Shale Gas Rig Counts Are Too High

Spending cuts for oil-directed drilling have dominated first quarter 2015 energy news but rig counts for shale gas drilling are too high.

Investors should pay attention to this growing problem. Bank of America fears sub-$2 gas prices now that winter heating worries are over. Low natural gas prices affect the economics for gas-rich oil production in the Eagle Ford Shale and Permian basin plays as well as for the shale gas plays.

Meanwhile, an orgy of over-production is taking place in the Marcellus Shale. Well head prices are now below $1.50 per thousand cubic feet of gas because of limited take-away capacity and near-saturation of regional demand. Even companies in the Wyoming, Susquehanna, Allegheny and Washington County core areas of the Marcellus play are losing money at these prices. 

The rig count for shale gas plays has decreased by only half as much as for the tight oil plays. The reason appears to be that most shale gas companies do not have significant positions in the tight oil plays and must continue to drill to maintain production levels.

Shale gas rig counts have dropped only 19% for horizontal rigs and 25% for all rigs from 2014 highs. The corresponding decrease for tight oil plays is 41% and 46%, respectively, as shown in the table below.

Rig Count Tight Oil vs Shale Gas Change Table 21 March 2015
Rig count change table for tight oil vs. shale gas plays as of March 20, 2015.  Source:  Baker Hughes and Labyrinth Consulting Services, Inc.
(click image to enlarge)

This has puzzled me because the shale gas plays are not commercial at less than about $6/mmBtu except in small parts of the Marcellus core areas where $4 prices break even. Natural gas prices have averaged less than $3/mmBtu for the first quarter of 2015 and are currently at their lowest levels in more than 2 years.  

Chart_2014-15 Quarterly Avg Price March 2015
Henry Hub daily and quarterly average natural gas prices.  Source: EIA and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

Most shale gas producers either do not have positions in the tight oil plays or are strongly gas-weighted in their production mix.  These companies must continue to drill in shale gas plays despite poor economics in order to avoid the consequences of falling production levels.

The only criterion that seems to matter to investors these days is production guidance.  If production drops, stock value will fall even farther than it has already.  This will trigger loan covenants if asset values fall below thresholds set out in the loan agreements. When that happens, the loans will be called unless the companies can come up with more cash. This might result in bankruptcy. So, the drilling must continue as long as there is capital.

The table below shows the companies that have overlapping positions in both tight oil and shale gas plays based on current drilling activity.

Rig Count Tight Oil vs Shale Gas Change Table 21 March 2015
Current rig counts for companies with positions in both tight oil and shale gas plays.  Source: DrillingInfo and Labyrinth Consulting Services, Inc.  Rig counts may differ from Baker Hughes because the source is different.
(click image to enlarge)

All companies in the table except Continental Resources are gas-weighted so maintaining gas production levels is important to them for the same reasons it is important to operators without tight oil exposure. Overall, the companies in the table operate only about one-third of all rigs in the shale gas plays. Shale gas is otherwise characterized by a different set of companies that feel they have no choice but to continue drilling and hope that investors don’t notice or care.

Shale Gas Operator Rig Count 21 March 2015
Shale gas rig count by operator.  Source:  DrillingInfo and Labyrinth Consulting Services, Inc. Rig counts may vary from Baker Hughes because the source is different.  (click image to enlarge)

But don’t oil-weighted companies face the same concerns about production levels?  

I compared the change in rig count from January to March 2015 by operator in the Eagle Ford Shale play to understand how rig counts are being reduced.  I found that key operators were strategically reducing their activity to the best locations in core areas in order to affect production levels the least (see chart below).  

Eagle Ford Shale rig count comparison by operator, January and March 2015.  Source:  DrillingInfo and Labyrinth Consulting Services, Inc.  (click image to enlarge)

The next most active class of operators are holding drilling fairly constant in this most productive of tight oil plays.  Then, there are a small number of new entrants to the play that are more than balanced by operators exiting the play.  My previous post on Eagle Ford well performance showed that there are ample locations in the most commercial parts of the core areas for well-positioned operators to optimize production with fewer new wells.

