Rig Count Increases by 19 As Oil Prices Plunge–What Are They Thinking?

The U.S. rig count increased by 19 this week as oil prices dropped below $48 per barrel–the latest sign that the E&P industry is out of touch with reality.

Wrong Way
Getty Images from The New York Times (July 26, 2015)

The last time the rig count increased this much was the week ending August 8, 2014 when WTI was $98 and Brent was $103 per barrel.

What are they thinking?

In fairness, the contracts to add more rigs were probably signed in May and June when WTI prices were around $60 per barrel (Figure 1) and some felt that a bottom had been found, left behind in January through March, and that prices would continue to increase.

Daily Crude Oil Prices Thru 24 July 2015
Figure 1. Daily WTI crude oil prices, January 2-July 24, 2015. Source: EIA and NYMEX futures prices (July 21-24).
(click image to enlarge)

Even then, however, the fundamentals of supply, demand and inventories pointed toward lower prices–and still, companies decided to add rigs.

In mid-May, I wrote in a post called “Oil Prices Will Fall: A Lesson in Gravity”,

“The data so far says that the problem that moved prices to almost $40 per barrel in January has only gotten worse. That means that recent gains may vanish and old lows might be replaced by lower lows.” 

In mid-June, I wrote in a post called “For Oil Price, Bad Is The New Good”,

“Right now, oil prices are profoundly out of balance with fundamentals. Look for a correction.”

Oil prices began falling in early July and fell another 6% last week. Some of that was because of the Iran nuclear deal, the Greek debt crisis and the drop in Chinese stock markets. But everyone knew that the first two were coming, and there were plenty of warnings about the the Chinese stock exchanges long before July.

The likelihood of lower oil prices should not have been a surprise to anyone.

Of the 19 rigs added this week, 12 were for horizontal wells (Figure 2) and 7 of those were in the Bakken, Eagle Ford and Permian plays that account for most of the tight oil production in the U.S.

Figure 2. Rig count change table for horizontal wells. Source:  Baker-Hughes and Labyrinth Consulting Services, Inc.
(click image to enlarge)

Horizontal shale gas plays added 8 rigs. That is as out-of-touch as the tight oil rig additions since gas prices averaged only $2.75 in the second quarter of 2015 (Figure 3) and are almost half of what they were in the first quarter of 2014.

Natural Gas Chart_2014-15 Price
Figure 3. Henry Hub natural gas daily prices and quarterly average prices.
Source: EIA and Labyrinth Consulting Services, Inc.
(click image to enlarge)

The U.S. E&P industry is really good at spending other people’s money to increase production.  It doesn’t matter if there is a market for the oil and gas. As long as the capital keeps flowing, they will do what they do best.

Don’t be distracted by the noisy chatter about savings through efficiency or re-fracking. Just look at the income statements and balance sheets from first quarter and it’s pretty clear that most companies are hemorrhaging cash at these prices. Second quarter is likely to be worse and it gets uglier when credit is re-determined in Q3, hedges expire, and reserves are written down after Q4.

This is an industry in crisis despite the talk about showing OPEC a thing or two about American ingenuity. Increasing drilling when you’re losing money and prices are falling doesn’t sound very ingenious to anyone.

Watch for the markets to agree as oil prices fall lower in coming weeks.


  • sani muhammed isah

    These situation can best be analised by expacts in the industry. You are doing a good job by giving us this comprehensive update. I am a student and a beginer for that mater but I promise to close mark u till I catch wit your source of knowledge. Thanks Art Berman

  • John Skees

    Please notify me of follow-up comments.

  • gamesjr

    Art, when will the downturn in production resulting from the 50% drop in rig count begin?

    • Arthur Berman

      The downturn in production will begin when the stupid money stops funding more wells and completions. Most of the wells drilled by too many rigs did not contribute much to total production–the 80/20 rule–so it’s really the 20% that we are talking about. Higher oil prices and more OPM (other-people’s-money) from mid-March through June meant more cash to complete wells.

      Remember, there is a long lag in production reporting so data from April is just beginning to stabilize. I don’t expect to see a downturn reflected in the data for another few months.

