Michelle Michot Foss, Miranda Wainberg and Gürcan Gülen* (email@example.com)
Since the price movements of 2006-09 a great deal has been written about the role of speculation in futures markets. It is true that new players such as pension funds have entered the market in a bigger way in recent years and might have initially exerted impact. (They also may have become more cautious, a consequence of both regulatory actions and market volatility, a potential effect going forward.) In fact, there is a large variety of market participants, many of whom treat commodities such as oil, and natural gas as a pure asset class to be traded within a portfolio approach. Their goals for financial returns and perceptions about physical supply-demand fundamentals, based on storage and inventories and triggers such as weather and geopolitical events, probably impact prices in the short-term. This impact can be enhanced, and in fact the market could be more attractive to such investors, when there is tightness that leads to high price expectations. As portfolios are evaluated, many investors are constantly comparing risk-weighted returns from commodities relative to other asset classes such as equities, bonds and so on. Interest rate movements, expectations about inflation, relative currency values and other factors all can influence investor perceptions, expectations and actions.
However, market fundamentals govern long-term prices; in other words, oil and natural gas prices revert to a mean eventually. The mean reflects long-term marginal cost of supplying the last barrel; it changes along with changes in fundamentals including sources of supply and cost of finding, development and delivery. Thus, of importance is understanding resource availability and costs, as well as longer term demand dynamics and constraints
The most basic of fundamental factors impacting oil prices is finding and development (F&D) cost. Although changes in F&D costs are not likely to influence daily trading (and many traders will tell you that they do not pay attention to these costs in their daily trading activities), they do contribute to prevailing perceptions and sentiment about market fundamentals. During the high price period of the mid-2000s (until mid-2008) most everyone, especially among the political class, focused on the role of speculation in commodities markets. During the same period, though, the global industry experienced significant challenges in identifying and/or accessing new resources, drilling and converting those resources to reserves, and delivering them to growing economies. Finding costs reflect many of the same pressures that underlie demand for oil. During periods of robust economic growth, demand is strong for energy and other basic materials that are also components of energy production (everything from steel to manpower). Coupled with prevailing exploration trends toward more complex and remote resources, and given the array of regulatory, geopolitical and strategic factors that impact access to reserves, finding costs in the years since 2000-2001 were markedly higher. For example, the IHS CERA Upstream Capital Cost Index rose from about 110 in 2005 to 200 and peaked at about 230 in mid-2008. Although the index dropped after the economic collapse in late 2008, it bottomed out at about 200 and started rising again recently. This cost increase was caused by the increase in the cost of steel, onshore and offshore rigs, and other equipment and services.
The tendency among analysts and researchers is to focus on direct “drill bit” finding costs. These estimates, which vary across basins and reflect technology as well as industry skill and efficiency, provide information among competing opportunities and locations to explore for and develop oil resources but do not reflect the full cost to producers associated with all of their obligations, including cost of leverage and taxes and other payments. A “3x multiple” of finding cost can be used as a proxy and to test the impact of fundamental and non-fundamental factors on oil price. The “three times finding cost” approach is a rough industry rule of thumb that links finding cost with profitability as expressed in oil price. Adam Siemenski provided an interesting treatment of the “West Texas” rule using U.S. EIA data to show that when finding costs are regressed on oil price, the coefficient fits this rough standard of three to four times finding cost (Deutsch Bank Commodities Research circular, July 16, 2007, USD60/bbl: The New Mid-Cycle Oil Price). A producer commented recently that when natural gas finding cost was $1/mcf (1990s money of the day), Henry Hub needed to be $3 for wells to be profitable.
As shown in Figure 1, for all of the modern decades of interest and over the longer term, oil prices largely have been in line with full finding cost trends. Clearly, these trends and relationships are moderated by other factors. Demand response eventually kicks in, pulling price down (and stranding high cost projects). Producers eventually develop technology and best practices that enable them to push finding cost down (and achieve or sustain profit margins).
Figure 1. Finding cost and real oil price
In order to further test this relationship, and to test the integrity of the “3x” rule of thumb and proxy, we calculated cash costs based on U.S. EIA FRS data between 1977 and 2008. Adding a 10 percent return on cash costs, we obtained a value that can be compared to the “3x finding cost” benchmark. To smooth out any spikes, we use three-year moving average values. The correlation between the “cash cost plus 10 percent return” and “3x finding cost” series is very high, 0.94. Out of 30 observations, only in four of them is the “3x finding cost” estimate larger than the “cash cost plus 10 percent return” data (Figure 2). The average deviation of “3x finding cost” series from the “cash cost plus 10 percent return” series is 20 percent. Hence, we feel confident concluding that the rough industry rule of thumb is fairly accurate and more conservative than actual cash costs.
Figure 2. Finding cost and cash cost + 10% return
Beyond oil, we have calculated full finding and development cost for U.S. natural gas using publicly available corporate financial data. Of great interest is sustainability of U.S. shale gas plays. As shown below in Figure 3, most natural gas producers in our sample have full costs plus return that far exceed current Henry Hub natural gas prices. Some have direct F&D costs in excess of HH; drilling has been sustained by producers that have remaining hedges in place or that face leasehold obligations. We find that the “three times” rule works well in the current natural gas price environment and should for the foreseeable future. In addition, cursory correlations across natural gas and overall oil and gas drilling (rig activity) and oil and gas production and prices indicates stronger correlations to oil prices. Indeed, oil and natural gas price volatility measures are strongly coincident (see Figure 4). The influence of oil price holds for the full history of U.S. data points but recent patterns demonstrate the importance. Given the strong divergence between crude oil and natural gas prices, many producers have shifted drilling expenditures toward oil and liquids rich gas production (condensates) because of greater profitability.
Figure 3. F&D Costs for Representative Sample, U.S. Natural Gas Producers
Figure 4. Crude Oil and Natural Gas Price Volatility
Note: Compiled using CME (NYMEX) data; STDEV of LN daily,1-yr MA annualized
In sum, both price level and volatility matter. In sifting through the countervailing factors across short and long run horizons, expectations regarding supply development and deliverability and associated costs are vital for better understanding of oil and gas prices and market dynamics.
* Center for Energy Economics, Bureau of Economic Geology, The University of Texas at Austin.
 For example, see “Calstrs Reins In Plans for a Big Bet”, Wall Street Journal, November 12, 2010.
 In an Energy SEER strategic brief, December 2009, Mike Lynch documented cost trends that we know very well in the U.S. upstream businesses, including impact of economic cycles; technology; and role of depletion and field maturity in creating upward push on costs. To that we would add that increased reservoir complexity – a prevailing trend in the U.S. and worldwide – commensurate with a shift toward unconventional resources also exerts an upward push on costs.
 Until the 2000s, oil additions were more than 50%; but it is mostly natural gas since then.
 We based our assumption of a 10 percent return on information released to analysts by EOG Resources in September 2010.