No Joy in Mudville*: Shale Gas Stalls, LNG Export Dead On Arrival

Something unusual happened while we were focused on the global oil-price collapse–the increase in U.S. shale gas production stalled (Figure 1).

U.S. Shale Gas Prod 30 July 2015
Figure 1. U.S. shale gas production.  Source:  EIA and Labyrinth Consulting Services, Inc.
(click image to enlarge)

Total shale gas production for June was basically flat compared with May–down 900 mcf/d or -0.1% (Table 1).

Shale Gas Prod Change Table 30 July 2015
Table 1. Shale gas production change table.  Source:  EIA and Labyrinth Consulting Services, Inc.
(click image to enlarge)

Marcellus and Utica production increased very slightly over May, 1.1 and 1.5 mmcf/d, respectively. The Woodford was up 400 mcf/d and “other” shale increased 300 mcf/d. Production in the few plays that increased totaled 3.3 mmcf/d or one fair gas well’s daily production.

The rest of the shale gas plays declined.  The earliest big shale gas plays–the Barnett, Fayetteville and Haynesville–were down 25%, 14% and 48% from their respective peak production levels for a total decline of -4.8 bcf/d since January 2012.

The fact that Eagle Ford and Bakken gas production declined suggests tight oil production may finally be declining as well.

To make matters worse, total U.S. dry natural gas production declined -144 mmcf/d in June compared to May, and -1.2 bcf/d compared to April (Figure 2). Marketed gas declined -117 mmcf/d compared to May and -1 bcf/d compared to April.

Chart_U.S. Natural Gas Prod 30 July 2015
Figure 2. U.S. natural gas production.  Source:  EIA and Labyrinth Consulting Services, Inc.
(click image to enlarge)

Although year-over-year gas production has increased, the rate of growth has decreased systematically from 13% in December 2014 to 5% in June 2015 (Figure 3).

Chart_Dry Gas YOY 30 July 2015
Figure 3. U.S. dry gas year-over-year production change.  Source:  EIA and Labyrinth Consulting Services, Inc.
(click image to enlarge)

This all comes at a time when the U.S. is using more natural gas for electric power generation. In April 2015, natural gas used to produce electricity (32% of total) exceeded coal (30% of total) for the first time (Figure 4).

Figure 4.  Monthly shares of total power generation by fuel, 2001-2015.  Source: EIA.

This is partly because of low natural gas prices but is mostly because of EPA clean air regulations that went into full effect in 2015 that are forcing retirements of older coal plants.

For now at least, the U.S. is producing less natural gas because shale gas is stalled and conventional gas production is in terminal decline at 10% per year. The country is consuming more gas for electric power generation thanks to government regulations, and we are poised to export more gas outside the country both as LNG and as pipeline gas to Mexico.

Combined LNG and pipeline exports plus coal-plant retirements are estimated to total 7 bcf/d of gas this year (10% of forecasted lower 48 states production), 12 bcf/d in 2016 (17%) and  18 bcf/d by 2020 (25%) (Figure 5).


Chart_Total Exports LNG+Pipeline
Figure 5. U.S. natural gas export and coal plant retirement forecast.  
Source:  EIA, SENER (Mexico Secretary of Energy) and Labyrinth Consulting Services, Inc.
(click image to enlarge)

Meanwhile, the global price of LNG is in the gutter.  Landed prices in Asia are now less than $8 per mmBtu and, in Europe, are less than $7 per mmBtu (Figure 6).

FERC LNG Landed Prices June 2015_Cropped
Figure 6. World LNG estimated June 2015 landed prices.  Source: FERC.
(click image to enlarge)

The appeal of U.S. LNG export was that prices in Asia were more than $15 per mmBtu and more than $11 in Europe before mid-2014.  Because LNG price is linked to crude oil price, all that changed when oil prices collapsed.  Also, demand has fallen considerably and nuclear power options are being re-started for power generation in Japan.

The cheapest “tolled” export option (e.g., Cheniere’s Sabine Pass Project) breaks even at about $9.30/mmBtu based on $3.00 Henry Hub price plus 15% tolling (Figure 7).

