New Research Questions Shale Gas Economics

Posted by Harvest Dream on Sunday, February 21. 2010 in Economy, Energy, USA

Source: Energy Tribune

Conventional wisdom says the United States is blessed with 100 years of natural gas supplies due to the success in applying horizontal drilling and hydraulic fracturing technologies to gas shale formations that underlie many of the oil and gas producing formations throughout the country. The drilling and completion success of the nation’s oldest and largest gas shale basin, the Barnett Shale in north central Texas, sparked exploration efforts throughout the country. The industry has found numerous new gas shale basins to exploit. The prospect of this new, huge gas endowment has sparked efforts to find additional markets for natural gas including as a transportation fuel for cars and over-the-road trucks. Gas shale enthusiasts are even suggesting that the U.S. may become an exporter of liquefied natural gas (LNG) to capitalize on this gas bonanza.

Key to the gas shale revolution is the huge initial production (IP) from wells in certain of the newer plays – Haynesville, Fayetteville, Eagle Ford and Marcellus Shales. The high IP rates of these horizontal wells are believed to lead to the recovery of significantly larger volumes of natural gas than can be extracted from vertical wells. The high IP’s and greater reserve recoveries contribute to low industry finding and development costs that make the fields highly profitable even at relatively low natural gas prices. High well reserve potentials at low per-unit costs have spawned a gas shale leasing boom, which, due to short lease lives, is stimulating a drilling boom. The downside of this industry focus on shales has been sustained natural gas production that has limited any rise in gas prices since demand has yet to recover.

Last week, two different analyses of the Haynesville Shale concluded that the economics of this basin have peaked and it will not become the bonanza producers and investors have forecasted. One of the analyses came from industry consultant Art Berman of Labyrinth Consulting Services, Inc. while the other came from Wall Street E&P analyst Ben Dell of Bernstein Research. Berman’s research report will soon be available on his blog, but we were provided with an early version.

So what’s behind the conclusions of these two analysts?

Both Berman and Dell have studied the results of roughly 135 (133 and 136, respectively) horizontal wells drilled and producing in the Haynesville Shale. The recent data shows that the average IP of Haynesville Shale wells is starting to fall and increasing the number of fracture treatments in each well is not helping to improve their output. While the basin’s production has grown dramatically since 2008, it now appears to be holding steady, which obscures the fact that the leading E&P companies are experiencing declining IP’s. In other words, the recent rise in the basin’s total production is largely due to better performance from newer entrant E&P companies and their use of larger numbers of fracture treatments in each well they drill.

Berman plotted the daily production from the Haynesville Shale wells owned by Petrohawk (HK-NYSE), which appear to be primarily in the core (most prolific) area of the basin. The IP starts high but then declines rapidly. The average daily production line he calculates, which admittedly may be influenced by the natural distortion arising from mathematical averaging, shows a rapid decline before stabilizing within one year. If accurate, these wells are reaching stable production much faster than wells in the Barnett, the oldest producing gas shale basin. That may mean lower volumes of gas recovered from these wells.

Based on the well production data, both analysts conclude the core of the Haynesville Shale will be smaller than for the Barnett Shale and with worse well economics. They question whether wells located outside of the core area will be economic at today’s natural gas prices. They also question whether wells will produce the volume of gas initially predicted. If so, the Haynesville Shale will not be as large a gas field as suggested by early entrant explorers.

A conclusion that comes from examining the well locations and their IP’s is that there appear to be faults in the basin defining the core and non-core areas. The production data from wells in the core is better than from non-core wells. This structural definition within the basin suggests that the development of the Haynesville Shale will not be a “manufacturing process” where the key to growing the basin’s production is merely drilling more wells and using the optimal number of fracture stages.

Dell’s analysis of the basin’s wells concludes that there are three distinct areas within the core area along with a large non-core area. Within the core area, according to the data, in 2009 the average IP rate of wells drilled was 9.7 million cubic feet per day (MMcf/d) compared to an average of 6.9 MMcf/d for wells drilled outside the core area. The western core area showed an average well IP of 7.5 MMcf/d; the lowest rate within the three core areas. Since all wells were completed with 11 fracture stages, these production results suggest that the well IP performance is related to geology and not due to less complicated well completions.

Berman’s analysis concludes that the average economic ultimate recovery (EUR) of wells in the Haynesville Shale is 2.0 billion cubic feet (Bcf). Based on his analysis of lease, drilling and completion, and operating costs, he estimates the minimum EUR breakeven economics at 5.0 Bcf per well. Of the wells he analyzed, only 11% meet or exceed this commercial breakeven threshold.

While Berman and Dell are critical of Haynesville Shale economics, there remain many Wall Street analysts and industry participants who believe this basin, and all other gas shale basins, will provide long-term profits for E&P companies. One Wall Street firm has estimated the economics for all the major gas shale basins, which includes an estimate of the threshold price needed for profitability. In the case of the Haynesville Shale, the firm estimates the threshold price at $4.40 per thousand cubic feet (Mcf). As natural gas prices are currently in the $5.45/Mcf range, there is roughly a dollar of profit per Mcf. A critical ingredient in this analysis, however, is the estimate of finding and development (F&D) costs. This cost estimate includes all the direct costs such as leasing expense, drilling and completion costs and production maintenance costs, and a share of the corporation’s overhead. In the future, however, there will likely be significant additional costs for new fracturing treatments that will be an ongoing need to sustain gas shale well production. The F&D estimate is also dependent on an assumption of the volume of discovered gas reserves that ultimately will be produced. The greater the gas volume estimate, the lower the F&D cost, and the easier to predict well profitability.

What is the significance for the domestic natural gas industry if the Haynesville Shale turns out to be smaller/less economic than initially anticipated? Early speculative estimates claimed the Haynesville Shale might contain 250 trillion cubic feet (Tcf) of natural gas. Last year, when the Potential Gas Committee reported that the nation had 1,836 Tcf of technically recoverable gas resources, it also estimated that 616 Tcf of this total was contained in gas shale formations. Based on the early estimates, the Haynesville Shale would account for roughly 40% of this estimated total. If the Haynesville Shale does not contain as much gas, does it call into question the Potential Gas Committee’s total resource estimate? Would that shortfall potentially undercut the universal belief that natural gas, especially given the contribution from the gas shales, will be the bridge fuel from an economy relying on dirty hydrocarbon fuels to one powered by clean fuels?

It may be early to draw definitive conclusions, but one at least needs to ask the question: What if?

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