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.
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?
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.
Rig count matters. Saying that it doesn’t is like a realtor saying that location doesn’t matter.
Rigs Don’t Produce Oil
The holiest mystery of shale plays is that so much production is possible with ever-fewer rigs.
But if we look at the number of producing wells, the mystery evaporates. That’s because rigs don’t produce oil and gas. Wells do.
Horizontal wells in a few tight oil plays tell most of the story for U.S. production. Figure 1 shows the rig count and number of producing wells for the Bakken, Eagle Ford, Permian, Niobrara, Mississippi Lime and Granite Wash plays.
Although rig counts decreased dramatically beginning in late 2014, the number of producing wells continued to increase until very recently. This may be a technical triumph for the drilling industry but it is no cause for oil producers to celebrate.
Average well costs are approximately $6 million so, despite falling rig count, the tab for new producing wells was about $3.9 billion per month in 2015. Add to that the cost of wells waiting on completion and other non-capital costs of doing business.
Many analysts and producers want us to believe that producing tight oil has become almost free thanks to awesome advances in efficiency and technology.
A rough rule of thumb is to multiply the monthly change in tight oil horizontal rig count by $6 million to approximate how much money is spent for new producing wells. There were about 2,400 more producing wells in 2015 than a year earlier in the Eagle Ford ($6 million per well) and 2,600 more in the Permian basin plays ($6.5 million per well). That works out to about $14 billion and $17 billion, respectively. For the Bakken where wells are about $8 million apiece, the cost for 2015 was $13 billion.
$45 billion for new producing wells in the 3 main tight oil plays in 2015—almost free.
Rig Count Matters
Rig counts are sensitive to price changes and generally excellent indicators of future oil production.The 4-week aggregate of weekly rig count changes accurately and quickly reflects changes in WTI price (Figure 2).
Oil prices began to fall in October 2014 and reached an initial bottom in January 2015. Monthly rig count change went negative in December 2014 and reached a maximum negative change in February 2015. When prices began to increase in April 2015, rig count change responded almost immediately.
Similarly, oil production followed changes in horizontal tight oil rig count quite closely and this includes total U.S. crude oil production, not just tight oil production (Figure 3) .
Production began to decline after April 2015 only 2 months after the maximum negative rig count change occurred in February.
Separating The Signal From The Noise
Oil companies tell us stories about new fracking technology, drilling productivity gains, and drilled uncompleted wells. These are mostly noise designed to distract us from the fundamental signal that the companies are losing a lot of money.
In order to navigate the uncertainties of investment, it is essential to separate the signal from the noise.
Companies and the minions of analysts and journalists would have us believe that rig count no longer matters. Pad drilling has relegated it to an anachronistic past that no longer applies in the brave new world of shale production where energy is impossibly cheap, abundant and profitable. This is a magical world where as the number of rigs approaches zero, oil production approaches infinity.
In this brief post, I have shown how that looks against the stark backdrop of facts. Rig count matters but it is only one factor that serious analysts use to try to decipher the signal amidst the deafening noise of oil-industry commentary.
The real signal is that all tight oil plays are losing money at current prices and will continue to lose money until oil prices reach and sustain approximately $65-75 per barrel. That scenario makes the doubtful assumptions that vast amounts of new capital will be available to E&P companies, and that the oil-field service industry will recover quickly. It is equally probable that oil prices languish well below the cost of production too long and that the E&P and service industries may never be the same again.
Investors should contemplate those alternative realities carefully. That will be possible only if the signal can be separated from the noise.
The break-even price for Permian basin tight oil plays is about $61 per barrel (Table 1). That puts Permian plays among the lowest cost significant supply sources in the world. Although that is good news for U.S. tight oil plays, there is a dark side to the story.
Just because tight oil is low-cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
The disturbing truth is that the real cost of oil production has doubled since the 1990s. That is very bad news for the global economy. Those who believe that technology is always the answer need to think about that.