It is worth noting that the top group of operators in the Eagle Ford Shale play have reasonably good balance sheets (see the table in my previous post) and are not particularly vulnerable to loan covenant threshold triggers. This cannot be said for many of the top operators in the shale gas plays shown in the table below.

GAS WEIGHTED Sampled E&Ps 2014 10 March 2015Summary table of 2014 year-end financial data for natural gas-weighted U.S. land-based E&P companies. All dollar amounts in millions of U.S. dollars. FCF=free cash flow; CF/CE=cash flow from operations/capital expenditures. Source: Google Finance and Labyrinth Consulting Services, Inc.
(Click image to enlarge)

The table shows financial data through year-end 2014. What it reveals is not pretty. 2014 negative cash flow reached $15.5 billion, an increase of $7.2 billion over 2013. Much of this increase involved Southwestern Energy’s puzzling acquisition of Chesapeake’s West Virginia Marcellus Shale position that increased that company’s negative cash flow by almost $5 billon over 2013.

On average, shale-gas companies earned only 68 cents for every dollar that they spent in 2014. Total debt increased almost $10 billion to $93.5 billion and average debt exceeded stated equity by 18% excluding companies with negative equity including the now-bankrupt Quicksilver Resources.

Shale gas plays are commercial failures.  The misuse of capital to continue to increase production while destroying price and shareholder equity has gone on for too long.  Investors should demand that shale gas companies cut rig counts at least as much as tight oil companies have.

Rig Count Summary for the Week Ending March 20, 2015

Rig counts are important today because they may indicate future trends for oil prices. Horizontal wells in the Bakken, Eagle Ford and Permian basin plays produced about 3.5 million barrels of crude oil per day in November 2014 (see table below).  These are, therefore, the key plays to watch for rig count decreases.

U.S. key tight oil play production. Source: Drilling Info and Labyrinth Consulting Services, Inc.
(click image to enlarge)

The horizontal rig count for these key plays–Bakken-Eagle Ford-Permian HRZ-dropped 25 rigs this week (23 rigs last week) and was down 40% from the 2014 maximum. The horizontal rig count for tight oil plays overall dropped 22 rigs this week (32 last week) and is 41% lower than the 2014 maximum (see the first table above in this post).  Rigs for all tight oil plays were down 31 this week (39 last week) and are 46% lower than 2014 maximum rig counts.

Summary of most changed rig counts by play. Source: Baker Hughes and Labyrinth Consulting Services, Inc.
(click image to enlarge)

The plays with the greatest change from their respective 2014 maximum rig counts may be viewed as the least commercially attractive to producers. This suggests that the Barnett, Granite Wash, and Permian All are the least attractive.

It is interesting that the Bakken moved into this category this week.  Well head prices in the Bakken have now fallen below $30 per barrel.  The play is geologically solid but wells are expensive, the pay-out times are fairly long because relatively low decline rates for a shale play, and rail transport adds a lot to the cost of each barrel of oil.

The overall U.S. rig count for the week ending March 20, 2015 was 1,069 of which 1,030 were land rigs. Only about 25% of total land rigs and 11% of horizontal rigs are drilling outside of the major shale gas and tight oil plays. Detailed data for all of the plays are shown in the table below.

Summary table for all U.S. land rig counts. Source: Baker Hughes and Labyrinth Consulting Services, Inc.
(click image to enlarge) 

This and other data continues to suggest decreasing U.S. tight oil production and increasing world demand. Rig count continues to fall for the critical oil-producing plays and that means that things are on track for an oil-price recovery sooner than later.

Investors should carefully examine why shale gas players have not reduced rig counts more. Continued drilling in the Marcellus will crush natural gas prices further.  The fact that there are 34 rigs running in the Haynesville Shale is economically baffling.  We may only speculate on why there are 51 rigs in the Woodford Shale and why some operators now call it the SCOOP play.



