Waiting for production declines in the natural gas market is getting to be like Waiting for Godot (or Guffman, if you prefer). Last week just brought more of the same.
At the end of each month, the U.S. Energy Information Administration [EIA] reports monthly natural gas production figures. This so-called 914 data, referring to the form that operators like Anadarko Petroleum (NYSE: APC) and Ultra Petroleum (NYSE: UPL) file with the government, is prone to revision, and is released on a two-month lag. That said, it's still one of the best tools for investors trying to keep tabs on the gas market.
According to the November data, lower 48 gross production came in at an estimated 63.13 billion cubic feet [Bcf] per day. That's roughly flat from the prior month, and more than 1% higher than the prior-year figure. As we've discussed before, production peaked in February 2009. The November average represents a decline of only around half a Bcf per day (or less than 1%) compared to that peak rate.
These results totally defy prior expectations.
Supply models could use some tinkering
On its August 2009 conference call, Chesapeake Energy (NYSE: CHK) was talking about a 2.5 to 3 Bcf / day year-on-year decline by the end of the year. EOG Resources (NYSE: EOG) called for an even steeper decline in 2009, initially calling for a 4.8 Bcf / day decline, and then dialing that down to 3.2 Bcf / day on its November call.
While these companies sometimes rag on the 914 data, and like to talk about how awesome their in-house production models are, the plain fact is that they totally whiffed on 2009 decline rates.
The broad themes of why production has held up in the face of a collapsed rig count are well recognized: horizontal drilling by shale players like Petrohawk Energy (NYSE:HK) and Southwestern Energy (NYSE: SWN) has made up for heavy declines on the conventional side, and operators have also gotten a lot more efficient. We discussed these themes when I said to forget the rig count back in November. Another consideration is the industry backlog of drilled but uncompleted wells, and on this point, I think there is much less clarity.
You often hear E&P companies talk about "drill and complete" costs. Completion involves everything from setting production casing to fracturing the formation to hooking the well up to a sales line. This represents a significant portion of the total cost to drill and complete a well.
Lots of companies had to drill furiously in 2009 to meet various obligations, but given their stretched balance sheets and low gas prices, they had a big incentive to defer completions. This factor, plus pipeline constraints, has spread very large production increases in new shale plays like the Haynesville and the Marcellus over a longer period of time.
So are the declines ever coming?
On its third-quarter call, Chesapeake said that its completion backlog was cleared out, and it suspected as much for the industry at large. XTO Energy (NYSE: XTO), soon to become part of the ExxonMobil (NYSE: XOM) empire, echoed these sentiments on its own results call. Meanwhile, the folks at Casey Research estimate that there are thousands more uncompleted wells out there, representing several Bcf per day of production.
I would normally give the big independents the benefit of the doubt, given their unparalleled view into the market, but we've seen what good that vantage point did them in predicting declines in 2009. If XTO is right, we will see production finally drop around the end of the first quarter. Rather than hold my breath, I'm going to stay focused on E&Ps that can thrive in a $4 to $6 per million BTU gas environment.
Disclosure: Author doesn't have a position in any company mentioned.