 withdrawal is normal, resulting in a -0.86 mmb decrease in C.I. A much larger-than-average distillate withdrawal led to a -5.87 mmb change in C.I. This was the largest decrease in distillate C.I. since August 2017 and potentially significant if it proves to be more than a one-off event.

Figure 1. Comparative inventory decreased -15.63 mmb week ending October 9.
Crude oil and all key refined products C.I. decreased except residual.
Source: EIA and Labyrinth Consulting Services, Inc.

Other than crude oil and distillate, the largest C.I. change this week was propane-propylene which fell -2.38 mmb probably because of cold weather in the northern half of the country (Figure 2). Kerosene-jet stocks fell -1.47 mmb for a C.I. change of -0.5 mmb. Residual C.I. increased +0.6 mmb on a larger-than-average addition of 0.66 mmb.

Figure 2. Comparative inventory decreased -15.63 mmb week ending October 9.
Crude oil and all key refined products C.I. decreased except residual.
Source: EIA and Labyrinth Consulting Services, Inc.

Comparative inventory has fallen -86 mmb since the week ending July 17 (Figure 3). The C.I. decrease was about twice as large as the average of -7.1 mmb over the last 3 months. Based on the average twelve-week decline rate, it will take 9 weeks for C.I. to reach the 5-year average.

Figure 3. Comparative Inventory has fallen -86 mmb (-58%) since July 17
-16 mmb decrease in C.I. week ending October 9 twice as large as average
9 weeks for C.I. to reach 5-year average at -7.1 mmb/week mean decline rate.
Source: EIA and Labyrinth Consulting Services, Inc.

Comparative inventory vs WTI price data continues to move toward the five-year average but has moved below the green yield curve over the last five weeks (Figure 4). This reflects more pessimistic market sentiment as Libya’s output is increasing and Norway’s oil worker strike has been resolved.

The weekly average WTI price of $40.19 was about $4 under-priced based on the yield curve. The current WTI futures price on October 7 of $40.89 is about $3.00 under-priced.

Figure 4. U.S. comparative inventory fell -15.63 mmb to 63 mmb more than 5-year average
Weekly average WTI of $40.19 is ~$4 under-priced
based on the green C.I. vs price yield curve.
Source: EIA and Labyrinth Consulting Services, Inc.

Supply and Demand

Table 1 provides a convenient snapshot of the major factors that affected this week’s storage report. Weekly consumption increased +1,130 kb/d and 4-week average consumption rose +614 kb/d. Refinery intakes fell -276 kb/d and field production fell -500 kb/d to 10.5 mmb/d.

Table 1. Petroleum status vital statistics.
Source: EIA and Labyrinth Consulting Services, Inc.

There was a +1,159 kb release from the strategic petroleum reserve (SPR) and a -5,495 kb volume of unaccounted-for oil. Crude oil imports were -446 kb/d lower at 5.3 mmb/d and crude exports were -524 kb/d lower at 3.4 mmb/d. Net refined product exports increased +270 kb/d.

U.S. refined product consumption rose +614 kb/d from 17.8 to 18.4 mmb/d for the week ending October 9 (Figure 5). Recovery increased +11.5% from 58.5% to 70% of the 5-year average. That is the highest level since the consumption and economic collapse earlier this year.

Figure 5. U.S. refined product consumption rose +614 kb/d from 17.8 to 18.4 mmb/d
week ending October 9
Recovery increased +11.5% from 58.5% to 70% of the 5-year average.
Source: EIA and Labyrinth Consulting Services, Inc.

The consumption increase this week was headlined by diesel which jumped from 17% to 87% recovery in a week (Figure 6). I have to be skeptical that this is a data problem or one-week anomaly. If additional data proves it to be durable in coming weeks, it would be quite significant indicating real strength in the pace of the U.S. economy. Gasoline’s recovery was unchanged from last week at 84%.

Figure 6. U.S. refined product consumption has recovered to 70% of the 5-year average
Diesel has recovered to 87% and gasoline to 84%
Kerosene jet is at 29% of its 5-year average.
Source: EIA and Labyrinth Consulting Services, Inc.

U.S. refinery intakes fell from last week’s highest level since week ending August 28 (figure 7). This week, intakes decreased -276 kb/d to 13.6 mmb/d. This is -1.9 mmb/d less than a year ago and -2.0 mmb/d less than the 5-year average.

