The Petroleum Truth Report

My 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 U.S. Over-Supply of Oil is Ending

The U.S. over-supply of oil is ending.

Comparative inventory (C.I.) has been dramatically reduced in 2017. Levels have fallen 159 mmb since February and are now approaching the 5-year average for the first time in nearly 3 years (Figure 1).

Figure 1. The U.S. Over-Supply of Oil is Ending. Source: EIA and Labyrinth Consulting Services, Inc.

An interpreted yield curve that correlates C.I. and WTI price is developed by cross plotting the same data without the time dimension (Figure 2). The yield curve may provide price solutions to inventory reduction assumptions in the near term.

Figure 2. Crude + Product Comparative Inventory Have Fallen 159 mmb in 2017. C.I. Could Reach the 5-Yr Avg By & $70 WTI Prices by Early 2018. Source: EIA and Labyrinth Consulting Services, Inc.

Accordingly, if C.I. continues to fall at the 9-month average of 4 mmb/week, oil prices may be approximately $67 per barrel by the end of December. If C.I. falls at the 8 mmb/week average since late September, WTI could approach levels not seen since before the price collapse in late 2014.

Exports and The Brent-WTI Spread

The causes of the U.S. inventory drawdown are clear: increased exports of crude oil and greater domestic consumption.

Crude oil exports for the first half of 2017 averaged 766 mmb/d but rose to 1.8 mmb/d in September and October. Increased exports now average more than 12 mmb/week and contribute substantially to reduced inventory levels.

Higher export levels correlate with the increased spread between Brent and WTI prices that began in late July (Figure 3). Traders can sell U.S. crude oil overseas at less than international prices but at levels higher than domestic pricing allows. Record exports of 2.13 mmb/d occurred during the week ending October 27.

Figure 3. U.S. Crude Oil Exports Reached Record 2.13 mmb/d Week Ending Oct. 27. Higher Export Volumes Correlate With Increased Brent-WTI Price Spread. Source: EIA and Labyrinth Consulting Services, Inc.

Tight oil production levels, crude oil quality and U.S. refinery blending needs are behind the WTI discount to Brent price. Most U.S. refineries are designed for international grades of oil like Brent which is heavier and contains more sulfur than WTI.

The U.S. has had a surplus of light sweet oil since the tight oil boom began, and the Brent-WTI spread reached almost $30/barrel in September 2011 as a result (Figure 4).

Figure 4. Brent-WTI Price Spread Related to Surplus Tight Oil Production. Source: EIA and Labyrinth Consulting Services, Inc.

The spread decreased to about $2.25 with the advent of rail shipments of WTI to East Coast refineries, and associated reduced light oil imports. The transport cost was reasonable when oil prices were $100 per barrel but lower oil prices after 2014 resulted in a progressive decline in rail shipments (Figure 5). East Coast refiners increasingly relied again on imported light oil mostly from West Africa to blend with heavier grades of oil.

Figure 5. Recent Increase in Brent-WTI Spread Related to Replacement of WTI Rail Shipments to East Coast Refineries by West African Light Oil Imports. Source: EIA and Labyrinth Consulting Services, Inc.

A surplus of tight oil returned as production recovered as a result higher oil prices in 2016 and 2017. Surplus supply caused discounted WTI prices, and the recent increase in the Brent-WTI spread. Some of excess oil has been exported in recent weeks but the price spread persists because import levels are so far unaffected.


The second major cause of the U.S. inventory drawdown is increased domestic consumption of refined products.

Consumption reached a 10-year record of 21 mmb/d during the summer of 2017 (Figure 6).  August 2017 consumption was 300 kb/d more than in August 2016 and that difference accounts for more than 2 mmb/week of incremental inventory reduction. In fact, the increase in consumption that began in January coincided with the beginning of comparative inventory reduction that in February (red dots in Figure 6).

Figure 6. Record 21 mmb/d Refined Product Consumption in Summer 2017 A Major Factor in Comparative Inventory Reduction. Source: EIA and Labyrinth Consulting Services, Inc.

The greatest portion of consumption is from transportation. The declining growth rate of vehicle miles traveled (VMT) that began in early 2016 reversed in the second quarter of 2017 despite somewhat higher gasoline prices (Figure 7).

Figure 7. Declining Growth Rate of Vehicle Miles Traveled Reversed in Q2 2017 Despite Higher Gasoline Price. Source: U.S. Federal Reserve Bank, EIA and Labyrinth Consulting Services, Inc.

VMT data is only available through July but it is likely that growth continued at least through August based on consumption data that is more current.

The Possible Downside of Consumption

It is reasonable to question the capacity of the rest of the world to continue to absorb U.S. exports. Exports have increased in each of the last 6 weeks except the week ending October 6, and exports that week were still a robust 1.3 mmb/d. It is impossible to get reliable inventory data for most of the rest of the world but OECD data suggests inventory reductions similar to those described in the U.S.

Continued high U.S. consumption is the only area of concern for sustained higher oil prices. September and October consumption were considerably lower than in August. It is normal for consumption to decline after the summer driving season but the magnitude of the decline is disturbing.

October consumption was 1.2 mmb/d (38 mmb/month) less than in August (Figure 8). That is almost as much as the total August-to-January seasonal decline during the previous year (1.4 mmb/d, 42 mmb/month).

Figure 8. October U.S. Consumption Was 1.2 mmb/d (-38 mmb) Less Than Than In August, Almost As Much As Total August-January Seasonal Fall in 2016. Source: EIA and Labyrinth Consulting Services, Inc.

The data may be biased by the effects of hurricanes Harvey and Irma, and two months do not define a trend. It is, nevertheless, a troubling observation despite the fact that it will probably not affect inventory levels or oil prices in the rest of 2017.

Consumption becomes a greater concern if oil prices increase as much as I expect because gasoline prices will increase accordingly–consumption and gasoline price are negatively related (Figure 9). Higher oil price means higher gasoline price and lower consumption.

Figure 9. U.S. Consumption is Inversely Related to Gasoline Price. Higher Oil Price Means Higher Gasoline Price & Lower Consumption. Source: U.S. Federal Reserve Bank, EIA & Labyrinth Consulting Services, Inc.

$70 WTI will result in almost a $1/gallon price increase above the current average retail price of $2.53 and that may depress consumption.

The U.S. Over-Supply of Oil Is Ending

Increased exports of crude oil have reduced U.S. inventories more quickly than I expected a month ago when I wrote Higher Oil Prices Likely in Early 2018. Higher consumption levels were well established at that time but evidence for a trend of elevated export levels consisted of two anomalous data points.

Because of the way that trades are arranged, if the Brent-WTI spread closed tomorrow, continued high export levels are almost inevitable through the end of the year. That means that oil prices will increase at least for the near term.

