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 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.
The global oil market is returning to balance based on the latest data from the EIA. That should mean higher oil prices but how high must prices be to save the industry?
Data suggests that oil producers need prices in the $70-80 range to survive. That is unlikely in the next year or so. Without more timely price relief, the future looks grim for an industry on life support.
EIA Revises Consumption Upward
Major EIA revisions to world oil consumption* data provide a new perspective on oil-market balance.
The world was over-supplied by only 570 kbpd of liquids in April compared to EIA’s earlier estimate for March of 1,450 kbpd; that March estimate has now been revised downward to 970 kbpd (Figure 1). February’s over-supply has been revised downward from 1,180 to 240 kbpd.
These revisions indicate that oil markets are much closer to balance than previously thought.
EIA adjusted world consumption growth for 2016 upward to 1.4 mmbpd. Its estimate for 2017 is now a very strong 1.54 mmbpd (Figure 2).IEA’s demand growth estimate for 2015 is 1.8 mmbpd but the agency maintains its 1.2 mmbpd estimate for 2016 based on concerns about global economic growth.
It is easy to be skeptical about these new revelations but reports by both groups have been pointing toward improving market balance for some time.
Oil Prices and Market Balance
Oil markets are never in balance. Producers always misjudge demand and either over-shoot or under-shoot with supply. Balance is simply a zero-crossing from one state of disequilibrium to the next, from surplus to deficit and back again.
Since 2003, the oil market has only been within 0.25 mmbpd of balance 16% of the time. The average price (2016 dollars) for that near-market balance rate was $82 per barrel (Figure 3).
But that was essentially the average oil price of $78 per barrel for the entire period (Figure 4).
In fact, market balance occurred in every monthly average oil-price bin in Figure 5 except $130 per barrel. Although prices above $90 per barrel represent 37% of near-market balance prices from 2003 to 2016, oil prices also averaged more than $90 per barrel 36% of the time during that 15-year period.
In other words, market balance merely reflects whatever price the market deems necessary to maintain supply at the time. There is no clear causal relationship between market balance and specific higher or lower oil prices. Balance merely represents the midpoint between prices on either side of the disequilibrium states that it demarcates.
Our recent memory is of $90-100 per barrel prices so we think that was normal. When those prices prevailed in 2007-2008 and in 2010-2014, the disequilibrium state of the market was largely deficit. Moving toward market balance and being on the deficit side of market balance are hardly the same thing.
The Price Producers Need
Lower-cost oil producers of the world (Kuwait through Deepwater in Figure 6) need $50-80 per barrel and an average price of $65 per barrel to break even. Probably $70-80 is a minimum price range for near-term survival of more efficient producers allowing that some will still lose money at those prices.
Existing Canadian oil sands projects, and Bakken and Eagle Ford Shale core areas are among the very lowest-cost major plays in the world. For all of the OPEC rhetoric about the high cost of unconventional oil, few OPEC countries are competitive with unconventional plays when OPEC fiscal budgetary costs are included.
Tight Oil Companies On Life Support
Despite this relatively favorable rating, most unconventional producers are on life support at current oil prices.
All of the tight oil-weighted companies that I follow had negative cash flow in the first quarter of 2016 except EP Energy and Occidental Petroleum (Figure 7). Nine companies increased their capex-to-cash flow ratios compared with full-year 2015 results and six increased that ratio by more than 2.5 times.
On average in 2016, companies spent $1.90 more in capex than they earned while in 2015, they spent $0.60 more than they earned. The percent of negative cash flow has increased more than three-fold so far in 2016 compared with 2015.
The good news is that about half of the companies (Apache, EOG, Laredo, Continental, Statoil, and Diamondback) only increased negative cash flow slightly despite falling revenues. The bad news is that the rest (Marathon, Whiting, Pioneer, Murphy, ConocoPhillips and Newfield) did not.
The debt side of first quarter earnings is far more disturbing. The average debt-to-cash flow ratio for tight oil companies increased more than 3-fold to 10, up from 3 in 2015 (Figure 8).
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 10 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 10 years to pay off debt is clearly beyond reasonable bank exposure risk.
