Listening to company presentations at an Energy conference last month, I was struck by one remarkable operating statistic. Southwestern Energy's (NYSE:SWN) CEO Steve Mueller, speaking of his company's drilling plans in the Marcellus Shale, indicated that by 2017 SWN anticipates to be producing almost 800 MMcf/d, on a gross operated basis, from its leaseholds in Susquehanna, Bradford and Lycoming Counties of Pennsylvania. About a year and a half ago, Southwestern had zero production coming out of the Marcellus. At the end of last quarter, SWN had 166 MMcf/d of gross operated production from the area, which the company expects to increase to over 300 MMcf/d already by the end of this year and to over 500 MMcf/d by the end of 2013. How many drilling rigs will it take to achieve this amazingly rapid production ramp up? It turns out, just four.
A question immediately springs to mind, how many rigs would it take to maintain the entire U.S. natural gas production at its current level assuming all gas-directed rigs had the same productivity as those working in the Marcellus Shale? I took this calculation a few steps further to include other empirical proxies to derive answers to the same question. The results are quite astounding: current gas-directed rig count is close to sufficient for the U.S. natural gas production to remain flat. This goes contrary to the common perception regarding the "normal" natural gas rig count range.
Southwestern Energy Marcellus Shale Case Study
Looking more closely at Southwestern's Marcellus rig count, the company started out 2011 with just one operated rig, ended the year with two rigs, added the third rig in the beginning of 2012 and the fourth rig during the second quarter. Southwestern plans to continue with its four-rig program for several years and reach a production plateau approximately in 2017.
Due to the infrastructure lag, Southwestern has been drilling ahead of its ability to put the drilled wells on production. At the end of 2011, the company had 22 operated wells online and approximately 44 operated wells waiting on completion of pipeline connection. The well backlog has continued to build up during the year, reaching, in my estimate, over 55 wells by the end of Q2. As the Bluestone pipeline in Susquehanna County comes in operation in October and November of this year, Southwestern anticipates that a large part of its backlog will be brought to sales at around year end 2012 or shortly after.
Using the 200 MMcf/d production growth guidance for the period from year end 2012 to year end 2013, I arrive at an estimate that a land rig drilling in highly productive dry gas areas of Northeast Pennsylvania has the capability to offset natural declines on 60 MMcf/d of base production (comprised of recent, fast-declining vintages) while adding as much as 40 MMcf/d of new production. In my calculation, I assume that at the end of 2012 Southwestern will have approximately 100-105 wells online and 45 backlog wells still outstanding, with the well inventory declining to a more "normal" 20-well level by the end of 2013. The inventory wells effectively add a "fifth rig" in 2013. As the production base builds up, a greater amount of rig time is spent on offsetting the declines from the growing population of producing wells. By 2017, each Southwestern rig will be offsetting the declines from approximately 200 MMcf/d of base production (which will include a range of vintages with a lower average decline) and still be adding some "growth" production.
These empirical metrics imply that approximately 250 drilling rigs with dry gas productivity similar to the four rigs SWN is operating in the Marcellus would be able to offset natural declines on over 50 Bcf/d "Marcellus-like" base production. As discussed in Part II, such rig count would be sufficient to more than offset natural decline of the entire U.S. natural gas production.
Clearly, it would be incorrect to extrapolate the Southwestern illustration on U.S. production as a whole. The Marcellus shale in Susquehanna, Bradford and Lycoming Counties is, arguably, the most productive dry gas acreage among the U.S. resources plays. According to Baker Hughes, there are only 29 rigs currently operating in these three counties (the sum of high watermarks is 66 rigs), as the infrastructure is struggling to keep pace with the rampant production. 250 rigs cannot be accommodated within this relatively small area (let alone this would imply a 30+ Bcf/d of production coming from Northeast Pennsylvania, in three to four years, which is of course not feasible). Nonetheless, this data point remains very valid in illustrating the extraordinary productivity of dry gas "sweet spots" and, as a result, a substantially reduced call on gas-directed rigs.
The very high EURs in the Northeast Pennsylvania Marcellus explain the exceptional rig productivity. Southwestern has assigned an average 7.5 Bcf EUR to its wells, which is substantially below the 11 Bcf EUR that Cabot Oil & Gas estimates, likely conservatively, for its Susquehanna County wells, but still quite extraordinary. In comparison, the significantly more expensive to drill wells in the sweet spots of the Haynesville Shale can have EURs as high as 8-10 Bcf. From a productivity perspective though, a rig in the Marcellus can drill two wells per month versus one well in the Haynesville, developing over 50% more reserves during the same period of time.
While Northeast Pennsylvania remains unmatched in terms of dry gas productivity, sweet spots in other gas shales yield still very impressive results. I estimate that at least 130 rigs, or about 30% of the current total gas-directed rigs, are currently drilling in the high-productivity dry gas sweet spots across various U.S. resource plays. These include approximately 25-30 rigs in the Haynesville shale, 14 rigs in the Fayetteville shale, at least 40 rigs in the dry gas window of the Marcellus, and at least 50 additional rigs in Wyoming (Pinedale, Jonah), the dry gas window of the Eagle Ford, and in other dry gas producing areas.
In Part II and Part III, I analyze empirical production data and its correlation with the rig count in another shale play, and draw quantitative conclusions regarding the gas-directed rig count required to offset natural declines in the U.S. gas production.
This discussion of natural gas fundamentals bears relevance to natural gas producer and land drilling stocks.
My natural gas producer index includes:
- Chesapeake Energy (NYSE:CHK)
- EnCana Corporation (NYSE:ECA)
- Devon Energy (NYSE:DVN)
- Southwestern Energy
- Ultra Petroleum (UPL)
- EXCO Resources (NYSE:XCO)
- WPX Energy (NYSE:WPX)
- Cabot Oil & Gas (NYSE:COG)
- Range Resources (NYSE:RRC)
- QEP Resources (NYSE:QEP)
- Quicksilver Resources (NYSE:KWK)
- Forest Oil (NYSE:FST)
- Bill Barrett (NYSE:BBG)
My land drilling index includes:
- Helmerich & Payne (NYSE:HP)
- Nabors Industries (NYSE:NBR)
- Patterson-UTI Energy (NASDAQ:PTEN)
- Precision Drilling (NYSE:PDS)
- Unit Corporation (NYSE:UNT)
- Union Drilling (NASDAQ:UDRL)
Disclosure: I have no positions in any stocks mentioned, and no plans to initiate any positions within the next 72 hours. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.