Comparative inventory is not a predictive methodology.  It is, however,  a powerful tool because it identifies trends that correlate inventory change and oil price. As such, it can provide price solutions to inventory reduction scenarios. Those scenarios suggest that WTI prices in the $60 to $70 range are almost certain in early 2018, and that prices higher than $70 are also possible.

The U.S. over-supply of oil is ending. It is likely that comparative inventory will be near or even below the 5-year average by the end of 2017 or early in 2018. Higher oil prices may be good for oil companies but bad for consumers.

For the first time since the 2008 financial crisis, the U.S. and global economy appear to have some reasonable potential for growth. Economists are generally too preoccupied with monetary policy, interest rates and abstract mathematical models to see the obvious connection between the price of oil, our master resource, and economic growth.

Will higher oil prices smother the weak flicker of economic growth that now seems possible?

Higher prices will unquestionably provoke a new flood of capital to E&P companies. Although demand is important, producer behavior and the impulse for over-production have been the defining aspects of the last decade in the oil industry. Under-investment and limited availability of frack crews have modulated supply since early 2015. That will change probably later in 2018.

The path to price recovery will not be straight. The elegant interplay between higher oil prices, credit and the impending threats of over-supply and under-supply will continue.  In the medium term, we will learn whether tight oil plays in fact have sufficient reserve potential to meet global supply needs. My guess is that they do not.

That means reliance on more costly deep-water projects that have much longer development time lines. Associated reserves are largely know and, while considerable, are insufficient for more than about a decade of demand.

Supply and its alter-ego credit are central to mapping the implications of the topics I have discussed here. Most investors and analysts assume—perhaps unconsciously—that future supply will be more abundant than present supply. What if they are wrong?

**Help from J.M Bodell and Matt Smith are gratefully acknowledged.




Higher Oil Prices Are Likely in Early 2018

Oil prices will be lower for longer—that is the conventional wisdom. Data suggests, however, that  oil supplies are tightening and that higher prices are likely in the relatively near-future.

Refined Product Demand and Crude Oil Exports

U.S. crude oil plus products comparative inventories have fallen 120 mmb (million barrels) in 26 of the last 32 weeks (Figure 1). Strong domestic demand for refined products and increased crude oil exports are the main reasons. That translates into lower net imports of both crude oil and petroleum products to the United States. The year-to-date average of U.S. product net imports is down 0.5 mmb/day from 2016. That’s 3.5 mmb/week which is about the average weekly storage withdrawal since mid-February.

Figure 1. Approximately 3.3 mmb/week (470 kb/d) Decrease in Net Petroleum Product Imports Account for Most Inventory Reductions in 2017. Comparative Inventories Have Fallen 126 mmb Since Mid-February. Source: EIA and Labyrinth Consulting Services, Inc.

U.S. crude oil exports have increased reaching a record 1.9 mmb/d during the week ending September 29 (Figure 2).

Figure 2. Record Crude Exports of 1.9 mmb/d Week Ending Sept. 29 2017. Source: EIA and Labyrinth Consulting Services, Inc.

Increased exports have been part of  how producers cope with limited U.S. refining capacity for the ultra-light oil from tight oil plays. Recent increases in exports levels, however, are because of higher international oil prices compared with domestic prices.

Brent has traded at a premium to WTI since U.S. tight oil became a factor in global supply in late 2010. That was largely because of limited take-away and refining capacity for the new U.S. supply in the early days of tight oil production.  The Brent-WTI “spread” reached $28 per barrel in September 2011 but decreased when infrastructure caught up with supply. It averaged about $1.68 in the first half of 2017.

In June, the spread began increasing and is currently almost $7 per barrel (Figure 3). Some of this is a “fear premium” because of tensions in the Middle East—the GCC boycott of Qatar and the Iraqi Kurdish independence referendum. Some of it is also a buildup of inventories at the Cushing, Oklahoma storage facility and WTI pricing point.

Figure 3. Brent Premium to WTI Has Increased More Than $5/barrel From 1H Average. Middle East Fear Premium plus Cushing Inventory Levels are the Cause. Source: EIA and Labyrinth Consulting Services, Inc.

Inventory increases at Cushing may be partly explained by refinery and pipeline outages following recent hurricanes but the build ups actually began in July a month before Hurricane Harvey. The causes are not entirely clear but rising inventories at Cushing especially when its storage exceeds 80% is generally a negative factor for WTI prices.

In addition to crude oil, exports of distillate, liquefied petroleum gases, and liquefied refinery gases have also increased in 2017.

Comparative Inventories and The Yield Curve

Falling U.S. comparative inventories (C.I.) in 2017 is a trend and not an anomaly. Figure 4 shows the 120 mmb decrease in C.I. since mid-February and the associated “yield curve” (Bodell, 2009) that correlates inventory with WTI price.

Figure 4. U.S. Crude + Product Comparative Inventory Has Fallen 120 mmb Since Mid-February–Yield Curve Suggests Higher Oil Prices Sooner Than Later. Source: EIA and Labyrinth Consulting Services, Inc.

The magnitude of the inventory drawdown cannot be over-stated. The fact that it is driven by increasing demand suggests that that U.S. supply is moving steadily toward balance.

OECD comparative inventory (less the U.S.) has fallen 99 mmb since July 2016 (Figure 5). Although the data frequency is lower (monthly vs. weekly) and less systematic than U.S. inventory data, the reduction in C.I. is the main point.

Figure 5. OECD (minus U.S.) Comparative Inventory Has Fallen 99 mmb Since July 2016. Source: EIA, IEA and Labyrinth Consulting Services, Inc.

The relative lack of price increase with falling C.I. for both the U.S. and OECD is because the yield curve was flat for much of the reduction because of the the magnitude of storage volume. Now, enough inventory has been drawn down that the curvature of the trend is increasing. Greater price response with incremental reduction in C.I. is likely as volumes approach the 5-year average.

Misplaced Concern About Shale Supply

Fears about burgeoning U.S. supply from shale reservoirs has been a consistent drag on market sentiment about price for at least a year. This has been based more on rig count than real evidence. Continental Resources chairman Harold Hamm has loudly blamed overly optimistic EIA supply forecasts for low U.S. oil prices. This is misplaced and typical of the hyperbole regularly heard from shale company executives.

The fact is that U.S. output has been flat since early 2017 and the EIA has adjusted its forecasts as data replaces sampling algorithms in their accounting (Figure 6).

Figure 6. U.S. Output Has Been Flat in 2017. Source: EIA and Labyrinth Consulting Services, Inc.

The reason is that despite increased drilling, frack crews and equipment are not sufficient to meet demand for well completions. Pressure pumping equipment was not maintained and parts were cannibalized after the oil price collapse, and crews were laid off. It may take another year of strong demand to rebuild this capacity.

The result is that far more tight oil wells are being drilled than completed and I expect that this pattern will continue (Figure 7).

