Strong Natural Gas Prices And Tight Supply In 2017

Posted in The Petroleum Truth Report on May 16, 2017

A year ago, most analysts were bearish about natural gas prices.   I wrote that natural gas prices might double and they did. Today, most analysts are again bearish about gas prices and again, I think that they are probably wrong at least for 2017.

The mainstream narrative is that new pipeline capacity—notably the Rover Pipeline—out of the Marcellus and Utica shale plays will unleash a torrent of pent-up supply. That is because over-production in these plays has saturated the northeastern U.S. markets and 2016 wellhead prices averaged about $0.88/mmBtu less than Henry Hub prices (Figure 1). New take-away capacity to higher-priced markets will fix that problem but gas prices will plummet later in 2017 because of increased output.

Figure 1. Marcellus Wellhead Prices Were $0.88 per mmBtu Less Than Henry Hub Prices in 2016. Source: MarcellusGas.Org, EIA and Labyrinth Consulting Services, Inc.

Systematic overproduction turned the northeastern U.S. from the highest-margin market to the lowest by 2013. With a second chance to at least be on par with national pricing, shale gas companies will, according to the narrative, over-produce the entire U.S. market to a loss once again. Smart.

Conventional Gas, Shale Gas and Net Imports

There are three components to gas supply: conventional gas production, shale gas production, and imports. These must be understood to establish a context for a potential supply increase from the Marcellus and Utica shale plays.

There is no doubt that low prices resulted in a 4.26 bcf/d (billion cubic feet of gas per day) decline in gas production from September 2015 through October 2016 (Figure 2).

Figure 2. U.S. Gas Production Fell 4.26 bcf/d From September 2015 to October 2016. Source EIA Natural Gas Monthly and Weekly Updates, and Labyrinth Consulting Services, Inc.

Since 2008, conventional gas production has been in terminal decline and has fallen 26 bcf/d. It is currently falling about 3 bcf/d each year. Shale gas–including associated gas from tight oil—now makes up more than two-thirds of domestic supply. That means that shale gas output must grow by more than 3 bcf/d each year to offset falling conventional supply.

But annual shale gas production growth slowed from almost 7 bcf/d in the first quarter of 2015 to less than 2 bcf/d in the first quarter of 2017 (Figure 3).

Figure 3. Shale Gas Growth Has Slowed from Almost 7 bcf/d in the First Quarter of 2015 to Less Than 2 bcf/d in the First Quarter of 2017. Source: EIA Natural Gas Weekly Update and Labyrinth Consulting Services, Inc.

If shale gas production growth doubles in 2017, then supply will be flat but considerably lower than 2015 levels when over-supply crushed gas prices. Gas supply must increase well beyond what is likely this year in order for prices to fall much below current levels of about $3.25 per mmBtu.

Considerable supply potential exists. The shale gas horizontal rig count has more than doubled—from 76 to 167 rigs—since June 2016 with higher gas prices (Figure 4). How quickly can that potential be converted into supply?

Figure 4. Shale Gas Rig Count Has More Than Doubled Since June 2016 With Higher Gas Prices. Source: EIA and Labyrinth Consulting Services, Inc.

EIA’s latest production forecast suggests that it may happen very quickly. The May STEO projects gas growth of 5.6 bcf/d in 2017 which includes an additional 3.5 bcf/d between April and the end of the year (Figure 5).

Figure 5. EIA Forecast is for a 5.6 Bcf/d Gas Production Increase in 2017 with Prices Rising to $3.43 By December. Source: EIA May 2017 STEO and Labyrinth Consulting Services, Inc.

Although that may be unreasonably aggressive, it is noteworthy that the overall supply balance (red and blue fill in the figure) remains in deficit for most of the year, and that spot prices continue to increase, ending the year at almost $3.50/mmBtu. Net imports (the third component of total supply in addition to shale gas and conventional gas) are forecast to average -0.3 bcf/d in 2017 compared to +1.7 bcf/d in 2016.

Rover Pipeline

The Rover Pipeline was certificated for construction in mid-February and will connect gas from the Utica and Southwestern Marcellus shale plays to the Defiance Hub in northwestern Ohio (Figure 6). There is a gas surplus (~1.8 bcf/d) in Ohio so this pipeline is a gas exit route to the Dawn Hub in Ontario, and to the Midwest and Gulf Coast via interconnecting Vector, Panhandle Eastern and ANR pipelines. There, it will compete with existing supply and result in lower prices.

Figure 6. Rover Pipeline Route Connecting Utica and Southwestern Marcellus Shale Plays With the Defiance Hub. Source: Energy Transfer and Labyrinth Consulting Services, Inc.

Although Rover is scheduled to reach Defiance in November, it is unlikely that any gas will move beyond there before 2018. It will not, therefore, have any effect on gas supply in 2017. Depending on how much gas ultimately is sent to Canada, it may have limited effect on U.S. supply in 2018.