  • Keith

    Very interesting blog.

    Initially, many comments were made to the effect that the rig count was not reducing production because of keeping high grade rigs in core ares.

    It seems that the background to these comments is that, as you pointed out, the IEA talked about Q4 production at the same time as descending rig counts (which only really kicked in in mid December and January.

    What do you make of the fact that the DMR in N Dakota and the Texas Railroad commission data show significant production falls in January whereas EIA predicts only very modest falls by April.

    Second, a detail, but your 2014 high for E Ford rigs is 138 whereas Baker Hughes shows it as 210.

    Third, do you think that the reason for continued drilling in uneconomic gas plays relates to activity, drilling or productivity clauses in debt covenants, or HBP clauses with landowners?

    Thanks and best wishes, Keith

    • Arthur Berman


      Thanks for your comments.

      The idea that production doesn’t change because operators move to better locations, assumes that they are too stupid not to have done that already. So, what may happen is that riskier locations are foregone in favor of less risky locations but, since less risky locations were being drilled before, all that happens is that the average well performance improves. Overall production declines. It amazes me that people somehow believe the hocus pocus that shale production is magical and doesn’t decline with fewer wells. Doesn’t everything decline when you do less of it? Isn’t that just basic physics? Amazing.

      EIA makes lots of predictions that are wrong and I appreciate that they make them and don’t criticize them for being wrong because it’s almost impossible to be right. Nevertheless, they predicted, along with the world except for me, that production would not decline until the second half of 2015. I predicted strong declines by mid-year ( My assumption was that January would be the peak month for Bakken, Eagle Ford, Permian, Niobrara. It looks like December may have been the peak month for the Bakken.

      About the Eagle Ford rig count, Baker Hughes shows the rig count as 138 as I do:

      There is no such thing as HBP agreements with landowners. A lease has a term and may be held by production beyond that term if commercial production is established. There is nothing in the lease agreement that requires the lessee to do anything except pay a bonus and rentals. So, the notion that companies are drilling to hold leases by production may be true but it is not an obligation of the lease agreement. The question you have to ask is this: does it make more sense to spend $5-10 million to drill a well that is doomed to produce into a non-commercial market or pay $1 million to extend the lease another 3 years and drill when prices are higher or not at all if prices stay low? I am in this business and I always take the cheaper, more sensible option every time. The HBP story is another of many fairy tales that companies and analysts tell to keep investors worrying about the noise instead of paying attention to the signal: shale gas plays are a commercial failure and always have been since 2008.

      All the best,


  • razz traffic

    Not so much a comment but a question. Where do you see the ever decreasing oil storage capacity coming in to play to impact price? As one of the large banks recently projected, storage capacity will max out sometime @ June, forcing oil onto the market at any price, if this scenario plays out. Also potentially increasing the glut of oil coming to market is today’s ZeroHedge article titled The Perfect Storm For Oil Hits In Two Months: US Crude Production To Soar Just As Storage Runs Out I’d love to hear any follow up comments you may have on STORAGE CAPACITY possibly topping out and also on the ZeroHedge article flooding even more crude onto the market in a couple of months. I appreciate your good work in this area. Razz

    • Arthur Berman

      razz traffic,

      There are opinions on both sides of the oil storage debate. First, the great big number that says we added 7 million barrels last week includes all liquids. The U.S. only produces 9 million barrels of crude oil per day and we’re sure not putting 80% into storage.

      So, at issue is the difference between storage capacity for crude oil of ~620 mmbo and current storage of ~450 mmbo. It will take about 6 months to reach 620 at the current rate according to my friend and expert Mike Bodell. Refineries are going back to full capacity any day now after their maintenance season so the fill rate will slow because of that and because of summer driving season.

      The real issue is not whether storage will become over-filled because it probably won’t based on the logic in the preceding paragraph. The issue is whether traders crush prices once storage reaches some magic level of perhaps 80 or 85% of total. I think that they will unless there is some tangible data that says that production is slowing and that is reflected in lower fill rates.

