In mid-July 2008, the United States somewhat unexpectedly discovered that it had an oversupply of natural gas, and prices fell sharply. Jen Snyder, head of Wood Mackenzie Ltd’s North American Gas Research Group, recently said that the development of shale gas plays has caused "a significant potential over-supply" (Oil and Gas Journal, December 1, 2008). Shale plays had become increasingly irresistable to the North American industry before prices fell this summer. Many traditional E&P companies, including some majors, decided to become shale players, and many are still considering the possiblity despite low gas prices. The global financial crisis has accentuated the aversion to risk that fueled shale plays to begin with, and it seems that no one now wants to pursue anything but shale.
In the first half of July, spot gas prices were more than $13.00 per million British thermal units (MMBtu). Six weeks later, the price had fallen below $8.00, and in March 2009, it is around $4.25/MMBtu. Some analysts predict that gas prices will average $4.00-6.00/MMBtu range at least through the end of 2010.
A total of 1,966 horizontally-drilled producing wells from the Barnett Shale were evaluated to determine commercial gas reserves using standard decline methods. Based on this analysis, only 30% of Barnett Shale wells will realize revenues that meet or exceed drilling, completion and operating costs in the most-likely case based on assumptions incorporated into a 10% net present value (NPV10) economic model. The economic model includes per-well drilling and completion costs of $3.25 million, a wellhead gas price of $6.25/MMbtu (the average spot sales price for 2007), 75% net revenue interest, 7.5% Texas severance tax, and $1.25/Mcfg lease operating and overhead cost. These assumptions are consistent with information published in 10-K U.S. Securities and Exchange Commission (SEC) filings by key Barnett Shale operators. The model requires per-well cumulative production of about 1,325 MMcfg over 10 years to reach an economic threshold.
An early analysis of 20 horizontally drilled wells in the Haynesville Shale play in Louisiana and parts of adjacent East Texas suggests a disappointing outcome because of extremely high decline rates. Average monthly decline rates are 24%, with 75% of wells declining 20-35% per month. The impressive initial production rates (IP) for these wells do not, therefore, necessarily translate into high reserves (actual daily production rates from the maximum 30-day period were, in fact, about 20% lower than reported IPs).
Fifteen Haynesville Shale wells had sufficient production history to analyze using standard rate-versus-time decline methods. Estimated ultimately recoverable reserves (EUR) averaged 1.5 Bcfg, and 67% of wells had reserves between 0.5 and 1.5 Bcf. These results indicate that Haynesville Shale reserves will be about the same as Barnett Shale wells at approximately twice the cost to lease, drill and complete.
I have struggled to understand the appeal of shale plays based on economic factors, and thought that low gas prices would greatly reduce activity. At $10.00/MMBtu, about half of horizontally drilled and fractue-stimulated Barnett Shale wells were commercial so, while prices were rising even higher, shale plays made some sense. At current prices, however, only about 11% of Barnett wells pay out, and all indications are that prices will fall lower or, at best, remain at current levels. While leasing has largely stopped, drilling continues*, and enthusiasm from both companies and analysts seems strong, at least for the Barnett, Haynesville and Fayetteville shales.
How can we understand what is happening with shale plays?
The diffusion model of innovation (Ryan and Gross, 1943; Rogers, 1962) shows that people adopt new ideas and technologies slowly, and that only about 5% of people make the decision to adopt based on information. The other 95% decide because of the the views of opinion leaders in the community, and on the eventual social momentum that develops—what Malcolm Gladwell called the “tipping point”. The 5% who base decisions on information in the diffusion model are critical thinkers; the rest are conventional thinkers.
What causes people to decide to abandon an idea that almost everyone previously accepted? It is reasonable that only critical thinkers make this decision based on information, and that conventional thinkers follow in what may become a stampede. Thomas Kuhn (1962) explained that scientists resist abandoning a ruling theory in favor of a new paradigm with a kind of orthodox fervor of conventional thinking, and often ostracize those critical thinkers who point out problems with the existing model. At some point, when opinion shifts to support a new paradigm, the previous theory is unceremoniously dropped, and its remaining supporters are criticized as dinosaurs.