Figure 7. More Permian Wells Have Been Drilled Than Completed in 2016 and 2017. The Number of DUCs (Drilled Uncompleted Wells) is Increasing. Source: EIA and Labyrinth Consulting Services, Inc.

Fears that DUCs (drilled uncompleted wells) will flood the market with supply are unrealistic. When these wells are completed, it will be gradual and the natural ~30% annual decline in legacy shale production will be difficult to overcome. Moreover, production from the Eagle Ford and Bakken plays is declining. Only Permian production is increasing and on balance, it is unlikely that net shale production will increase much unless production trends outside the Permian basin somehow reverse.

The Tyranny of Preconception and Conventional Wisdom

In a recent interview about the documentary film The Vietnam War, co-director Ken Burns  discussed the “tyranny of preconception and conventional wisdom” on public perception. Similarly, the lower-for-longer mentality has distorted perceptions of global oil markets.

That mantra made sense in 2015 and in the first half of 2016 as global inventories soared and supply outstripped demand. But data clearly shows that things have changed. The OPEC-NOPEC production cuts and increased demand for oil and refined products have resulted in a profound reduction of inventories. If those patterns continue, higher oil prices are likely in the first half of 2018.





WTI Probably Stuck in High $40 to Mid $50 Range Through December 2017

The most likely case is that WTI will remain stuck in the upper $40 to lower or mid- $50 range through December 2017.

Comparative inventories have fallen dramatically since mid-February yet oil prices languish in the mid-to-upper $40 range. What will it take for oil prices to break out of the $45 to $55 range boundaries since OPEC production cuts were announced in late 2016?

WTI prices increased from below $45 to almost $55 per barrel based on expectation that OPEC cuts would quickly balance international oil markets and result in near-term higher oil prices. While that expectation lasted, prices remained near $55 from late November 2016 until early March 2017 (Figure 1).

Figure 1. WTI Prices Have Been Largely Range-Bounded Between $45 and $55/Barrel Since The OPEC-NOPEC Production Cuts. Source: EIA, Bloomberg and Labyrinth Consulting Services, Inc.

Prices adjusted downward four times between March and August as it became clear that output cuts were not enough to produce a meaningful price recovery. Since mid-August, markets have rallied back to the ~$49 per barrel price average since November.

Tight Oil Rig Counts

Rising rig counts in U.S. tight oil plays have been the most important factor constraining oil prices. Investors fear that resulting increased output will prevent the market from reaching balance.

Rig counts in the Permian basin, Bakken and Eagle Ford plays began increasing after WTI fell below $30 per barrel in early 2016. Since OPEC first suggested the possibility for a production cut in August 2016, tight oil rig counts have more than doubled (Figure 2).

Figure 2. Tight OIl Rig Counts Have Doubled Since Mid-August 2016. Eagle Ford horizontal rig count has fallen the most of the tight oil plays. Source: Baker Hughes and Labyrinth Consulting Services, Inc.

While the increase in the number rigs is impressive, the most revealing aspect of Figure 2 is the decline of the Eagle Ford, and the flattening of Permian basin and Bakken rig counts since June. This suggests that the appetite for tight oil plays among equity investors may be moderating.

Despite claims of sub-$40 per barrel break-even prices by Permian basin producers, rig count data indicates that overall play economics require higher prices.  The weekly change in Permian rig count suggests that break-even WTI prices may be closer to $55 or $60 per barrel (Figure 3). Break-even prices for some producers are certainly lower but higher prices are required for the average company.

Figure 3. Rig Count Weekly Change Suggests Permian Break-Even Price Is $55-$60/Barrel. Rig Count Rises and Falls on Expectation of $55 to $60 Prices. Source: Baker Hughes, EIA and Labyrinth Consulting Services, Inc.

Above all, rig count reflects capital flows and the availability of other peoples’ money to fund the tight oil plays—this is critical to production maintenance and growth. Figure 3 shows that capital availability is dependent on expectation of $55 to $60 oil prices. Capital flows have apparently faded with those expectations or else producers are using available capital for other purposes in addition to drilling.

Comparative Inventory

Comparative inventory (C.I.) fell 117 million barrels (mmb) from mid-February through the end of August (Figure 4).*  This is the most significant oil market development since oil prices collapsed in 2014 but it has had little affect on oil prices so far.

Figure 4. ~4.2 mmb/week (600 kb/d) Decrease in Net Petroleum Product Imports Account For Most Inventory Reductions in 2017. Note: Net imports of petroleum products increased 1.7 mmb for the week ending September 1 because of Hurricane Harvey. Latest data is not included in Figure 4 because it skews net imports based on a weather-related anomaly. Source: EIA and Labyrinth Consulting Services, Inc.

Lower net imports of petroleum products is the main reason for this reduction in C.I. Refinery intakes are at record levels as refiners produce and sell refined products in the U.S. and abroad. As I pointed out last month, this trend is only sustainable if demand for U.S. refined products persists.

While exporting products helps reduce U.S. stocks, it aggravates the global over-supply of liquids. Higher net imports in recent months suggest that this trend may be weakening or ending.

Figure 5 shows the magnitude of inventory reductions from mid-February to late August as a “yield curve” of WTI price vs. C.I.

I estimated a range of probable year-end C.I. values to be between 40 and 75 mmb using EIA August STEO inventory forecasts and 2017 inventory decline trends. This range of C.I. translates to December WTI prices between $50 and $56 per barrel.

Figure 5. Most-Likely December 2017 C.I. Range 40-75 mmb and $50-$56/barrel WTI prices. Source: EIA and Labyrinth Consulting Services, Inc.

Continued demand for refined products is the key. I stated in a previous post that I doubted that ongoing U.S. inventory reductions were sustainable because of over-supply in international refined product markets. That would result in lower reductions in C.I. and most-likely December prices in the upper $40 to lower $50 range.

On the other hand, if refined product demand remains strong and inventory reductions follow a trend similar to that of the last several months, it is more likely that year-end WTI prices will be in the $50 to $56 per barrel range.

Large reductions  in C.I. so far have not resulted in meaningful increases in oil prices because the yield curve is fairly flat. That is typical of outsized storage levels.

Oil prices collapsed in 2014 because of excess supply from over-production. Low prices and the contango term structure of forward curves encouraged putting large volumes of crude oil and refined products into storage.

Record U.S. inventory levels were reached in February 2017. Inventory reductions since then leave comparative inventories down only somewhat from record levels (Figure 6).

Figure 6. Inventories Are Somewhat Down From Record Levels—the Difference Between Inventories and the 5-Year Average (Comparative Inventory) is Also Near Record Levels. Source: EIA and Labyrinth Consulting Services, Inc.

Progressively higher absolute inventory levels push the 5-year average continually higher. Since C.I. is the difference between inventories and the 5-year average, falling C.I. relative to climbing 5-year averages results in a fairly flat yield curve (Figure 5).