Figure 7. U.S. refinery intakes fell from highest level since week ending August 28.
Intakes decreased -276 kb/d to 13.6 mmb/d week ending October 9.
-1.9 mmb/d less than a year ago and -2.0 mmb/d less than the 5-year average.
Source: EIA and Labyrinth Consulting Services, Inc.

Discussion

The most remarkable aspect of this week’s storage report is that oil prices did not increase. Everything about the report was strongly positive except lower refinery intakes. Consumption recovery reached the highest level so far. Distillate/diesel demand and inventories have been a major drag on oil markets and this week’s distillate withdrawal was the largest in three years. Across-the-board larger-than-average withdrawals of crude and most other products should have moved price higher at least for a day or so. Instead, futures fell -$0.08.

New Covid-19 surges in Europe, the apparent resolution of Libya’s production hiatus and the settlement Norway’s oil-field workers strike all weighed on market sentiment. Reports by OPEC and IEA this week emphasized the magnitude of over-supply and fueled growing sentiment that oil is not part of the global energy future. These seemed to underscore the gloomy views from BP’s Energy Outlook published last month.

That is the mainstream explanation.

Comparative inventory, however, anticipated this price trajectory. Figure 8 is from the April edition of The Comparative Inventory and Oil Storage Report. Even with limited data, the anticipated green yield curve was largely the same as it is today as shown above in Figure 4.

Figure 8. Comparative inventory chart from April 2020.
Source: EIA and Labyrinth Consulting Services, Inc.

A flat yield curve means that markets have little sense of supply urgency. Even large changes in C.I. do not result in much change in price. The downward price departure from the yield curve in Figure 4 probably reflects sentiment and price discovery. WTI should return to the low-to-mid $40 range once the market changes its present negative perspective.

Some analysts see more downside than upside price risk. Comparative inventory suggests the opposite.

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Oil and The Changing World Order

U.S. oil inventories have fallen every week for two months yet WTI has averaged less than $40 per barrel since the end of August. That is because oil has been re-priced and markets are unwilling to pay more for it.

Those who expect a return to 2019 price levels acknowledge that the oil-demand recovery has stalled. They believe that this is because of Covid-19 and that things will be return to normal once there is a vaccine.

Perspective

“I don’t think the severity of this downturn has been well understood yet.”

Sophia Koropeckyj, Moody’s Analytics

What is happening to oil markets and to the global economy is not because of a virus. The virus greatly accelerated what was already happening. Things won’t go back to normal when the virus ends. I wrote that a month ago and nothing has happened since then to change my mind.

The world is in a debt cycle that began fifty years ago. World orders change when debt cycles approach their end. Ray Dalio has studied how and why world orders have changed over the last 1500 years. These are the requisites that changing world orders have in common:

  • High levels of indebtedness.
  • Low interest rates that limit the ability of central banks to stimulate the economy.
  • Large wealth gaps and political divisions that lead to social an political conflicts.
  • A rising world power that challenges the over-extended leading power.

These criteria have clear relevance to the present world order as China challenges U.S. hegemony. Discord created by debt, interest rates and income inequality have been aggravated by the Covid-19 pandemic but will not be resolved when the virus is controlled.

What Recovery?

The U.S. oil consumption recovery is getting worse, not better. U.S. oil consumption recovered to 65% of normal in July and has since decreased to 61% (Figure 1).

Figure 1. U.S. oil consumption recovery is getting worse, not better.
Recovery fell from 65% (18.32 mmb/d) in July to 58% (17.81 mmb/d) in September.
Source: EIA and Labyrinth Consulting Services, Inc.

Some analysts report a much more optimistic recovery of about 90%.

Figure 2 shows EIA consumption data for September. September consumption of 17,815 mmb is 90% of the 5-year average of 19,834 but that is not a measure of recovery. Recovery must be measured between two datums.

Recovery is determined by comparing the current level (90%) with the 2020 minimum (74%) and the 5-year average (100%). The current level is 16% of the 26% gap between the April minimum and the average. Sixteen divided by twenty-six is sixty-two so recovery is 62%, not 90% (These are rounded to an even percent so the true recovery is as shown in Figure 1 as 61%).

