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.


  • Vince

    Excellent insight as always Art! The easy money conditions seem to have really messed up the nat gas market. These oil and natural gas producers are trading at high multiples or have no multiples. With the rig count strongly picking up during a period of declining oil prices, I’m leaning to a correction in oil lasting longer. These guys seem pretty confident when taking into account the drubbing they got in 2015.

    EMES has been absolutely clobbered but the analysts have not changed opinion at all or earnings outlook. How good are these guys? I don’t have a lot of experience looking at the sector. Seems to me the analysts are somewhat contrarian indicators.

    • Arthur Berman


      Oil prices were crushed today, supposedly because Russia said it would not consider further production cuts. My take is that short covering got a little carried away and prices got a bit too high. The comparative inventory vs WTI plot has indicated $45 as the right price for some time.


      All the best,


  • HS

    If it’s not a revolution, what is it? Ask the executives in the coal industry whether shale is a revolution. Ask the Saudi royal family if it’s not a revolution…or might lead to one.

    Art, I respect your geological point of view. You do yourself a disservice by making headline grabbing statements that are, at best, a stretch (I know someone else that should refrain from these). Whether anyone makes money at this price, doesn’t negate the fact that the combination of hydraulic fracturing and horizontal drilling (as often applied to shale) is a revolution. North American gas has been most impacted by this technology for a variety of reasons.

    How long it lasts, what it costs to develop, and how that cost changes over time are important and complex subjects. But the fact is this technology has been having a major impact for well over a decade. You can take the long view and say this decade+ will be a blip in history (I will remind you that there is a bit over a century of history in the whole gas industry and some might consider that a blip in history), but the reality is that even you are saying that $4/mmBtu is where you think producers will add lots of rigs. So let me ask the question another way: where would gas prices in the US be today if hydraulic fracturing hadn’t been successfully combined with horizontal drilling?

    Now if you’re making a call that we are going back to $6+/mmBtu gas in the US within the next five years, then I would very much like to hear the logic behind that. I won’t dismiss it unless I’ve read the logic. But that doesn’t sound like what you’re saying, and I think we’d be above that price without “shale”.

    It is true that there are other commodities that have gone through long peaks only to suffer very large declines like occurred in gas (e.g. iron ore, uranium), but everyone in those businesses knew the clock was ticking on the very long cycles they had experienced. If you sat them down, no one would have told you the world was going to run out of iron, or even low-cost iron. What they would have told you is that it takes a very long time to get mine up and running.

    Now we can go with the age old platitude that the cure for high prices is high prices and something else would have come along to drive down gas prices, but you don’t really believe that do you? I don’t think the coal guys believe that something is coming to save them. That doesn’t mean it won’t, but if it does, it will be either higher gas prices or another technological revolution. It doesn’t have to happen.

    And my guess is that the next technological revolution in energy will involve energy storage, rather than production, but who knows.


    • Arthur Berman


      I respect your comments and perspective.

      The lead photo and quote on my website has been “Shale is not a revolution–it’s a retirement party” since early 2014 and I have used a similar phrase in public presentations as early as 2011. That doesn’t make it right but it is my public opinion and has been for 5 years or more.

      The coal industry has been dying a slow death for decades. There hasn’t been a new coal mine in the U.S. (until just recently) for something like 30 years or more and coal jobs have been declining since the 1950s. Environmental concerns are killing coal along with the fact that there are cleaner alternatives. The first body blow was the 1990 amendments to the Clean Air Act–before shale gas was more than George Mitchell’s science project.

      You can call anything a revolution but in this case, we’re just talking about price. Shale gas reset gas price back to where it was before the scarcity of the early 2000s.

      I certainly didn’t choose the title of this post to be sensational. My work is too detailed and technical to appeal to sensational types (my version of the post on Forbes has a whopping 469 views so far today–my own site as a little over 1000).

      All the best,


  • HS

    For the record, I said nothing about jobs in coal. Those were destined to disappear, regardless of what certain politicians would like to pretend, and efficiency and technological innovation were the root causes of the disappearance. Environmental regulation had very little to do with it over any decent stretch of time.