Through that lens, Permian basin tight oil plays are the best of a bad, expensive lot.
Not Shale Plays and Not New
The tight oil plays in the Permian basin are not shale plays. Spraberry and Bone Spring reservoirs are mostly sandstones and Wolfcamp reservoirs are mostly limestones.
Nor are they new plays. All have produced oil and gas for decades from vertically drilled wells. Reservoirs are commonly laterally discontinuous and, therefore, had poor well performance. Horizontal drilling and hydraulic fracturing have largely addressed those issues at drilling and completion costs of $6-7 million per well.
Permian Basin Overview
The Permian basin is among the most mature producing areas in the world. It has produced more than 31.5 billion barrels of oil and 112 trillion cubic feet of gas since 1921. Current production is approximately 1.9 million barrels of oil (mmbo) and 6.6 billion cubic feet of gas (bcfg) per day.
The Permian basin is located in west Texas and southeastern New Mexico (Figure 1). It is sub-divided into the Midland basin on the east and the Delaware basin on the west, separated by the Central Basin platform.
The first commercial discovery in the Permian basin was made in 1921 at the Westbrook Field (Figure 1). It was followed in 1926 with the 2 billion barrel (bbo) Yates Field (San Andres & Grayburg reservoirs), the 2.1 bbo Wasson Field (Glorieta and Leonard reservoirs) in 1936, and the 1.5 bbo Slaughter Field (Abo and Clear Fork reservoirs) also in 1936. Reservoirs were chiefly high-quality limestones although the Wasson and Slaughter fields also produced from mixed sandstones and limestones that are equivalent to reservoirs in today’s Bone Springs tight oil play.
The Spraberry Field (1949) was the first discovery whose primary reservoir was among the present tight oil plays (Figure 2). Its ultimate production before horizontal drilling was estimated at 932 mmbo. The field had low recovery efficiency of 8-10% and was only marginally commercial prior to the recent phase of tight oil drilling.
Tight Oil Plays
I evaluated the three main tight oil plays. The Trend Area-Spraberry play is located mostly in the Midland basin while the Wolfcamp and Bone Spring plays are located mainly in the Delaware basin (Figures 1 and 2).
The Wolfcamp play has produced the most oil and gas—205 million barrels of oil equivalent (mmBOE)*—and has the largest number of producing wells, followed by the Trend Area-Spraberry and Bone Spring plays (Table 2). All of the plays produce considerable associated gas and only the Trend Area-Spraberry is technically an oil play. The Wolfcamp and Bone Spring are classified as gas-condensate plays based on liquid yield.
The Bone Spring play is the most commercially attractive of the tight oil plays with an estimated $49 per barrel of oil equivalent (BOE) break-even price for the top 5 operators. The Spraberry play has a break-even price of $55 per BOE for the top 5 operators but considerably higher well density and, therefore, lower long-term potential. Results from the Wolfcamp play are mixed with an average break-even price of $75 per BOE for the top 5 operators but $61 per BOE excluding one operator with poorer well performance.
Trend Area-Spraberry Play
I evaluated the 5 key operators in the Trend Area-Spraberry play with the greatest cumulative production and number of producing wells: Pioneer (PXD), Laredo (LPI), Diamondback (FANG), Apache (APA) and Energen (EGN) (Table 3).
I did standard rate vs. time decline-curve analysis for those operators. The matches with production history were generally good as shown in the examples in Figure 3.
Much of the gas production in the Permian basin is irregular because of periodic flaring so matching gas production history was sometimes difficult. Oil reporting in Texas is by lease rather than by well so there are periodic upward excursions of oil production as new wells on the same lease come on line. For these reasons, I feel that the decline-curve analysis results are probably optimistic.
The average Trend Area-Spraberry well EUR (estimated ultimate recovery) for the 5 operators is approximately 265,000 BOE using an economic value-based conversion of natural gas-to-barrels of oil equivalent of 15-to-1 (Table 4). The break-even oil price for that average EUR is approximately $55 per BOE. Laredo has the best average well performance with a break-even oil price of about $43 per BOE and Apache has the poorest well performance and highest break-even price of almost $92 per BOE.