What Could Go Wrong?



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20 comments on this entry

  1. I was wondering why natural gas stocks have been performing so poorly relative to the underlying commodity. Usually, thats not a good sign for the commodity. Thanks for you post Art!

  2. Vince,

    Almost all energy stocks have been substantially devalued in the last few months. Some of that is an adjustment from exaggerated valuations and some of it is failing confidence in oil-price recovery. But your point that gas companies have been punished more than oil-weighted companies is valid. That is because of the expectation that new pipelines will bring overwhelming supply and lower prices to the market. There are a few exceptions like Rice and Cabot.

    All the best,


  3. Good points Art. Although I think what the market (by which I mean the forward curve) is telling us that prices spike to the mid $3’s this winter, fall to just above $3 in 2018, and then stay below $3 for the foreseeable future (on an annual basis). The curve will almost always be wrong because weather plays such a big role in gas prices, and there are plenty of traders positioned for a spike this year (i.e. they expect prices to spike much higher that the curve if we have a real winter). But the market is saying the new normal (beyond 2017/18) is sub-$3 nat gas, which is the basis for pricing equities. I tend to broadly agree unless oil prices cause service costs to spike higher which will also affect nat gas prices. In any case, equity prices for non-distressed companies are based on mid to long-term expectation for pricing, so the analysts are in fact using the curve to lower their price targets for nat gas focused E&Ps.

    So do you have a mid-term (3-5 years out) view on nat gas prices that differ from the market?


  4. HS,

    I agree with your analysis of the gas forward curves but I think the mid-term view they represent will be shown to be wrong.

    The Marcellus will peak in the next 3-5 years and that will be a serious wake-up call for those who think that shale gas and tight oil are exempt from the laws of depletion physics. There is nowhere to run from impending loss of 20%+ of total U.S. supply.

    The Utica is a relatively small resource and Antero showed negative PV for Utica PUDs in their 2016 10-K. I will post our recent study of the Haynesville Shale soon but the commercial area is fairly small and already 50% developed.

    That leaves tight oil associated gas to fill the gap. I suspect that the Permian will follow the path of the Bakken and peak because of loss of gas-expansion drive and water production much sooner than most people imagine. Add increased exports and the elements for the next natural gas supply crisis is at hand.

    I may be overly skeptical but the market will adjust quickly to newly found supply insecurity if any part of my story is correct.

    All the best,


  5. Good analysis Art! I have been telling our EPG members for months that I see much tighter natural gas and NGL markets in the U.S. by the end of the 3rd quarter. I believe that the warmer than normal winter of 2015/2016 masked the rapidly growing U.S. gas market. After a closer to normal winter 2016/2017 we have gas in storage closer to the 5-year average today and probably heading to below the 5-year average by October. Increasing exports of LNG by Cheniere and via pipeline to Mexico will come on top of the big increase in demand for power generation coming in Q3.
    In 2018 the gas market may be over-supplied again, but for the coming winter the “gassers” should get good prices.

  6. If conventional gas production is declining by 3.2 bcf/day annually, then the production will fall to zero by 2025. After that point the US would be entirely dependent on shale gas and associated gas from shale oil production for domestic production of gas. If shale gas peaks as well within that time and the decline rate is high in shale gas production…

    Well… there is still some time to figure out a solution.

    Thx for an informative article about nat gas.

  7. Great article as always. Can I ask, how do you calculate comparative inventory? Thank you, M

  8. Maurilio,

    Comparative inventory is calculated by subtracting the 5-year average from the current stock level for the same week. I use a moving average for the 5-year average to normalize the weekly variances.

    All the best,


  9. Art

    I always look forward to your posts
    On your question What Could Go Wrong?

    I have looked at the US EIA data on uses for US gas
    From my interpretation I see the EIA only has four main areas

    When you examine inside all these I am perplexed to see that they are not considering

    Petrochem expansion by my guess at least 3BCF/d based on Methanol/ Ammonia plants sanctioned / relocated from Chile
    LNG which has 12BCF/d sanctioned capacity by 2020 and at least 2-3 BCF/d by end of 2017
    Pipeline gas to Mexico of at least 5BCF/d by 2020 and 3 – 4 BCF/d by end of 2017

    My concern is that if you add these onto the current base use of circa 68 BCF/d US gas supply has to increase to 76 BCF/d end of 2017 and more than 85 BCF/d by 2020

    I realise that there is potentially some switching available from Natural Gas but I think the new power plants sanctioned by my research 2 -3 BCF/d will offset any declines in other areas

    So my point is to What could go wrong is has the EIA taken its eye off the ball and convinced everyone that there forward curves only showing a use of 70 – 75 BCF/d by 2020 has lulled the US market into a false sense of security

    My warning is look at the East Coast Australia gas market – before the LNG plants plenty of low cost gas – today very little very high cost gas

    Your views will be greatly appreciated


  10. John,

    Many thanks for your valuable insights. I agree with you that there are serious potential supply risks when demand is fully understood.