Figure 2. U.S. oil consumption calculation method.
Source: Labyrinth Consulting Services, Inc.

The consumption recovery continues to be dominated by gasoline which was 8.74 mmb/d in September or 84% between its minimum and five-year average (Figure 3). That is not surprising since gasoline accounts for about 45% of refined products produced from every barrel of oil. Jet fuel’s recovery is only 30% and diesel’s is only 17%.

Figure 3. U.S. refined product consumption recovered to 61% of the 5-year average in September.
Gasoline has recovered to 84%, jet fuel to 30% and diesel to 17%.
Source: EIA and Labyrinth Consulting Services, Inc.

Gasoline use is important but driving around to see friends and make small purchases contributes little to economic activity.

Diesel is the barometer of the economy and its use is normally fairly insensitive to price. As long as there are orders, trucks, trains and ships run. When diesel use is down, it is because there are few orders. With recovery at 17%, it is difficult to be very optimistic about the state of the economy.

It took 4 1/2 years for oil consumption to return to the five-year average after the 2008 Financial Collapse (Figure 4). The present collapse is far greater and September use was lower than all but the worst two months of the last recovery from 2009 to 2013.

This is very significant. Why should we expect this recovery to proceed any faster than the last one?

Figure 4. It took 4.5 years after 2008 Financial Collapse for U.S. refined product use to recover.
The magnitude of the 2020 consumption collapse is far greater than in 2008.
September use was lower than all but the 2 worst months of the 2008 contraction.
Source: EIA and Labyrinth Consulting Services, Inc.

Paradigm Change

Much of the thinking about oil markets and the economy assumes that what is happening now is a temporary anomaly and that things will return to the previous state at some time.

We are in a depression—not a recession, but a depression. And I think the dynamics of a depression are different than they are in a recession because depressions invoke a secular change in behavior. Classic business cycle recessions are forgotten about within a year after they end—the scars from this one will take years to heal.

David Rosenberg, Rosenberg Research

We should pay attention to what David Rosenberg says but even his stern message suggests a return to normal after a number of years. Return is never a useful or valid assumption for the future but particularly not now. A new paradigm is needed.

A paradigm is a model that for a time seems to explain the state of the world better than competing theories (Thomas Kuhn, The Structure of Scientific Revolutions). Economic growth has been the ruling paradigm since the end of World War II. Technological innovation, capitalism and democracy have evolved as possible causes for the growth paradigm. The problem is that they were hardly unique to the second half of the twentieth century.

Energy is the economy. Money is a call on energy. Debt is a lien on future energy.

The extraordinary growth after 1945 was because of the widespread shift to petroleum as the primary energy source for the world. Because a barrel of oil contains the equivalent of about 4 1/2 years of human work, the resulting increase in productivity was the true cause for economic growth.

Early empires rose by enslaving conquered populations and capturing their work, and by taking their gold—a claim on work. World War I was fought initially over coal. Germany challenged England’s energy dominance by sinking ships like the Lusitania that was carrying coal. World War II was fought largely over oil. Germany’s first attacked Poland because it produced oil. Japan took Indonesia for its oil and then attacked the United States for denying it oil exports.

The United States rose initially on the backs of negro slaves. It became a major power first on the back of coal and then petroleum, the most productive slave in human history.

Great states fall when they reach the limits of their resources or they are defeated in wars trying to obtain more. The rise and fall of world powers is closely related to their access to credit which, in turn, is a call on future energy resources.

The world order has changed. U.S. dominance is declining and China’s is rising. Producing countries largely determined oil prices until 2014. Since then, consuming countries led by China have begun to assert their power.

Many people tell me, “I agree with everything you say but the difference between you and me is that you’re a pessimist and I’m an optimist.”

I am neither an optimist or a pessimist. I am a scientist. I use data to best describe the present state of things. If someone prefers a different story, I understand. Stories are good for entertainment but rarely lead to a clear view of what the future may bring much less good investment decisions.

The growth paradigm is dead or dying. Most future energy scenarios do not acknowledge slow growth. They imagine that technology will allow the world to simply switch from fossil to renewable energy without sacrificing living standards. The physics of that simply don’t work.

