Natural Gas Price Increase Inevitable in 2016

Every week, the EIA proclaims a new record for natural gas production. But their own forecasts show that the U.S. will be short on supply by October of this year. A price increase is inevitable beginning later in 2016.

Popular Myth vs Reality

The popular myth is that gas production will continue to increase and that prices will remain low for years. In the myth, price has no effect on production. The reality is that price matters and production is down 1.2 bcfd1 since September 2015 (Figure 1).

STEO_FEB 2016 Natural Gas Prod
Figure 1. U.S. dry gas production. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

The production increases reported by EIA are year-over-year comparisons that don’t reflect declines during the last 4 months.

Prices have fallen to less than half what they were in early 2014. The average price for the first quarter of 2016 is only $2.25 per MBTU2 (Figure 2).

Chart_2014-16 Price & Quarterly Avg Price

Figure 2. Henry Hub daily and quarterly average natural gas prices. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Hedges made when prices were in the $5-range carried many companies through falling prices as they continued to produce like there was no tomorrow. Tomorrow has arrived and the hedges are gone.

Over-production in the Marcellus Shale means that producers have to compete for limited pipeline capacity by deeply discounting their sales price. The best core area locations are commercial at $4 per mcf3 but wellhead prices averaged only $1.75 per mcf in 2015.

No Simple Solution to Falling Supply

There is no simple solution to falling supply. That’s because almost half of U.S. supply is conventional gas and it is in terminal decline. Now, shale gas is also in decline (Figure 3).

STEO_NATURAL GAS MASTER_Conventional vs Shale Gas Prod

Figure 3. U.S. conventional and shale gas production. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Conventional gas supply has fallen 16.75 bcfd since July 2008. Until July 2015, increases in shale gas production more than offset those losses.

Conventional gas will continue to decline at about 5% per year because few companies are drilling those plays. Shale gas must, therefore, continue to grow by at least 15 bcfd per year just to offset annual conventional gas decline (~2.5 bcfd per year) and legacy shale gas production decline (~12.5 bcfd per year).

It will take 15 bcfd of new shale gas production in 2016 to keep U.S. production flat.

Shale gas production replacement and growth for 2015 were 14.5 bcfd, down from almost 18 bcfd in 2014. It will be difficult to match 14.5 bcfd in 2016 because shale gas production has been falling 0.72 bcfd (~2.2 bcfd annualized) for the last 4 months of data (Figure 4).

ShaleGas Chart 14 Feb 2016
Figure 4. Shale gas production. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

The biggest declines since peak production are from the older “legacy” shale gas plays namely, the Barnett, Fayetteville and Haynesville (Table 1).

Shale Gas Max & Change Summary Table

Table 1. Summary table of shale gas volume changes since peak production. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Although additional reserves exist in the Barnett and Fayetteville plays, the core areas have been largely developed and marginal areas require substantially higher gas prices to be commercial. There is only one horizontal rig operating in the Barnett and there are none in the Fayetteville.

Production in the Haynesville Shale has decreased by 3.64 bcfd since its peak. High costs and relatively low EURs make the play uneconomic below about $6.50 gas prices. Parts of the core areas remain under-developed at today’s prices.

Marcellus production declined 0.52 mcfd since July 2015. Most of this probably represented intentional shut-ins because of low wellhead prices. Marcellus production can grow but new pipelines are needed to turn reserves into supply. Even with additional infrastructure, production will peak in the next few years just like in the older plays.

Production in the Utica and Woodford plays is increasing but it is largely offset by declining associated gas from the Eagle Ford, Bakken and other tight oil plays.

A Supply Deficit Even In The Optimistic EIA Case

The EIA forecasts that net dry gas production will increase 1.4 bcfd in 2016 and 1.6 bcfd 2017. Even with that optimistic forecast, their data still shows that the U.S. will have a supply deficit beginning in the last quarter of 2016 (Figure 5). A more realistic forecast implies a much greater deficit that begins sooner.

STEO_FEB 2016 Natural Gas Supply Balance & Storage

Figure 5. U.S. natural gas supply balance and forecast. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

A supply deficit does not mean that there won’t be enough gas. There is ample gas presently in storage to cover a supply shortfall for awhile. That is what happened during the supply deficit in 2013-2014 (Figure 5). That deficit was created by flat production similar to what EIA predicts for the first 3 quarters of 2016.

What is different this time, however, is that net imports will reach zero in early 2017 because of decreasing imports from Canada and increasing exports. Add to that the challenge of replacing conventional gas depletion, and there is a much more serious supply problem than EIA’s already questionable forecast suggests.