Chart_Landed Costs 30 July 2015
Figure 7.  Break-even North American LNG project costs.  Source:  Royal Bank of Canada and Labyrinth Consulting Services, Inc.
(click image to enlarge)

Woops!  LNG export from the U.S never made competitive economic sense to me but now, it looks dead-on-arrival.

The other big appeal of LNG export, of course, was that we had 100 years of the stuff so it wouldn’t affect our supply or the price by very much. Now supply is stalled and demand is rising. If this continues, price increases won’t be far behind.

Despite a potential reality check in December 2014 during The Fracking Fallacy Controversy, the EIA Annual Energy Outlook 2015 forecasts ever-increasing gas supply out to at least 2040 (Figure 8).

Chart_Gas + Shale Gas 31 July 2015
Figure 8.  EIA total natural gas forecast.  Source:  EIA and Labyrinth Consulting Services, Inc.
(click image to enlarge)

The stalling of gas production is a temporary anomaly but it is also a red flag. In July 2015, the future for cheap and abundant natural gas for decades looks increasingly uncertain.

*The Saga Of Casey, Ernest Lawrence Thayer.


  • Art, I wouldn’t read too much into the stalled shale gas production since this currently supported by only about 220 rigs. Looking at your chart of gas production and the rig count chart (link below) I find it impossible to make sense:

    I believe US has gas import contract with Canada, and apart from that production is balanced to meet demand ± dStorage. So I think this is nothing more than a supply / demand balancing exercise.

    Your map of LNG prices is now fascinating. The big differential between Europe and Far East has gone. I always felt that US exporting shale gas was less than sane. While this was touted as the US bringing cheap shale gas to Europe, the only way I could rationalise it was to expand the market for shale gas and to normalise US price with the rest of the world – in other words to drag the US price up to $9. I’m not sure how the world escapes the deflationary energy spiral that it finds itself in. Producing loads and loads of expensive gas and selling it cheap doesn’t seem to be the way to go.

    • Arthur Berman


      First, I say at the end of my post, “The stalling of gas production is a temporary anomaly.”

      My guess is that the stall in U.S. gas production is mostly because of price. Well head prices in the Marcellus are less than $1/mcf so, for poorly hedged producers (majors do not hedge), not even shale voodoo economics can justify continued production at this price. Half of the net decrease is associated gas from tight oil plays and this is probably because of low oil, not gas, prices.

      I take your point, however, and appreciate your comments. This is not, however, a supply-demand balancing exercise.

      Natural gas production has not stalled for lack of storage or demand for gas sales, nor is it because of declining rig count.

      There is more than adequate storage to accommodate additional supply. Current storage is 2,880 bcf and working volume is 4,336 bcf. Also, year-over-year comparative injection volumes are down ~20% over the last 7 weeks so not only is there ample storage capacity but there is also less gas available for storage than a year ago presumably because of increased consumption/demand.

      There is no lack of demand for gas sales. Despite the fact that marketed production is down 1 bcf/d compared with April 2015, more gas was sold in 2015 than ever before. Marketed gas has averaged +5.8 bcf/d (+7%) year-over-year compared to 2014. Some of this may be because of extremely low gas prices–more people want to buy it when it’s cheap!

      Shale gas rig counts have not decreased nearly as much as tight oil rig counts–35% for shale gas vs. 55% for tight oil–but oil production has not declined yet gas production has.

      Net imports from Canada are down 51% year-over-year because the U.S. needs less Canadian gas thanks to increased U.S. production.

      All the best,


  • awbeattie

    It appears that the nat gas plans for Oxnard are moving along swimmingly. The natives are restless however. To stay with your baseball theme, “It ain’t over till it’s over.”

  • Mahalo (thank you, in Hawaiian). Your reminder that “conventional” gas production is declining 10% a year (I assume compounded) never ceases to amaze me. It is probably not practical, and probably violates SEC regulations, but your opinion of where to invest in oil/gas/coal companies or funds would be very welcome. I look for example at Fidelity’s energy fund, and have no idea whether they have their feet on the ground like you do. I do remember your mentioning one E&P company as one of the best (and that one because it breaks even!).

