The Petroleum Truth ReportMy goal is to offer clear and direct explanations of energy reality. These posts are data-driven interpretations of oil and gas topics that often challenge conventional thinking.
IEA and EIA dropped an oil-glut bomb this month. Their September monthly reports indicate that the world continues to have a glut of oil with little hope of a balanced market in the near future.
IEA’s Oil Market Report focused on weakening demand growth for oil.Their quarterly data shows that year-over-year demand growth has decreased consistently from 2.3 mmb/day in the third quarter of 2015 to 1.4 mmb/day for the second quarter of 2016 (Figure 1). The forecast for the third quarter is only 1.2 mmb/day.
IEA downgraded its forecast for 2016 to an average of 1.3 mmb/day annual demand growth and only 1.2 mmb/day for 2017.
EIA monthly data from the September STEO (Short Term Energy Outlook) shows that world oil-consumption growth has declined from more than 4% in late 2015 and early 2016 to 2.1% in August 2016 (Figure 2).
EIA data indicates that maximum consumption growth as a percentage occurred when oil prices were falling into the low-$30 range and that it has weakened as prices increased into the mid- to upper-$40 range. This suggests the global economy is too weak to support oil prices in the current range.
The world production surplus increased in August because production increased and consumption decreased. The over-supply rose to +0.97 million barrels of liquids per day from near-market balance (+0.12 million barrels per day) in June (Figure 3).
Both agencies stressed that high OPEC production levels are a major cause of continued world over-supply. Iraq, Iran and Saudi Arabia have increased crude oil production by 2.74 million barrels per day since January 2014 (Figure 4).
This is why a production freeze by OPEC would not be particularly helpful.
One hundred years of natural gas? Not at these prices.
U.S. gas production is declining and shale gas output is down almost 2.5 Bcf per day. Production is decreasing while consumption and exports are both increasing. EIA data indicates a supply deficit by the end of 2016.
Henry Hub spot prices have doubled since early March. Will companies show discipline to preserve higher prices?
Not a chance. They will drill more wells if investors continue to provide capital. This, however, will probably be too little too late to stop the decline in gas production that is already underway.
Real Gas Prices Have Never Been Lower
In February 2016, I wrote that an increase in natural gas prices was inevitable and in April, I wrote that prices would double. Now, spot prices have doubled from $1.49 on March 4 to $2.97 per mmBtu on August 29 (Figure 1).
Still, real natural gas prices (in July 2016 dollars) have never been lower. Average prices so far this year are just $2.20 per mmBtu. That’s the lowest annual price in since 2000 and it is lower than any monthly price except April 2012.
Prices have increased because total dry gas production has declined 1.6 Bcf per day (Bcfd) from its peak of 75.29 Bcfd in February. Shale gas production has declined 2.4 Bcfd from its peak of 44.17 Bcfd (Figure 2).
Conventional gas has been in terminal decline since 2008 and shale gas production growth has maintained and increased U.S. supply. Now, that shale gas production is also in decline (Figure 3), it is unlikely that production will increase much without higher prices.
All shale gas plays have declined including the Marcellus which is down -0.64 Bcfd (Table 1). Even the relatively new Utica play has declined -0.12 Bcfd. The legacy plays have declined the most: Haynesville, -3.77 Bcfd; Barnett, -1.91 Bcfd; and Fayetteville, -0.92 Bcfd. No new horizontal wells have been drilled in either the Barnett or Fayetteville since early 2016.
Shale gas plays were supposed to provide 100 years of supply but there never was 100 years of gas.
It was a story told to promote the erroneous idea that the U.S. had so much gas that it could afford to squander and export this valuable natural resource. It is true that some of the production decline from shale gas plays is because the plays are not commercial at current prices.
But whose fault is that? Conscious over-production reduced the price below the marginal cost so promoting increased consumption and export became the only ways to increase price.
The U.S. government has been a great ally of the shale gas companies. The SEC changed reserve reporting rules in 2010 making it easier for companies to book reserves and borrow against them. EPA air pollution regulations since 2011 have led to the closing of dozens of coal-fired power plants in favor of increased dependency on natural gas for electric power thus increasing demand. The U.S. Department of Energy has granted almost blanket approval to applications for LNG (liquefied natural gas) and pipeline export in recent years also increasing demand. And in 2011, the U.S. Department of State under Hillary Clinton created the Bureau of Energy Resources, a 63-person group to promote shale gas export and the spread of fracking technology around the world.
Meanwhile, E&P companies destroyed billions of dollars in shareholder value. They did this by knowingly producing gas into a non-commercial market and then, diluting shareholders by issuing more stock to fund more drilling and production.
Comparative Inventories Tell The Story
Natural gas storage is at near-record levels for this time of year. This surplus distracts from the likelihood of a supply deficit by the end of 2016 suggested by EIA STEO data (Figure 4).
Periods of production growth led to lower prices and lower gas-directed rig counts. Flat production led to supply deficits that resulted in higher prices and more drilling. During the last deficit in 2013 and 2014, spot prices averaged $4.06 per mmBtu. The ensuing low prices have resulted in less drilling and flat production.
It is, therefore, reasonable that the increase in gas prices since March 2016 will result in more supply but how high might gas prices go before that happens?
Comparative inventories are the best indicators of price trends. Comparative inventory is the difference between current storage volumes and the 5-year average of storage levels for the same week. Figure 5 shows that there is an excellent negative correlation between comparative inventory and spot gas prices.
That is because the U.S. gas market is a disequilibrium system in which production and consumption are never in balance. During the months of winter heating, consumption greatly exceeds production. Withdrawals from storage provide the portion of supply that remains unmet by production. Once winter is over, production exceeds consumption. Additions to storage restore that portion of supply needed for the next winter heating season.
Gas traders compare the current year’s evolving inventory level with that of previous years to determine if storage will be adequate to meet winter demand. If the rate of inventory buildup is judged to be ahead of expected winter demand, the price of futures contracts decreases. If that rate is deemed questionable to meet winter demand, the price of those contracts increases. Producer response to price signals is typically delayed until a price trend emerges to justify increased or decreased drilling. The potential for over-shoot and under-shoot is great.
Comparative inventory is, therefore, the best measure of the disequilibrium in the seasonal supply chain. It effectively removes the seasonal effects of energy use and plant maintenance that sometimes confuse the interpretation of absolute inventory levels.
Figure 6 shows that the fall in comparative inventories since May 2016 has been significant compared to both the 5-year average and to 2015 inventory levels.
Despite falling comparative inventory, prices commonly decrease in the late summer based on probable inventory levels needed to meet winter consumption. Although that may be happening now, I believe that higher prices will prevail by the end of 2016.
A simplified cross-plot of comparative inventory and spot prices suggests a range of likely year-end prices between $3.00 to $3.75 with a most-likely case of of approximately $3.35 per mmBtu (Figure 7).