How High Might Oil Prices Go?
Current prices around $46 per barrel are a big improvement from earlier this year when prices were below $30. Nevertheless, all producers–companies and exporting countries alike–are failing and probably need sustained prices in the $70-80 per barrel range to survive.
That is a stretch from the mid-$40’s resistance level of the past 10 months or so (Figure 9).
In fact, EIA’s forecast data suggest that improving market balance may result in a minor supply deficit by the second half of 2017 (Figure 10). Its forecast for Brent price, however, is to remain below $60 per barrel.
Through A Glass Darkly
The price rally that began in late January-early February 2016 seems to have substance even though there are outsized inventories that concern serious observers. Anticipation of future supply deficits are moving prices higher in defiance of present-moment fundamentals to the contrary. Recent consumption data from EIA support improving oil prices going forward.
At the same time, I expect to see high price volatility and price cycling similar to what has characterized oil markets since prices collapsed in late 2014. The current cycle appears to have found resistance at about $46-48 per barrel and will probably move downward in an uneven way over the next few months before beginning the next upward cycle.
Recent outages in Kuwait, Nigeria, Venezuela and Canada have underscored the fragility of supply despite the prevailing production surplus. Under-investment during 2015 and 2016 will undoubtedly lead to much higher oil prices in just a few years especially with strong demand growth.
Prices must eventually reach the $70 to $80 per barrel range to restore balance sheets enough that investment may resume. It is, however, difficult to see that happening in 2016 or 2017 without serious supply disruptions or an OPEC production cut. Otherwise, prices should gradually and irregularly improve over the course of several 4- to 5-month cycles.
The weak global economy will be an important check on price recovery. Demand has improved during the period of lowest real oil prices since the 1990s but I expect demand destruction at prices higher than about $60 per barrel.
The last two years have severely damaged the oil industry and some producers and plays will not survive even with higher prices.
A return to market balance does not necessarily mean that prices will return to the $70-80 range. That is the level necessary to keep enough producers in business to maintain an adequate supply of the world’s primary energy source at a somewhat affordable price.
If a weakened world economy cannot support those prices, we may see supply dwindle in a few years to levels that cause price spikes that cannot be absorbed. That may bring a traumatic end to the Age of Oil. People will have to learn to get by with less in a future based on lower energy-density fuels and lower economic growth potential than oil has provided.
*Consumption a measure of oil use. It is often used as a proxy for demand but does not address the supply stream including stocks. It does not measure requirement for oil that may differ from use.
Gasoline demand is a red herring.
A red herring is something that takes attention away from a more important subject. Gasoline demand distracts from the more important subject that there is no fundamental reason for the current oil-price rally.
U.S. Gasoline Consumption Has Fallen 2 Million Barrels Per Day Since 2005
Those who believe that gasoline demand is the fire behind oil’s recent rally confuse production with consumption. They also don’t understand that Americans increased their driving when oil prices were $100 per barrel and continued to travel more miles throughout and despite oil-price highs and lows.
A recent Bloomberg article stated, “American gasoline consumption rose to 9.25 million barrels a day in March, an all-time high for the month.”
9.25 million barrels per day is product supplied, the measure of how much gasoline is produced in U.S. refineries. Total wholesale and retail sales is the measure of U.S. consumption and that amount is only 7.76 million barrels per day.
Consumption of gasoline in the U.S. has increased 802 thousand barrels per day (kbpd) since January 2014 but is 1,973 kbpd less than peak consumption in June 2005.
U.S. production of gasoline is 908 kbpd more than the post-Financial Collapse low in January 2012 but is 542 kbpd less than the peak in July 2007 (Figure 1).
Meanwhile, net gasoline exports are at record high levels. Exports have increased 1,443 kbpd since June 2005.
So, consumption has increased but remains far below pre-2012 levels. Production is again approaching earlier peak levels but most of the increased volume is being exported. The belief that U.S. consumption is approaching record highs is simply not true.
Americans Are Driving More But Using A Lot Less Gasoline
Americans are driving more than ever before. Vehicle miles traveled (VMT) reached an all-time high of 3.15 trillion miles in February 2016 (Figure 2).