      My colleague Euan Mearns will post his analysis of tight oil production tomorrow. He estimates a drop of 830,000 bopd.

      Thanks for your question,


  • Art, I’m one of your biggest fans and it’s a rare day that I disagree with you. But in the case of this post, I think you’re glossing over some important drivers that make the increasing rig count unsurprising to me.

    Most land leases include provisions that drilling must begin before date X or the deal is off. While I don’t have objective statistics on the specific dates, it would be reasonable to assume that “it’s now or never – we’re going to lose the lease otherwise!” mentality is driving a lot of this bad decision making.

    More importantly, when credit lines are again reviewed in October, this industry is going to be in BIG trouble, and the execs know it. Consistent with your “good at spending other people’s money” sentiment, I think they are drilling now because they know it’s going to be a few years before they can again get financing for more drilling. The bank can’t pull credit that’s already been spent.

    I use the analogy of a young person living beyond their means on credit cards. It’s well known that when it becomes clear their credit is about to come crashing down, they often go on one last big spending spree, knowing they won’t be able to do so again for about 7 years after they declare bankruptcy. The shale drillers are doing the same thing.

    Don’t get me wrong – I strongly concur that this industry is in BIG trouble. I think it’s really going to hit the fan during fall maintenance season when we could again face a storage crisis and contango explosion. But I don’t think these guys are too dumb to know what’s happening. I think they’re even better than you give them credit for at spending other people’s money on mal-investment before their creditors wise up to what’s happening.

    In short, I wholeheartedly agree that “they don’t get what’s really happening”, but the “they” in question is not the E&P’s, it’s their creditors.

    Respectfully submitted,

    Erik Townsend
    Fourth Turning Capital

    • Arthur Berman


      I didn’t say that I didn’t understand what the executives are thinking and doing.

      More drilling now just reflects ongoing bad business decisions and total disregard for market fundamentals, not to mention for shareholders’ and investors’ interests–like the spoiled adolescent you describe.

      “Use it or lose it,” however, is just another piece of noisy chatter to distract from the truth that the companies are losing money needlessly.

      There is no requirement that a company must drill a lease. Most leases have a built-in extension clause called a “kicker.” They can pay an additional bonus–usually much less than the cost of a well–and worry about drilling when prices are higher.

      Worst case is that they let the lease go and the mineral owner gets squat–it’s in the owner’s interest to get a well drilled because he gets a royalty payment for no investment regardless of whether the producer makes or loses money on the oil.

      All the best,


  • Sam Taylor


    The standard deviation of the weekly rig count is something like 12 or 13, so a move like this is barely distinguishable from background noise in a weekly time series. I think it would be wise to wait for a few more data points before we call the reversal in tend of the last few weeks significant.

    • Arthur Berman


      I disagree.

      The rig count standard deviation that you mention has not been the case since mid-2014 and for most of the intervening period the trend was down, not up. As with all data, one week is not a trend but there were 7 previous weeks of rig counts leveling out after the long fall, so this increase does fit a somewhat more-established trend of stabilization.

      In any case, a 19-rig increase is huge–even if only a one-week anomaly–especially given the current oil and gas price and the general state of the industry.