    Regardless, in 2008 coal was the source of about 50% of electricity generation, while natural gas accounted for 17%. As a point of reference this was about the same % for both sources as the average of the prior 60 years, and at no point did natural gas ever come close to coal as a source. Today, natural gas has crossed over to be a more important source than coal. This is not a coincidence. Did environmental regulation hasten the retirement of some coal power plants? Of course. But do you think this would have happened if gas prices had stayed elevated? I don’t. People tolerate environmental regulation easily when it’s easy to tolerate. Once you tell them their electricity cost is going to double, they don’t tolerate it as well.

    As for your comments about this being just about price, I’m not sure what you’re getting at. Is the electricity supposed to make me dinner at night too (to be considered a technological revolution)? Other than price, was kerosene any better than whale oil? I’ve heard some people preferred the latter…

    All the best,

  • Conrad E Maher

    Thank you again for another great article and bringing clarity to the long term supply/demand/price of natural gas. My work for nearly 50 years was more on exploration/development and improving recovery of oil. The longer term price and supply of natural gas was always more of a mystery. It appears that I never had/took the time to understand all the things that effect the price/supply of this commodity to achieve what you have done with this article. I do remember in the 1960’s that gas plays could not be sold as a gas play. The emphasis was placed on the possibility of the play being oil or having an oil leg to get it plays drilled. This might have resulted in a greater gas supply.

    That oil and gas executives make very bad decisions based on ‘gut feelings’ was observed many times during my career. This led to some research and effort to understand what these executives were doing when making longer term decisions.

    There is no such thing as a gut feeling. With sufficient relevant knowledge and experience better decisions can be made. Lacking such a background, ‘gut feeling’ decisions are mostly a mixture of 3 martini lunches and too much rich, spicy food coupled with the arrogance of ignoring the recommendations of people with much better relevant knowledge/experience. It can be further compounded with remuneration so high that they confuse/combine gut feeling with direct communication with an all knowing supreme being who addresses them as Sir.

    • Arthur Berman


      Thanks for your comments and observations. People make generally poor decisions although they think their decisions are logical. Kahneman and Tversky systematically showed how most decisions are based on heuristics and their footprint, biases. Our brains still function as they did when we were hunter gatherers on the savannah.

      All the best,


  • There is something else at stake and it is the price of energy for a complex system to work and not start to fall apart.
    I do not know those prices, but today it is not possible to speak of a particular country, but rather to think globally. This is because it would not be useful if X country has a cheaper price of energy if other countries do not have these prices and their economy shrinks and their imports deteriorate for example.
    I understand that the issue is global and the variation of energy prices, even if they are moderate, have repercussions today and will be reflected more and more in the global society.
    I do not know if I’m right
    I do not want to stop saying something about “fundamental structures” such as roads, bridges, power plants, electricity grid, effluent network, etc.
    There, too, large investments must be made to make them work.
    The other day I read that in New York there are still parts of the gas pipes that are very old, they are made of iron, and they produce serious accidents. The problem is that you can only change between 80 and 100 km of pipes per year when there are more than 3000 km in total.
    Sometimes we do not realize that New York is the oldest modern city in the world.
    On the other hand leave in the previous post a question about the investment in research and development of new fields of oil made by Chris Materson and wanted to know your opinion Art.
    Best regards and thanks for always being so clear in your articles and kind in your responses to us
    My English is not so good as to talk about such specific topics I hope you understand.

    • Arthur Berman


      It is good to hear your perspective on global energy networks.

      Many years ago, I read Ilya Prigogine’s work on dissipative structures, and how increasing growth and structural complexity in certain organisms requires a huge expansion in energy needed to maintain all of the new connections. Eventually, the organism must spontaneously modify its architecture or die.

      I think that is a reasonable model for human society. Mostly because of petroleum, we have greatly expanded our work efficiency and our population. Now, the cost of energy is higher (even though oil is relatively cheap compared with the record high prices of 2011-2014), the gains from petroleum have flattened, and the world has taken on massive debt, essentially selling forward its limited surplus energy to make it more affordable in the present.

      A major re-structuring and de-complexification is required such as Prigogine described for micro-organisms. That involves a substantial decrease in population which will decrease economic growth. All of this will be very painful in the near term but necessary for survival.