Economic assumptions are shown in Table 5.
The top 5 producers in the Wolfcamp play are Cimarex (XEC), Anadarko (APC), EOG, Devon (DVN) and EP (EPE) (Table 6).
Examples of decline-curve analysis for this play are shown in Figure 4.
The average Wolfcamp well EUR for the 5 operators is approximately 228,000 BOE (Table 7). The break-even oil price for that average EUR is approximately $75 per BOE. That is because of poor well performance by Devon and EP whose break-even oil prices are more than $100 per BOE.
By eliminating EP from the calculations, the average EUR for the play is approximately 303,000 BOE and the associated break-even price is about $61 per BOE.
Anadarko has the best average well performance with a break-even oil price of about $45 per BOE and EP has the poorest well performance and highest break-even price of almost $177 per BOE.
Economic assumptions are shown above in Table 4.
Bone Spring Play
The top 5 producers in the Bone Spring play are Cabot (COG), Devon (DVN), Cimarex (XEC), Energen (EGN) and Mewbourne (Table 8).
Examples of decline-curve analysis for this play are shown in Figure 5.
The average Bone Spring well EUR for the 5 operators is approximately 294,000 BOE (Table 9). The break-even oil price for that average EUR is approximately $49 per BOE.
Cimarex has the best average well performance with a break-even oil price of about $42 per BOE and Mewbourne has the poorest well performance and highest break-even price of almost $78 per BOE.
Economic assumptions are shown above in Table 4.
Commercial Play Areas
I made EUR maps for the 3 Permian basin tight oil plays using all wells with 12 months of production. I then used the average play EUR to determine commercial cutoffs for $45 and $60 per BOE oil prices using the economic assumptions in Table 4.
Using the calculated EUR-cutoffs for the two oil-price cases, 26% of Permian tight oil place well break even at $45 per BOE, and 40% break even at $60 per BOE price (Table 10).
Current well density was calculated by measuring the mapped area of the $60 commercial area and dividing by the number of producing wells within those polygons. The Wolfcamp has the lowest well density of 1,269 acres per well and, therefore, the most development potential (Table 11). The Bone Spring also has considerable infill potential with 725 acres per well.
The Trend Area-Spraberry has additional development potential but a comparatively lower current well density of 281 acres per well because there are more than 6,000 vertical producing wells within the $60 commercial area defined by horizontal well EUR. These vertical wells have produced 203 MMBOE to date, approximately equal to the 206 MMBOE for all horizontal wells both inside and outside of the commercial area.
Operators routinely stress the large number of potential infill locations in their investor presentations and press releases based on very close well spacing of, for example, 40 acres per well. Although well density is important for determining play life, I doubt that well spacing of much less than 100 acres per well is economically attractive because of potential interference between wells that are drilled horizontally and hydraulically fractured.
Investors should understand that more wells is not better. Superior economics result from drilling the fewest number of wells necessary to optimize production.
Operators also stress the potential for additional potential reservoirs within the same play reservoir. That is undoubtedly true but those are not yet discovered and are, therefore, resources and not reserves of any category based on the SPE Petroleum Resources Management System. If they are so attractive, why haven’t they been drilled and produced already?
Love In The Time of Cholera
Tight oil and shale gas plays emerged at a time of worry and angst about impending resource scarcity and the decline of America as an world energy power. For some, these plays renewed faith in the ingenuity and technology that made America great. Now, there are even widespread delusions about becoming energy-independent and using new-found resources for global political and economic advantage.
Tight oil was a story of bittersweet success because the plays were commercial only at very high oil prices. When prices dropped in 2014, many expected that these plays would collapse. Instead, producers have taken advantage of the lowest oil-field service prices in decades and the plays have emerged as low-cost leaders among important suppliers of the world’s crude oil.