    I have long questioned LNG export from a supply security perspective. I understand that a free-market allows everyone an equal opportunity to do stupid things if they can find someone else’s money to lose doing it.

    I urge readers to learn about the current electric power crisis in Australia that exists in large part because the country allowed unrestricted export of natural gas and now does not have sufficient supply to manage its own power needs. I am not saying that will happen here but think about it.

    There is a magical belief that shale gas and tight oil are exempt from earth physics and the well-established observation of depletion.

    The Marcellus will peak in the next several years and accounts for almost 25% of U.S. gas supply. The Utica is far too small to replace it and Antero–a leading operator in the gas-prone southern core–assigned negative PV to its PUDs in the Utica in its 2016 10-K.

    The Barnett and Fayetteville are in terminal decline.

    The “monster” wells in the Haynesville cost $13 mm to D&C and the $4 commercial core is small and more than 50% developed (a post is forthcoming on those details).

    So, is the future gas (and oil) supply of the United States dependent on the Permian basin?

    All the best,


  11. A offsetting factor has been renewal (excluding hydroelectric) energy additions added throughout last year that resulted in a power burn that is down more than 3 Bcf/d year over year. This is structural with respect to green energy initiatives – and this demand is gone.

  12. TDP,

    I don’t believe it is that simple. I filter out all but wind, solar and geothermal from the “renewables excluding solar” because there is a lot of garbage included like municipal solid waste, landfill gas, and wood.

    What I see for Feb 2017 YOY is the 3.15 bcf/d overall drop that you mentioned in coal, nuclear and natural gas but only a 0.2 bcf/d increase in renewables.


    I think we are seeing overall lower power demand because of a mild winter.

    All the best,

  13. Thanks for the explanation.


  14. Thanks Art- great analysis. Do you see the proposed China trade agreement that includes LNG exports as being a potentially bullish factor in gas prices? Seems if and when enacted, it could reduced the over supply being forecasted. NG prices initially spiked up on the news but have come back down since the report came out early this week.

  15. Jeff,

    I think the LNG trade is based on bogus economics particularly for Asian export. It only makes sense if you believe that landed prices will be much higher in the future or that buyers are willing to pay a premium for supply security.


    No one is paying attention to the re-negotiated gas deal between Russia and China that is underway to bring cheaper pipeline gas to East Asia. Iran has the largest proven gas reserves in the world and will provide gas to South Asia before long.

    All the best,


  16. Art,

    According to the latest EIA drilling report, legacy decline rates are rising faster than production from new wells. Utica follows closely. This is why net production stagnates in Marcellus and Utica and overall US natgas production is still down year over year.

    For that reason the 5.6 bcf/d production growth forecast for the US by end of this year is in my view unrealistic. As Marcellus and Utica mature, legacy decline rates are accelerating exponentially, leaving the net production growth in a deep deficit – despite frantic drilling of new wells.

  17. Heinrich,

    Depletion is inexorable and applies equally to conventional and unconventional reservoirs. Production grows as long as enough new wells are added to overcome the increasing production base decline. Once optimum infill is achieved, terminal decline begins. Rate may be accelerated by over-drilling beyond optimum infill but then, terminal decline will correspondingly accelerate.

    Many people think that shale plays are magically exempt from this fundamental law of physics but they are wrong. The Marcellus will peak and begin to decline in a few years. It represents more than 25% of U.S. dry gas production. There is nothing that can replace it unless some new play is found.

    All the shale gas growth is presently in 3 plays: Marcellus, Utica and Permian. Growth rates are falling in the Marcellus and Utica and may be rolling over in the Permian (by the way, you cannot use the DPR for the Permian because it includes all gas not just shale gas–you must use the Natural Gas Weekly Update that shows the production is about 50% of DPR).

    The EIA STEO forecast for +5.6 bcf/d increase in dry gas production in 2017 seems optimistic but may occur. The real question is, When will depletion take over?

    I suspect it will occur much sooner than most imagine and then we will really begin to question the wisdom of natural gas export.

    All the best,


  18. Hi Art,

    I have followed your thesis on natural gas over the past year (to my benefit as a trader). Gas drive expansion in Permian (loss of reservoir energy) may be a good story for another day be currently the associated gas production from a wide swath of Permian is quite large. Any thoughts on how it might affect the NG supply narrative over the mid-term?

  19. Ryan,

    Associated gas production from Permian tight oil is about 4 bcf/d and will increase as oil output grows. For now, a lot of gas is flared for lack of take-away capacity. In the medium term, much of it may go to Mexico as most Eagle Ford gas does today. I don’t want to minimize the significance of Permian gas but I see it as potentially balancing future declines in the Marcellus assuming that meaningful volumes eventually go into the domestic market.

    All the best,


  20. Thanks Art! Believe it will be something to keep an eye on.