      All the best,


  • Anonymous

    1. Natgas averaged 3.12 from 2012 to now. That is much lower than what it averaged from mid-decade to 2009. So you need to look at the trend, not just the average over a long time frame. Note, that this happened WHILE consumption expanded strongly, not because of a demand contraction. So in the face of expanded usage, price dropped. That is a major supply story.

    2. Shale gas is now over 40% of total US nat gas. That is a dramatic development. I don’t think “revolution is overstating it. The conversion of LNG import to export terminals is case in point.

    3. Peak gas people were way, way, way off on their predictions for US gas supply. You can go to youtube and listen to David Hughes 2006 ASPO presentation on peak gas for this perspective.

    4. You are correct that 1.50-2 is not realisting for the Appalachian basin overall. And that 3 may be a little difficult for the Haynesville. I think we have seen enough behavior (production changes, drilling rig moves) to see that the Haynesville does turn on at 3.50 though. And the App seems to get by at 2.50 (look at in basin price, not HH for the App). The Haynesville is interesting in particular as it was pointed out a lot by peak oil types (including yourself) as an example of growth and peak and decline. But if you look at the last 3 years, the decline has actually arrested and it is more of a long plateau. See the EIA data for instance.

    5. You seem to have adjusted your thinking (although still positioning yourself as critical). For instance on The Oil Drum, you said that shale gas needed $8+ to work. And you had an article titled The Marcellus Will Dissapoint in ~2010. The Marcellus has been a world class resource and I don’t see how the heck you can call the growth from 2010 to now a “disappointment”. Although you have walked back from some of your comments, you haven’t really acknowledged them, that you were wrong and in which direction you were wrong.

    6. This piece is a cogent, easy to read article on the downfall of peak gas.

    • Arthur Berman

      Unlike ideologues, I am a scientist. When new data is available, I modify my interpretations.

      Shale gas plays have made progress but you don’t seem to have read the post very carefully.

      Production volumes, break-even prices, lower gas prices over some selective window are not relevant when the shale gas companies are losing money. When their financial data reflects success, I will modify my interpretation and write about that.

      I considered discussing Zeits’ terrible article in the post.

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

      You dance very well—and are courageously anonymous!

      All the best,


  • Anonymous

    7. Also look at the rig count. It goes up and down in response to price. But we seem last couple years to be able to maintain US production with only 200 dedicated gas rigs. That is AMAZING productivity. That is keeping the Red Queen at bay with both feet tied and one hand behind the back. It is the opposite of a narrative that reflects drilling out core sections and moving to poor rock.

  • Yoshua

    The options were to import LNG at $10/MMBTU or to finance shale gas at $4/MMBTU.

    Even if shale gas production is uneconomic and losing money it was the better option.

    Wall Street might be financing a project that is losing money, but without nat gas the economy would collapse and with that Wall Street would collapse as well.

    • Arthur Berman

      I didn’t know that investment bankers and their clients were in business to underwrite the public good. Thanks Wall Street!

  • Anonymous

    You know all it will take is another dollar downward revision of your Bayesian expectations to be about in line with the market. Anyway, good to see that when the cold hard facts pound on you hard enough you do listen. That puts you above the crazier peakers who just put fingers in ears.

    Then again, there is a consistent pattern with how you are wrong. Like someone who counts change wrong always in the same direction. Maybe you should think about that. Are your wishes affecting your analysis? It is a phenomenon called wishcasting.

    • Arthur Berman

      I have no vested interest in a negative outcome for shale gas or tight oil plays. The plays are marginally profitable at best, as their predecessor unconventional plays were and are–tight gas, coal-bed methane, oil sands and deep water. There’s not a thing wrong with that but you have to be really careful about spending to eke out a small margin. The shale players have been profligate.

      When I say that the plays are doing better, that is because costs have come down for everyone. Did you think about Figure 8?


      Years ago, I said that shale gas needed ~$8 gas price to break even. Now, the plays need $4 gas because drilling costs are almost half of what they were when I wrote the earlier piece in The Oil Drum.

      As I said before–assuming you are the same anonymous as the other commenter–when the companies make money, I will write about that. Until then, you can accuse me of “wishcasting” a negative outcome but you are without basis that does not involve distorted economics inconsistent with the companies’ own income statements and balance sheets.