Another big difference is that in 2013-2014, capital was freely available with average oil prices above $90 per barrel and average gas prices more than $4 per MBTU. Today, the oil and gas industry is in financial shambles with both oil and gas prices at very low levels, and it is unlikely that companies can raise the capital necessary to ramp up gas drilling quickly if at all.

Export plans of at least 7 bcfd by 2020 are not helpful considering the challenges of meeting domestic supply in coming years (Figure 6).

AEO 2015 Natural Gas Imports & Exports Jan 2016
Figure 6. U.S. net natural gas exports. Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

The prospect of exports increasing to 13 bcfd by 2030 is even more troubling absent some new shale gas play that we don’t know about yet.

Higher Gas Prices Are Inevitable

A few years ago, the oil and gas industry convinced the world that the U.S. had 100 years of natural gas. Some of us cautioned that it is worth reading the fine print, that there is a difference between a resource and a reserve. The harsh light of reality eventually reveals that what seems too good to be true usually is.

The obvious solution to declining gas supply is higher prices.

The EIA’s STEO forecast calls for $3.17 per MBTU gas prices by December 2016 and for $3.62 by December 2017. Those prices will not support necessary drilling in legacy shale gas plays. EIA’s AEO 2015 reference case does not call for gas prices to reach $5 per mcf until 2025. We can’t afford to wait 9 years.

It is, therefore, inevitable that natural gas prices must increase sooner, preferably in the next 12 to 24 months. If oil prices remain low, a shale-gas revival may save the domestic E&P business. During the last supply deficit in 2014, gas prices averaged $4.36 per mcf compared to only $2.63 in 2015.

But it will take time for producers to reverse the decline in drilling and production. It may be difficult to raise capital for renewed drilling given the current distress in the oil and gas industry.

Something will have to give sooner than later. That will be natural gas export.


1 billion cubic feet of gas per day
2million British thermal units, approximately 1000 cubic feet of gas
3thousand cubic feet of gas


  • Dean

    Thanks for the interesting post. Is it possible to know what is the percentage of associate gas from oil wells over total dry gas production ? Thanks,Dean

  • Cloud9

    If prices don’t go up, we are cooked. The real question is has the EROEI reached the tipping point?

    • Arthur Berman


      EROI or net energy is difficult to know. Getting reliable and consistent data on this has been frustrating to the researchers also.

      Net energy is a critical factor and is unfortunately best understood with basic economics. Most shale gas production is non-commercial at current gas prices. That is a proxy for an imbalance in net energy. Quantifying how the loss in net present value relates to net energy is another thing.

      Thanks for your question,


  • Mike


    I’m curious as to what effect the Permian associated gas has on this metric?


    • Arthur Berman


      What metric are you referring to? Net energy (EROI) or the contribution to total gas production from gas associated with tight oil production?

      The Permian basin is complicated because almost no production is from shale. Most of the production using horizontal drilling and hydraulic fracturing is from 3 conventional oil plays: Wolfcamp, Spraberry and Bone Spring. Oil and gas production in the Permian basin peaked in 1974 at 2.3 mmbpd and 10.4 bcfd, respectively. Today, oil production has recovered to 2 mmbpd and gas, to 7 bcfd.

      Wolfcamp-Spraberry-Bone Spring gas production is 3.1 bcfd and oil production is 0.9 mmbpd. This is the production that people should focus on. 3 bcfd is comparable to the Barnett, Utica and Haynesville but less than the Eagle Ford or Marcellus (see table 1 in my current post). It is 4% of total dry gas production.

      Let me know if this is the answer you are looking for if there is some other metric you are asking about.


  • Do you think the gas heavy players (SWN, CHK, etc.) can “ramp up” gas production if prices improve? It seems to me that financing may play a role. We are now down to zero rigs in the Fayetteville (in fact, in the whole state of Arkansas) and many of these rigs are in mothballs. I don’t see where SWN is going to scrape up the cash to really bring back a lot of rigs in say the Fayetteville.

    • Arthur Berman


      I agree with you. I don’t think that it will be easy to raise capital to ramp up shale gas drilling–certainly not with the E&P business in its current mess. In a few years with higher gas prices, yes.

      All the best,


  • TaylorScott

    Art, thank you so much for sharing your data driven and factual knowledge of all manner oil and gas industry. It is invaluable and I am grateful that you are gracious to share it with the public. As a 30 year veteran of the oil and gas industry I have never read more accurate, forthright and valuable articles. Please continue to write so we may all learn the truth about the complex oil and gas industry. Scott.

  • Dave


    Thoughtful commentary – thank you. With all the money from Private Equity and to a large extent, plentiful supply still coming from the public market, would there likely be a quick response to higher prices w/ increased drilling bringing new production on-line quickly, plus efficiency gains (lower drilling and completion costs), plus DUC’s leading a muted price response and/or the proclivity for producers to hedge future too quickly after sustained low prices?