      Thanks for your comment,


  • Ryan Cobb

    Hi Art,

    Back again to take the other side of the coin. After all, it’s no fun if everybody is on the same team.
    Surprised by the timing of the rig-ads but not the fact that operators are looking to get back to work. What choice do they have? Wall St. has proven that production cuts will be met with a big sell-off.
    Something happened in Q1 that the media seems to have totally missed. In fact, one would have needed to sit through numerous conference calls to pick up on the trend of E&Ps layering in a substantial amount of new hedges at $65. To me, this suggested that management was aware that the downturn would be a longer protraction than originally anticipated and that $65ish is a workable level for those who have good assets. Again, when I read these articles, I tend to wonder who are we talking about? The litany of walking dead who will be bankrupt or bought out in the next three months (mainly juniors with low quality assets) or the land rich, cash poor class of E&P who has acreage worth drilling at sub $70 WTI. If it is the latter that these post seek to target, then I have to disagree with your statement that “the companies are losing money needlessly”
    The negative cash flow is cause for concern and on a fundamental basis- you are right that the industry as a whole has basically bled out other peoples cash even through the $100 dollar cycle. This is probably attributable to E&P’s propensity to spend other people’s money as well as their backer’s appetite for rolling up the debt into high yield instruments. Still, the source of the cash burn is hard to track (some of costs of infrastructure and acreage delineation is still leaking into the balance sheet). Adding D&A back to net income gives a slightly better idea of current FCF (or lack of) and changes the numbers compared to simply subtracting CAPEX from operational cash. The average FCFE or leveraged cash flow ratio is slightly more encouraging for the better E&P’s. This is a weak defense I know, but it is important in the scope of how Wall St. and the public treat this sector as opposed to others. Net flicks has burned more cash than Pioneer and EOG combined but still trades at a 150X forward multiple. IBB, biotech etf with largest AUM, has tripled in last 2 years despite the overwhelming majority of companies which comprise the index having negative, sustained earnings. Investors latch on to these companies, blind to the fundamentals, pinning their hopes on one drug that is still in the first phase of testing. Yet the energy sector has been crucified by WS. Investing is about alternatives. Markets are supposed to serve as a discounted mechanism for future growth. So if we are going through a global deflationary cycle and subsequent demand destruction: what is being appropriately discounted here oil or net flicks subscriptions? For my money, I would rather support companies backed by hard assets which I know the world absolutely needs to function. IEA almost always revises demand upward for crude oil. This has been going on for years yet people still believe their forecasts. Pub traded E&P’s are at mercy of WS and cannot afford to let production drop off a cliff while they wait for prices to come back. You may consider that a bad business decision but I think shareholders would disagree.
    In reference to Mr. Townsend’s mention of drilled to hold wells. I would be willing to wager that if we look at wells completed since beginning of year and new permits issued, 90% would be in-fill wells designed to target best rock/low cost combo. High-grading now (waiting for 2016 Q1 financials might be the only way to know for sure) will have a significant impact on earnings and many of the companies with attractive acreage really have no option. I will include some notes on EF operators I follow to make the point (this considers strip prices;does not reflect hedging activity):
    Devon- 60+ wells drilled since 1/1/2015, majority in Dewitt corridor (possibly best unconventional rock in all of North America) second month average for majority wells 1,000 bbl per day+++) Average undiscounted payback period (EBITA)- 5 months.
    Marathon- lots of wells in down dip EF Karnes County and a few chalk wells. Not as prolific as DVN but should meet minimum threshold of 100k bbl in 10 months to support a reasonable IRR.
    EOG- not going into specifics here but lots of quality leasehold that can be drilled at today’s strip prices
    Carrizo- Medium GOR window of LaSalle County continues to impress. Not particularly high IP’s but low decline profile helps to stabilize production targets. Most of CRZO wells can be drilled at $50.
    SM- low cost, gas play in Webb County. Improved liquids yields. My type curve for best areas shows 200k bbl, 3 bcf. Gas pays for the wells on its own.
    COP- lots of fairway to work.
    Numerous operators with good acreage in Delaware Basin, particularly Phantom wolfcamp in Reeves County.
    Point is this: there are too many factors in global market for E&P’s to dictate oil price. You suggest, in the meantime, that they just wait on sidelines while Saudi and Iraq pump at full capacity? The problem is not lack of economic inventory in North American shale fields. The problem is depleting best cost/quality combo at low prices and not having growth engines in future when prices MIGHT be higher. But being a public company means making sacrifices for the good of shareholders in the interim. Markets always overshoot to upside or downside in these circumstances. Many of these companies’ stock prices are well past oversold. The bar is set reasonably low for earnings. E&P’s have to do something to stem the outflows. Drilling their best acreage should make for an easy earnings beat regardless if it is healthy for long term prospects. I am not saying I agree with this strategy or that there is not deficiencies in the entire business model but not sure why we keep piling on the shale guys. Their plight is not much different than any other mediocre market segment. But by all means let’s continue the onslaught; it will make for some good investment opportunities when some of the short money eventually gets squeezed out. And it will.