A greater rate of curvature will result in higher oil prices from incremental C.I. reductions as the yield curve approaches the y-axis and mid-cycle price. That, however,  is not likely to happen in 2017.

Barring unforeseen supply outages and ongoing rates of C.I. reduction, December 2017 WTI prices should be only slightly higher than current prices namely, in the lower or mid-$50 range at best.


* C.I. increased 5 mmb for the week ending September 1 and net imports of petroleum products increased 1.7 mmb because of Hurricane Harvey. Latest data is included in Figure 5 but not Figure 4 because it skews net imports based on a weather-related anomaly.


U.S. Inventory Reductions Probably Not Sustainable

The decline in U.S. comparative inventories since February is the most significant oil market development since prices collapsed three years ago. It means that U.S. demand has exceeded supply for most of the last 5 months. The main cause is lower net imports, not higher domestic consumption, and that is probably not sustainable.

Comparative Inventories: The Key To Understanding Oil Prices

Comparative inventory (C.I.) is the difference between current storage levels of crude oil plus a select group of refined products, and their 5-year average for the same weekly time period (Figure 1). It is an indicator that normalizes seasonal variations in production, consumption and refinery utilization.

Figure 1. Comparative Inventory Is The Difference Between Stock Levels & Their 5-Year Average. Source: EIA and Labyrinth Consulting Services, Inc.

C.I. is the key to understanding oil prices yet few analysts use or even discuss it. Instead they try to explain price fluctuations by events in the daily news cycle or by simple year-over-year comparisons.

The negative correlation between C.I. and WTI price is strong. The 121 million barrel (mmb) increase in C.I. that began in June 2015 corresponded with a decrease in oil prices from $60 to $28 per barrel (Figure 2). The subsequent decrease in C.I. from April to July 2016 corresponded to an increase in oil prices from $28 to $50 per barrel.

Figure 2. Strong correlation between Comparative Inventory and WTI Prices. Source: EIA and Labyrinth Consulting Services, Inc.

U.S. comparative inventories have fallen more than 104 million barrels since mid-February 2017. Average weekly withdrawals of 4.3 mmb of crude oil and refined products indicate that demand has exceeded supply by almost 600,000 barrels per day (b/d) over the past 24 weeks.

Figure 3 shows the same C.I. vs. price data as a cross-plot (with the time dimension suggested by the light blue connecting lines). The resulting “yield curve” (Bodell, 2009) offers a structure for organizing seemingly random variations in oil prices.

Figure 3. Comparative Inventory Provides a Framework and Context For Oil Prices. Source: EIA and Labyrinth Consulting Services, Inc.

The yield curve does not provide a precise solution to comparative inventory vs. price trends.  Nor does it represent a simple regression fit although the data correlate systematically in time. Interpretation based on experience is required because much of the apparent data scatter is due to sentiment-based fluctuations in price.

Nevertheless, the C.I. vs. price yield curve presents a unique framework and context for prices and price trends. Because it reflects movement of oil volumes in and out of storage, it integrates true demand and supply variations with price. It also places probabilistic constraints on future price movements.

The yield curve shows that the March-June 2015 “false” price rally to more than $60 per barrel was a significant over-shoot. It reflected unwarranted optimism soon after oil prices collapsed that a return to $100 per barrel prices was likely. A short-lived fall in comparative inventory supported that optimism (Figure 2).

Similarly, the price collapse to less than $30 per barrel in late 2015-early 2016 represented a substantial under-shoot. Yet, it corresponded to the second phase of the largest increase in comparative inventory in history (Figure 2). Cushing storage capacity was greater than 80% during that period and it is a factor that generally puts downward pressure on prices.

The yield curve further shows the artificial uplift in prices from November 2016 through February 2017. This was based on unrealistic optimism that OPEC production cuts would result in a meaningful oil-price recovery to perhaps the $60-$70 range. Again, the anticipated mechanism was expected to be inventory reduction.

These price outliers reflect the daily decisions of oil traders who must trade, and the influence of sentiment and analyst narratives on short-term prices. Their causes were recognized as probable deviations from the yield curve norm at the time they were occurring.

The yield curve furthermore imposes constraints on the potential limits to future price trends. Its intersection with the y-axis is called the mid-cycle price, the price that the market deems necessary to maintain supply for a complete price cycle.

That price for the current cycle is approximately $75 per barrel. It represents the most likely price when stock levels are equal to their 5-year average. Barring fear premiums because of geo-political events, the mid-cycle price tempers overly optimistic price expectations as long as comparative inventories remain elevated.

I used July STEO forecasts to estimate a possible range of comparative inventory values and corresponding WTI prices for December 2017. These suggest C.I. in the range of 40 to 60 mmb above the 5-year average, and corresponding WTI prices between $48 and $53 per barrel. These may be conservative based on recent large inventory withdrawals—if those continue, oil prices could be in the mid-to-high $50 range by year-end.

Consumption and Net Imports

Ordinarily, higher demand is because of increased consumption but data suggest that year-to-date U.S. consumption (product supplied) is flat compared with 2016 (Figure 4). Record levels were reached in late June and July but first-half consumption was actually about 150,000 b/d less than for the same period in 2016.

Figure 4. Late June-July Consumption Has Reached Record Levels But Year-to-Date 2017 Consumption Is Flat With 2016. Source: EIA and Labyrinth Consulting Services, Inc.

Although the last 5 weeks of data indicate approximately 440,000 b/d of additional consumption, comparative inventory began to fall in mid-February and this recent increase, therefore, cannot account for most of the C.I. reduction.

Net oil imports provide a more consistent but still incomplete explanation for increased U.S. demand and C.I. reductions. Since mid-February, average net imports of crude oil and refined products have decreased about 334,000 b/d (Figure 5).

Figure 5. Lower Crude & Refined Product Net Imports Are Responsible For ~55% of Comparative Inventory Decline. Source: EIA and Labyrinth Consulting Services, Inc.

That translates to 2.4 mmb/week or about 55% of the average C.I. decline of 4.34 mmb/week. Lower crude oil net imports account for about 65% of that total decrease. Year-to-date crude exports have averaged 757 kb/d compared to 445 kb/d in 2016.

Unaccounted-For Oil

Lower net imports and higher consumption account for all of the comparative inventory reductions since late June but only for a little more than one-half of reductions for the previous 4 months. It is disturbing that this important development cannot be more fully understood.

Last October, my colleague Matt Mushalik and I wrote a post about the large and growing volume of unaccounted-for oil in U.S. storage. We showed that implied stock changes based on input and output volumes published weekly and monthly by the EIA could not be reconciled with reported stock changes to U.S. crude oil storage.

That situation has not changed. Implied stock levels (field production + net imports – refinery intakes) are consistently less than reported stock levels. The cumulative difference is now 137 million barrels from a common starting value in January 2015 (Figure 6). That is the amount of unaccounted-for crude oil in U.S. storage.

