In 1956, M. King Hubbert predicted that crude oil production in the U.S. (ex-Alaska) would peak in rate around 1970, to be followed by a long, irreversible decline. Hubbert nailed the timing of the peak, and in doing so, cemented his status as a technological visionary among neo-Malthusians and opponents of fossil fuels.
The method Hubbert employed to make his prediction is simple and elegant, almost trivial in its application. But is it valid? Should we base policy decisions on its conclusions?
Before answering that question, consider that Hubbert’s 1956 paper contained a similar prediction: that Lower 48 natural gas production would peak in the early 1970s. In a classic case of confirmation bias, Hubbert’s 1978 update declared his gas prediction correct (as with oil, he had missed the rate prediction on the low side). For Hubbert, gas had begun its “inexorable decline” right on schedule.
In 1956, Hubbert’s estimate of the amount of natural gas that would ultimately be consumed in the U.S. was 850 trillion cubic feet (TCF).
In the 1978 update, Hubbert increased his estimate to 1,103 TCF, but considered that value to be on the high side.
By the end of 2010, we had produced and marketed 1,131 TCF from the Lower 48, more gas than Hubbert thought would ever be possible (Figure 1). We are in the midst of a natural gas boom, with gas production now exceeding the peaks of 1973: rates are over three times higher than the 7 TCF per year Hubbert foresaw for 2010 (Figure 2). The Lower 48 resource base is some 3,100 TCF, three to four times Hubbert’s earlier estimates.
Peak Oilers rarely mention Peak Gas. Hubbert expected his method to work for all resources; why did it fail with respect to gas? The answers to that question shed light on the shortcomings of Peak Oil Theory, and reveal the reasons why it should not be used as a policy-making tool.
Shortcoming #1: Hubbert’s technique depends entirely upon the estimate of the ultimate resource base. Any extrapolation of historical trends contains only the information embedded in the history. There is no way to anticipate “game-changing” developments outside the confines of the history upon which it is based. A forecast of a limited future thus becomes a self-fulfilling prophecy if it is used to set policy.
Shortcoming #2: “Hubbert’s Peak” is the ultimate ceteris paribus analysis. Problem is, all other things are never equal, particularly in the realm of economics. Hubbert’s equations worked well in his experience, so well that he accepted them as immutable laws. Hubbert showed little concern for how changing policies or economics might affect his resource estimates (see Shortcoming #1).
Shortcoming #3: We are all limited by our imaginations. Hubbert could not imagine economic production of hydrocarbons from water depths over 600 feet; we now have production in nearly 10,000 feet of water. Shale rocks were never considered to have economic potential. Moore’s Law has enabled accomplishments in drilling and exploration beyond Hubbert’s wildest dreams.
Hubbert’s Estimate of Ultimate Resources – 1956
At the time of his 1956 paper, Hubbert was a geologic advisor to Shell Development Company in Houston. His estimate of ultimate natural gas for the Lower 48 was derived from his crude oil estimate; at the time gas was regarded a by-product of oil, a nuisance as much as a resource.
Because crude oil and natural gas are genetically related, probably the most reliable procedure for estimating the ultimate reserves of natural gas is from the ratio of gas to crude oil in current production and in the proved reserves. … [Adding the figures so derived to] the cumulative production of 130 trillion cubic feet then gives as the ultimate potential gas reserve of the United States a low figure of 540 or a high of 860 trillion cubic feet. Of these figures the latter seems more reliable …
The latter figure was also in rough agreement with the estimate derived independently by the legendary Wallace E. Pratt, chief geologist for Humble Oil and Refining (a predecessor of ExxonMobil): 850 TCF. Hubbert credited Pratt in Figure 22 of his paper (reproduced as Figure 3 herein), which forecast a peak rate of 14 TCF per year in the early 1970s.