  • Heinrich Leopold

    Mr. Berman,

    Very interesting article, which meets exactly my point as well. As I very much agree with your and Bill Power’s research, it is also important to put some numbers behind opinions, which could then serve as a base for a corporate strategy. As shale has replaced conventional gas by over 60% in the last ten years, how did this change the growth cycles, which still exist? The last three growth cycles in natural gas have shown an increasingly slower growth followed by an increasingly sharper fall in growth when the cycle ends. I think this will now take the industry by surprise. Secondly, having moved in tandem over decades, oil and gas seem to move countercyclical. This trend becomes more and more distinct. There could be very much interest from the industry and from investors for this research as this makes timely investment and capital expenditures more effective.

    • Arthur Berman

      Mr. Leopold,

      Thank you for your comments.

      We must first separate stranded gas that includes North American gas from global considerations of growth and cyclicity. There is more than ample gas supply in the world for the next several decades. Realistic gas movements and sales within that market are key to unraveling the topics that you describe.

      Australian Northwest Shelf gas will come into the international market in the near term as LNG (albeit at a loss to producers at present prices) as well as Iranian gas both as pipeline supply to India and Pakistan as well as to Europe, and as LNG. Much but not all Russian gas from eastern Siberia will remain stranded as long as Russia’s economic woes continue (and it cannot fund pipelines announced last year to China) and east Asia can get relatively inexpensive LNG with lower oil-linked pricing. And, of course, North American LNG will remain largely stranded because export is not commercial at present international prices.

      I disagree with your comment about oil and gas prices trending counter-cyclicly–that has been true only about North American gas price compared to world price since the Financial Collapse of 2008. Look at the map in my Figure 6 in this most recent post and you will graphically see that global LNG prices have fallen dramatically as oil prices have decreased.

      I expect to see North American gas prices increase slowly but notably in the next year or so. Much of the flattening of U.S. production is, I believe, because of low price. As I commented to Euan Mearns yesterday,

      My guess is that the stall in U.S. gas production is mostly because of price. Well head prices in the Marcellus are less than $1/mcf so, for poorly hedged producers (majors do not hedge), not even shale voodoo economics can justify continued production at this price. Half of the net decrease is associated gas from tight oil plays and this is probably because of low oil, not gas, prices.

      This production has not flattened because of lack of gas. There is plenty of gas especially at $6/mmBtu but it won’t be exported when prices reach this level because economics will favor domestic sales. I see North American and international prices converging over the rest of this decade as long as oil prices remain relatively low as I expect they will–they will rise but not to previous $100 levels at least until the effects of major oil project postponements in deep water and elsewhere take their toll on supply.

      I hope this clarifies my views.

      All the best,


  • Jill

    Stunning drop for LNG price landed Japan. Was $16-19 in 2014. Any thoughts on what the effect will be on LNG shippers such as Dynagas LNG Partners or Gaslog Ltd.?

    • Arthur Berman


      The higher LNG prices were pre-June 2014. I don’t know specifics about the two LNG carriers that you mentioned but transport rates have dropped greatly reflecting lack of business.

      All the best,


  • Fred Palmer

    Chickens headed home to the roost!

  • Walter Stewart

    Mr. Berman, Do you have any information on the huge Energy Transfer Facility being built just west of Crockett, TX on a 380 plus acre site. They are building 3 pipelines to and from it. A 24 in, two 30 in. lines and a 42 in. pipeline already is next to it. Lone Star owns 70% of the project according to their website and Energy Transfer site. These lines are said to be for Liquids to be separated and processed at the plant? It is believed to be from most local production in the immediate area and is expected to be for new oil and gas in the Houston, Madison, Leon and Brazo’s County. Will this increase natural gas production in the local area’s to be sent to the New LNG plants on the Gulf Coast?

    • Arthur Berman


      I don’t have any specific information on the plant but I believe it is part of the EOG Buda-Glen Rose play developing in that area and centered in Madison and Houston counties. Based on the limited information that I have, this may ultimately add a few bcf/d of supply–these reservoirs produce mainly light oil but the oil volumes that EOG estimates suggest a fair amount of gas despite relatively low GOR. I have looked at publicly available data on the wells and, frankly, it is hard to be as optimistic as the infrastructure investment indicates. At the same time, EOG has all the data and is an intelligent company.