    • Arthur Berman


      I believe that the capital for shale gas and tight oil is largely gone although we see some last gasps like the Devon and Pioneer equity offerings. I don’t think it will come back quickly either. The debacle in the banking business with energy debt is just beginning, and it will be ugly and may spill over into other markets. The bankruptcies will be sobering as well.

      Most of the talk about efficiency gains and DUCs is noise to distract from the truth that the companies are losing their asses. Everyone has been wrong about when the bubble will finally deflate so I don’t want to be too adamant but I believe the U.S. E&P business is injured more than many realize. That’s not good news.

      All the best,


  • David Ryan

    Art, can you give me a ballpark estimate of what you think
    gas prices might rise to before we see a supply response?
    Thank you sir

    • Arthur Berman


      I don’t do price forecasts. I stated in the post that prices averaged more than $4/mcf during the last supply deficit during 2012-2013. That’s not a bad guideline but really, a lot depends on weather and the economy.

      All the best,


  • PaOil

    Hi Art,

    As always, thank you for your solid work. In the Marcellus/Utica there remain a number of completed but shut-in wells. A number frequently discussed in the industry is 1200 to 2000 such wells. (These are in addition to DUC’s.)

    If that number is in the ballpark, and if they are shut in due to either pipeline constraint or pricing, they are presumably able to come on line when heightened demand frees up pipeline capacity or lifts pricing.

    How have shut in wells factored into your thinking and is 1000+ consistent with information you are hearing about the Marcellus/Utica? Are completed but shut in wells a factor in any other play?

    Thanks. Always look forward to your research and perspective.

    • Arthur Berman


      During the fall in rig count after the Financial Collapse a few years ago, there were all kinds of articles speculating that there were thousands of shut-in and waiting-on-completion wells that would overwhelm supply. At one point, I saw an estimate of 12,000 of these wells. Although there were unquestionably many valid cases of spare capacity wells, the outcome was like Y2K–much ado about little.

      Shut-in and WOC wells represent poor planning and management of capital. They also appear to be a normal part of the development cycle for shale companies as drilling exceeds the availability of completion crews and take-away infrastructure. It is no surprise that chronically cash-flow negative companies are poorly managed.

      I have no idea how many spare capacity wells there are in the Marcellus. The real question is, What is the normal, ambient backlog of these wells and how do current guesses about their numbers compare to those levels?

      There are a host of issues that the industry and pandering analysts throw out to the public to distract from the reality that the shale gas plays are not commercial. DUCs are a sure bet to get people’s attention. Drilling efficiency is another. We must be diligent to separate the signal from the noise.

      If there is spare capacity production in the Marcellus, it will need pipeline capacity to reach sales. I don’t see a lot of new capacity getting added with the E&P industry in shambles and the overall economy weak but I could be wrong. I suspect that most renewed pipeline approval and construction will have to wait on higher gas prices and suppliers in a stronger financial position to deliver on send-or-pay commitments.

      I don’t envision gas prices rising to the $6-8 level. Coal vs gas pricing creates a ceiling. Prices above $4 would not surprise me in the coming few quarters.

      All the best,


  • Dave

    Thanks Art,

    There could be a view that all the dry powder from Energy Private Funds raised will prolong the glut beyond what seems reasonable or rational. Today, a SPAC backed by Riverstone (Silver Run) raised $450MM to buy distressed companies in the E&P space and there is north of $125bn of dry powder for PE firms to invest (Preqin) in energy and over 200 funds raising fresh capital at the moment, the demand remains high. It will be interesting to see how well this new money gets put to work.

  • Bradley


    I was looking for the same info today and according to this it is 8% and in 2014 represented 33% of the nat gas growth.

  • Bradley

    Thank you Art,

    Your predictions have really been on point for the last year (the period I have been following your articles) and your insight has been a great help. BTW I think the figures from the article I posted above are incorrect when bumped up against EIA’s data. No surprise.

    Question: What effects do you believe the increasing bankruptcies (40 or so last year) will have on Natural Gas production? I have read some terminate drilling but some do not.


    • Arthur Berman


      I was on a panel at UT Austin last week for UT Energy Week and the other panelists were energy economists, hedge fund managers and E&P financial people. They agreed that more than 30% of U.S. oil and gas companies will go bankrupt in 2016. That will have a huge effect on drilling, production and pipeline construction. Bankruptcy allows all contracts to be ignored, I believe—drilling, send-or-pay, etc.

      Please see this recent article “As U.S. shale sinks, pipeline fight sends woes downstream” on energy bankruptcies.