Hubbert’s Estimate of Ultimate Resources – 1978
In 1978, Hubbert was recently retired as a research geophysicist for the U.S. Geological Survey. Upon looking back at his original work, he concluded:
From these data, it now appears, as of 1978, that the production rates of oil and natural gas in the lower 48 states reached their culminations in the years 1970 and 1973, respectively, and are now in their inexorable decline.  [Emphasis added.]
In the 1978 paper, Hubbert introduced new graphical techniques, basing his 1,103 TCF resource estimate on a declining trend of new reserves per foot drilled. He also went to considerable lengths to discredit more optimistic resource estimates from the U.S. Geologic Survey, the Potential Gas Committee and others. Those estimates took a more statistical approach than Hubbert by attempting to quantify the remaining gas in all of the unexplored and undrilled basins. In retrospect, those estimates are more in line with today’s resource estimates.
At the time, Hubbert was not alone in his pessimism for future gas supplies. The nation experienced gas shortages during two extremely cold winters when demand exceeded gas deliverability. Proved reserves were at historic lows. An alarmed Congress passed the Industrial Fuel Use Act (1978), which outlawed new gas-fired electrical generating plants, just one example of a bad policy that was based on a pessimistic resource outlook.
Problems with Estimating EUR
The press and policy makers often portray resource estimation in a deterministic light, as in “We know that umpteen TCF of gas reserves lie off the east coast of the United States.” We know nothing of the sort. It would be more accurate to say “Our mean estimate of the gas resource which may lie off the east coast is umpteen TCF,” but the nuance is lost on folks who struggle with elementary math.
There are two ways to make an estimate of ultimate recovery on a global or national scale. One is to extrapolate historical performance trends using the performance of existing production and discovery trends. This was Hubbert’s technique. The problem with such an approach is that it cannot anticipate a “game-changing” innovation or fundamental shift in economics. The forecast implicitly extends the rules that shaped history, even when those rules no longer apply.
The other approach is a “volumetric” exercise, one in which there is a broad range of uncertainty. The resource estimates of the Potential Gas Committee are an example. The PGC attempts to catalog the “undiscovered, technically recoverable resource” by considering the volume of the known sedimentary basins, the volume of potential reservoir rock, and their likelihood of containing hydrocarbons. Even under this approach the resource estimate has grown over time, as wells are drilled and the production curve, technology and information frontiers advance (Figure 4).
Hubbert’s curve was inherently backward-looking. He had no way to look in a crystal ball and divine the “correct” value of the resource estimate; instead he simply presumed that the future must reflect the past:
“… for a large area, such as the United States or Texas, [a production plot] most likely will be a single-cycle curve with only one principal maximum.” 
The natural gas case history proves that to be a false presumption. The number of methane molecules that exist in the earth’s crust may be a “fixed, finite” number, but the proportion of those that will ultimately be discovered, produced and marketed as natural gas depends on the interplay of external factors which Hubbert simply ignored: product price, public policy, and technology.
Until the mid-1970s, natural gas was dirt cheap, so cheap that drillers rarely targeted it intentionally. Most of the gas that was found and produced was incidental to oil operations, which explains why Hubbert deemed the gas resource to be a ratio of his crude oil estimate.
Figure 5 shows the history of natural gas prices (which was historically priced per mcf, or 1,000 standard cubic feet). The average wellhead price (i.e., the price received by the producer in the field) from 1925 until 1970 was less than 10¢ per mcf (about 66¢ in 2005 dollars). The energy content of one barrel of oil is roughly the same as 6 mcf of gas, so that the cost of buying one barrel’s worth of energy in natural gas form was only 60¢ (or less than $4.00 in 2005 dollars).
Since 1938, the Natural Gas Act had enforced low gas prices and near monopoly status for the big interstate gas pipelines. It was not unusual for a producer to be locked into a long term gas sales contract at 3¢ per mcf, with no recourse and no alternatives. Intrastate gas (gas that was consumed in the state where it was produced), being free from Federal controls, provided better markets to the producer, and better availability of gas to producing-state consumers.