Figure 6. 137 Million Barrels of Unaccounted-For Oil in Storage (28% of total). Source: EIA and Labyrinth Consulting Services, Inc.

An EIA representative initiated dialogue about the points raised in our post just after its publication. The EIA contends that its methods for estimating stock changes are more reliable than its published flows we used to calculate implied stock changes. Although this may be valid for relatively recent data, it seems that revisions should largely cancel those differences after some reasonable number of months have passed.

The representative also noted relative agreement between EIA and API stock estimates as validation of its methodology. It seems, however, that differences between what EIA and API report are common and sometimes large.

The main point is that these stock levels are estimates. Storage volumes are not directly measured by the EIA. Circumstances change and algorithms that may have been reliable in the past have become progressively undependable.

Although I agree with the EIA that absolute stock levels are probably more correct than the underlying flows, unaccounted-for oil is a problem that the EIA has chosen not to acknowledge. Either inventory reductions are less than reported or the underlying flows are not accurate enough to account for those reductions.

Lacking unambiguous percentages, most of increased demand is because of exports. The potential to continue reducing inventories in this way is, therefore, limited by world capacity to absorb excess U.S. supply. Much of the increase in U.S. exports was possible because of temporary outages in places like Nigeria.

Meanwhile, the outlook for meaningful reductions in world over-supply seems questionable. OPEC’s output jumped almost 1 mmb/d above its target in July. Wood Mackenzie anticipates that global supply may increase almost 2 mmb/d in 2018 if the agreement does not hold.

Figure 7 is a synthesis of supply-production and demand-consumption data from the principal international reporting organizations. It suggests that the world supply surplus is likely to increase during the rest of 2017 and the first half of 2018. It further indicates that the second quarter of 2017 may be the only period of supply deficit for the next 17 months—that the last quarter was as good as it gets for quite awhile.

Figure 7. World Market Balance Suggests Increasing Over-Supply Going Forward. The Second Quarter of 2017 May Be The Only Under-Balanced Quarter Through 2018. Source: IEA, EIA, OPEC, BP and Labyrinth Consulting Services, Inc.

None of this is good news for continued high U.S. export levels. The last 5 weeks of data suggest that increased consumption may become more important going forward. It is more likely, however, that these elevated levels reflect temporary, higher seasonal consumption after lower-than-normal usage in the first half of the year.

The U.S. oil industry is justifiably proud of the ingenuity it used to survive the last 3 years of reduced commodity values. Technology, efficiency and lower oil-field service costs enabled increased production since September 2016 despite low oil prices.

Production growth, however, does not solve the underlying cause of low prices namely, over-supply. It makes it worse and prolongs lower prices.

I have no illusions that tight oil producers will willingly resort to business discipline. Only reduced access to capital will impose that necessary change on their behavior.


Permian Reserves May Be Much Smaller Than You Think

We are entering a new age of American energy dominance according to Energy Secretary Rick Perry. President Trump reflected that view in comments he made last week that “…we’ve got underneath us more oil than anybody, and nobody knew it until five years ago.”

Trump was referring to tight oil production and today, that means the Permian basin.

Global energy dominance by the United States is somewhere between aspirational and absurd.

So far in 2017, the U.S. has imported more than 9 million barrels of crude oil per day, and net imports have averaged more than 7.3 million barrels per day. How exactly can the world’s biggest importer of oil become the supplier upon which other countries depend?

The recently released BP Statistical Review Of World Energy 2017 places the United States 10th in the global ranking of oil reserve holders between Libya and Nigeria (Figure 1). That’s not bad but it hardly puts the U.S. in the same league as energy-dominant countries like Venezuela, Saudi Arabia, Canada, Iran, Iraq and Russia that have on average 4 times more proved reserves than the U.S.

Figure 1. The U.S. is the 10th Largest Oil Reserve Holder in the World. Source: BP and Labyrinth Consulting Services, Inc.

Perhaps the President and Secretary Perry have been reading John Mauldin’s recent work of magical realism Shale Oil: Another Layer of US Power. It features a chart which shows that the U.S. is the largest oil reserve holder in the world (Figure 2).

Figure 2. John Mauldin’s Recoverable Oil Reserves chart. Source: Mauldin Economics and Rystad Energy.

The chart is so wrong that it defies explanation.

Its Rystad Energy source data reveals that Mauldin has misrepresented recoverable resources—all oil regardless of commercial value–as reserves—a specific volume that is commercial at today’s oil prices.

It also seems that Mauldin didn’t show Rystad’s data correctly. Saudi Arabia—and not the U.S.—is the largest holder of recoverable resources according to Rystad (Figure 3).

Figure 3. Rystad Energy Global Oil Recoverable Resource Estimate. The chart shows Rystad’s 2PCX category: proved reserves plus contingent resources plus risked prospective resources in undiscovered fields. Source: Rystad Energy and Labyrinth Consulting Services, Inc.

Rystad’s P1 proved and P2 proved-plus-probable reserve estimates put the U.S. behind Saudi Arabia, Russia and Iran.

There are many other errors in Mauldin’s transcription of Rystad’s data that can be seen by comparing his chart as my Figure 2 with Rystad’s data in my Figure 3. That’s what happens when energy amateurs masquerade as energy experts.

Assessing the Growth Potential of the Permian Basin

So much for U.S. energy dominance today but what about the growth potential of the Permian basin?

Pioneer Natural Resources CEO Scott Sheffield claims that output may exceed 160 billion barrels of oil. Even credible sources like Wood Mackenzie believe that Permian Wolfcamp growth alone will add 3 million barrels per day by 2024.

The EIA, however, estimated that 2015 Permian tight oil reserves were only 782 million barrels (Table 1). That seems low and is considerably less than the 5 billion and 4.3 billion barrels attributed to the Bakken and Eagle Ford plays, respectively.

Table 1. EIA 2015 Tight Oil Reserves. Source: EIA U.S. Crude Oil and Natural Gas Proved Reserves, 2014

I estimate that there are approximately 3.7 billion barrels of proved Permian tight oil reserves using 2016 10-K SEC filings for leading operators in the plays (Table 2).

Table 2. Estimated 2016 Permian Basin Tight Oil Play Reserves. Source: Company 10-K Filings, Drilling Info and Labyrinth Consulting Services, Inc.

All the companies in Table 2 differentiated Permian reserves from other company reserves. Those companies accounted for 47% of all tight oil production in 2016. I used that as a scaling factor to estimate the contribution of companies such as Anadarko, Apache, EOG and OXY that did not separate Permian from other company reserves in their 10-K filings.

The estimate is grounded on a reliable base of 1.7 billion barrels from company filings. The assumption that unknown company reserves will follow 2016 production ratios is reasonable but uncertain.

I imagine that an estimate of only 3.7 billion barrels may surprise many who buy into the vision of American energy dominance. Others may accept the estimate but argue that Permian plays have significant growth potential that the Bakken and Eagle Ford do not.