Low oil-field service costs won’t last and neither will the low break-even prices shown in this post. Still, tight oil plays and two of the Permian basin plays in particular, will break-even at lower prices that almost all OPEC producers once fiscal costs are included (Figure 9). The cost to balance a fiscal budget is the equivalent of corporate overhead for a country whose principal source of income is oil.
But just because tight oil is low cost compared to other expensive sources of oil doesn’t mean that it is cheap. Nor is it commercial at current oil prices.
Since 2009, oil has never been more expensive. The average price in real May 2016 dollars is $83 per barrel, the highest in history (Figure 10). This average includes the year of low oil prices in 2009 after The Financial Crisis and the two years since the mid-2014 oil-price collapse.
Even during the period of the oil shocks from 1974 to 1986, real oil prices were far less averaging $68 per barrel. Today’s price of $48 per barrel remains higher than the average real price of $45 since 1950.
Those who believe that Peak Oil is a failed observation do not understand that it was never about running out of oil. Peak Oil was always about running out of cheap oil. That is an indisputable fact.
The Bone Spring and Trend Area-Spraberry plays of the Permian basin are cheaper than any major world source of oil except Kuwait. They are the best of a bad lot.
Gabriel García Márquez’s masterpiece Love In The Time of Cólera is a story of forbidden love. Cholera is, of course, a disease that comes from infected water supplies and can result in prostration from the loss of fluids (Cólera more commonly means anger or rage in Spanish).
Like a disease, the high cost of energy and debt, its corollary, have drained the life from our global economy over the last several decades. The economic benefits anticipated from lower oil prices after the price collapse did not materialize because prices never stayed low enough for long enough.
The period of high oil prices from 1974 to 1986 created great economic distress for most of the world including the United States. Those who want to make America great again recall the economic prosperity of 1987 to 1999 (Reagan-Bush-Clinton years) when real oil prices averaged only $33 per barrel.
The economic problems that lead up to the 2008 Financial Collapse included high oil prices from 2000 through 2008. The massive new debt incurred to remedy that crisis along with even higher oil prices have thwarted a recovery.
Since the 2014 price collapse, monthly oil prices were less than $33 per barrel for only two months in January and February of this year.
Many talk hopefully about renewed drilling now that oil prices are near $50 per barrel. I doubt that prices will stay at $50 but will, instead, follow the 2015-2016 pattern of cyclicity. Prices should trend higher but I don’t expect a major shift to new drilling or a return to the peak production rates of 2014 and early 2015. The industry is wounded and will not heal for many years if ever.
Tight oil may have bought us a few years of abundance but the resulting over-supply, debt and prolonged period of prices below the cost of production have exacted a terrible cost. Under-investment, a damaged service sector, weak oil company balance sheets and a decimated work force practically ensure cripplingly higher prices a few years in the future.
The calamity of our time of cholera is that we cannot escape ever-higher costs of oil production.
*I use a 15 mcf per barrel equivalent conversion based on the price of natural gas and crude oil. The conversion based on energy content is approximately 6:1 and is used by most producers to calculate BOE EUR. The EUR reported by producers are, therefore, higher than those shown in this study especially for plays and wells with high gas-oil ratios.
U.S. crude oil production fell 150,000 barrels per day in May and the global over-supply of liquids was 680,000 barrels per day.
The EIA Short-Term Energy Outlook (STEO) posted on June 7 showed that U.S. oil production declined by the greatest monthly amount so far since the peak in April 2015 (Figure 1).
Production has declined 950,000 barrels of oil per day (bopd) from 9.69 million bopd in April 2015 to 8.6 mmbopd last month. EIA forecasts that production will decrease another 650,000 bopd by September for a total decline of 1.6 mmbopd since April 2015.
