Natural Gas and Oilfield Service Intensity

Back in November, when natural gas prices had fallen hard and many were wondering where the floor price was, I published an entry here called "Natural gas prices: Why $7 is the new $3". I mentioned that drilling rig costs are not as important to overall finding costs as they once were, due to the nature of the unconventional gas reservoirs we now target and the cost of well completions relative to drilling costs. It is a good time to discuss that statement, since I believe the average citizen does not recognize the incredible increase in asset utilization and the technological improvements that have been required just to keep our U.S. natural gas production flat over the last few years. But first, a quick reminder of natural gas supply fundamentals, for those who don't worry about this stuff every day.

The U.S. is the second largest producer of natural gas in the world, just behind Russia. We produce about 50 billion cubic feet (bcf) per day.We also import another 10-12 bcf per day, primarily via pipeline from Canada, but also a small amount in the form of liquefied natural gas (LNG), with our largest LNG provider being Trinidad.

As for our sources of natural gas, that profile has been changing over the years.
Production from the Gulf of Mexico, where large, high-rate wells were the norm 20 years ago, is giving way to more onshore production , specifically from tighter sands, coalbed methane, deep gas, and gas shales, collectively known as "unconventional" gas reservoirs (labeled so because gas from these formations were difficult to produce with available technology just a few years ago). The Energy Information Administration shows this trend in historical data and in their projections through 2030, shown here.

We will discuss demand increases in another post, and more importantly, the components of demand that have dramatically changed to make prices demand less price-sensitive than in the past. For now, let's focus on how much we have to drill in order to keep production at least stable. The chart below shows, for each month over the last 10 years, the average daily production of natural gas in the U.S.:
Note that production peaked in 2001. This is in spite of the fact that prices have risen from around $2.00 per MCF to around $8 per MCF today. Natural gas producers have every financial incentive to bring more supply to market. However, there are a number of factors that make this difficult, some of which I discussed back in November in "$7 is the New $3":
1) targets are smaller than ever before
2) costs are increasing as demand for services is high and service providers are stretched to their limits
3) production decline rates on new wells are steeper than previously, partly due to the application of new methodologies such as directional and horizontal drilling, fractionation, chemical stimulation, and other well completion technologies.

So here is the key chart to see here...
it compares the declining gas production number to the number of wells we are drilling. Note that in 2006 we drilled a record number of gas wells, almost 30,000 of them, almost triple what we drilled just in 1999, and yet we got no appreciable production increase. That said, we are beginning to see an increase in production in 2007 that may be a delayed response to the last 12 months torrid drilling pace. The delay may be partly due to the fact that many wells get drilled but have to wait for a completion crew or for pipeline connections.

So, of course, with more wells to drill, more rigs are being put to work, to the point where we are building new rigs in the U.S. after many years of having been over-supplied.

Virtually every available rig is now working, but many people believe the new-builds coming into the market will hurt the drillers. My contention, and a view held by many rig operators, is that the new ones will merely replace the older rigs that are not fit for today's intense drilling requirements.

Wells are being drilled deeper than before, through more complex geology, and with longer horizontal laterals. This requires higher-spec drilling rigs, more complex tools, more pipe, and more experienced personnel. All these things are harder to get in this very robust drilling environment. Note that while the number of gas rigs employed has risen dramatically, horizontal and directional rigs have been the fastest growth area.

Uncoventional gas, by definition, is costlier to produce and requires a greater amount of applied technology. 20 years ago, the primary equipment required to drill a vertical well into conventional gas was the drilling rig. The cost of that rig on a "day rate" basis was the most important factor in the cost of a well.However, today's unconventional gas wells have cost structures with more non-rig costs and completion costs. That is, the rig may be less important than the downhole tools like Measurement-While-Drilling ("MWD"), Logging-While-Drilling ("LWD") , and 3-D Rotary Steerable tools. Once you have drilled the hole, you may need pressure pumping equipment to fractionate the well, chemicals to pump into the formation for optimal well performance, and other specialized well completion services. The total cost of many of today's gas wells may be half completion costs, which have nothing to do with rig costs. This is why I have said that rig rates themselves may not be the same leading indicator they once were. Rising rig costs may no longer be the ultimate determining factor of whether or not a well is economic. Oil and gas production companies may be somewhat less price sensitive when it comes to rig costs, per se. They will care much more about rig efficiency and rig capability.

The bottom line is that increasing rig rates do not spell disaster for the market, nor is the arrival of new-build rigs with higher capabilities. With the rise of horizontal and directional drilling, declining production from mature basins like the Gulf of Mexico, and the increase in well complexity, natural gas looks to keep the U.S. oilfield service market very busy for some time to come.