Concho and Pioneer included tables in their 2016 10-Ks that projected future production from proven undeveloped (PUD) reserves. That data indicates that the two leading producers in the Permian tight oil plays anticipate PUD production to peak in 2019 (Figure 4).

Figure 4. Concho & Pioneer Proved Undeveloped Future Production Expected to Peak in 2019. Source: Company 10-K Filings and Labyrinth Consulting Services, Inc.

Concho’s and Pioneer’s combined peak 2019 PUD production volumes are approximately 25% of their combined 2016 daily production from the Permian basin. That means that the addition of future PUD production may only offset legacy production decline rates.

Anticipated PUD volumes are already included as proved reserves so however we view this data, it does not affect the implied reserves for the Permian basin. 10-K reserve and PUD production forecasts are based on 2016 SEC oil and gas prices. Higher prices would mean higher reserves and PUD production although few now anticipate substantial price changes over the period covered by Concho’s and Pioneer’s estimates.

Tank Theory

Permian tight oil reserves implied by this study are less than accepted estimates for the Bakken and Eagle Ford plays. Permian production, however, has already reached peak Eagle Ford levels and is still increasing (Figure 5).

Figure 5. Permian Tight Oil Production Has Reached The Eagle Ford Peak & Is Still Increasing. Source: Drilling Info and Labyrinth Consulting Services, Inc.

To many, this implies that Permian production will continue to increase and will eventually eclipse output from the older tight oil plays. That may be true but, without additional reserves from new plays or deeper layers, it may only reflect rate acceleration followed by steep decline once peak production is reached. Concho’s and Pioneer’s future production forecast suggests that peak production may occur sooner than later.

This study represents one scenario that may provide context for the claims and expectations about future production potential for the Permian basin.  Aside from weak growth in the offshore Gulf of Mexico, or some return to growth in the Bakken and Eagle Ford plays, it is the only current basis for the crude oil portion of emerging American energy dominance.

For the U.S. to move into the top tier of oil producing countries, reserves must at least double from accepted estimates by BP, EIA and other credible organizations (Figure 6).

Figure 6. The U.S. Must Double Reserves To Become an Oil-Dominant Producer Even Doubling or Tripling Permian Reserves Not Nearly Enough. Source: BP, EIA and Labyrinth Consulting Services, Inc.

In some upside scenario in which Permian reserves of 3.7 billion barrels somehow double or triple, that still will not be nearly enough for the U.S. to become energy dominant in oil.

Engineers commonly think of reserves as a tank—you can drain the tank with the best technology at very high rates, and perhaps make some money along the way, but ultimate production is limited by the size of the tank.

I have presented an estimate of tank size using as a basis data from the companies that know most about the plays. If it is even close to correct, American energy dominance should be recognized as just another expression of alternative facts.


Shale Gas Is Not A Revolution

Shale gas is not a revolution. It’s just another play with a somewhat higher cost structure but larger resource base than conventional gas.

The marginal cost of shale gas production is $4/mmBtu despite popular but incorrect narratives that it is lower. The average spot price of  gas has been $3.77 since shale gas became the sustaining factor in U.S. supply (2009-2017). Medium-term prices should logically average about $4/mmBtu.

A crucial consideration going forward, however, will be the availability of capital. Credit markets have been willing to support unprofitable shale gas drilling since the 2008 Financial Collapse. If that support continues, medium-term prices for gas may be lower, perhaps in the $3.25/mmBtu range. The average spot price for the last 7 months has been $3.13.

Gas supply models over the last 50 years have been consistently wrong. Over that period, experts all agreed that existing conditions of abundance or scarcity would define the foreseeable future. That led to billions of dollars of wasted investment on LNG import facilities.

Today, most experts assume that gas abundance and low price will define the next several decades because of shale gas. This had led to massive investment in LNG export facilities. Both the assumption and its investment corollary should be carefully examined through the lens of history.

The Lens of History

The last 40 years have been characterized by two periods of normal gas supply, and two periods of gas-resource scarcity. Supply was tight from 1980 through 1986, and gas prices averaged $5.57/mmBtu (all values in this report are in April 2017 dollars) (Figure 1). Normal supply was restored from 1987 through 1999, and gas prices averaged $3.24/mmBtu.

Figure 1. Cost Structure of Shale Gas Plays Consistent With 40-Year Natural Gas Average. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.

Scarcity returned from 2000 through 2008, and prices averaged $7.72/mmBtu. Shale gas production began with the Barnett Shale in the 1990s. Development of other shale gas plays culminating in the giant Marcellus completed the return to normal supply. Prices since 2009 have averaged $3.77/mmBtu.

Because prices fell about 50% with growth of shale gas production, many assume that shale gas is low-cost. That is only true compared with the preceding period of high prices that resulted from resource scarcity, but not compared with conventional gas prices during periods of normal supply.

The 40-year average gas price since 1976 has been $4.70/mmBtu. Excluding periods of resource scarcity, it has been $3.40. The average cost of conventional gas from 1987-2000 was $3.42/mmBtu. During the period of shale gas supply dominance (2009-2017), prices have averaged $3.77 (Figure 2).

Figure 2. Cost Structure of Shale Gas (2009-2017) Higher Than Conventional Gas 1987-2000. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.

Gas Supply Models Consistently Wrong and LNG The Wrong Solution

The lesson from history is that U.S. gas supply is highly uncertain. Normal supply characterized 60% of the period since 1976, but scarcity characterized the remaining 40%. During each episode of either normal or tight supply, experts agreed that existing conditions would define the long-term. They were consistently wrong.

Cheap, regulated natural gas was abundant in the 1950s and 1960s, and most analysts believed that this would be the case for decades. Abundance and low price led to demand growth of 283% (45 bcf/d) between 1950 and 1972 (Figure 3).

Figure 3. U.S. Gas Models Have Been Consistently Wrong For 50 Years. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.

Supply could not keep pace and there were acute shortages of gas during the winter of 1970. By 1977, shortages had grown to crisis proportions. Few saw this coming partly because of incorrect reserve estimates.

Experts agreed that scarcity would be the case for decades and that imported LNG was the only solution. Four LNG import terminals were built between 1971 and 1980. Limited gas supply led to a golden age of nuclear and coal-fired power plants that largely re-balanced the electricity market. Government subsidies and tax credits provided incentives to evaluate shale gas and coal-bed methane as alternative sources of natural gas.

The 1980s and 1990s were a period of great stability in natural gas prices. Increased pipeline imports from Canada gave the false impression that, once again, there was cheap and abundant natural gas for decades to come. All LNG plants were closed and some were used for gas storage.

Amendments to the Clean Air Act in 1990 caused many power plants to switch to natural gas to replace coal. Demand for natural gas increased 40% (15 bcf/d) but production did not keep pace with demand growth despite increased gas-directed drilling.

