Economics of Shale Gas
- Jun 8, 2015 9:25 pm GMT
Since 2007, when vast amounts of shale gas in the United States have been tapped, US natural gas production has significantly grown by 20% causing sharp fall in Henry Hub's natural gas spot price. Consequently, this turned industry's attention to profitability of shale gas extraction. In the middle of this September spot gas in the USA was trading at levels of up to 3.00 USD per MMBtu which may still not be the level equalizing market price with individual producers' marginal costs. Although it may seem that April lows, when gas traded below USD 2.00, are unlikely to come back again soon, one may ask oneself where did push for this price hike come from? Also, could this movement continue over the foreseeable future? To some extent this question may be answered by looking at costs faced by a representative shale gas E&P company and at what price does it breakeven.
Typical company aiming at production of shale gas faces cost structure as depicted in Figure 1 (time unit is year). At the beginning there are significant Finding & Development (F&D) costs to be incurred1. According to (2011) report published by 3Legs Resources, costs associated with development of shale formations are ranging between USD 2-3 m and may be significantly higher than these of conventional reservoirs -- it is mostly due to extensive use of horizontal drilling and hydraulic fracturing. Production begins alongside build-up phase. In particular, production from shale gas reservoirs builds up at a much faster pace, reaches higher level than in case of conventional reservoirs2 and eventually leads to higher cumulative production. Consequently, higher F&D costs are usually offset on gas-produced basis with e.g. high quality Barnett vertical well's F&D cost at USD 1.71 per Mcfe as opposed to horizontal well's USD 1.06 -- 1.34 per Mcfe (Hayden & Pursell, 2005). However, the exact F&D costs may vary significantly and obviously depend to a large extent on amount and flow-rate of gas produced. Furthermore, consultancy SAIC expects F&D costs to decline within five to ten years and reach stable low real rate of cost escalation.
After build-up phase, production from a field reaches plateau which can be considerably shorter in case of production from shale formations. Notably, horizontal wells often have to undergo costly re-fracturing in order to maintain plateau.
Importantly, as gas production from shale's occurs earlier than from conventional formations, and therefore revenue is incurred earlier too, discounted value of profits could be potentially higher.
However, while discussing economics of gas production one should not forget about the so called decline rate defined as below with Q standing for production rate at time t:
Decline rate is of particular importance in case of single well -- it presents production decline due to pressure decrease from gas well. As has been shown below, shale gas wells' production decline tends to be much higher than that of vertical wells. In terms of production against time we talk of decline curve. Although there are some projections of the latter, exact projection of production profile is difficult due to lack of long-term history data and is possible only in case of oldest shale gas plays such as Barnett.
According to engineering consultancy Fekete (2011), equation for decline is given by:
Where D(t) is the decline rate at flow rate Q at time t.
As it has been picturesquely described by John Dizard (2010) of Financial Times, some engineers involved in production of shale gas use in their production projections hyperbolic decline and some others -- exponential decline.
The difference in curvature turns out to be crucial and comes down to "b exponent". According to Dizard, with "b" in range of 0 and 1 production decline curve resembles more exponential curve, and with "b" higher than one -- hyperbolic. If production decline is modeled using hyperbolic curve, production flattens earlier than in case of exponential curve and thus leads to higher Estimated Ultimate Recovery (EUR) and longer well life which in consequence increases project's profitability. For a better picture of these logics, look at Figure 2 presented in 2006 at University of California Santa Barbara by Chris McGill.
In their thorough analysis of shale gas economics, Berman & Pittinger (2011) looked carefully at more than 1000 horizontal wells in each: Barnett, Fayetteville and Haynesville Shales. Their estimation of average "b exponent" was 0.66, 0.56 and 0.25 (accordingly) indicating that production decline curve is closer to exponential than to hyperbolic as most operators would like it to be. Furthermore, authors estimated EUR per well at approx. 50% lower than what is typically claimed by operators. It may be ascribed to operators attaching these numbers only to their sweet spot production areas while Berman & Pittinger (2011) analyzed wells in all locations.
Each gas well or field, sooner or later, is abandoned after reaching its economic limit meaning that gas flow's rate is too low in order to allow for economical production. At the same time shale gas well/field operator may incur additional clean-up costs if the property has been devalued during gas production operations for example due to visual impact or contamination.