Shale Gas Company Performance Is Weak
What will happen if gas prices increase to approximately $3.35 per mmBtu in the next several months? Operators with access to capital will probably add rigs and increase production. That is the correct response to market price signals in a market that believes company claims that they are making money at current gas prices.
Approximately 150 new wells are being completed each month in the currently active shale gas plays namely, the Marcellus, Utica, Haynesville and Woodford plays (Figure 8).
Unfortunately, most companies cannot make a profit at current gas prices despite their public statements. Today’s wellhead prices in the Marcellus Shale play have increased to $1.34 per mmBtu and Utica prices averaged $1.44 in the second quarter of 2016. A few well-hedged companies may break even on costs in the best parts of the Marcellus and Utica core areas but most do not.
Even so, breaking even does not meet the standards of serious investors who need at least a 10-15% discounted return once the cost of capital, and project and commodity risk are considered. Most Haynesville and Woodford wells need at least $6.00 per mcfe to break even.
All leading companies in the Marcellus and Utica plays reported net losses for the second quarter of 2016 summarized in Table 2. Antero, Cabot, Gulfport and Rice apparently had better access to equity capital than the rest based on share offerings in the first half of 2016.
The debt loads and debt-to-cash flow ratios of these companies is alarming. The average for the companies shown in Figure 9 was 9.4 in the first half of 2016. The current bank-risk threshold for debt-to-cash flow is about 4:1.
Nor do the stock prices of most of these companies provide a good proxy for the substantial increase in Henry Hub spot prices of 75% since March 2016. Although the increase in stock prices for all companies exceeded 10%, only Rice and Consol out-performed commodity price and UNG (Exchange-traded natural gas fund) gains (Figure 10).
100 Years of Gas? Not At These Prices
Despite their financial weakness, I expect that a small number of producers will continue to find favor among yield-hungry investors. I doubt, however, that increased drilling by those companies and a few like them in the Woodford play will be able to reverse declining shale gas production and, therefore, U.S. gas production.
In the early 2000s, the U.S. was running out of natural gas. Canadian imports supplied 17% of U.S. consumption by late 2005. The shale gas revolution was a singular phenomenon that occurred initially because gas prices from 2000 through mid-2008 averaged more than $7 per mmBtu in real 2016 dollars.
In late 2002 and early 2003, a few wells were horizontally drilled and hydraulically fracturing in the Barnett Shale. Initial production rates were more than three times higher than Mitchell Energy’s vertical wells that had been drilled as an experiment in the previous decade. Devon Energy and other operators applied for permits to drill more than 180 additional horizontal wells by mid-2003 and the shale gas rush was on.
A few years later in 2005, Southwestern Energy began the exploration and development of the Fayetteville Shale in nearby Arkansas. The apparent early success of the Barnett and Fayetteville plays heightened the frenzy of mineral leasing as prices soared to over $10,000 per acre. By 2007, Chesapeake Energy Corporation emerged as the dominant player in shale gas with a position second only to Devon in the Barnett and the leading position in the emerging Haynesville Shale play in Louisiana and East Texas.
Initial production rates of more than 10 million cubic feet (mmcf) per day from Chesapeake’s first Haynesville wells lead to an unprecedented land grab reminiscent of gold rushes in the 19th and early 20th centuries. Plains Exploration and Production Company paid more than $30,000 per acre to form a joint venture with Chesapeake. Foreign oil and gas companies eagerly entered similar partnerships with the company in the Haynesville, Barnett and Marcellus plays while major oil companies like ExxonMobil and BP also entered the shale gas arena.
Range Resources tested the first horizontally drilled wells in the Marcellus Shale in Pennsylvania in 2005. Development in the Marcellus was somewhat slower than the other plays but it has now proven to be the most prolific among them.
The explosion of production resulted from the mass participation in the plays by thousands of companies. Gas prices collapsed beginning in July 2008 with the onset of The Financial Collapse. After that, easy-money policies kept the party going for a few more years.
Over-production pushed gas prices well below the marginal cost of the wells. Liquids-rich and later, tight oil plays then stole the spotlight from shale gas. Gas could not compete with oil for profit or investor capital and it was really gas associated with the newer tight oil plays that kept gas production strong.
Despite the flagging fortunes of the shale gas plays, the natural gas lobby concocted a story that said the United States had 100 years of natural gas supply. This was based largely on technically recoverable resource estimates by the Potential Gas Committee that had nothing to do with reserves or economics. By 2012, the idea of 100 years of gas found its way into President Obama’s State of the Union address.
The collapse of oil prices in 2014 was the turning point for U.S. gas supply. It does not seem likely that oil prices will break out of their current range boundaries of about $40 to $50 any time soon and so associated gas will continue to decline. Even adding 150 new wells per month in the 4 active shale gas plays has not arrested or even slowed the inexorable decline of shale gas production.
North American natural gas supply is largely a closed system. Even a weak economy cannot suppress the price of gas as supply becomes less secure. That is because gas use has been implicitly mandated by EPA regulations and its low price over the last 7 years has greatly limited the growth of renewable alternatives.
Those regulations and the foolish decision to allow increased exports were founded on the preposterous belief that U.S. gas supply was almost unlimited, that we had at least 100 years of gas. It was a classic case of thinking that the future would be just like the present and immediate past, and that gas production would continue to increase forever. A similar irrational belief underlaid the real estate bubble that ultimately led to the 2008 Financial Collapse.
People in the eastern U.S. are not really all that into gas drilling, fracking and pipelines. Environmental groups have learned that they can slow the permitting and construction of pipelines. This has kept wellhead prices low and development in check.
There never was 100 years of natural gas. The Barnett and Fayetteville plays that began a little more than a decade ago are dead at today’s prices. No horizontal wells have been drilled in either play since January of this year.
The Haynesville Shale was a great disappointment but has considerable volumes that can be developed commercially at $6 gas prices or higher. There are 35 rigs working in the Woodford play where liquids contribute to the value stream but unhedged producers need about $6 prices there also.
The Marcellus is the jewel in the shale gas crown and is currently providing almost 25% of U.S. total supply. Even the Marcellus, however, needs $4 gas prices for unhedged operators to break even. Although production has peaked, it will continue to provide meaningful supply into the next decade but not forever.
The Utica Shale is still in a relatively early stage of development but has the potential for commercial production at $4 to $5 gas prices in its core. That area is poorly defined at present but is smaller than the Marcellus core areas. Utica counties outside the core need $6 gas prices to break even.
The U.S. is not running out of gas yet. It will, however, take much higher prices to develop the remaining decade or so of supply. We have squandered the best production into a losing market and committed additional volumes to long-term foreign contracts that never made sense in the first place.