      All the best,


  • Clueless

    Your comment on fig 3: “Conventional gas supply has fallen 16.75 bcfd since July 2008. Until July 2016, increases in shale gas production more than offset those losses.”

    Should that be until July 2015?

  • Martin

    Wow, you guys are amazing! Thank you Art for all the insight and substantive details you share with us. I have learnt so much with you in the last few years.

    All the comments here are also spot on. I had some questions but you beat me to the smart ones.

    Thank you,


  • Sergey

    Hello Art,

    I’ve been reading your articles for a while. Thank you for providing such usefull and consistent information. One question arises though: according to the last few EIA’s natural gas weekly updates, production of dry gas has risen almost 6% for the last 1.5-2 month. However, there is no such information in Drilling Productivity Report. In the report for week ending February 10 they say that “New Northeast pipelines help boost gas production 18%”, but it only explains 4% growth max.

    I would be really greatful if you could privide some comments on that.

    All the best,


    • Arthur Berman


      EIA’s most recent Short-Term Energy Report shows both dry gas and marketed gas for January 2016 lower by more than 1 bcfd from peak levels in September 2015.

      In the Monthly Energy Review, EIA cites Bentek as the source of higher gas production. Bentek measures pipeline flows and is a long-time sycophant of the natural gas-shale gas business. Obviously, EIA thinks enough of their work to mention them in the MER but not enough to include their data in the STEO.

      The main new northeast pipeline capacity is from the Rockies Express that has been reversed to take 0.55 bcfd of gas west from Pennsylvania and Ohio. Columbia, Tennessee and Tetco also completed pipeline expansions that will carry another 1.3 bcfd. I assume that this new capacity is included in the January STEO data so I cannot really address your questions except to say that when I see the increase in the February STEO, I will report it. I do not have a partisan position about Marcellus gas and am just summarizing the patterns that I see in the EIA data.

      All the best,


  • You mentioned the damage done to the industry will be severe. One of the old timers (in other words, my age group) I visit with regularly will be spudding a well soon and he mentioned that the companies hired are cheap now but he expects costs to rise because the more rigs that lay down, the more companies go under, then there won’t be that many rigs to choose from. In fact, those high dollar rigs are mostly doomed in his mind. They may never drill another well and are headed for the scrap pile. So I am pretty confident that this shake out will seriously impact the service sector at least as much as the explorers. If the glut shrinks fast, and power plants ramp up gas consumption for electric production at the expense of coal (which suffers from Presidential headwinds) then it suggests natural gas could pop upwards and new drilling isn’t going to fuel a glut for some time. The recovery may be very slow, even beside the fact the banks are being toasted dark brown and won’t be so eager to lend.

    – “We can’t just drill our way to lower gas prices,” Later in his speech, he added: “anybody who tells you that we can drill our way out of this problem doesn’t know what they’re talking about, or just isn’t telling you the truth.” “You can bet that since it is an election year, they’re already dusting off their three-point plans for $2 gas. I’ll save you the suspense: Step one is drill, step two is drill, step three is drill.” – Obama 4 years ago (thanks for the quote to Marita Noon, energy columnist)

  • Joseph Wells

    Art, great article. You nailed it. The sooner than later price increase will be between now and July 2016. I made a similar prediction in the following article. My forecast was made by computer model where production of all wells was determined theoretically based on past drilling activity. The process also depends on production curves and published EIA drilling rig productivity and results in production that is amazingly close to EIA records. By playing with the model I was also able to deduce that the overall effect DUCs is very small. BTW I’m just an engineer who recently took an interest in natural gas because of the wild swing happening right now.

  • Horizontal oil wells in four major oil producing regions (Bakken, Eagle Ford, Niobrara and Permian Basin) produced about 8 Bcf per day in 2015. Gas from all four is now on steep decline.

    • Arthur Berman


      Niobrara and Eagle Ford have certainly declined a lot. Shale gas is down 0.7 bcf/d excluding Barnett, Fayetteville and Haynesville–with them, its 6.7 bcfd.

      Thanks for your comments,


  • Flint Ogle

    Great analysis, Mr. Berman. Regarding your figure 5, are you somehow normalizing the data (I assume drawn partially from table 5a in the EIA STEO)? I created a similar chart from the data in the March STEO just out, and it is far choppier… Thanks for any input. Flint

  • Flint Ogle

    Regarding my prior question, please disregard. Just noticed the note on figure 5 regarding moving averages…

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  • Art P

    Hi Art,

    Any concerns with the strong import volumes from Canada we’ve been seeing? “What is different this time, however, is that net imports will reach zero in early 2017 because of decreasing imports from Canada and increasing exports.”

    A fellow Art

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