Canadian and U.S. gas production peaked in 2001 and by 2003, LNG import terminals were re-opened and capacity was expanded. More than 42 additional import facilities were proposed between 2001-2006. Seven were built. Experts agreed that LNG import was, once again, the only solution to the gas-supply problem.

The first long-lateral horizontal wells were drilled in the Barnett Shale in 2003. By late 2006, shale gas production in the Barnett, Fayetteville and other shale gas plays exceeded 4 bcf/d and confounded not only the U.S. LNG import market but also the global LNG industry that had planned on the U.S. being the market of last resort.

In every supply cycle, major investments in LNG were either undertaken or abandoned. Total installed LNG import capacity reached 18.7 bcf/d but imports averaged only 1.3 bcf/d from 2000-2008 and never exceeded 2.1 bcf/d. That’s an average utilization of 7% and a maximum of 11%. The original cost for the terminals was approximately $18 billion. How could industry analysts, company executives and investors get things so wrong?

Now, experts agree that, because of production from shale, gas will be abundant and cheap forever. LNG exports began in early 2016, and the U.S. became a net exporter of gas in April 2017. Seven previously failed import facilities are being converted for LNG export at an anticipated cost of approximately $48 billion. Three other export terminals have been approved by the Department of Energy (Figure 4) and applications for a total of 42 export terminals and capacity expansions have been approved.

Figure 4. North American LNG Import/Export Terminals Approved. Source: FERC.

The total of approved export applications amounts to more than 54 bcf/d75% of U.S. dry gas production. Daily U.S. dry gas production in 2016 was 72 bcf/d. Are we repeating the mistakes of LNG import in reverse?

The Natural Gas Act (1938) states that the Department of Energy should approve an application unless “the proposed exportation or importation will not be consistent with the public interest.”  It is, therefore, not a question of whether or not to regulate but rather, how to regulate in the public interest. Approving LNG export applications for 75% of U.S. production does not seem to be in the public interest from either a supply security or gas price standpoint.

Shale Gas Marginal Cost 

Shale gas producers have been making exaggerated claims about low-cost supply for so long that markets now believe them. Sell-side analysts routinely gush about sub-$3 break-even prices despite corporate income statements and balance sheets that show otherwise. Marcellus leaders Cabot, Range and Antero spent an average of $1.43 for every dollar they earned in 2016; Chesapeake had negative earnings for the year—it couldn’t even pay for operating expenses out of revenues before capital expenditures and other costs.

Rig count is a direct indicator of how oil and gas producers choose to allocate capital. It is, therefore, a simple way to judge marginal costs by how companies “vote with their feet.” Horizontal shale gas rig counts remained fairly flat in 2014 when gas prices fell from more than $6/mmBtu to $4 (Figure 5). Rig counts collapsed, however, when prices fell below $4.

Figure 5. Shale Gas Plays Have $4 Marginal Cost. Source: EIA, Baker Hughes and Labyrinth Consulting Services, Inc.

Gas prices reached a weekly average low price of $1.57/mmBtu in February 2016 and then, rose consistently through the end of 2016. Shale gas rig counts doubled on expectation of $4 gas prices but flattened when prices failed to reach that threshold. The implication is that the marginal cost of shale gas is approximately $4/mmBtu.

The Bearish Scenario

Most gas-market observers anticipate a supply glut and gas-price collapse beginning late in 2017 because of new pipeline take-away capacity from the Marcellus-Utica plays. Associated gas from tight oil plays—the Permian basin in particular—is expected to extend this bearish view some years into the future.

Forward curves reflect this perspective. Their term structure is inverted meaning that near-term futures prices are higher than longer-term prices (Figure 6). Market traders are betting that winter gas prices will peak between $3.25 and $3.50/mmBtu and fall below $3 in early 2018. The volume of contracts beyond May 2018 approaches zero so the picture of worsening prices is speculative even a year into the future.

Figure 6. Henry Hub Forward Curves Are Currently in the $2.70 to $3.30/mmBtu Range. Source: CME and Labyrinth Consulting Services, Inc.

The bearish scenario will be disastrous for producers whose share prices have fallen nearly 30% already in 2017 (Figure 7). Although investors have been willing to fund the unprofitable efforts of these companies for many years, I suspect that their patience is wearing about as thin as it has lately for tight oil.

Figure 7. Natural Gas Equity Shares Have Fallen 29% Since January 2017. Source: Google Finance and Labyrinth Consulting Services, Inc.

Some analysts incorrectly believe that shale gas producers have already pushed costs so low through technology and efficiency innovation that sub-$3 gas prices will become the new normal. Although it is true that costs have fallen substantially, than because of deflationary pricing by the service industry and less because of  technology and innovation.

In fact, the technology that enables unconventional oil and gas production resulted in a 4-fold increase in oil and gas drilling costs from 2003 to 2014 (Figure 8). Depressed demand since 2014 has resulted in a 45% reduction in drilling costs and this accounts for most savings.

Figure 8. The Cost of Drilling Oil and Gas Wells Fell 45% After The Oil-Price Collapse. Unconventional Plays Resulted in a 4-fold Increase in Drilling Costs. Source: U.S. Federal Reserve Bank, EIA and Labyrinth Consulting Services, Inc.

I have little doubt that there will be downward pressure on gas prices in the near term but do not see how sub-$3 prices can become the new normal. Producers have send-or-pay agreements with the pipelines that will carry new supply from the Marcellus and Utica plays. Some of these projects will probably deliver gas to Canada and LNG export markets having limited effect on domestic supply. Similarly, much future Permian basin gas will likely go to Mexico. New supply from the Marcellus and Utica plays will inevitably force gas from higher cost plays out of the market.

New volumes that enter the domestic market must first overcome the present supply deficit (Figure 9). Gas production fell more than 4 bcf/d from February 2016 to January 2017. EIA forecasts that production will increase 4.7 bcf/d in 2017 but only 1.9 bcf/d in 2018. EIA anticipates monthly average prices above $3.00 in 2018 ending the year at $3.66/mmBtu.

Figure 9. EIA Forecast: Supply Deficit & Prices Rising to $3.66 By December 2018. Source: EIA June 2017 STEO and Labyrinth Consulting Services, Inc.

This is only a forecast and certainly incorrect in its details but EIA’s domestic gas forecasts have been notionally reliable over the past several years. Increased consumption and exports should keep supplies relatively tight, and prices reasonably strong.

Broadcast The Boom Boom Boom and Make ‘Em All Dance To It

Since the early 2000s, producers and analysts have proclaimed that shale gas is a “game-changing,” end of history-type phenomenon. From now on, natural gas will be abundant and cheap. The United States was running out of natural gas before 2009 but now can afford to export to the world. We were lost but now are found.