It is useful to review some of the history of how our industry arrived in its present state. The collapse of oil prices in 1982-1986, and the ensuing 13 years of over-supply and low prices created an environment in the E&P business where cutting cost and reducing risk were paramount. Thousands of jobs were lost, and companies disappeared as layoffs, reorganizations, mergers and consolidation became the core business of oil and gas companies.
As oil prices slowly recovered in the late 1990s, risk analysis teams were formed to manage technical work. Executives abdicated their technical responsibilities to risk committees, and turned their attention to buiness models. With the help of consultants, they envisioned companies in which exploration and production would become a manufacturing operation, and risk was eliminated. Execution was paramount, standardization was essential, and new geological ideas were unnecessary. The new vision for the E&P business represented the victory of conventional over critical thinking.
Shale plays not only satisfied this model, but also solved the perennial E&P problem of being opportunity-constrained: because shale is practically ubiquitous, there are no limits to what can be spent pursuing new and existing opportunities. This shift was widely supported by the capital investment community because of the low perceived risk, and the fact that non-scientists could understand the play.
Returning to the present, myths about the current state of domestic E&P must be clarified in order to put shale plays in context. These plays are an important component of domestic natural gas production, but represent a relatively small—though growing—portion of the total gas supply. Even among unconventional gas resources, tight gas and coal-bed methane dominate production.
Second, these plays involve considerable risk. The fact that 75% of wells are commercial failures at current gas prices is a tangible risk. Great emphasis is placed on engineering ideas and technology, but it seems that concern for geological and geophysical understanding is uneven among shale players. All shale plays are different, and require unique approaches based on thermal maturity, structural factors, fracturability, and identification of sweet spots.
Third, economic models must be aligned with full-cycle PV10 industry standards. Wood MacKenzie’s Snyder says that established shale plays have "sufficient volumes available at a development break-even price of $5.50/MMbtu or below" (Oil and Gas Journal, December 1, 2008). I don’t believe that. I do not know any credible industry analysts who believe that shale plays are commercial below $7.50. The only way to arrive at the thresholds that Snyder mentions is to understate or ignore current levels of capital expenditure, as well as general and administrative, lease operation, midstream, and discounted capital costs, or to inflate rates and reserves beyond what can be supported by performance history.
Additionally, the over-supply of natural gas that analysts describe may be relative, and that would be positive for shale plays. Spot prices rose to $13.00/MMcf because of an imbalance between supply and demand. Prices fell when about 2 Bcfd of additional supply came online from the Independence Hub, Thunder Horse and Tahiti in the offshore Gulf of Mexico, in addition to increased unconventional gas production, including shale gas. Monthly natural gas production over the past year averaged approximately 1.75 Tcf. The additional 2-3 Bcfd that produced an over-supply is only 3.5-5.5% of total production. Many circumstances might quickly upset the supply-demand balance and result in higher prices. At the same time, the global financial crisis will probably reduce demand, and somewhat offset other factors that may favor rising price. The point, however, is that the difference between what the market perceives as over- and under-supply can be razor thin.
Finally, gas rig counts and rates have fallen sharply in recent months from more than 1,600 in September 2008 to 970 in late February 2009. Some predict that rig counts may fall to 800-900 in coming months. Unconventional wells have steep decline rates, and any decrease in drilling will quickly result in dramatically lower gas production from these plays. That, in turn, will affect supply, and prices could rise, but may also expose the ephemeral contribution of unconventional gas sources to total natural gas supply.
There is little doubt that Shale Plays are likely to be important for some time. I hope that operators will continue to learn how to reduce cost, optimize production, and better incorporate geology and geophysics into their play strategies. It is not certain that the U.S. has a long-term over-supply of natural gas, or that today’s surplus is chiefly because of shale gas production.
Shale plays represent a disturbing tendency in the E&P business away from critical thinking. The belief in reward without risk is irrational. Failure to acknowledge the marginal economics of the play is bewildering. Unless opinion leaders confront the underlying economic and geological risks of these plays, I fear that a financial crisis may develop that will discredit the E&P industry.
*Barnett Shale completions have dropped from about 250 wells/month in May 2008 to approximately 125 wells/month in late 2008.