Henry Ford is famous for having once said, “History is more or less bunk.” He was, in fact, attacking tradition in an age of rapid technological and social change. Almost a century later we have a less ambitious observation which may not achieve the broad visceral appeal of Ford’s statement, but one which may turn out to have a good deal of importance, to wit: Oil and natural gas reserve numbers are more or less bunk.
Let me introduce you to B. J. Doyle, vice president of operations for a small Houston-based oil and natural gas exploration company. Doyle’s views on the oil and gas business have been on display for more than a year now at The Oil Drum, a site famous for its technical prowess and breadth of coverage when it comes to energy-related issues. On the site Doyle goes by the moniker Rockman, and through his frequent comments he has been trying to educate readers about the realities of the oil and gas business.
Now, he didn’t actually say that oil and natural gas reserve numbers are more or less bunk. Nevertheless, that is a fair summary of what he told me when I spoke with him recently. To understand why an insider would cast aspersions on this sacred metric of the oil and gas industry, you need to know two things. First, Doyle doesn’t have to please shareholders. The company he works for is privately held. Second, reserve numbers are meaningless unless they are indexed to a price.
Doyle began his explanation with a seemingly astounding statement: “One of the things we’re least interested in is the amount of oil and gas that we are going to produce.” How can this possibly be true? It turns out that the oil and gas industry uses a method common to nearly every modern business enterprise to evaluate its investments, namely, net present value analysis or NPV.
The concept is actually simple. If you have the choice of receiving $1,000 now or $1,000 three years from now, naturally you’d take the $1,000 today. That’s because of what is called the time value of money. If you can invest the $1,000 today, say, in a bank CD, you can at least earn some interest in the next three years. Also, if you were foolish enough to wait for your money, inflation might undermine the purchasing power of that $1,000. The inflation calculator at the U. S. Bureau of Labor Statistics shows that it would take $1,072 in 2009 to equal the purchasing power of $1,000 received in 2006.
Every business knows that there are several ways in which it can invest its capital. So, business owners take the amount of the initial investment in, say, a new factory or a new oil well, and subtract that amount from the present value of what they forecast will be the future cash flows from that investment. If the amount is positive, then the project will be profitable and should be considered. If the amount is negative, the project should be abandoned. Of course, there are many factors when considering an investment, but a project that appears to be unprofitable will certainly not be considered.
Net present value analysis, however, doesn’t describe the real world perfectly. This flows from the obvious truth that no one can actually know the future. One has to estimate the expected future cash flows. This is no easy feat when dealing with the uncertainties of yet-to-be drilled underground reservoirs, the challenges of operating producing wells, and the vagaries of the oil and natural gas markets. Then, one needs to apply a so-called discount rate. This process assumes that future cash flows received years down the road must be “discounted” to reflect the time value of money as described above. Doyle explains that discount rates applied in the oil and gas industry often range from 10 to 15 percent. He admits it’s an arbitrary number, but it’s arbitrary in every industry except perhaps as it reflects the presumed risks involved in the venture and the cost of capital (such as interest on loans).
When you work out what this implies for cash flow generated from a well several years after production begins, it becomes clear why the ultimate amount of oil and gas recovered from a well has little relevance to the decision to drill it. Let’s do an example to see why. If you invest $3 million to drill a well (not an unusual amount these days) and expect to get cash flow of $1 million per year from the well for 10 years, on the face of it that sounds as if you are reaping more than three times your investment. But when you discount the cash flows appropriately, for example at 12 percent, you get an NPV of $5,650,223. That’s $2,650,223 more than you are investing, so it’s still a positive number even after discounting. And, it’s 1.88 times the initial investment, a ratio that will become meaningful below. But the NPV of the $1,000,000 in yearly cash flow in years 8, 9, 10 are as follows: $359,634; $316,478; and $278,500. If the well keeps producing in year 20, the NPV of the cash flow in that year falls to just $77,562. If it is a very long-lived well, the NPV of the cash flow from year 40 is negligible, $6,015.
As it turns out, few companies would even bother drilling such a prospect. Doyle says that right now his company won’t even look at a prospect unless, based on seismic data and other information, it reasonably expects that the completed well will produce an NPV six or more times that of the initial investment. When there is keen competition for prospects, companies will drop their expectations down to three to four times the NPV.
This is where things get interesting. Doyle has seen some public companies drop their goal down to one. That’s right. They will drill prospects that they believe have no reasonable chance of doing anything other than breaking even. Why will they do this? To boost stated reserves, a number by which Wall Street judges the value of oil and gas companies. They won’t, however, make any true profit on these wells. But they will become what Wall Street calls an “asset play.” They will be valued on their assets, in this case stated reserves, rather than on their profitability. This strategy has proven especially tempting to those engaged in the hunt for shale gas since drilling success rates are very high. This is a risky strategy, however, that leaves little margin for error. Prices lower than those forecast by such an analysis could quickly bankrupt a company that drills too many wells based on an assumed one-to-one ratio of investment to net present value.
The claims that the United States has 100 years of recoverable natural gas as a result of the newly accessible shale basins has no meaning without attaching a price to it, Doyle contends. The fact that major shale gas producers have trimmed their active drilling fleets to a fraction of what they were during the 2008 boom in natural gas prices proves that price is a critical factor in determining whether to drill. And, where there is no drilling, there are no additions to reserves. The natural gas market has shown itself to be highly volatile which has not surprisingly led to wide swings in natural gas drilling. The notion that somehow there will be a consistent accretion of natural gas reserves from year to year or that all discoveries from previous years will still be considered reserves in a low-price environment is pure bunkum.
The same logic applies to oil discoveries. But these days no one is claiming the United States has enough oil left to supply the entire country for 100 years. And, so hype about oil reserves is less of an issue.
The upshot is that expected cash flow determines what areas will be drilled, not the size of potential reserves. Most companies won’t drill a prospect unless they believe they can get their money back within two to three years, Doyle says. If it takes four or five years, the prospect is not very attractive. Cash flow is king.
It turns out that the NPV of the first three years of cash flow from my hypothetical well mentioned above is $1,556,112, only about half of the initial investment. Most companies would or should pass on such a prospect, and it would therefore never become part of anyone’s reserves, he explains. Part of the hype over shale gas has to do with the claim that the wells may be very long-lived, he adds. Even if that turns out to be true–not a certainty as of now–the low flow rates expected after the initial burst of production and the distant payoffs would actually work against any decision to drill such wells. No wells, no reserves.
Doyle says that given modern technology, oil and natural gas are easier to find than ever before. But he doesn’t believe that in North America at least, there is that much more to find. He thinks that shale gas in North America my indeed prove to be plentiful. But it will not be both plentiful and cheap.
And, of course, if we succeed at expanding natural gas production to meet the needs of a new natural gas-powered vehicle fleet–an idea advocated by one of the leading producers of shale gas–and expand other current uses such as the generation of electricity, we can expect that natural gas prices will soar. That may provide the necessary incentive (i.e. cash flow) to extract the shale gas that lies below the American landscape. But it will also certainly mean that the 100 years of supply that has been so frequently touted in the media will rapidly shrink to perhaps 30 or 40, and that the peak in production will come much sooner.
A peak in natural gas production in, say, 20 years would not exactly be a useful talking point for those advocating the wholesale conversion of key parts of the U. S. economy to run on natural gas. Just as we would be finishing such a conversion, we could find ourselves on the downslope of the natural gas production curve and faced with the urgent need to adapt our costly and newly completed natural gas infrastructure to run on some other energy source.