      All the best,


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  • Steve


    Thank you for the update on the natgas sector.

    While world/US oil gets all the attention, it appears the greater potential ROI is in US natgas prices.

    Hoping you would comment on a private company Siluria Technologies.

    For those not familiar, they claim to a revolutionized the GTL and gas to ethylene process. They have demonstrated it in the lab. Demonstrated in a pilot facility in Hayward. And the first commercial plant is to open early 2017.

    Have read that currently plants can adopt this technology. They can make a cleaner burning gasoline for the car for about $1 per gallon (with $3 natgas, i assume). Even if it’s double that…wow.

    If all true, seems like a direct connection between oil and natgas bringing us back toward BTU parity.

    Last but not least, one of their key investors is Saudi Aramco.


    (long 2019 natgas futures!)

    • Arthur Berman


      “If true” is always the key for these supposedly revolutionary technologies. Ethane is so cheap that it’s worth even less than natural gas because of over-supply. Everything that the shale producers touch becomes practically worthless from over-production–natural gas, NGLs and now, crude oil. With ethane, the feedstock for ethylene, as cheap as it is now–and falling like a stone–I can’t understand why anyone would want to make ethylene especially from something more expensive like, for now, natural gas.

      The website for the company you mention does not discuss cost except in the broadest “blue sky” terms. The fact that Saudi Aramco has invested means almost nothing since they invest in lots of crazy things on the wild chance that one turns out to be worthwhile.

      I would be very skeptical of any GTL technology because their history is super high cost. Shell and Qatargas, ExxonMobil and many others have worked the problem pretty hard and have not solved it.

      All the best,


  • Nony

    I don’t understand why slowed production at low price is a red flag to continued cheap gas. What the market is saying is “this is the amount of gas we will supply at this price”. Of course there is a price where they stop. But over the course of a longer period of time (2010 to 2015), they have had stunning volume growth and at reasonable prices. [And recall David Hughes in 2006 ASPO predicting 1.5 bcfpd/year declines and LNG imports (!) unable to keep up.]

    As with a low price stopping growth, there’s a price where they grow. How do you know how much extra gas they could supply as prices go up a few pennies? How much Appalachian gas could flow if transport increased enough to equalize prices to Henry Hub? It might be a lot for a low increase, or it might be little. But what is the shape of that supply curve?

    (There’s also weather impacts on the demand cycle…for the last year we were refilling the storage that was drained down from a cold winter…now storage is at average levels. IOW, “refilling storage” was “extra market” last year.)

    You said shale producers needed $8+ about 5 years ago. And we have never consistently been above $4 since then. Even while volume grew. I think that is pretty direct proof that the shale producers DIDN’T need $8.

    Yeah, the Haynesville is down. But it’s very interesting how curve changes at around OCT2013. Before that, it looks like a beautiful bell curve, up and down. Since OCT2013, it is declining a lot less and close to stabilizing for the last year or so. [I plotted weekly review, actually monthly for shale plays data. This is not the DPR data which includes conventional, but a different shale only data source. ]

    Finally, look at the futures strip. Sure the strip is not omniscient. But it is an estimation by people putting money on the line to bet for/against. As a scientist, you should consider it a Bayesian process. Of course it might be wrong…high or low! And it sure can’t predict mild versus harsh winters so those will always cause seasonal variations. But it’s info. If you really think it is wrong, go speculate.

    • Arthur Berman


      It seems that you completely missed the point of my post. As I commented to Euan last week in this thread:

      “My guess is that the stall in U.S. gas production is mostly because of price. Well head prices in the Marcellus are less than $1/mcf so, for poorly hedged producers (majors do not hedge), not even shale voodoo economics can justify continued production at this price. Half of the net decrease is associated gas from tight oil plays and this is probably because of low oil, not gas, prices.”

      Appalachian gas flow is limited by infrastructure take-away and I don’t see that situation changing greatly. The REX reversal will provide some new capacity and other small projects will move forward, but environmental groups opposed to natural gas development have learned that delaying pipelines is their most effective approach.