Declining production, greater consumption and increased exports have combined to make natural gas one of the best commodity values around. If somewhat higher prices cannot rescue supply then, even higher prices will be needed.
Remember the shale gale and Saudi America? The scale of those outlandish delusions has now dwindled to plays in a few counties in West Texas and southeastern New Mexico. Saudi Permian.
It’s a race to the bottom as investors double down on the tight oil companies that can still tell a growth story. Permian-weighted E&P companies are the temporary darlings of Wall Street as other tight oil plays have lost their luster.
A Silly Price Rally: Catch-22
We are in the middle of a truly silly price rally. Other rallies of 2015 and 2016 took place despite substantial production surpluses and too much inventory. Then, there was some hope that higher prices might result if over-production could be brought under control. Now, the world’s production and consumption are near balance but oil prices remain mired in the $40 to $50 per barrel range.
This current rally will end badly because there is something more fundamental keeping prices low. Despite repeated assurances from IEA and EIA that demand growth is strong, it is not strong enough to draw down outsized global inventories.
Hope for an OPEC production freeze at next month’s meeting in Algiers is the main factor driving this rally. The problem is that the world liquids market is as close to balance as it ever gets—over-supply has been less than 0.5 million barrels per day for the last two months (Figure 1). Oil prices were more than $100 per barrel at similar or greater production surpluses in 2013 and 2014.
In 2015, when the average production surplus was 2 million barrels per day, it was a different story. Over-production is not the problem now as it was then. If OPEC freezes production, it won’t make any difference.
Inventories exceed all historical levels. The world remains over-supplied because there is too much oil in inventory.
As long as oil prices are are range-bound between about $40 and $50 per barrel, it makes more sense to store oil than to sell it. The carrying cost of storage is less than what can be made by rolling futures contracts over each month. Inventories will stay high until prices break out of their current range but outsized inventories make that impossible. Catch-22.
Four Oil-Price Cycles in 2015 and 2016
There have been four oil-price cycles in 2015 and 2016–the first three each lasted approximately 6 months (Figure 2). Each new cycle began with high price volatility that fell as price peaked. We are currently in the upward arc of Cycle 4.
The oil-price volatility index has fallen to levels similar to when prices peaked during the last cycle suggesting that current WTI futures prices just above $48 per barrel may already be near the peak for this cycle. Prices may increase into the low-$50 per barrel range as they did in June before falling again.
The latest cycle began when NYMEX futures prices fell below $40 per barrel in early August. In the succeeding two weeks, they have climbed to more than $48 (Figure 3). A factor beyond a possible OPEC freeze is the weakened U.S. dollar because of expectations that the Federal Reserve Bank will not raise interest rates at least until December. The value of the dollar against other major currencies has fallen 3% over the last month (36% annualized). WTI futures prices have increased 22% since August 1.
A third factor driving the current price rally is long-term concern about supply because of under-investment in oil development projects and exploration since the oil-price collapse. Recent statements by the International Energy Agency that demand may outpace supply in the next few years underscored that anxiety.
Figure 3 shows that oil prices appear to be range-bound between about $40 support and $51 per barrel resistance levels. The upper boundary is largely controlled by record-breaking volumes of U.S. and world crude oil inventories and the fact that producers add rigs and production with each upward swing in oil prices.
The 200-day moving average of NYMEX futures prices suggests similar range boundaries of about $38 and $52 per barrel (Figure 4).
This market looks for any excuse to raise prices. Every price upswing is seen by some as the beginning of a return to oil prices above $70 per barrel. We seem to selectively forget that the staggering inventory levels of crude oil make this impossible until those volumes are drawn down substantially. Oops.
U.S. crude oil inventories fell 2.5 million barrels this week but have increased a net 1.6 million barrels over the last month during what is supposed to be de-stocking season (Figure 5).
Storage volumes are 57 million barrels more than at this time in 2015 and are 143 million barrels higher than the 5-year average. This is definitely not a basis for a sustainable oil-price rally. Until inventories are drawn down by at least another 125 million barrels, a recovery to somewhere approaching mid-cycle 2014 levels of about $80 per barrel is technically impossible.
The Permian Basin Dominates Rig Count Increases
Five new horizontal rigs were added last week to drill tight oil objectives in the Permian basin and 12 rigs were added the previous week. Only 1 rig was added in the Bakken play after losing 2 rigs a week ago. No rigs were added in the Eagle Ford after losing 1 rig the previous week. More capital is being spent in the Permian basin than in all the other plays put together.
Overall, 67 tight oil rigs have been added since early June. Forty eight of those are in the Permian basin, 5 in the Bakken and 6 in the Eagle Ford play (Figure 6). Four rigs were added in the Niobrara, 3 in the Granite Wash and 1 in Other. Rig count increases began as oil prices peaked above $50 per barrel in early June and continued through the slump toward $40 prices before the latest upward swing to $48 per barrel.
Weekly changes in the Permian basin rig count are the leading indicator of capital flows and expenditures. Permian rig count is more responsive to capital flows than the other tight oil plays because there is more money available for Permian-weighted companies.
In late July, I wrote, “When prices fall and oil-price volatility increases, the floodgates of capital open. Every genius-investor wants to buy low and sell high. Rig count rises with fresh capital, production increases and oil prices fall.”
In fact, the Permian basin accounts for 64% of the total U.S. horizontal tight oil rig count (Figure 7).
This is curious because Permian production from the Bone Spring, Wolfcamp and Trend-Spraberry horizontal plays represents only 21% of total tight oil production (Figure 8).
It is even more curious because Permian basin tight oil proven reserves rank 42nd in the world just behind Denmark and Trinidad and Tobago based on the latest EIA data (Figure 9).
Some will argue about potential and possible Permian resources and reserves preferring Pioneer CEO Scott Sheffield’s view of things to reality. I won’t debate them but the point is that Saudi Permian is a stretch based on any reality-based interpretation of existing data.
It’s A Stock Play, Not An Oil Play
Eleven companies now operate 3 or more rigs in the Permian basin (Figure 10). These represent a mix of independents and major oil companies. Concho operates the most rigs with 15 and Pioneer is second with 13. Energen, Anadarko, Chevron and Apache all operate 5 rigs or more. Companies that operate at least 3 rigs include Cimarex, Diamondback, Oxy, Parsley and Callon.
The stock performance of all oil companies correlates strongly with oil prices but many Permian basin-weighted stocks have significantly out-performed ETFs (exchange-traded funds) by 2-to-1 to as much as 4-to-1 since the current price rally began in early August (Figure 11).
Callon’s stock price has increased 34% since August 1, 2016. Parsley’s and Energen’s have increased 22%, Pioneer’s has risen 18% and EOG’s, 17%. These companies have all beaten the 16% increase in WTI futures prices over the same period and have substantially out-performed oil ETFs (Energy Select XLE and Vanguard Energy VDE) whose returns averaged only 8% in August.