Most analysts incorrectly assume that slowing oil demand signals the end of the oil age. They don’t understand that all growth is slowing because of unmanageable debt and a weakening economy. Covid-19 brought that grim future to us a decade or so earlier than expected.

The world order is changing. The world will need oil more than ever because of its unparalleled productivity. Oil was responsible for the singular economic growth after World War II. It is the only thing that can prevent slow growth from becoming negative growth in that new world order.

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US Land Horizontal Rig Count Report, Week Ending October 9, 2020

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COMPARATIVE INVENTORY & NATURAL GAS STORAGE REPORT OCTOBER 9, 2020 (2020-19)

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COMPARATIVE INVENTORY & OIL STORAGE REPORT OCTOBER 8, 2020 (2020-24)

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ART BERMAN NEWSLETTER: SEPTEMBER 2020 (2020-8)

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US Land Horizontal Rig Count Report, Week Ending October 2, 2020

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COMPARATIVE INVENTORY & NATURAL GAS STORAGE REPORT OCTOBER 2, 2020 (2020-18)

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Art Berman: U.S. Production still set to decline…but so is demand

COMPARATIVE INVENTORY & OIL STORAGE REPORT OCTOBER 1, 2020 (2020-23)

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US Land Horizontal Rig Count Report, Week Ending September 25, 2020

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COMPARATIVE INVENTORY & NATURAL GAS STORAGE REPORT SEPTEMBER 25, 2020 (2020-17)

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COMPARATIVE INVENTORY & OIL STORAGE REPORT SEPTEMBER 23, 2020 (2020-22)

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US Land Horizontal Rig Count Report, Week Ending September 18, 2020

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COMPARATIVE INVENTORY & NATURAL GAS STORAGE REPORT SEPTEMBER 19, 2020 (2020-16)

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COMPARATIVE INVENTORY & OIL STORAGE REPORT SEPTEMBER 17, 2020 (2020-21)

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COMPARATIVE INVENTORY & NATURAL GAS STORAGE REPORT SEPTEMBER 12, 2020 (2020-15)

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US Land Horizontal Rig Count Report, Week Ending September 11, 2020

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Comparative Inventory & Oil Storage Report September 11, 2020 (2020-20)

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US Land Horizontal Rig Count Report, Week Ending September 4, 2020

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Art Berman Newsletter: August 2020 (2020-7)

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Comparative Inventory & Natural Gas Storage Report September 4, 2020 (2020-14)

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Comparative Inventory & Oil Storage Report September 3, 2020 (2020-19)

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Stop Expecting Oil and the Economy to Recover

Global oil markets are on the cusp of something.

Nafeez Ahmed says that the oil age is coming to an end.

The oil industry is on the cusp of a process of almost total decimation that will begin over the next 30 years, and continue through to the next century.

Nafeez Ahmed, Director Institute for Policy Research & Development

Goehring and Rozencwajg say there’s not nearly enough oil to meet demand and that a global energy crisis is imminent.

“We are on the cusp of a global energy crisis…Global energy markets in general and oil markets in particular are slipping into a structural deficit as we speak. We believe that energy will be the most important investment theme of the next several years and the biggest unintended consequence of the coronavirus.”

Goehring and Rozencwajg

They are both partly right but miss the larger point namely, that it is unlikely that either oil supply or demand will ever return to 2018 levels.

World Oil Growth is Dependent on U.S. Tight Oil

U.S. oil production fell -2.72 mmb/d (-21%) from 12.7 to 10 mmb/d from March to May as oil prices collapsed (Figure 1). It recovered to 11.36 mmb/d in June as shut-in wells were re-activated. EIA expects output to average 11.2 mmb/d in the second half of 2020 and 11.1 mmb/d in 2021.

That is impossible.

Figure 1. U.S. oil production fell -2.72 mmb/d (-21%) from 12.7 to 10 mmb/d from March to May.
It recovered to 11.36 mmb/d in June as shut-in wells were re-activated.
Output expected to average 11.2 mmb/d in 2H 2020 and 11.1 mmb/d in 2021.
Source: EIA 914 and Labyrinth Consulting Services, Inc.

During the last oil-price collapse in 2015 and 2016, U.S. output decreased 1.12 mmb/d over a period of eighteen months. This time, a much larger decline has taken place over a period of just a few months.