      Your notions of “proof” of producers’ break-even prices reflect your lack of experience and knowledge of the E&P business and how it is funded.

      Likewise, your reliance on futures contracts. Look at the volumes on futures contracts and you will see that there is no volume beyond a few months meaning no one is willing to take the bet. No one who knows anything about the oil and gas business uses futures strips as price estimates. They reflect what traders are willing to pay for now and in the very near term.

      My comments several years ago about $8 gas were valid when they were made (I think they were made pre-Financial Collapse) but things change.

      And your point about the Haynesville Shale is…? The play is a commercial failure reflected by the fact that production is down by almost half. Period.

      As someone who described himself as an oil and gas “civilian” in a previous comment, you would do well to focus on learning rather than playing the expert and second-guessing those who are.

      All the best,


  • Nony


    1. The article is confusing because in part you say it is low price (and takeaway behind that) limiting production, but then you still say it is a red flag that production slowed. Unless you think the takeaway will never get built, than it seems like there is a lot of reserve that can still hit the market later. I’m not the only one who saw an apparent conflict in the article.

    2. I think there is enough activity at futures forward dates to cover an individual investor (IOW, you won’t move the market). So if you think you know better than the futures market, you could make some easy money.

    3. The Utica as a dry gas play is more and more serious. It has gone from ~nothing to bigger than the Fayetteville in about two years. It’s no longer just some cornie hope (as for instance refracking is), but something that needs serious watching. And one swallow does not make a summer but what do two do? [The Consol and EQT massive wells in the last couple weeks.]

    • Arthur Berman


      I regret if I may have confused readers by not being clear on what decreased production means.

      Lower gas production is a red flag because it means that current rates at current prices may be unsustainable. In other words, companies can only produce at a loss for so long depending on availability of other people’s money and that is becoming more of a factor with the poor performance of the E&P sector.

      I don’t question that there is ample gas supply from shale plays at least for another 5-10 years. A reserve is supply that is commercial at a certain price, so price is the link between supply and production in a perfect world where companies produce to make money. Many companies produce to stay alive from cash flow even if they are losing money and that’s the part that is difficult for some people to grasp.

      Let’s be clear: most companies are losing money at current gas prices. Not all but most.

      Some analyst reports discuss break-even gas prices in the Marcellus of $3.50/mcf (see, for example, Simmons’ latest report). This does not include corporate expenses (G&A, interest expense, etc.) or land. Gas prices averaged less than $2.75 in Q2 2015 so, unhedged, everyone is losing money. Realized (hedged) prices for better-positioned companies (Cabot, EQT, Range) with NGLs in the Marcellus averaged just under $3.50 according to their 10-Qs for Q1 2015.

      I’m not going to argue any more with you about futures strips.

      Production volume does not equal profit. The Utica is producing a lot of gas. That doesn’t mean that anyone is making money. EQT’s “massive” wells are in the Utica in West Virginia at 13,500 ft and well costs of more than $13 million. Not commercial.

      So, my point to you remains, you need to be careful about conclusions based on impressionistic talk and headlines vs. data.

      All the best,


  • Nony

    OK man. No more futures stuff. 😉

    The EQT record setter well was in PA and actually cost $30 MM!! (Not 13.)

    [The dollars actually support your viewpoint, not mine, and the state is no biggie. I just want to be correct on the details.]

    • Arthur Berman


      Thanks for the link. I had mis-read the map in EQT’s investor presentation and saw their Wetzel County, WV planned well and thought it was the tested well.


  • Nony

    The pdf from the second link (Utica conference, early JUL2015) on page 3 has a map showing the location of several of the big wells. At this point in time, the record Utica Sportsman and the CNX Gaut had not been completed yet so their IPs are not shown in the list on page 6. [Nor are the Gee and Neal Shell wells in NE PA, not sure why.] Anyhow, from the 3 big July Utica wells, it seems like the high IPs are not in exactly the contours that were mapped in page 3 or at least more drilling is needed to really map it out.

