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.
Did you hear about the largest U.S. oil and gas field that’s in the Permian basin of west Texas?
That’s the one that’s not a field because it hasn’t been discovered yet. That’s the one whose 20 billion barrels are an estimate by the U.S. Geological Survey. That’s the one whose 20 billion barrels would lose $500 billion at today’s oil prices.
Wait a minute. What about the headlines?
Deutsche Welle: Largest US oil and gas discovery made – USGS
Read the source–the U.S. Geological Survey. The USGS did an assessment of the undiscovered, technically recoverable resources of the Wolfcamp shale in the Permian basin.
“Undiscovered” means what it says–it has not been discovered. It’s an estimate, an educated guess. “Technically recoverable resources” means the oil that could be produced if cost didn’t matter.
Where Did $900 Billion Come From?
Where did the $900 billion value come from? Multiply 20 billion barrels times $45 per barrel and you get $900 billion. In other words, if the oil magically leaped out of the ground without the cost of drilling and completing wells; if there were no operating costs to produce it; if there were no taxes and no royalties.
Sweet. Jeb Clampett shootin’ at some food.
In the real world, an average Wolfcamp well costs $7 million to drill and complete (Table 1 from my June 2016 post on the Permian basin plays). Average operating costs are about $12 per barrel. Severance taxes are almost 5% and the average net revenue per barrel after royalties is only 75%.
The obvious question that reporters apparently failed to ask is, What is all of this going to cost?
The USGS document “Fact Sheet 2016–3092” that summarizes the Wolfcamp study includes a table that allowed me to calculate the number of wells required to produce the estimated 20 billion barrels of oil.
For each subdivision of the Wolfcamp play or “AU” (Assessment Unit), the USGS provided a calculated mean number of potentially productive acres and the average drainage area of wells. By dividing the two, I was able to determine the number of wells (shown in yellow) for each Assessment Unit in Table 2.
According to the USGS’ input data, it would take 196,253 wells to produce the 20 billion barrels if it exists. At $7 million per well, that would cost almost $1.4 trillion in drilling and completion costs alone.
It would cost more than $1.4 trillion to generate $900 billion in revenue resulting in a net loss of $500 billion at $45 oil prices excluding all operating expenses, taxes and royalties–and no discounting.
That’s a discovery that no one can afford to make.
World oil production is in balance and U.S. marketed natural gas output fell for the first time since 2005.
The EIA (U.S. Energy Information Administration) published its Short Term Energy Outlook (STEO) today. Here are the highlights.
World oil (liquids) output for September was 96.47 mmbpd (million barrels per day) and consumption was 96.39 mmbpd. That resulted in a slight surplus of 80,000 bpd, about as close to balance as it gets (Figure 1). That’s bad news considering that the Brent price of $52 per barrel acts like there are a few million bpd of surplus. So much for the global economy.
EIA forecasts an average production WTI price of $50/barrel in 2017 with Brent $1/barrel higher.
The long decline in U.S. crude oil production appears to be over. September output increased 60,000 bopd (Figure 2).
Natural gas marketed production fell from 3.2 Bcf/d (billion cubic feet of gas per day) in 2016 but EIA expects it will magically gain 1 Bcf/d before the year is over (I doubt that).
Natural gas production continues its decline and total supply is projected to go into deficit in December 2016 (Figure 3).
This is the first annual decline in gas production since 2005. But never fear–EIA projects a 3.7 Bcf/d increase in 2017.
I’m not sure where that will come from given that their gas forecast is an average price of $3.07 for 2017 and the best shale gas areas need $4 while the other plays need more like $6/mmBtu.
I guess that hedges and awesome increases in productivity explain the expected production rally.
EIA forecasts gas prices to average $3.04 for fourth quarter. Too bad the price is $3.31/mmBtu today!
This is a joint post with Matt Mushalik, a retired civil engineer and regional planner based in Sydney, Australia, and may be seen also on his website Crude Oil Peak.
U.S. crude oil storage is filling up with unaccounted-for oil. There is a lot more oil in storage than the amount that can be accounted for by domestic production and imports.
That’s a big problem since oil prices move up or down based on the U.S. crude oil storage report. Oil stocks in inventory represent surplus supply. Increasing or decreasing inventory levels generally push prices lower or higher because they indicate trends toward longer term over-supply or under-supply.
Why Inventories Matter
Inventory levels have reached record highs since the oil-price collapse in 2014. This surplus supply is a major factor keeping oil prices low.
Current inventories are 45 million barrels higher than 2015 levels, which were more than 100 million barrels higher than the average from 2010 through 2014 (Figure 1). Until the present surplus is reduced by almost 150 million barrels down to the 2010-2014 average, there is little technical possibility of a sustained oil-price recovery.
U.S. inventories are critical because stock levels are published every week by the U.S. EIA (Energy Information Administration). The IEA (International Energy Agency) publishes OECD inventories but that data is only published monthly and it measures liquids but not crude oil. It also largely parallels U.S. stock levels that account for almost half of its volume. Inventories for the rest of the world are more speculative.