In an effort to build domestic gas supplies, President Carter signed the Natural Gas Policy Act (NGPA) in 1978. It maintained existing price controls while granting preference to newly-found supplies. Its recognition of a dozen or more “vintages” of gas led to a price structure that became increasingly byzantine over time.
President Reagan began phasing out price controls on oil and gas in 1983. Tax reform ended limited partnerships’ tax shelters for drilling dry holes. The industry floundered as prices tanked and investors vanished. From 1981 until 1985, the count of active drilling rigs declined from 4,500 to 700. Under severe economic pressure, the energy industry consolidated and contracted, then set about figuring out how to regain profitability.
The interstate pipelines were also decontrolled in the mid 1980s. They lost their monopoly status, becoming common carriers more like the railroads. Producers were free for the first time to seek out the most profitable marketing alternatives. Commodities trading began on the NYMEX, with a common exchange point being established at Louisiana’s Henry Hub, a key pipeline interconnect.
Coincidentally, by about 1985, the impact of cheaper, distributed computing began to be felt in the industry. Directly or indirectly, the PC era would contribute to a number of important technical advances in exploration and well operations, including 3-D seismic, horizontal drilling and logging-while-drilling. Using these and other new technologies, operators began finding ways to produce natural gas from rocks that had been never before been considered to be commercial sources of hydrocarbons. Explorers drilled fewer dry holes, and more efficiently developed smaller accumulations than in earlier days.
It is important to note that the connection between price spikes and technical innovation is often indirect. Many of the important innovations happened during periods of low prices as producers looked for a way to survive hard times by working with the resources at their disposal. And technological advancement tends to be a one-way street: good ideas are not forgotten, and any successful technology spawns copycats and imitators.
Looking Outside the Box
It was always known that some shale rock formations contain gas; the problem was getting the gas out in commercial quantities. Industry pioneer George Mitchell’s Mitchell Energy tried for years to find the key in a shale zone called the Barnett near Fort Worth, TX. Eventually they found that the combination of horizontal wells (wells drilled vertically from the surface, then turned horizontal in the target formation) combined with hydraulic fracturing (“fracking”), produced economic results. In time, Mitchell’s Newark East Barnett Shale field became the nation’s #1 producing gas field. 
Strong natural gas prices starting in 2004 drove the search for other productive shales. When the technology was applied to other shale trends (notably the Haynesville of northwest Louisiana and the Marcellus of Pennsylvania, both of which typically produce at higher rates than the Barnett), shale gas development became today’s full-fledged boom. Shale plays tend to cover broad areas compared to conventional sandstone and carbonate gas reservoirs, so the impact on the estimate of the resource base is enormous.
The success of the deepwater Gulf of Mexico is another example of the confluence of price, policy and technology in expanding the resource base. In the 1990s, a time of low product prices, favorable government policy in the form of royalty relief encouraged the search into deepwater. 3-D seismic and cheaper computer processing enabled geoscientists to see reservoirs lying beneath a thick layer of salt. Marine engineering and subsea innovations make it possible to drill and produce in water up to 10,000 feet deep. The result is a major source of hydrocarbons that was unimaginable in Hubbert’s day.
Hubbert’s estimate did cover the offshore, but only the “shelf”, out to a water depth of 600 feet. As it turns out, the deepwater Gulf of Mexico is a major new producing province. Obviously, Hubbert, Pratt and their contemporaries would never have assigned a reserve value to shales or coals, the unconventional sources that today comprise 40% or more of our gas market.
“Hubbert was imaginative and innovative… [but he had] no concept of technological change, economics or how new resource plays evolve. It was a very static view of the world.”– Peter Rose, King Hubbert’s boss at the U.S. Geological Survey. 
Hubbert knew a world of low gas prices. Active Federal intervention kept prices low, so low that there was little incentive for innovation or aggressive exploration.
Natural gas dutifully followed Hubbert’s Curve up and over the peak, but about 1985 it veered sharply off the trend, never to look back. That’s about the same time that price decontrol became permanent and producers gained access to commodity markets. We should not be surprised to find the roots of the change in free market economics. Gas is subject to the Law of Supply and Demand just like any other commodity. In addition, the concepts by which we gauge remaining supply (“Resources” and “Reserves”) contain economic considerations in their very definitions.