VMT have increased 97 billion miles per month (3%) since the beginning of 2015 and gasoline sales have increased 187 kbpd (2%). The rates of increase are not proportional.
For example, VMT was fairly flat from mid-2011 until oil prices collapsed in September 2014 yet gasoline sales fell more than 1 million barrels per day during the same period. Americans traveled the same number of miles but used a lot less gasoline. Even with the VMT increase since 2015, sales are still 539 kbpd less than in January 2009.
Vehicle Miles Traveled Independent of Gasoline Prices
Gasoline prices fell along with oil prices in late 2014 and consumption increased (Figure 3) but the relationship between prices and consumption is not straight-forward.
Prices reached a low in January 2015 and then increased to a peak in July 2015. Gasoline sales increased right along with prices, not exactly the relationship we would expect. Although gasoline usage is strongly seasonal, consumption is not simply a function of price.
Figure 4 shows that vehicle miles traveled increased from March 2013 through September 2014 when oil prices averaged almost $100 per barrel. It is unclear why Americans began driving more but it was not because gasoline prices were cheap.
When oil prices fell to less than $43 per barrel by January 2015, there was no change in VMT growth. Furthermore, VMT continued to increase despite cycles of high and low prices in 2015 that first rose to $60 and then fell to less than $30 per barrel.
The factors that underlie driving behavior are complex. Gasoline price is among those factors but there is no clear correlation between price and consumption.
To put gasoline consumption in context, the 187 kbpd increase in gasoline sales since January 2015 is 1.2% of monthly U.S. oil consumption. The increase in product supplied is 1.7% of monthly consumption.
Crude Oil Imports Increased As U.S. Production Declined
As U.S. crude oil production began to decline in 2015, more oil was needed to produce gasoline and other refined products so imports increased.
From April 2015 to March 2016, oil production decreased 660 kbpd (-7%) but net crude oil imports increased 800 kbpd (+10%) (Figure 5).
When analysts mistake gasoline production for consumption, they include gasoline made from imported oil in their celebration of increased U.S. “demand!”
Moreover, increased imports are also included in U.S. inventory volumes. If the whole situation seems complicated, that’s because it is and the lesson is to be careful about your sources of information.
Gasoline Demand Is A Red Herring
Americans are driving more than ever but using less gasoline than a decade ago. A lot of this is undoubtedly because of greater fuel efficiency. It seems unlikely that gasoline consumption will ever again reach levels before the Financial Collapse in 2008-2009.
The correlation between gasoline price and vehicle miles traveled is not very good. Americans started driving more when prices were very high and kept driving more despite large fluctuations in price. I cannot explain this except to observe that aspects of gasoline consumption must be somewhat inelastic. Price matters but not as much or in the same way that I imagined.
What is clear is that gasoline consumption is not a significant factor in the recent oil-price rally. The collective consciousness that drives the oil market is fed up with low oil prices. It looks for and sometimes invents excuses to raise prices and ignores compelling reasons to lower them.
Gasoline demand is the most recent invention and it is a genuine red herring.
The production freeze meeting in Doha was a no-brainer but it ended mindlessly with no action taken.
OPEC plus Russia and Mexico met yesterday to agree to do almost nothing by freezing production. Instead, they agreed to do absolutely nothing leaving everyone wondering why they even held the meeting.
All that they had to do was agree not to increase oil production above levels in January. They could have modified that to current levels. Probably, that would have ensured that oil prices remain near currently inflated levels that were created mostly by expectation of a production-freeze agreement to begin with.
It should have been a no-brainer because the Doha group’s production is already 130,000 barrels per day less than it was in January (Figure 1). Kuwait, Qatar, Russia, Mexico, Ecuador and Indonesia are all producing slightly more than they were in January but were prepared to go back to those levels.
Iran is producing about 350,000 bpd more than in January and has stated its intent to raise output much higher. Everyone else is producing less or the same as in January.
But this has been clear for months. Iran called the idea of a production freeze “ridiculous” in February and did not even send a representative to the meeting in Doha.
So, what was the point of the meeting?