Most of the Permian companies with strong stock performance also have sizable debt loads and high debt-to-cash from operations (EBITDA) ratios. The average debt-to-cash flow ratio is 5.4:1 and 4:1 is considered the current threshold for bank loan risk (Figure 12). Among the independent companies with high stock performance, only Diamondback and Energen have ratios less than 4:1. Parsley, Cimarex and Concho all exceed 7:1.
Another reason for the highly volatile stock prices of most Permian companies is in their stock valuations.On average, the ratio of current to mid-2014 stock valuations is double the ratio of first half 2014-first half 2016 NYMEX WTI oil prices (Figure 13).
Stock prices of shale companies with good positions in the Bakken and Eagle Ford have also increased but those companies have a harder growth story to tell. At $70 per barrel wellhead prices, average well density in the Permian horizontal plays is about 1 well per 860 acres. That is less than half of the 1 well per 382 acres per well in the Bakken and one-fifth of the 1 well per 172 acres per well in the Eagle Ford play (Table 1).
Among the high stock performers, both EOG and Pioneer also have positions in the Eagle Ford and EOG is also represented in the Bakken play.
A Race To The Bottom
The main cause of the collapse of global oil prices in 2014 was a production surplus. That continued to be the key factor throughout 2015. Now, over-production is still a concern but the market has been close to balance for the last 6 months.
For most of 2016, however, liquids consumption growth has declined. It increased with falling oil prices and peaked at the end of 2015 when monthly average oil prices were near $30 per barrel (Figure 14). As prices recovered into the $40 to $50 range, consumption growth dropped. The global economy is apparently too weak for prices in this range.
Growth occured only when oil prices were below disturbingly low thresholds. Declining consumption growth is the likely cause of persistent high inventory levels and range-bounded prices.
The dream of Saudi America has fallen on hard times since oil prices collapsed. Persistent and often misleading claims about technology, efficiency and lower cost have kept hope alive for true believers. The truth is that production costs are more than oil prices.* The present situation cannot be sustained without even more carnage in the oil industry.
Investors have identified the plays and companies that are in the best position to survive and they are in the Permian basin. As the field of attractive companies dwindles, more short-term investment is directed toward the perceived winners. These favored companies can go to the capital markets more or less at will with new stock or bond offerings and easily raise hundreds of millions to billions of dollars. This allows them to continue drilling and spending, and accounts for the upsurge in Permian rig counts at the beginning of every new price cycle.
Those who bought stock in Permian-weighted companies made a good profit this month.Those companies are attractive to investors not because of their underlying financial strength. It is because they satisfy the reach for yield that is no longer met by Treasury bonds or other conventional investments in a low-interest rate and low-growth economy.
Like the companies, the Permian plays are attractive mostly because they don’t lose as much money as the other tight oil plays and have a better growth story.They are the best of a bad lot. But they still lose money at oil prices less than $50 to $60 dollars per barrel at the wellhead. There is about a $5 differential between Permian wellhead and benchmark price so $55 to $65 per barrel WTI prices are needed for Permian tight oil plays to break even.
Permian basin tight oil production will peak around 1 million barrels per day and begin to decline in the mid-2020s based on our models. Those models assume a return to $75 to $80 oil prices in the next 3 to 5 years and that capital will be readily available to fund ongoing drilling. If either assumption is too optimistic, the plays will peak later but will not produce any more oil. The Permian basin has good, prolific plays but it is no Saudi Arabia.
The Bakken and the Eagle Ford were all the rage for investors until lower-for-longer oil prices were accepted as the new reality during the second half of 2015. Now, investors believe that the Permian basin is the only place with profitable plays at low oil prices. Eventually, they will tire of the Permian also and may be lured back to the Eagle Ford or Bakken by some new tall tale about technology or efficiency.
Investors will provide capital as long as the stock plays earn them the yield that they need. Companies will dress themselves and their plays up in order to compete for the capital offered. Meanwhile companies continue to produce about 3.5 million barrels per day of tight oil that loses money on each barrel.
With every new price rally, investors and companies think that this time oil prices will finally recover to a level where the companies can make money again. But with every price rally, rig counts and production increase, demand falters, inventory rises and prices fall back.
It is Einstein’s definition of insanity–doing the same thing over and over again and expecting a different result.
It is race to the bottom.
*I get many emails and data from readers with “real” examples from companies of wells that break even at oil prices less than $40 per barrel. These all require an average well EUR of 1 million boe or more.
Does anyone realize how very few wells in world history have produced 1 mmboe?
Most Permian horizontal wells produce at least as much water as oil. So, if you believe that every well will produce 1 mmboe, you must also believe that it will produce at least 1 mmb of water. Water disposal costs of $1 to $2 per barrel are seldom found in these break-even economics from the “real world.”
These examples rarely include the discounted cost of capital, production taxes or royalty payments. Nor do they include any operational risk so every mile-long lateral and multi-stage fracture stimulation goes flawlessly and there are never any unexpected costs.
Pioneer CEO Scott Sheffield made headlines last week when he claimed that his company’s Permian production costs “…can compete with anything that Saudi Arabia has.”
Is that a lie?
Pioneer’s Q2 2016 Earnings presentation shows that production costs for Permian basin horizontal wells are $2.25 per BOE (Figure 1).That cost cannot be verified because only company-wide production costs are included in the company’s 10-Q Quarterly Report.
The footnote in Figure 1 indicates that its stated production costs are untrue because they do not include all production costs. A lie is not a lie if you tell everyone that it is a lie.
By including the next line item “Production and ad-valorem taxes,” production costs become $4.13 instead of $2.25 per BOE. As Figure 1 shows, Pioneer’s overall production costs are $6.66 per BOE.
In fact, Pioneer’s total variable costs for the second quarter of 2016 were almost $18 per BOE (Table 1).This is the standard method to evaluate a company’s costs. It does not include considerable expenses for salt-water disposal because they are not mentioned in the company’s 10-Q.
Pioneer’s realized price for the first half of 2016 was $28.95 per BOE so the truth is that the company only has about $10 of margin before major capital expenditures of $7 million to drill and complete each well, much less pay royalties and income taxes!Break-even price for Pioneer’s average Trend Area-Spraberry well is about $52 per BOE. I’m sure the Saudis are scared to death about that.
Pioneer has “cherry-picked” the very best of their production and focused only on its production expenses thereby excluding 85% of its stated variable costs—to what end? Pioneer is a solid company that compares favorably to its competitors. After a rough first quarter for all companies, performance improved markedly in the second quarter and first half of 2016 (Figure 2).