Hubbert may have been correct about the ultimate volume of gas that would have been produced under pre-1970 prices and marketing structures. That price was unrealistically low compared to the energy content of gas. Today’s gas prices are about six times the pre-1970 average (2005 dollars), but gas is still a relative bargain. (Six thousand cubic feet of gas costs about $24, but can do as much work as one $100 barrel of oil – see Figure 5.)
So, if all this is true, why does Hubbert’s curve seem to work so well for crude oil?
One key fact distinguishes natural gas and oil. Oil can be readily imported from anywhere in the world. Gas is primarily a North American commodity. Imports (other than Canadian pipeline imports) can impact the market only when domestic prices are high – and even then we have to compete with Japan and other regular customer on the world market. At the current low price of gas (relative to oil), the United States may become a gas exporter.
The transportability of oil caused the oil-oriented major integrated companies to focus their exploration efforts overseas when drilling and production costs rose in the U.S. Finding large deposits of oil overseas was easier, cheaper and more efficient than it was in the States. The U.S. natural gas market became the domain of domestic independents.
Policy decisions have taken much of the domestic oil resource base off the table, namely in the Alaskan North Slope, much of the Mountain West and the 85% of the Outer Continental Shelf which is closed to exploration. We cannot know how big this potential resource base is until we drill it. Many would prefer not to know, whether for political or environmental reasons, so we can expect the fight to continue.
“Gold is where you find it, according to an old adage, but judging from the record of our experience, oil must be sought first of all in our minds.” – Wallace E. Pratt, Chief Geologist at Humble Oil and Refining.
Notes on terminology
Cumulative Production is the amount of a resource that has been produced to date.
Remaining Resource is the currently accepted term for the amount of that resource that will be produced in the future.
Ultimate Resource = Cumulative Production plus Remaining Resource. In this paper I have used “Estimated Ultimate Recovery” (EUR) or “resource base” interchangeably with Ultimate Resource.
Remaining Reserves, Proved Reserves and SEC Reserves are used interchangeably to mean the quantity of future production that is expected to be recovered with relative certainty, and under existing technology and economic conditions, from existing wells plus nearby offset locations. Reserves are subsets of the Remaining Resource.
The other component of the Remaining Resource is the Undiscovered Resource, that quantity that will be discovered and produced from new sources and new basins. It is subject to much less certainty than “reserves”. The Potential Gas Committee (PGC) quantifies the “Undiscovered Technically Recoverable Resource”, which tallies the resource thought to be recoverable with known methods, regardless of economics.
To add more confusion, this nomenclature was not yet standardized in Hubbert’s day, so he sometimes used the term “reserves” when he meant “resources”.
 M. King Hubbert, “Nuclear Energy and the Fossil Fuels”, presented to the Southern Division of the American Petroleum Institute, San Antonio, March 1956. http://www.hubbertpeak.com/hubbert/1956/1956.pdf
 M. King Hubbert, “U.S. Petroleum Estimates 1956-1978”, presented at the annual meeting of the American Petroleum Institute Production Department, Denver, April 1978.
 Report of the Potential Gas Committee (December 31, 2010): Potential Supply of Natural Gas in the United States. http://www.narucmeetings.org/Presentations/PGC%20NARUC%20Committee%20on%20Gas%20July%2018,%202011.pdf
 C. Paul Hilliard, personal interview.
 As quoted by Daniel Yergin in The Wall Street Journal Online Saturday Essay: “There Will Be Oil” (September 17, 2011). http://online.wsj.com/article/SB10001424053111904060604576572552998674340.html
Natural gas data from the Energy Information Administration (http://eia.doe.gov). Gas production figures are “U.S. Natural Gas Marketed Production” (Sourcekey N9050US2) less Alaska volumes (N9050AK2). Average U.S. wellhead price (N9190US3)