      You are fond of name calling. In addition to calling me a wishcster, you call me a “peaker.” Where in this post do I mention or allude to peak anything? Do call me a peaker because I wrote on The Oil Drum or because I was involved with The Association for the Study of Peak Oil?

      Do you understand what peak oil is about because most people don’t and it’s not about running out of oil.

      Peak oil is about the end of cheap oil. The End of Cheap Oil was the title of Campbell and Laherrere’s 1998 paper. Look at Figure 8. Is there a different conclusion that I am missing. That doesn’t mean I am an ideologue. It is an objective observation.

      This site is a place for dialogue not name calling. I am open to criticism and disagreement.

      Calling me names will get your comments unapproved in the future. I have only unapproved one commenter in a decade. You may have the distinction of being number 2 if you don’t behave professionally.


  • Anonymous

    Colin Campbell has a record of bad predictions on peak oil. Always in same direction…

  • Jesse

    Another cracker of an article Art. Thank you very much for posting.

  • Yoshua

    Wall Street had to be bailed out after the Financial Crisis by the Fed and the Government and the economy is now on government life support.

    The financial system is broken. The same thing is true for the financial system in Europe.

    So, Wall Street is perhaps not the right name. “Wall Street” is now working for the public good.

    Wasn’t there a report that leaked that showed that the Fed had ordered the banks to continue to support the oil & gas industry after the oil price collapse ?

    The shale gas production cost has fallen from $8/MMBTU to $4/MMBTU with the collapse of the oil price ? I didn’t know that.

    I just follow this subject with interest from the outside of the banking and energy industry.


  • Jeff

    Art- For the BEG study “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.”

    Are you saying the reserve estimates are OK (study not flawed) but only the timing of production of reserves is delayed? On the right hand scale of Fig 11 you have the number of completions per year. Which line in the graph corresponds to the number of completions? ( Is data available for the number of completions for the BEG study or the actual results? ) Since the BEG price forecast was too optimistic in the study, are you implying that the # of completions was therefore less than the study had estimated because economics would not justify the completions which is for the missed production forecast?

    In Figure 9, do you agree with the EIA forecast that the US will be in supply deficit through the end of 2018? If this is the case, why doesn’t the price forecast show a more dramatic price increase that has been more typical of previous supply deficits?
    thank you

  • I like you see this part of text of Wolf Ricther. Are we growing? or Are we at Disneyland?

    “Since July 2012 – so over the past five years – the trailing 12-month earnings per share of all the companies in the S&P 500 index rose just 12% in total. Or just over 2% per year on average. Or barely at the rate of inflation – nothing more.

    These are not earnings under the Generally Accepted Accounting Principles (GAAP) but “adjusted earnings” as reported by companies to make their earnings look better. Not all companies report “adjusted earnings.” Some just stick to GAAP earnings and live with the consequences. But many others also report “adjusted earnings,” and that’s what Wall Street propagates. “Adjusted earnings” are earnings with the bad stuff adjusted out of them, at the will of management. They generally display earnings in the most favorable light – hence significantly higher earnings than under GAAP.

    This is the most optimistic earnings number. It’s the number that data provider FactSet uses for its analyses, and these adjusted earnings seen in the most favorable light grew only a little over 2% per year on average for the S&P 500 companies over the past five years, or 12% in total.

    Yet, over the same period, the S&P 500 Index itself soared 80%.

    And these adjusted earnings are now back where they’d been on March 2014, with no growth whatsoever. Total stagnation, even for adjusted earnings. And yet, over the same three-plus years, the S&P 500 index has soared 33%.”

    • Arthur Berman


      I ignore statements of “net income,” “profit” or “adjusted earnings” because they ordinarily involve accounting methods or tricks that are beyond my level of sophistication. To make matters worse, oil companies use at least 2 methods of accounting–“full cost” and “successful efforts.” These different approaches result in big differences to outcomes like net income, etc.

      The simplest and most diagnostic approach is to evaluate net cash flow by subtracting capital expenditures from cash from operations. Those numbers are not affected by different accounting methods or terminology. If the number is positive, the company is making money and vice versa. There may be legitimate reasons why a company has negative cash flow in a given quarter or series of quarters but it still is losing money.

      The shale gas and tight oil companies have–as a group and individually with few exceptions–had negative cash flow forever. That’s the bottom line. They can talk about low break-even prices, technology and efficiency all they want but if these never show up in their balance sheets as positive cash flow, who cares?