The company outspent cash flow by 2-to-1, down from almost 5-to-1 in the first quarter. Debt-to-cash flow moved back within today’s bank-risk tolerance of less than 4-to-1 after exceeding 8-to-1 in the previous quarter. Why couldn’t Sheffield have pointed to this data as evidence that Pioneer is a strong performer among the shale players?
Sheffield is known for grandiose flights of fantasy. In 2013, he stated “The Spraberry Wolfcamp could possibly become the largest oil and gas discovery in the world,” comparing it to Ghawar, the world’s largest oil field. A year ago, Pioneer published a news release claiming Spraberry Wolfcamp “EURs averaging approximately 1 MMBOE, with IRRs averaging 50% to 60% at current strip commodity prices” that were around $45 per barrel. My work indicates an average EUR for those horizontal wells of approximately 300,000 BOE and financial results for Pioneer hardly reflect the returns stated in that release.
No credible oil and gas analyst believes those claims any more than recent statements that Pioneer’s well costs can compete with Saudi Arabia.
The shale gas and tight oil companies have developed a culture of exaggeration and misrepresentation. They have consistently tried to make the ludicrous case that a terrible reservoir and super-expensive technology can somehow out-perform much cheaper wells and better reservoirs in conventional plays.
It’s an unnecessary case to make because we’ve been out of those better, cheaper plays in the U.S. for decades. But, once you get started with embellishment, it leads to deception and then, it’s hard to remember what the truth is or even why you’re telling such unbelievable stories in the first place.
Investors play a role too. Many prefer a make-believe reality where America is great again, and they can dream of making crazy profits like in the good old days.
Seventy percent of Pioneer’s production is in the Permian basin (Table 2) and 80% of Permian production is from horizontal wells. So, 55% of Pioneer’s production is from the same subset of wells that Sheffield says can compete with Saudi Aramco.
If I were a Pioneer investor, I would ask Scott Sheffield at the next earnings call why he doesn’t just sell all of the company’s assets except horizontal wells in the Permian basin. Then we will find out if his comments are a lie or not.
The current oil-price rally is over.
U.S. rig counts have surged as oil prices sink. Capital is driving the oil markets and it enables bad behavior by producers. That is why oil prices will stay low.
The oil-price rally that began in February is over. Prices rose from $26 per barrel to $51 by early June and are now below $42 (Figure 1). If they fall through $40, the next likely support level is at $36 per barrel.
Capital Drives The Oil Market and Prices
Most people think that fundamentals–supply and demand–drive the oil market but capital drives the market and oil prices.
More than anything, rig count reflects capital flow. Many believe that price drives rig count but it is really capital flow that drives rig count and production and that affects oil prices.
When prices fall and oil-price volatility increases, the floodgates of capital open. Every genius-investor wants to buy low and sell high. Rig count rises with fresh capital, production increases and oil prices fall (Figure 2). The weekly change in tight oil horizontal rig count is the leading indicator of capital expenditures. Price trends roughly follow the inverse path.
When oil prices were around $100 per barrel in mid-2014, oil-price volatility was low. When prices fell below $90 per barrel in October 2014, oil-price volatility began to increase. When prices bottomed below $46 in January 2015, volatility peaked. Correctly believing that a price floor had been reached, investors poured capital into the markets and oil companies were flush with money to start drilling again. Prices rose to $60 per barrel by May 2015.
As drilling proceeded, oil-prices began to fall as market confidence in a price recovery faded. In July 2015, prices began to fall. As they fell to near $40 per barrel by late August, price volatility increased again. Investors saw another price floor and opened their wallets.
Prices rose 18% to more than $48 by early October but by then, confidence in a price recovery again faded with increased drilling and global economic concerns about Chinese growth and oil demand. Oil prices fell below $30 in late January 2016 and by mid-February, oil-price volatility reached its highest level since the Financial Collapse in November 2008.
Once again, investors saw a price floor and the floodgates of capital opened. Pioneer and Diamondback raised almost $1.5 billion in share offerings in January 2016, probably the darkest time for oil markets since 1998.
In the first half of 2016, more capital has flowed to E&P companies than during 2013, the previous record year when oil prices were more than $100 per barrel and the tight oil boom was in full bloom (Figure 3).
Rig Count Surges and Oil Prices Fall
During the current price rally, prices increased from $26 in mid-February to more than $51 per barrel by early June. Meanwhile, the rig count change rate has exploded (Figure 2). Predictably, oil prices have fallen below $42 per barrel as hopes for a price recovery fade once again. This repeating process qualifies under the standard definition of insanity namely, continuing to do the same thing that got you in trouble before.
66 land rigs and 47 tight oil horizontal rigs have been added since early June (Figures 4 and 5). Last week, prices were crashing but 18 rigs were added, the biggest increase in almost 2 years.
Those added rigs, however, resulted from decisions and a process that began weeks or even months ago. After a company decides to add a rig, negotiations follow. More time passes between signing a contract and a rig showing up on location. Empirically, there is about a 5-week lag between changes in price trends and a response in rig count (Figure 5).
Who Are Those Guys?
Which companies are adding rigs and do their financial results support more drilling at these oil prices?
About 60% of rigs added in the tight oil plays during the last few months are in the Permian basin where there are currently 145 rigs operating (Figure 6). The rest of the new drilling is fairly evenly spread among the Bakken, Eagle Ford, Niobrara, Mississippi Lime and Granite Wash plays.
The most active operators in the 3 most-productive plays–the Permian, Bakken and Eagle Ford–are shown in the table below.
In the Permian basin, Concho Oil & Gas currently operates 15 rigs, Pioneer Natural Resources operates 12 rigs, and Energen operates 8. Apache, Chevron and XTO each operate 6 rigs, and Anadarko and Endeavor each operate 5. Cimarex, Diamondback, EOG and Parsley all operate 4 rigs.
The most active operator in the Eagle Ford play is EOG with 5 rigs. EOG is followed by Chesapeake and Marathon each with 3 rigs. In the Bakken, Continental Resources is the leading operator with 5 rigs. Hess operates 4 rigs, Whiting operates 3 and Oasis, 2 rigs.
So how are these operators doing financially?
Terribly, despite preposterous stories of technology gains, costs approaching zero, and single-well EURs of 1 million barrels of oil equivalent.
Figure 7 shows the main rig operators in the Permian, Bakken and Eagle Ford plays. These companies spent an average of 4 times as much as they earned in the first quarter of 2016. And it’s been going on for years. Imagine doing that yourself.
Among Permian operators, Parsley spent more than 10 times cash flow and Energen, more than 6. Pioneer and Chevron spent 5 times more than they earned. Anadarko had negative cash from operations meaning that it didn’t even earn enough to pay for well operations.