Goehring and Rozencwajg are correct that tight oil is crucial to world supply growth and that the best parts of those plays are fully or nearly full developed.

U.S. tight oil accounted for 83% of growth in world production over the decade 2009 to 2019 (Figure 2). Deep water and oil sands were the other growth area at 23% while conventional production declined 9% over the same period.

World crude and condensate production fell an astonishing 10.8 mmb/d from 82.5 to 71.7 mmb/d from April to June of this year. About 30% of that decline was from U.S. output and a little more than half of the U.S. decline was from tight oil.

Figure 2. U.S. oil production fell -2.74 mmb/d (-21%) from 12.7 to 10 mmb/d from March to May.
It recovered to 11 mmb/d in June as shut-in wells were re-activated.
Output expected to be flat through 2021 from 10.5 to 11 mmb/d.
Source: EIA 914 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 a month or two between increased oil price and a signed rig contract. It takes another 5 or 6 months to drill and complete all the wells on a drilling pad. It then takes another 5 or 6 months from first production before new wells offset declining output from older wells. Add it all together and it takes at least a year between an upward price signal and enough new production to maintain or increase output.

Twelve-month lagged tight oil horizontal production reached 7.28 mmb/d when the rig count was 613 (Figure 3). That corresponded to 12.9 mmb/d of U.S. oil production (tight oil is about 53% of total U.S. output). The EIA forecasts about 11 mmb/d of output through 2021. Approximately 450 rigs are needed to maintain that level but the July tight oil rig count was 147, about one-third of the number needed to maintain 11 mmb/d.

Figure 3. Tight oil output may decline to 3.5 mmb/d & U.S. to 6.5 mmb/d in Q3 2021
Tight oil rig count is 147, 32% of 450 rigs needed to maintain
5.5 mmb/d tight oil/11 mmb/d total U.S. output.
Source: EIA, Baker Hughes and Labyrinth Consulting Services, Inc.

It is, therefore, inevitable that production will fall. The considerable lags and leads mean that production decline cannot be expected to reverse until well into 2021 assuming that large numbers of rigs are added immediately. That won’t happen because of constrained budgets and low oil prices. Based on rig count analysis, U.S. oil production will probably be about 6 mmb/d by mid-2021 or less than half of peak November 2019 levels.

This is why EIA’s production forecast is impossible. It does not acknowledge that production cannot be maintained without drilling new wells to offset legacy well declines.

What about DUCs (drilled, uncompleted wells)? The DUCs drilled before 2015 will never be completed because they were questionably commercial at $100/barrel oil prices. Many remaining DUCs are part of the 12-month delay from well spud-to-production. Nor is completing DUCs free. Completion accounts for roughly half of total well cost.

Supply and Demand: Two Parts of a Single Whole

Goehring and Rozencwajg believe that we are on the cusp of a global energy crisis because of the depletion of U.S. tight oil plays. They are right but are not paying enough attention to demand. Ahmed believes the oil industry is dying a slow death because of decreasing demand. He is right about lower demand but is not paying enough attention to supply.

Supply and demand are two parts of a single whole.

World liquids supply has fallen 9.5 mmb/d in the first half of 2020. Demand has fallen almost 19 mmb/d for a supply-demand surplus of almost 9.5 mmb/d (Figure 4). That is precisely why oil prices remain range-bound in the $40 range. A big drop in supply only results in an energy crisis if demand recovers to 2019 levels.

This image has an empty alt attribute; its file name is image-90.png
Figure 4. OPEC-EIA* expects a supply-demand deficit for 2H 2020 through 1Q 2021
but a supply-demand surplus for the last 3 quarters of 2021.
-9.1 mmb/d demand growth and -6.1 mmb/d supply growth in 2020.
Source: OPEC, EIA and Labyrinth Consulting Services, Inc.

The integrated OPEC-EIA data shown in Figure 4 indicates a V-shaped demand recovery in the third quarter of 2020 with a lagging recovery in supply. I don’t believe that either forecast is likely but let’s put that aside for now so we can understand the best-case outcome.

A huge supply surplus in the first half of the year is expected to give way to a smaller yet significant supply deficit in the second half. A 2.25 to 2.50 mmb/d supply deficit in the second half of the year is not an energy crisis but it does suggest higher oil prices are ahead.