Understanding U.S. Stock Levels
Understanding U.S. stock levels should be straight-forward. Every Wednesday, EIA publishes the Weekly Petroleum Status Report which includes a table similar to Figure 2.
The calculation to determine the expected weekly stock change is fairly simple:
Stock Change = Domestic Production + Net Imports – Crude Oil Input to Refineries
Domestic production and net imports account for crude oil supply, and refinery inputs account for the volume of oil that is refined into petroleum products. If there is a surplus, it should show up as an addition to inventory and a deficit, as a withdrawal from inventory.
But that’s not how it works because EIA uses an adjustment in order to balance the books (Table 1).
The logic is that estimated stock levels in tank farms and underground storage are relatively dependable and that any imbalance must be from less reliable production, net import or refinery intake data.
There is nothing wrong with adjustment factors if they are small in comparison to what is to be balanced. In the Table 1 example from September 2016, however, the adjustment is 60% of the stock change–a bit too much.
A one-off perhaps? No, it’s a permanent problem that has gotten worse during the last several years.
Figure 3 shows that crude oil supply and refinery intake of oil vary considerably on a weekly basis. The balance is cumulatively negative over time beginning with a zero balance in January 1983. That suggests that crude oil stocks should be falling over time but instead, they have been rising.
The vertical bars show the weekly crude supply from production and net imports either exceeding the refinery input requirements (positive, green) or not reaching these requirements (negative, red). The solid red line is the cumulative.
Between 1991 and 2002, the deficit increased to a whopping 1.3 billion barrels.
Looking at only recent history, an additional gap of nearly 200 million barrels developed as refinery intake exceeded crude oil supply for most of 2010 through 2014 (Figure 4).
Adjustments were introduced in late 2001 so let’s look at the period starting January 2002 (Figure 5).
There are both upward (blue) and downward (red) adjustments. Upward adjustments resulted in a 420 million barrel stock increase over the period January 2002 through September 2016.
All together now
Expected or implied stock changes calculated from weekly crude oil balance indicate falling inventories from May 2009 through the present. Yet, EIA makes adjustments to that balance in order to match observed inventory levels. Rising inventories result after those adjustments are added to the physical balance or implied stock changes (Figure 6).
The green area represents the physical balance (crude production plus net crude imports minus crude refinery intake). The gray area shows the unaccounted-for (adjusted) stocks.
The adjustment for unaccounted-for oil averaged about 15% from 2002 through 2010. In 2016, almost 80% of reported stocks are from unaccounted-for oil.
When You Have Eliminated The Impossible
There is no obvious solution for the mystery of unaccounted-for oil in U.S. inventories. Possible explanations, however, include:
- Crude field production is underestimated
- Net crude oil imports are underestimated
- Refinery inputs are over-reported
- Crude oil stocks are over-reported
or any combination of those possibilities.
Production, imports and refinery inputs are taxable transactions. It is likely that reporting errors are largely self-correcting over time because of the financial incentive for government to collect its due.
State regulatory agencies are the source of production data. Their principal objective is to assess production taxes. It is unlikely that states would consistently under-estimate production and forego substantial tax revenue.
Also, producers must state crude oil production in their SEC (U.S. Securities and Exchange Commission) filings and pay federal income tax on revenues from oil sales. It seems improbable that the SEC and U.S. Treasury would consistently accept under-reported production and associated lower tax payments.
Crude oil imports are subject to both tariffs and excise taxes so it seems unlikely that the U.S. government would consistently fail to identify under-payment of those revenues.
Similarly, taxes are involved when refiners buy crude oil and sell refined products. It seems improbable that they would over-state those transactions and consistently over-pay associated taxes.
The principal components of supply balance—production, imports and refinery intake—are shown in Figure 7. In a general way, increased production and decreased imports tend to cancel each other out. Refinery intake has increased since about 2010.
Those trends determine the physical balance or implied stocks. The inescapable conclusion is that implied stocks (in light blue) are substantially less than reported stocks (in gray).
Adjustments for unaccounted-for oil are unreasonable and out of proportion to the underlying factors that determine crude oil stock levels.
It would be speculation to blame anyone for this apparent statistical disaster. Nevertheless, there is a problem that has major implications for oil price and the reliability of reported data.
In several of his Sherlock Holmes mystery stories, Arthur Conan-Doyle wrote, “When you have eliminated the impossible, whatever remains, however improbable, must be the truth.”
We have not eliminated any impossible explanations. We have, however, eliminated the three most improbable explanations for unaccounted-for oil.
The truth—however improbable—is that inventories are probably much lower than what is reported.
Some readers noted that EIA Weekly Petroleum Status Report (PSW) data that we used in our evaluation includes estimates of production, net imports and refinery inputs. They questioned whether EIA monthly Supply and Deposition data might resolve the disparity between implied and reported stocks described in this post.
Figure 8 shows the monthly averaged data from the PSW and implied stocks calculated from monthly Supply and Disposition data (the red line). The difference between implied and reported stocks before 2010 is less than in our original evaluation. The difference from 2010 through 2012 is approximately the same, and for 2013 through the present, the differences are actually greater.
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.