The impact of the Marcellus shale formation on domestic natural gas supply is difficult to overstate. The speed and volume in developing this formation is astonishing. In 2007, Marcellus supplied only 2 percent of domestic supply in the U.S. By the end of 2013 it accounted for nearly 20 percent of total supply. The EIA predicts the formation will produce an average of 15.9 billion cubic feet of gas per day in September, nearly a quarter of all U.S. production. If Marcellus had one constant trait, it would be that it has continued to prove ‘experts’ wrong or extremely conservative in their projections of the formation’s output.
Just how has Marcellus continued to grow at such a blistering pace? To start, the industry’s learning curve has been impressive. Marcellus natural gas production continues to grow despite a drop in rig count since 2012. Historically, natural gas volumes have responded to shifts in rig counts. Analysts have argued that it would be difficult for the industry to maintain production with a slowdown of drilling activity. The Marcellus has turned this logic flat on its face.
Figure 1 Source: EIA
Marcellus producers have succeeded in producing more gas from each rig. In 2007, one rig averaged roughly 422 mcf/d. The latest data in 2014 shows that producers are averaging nearly 8,000 mcf/d.
Figure 2 Source: EIA
Not only are rigs producing more gas, wells are being drilled faster. Cabot Oil and Gas, a major player in the Marcellus, recently published an investor presentation that highlights efficiency gains over the past few years.
Figure 3 Source: Cabot Oil & Gas
Since 2011, Cabot has reduced drilling days while increasing its drilling depth.
Figure 4 Source: Cabot Oil and Gas
In terms of project economics, last October, Terry Engelder, a professor of geosciences at Penn State University raised eyebrows when he stated that roughly 78 percent of the producing horizontal-drilled Marcellus natural gas wells have already paid for themselves. Even with record amounts of natural gas coming online domestically, it looks as though Marcellus producers, at least Cabot Oil & Gas, will have solid margins for a typical Marcellus well.
Figure 5 Source: Cabot Oil & Gas
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Looking ahead, the Marcellus formation will continue to be exploited more efficiently by companies that have learned from past drilling experiences. As in other formations, production will increase faster than infrastructure development and all players will look to reduce drilling costs. Producers believe one of the best areas to lower costs is by using water more efficiently. In the Marcellus, a typical hydraulic fracturing operation for a horizontal gas well in a tight shale formation requires between 3-5 million gallons of water, typically over a 2-5 day period. In 2012, Southwestern Energy CEO Steven Muller stated that water removal averaged about $1.5 million per well. Today, that cost has dropped to roughly $1 million per well.
If history is any indicator of the future, it is difficult to predict the scale or speed of Marcellus shale production. Domestic and even international natural gas demand will play a significant role. This demand will be fueled by the widespread fuel switch of power plants from coal to natural gas, the growth in the petrochemical and manufacturing industry, and even LNG exports down the road. If demand does keep natural gas prices between a sweet spot of $5-6, where producers have the incentive to produce and consumers aren’t discouraged, natural gas production could be prolific.
By. Chris Pedersen
That was then. Today, drilling is still important and it doesn't hurt that we can drill twice as fast. But are we using an old metric, "rig count," where the more important metric today is the number of well completion stages? The chart on "Stages" in the article shows that they are up by more than a factor of more than 3 since 2008.
If the number of stages per well is important, how does that relate to cost? It's not just drilling anymore, it's high-pressure pumping of large treated water volumes and disposal of those volumes, touched on in the article.
Investors are comforted by the thought that "volumes" are up relative to rig counts, but... industry finances are really the bouncing ball to watch.
I'm not sure if 78% of operating wells "are paid for already" is a good number. The production decline rate is high for these unconventional wells. Production declining by half after the first year means that these wells better be economic... or stop pumping!
So I ask, is industry giving investors that wrong bouncing balls to watch and use for evaluating the industry?
The "sweet spot" of $5-6 is more than just a "sweet spot." It's a necessity for the industry to continue. Unconventional petroleum is very capital intensive. And guess what? Much more capital is needed for piping, storage and LNG facilities.
Best of luck to us. I hope we are going down the right path. Let's hope the touted companies, like Cabot, are typical and not just poster companies.
Also, I think you'll find that the productive life expectancy is also changing. While there is a significant drop-off in production after the first few months, the fall off after that appears to be slower and longer than first thought... I think the latest estimate is 10 years, up from 7 years before.
And, looking at the chart in the article, the NECESSARY price range is above $3. So, I'd say that $5 and up is the 'sweet spot', not required.
Finally, I think the thing that I would monitor, as an investor, is the infrastructure build-out and the tax scenario. Right now, PA is starting to figure out different ways to get more tax money than a straightforward $50,000 per wellhead. And, pipelines are struggling to catch up to demand. Also, when Cove Point is completed, LNG export will open a whole new, higher priced market for natural gas.
One final thought... Recent exploitation of Utica shale and Upper Devonian Shale will also benefit these companies since the same mineral rights AND the same wells can be reused for those other shale layers since they all basically reside one on top of the other.