EOG leads the drilling in the Eagle Ford play and only spends twice what it earns–among the best of a bad lot. Marathon, on the other hand, outspends earnings by more than 6-to-1 and ConocoPhillips is not much better at more than 4-to-1. Like Anadarko, Chesapeake has negative cash from operations and, therefore, does not appear in Figure 4.
In the Bakken play, Hess cannot even pay for well operations from its cash flow yet operates 5 rigs. Continental Resources leads Bakken drilling and has a respectable capex-to-cash flow ratio only spending $1.30 for every dollar it earns. Whiting outspends cash flow by almost 6-to-1 and Oasis has negative cash from operations.
The debt picture is equally grim.
It would take top tight oil rig operators an average of 10 years to pay off debt if all cash earned from oil and gas sales were exclusively for that purpose based on first quarter 2016 financial data–in other words, no drilling, no salaries, no nothing except debt payments (Figure 8). That’s way above standard tolerance for this critical measure of bank risk which is now about 4:1 but before 2012, it was closer to 2:1.
In the Permian basin, most operators have a debt-to-cash flow ratio of about 6:1 or 7:1. Chevron and Pioneer are much higher at 9.3:1 and 8.2:1, respectively. It would take Apache 8 years to pay off its debt and 7.4 years for Concho. Cimarex is somewhat lower at 4.4 years and not surprisingly XTO (ExxonMobil) is at 2.2 years.
In the Eagle Ford play, EOG has more debt than it could pay off in 6 years and Marathon has a stunning debt-to-cash flow ratio of almost 25! Conoco is not far behind at almost 18-to-one.
In the Bakken play, Continental would need 6 years to pay off its debt but Whiting leads all major tight oil players with a debt-to-cash flow ratio of 29-to-1!
Meanwhile, these companies tell investors tall tales of fantastic rates of return even at low oil prices that clearly do not pass even a superficial fact check using Google Finance or Yahoo Finance. Why would any rational investor give money to most of these companies?
Short-Term Price Spikes In a Few Years
There is an important difference between oil supply and reserves. Supply is available on demand and reserves require long-term, capital-intensive investment to develop.
Tight oil is really a supply project because reserves can become supply one well at a time. Tight oil development can be turned on or off at will as prices rise and fall because at-risk capital is incremental–basically the cost of the number of wells in a rig contract.
While tight oil supply has overwhelmed markets in recent years, remaining reserves are relatively small–a few tens of billions of barrels–compared with true reserve projects like conventional and deep-water oil or oil sands that involve hundreds of billions of barrels. True reserve projects have been largely deferred because of uncertainty about how long low prices will continue.
The insane cycling of oil prices will continue as long as tight oil production keeps the market in a supply surplus. At some time in the next few years, the market will go into deficit as deferred investment in reserve projects comes back to haunt us. Then, inventories will finally be drawn down to 5-year average levels and prices will probably spike.
If that happens, it is likely that prices may go well above $90 per barrel. This may last for a year or somewhat longer based on what occurred in 1979-1981 (27 months), 2007-2008 (13 months) and 2010-2014 (48 months) when prices were more than $90 per barrel. Then, demand destruction will set in and prices will fall. Because the global economy is so much weaker now than during those past periods of high oil prices, I suspect that it will only take a few months to a year before prices fall hard.
Lower Prices Ahead
The current oil-price rally led many to believe that a full price recovery was underway. But inventories have been too large for that to happen short of epic supply interruptions. Current OECD inventories stand at 3.1 billion barrels and untold millions of barrels in places like China and Russia that do not report storage volumes.
In mid-April, I cautioned:
Two previous price rallies ended badly because they had little basis in market-balance fundamentals. The current rally will probably fail for the same reason.
You don’t have to be a genius to figure this stuff out. Attention to data and recent history is all it takes.
So, why do producers mis-read price signals so badly and act in ways that lower prices and hurt their own businesses?
They can’t help themselves. Give them money and they will spend it. That’s what E&P companies do.
The cost of credit dictates the precedence of cash flow over common sense even as more debt and the growing burden of debt service dictate even more production to meet new cash flow demands.
It is a vicious cycle that cannot be broken unless the capital stays away. That has not happened because other options for similar yields at acceptable levels of risk cannot be found. And so it continues.
The longer companies continue to produce at a loss and make absurd claims that they are making money at low prices, the more that investors believe them. The market graciously obliges by shorting oil prices.
I see no graceful way out of all of this.
Two years into the global oil-price collapse, it seems unlikely that prices will return to sustained levels above $70 per barrel any time soon or perhaps, ever. That is because the global economy is exhausted.
The current oil-price rally is over as I predicted several months ago and prices are heading toward $40 per barrel.
Oil has been re-valued to affordable levels based on the real value of money. The market now accepts the erroneous producer claims of profitability below the cost of production and has adjusted expectations accordingly. Be careful of what you ask for.
Meanwhile, a global uprising is unfolding.
The U.K. vote to exit the European Union is part of it. So is the Trump presidential candidacy in the U.S. and the re-run of the presidential election in Austria. Radical Islam and the Arab Spring were precursors. People want to throw out the elites who led the world into such a mess while assuring them that everything was fine.
The uprising seems to be about immigration and borders but it’s really about hard times in a failing global economy. Debt and the cost of energy are the pillars that underlie that failure and the resulting discontent. Immigrants and infidels are scapegoats invented by demagogues.
Energy Is The Economy
Energy is the economy. Energy resources are the reserve account behind currency. The economy can grow as long as there is surplus affordable energy in that account. The economy stops growing when the cost of energy production becomes unaffordable. It is irrelevant that oil companies can make a profit at unaffordable prices.
The oil-price collapse that began in July 2014 followed the longest period of unaffordable oil prices in history. Monthly oil prices (in 2016 dollars) were above $90 per barrel for 48 months from November 2010 through September 2014 (Figure 1).
That was more than 3.5 times longer than the period from September 2007 through September 2008 just before the Financial Collapse. It was almost twice as long as the period from September 1979 through November 1981 that preceded the longest oil-price collapse in history.
There is nothing magic about $90 per barrel but major economic dislocations have occurred following periods above that level. Few economists or world leaders seem to understand this or include the cost of energy in their models and policies.
There is a clear correlation between oil price and U.S. GDP (Gross Domestic Product) when both are normalized in real current dollar values (Figure 2). Periods of low or falling oil prices correspond to periods of increasing GDP and periods of high or rising prices coincide with periods of flat GDP.
Economic growth is complex and some will object to this correlation. Fine. But energy is also complex. Most people think about it as an independent topic or area of our lives. Like business, politics, economics, education, agriculture, and manufacturing, there is energy. This is understandable but wrong.
Energy underlies and connects everything. We need energy to make things, transport and sell things and to transport ourselves so that we can work and spend. We need it to run our computers, our homes and our businesses. It takes energy to heat, cool, cook and communicate. In fact, it is impossible to think of anything in our lives that does not rely on energy.
