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.

Natural gas prices: Why $7 is the new $3

Natural gas prices have been volatile, and there are no end to the different opinions you can get as to the future of gas prices. I get asked about gas prices quite a bit and over the last couple of years I have often stated that I believe $7 per mcf is the price at which we can see meaningful exploration and development of gas - enough to at least offset the significant decline rate of the average natural gas well in the U.S. This $7 view isn't anything earth-shattering, and is a view shared by many in the industry, but that isn't why we believe it to be true. It is based simply on the economics of drilling for natural gas in the somewhat mature basins of North America.

Let me start with the simple example I've shared over the years, an example from the "old days" of oil and gas (pre-2000). I'm simplifying here, but back then, if you were a producer that could find an MCF for $1, produce it for $1 and sell it for $3, you'd be pretty happy. This mathematical model allowed for growth in reserves and production and a positive return on capital. First you should recall that an oil and gas company needs to at least replace each unit of gas it produces with a like unit, otherwise it is just depleting away it's existing asset base. Therefore, the sale of each unit must generate enough excess cash flow to go replace that unit at a cost equal or below that excess cash flow. In the "old days" example this works out like this:

1) Drilling and completion cost of your latest well: $1,000,000
2) Size of new reserve from this well: 1,000,000 MCF (a.k.a. 1 billion cubic feet)
3) Fiding cost per MCF: $1,000,000 / 1,000,000 = $1.00 per MCF
4) Producing life (reserve life) of well: 10 years (note that production is not linear, that it comes on at the highest rate it will acheive and will decline over time due to reservoir and pressure depletion)
5) Lease Operating Cost per unit (to flow it from well, maintain well ops, etc): $1.00 per MCF
6) Sale price per MCF: $3.00

Therefore, each unit produced will generate cash flow of $3.00 minus $1.00 in lease operating costs, or $2.00 per unit. But now you have depleted your asset base by 1 unit, so what do you do? You take your $2.00 in cash flow and go invest it into a new drilling program. Since your finding costs are $1.00 per MCF for a 1 BCF well, you have the ability to replace your one unit produced with two more. This is essentially how you grow the company. In this case, your company would have the ability to replace reserves on a 2-to-1 basis. But note that producing one actual MCF unit doesn't actually get you two because you don't drill wells that are just two MCF in size. In the absence of borrowing money to drill, you actually need to produce enough of your existing reserve to get the money to drill the next well. In this case, you'd have to produce 500,000 mcf before you had enough money to drill your next $1MM well...this would take a few years.

So let's assume you have 10 BCF of total reserves at the begining of the example. You spent $10MM to develop those reserves and have total finding costs of $1.00 per MCF. Your average reserve life is about 10 years, so you are producing 1 BCf each year. You are therefore generating $2 in cash flow per MCF times 1 BCF for $2,000,000 per year. You can use that to drill 2 new wells at $1MM each and come up with another 2 BCF of new reserves. This would be considered a 200% reserve replacement ratio (2BCF new / 1 BCF produced). But although you replaced 200% of what you produced, your underlying reserve base grew by just 10%:

10 BCF - 1 BCF produced + 2 BCF found = 11 BCF.

In this case, you can grow your company's reserve base by 10% annually if you can acheive a 200% replacement ratio on production. Of course, if you have a bad year and you spend $2MM in drilling costs and only find 1 BCF of gas, you find that your reserves did not grow at all. This is essentially the position many of the larger integrated companies find themselves in: it is very hard to grow reserves once you get to a certain size.

So, how does all this relate to $7.00 gas? The fact is that finding costs on average have been climbing precipitously the last few years. We analyze operating data on over 75 publicly-traded exploration and production companies (micro-to-large cap, exlcuding the majors) and note that the average for 2005 was $2.77 per MCFe (the "e" stands for equivalent, meaning that oil volumes are included and converted to gas on a 6-to-1 basis). One year isn't all that meaningful, but we also look over 3 and 5 year drilling cycles to see how costs fare. We find that the 3-year average for our group is $2.50 per MCFe. We also note that the average per MCF operating costs are $1.60 for the group in 2005.

Therefore, in order to replicate the same economics as the "old days" example ($1-$1-$3), we need to generate a cash flow per MCF of double our finding costs, or $2.75 X 2 = $5.50. Given the $1.60 operating costs, that means that gas needs to sell for $7.10. So that is the short answer as to why I believe in $7.00 gas prices. While it is true that companies can replace reserves over 100% at levels below that, it is also true that they would not be able to generate any meaningful growth in reserves. Standing still at the same reserve level and merely replacing each unit you produce is not a way to create value.

All that said, there will be seasonal swings in prices. We will see prices well above $7 and well below $7. But the long-term average has to be $7 or so or "average" companies simply won't drill (that said, there are vast differences amongst companies' finding costs and operating costs - some will grow reserves at $4 gas and some can't do it even at $8 gas).

Also, I do not see any chance for average finding costs to come down significantly , but that is a topic for another day, when we can discuss why rig costs are not as important to overall finding costs as they once were (hint, it has to do with the type of reservoirs we are targeting and the nature of completions costs). And another day, we'll talk about why natural gas has become a more weather dependent commodity as prices have risen. Stay tuned...