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Plummeting Rig Counts: How Low Can They Go, and Should We Care?

April 6, 2016 | By Charles Nevle

Another week – another drop in the U.S. rig count. The rig count for the week ended April 1 is down to just 450, a drop of 14 from the prior week. If that sounds low, it is. In fact, it's the lowest total in the history of the count, which dates all the way back to 1944, according to Baker Hughes.

However, conventional wisdom for some time now has been that rig counts don’t really matter. This wisdom is based on the evolution of rig productivity. As technology improves, there is no comparison between the rigs of several years ago and the rigs of today, which are drilling supercharged wells benefiting from horizontal drilling, multi-stage fracking and extremely long laterals -- among the many technological innovations that have come to fruition.

Since their peak in October 2014 of over 1,930 rigs, we’ve seen rig counts fall by an amazing 77%. Think about that: We are operating with only 23% of the rigs which were active just 18 months ago. And yet, over that 18 months, production continued to grow.

Rig Counts and Dry Gas Production

So, even as rigs fell, efficiency gains have allowed production to continue to grow. One way to see this is to look at the number of wells drilled per rig. 

Wells Per Rig Increase with Rig Decline

As rigs have declined, the number of wells drilled per rig have increased. Operators are doing more with less, operating with the best crews and focusing on known areas to maximize the productivity out of each dollar in capital expenditures. Gone are the days of experimenting with peripheral sub-plays.

We also see this in the data on productivity from each well. As operators move to the best areas with the highest production potential, the average amount of gas from each new well is also increasing. For example, let’s look at PointLogic’sEagle Ford Dry Producing Area. 

Productivity Per Well Increases as Rigs Decline

As rig counts in the Eagle Ford Dry producing area declined from around 35 to 15, the productivity of the average well as measured by the 2nd month of production increased from about 2.7 million cubic feet per day (MMcf/d) to over 4 MMcf/d. That is an enormous increase per well and certainly helps offset the reduced drilling activity in the area. In fact, Eagle Ford Dry production as a whole has basically remained flat even as rigs have declined to now fewer than 10.

So, the question becomes, how long can these increases in productivity last? How long can plays like the Eagle Ford maintain production as rig counts continue to drop?

The answer, we believe, is not much longer -- the blood has been squeezed out of the productivity turnip, so to speak. We believe that producers have moved beyond doing more with less and are now entering the stage of doing less with less.

We see this in the big picture of lower 48 production, with production having peaked in February at 74.7 billion cubic feet per day (Bcf/d) and now hovering around 73.5 Bcf/d. That’s fine from a supply and demand perspective because production declines are necessary due to the large excess of gas in storage. But as we discussed in A V-Shaped Production Outlook for Natural Gas Production and Prices, the market will soon begin clamoring for an increase in gas production. That increase cannot be met with the current rig count, and thus rigs will need to increase, perhaps substantially.

In late 2016 and throughout 2017, higher and higher production levels will be necessary to satisfy increasing demand from LNG exports, Mexican exports and natural gas fired power generation. Our colleagues at IHS expect that the U.S. may need to increase the rig count by 200 (or 44% from where it stands this week) just by the end of this year and over 200 more throughout 2017 to meet expected demand increases. This increase would represent nearly a doubling of the current rig count by January 2018.

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The prospect of this kind of turnaround should be welcome news to producers, service companies and related equipment providers. However, significant challenges will be faced by these industries as they are signaled to respond. More drilling crews, fractionation crews, truck drivers and all the rest of the manpower, expertise and equipment will need to be called back into service. Some in the industry believe this is easier said than done, that the folks laid off or idled during this downturn will be difficult to bring back.  

The U.S. labor market as a whole is very healthy - wages are up and unemployment is down. According to a recent Reuters article, unemployment is near an eight-year low of about 5%, and wages rose 2.3% compared with a year earlier. In other words, the work force hurt by the downturn in oil and gas prices has been released into an economy that provided alternative opportunities, in theory anyway.

This fall, the market should regain its balance: production is down, demand is strong and the prospect of significant demand uptick is on the horizon. Now what the market needs is a rebound, but how do we make it happen? Producers will need to deploy more capital, which means going to banks that may be a little reluctant to jump in. Many shale producers are outspending their cash flow, which will make it very challenging for them to raise capital to fund the new drilling that the market will need in 2017. Producers, operators and service companies will need to lure back workers who may be inclined to demand some sort of guarantee before signing on.

All of this leads to one thing – higher prices for natural gas. That's the lever that will need to swing the pendulum in the other direction. The signal prices will need to send cannot be subtle.

PointLogic forecasts that dry gas production will need to increase to over 80 Bcf/d by the end of 2017 (in an environment with rig counts at their lowest level since at least 1944). This turnaround will not really be signaled for several months, so we still will likely see downward pressured gas prices, which will beget a continuing rig count drop, further cuts in the workforce, and additional bankruptcies of producers and service companies alike. In other words, we know the pendulum has to swing strong the other way, but momentum continues to push it the other direction, which makes the coming turnaround that much more difficult.

Some might point to breakeven costs and maintain that all prices need to do is get to a point that puts plays like Haynesville in the money, and then the market will be fine – plenty of gas at that price. That may be true in a frictionless market, but this market is anything but frictionless. For a long time the friction has been on the side of maintaining production increases, no matter how low prices moved, no matter how badly rig counts were decimated.

Now, we are moving to the other side where prices will have to rise, perhaps higher more than a theoretical economic breakeven. We won’t get there for several months, but it is coming. In the meantime, PointLogic is projecting a very interesting summer to churn through. Stay tuned as we monitor developments in this very interesting and historic market.


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