When energy costs are low, the costs of doing business are correspondingly low. When energy prices are high, it is difficult to make a profit because the underlying costs of manufacture and distribution are high. This is particularly true in a global economy that requires substantial transport of raw materials, goods and services.
The global economy expanded in the mid-1980s through 1990s when oil prices averaged $33 per barrel. Then, oil prices nearly doubled to an average of $68 per barrel from 1998 to 2008, and subsequently increased after 2008 to 2.5 times more than in the 1990s. When oil prices exceed $90 per barrel, the global economy is no longer profitable.
America’s Golden Age
The United States experienced a golden age of economic growth and prosperity during the 25 years following World War II. This period forms the basis for U.S. and indeed global expectations that growth is the norm and that recessions and slow growth are aberrations that result from mis-management of the economy. This is the America that today’s populists want to return to.
The Golden Age, however, was a singular phenomenon that is unlikely to recur. After 1945, the economies and militaries of Europe and Japan were in ruins. The U.S. was the only major power that survived the war intact. Having no competition is a huge competitive advantage.
The U.S. was the first country to fully convert to petroleum, another competitive advantage. A barrel of oil contains about the same amount of energy as a human would expend in calories in 11 years of manual labor. Crude oil contains more than twice as much energy as coal and two-and-a-half times more than wood. And it’s a liquid that can be moved easily around the world and put in vehicles for transport.
In 1950, the U.S. produced 52% of the crude oil in the world and was largely self-sufficient. Texas was the largest U.S. producing state and the Texas Railroad Commission (TXRRC) controlled the world price of oil through a system of allowable production that also ensured spare capacity.
Oil was cheap, the U.S. controlled its price and had a positive balance of payments.
Oil Shocks of the 1970s and 1980s
That began to change toward the end of the 1960s. A re-built Europe and Japan rose to challenge American commercial dominance and the costs of fighting the spread of communism–especially in Vietnam–weakened the American economy. In 1970, the U.S. economy went into recession and President Nixon took drastic steps including the end of backing the dollar with gold reserves. The rest of the countries that were part of the Bretton Woods Agreement did the same resulting in the largest global currency devaluation in history.
In November 1970, U.S. oil production peaked and began to decline. In March 1972 the TXRRC abandoned allowable rates. The United States no longer had any spare capacity. OPEC had long objected that oil prices were held artificially low by the U.S. Now OPEC had the clout to do something about it.
In October 1973, OPEC declared an oil embargo against Israel’s allies including the U.S. during the Yom Kippur War. This was really was just an excuse to adjust oil prices to the devalued Western currencies following the end of the Bretton Woods Agreement.
The price of oil more than doubled by the end of January 1974 from $22 to $52 per barrel (2016 dollars). When the Arab-Israeli conflict ended a few months later, oil prices did not fall.
Real oil prices more than doubled again in 1980 to $117 when Iran and Iraq began a war that took more than 6 million barrels off the market by 1981. The effect of these price hikes on the world economy was devastating. World demand for oil decreased by almost 10 million barrels per day and did not recover to 1979 levels until 1994 (Figure 3). Real prices did not recover to $40 until 2004 except for a brief excursion during the First Persian Gulf War in 1990.
The Miracle of Reagan Economics: Low Oil Price
Ronald Reagan is remembered as a great U.S. president because the economy improved and the Soviet Union fell during his administration. Both of these phenomena were because of low oil prices.
After U.S. oil production peaked, imports increased 5-fold from 1.3 to 6.6 mmbpd from 1970 to 1977 (Figure 4).
When oil prices rose to nearly $110 per barrel during the Iran-Iraq War, the U.S. went into recession from mid-1981 through 1982. Oil consumption fell more than 3 million barrels per day. Production from Prudhoe Bay began in 1977 and somewhat dampened the overseas outflow of capital but it did not help consumers with price.
Federal Reserve Chairman Paul Volker raised interest rates to more than 16% by 1981 to bring the inflation caused by higher oil prices under control (Figure 5). This worsened the economic hardship for Americans in the short term but also became the foundation of the Reagan economic revival.
Much of the developing world had survived the oil shocks of the 1970s by borrowing from U.S. commercial banks. Higher U.S. interest rates put those countries into recession and that helped keep oil demand and prices low. By 1985, oil prices had fallen below $40 per barrel and would not rise above that level again until 2005.
Volker found an opportunity in the demand destruction from oil shocks. By raising U.S. interest rates, he managed to roll back oil prices almost to levels before the 1973 oil embargo and created a great economic boon for the U.S.
“He [Volker] used the strategic price that America continued to control—namely, world interest rate—as a weapon against the price of the strategic commodity that America no longer controlled, which was oil.”
—James Kenneth Galbraith*
High interest rates attracted investment. Along with low oil prices, a strong dollar, tax cuts and increased military spending, Volker and Reagan restored growth to the U.S. economy. By 1991, the Soviet Union collapsed under the strain low oil prices, debt, and military spending.
Things Fall Apart; The Center Cannot Hold
Treasury bonds became the effective reserve asset of the world. The U.S. put economic growth on a credit card that it never planned to pay off. Public debt increased almost 6-fold from the beginning of Reagan’s administration ($1 trillion) in 1981 to the end of Clinton’s ($6 trillion) in 2000 (Figure 5). By the end of Bush’s presidency in 2008, debt had reached $10 trillion. It is now more than $18 trillion.
The 1990s were the longest period of economic growth in American history. There are, of course, limits to growth based on debt but the new economy seemed to be working as long as oil prices stayed low. Then, Prudhoe Bay peaked in 1985. Total U.S. production declined, and imports increased sharply as the economy improved (Figure 4). Similarly, the world economy slowly recovered after 1985 with lower oil prices.
Consumer credit expanded under President Clinton through mortgage debt. Manufacturing had been progressively outsourced to Latin American and Asia, and the evolving service economy was underwritten by consumer debt that increased 7-fold from less than $0.5 trillion in 1981 to $2.6 trillion in 2008 (Figure 5).
The “dot.com” market collapse in 2000 and the September 11, 2001 terror attacks pushed the U.S. economy into recession and the Federal Reserve reduced interest rates below 2%, the lowest levels in U.S. history to date. Mortgage financing boomed.
The 1993 repeal of The Glass-Steagall Act allowed banks to package mortgage debt into complex, high-risk securities (CDOs or collateralized debt obligations). In what can only be described as out-of-control speculative greed and institutional fraud, CDOs, synthetic CDOs that bet on the outcome of CDO bets, and the credit default swaps that bet against both propelled the economy to levels of leverage and instability not seen since the 1920s.
“This was the new new world order: better living through financialization.”