Breakeven Price of Shale Gas Production
Thanks to on-going technology advancements of horizontal drilling and hydraulic fracturing, production of natural gas from shale formations has become more cost-effective leading to lower breakeven price. In this paragraph, if not mentioned explicitly, estimates concern only natural gas production with no associated production of NGLs which are significantly improving wells' economics.
Berman & Pittinger have done a conservative analysis of shale gas economics in three basins: Barnett, Fayetteville and Haynesville. Their results and assumptions used for calculations can be seen in Figure 3.
The study estimated gas price at which an average shale gas producing company breaks even in its overall operation areas and in sweet spot areas (where EUR is higher) in two scenarios: (1) full financial burden including land acquisition (i.e. `Full Cycle'), and (2) limited including only drilling, well completion and operating costs. As far as it concerns land costs, they vary considerably between different operators and depend on whether the company was early or late in entering the play. Finally, authors of the study claim that gas spot price has to be in range of approx. USD 4.20 -- 8.75 per MMBtu (depending on place of production) in order to allow for profitable or at least non-loss generating production, well above current level of prices in the US market.
It has to be remembered that results of Berman & Pittinger's analysis present averages for whole basins and are based on rather conservative approach. On an individual company basis breakeven gas price are often lower in case of well managed companies with high quality assets -- this can be derived from Figure 4 below presenting comparison of different North American companies from gas industry. Importantly, it does not directly apply to shale gas since this comparison takes into consideration all assets: both conventional and unconventional gas wells.
On the other hand, in its special report (2012) IHS believes that only one third of 3,300 tcf of resource in North America may be produced profitably at price of USD 4.00 or less.
Nevertheless, several industry senior managers seem to confirm picture presented above:
- During discussion of Q1 2012 financial results, James Tisch, Loews' CEO, said that natural gas at USD 4.50 per MMBtu is "still a veritable bargain".
- In April 2010 John Watson, Chevron's CEO, said that production of shale gas at USD 4.00 is not profitable at all.
- Devon Energy's CEO, John Richels, said that in order to sustain drilling activity gas prices would have to be between USD 6.00 -- 7.00.
However, it has to be remembered that costs of production may go down as learning curve of shale gas technology goes up. In particular, the best shale plays may produce profitably at prices in range from USD 2 to 3 per thousand cubic feet of gas, which is according to John Deutch around one-half to one-third the production cost associated with new conventional gas wells in North America. This has also been confirmed in some respectable studies by (1) Rice University's researchers (2011) saying that "breakeven prices for some of the more prolific shales are estimated to be as low as USD 3.00, with a large majority of the resource accessible at below USD 6.00"; and (2) by IHS Global Insight (2011) which estimates that ,the full-cycle cost of shale gas produced from wells in 2011 is 40-50% less than the cost of gas from conventional wells drilled in 2011".
Finally, one should not forget about natural gas liquids associated with unconventional gas production. As can be derived from Figure 5, price of a barrel of NGLs mix (consisting in 36.5% of ethane, 31.8% butane, 14.3% natural gasoline, 11.2% normal butane and 6.2% iso-butane) is positively correlated with price of oil. Since the latter has recently been at rather high levels, economics of shale gas production were significantly improved by production of NGLs. However, as companies drilled more and more for lucrative liquids, their price in recent months has also been depressed (best seen in Figure 6).
As can be seen from the above, unless associated with production of other liquids, current production of shale gas in the United States of America is far below its breakeven. Consequently, this fact has triggered rapid decline in drilling activity (lasting until today) and thus lowered natural gas production. This is where the recent price increase in large part stems from. However, this should be not solely ascribed to supply-side factors -- please do not forget about demand-side factors which may be equally important!
- These cost include: (1) acquisition of mineral lease and seismic data identifying reservoirs potential (which has to be properly interpreted later on); and (2) actual costs of drilling and developing gas field.
- Exact level depends on formation's structure, e.g. Haynesville's Initial Production rates are one of the highest out of all shale basins.
3Legs Resources. (2011, June). An introduction to shale gas.
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