      It is hard to keep the signal in focus when analysts throw out so much noise, as I commented to Keith earlier. The noise overwhelms what is really important:

      The U.S. tight oil companies have ruined their own market by wanton over-production and have brought the global oil price into the gutter

      OPEC is doing nothing because there is nothing to do until these cowboys put their guns and bravado away and act like adults (which they are incapable of so we will have to wait and let price do its magic).

      All the best,


  • Keith


    Thanks for the response. Sorry, I was confusing present from original high values of rigs in the BH data.

    Re your estimate of production reduction of 600 k bopd by June, I read that and agree. I did a simpler calculation, looking at rig reductions, particularly horizontal capable ones, with EIA estmates of production per rig across the 4 main oil production basins and figured that production should decline by about 220 k bopd/ month from around March or April.

    I can understand why Exxon issues bearish comments on oil price. THey have more time to pick off acquisition candidates while prices are low

    I can see the political angle from the IEA or the EIA (talking down prices puts more pressure on Russia, and the political rapprochement with Iran puts more negative pressure).

    THe banks issuing bearish comments seems more puzzling. If they were short on prices – fair enough. But they also made money issuing junk bonds, and low prices makes defaults more likely.

  • Keith

    Finally re your response to Razz, re cowboys, the CEO of Continental called the frac arena coyboyistan

  • Keith


    Was just thinking about why rig counts are not falling in gas plays. Is it possible that company A, having a contract with rig provider B, and deciding to use the rig rather than take the hit in the early release clause, decides to transfer that rig to a gas play rather than an oil play? Could it be that operators feel they may lose less money utilising a contracted rig in a gas play rather than an oil play?


    • Arthur Berman


      I don’t know the answer beyond what I stated in the post. What you suggest may be occurring but there are some significant mobilization-demobilization fees from moving from one geography to another that must be serious.

      All the best,


  • BP

    “This has puzzled me because the shale gas plays are not commercial at less than about $6/mmBtu”

    We haven’t seen a quarterly price of $6/mmBtu since the lead up to the great recession, but shale gas production keeps on rising. I have to think a lot of gas is commercially viable at prices lower than $6/mmBtu. The market knows something that we don’t.

    • Arthur Berman


      The market knows nothing.

      The market acknowledges that drilling and production continue at low gas prices, not that the production is commercial.

      As long as pure shale gas players continue to have negative free cash flow and increasing debt, the plays are not commercial by definition.

      The argument that the companies are expanding their capital base at the expense of positive cash flow goes only so far. This has been going on for a decade.

      The problem is that shale wells decline so fast that new wells must be drilled continuously or production drops. When production drops, investors abandon the company’s stock which lowers asset value which triggers loan covenants and the game is over.

      All the best,


  • Keith

    Thanks again Art for the replies.

    If it was me and I was negotiating with my rig provider, I would be saying: “Ok, the rig I have contracted until May is in oil play X, and the rig I have in gas play Y is completing its contract now, what about we switch the contract to the rig in gas play Y so I can obviate the mob de-mob costs?”

    Just a thought, because I also noticed that gas wells were not being idled at the same rate.

  • Stephen

    It’s not just the stock market that has a different view of what the breakeven price is. It’s also groups like RBN Energy that have done a well-by-well analysis.

    Also, Bentek has reported that oil production in the big shale plays has been largely flat so far this year, not down. And then there is the big fracklog waiting to be unleashed once prices start to move higher, per companies like EOG and Continental. So I’m not sure that I agree with your call of large production declines coming soon.

    • Arthur Berman


      Differing views on break-even prices are the rule.

      How were the break-even prices determined? What costs are included or excluded? Are costs like G&A or interest expense excluded from these calculations? How about the differential local price to the Henry Hub or WTI? If enough costs are excluded, the break-even price can be whatever we want it to be.