–James Kenneth Galbraith**
From 2004 through 2008, world liquids production reached a plateau around 86 million barrels per day (Figure 5). Increased demand from China and other developing economies pushed oil prices higher as traders and investors worried that Peak Oil had perhaps arrived.
Oil prices soared to more than $140 per barrel and interest rates rose above 5%. The adjustable interest rates that underlaid much sub-prime debt also rose. Mortgage holders began to default and world financial markets collapsed in 2008.
The Second Coming
Debt and higher oil prices had spoiled the party. The problem was addressed with more debt and higher oil prices.
The Federal Reserve Bank brought interest rates to almost zero, created money and bought Treasury bonds while the government bailed out the banks and auto industry. OPEC cut production by 2.6 million barrels from December 2008 to March 2009 and oil prices recovered from $43 to $65 by May, and were more than $80 by year-end propelled by a weak dollar and easy credit.
Tight oil, deep water and oil sands projects that needed sustained high oil prices took off. Unconventional production in the U.S. and Canada increased 5 million barrels per day between January 2010 and October 2015 (Figure 7).
Tight oil used the same horizontal drilling and hydraulic fracturing technology that had been pioneered in earlier shale gas plays. The technology was expensive but once oil price topped $90 per barrel in late 2010 and stayed high for the next 4 years, the plays were deemed successful by producers and credit markets.
U.S. tight oil and deep-water production resulted in a second coming of sorts with monthly crude oil output reaching 9.69 million barrels per day in April 2015. That was 350,000 bopd less than the 1970 peak of 10.04 million bopd.
The difference of course was cost. In 1970, the market price of a barrel of oil in 2016 dollars was $20 per barrel versus $100 from 2011 to 2014, and $55 per barrel in 2015.
And this is precisely the problem with the almost universally held belief that technology will make all things possible, including making a finite resource like oil infinite. Technology has a cost that its evangelists forget to mention.
The reality is that technology allows us to extract tight oil from non-reservoir rock at almost 3 times the cost of high-quality reservoirs in the past. The truth is that we have no high-quality reservoirs left with sufficient reserves to move the needle on the high global appetite for oil. The consequence is that to keep consuming and producing as we always have will inevitably cost a lot more money. This is basic thermodynamics and not a pessimistic opinion about technology.
Nevertheless, in a zero-interest rate world, there was great enthusiasm for yields greater than conventional investments like U.S. Treasury bonds and savings accounts that continue to pay less than 2%. Bank and mezzanine debt, high-yield corporate (“junk”) bonds and share offerings promised yields in the 6 to 10% range. As long as prices were high and the plays were marginally profitable, risks were downplayed and capital was almost unlimited. Two years into the oil-price collapse, capital is more limited because banks and investors have been burned.
Producers continue the mantra that costs keep going down and well performance keeps getting better. Those with some history and perspective, however, know and remember that they always say that but the balance sheets never reflect the claims.
In 1996, the late Aubrey McClendon made the following statement about the Louisiana Austin Chalk play:
“Today, because of improvements in horizontal drilling technology, you’ve got a play that could be the largest onshore play in the country, not only in size of potential reserves but also in a real extent.”
That play was a total failure for McClendon’s Chesapeake Energy Corporation and today Chesapeake is on the verge of bankruptcy for the second time.
People want to believe that things keep getting better and that they won’t have to change their behavior—even if these beliefs defy common sense and the laws of nature.
Slouching Toward Bethlehem
The oil-price collapse that began in July 2014 was technically about over-production. A surplus of unconventional oil from the United States and Canada, and a hiatus in geopolitical outages upset the world market balance and pushed prices lower.
Some have tried to emphasize the role that demand played. But there is simply no comparison to the 10 mmbpd demand destruction that occurred between 1979 and 1983 nor is this anything like the 2.6 mmbpd demand decline in 2008-2009.
This price collapse is simply different than the others. It more fundamental. The economy has been pushed beyond its limits.
Post-Financial Collapse monetary policies, the cumulative cost of nearly four decades of debt-financed growth, and the return of higher oil prices have exhausted the economy. Most debt is non-productive, interest rates cannot be increased, and 2016’s low oil prices are still one-third higher than in the 1990s (in 2016 dollars).
Producers and oil-field service companies are on life support. One-third of U.S. oil companies are in default. Yet some analysts who have no experience working in the oil industry proclaim break-even prices below $40 per barrel and breathlessly predict that the business will come roaring back when prices exceed $50. Producers don’t help with outrageous claims of profitability at or below current oil prices that exclude costs and are not generally applicable to their portfolios.
As a result, the public and many policy makers believe that tight oil is a triumph of American ingenuity and that energy will be cheap and abundant going forward. The EIA forecasts that U.S. crude oil production will exceed the 1970 annual peak of 9.6 mmbpd by 2027 and that tight oil will account for almost 6 million barrels per day. Although I have great respect for EIA, these forecasts reflect a magical optimism based on what is technically possible rather than what is economically feasible.
Renewable energy will be increasingly part of the landscape but its enthusiasts are also magical thinkers.
In 2015, renewables accounted for only 3% of U.S. primary energy consumption. No matter the costs nor determination to convert from fossil to renewable energy, a transition of this magnitude is unlikely in less than decades.
Solar PV and wind provide much lower net energy than fossil fuels and have limited application for transport–the primary use of energy– without lengthy and costly equipment replacement. The daunting investment cost becomes critically problematic in a deteriorating economy. Although proponents of renewable energy point to falling costs, more than half of all solar panels used in the U.S. are from China where cheap manufacturing is financed by unsustainable debt.
It is telling that energy and its cost can hardly be found among the endless discussions about the economy and its failure to grow. Technology optimists have disparaged the existence of an energy problem since at least the 1950s. Neither unconventional oil nor renewable energy offer satisfactory, reasonably priced, timely solutions to the dilemma.
As political leaders and economic experts debate peripheral issues, the public understands that there is something horribly wrong in the world. It is increasingly difficult for most people to get by in a failing global economy. That is why there are political upheavals going on in Britain, the United States and elsewhere.
The oil industry is damaged and higher prices won’t fix it because the economy cannot bear them. It is unlikely that sustained prices will reach $70 in the next few years and possibly, ever.
The British exit from the European Union adds another element of risk for investors. Lack of investment will inevitably lead to lower production, supply deficits and price spikes. These will further damage the economy.
The future for oil prices and the global economy is frightening. I don’t know what beast slouches toward Bethlehem but I am willing to bet that it does not include growth. The best path forward is to face the beast. Acknowledge the problem, stop looking for improbable solutions that allow us live like energy is still cheap, and find ways to live better with less.
*J.K. Galbraith, 2014, The End of Normal, p.54. Much of the economic interpretation in this post is based on Galbraith’s work.
**J.K. Galbraith, 2014, The End of Normal, p.57.