Declining U.S. production, an outage of 800,000 bopd because of Canadian wildfires, along with outages in Nigeria and Venezuela of perhaps 1 mmbopd are pushing oil prices higher and contributing to falling U.S. crude oil comparative inventories (Figure 2).
Comparative inventories are the most timely and reliable indicators of oil-price change. Figure 2 shows that comparative inventories fell sharply before the March-August and August-October 2015 oil-price rallies, and also fell along with the present price rally that began in March 2016. WTI futures are trading above $51 per barrel today.
The June STEO also shows that the global liquids over-supply for May was essentially flat with April at 680,000 bpd (Figure 3).
Supply fell 410,000 bpd and consumption fell 470,000 bpd–consumption typically falls in the second quarter before increasing in June or July as northern hemisphere seasonal usage peaks. World market balance (supply minus consumption) has been improving since late 2015 and early 2016. This is partly because of outages also.
I expect U.S. production and world market balance trends to continue to favor stronger crude oil prices although it is likely that the same cyclicity that has characterized prices since the price collapse in late 2014 will continue.
Enthusiasts believe that shale gas is simultaneously cheap, abundant and profitable thus defying all rules of business and economics. That is magical thinking.
The recently released EIA Annual Energy Outlook 2016 sparkles with pixie dust as it forecasts almost unlimited gas supply at low prices out to 2040 and beyond. Exuberant press reports herald a new era of LNG exports that will change the geopolitical balance of the world and make America great again.
But U.S. shale gas production is declining because of low prices and shale gas companies are in deep financial trouble because in the real world, price and cost matter.
That is not magical.
First Quarter 2016 Financial Performance
The financial performance of shale gas-weighted E&P companies in the first quarter of 2016 was a disaster.
Chesapeake Energy, the biggest shale gas producer in the world, had negative cash from operations. That means that oil and gas sales didn’t even cover operating costs much less capital expenditures like drilling and completion.
Other shale gas-weighted companies including Anadarko, Comstock and Petroquest also had negative cash from operations. Goodrich and Sandridge are in bankruptcy and Exco and Halcon will soon follow. Ultra, Forest, Quicksilver, Swift and Talisman were lost in action last year.
On average, surviving companies out-spent cash flow by two-to-one both in 2015 and 2016 but many normally strong companies greatly increased negative cash flow this year (Figure 1).
Devon Energy has been cash-flow neutral through much of the shale gas revolution but disturbingly increased capex-to-cash flow 5-fold in the first quarter of 2016. Similarly, Southwestern Energy has had an excellent record of near-cash flow neutrality but doubled its negative cash flow in 2016.
The debt side of first quarter earnings is far more disturbing. The average debt-to-cash flow ratio for shale gas companies increased almost 4-fold to more than 7, up from less than 2 in 2015 (Figure 2).
Devon’s debt-to-cash flow was more than 21 and Southwestern’s, more than 17. Gas prices below $3 cannot be sustained without damaging the balance sheets and income statements of even well-managed companies.
Debt-to-cash flow is a critical determinant of risk from a bank’s perspective because it measures how many years it would take to pay off debt if 100% of cash from operations were used for this purpose. This means that it would take these companies an average of 7 years to pay down their total debt using all cash from operating activities.
The energy industry average from 1992-2012 was 1.53 and 2.0 was a standard threshold for banks to call loans based on debt-covenant agreements. That threshold increased in recent years to about 4 but 7 years to pay off debt is clearly beyond reasonable bank exposure risk.
Low Gas Prices and Declining Production
Shale gas is the principal support for all U.S. gas production since conventional gas is in terminal decline. U.S. dry gas production has declined almost 1 Bcf per day since September 2015 largely because of low gas prices (Figure 3).
Henry Hub gas prices have fallen for the last 2 years from more than $6/mmBtu in January 2014 to $2 today and prices have been below $3/mmBtu since early 2015. A similar gas-price decline occurred from June 2011 to April 2012 (Figure 3). Then, dry gas production fell when prices dropped below $3/mmBtu.