      How was EUR determined? Was it by careful decline-curve analysis or from type wells taken from company presentations? A large EUR results in a lower break-even price.

      If you go to the company 10-Ks for 2014, costs are provided along with revenues on a per barrel, mcf or equivalent basis. You will find that the break-even prices determined from the companies public filings rarely correspond with the published break-even prices from research consultancies and investment banks.

      The chronic negative cash flow stated by the companies in these filings argues against the low break-even costs that many consultancies and research groups claim.

      I don’t believe that I said that oil production was down. What I said was that decreasing rig count suggests that oil production will fall.

      EIA published “Falling rig counts drive projected near-term oil production decline in 3 key U.S. regions” last week.

      The specter of thousands of uncompleted wells that will unleash untold waves of production was a hot topic after the 2008-2009 price collapse but we never saw the predicted surge. Bernstein published “The Myth of the Frack Backlog” last week on current drilled uncompleted wells and concluded that “overall working inventory is not significantly higher than in prior years.”

      There is always more noise than signal about shale plays. There are hundreds of articles written every week to promote the notion that production from shale reservoirs does not follow the laws of physics or decades of empirical observations of depletion. People may believe whatever they like but there are a some fundamental realities that cannot be denied.

      If most companies reported negative cash flow for 2014 at $93 average oil prices, then claims of break-even prices at less than that must be viewed with caution. Since wells must be drilled to produce oil and gas, fewer wells drilled must eventually result in decreased production.

      Thanks for your comments,


  • Chris


    I really enjoy your presentations and articles. As far as you are aware, are there any companies left that primarily produce natural gas using conventional methods/wells?


  • Keith


    Following earlier comments and corroborating your type of approach versus EIA reports, Platts is reporting that EIA figures now show lower 48 January gas production versus December 2014 is down 1.2 Bcf/d. (1.4%). (March 31).

    Meanwhile the EIA drilling productivity report issued on March 10 suggested that gas production for April 2015 versus March 2015 would be up 221 MM scf/d (onshore main frac basins only).

    Amazing. One report suggests April is still growing while the other points out a decline for January, 3 months earlier.

    Best wishes, Keith

  • Keith

    Update: the numbers are from EIA report Mar 30, Petroleum and other liquids, Crude Oil Production

  • Steve


    I feel you are overlooking a fundamental reason why drilling cannot stop in the Marcellus in particular. That reason in produced water disposal. Water disposal in the Marcellus cost more than $13 per barrel and many wells have water oil ratios greater than 50 BW/MMcf. Operators solve this problem by reusing produced water to frac new wells. However, imagine what happens to your earnings if you stop drilling and fracing new wells and have to dispose of all the water especially at $1/Mcf realized gas prices. Now your existing wells are cashflow negative and your reserve base vastly shrinks or approaches zero depending on water ratios in your area. Companies must stay on the treadmill and hope for higher prices or die today. It’s a bad situation that is self perpetuating and the industry badly need to solve the produced water problem with the State of PA. Sadly, PA is intent on killing its golden goose with overregulation and ever increasing burdens on industry. In short, the water issue should not be ignored as part of what drives these companies and stopping drilling may not be quite as simple as it seems.

    • Arthur Berman


      Are you saying that operators will spend even more money to complete new wells that will lose still more money at $1/mcf well head prices to save the cost of water disposal?

      I have never heard of water disposal costing anything approaching $13/barrel.

      I am confused.

      All the best,


  • Steve


    Yes, that is what I am saying. Water disposal costs in PA are enormous. There are only 6-7 disposal wells in the state and other water must be treated or hauled to Ohio for disposal. Realizing this operating expense against current revenues on each producing well would in many cases make the wells cash flow negative right now. Cashflow negative wells have zero reserves. Other wells would have greatly decrease positive cash flow and reserves. Produced water must be reused or reserve writedowns, sometimes major, will be the result for operators. Operators keep drilling to delay the day of reckoning in multiple ways and water disposal plays into their calculations.

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