In late March, Morgan Stanley analysts wrote that Haynesville Shale “break-evens now sit comfortably below $3/MMBtu” and Marcellus-Utica “break-evens range from $1.50 to $2.50/MMBtu.” Yet, with average gas prices above $3 for the last 7 months, none of that good news can be found in the balance sheets and income statements of the main producers in those plays.

Shale gas companies spent an average of $1.42 for every dollar they earned in the first quarter of 2017 (Figure 10). That average excludes Gulfport and Chesapeake whose capital expenditure-to-cash flow ratio was 10.7 and 5.4, respectively. Including those two operators, companies spent $2.12 for every dollar they earned. It doesn’t seem like even $3 gas is working very well.

Figure 10. Shale Gas Companies Spent $1.42 For Every Dollar Earned in Q1 2017 Excluding Gulfport and Chesapeake; $2.12 for Every Dollar Including Gulfport and Chesapeake. Source: Google Finance and Labyrinth Consulting Services, Inc.

Bernstein Research published a report in May (“Inventory a plenty in Appalachia- we estimate at least 20 years of drilling remain”) that predicted 19-37 years of Marcellus-Utica “inventory at a steady-state production profile of 36 Bcfd”—current production is about 24 bcf/d. I know of no other oil or gas field in the history of the world with a trajectory of increasing production for so long.

That’s because Bernstein has made a technically recoverable resource estimate with quite optimistic spacing assumptions.*  The report does not tell us anything about gas volumes that are commercial to produce at a some gas price.

To place this and other sell-side reports in context, I re-visited the Bureau of Economic Geology’s (BEG) production forecast for the Barnett Shale published in 2013. The BEG study determined individual well reserves and economics for 15,000 Barnett wells at $4 gas prices.

Figure 11 shows that actual Barnett production (from Drilling Info) has fallen far short of the BEG forecast and will probably result in much-reduced ultimate recoveries. That is not because the BEG study was flawed but because gas prices have been lower than the $4/mmBtu price assumed in their forecast.

Figure 11. Comparison of Bureau of Economic Geology (BEG) Barnett Shale Production Forecast and Actual Barnett Production. Source: Bureau of Economic Geology, Drilling Info and Labyrinth Consulting Services, Inc.

If Barnett production varies so much from the BEG’s scrupulous analysis and forecast, how can we have confidence in less rigorous analyst reports that call for for decades of cheap, abundant shale-gas supply?

The Barnett and Fayetteville shale plays are dead at current prices because their core areas have been fully developed. Rig counts reflect this unavoidable reality (Figure 12). Considerable resources remain but not at sub-$4 gas prices. The Marcellus and Utica will inevitably meet the same fate–all fields do. Higher marginal cost of production outside the core will result in more supply but will also require higher gas prices to develop and produce.

Figure 12. Barnett & Fayetteville Have Much Higher Marginal Costs Than Marcellus, Utica or Haynesville: Barnett-Fayetteville Core Areas Are Fully Developed. Source: EIA, Baker Hughes and Labyrinth Consulting Services, Inc.

Few analysts seem to consider the economics of shale gas as a limiting factor to output and, therefore, to supply. Perhaps they actually believe the phony economics that lead to supposed break-even prices for the Marcellus and Utica in the $1.50 to $2.00 range.

But price matters and production growth lags price change by approximately 10 months. Gas prices fell below $4 in late 2014, and about 10 months later, production growth slowed from almost 7% to 1% (Figure 13). Gas supply is fairly tight today because year-over-year production growth has been negative for 14 consecutive months.

Figure 13. Production Response Lags Price Change by ~10 months. Source: EIA, U.S. Dept. of Labor Statistics and Labyrinth Consulting Services, Inc.

Gas production has increased since January, and the EIA forecasts that this will continue through 2018. Yet, EIA data also indicates continuing tight supply. That is because demand is increasing while pipeline and LNG exports are increasing.

Most analysts believe that gas prices will collapse in early 2018 as new Marcellus and Utica pipelines bring new supply to market. That may be for the short term but evidence suggests that gas prices will recover and remain fairly strong over the medium term. After one of the mildest winters in history, gas prices remain in the $3.00/mmBtu range and comparative inventories have fallen for 3 consecutive weeks.

Production growth, rig count data and company balance sheets all indicate that the marginal cost of shale gas production is about $4/mmBtu. Yet, most analysts say it isn’t so. Gas supply and price models have been consistently wrong for 5 decades. Yet, this time it will be different. LNG import terminals were investment fiascos but LNG export will be a great success.

All ruling theories falter and are replaced by new paradigms. It is unlikely that shale gas will be an exception.

There are wildcards that might prolong the shale gas phenomenon. Increased associated gas from tight oil plays particularly in the Permian basin might provide a few more years of proxy shale gas supply.  Today, much of that gas is flared to avoid tie-in and processing expenses. Almost 40% of current Permian gas goes to Mexico, and it is reasonable that more future Permian gas will be exported than face gas-on-gas competition in other regions of the U.S.  In addition, optimistic forecasts for Permian gas assume $60/barrel oil prices that now seem increasingly unlikely.

Credit markets are another wildcard. Investors have been willing to look past evidence that shale gas is unprofitable. This is based largely on the expectation that negative cash flow is normal during field development and that profits will come later. The problem with this is that shale gas decline rates average about 30% and capital expenditures never end.

The lens of history places shale gas in its proper perspective. The plays are not lower-cost than conventional gas plays. They are only low-cost compared with higher prices that resulted from depletion of conventional gas plays in the early 2000s.

Shale gas is not a revolution but it bought the U.S. a decade or so of normal supply before facing another period of gas scarcity.

The plays are large but finite, and price matters. The industry has abandoned the early shale gas plays—the Barnett and Fayetteville—because their core areas are fully developed, and the cost to develop marginal resources is higher than it is in the the core areas of the Marcellus and Utica plays.

Those newer plays will follow the same pattern of growth, peak and slow decline as the Barnett and Fayetteville, as all plays have in the long history of the oil and gas industry. The idea that shale plays are somehow different defies the well-established laws of earth physics and depletion.

The shale gas story claims success based on resource size but not reserves. It emphasizes production volumes but not the cost of that production. Its champions focus on the technology that makes the plays possible but not the cost of that technology. Break-even prices are discussed rather than profits because the plays are not profitable. No smart investor puts his money in break-even projects anyway. When economics are addressed, analysts and industry exclude important expenses that we are told are sunk and can, therefore, be ignored.

The shale gas story is accepted because it paints a picture that fulfills aspirations of American energy independence, re-emerging political strength, and economic growth.

If the story is repeated enough, maybe it will become true.

Broadcast the boom, boom, boom and make ’em all dance to it.*

*Bernstein considers 100-acre spacing conservative. Assumed average-well EUR of 17 bcf suggests a much larger drainage area to me and, therefore, full development at a much lower well density than 100-acres per well.

*Lorde, “At The Louvre.”


I do not have any investments that are affected by the outcome of shale gas plays.

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