      Capital expenditures and cash from operations can easily be found on Google or Yahoo Finance by selecting the company in question, choosing Financials > Cash Flow and then, choosing either Quarterly or Annual Data.

      All the best,


  • Timo Puts

    Good points Art, as always. I very much appreciate your in depth analysis in an industry infused with such hype and screaming excitement(just found your blog a few weeks ago).

    If I may be so bold, could you give your quick(or extensive) thoughts on the situation in the offshore industry: Isn’t shale a viable alternative for part of the 30% of oil now being produced offshore? What do you think of the levels of capex? When comparative inventories decline in the u.s. will drilling have to pick up quickly(I see capex being projected to decline until 2020 absolutely and relative to onshore). Is there light at the end of the inventory tunnel for offshore in short? Is it just another cycle?

    Also, have you taken a look at the developments concerning ev’s? They could replace about 25% of the future oil demand combined with for example solar pv in the coming decades.

    Whether or not you can answer any of these question, thank you very much for your work!

    Timo Puts(Europe)

  • Heinrich Leopold


    Your view has been confirmed by the recent announcement of BHP Billition, which regrets its USD 20 bn investment in shale gas and oil. It made an USD 13bn impairment in its latest quarter and it looks like more impairments are to come. BHP has an excellent accounting department and they would have been more than excited to publish a success of its investment rather than its humiliating loss.

  • Anonymous

    I don´t know if is posible put a link, buy may be interestig for Art and the people here:

    $2 billion energy investment goes bust in rare complete failure of private equity fund

    A $2 billion EnerVest fund that invested in oil and gas wells has essentially gone bust.
    Major pensions and other investors could be left with just pennies on the dollar at best.
    The loss is unusual for a private equity firm of EnerVest’s size and raises concerns that similar funds offered by competitors could fail.

  • Ken

    Hi Art

    Great article. The vagaries of marginal cost pricing for commodities are a real challenge for making drilling decisions. It is not unexpected that the “land grab” theory of exploration leads to poor pricing early on. As you say, these prices will correct upwards over time – unless even better resources are discovered that require yet another loss leader investment.
    The US is as you explain in a bad position with respect to gas resources – in oil our loss making shale plays at least compel the OPEC and Russia to lower their prices to our benefit and other consuming nations are along for the ride. In gas, the US is inflicting damage to our own resource base and throwing good money after bad. I guess Wall Street is “helping” main street consumers…..
    What is your sense of gas price trends over the next decade or so? All my sources and reading indicate that Marcellus and Utica will dominate US production for at least that time frame and costs are likely sub $3/mcf. You suggest $4 breakeven at the margin. That’s a big step up. A related question is gas to coal switching economics and its impact of gas demand and gas pricing. Any thoughts on that?

  • Stanley Reitsma


    thank you again for your significant insights.

    I have one question.

    – NG production declined from 1970 to 1986 – probably due in part to reduced associate gas production
    – NG supply increased from 1986-2002 due in part to price although stable and increased imports from Canada
    – NG production declined from 2002-2006 despite incredible gas prices (maybe if I remember even to the panic of many within the energy sectors)
    – NG production increased from 2006-2016 (and maybe will continue to grow but jury remains because we have seen a decline but likely for a while) due to shale gas production, meanwhile conventional production has been in serious decline since 2002.

    Now the question. Is there another gas resource after shale? If not (sorry two questions), what happens when shale gas production goes into decline?

    I just cannot help but see where this is going to go despite all the boom, boom, boom of energy rhetoric.

    As always, I look forward to your posts!

  • Anonymous

    EIA data, HH spot:
    2017: 2.99
    2018: 3.15
    2019: 2.56

    Seems like $4 is taking it’s time getting here. Has been three years since this article. Maybe we see 4+ in snaps from weather. But sustained?

    In all seriousness, do you still believe the 4+ sustained or have you changed your views, based on recent data? Either is OK, but if you are still holding a candle for 4+, need a clear explanation why. It’s one thing to have a strong hypothesis, but eventually enough data should move you to change your position.

    P.s. Check out the Haynesville. It repeaked even higher than previous peak. And that, with prices sub 4. Go Jerruh?

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