$3 is well below the break-even gas price for any operator in any play. Even in the Marcellus–the most commercially attractive shale gas play–break-even prices are more than $3 (Table 1).
Shale gas production has fallen 0.83 Bcf/d since February 2016 (Figure 4).
All plays have declined from their respective peaks except the Utica Shale. Marcellus production accounts for more than a third (-0.36 Bcf/d) of shale gas decline in 2016. There is certainly no shortage of supply in that play but low prices and related delays in pipeline commitments have taken their toll on production.
There are no longer any horizontal rigs drilling in the Barnett or Fayetteville, plays that were supposed to help provide the U.S. with 100 years of gas supply . That is the intersection of magical thinking and low gas prices.
Higher Gas Prices Are Likely
Lower gas production along with increased consumption and exports spell higher gas prices later in 2016 and in 2017. Latest data from EIA corroborate the impending late 2016 supply deficit that I wrote about last month (Figure 5).
A supply deficit does not mean that there won’t be enough gas but will require more extensive withdrawals from inventory and that will move prices higher. During the last supply deficit in 2013 and through much of 2014, Henry Hub spot prices increased from $2 at the peak of the previous surplus to more than $6 per mmBtu and averaged $4.05.
Comparative inventory (C.I.) is determined by comparing current stocks with a moving average of stocks over the past 5 years. There is a strong negative correlation between C.I. and natural gas price (Figure 6).
The same June 2011-April 2012 price decline shown in Figure 5 correlates with a strong increase in C.I. in Figure 6. In February 2012, C.I. turned around abruptly and prices responded quickly.
Similarly, the February 2014-March 2016 price decline in Figure 5 correlates with a C.I. increase in Figure 6. That build has slowed in recent weeks and C.I. will probably begin falling as production continues to flatten and decline.
During the period of C.I. surplus from October 2011-March 2013, gas prices averaged less than $3 just as they have during the present period of C.I. surplus since February 2015. I expect prices to move above $3 as the winter heating season begins. A possible temporary price drop in September would be consistent with previous periods when ample winter storage levels are reached after the U.S. Labor Day (J.M.Bodell, personal communication).
Shale Gas Magical Thinking: Price and Cost Matter
Shale gas made sense in the first decade of this century when real gas prices averaged almost $7/mmBtu (Figure 7). That was because there was a supply deficit as conventional production declined before shale gas supply increased to replace it.
Since 2009, however, prices have averaged only $3.81 and that is less than the break-even price for core areas of any play except the Marcellus (Table 2).
Shale gas enthusiasts have embraced point-forward economics that ignore many important non-capital costs of doing business. That is the difference between the break-even prices in Table 2 and lower estimates found in many analyst reports.
The EIA magically forecasts that shale gas production will increase from almost 40 Bcfd in 2016 to almost 70 Bcfd by 2030 at $5 (2015 dollars) gas prices; it will increase to almost 80 Bcfd by 2040 at prices below $5 per mmBtu.
The prices in Table 2 are for the core areas of the plays–much higher prices will be necessary to produce the marginal areas needed to support supply after core areas are fully developed. Although I respect EIA’s work and do not hold them to a very high standard on long-term forecasts, this view of the future of shale gas is not helpful.
Falling gas prices have exposed the delusion of shale gas magical thinking. Production growth was funded by debt. Capital in search of yield continued to flow and over-production pushed prices below $2 by the end of 2015.
The wreckage is clear from disastrous first quarter financial data and falling production. The Barnett and Fayetteville plays that were supposed to last 100 years are dead at current prices. The Haynesville will probably follow soon enough.
Capital may continue to flow to shale gas companies but most of it will be used to repair balance sheets. Prices will gradually increase and financially stronger companies with core positions in the Marcellus and Utica plays will survive. Many companies will not.
The U.S. has perhaps a decade of gas supply at about $6 and considerably more at higher prices. By the time prices reach those levels, the folly of export will be apparent.