  • […] topic, for a sobering view on where U.S. shale gas production and global LNG prices are going, read this recent post by Arthur Berman, who spoke at the NOIA 2015 oil and gas conference held in June in St. […]

  • […] once a bulwark of reason and of environmental consciousness, lost its focus,in particular with the mad hope of importing natural gas from the US. Most people all over the world seem to be so busy with their day-to-day economic worries, that […]

  • Philip Hood


    Thank you for this post and everything else you have shared on the industry. I am not a geologist, but I have followed the industry over the last 8 years or so and discovered your blog and presentations more recently. My interest comes from the accounting/investing perspective (I used to work at the FASB/Big 4 and I now manage investments for family).

    I am in the process of reviewing the most recent 10-K’s/10-Q’s for the top 40 gas producers in the U.S. One thing that has struck me based on your comments on free cash flow and my review of their financial statements is the disconnect between depreciation/depletion and investing cash outflows for drilling and completion costs. The cash outflows are 2 to 2.5 times depreciation/depletion for many companies. How is this possible? Are they doing their depletion calculation correctly? It seems like depletion should be much higher, which would make income statements look much worse. Also, their production rates should increase a lot more year over year if their investing cash outflows for well development and completion are that much higher than their depletion expense.

    At one company, I saw depletion remain basically the same in 2014 and 2013 even though the company’s production increased almost 25%. Does this come from optimistic estimates of the total gas that will be obtained from unconventional wells?

    It is painfully obvious looking at the cash flow statements for many of the unconventional producers that once other people’s money runs out, they will have to either drastically cut back on production or go out of business.

    • Arthur Berman


      I believe the disconnect is that companies lose DD&A as they take impairment write-downs giving themselves an artificial increase in “profit.”

      All the best,


  • Philip Hood


    thanks for your reply…that makes sense.

    On a separate but related note, I can’t figure out how the EIA’s monthly production figures and the weekly natural gas storage reports are correct given the monthly natural gas production figures reported by the Texas RRC and Pennyslvania DEP.

    Between January 2015 and October 2015, Texas is showing a 12% decline in total natural gas production (from both oil and gas wells), while Pennsylvania is showing a roughly 15% decline from unconventional wells. Given the ongoing declines in conventional wells, how is it possible that the EIA is reporting total monthly dry natural gas production for July, Aug, and Sept at slightly more than January production???

    I also question their inventory reports. They are showing an increase in inventory between July and Nov of roughly 1,500 bcf, which would require 300+ per month of injections.

    Given the declines being reported by Texas and Pennsylvania, I would guess that production from July onward would have to be at least 5% lower than January, and probably closer to 2,000,000 mcf per month. The EIA is reporting July and August consumption at roughly 2,000,000 mcf per month. Again, this doesn’t make sense, although it seems to be consistent with their own monthly production reports through September.


    • Arthur Berman


      In general, I think EIA does an excellent job of sorting out an exceptionally complex system of varying reports by operators and states. It is not perfect but it is adjusted regularly, and generally reflects reality on a 3-6 month lagged basis.

      Gas production accounting is complicated and many have noted inconsistencies between reporting by large producing states like Texas, Pennsylvania, Louisiana, Oklahoma, etc. and EIA reports. It is important to understand that EIA estimates production based on sampling algorithms that are adjusted to storage volumes by a “balancing item.” There is often a bulk-shift correction applied by EIA in February.

      It is also worth noting that large states have significant backlogs and corrections in reports from operators and that the states do a certain amount of estimating and adjusting so I wouldn’t necessarily believe the state volumes either. Also, some states do a much better job of reporting than others. Generally, for example, Texas and Louisiana reporting is excellent while Oklahoma is awful. Until very recently, Pennsylvania only reported on a 6-month basis and did not provide monthly production even then. Ohio only reports quarterly and similarly does not provide a monthly breakdown of production.

      This is the real world of oil and gas data and it is far more opaque outside of the United States.


  • […] Shale Gas Stalls, LNG Export Dead On Arrival | Art Berman – «No Joy in Mudville*: Shale Gas Stalls, LNG Export Dead On Arrival Posted in The Petroleum Truth Report on July 31, 2015. Something unusual happened while we were … […]

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