The OPEC-EIA model suggests approximate market balance in early 2021 followed by a substantial surplus during the rest of the year. That is hardly a death knell for the oil industry but it does suggest lower oil prices are ahead.

Where is the crisis for either supply or demand?

To be fair, I’m sure that Goehring and Rozencwajg, and Ahmed would say that they are thinking farther into the future. Their models assume some version of business-as-usual but I don’t think there is anything usual about the either the present or the future. The world has changed but paradigms change slowly.

Stop Expecting Oil to Recover

Many believe that oil markets are recovering and will return to normal sooner than later. I’m not sure that normal applies to oil markets but let’s look at the facts.

August average WTI price of $42.88 is less than the 2003 average inflation-adjusted price of $43.54 and, of course, every one of the sixteen succeeding years (Figure 5). That is hardly an impressive recovery.

Figure 5. August 2020 WTI price of $42.88 has recovered almost to 2003 CPI-adjusted price of $43.54
but is lower than average price of each of 16 successive years.
Source: U.S. Bureau of Labor Statistics, EIA and Labyrinth Consulting Services, Inc.

Figure 6 shows U.S. supply, demand and supply-demand balance. Supply has been trending lower since late 2018 except for the early 2020 spike that resulted from shutting in production with collapsing consumption and limited storage.

Although demand has recovered from early May low levels it appears to be turning downward now and is, in any case, far below levels for the last 12 months. Again, not a great recovery.

Figure 6. U.S. oil supply is falling and demand is flattening and beginning to decline.
Supply and demand may remain in balance
as long as supply and demand move in tandem.
Source: OPEC, EIA and Labyrinth Consulting Services, Inc.

U.S. refined product consumption has recovered only to 62% of its 5-year average (Figure 7). Gasoline has recovered to 81% of 5-year average and diesel to 84% of 5-year average. Kerosene Jet has only recovered to 34% of 5-year average.

Figure 7. U.S. refined product consumption has recovered to 62% of the 5-year average.
Gasoline has recovered to 81% of 5-year average and diesel to 84% of 5-year average.
Kerosene Jet has only recovered to 34% of 5-year average.
Source: OPEC, EIA and Labyrinth Consulting Services, Inc.

The recovery is not going all that well but history tells us that is what we should expect. It took 4 1/2 years after the 2008 Financial Collapse for U.S. refined product use to recover (Figure 8). The magnitude of the 2020 consumption collapse is far greater than in 2008 so why should this recovery be any faster?

Figure 8. We should stop expecting oil consumption to return to normal.
It took 4.5 years after 2008 Financial Collapse for U.S. refined product use to recover.
The magnitude of the 2020 consumption collapse is far greater than in 2008.
Source: OPEC, EIA and Labyrinth Consulting Services, Inc.

In fact, the only thing that justifies calling what is happening today a recovery is the presumption that things can’t get any worse than they were in April. That presumption is probably wrong.

The Great Simplification

Energy is the economy. Money is a call on energy. Debt is a lien on future energy.

What is happening to oil markets and to the global economy is not because of a virus. The virus greatly accelerated what was already happening. Things won’t go back to normal when the virus ends.

The expansion of energy and debt have been leading toward some sort of reckoning for at least the last fifty years. That day of reckoning has been brought forward by coronavirus economic closures.

Oil prices had averaged $25 per barrel from the end of World War II until 1974 when average prices doubled (Figure 9). From 1979 through 1986, oil price soared to an average of $86 per barrel. These massive economic dislocations resulted in use of debt to maintain economic growth.

This image has an empty alt attribute; its file name is image.png
Figure 9. High oil prices resulting from oil shocks of 1974-1986 led to widespread use of debt to maintain economic growth.
Source: EIA, Bureau of Labor Statistics and Labyrinth Consulting Services, Inc.

Excessive debt was the leading cause for the Financial Collapse of 2008. The crisis was resolved with more debt and monetary policies that ushered in the present era of central bank primacy in the world financial system.

Quantitative easing, near-zero interest rates and high oil prices led to the first wave of the tight oil boom. Over-investment resulted in over-supply and price collapse in 2014. By February 2016, WTI price reached $33 and investors rushed in to support the second wave of the tight oil boom.