    • Arthur Berman


      Thanks for your very thoughtful comments. You make some good points and I like the way you that you have rationalized the current situation.

      First, by free cash flow I mean the difference between cash from operations and capital expenditures so DD&A is not an issue.

      Second, I agree with your logic about drilling good positions now that are profitable at today’s price or, at least, may be profitable at a price in the near future.

      The problem is that the break-even prices offered by investment bank research groups or the companies themselves are too low. I say this based on many years of doing the reserve forecasts on these plays, and running economics based on 10-K and 10-Q data from the companies themselves.

      The companies in good positions in the tight oil plays had negative cash flow from their Q1 10-Qs when oil prices averaged about $48/barrel. Today, prices are a bit below that average price so I’d say they must be losing money today based on the best information we have from them. I am sticking to my story that the rigs added last week were contracted when oil prices were $60 and people believed they were increasing.

      I disagree with your statement that companies are drilling wells today at a loss for the benefit of their shareholders. They are drilling today because they need to maintain production levels and know that credit re-determination, expiring hedges, and reserve write-downs are all coming in the next 6 months–their ability to drill will be more limited then.

      Your point about buying $65 hedges says less about their break-even prices than it does about their pessimism about the direction of price.They are doing what they can to control the damage and I support that, but let’s not turn that negative into a positive.

      The oil and gas business is not an on-line sales business like Netflix nor is it like the electronics business. It is an old extractive industry that has real limits on what technology can do for cost. The Moore’s Law analogy is silly and may not apply much longer to electronics as that industry matures.

      When you talk about future growth, it is worthwhile to look at tight oil proven and proven undeveloped reserves because that at least sets some framework limits to the conversation. EIA forecasts peak U.S. oil production in 2020 and I suspect that is optimistic.

      No one can deny that the growth of tight oil production in the U.S. is impressive and was somewhat unexpected. But production volumes and profit do not necessarily go hand-in-hand.

      Despite favorable well economics at $95 oil prices, the companies had negative cash flow. As I cautioned in my post, Don’t be distracted by the noisy chatter about savings through efficiency or re-fracking. If they couldn’t show at least neutral cash flow a year ago at $95, do you really think that so much has changed that they can now be profitable at half that? If so, you are more of an optimist than data allows me to be.

      All the best,



    Art, The US oil directed rig count has most certainly turned a corner “for now”. A number of reasons have been offered for this. Regardless of reason, this is undoubtedly the wrong way for the oil price. The main point of my recent article that you link to up this thread was to observe that at current drilling rate (rigs * efficiency) US oil production may fall be less than 1 Mbpd and that is unlikely to be sufficient to revive price and profitability.

    IEA OMR data for June are out now. Total supply is up another 500,000 bpd. US production is down a paltry 50,000 bpd (difficult to evaluate because of revisions). Demand growth looks incredibly weak.

    I have become very gloomy. If WTI does not hold at support level around $43 then I think we may see sub-$20 and US rig count going S of 100. 2 to 3 Mbpd of non-OPEC production has to go to normalise price at a level where conventional producers can make a profit. Sub $20 will create an interesting social experience throughout OPEC and Russia.

    • Arthur Berman


      Thanks for your comments and I sure hope that you are wrong about $20 oil!

      Of the 500,000 bopd world liquids increase in June, 340,000 was from OPEC of which 270,000 was from Iraq.



  • Art, one thing I’ve been wondering about the Iraq production figures is if they include Iraqi Kurdistan – I think production has grown there to over 500,000 bpd, exported through Turkey that is both best friend and worst enemy of the Kurds at present.

    Revenues evidently go to Baghdad and re-imbursed to Erbil. trickling down slowly to the OECD cos operating there. This all seems a bit phoney to me.


  • Fred Palmer

    Natural gas production will go down with oil production and a natural gas “black swan” experience may be coming for the U.S. economy. Decline rates are as inexorable as the sun coming up every day and will result in sharply higher prices,
    stabilizing only after reinvestment from available cash flow is deployed by the remaining NG producers.

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