WTI reached $72 by mid-2018 but by then, investors had begun to abandon tight oil as well as oil companies in general. The coronavirus economic closure brought monthly average prices to $17 in April, 2020—the lowest month on record. Unlike early 2016, investors weren’t writing any checks this time.

U.S. production may be 50% lower by mid-2021 than at year-end 2019. The implications for U.S. geopolitical power and balance of payments are staggering. It seems likely that the economy will weaken as government support for the unemployed decreases

I doubt that we are on the cusp of either a global energy crisis or the end of the oil age. It is more likely that both supply and demand will fall in tandem as the global economy contracts.

These observations are at odds with the mainstream view that both supply and demand are recovering. Some might concede that I am correct for the present but that things will improve and return to normal although it may some time.

Figure 10 shows credit growth and credit impulse for the United States from 1960 through the first quarter of 2020. Credit impulse is the change in flow of credit (debt) relative to economic activity (GDP).

Spikes in credit impulse correlate well with the oil-price shocks of the 1970s and 1980s. The extraordinary U.S. comparative inventory drawdown of early 2017 through the second quarter of 2018 also corresponds to credit impulse anomalies.

Figure 10. First quarter 2020 increase in U.S. credit impulse* was greatest on record
First quarter credit growth was greatest since 1984.
Source: EIA, Bureau of Labor Statistics and Labyrinth Consulting Services, Inc.

The chief feature of Figure 10, however, is that the magnitude of the first quarter 2020 credit impulse was more than twice as large as any previous increase. Moreover, GDP growth was either neutral or positive during previous spikes but was negative (-10%) for the first quarter of 2020. Also, oil prices were increasing during earlier periods but prices were decreasing in early 2020.

Ilya Prigogine was a chemist who won the 1977 Nobel Prize for his work on dissipative structures and self-organization. Dissipative structures are physical systems that release considerable heat as they consume ever-greater energy to support their growth and increasing complexity. A crisis occurs when growth can no longer be supported by available energy resources. The system either collapses or spontaneously re-organizes itself into a simpler form that uses less energy.

Empires, organizations and economies are dissipative structures. So is the human brain.

My friend Nate Hagens has applied some of Prigogine’s ideas to his own research about world energy, economics and ecology. He believes that we are on the cusp of something quite different from the scenarios suggested by Ahmed, and Goehring and Rozencwajg.

Hagens predicted a global economic decline in the 2020s and publicly expressed that opinion before the Covid pandemic. The main reason for decline, he stated, was too much debt undertaken to continue consuming and growing the economy. The virus has accelerated its timing and may result in contraction greater than the 30% drop during the Great Depression.

The Great Simplification will occur when the credit-supported part of the economy is removed. Economic activity will contract and less energy will be needed because it will be increasingly unaffordable to many parts of the population. People will be forced to adjust living standards downward and self-organize around energy with greater emphasis on local supply chains and regional economies.

I expect that the mix of energy sources will be similar initially. That will probably change as declines to meet the decreased carrying capacity of a society deprived of fossil energy productivity. Then, I imagine the world will move increasingly toward lower productivity energy sources like wind and solar. A viable economy may very well be created based heavily on wind and solar. It will, however, support a much poorer world than we have known for many decades in the world’s advanced economies.

Most ideas and analyses about future trends in energy and the economy fail to recognize that they are the two aspects of the same thing. That is why they are so far off the mark. This basic misalignment is painfully obvious because the energy sector represents only 2.5% of the S&P 500 valuation but underlies probably 95% of U.S. GDP.

That is what Hagens calls energy blindness.

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US Land Horizontal Rig Count Report, Week Ending August 28, 2020

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Comparative Inventory & Natural Gas Storage Report August 28, 2020 (2020-13)

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Comparative Inventory & Oil Storage Report August 27, 2020 (2020-18)

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US Land Horizontal Rig Count Report, Week Ending August 21, 2020

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Comparative Inventory & Natural Gas Storage Report August 21, 2020 (2020-12)

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Comparative Inventory & Oil Storage Report August 20, 2020 (2020-17)

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US Land Horizontal Rig Count Report, Week Ending August 14, 2020

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Comparative Inventory & Natural Gas Storage Report August 14, 2020 (2020-11)

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Comparative Inventory & Oil Storage Report August 13, 2020 (2020-16)

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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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