Chesapeake has elected to curtail approximately 240 million cubic feet of natural gas equivalent (mmcfe) per day ( 0.23 bcf/day) of its gross natural gas and oil production due to currently low wellhead prices in the Mid-Continent region. The company has curtailed approximately 200 million cubic feet per day of gross natural gas production and approximately 6,000 barrels per day of gross oil production for at least the month of March 2009. The curtailed production represents approximately 7% of Chesapeake’s current gross operated production capacity. Additionally, the company is considering a further 10% reduction in its drilling activity during 2009 if natural gas and oil prices remain low during the next few months. The company’s attractive hedges and cash availability provide it with the operational and financial flexibility to curtail production during periods of unusually low prices, such as the current market environment. The company believes conditions are developing that will support higher prices for natural gas and oil later this year and in 2010.
This got me thinking about how much we use, who produces it, and issues such as the understanding of the different units that are used. So I am working on a standardized presentation of units – and see the sidebar for conversions etc.
Putting the Chesapeake statement in context, the CEO is quoted
During March 2009, most Mid-Continent natural gas prices at major interstate pipeline delivery points will average around $2.70 per thousand cubic feet (kcf), a price at which most natural gas production is unprofitable. We believe low wellhead prices combined with constrained capital availability will likely cause U.S. drilling activity to decline well beyond the 40% drop already seen since August 2008. As a result, U.S. natural gas production will begin to dramatically decline before the end of 2009 and consequently natural gas markets will regain better supply/demand balance by the end of 2009, if not sooner. …… In addition, we have reduced our drilling activity from 158 operated rigs in August 2008 to 110 currently. We are considering a further 10% reduction in our drilling activity, which if implemented, will be in areas where we do not have joint venture drilling carries.
To put the price in context Atlas Energy just reported that their drilling costs in the Marcellus Shale where they are currently developing production in the Applachian Basin, were $1.49 per kcf.
In 2008 the United States consumed a total of 23,241,512 mcf of natural gas, of which 21,328,916 mcf is delivered to customers (91.7%). This averages 63.6 bcf a day of total consumption, with 58.4 bcf going to customers. This is not an even consumption, but as you might imagine, is a function of the month (as shown below).
Natural Gas Consumption by month for 2008 (Source EIA ) And for those curious as to whether the weather was exceptional in those months, the average heating degree days for the regions of the country were higher in the 2008-2009 heating season over the previous season by over 7% on average.
Natural gas is supplied to four main markets electrical power generation (18.2 bcf/d); industrial use (18.2 bcf/d); Residential (13.4 bcf/d) and Commercial (8.6 bcf/d) use. The natural gas that goes to power generation now produces roughly 25% of US electrical power, and has the advantages of being both cleaner than coal, and also more flexible. This is particularly useful as more renewable sources such as wind and solar come into the grid, where their fluctuating power needs to be balanced, and natural gas is better at doing this.
To get some sense of where this came from, consider that Devon Energy drilled 2,441 wells in 2008, with a claimed 98% success rate. 659 of these were in the Barnett Shale, where the company now has a total of 3,809 wells, which produced 398 bcf in 2008. By the end of 2008 company gas production was nearly 1.2 bcf/day. Devon actually produces both oil and gas and so I can’t do the following calculation using their numbers, but let me instead set up a hypothetical company, but using some similar numbers.
Let us assume that this company is producing 1.2 bdc/day of natural gas. It only produces natural gas, and it got this production from 4,000 wells in 2008. If it drilled 2,500 wells in 2008 of which 90% were productive, then it would have 2,250 new productive wells. If one divides the daily volume among the producing wells that gives a daily average production of 300 kcf/day. However it is important to remember that in the gas shales some 60% of production comes from the well in the first year, and if, for simplicity we say that 36% comes in year 2, and that the remainder can be neglected, then I can illustrate the drilling need with a very crude calculation.
Let us say that wells come on stream at the first of the next year. Then at the beginning of 2009 1,750 wells were entering the second year of production while 2,250 were just starting up, then the production number changes so that in their first year the new wells will produce an average 363 kbd and this drops to 218 kbd in the second year, and the well is then done. Now we move forward to the start of 2010, so the original wells drop out of production, and the new wells drop down to second year production values. In order to sustain gas production the company will have to drill an additional 2,167 wells this year, at the assumed new production rate and success rate.
However the price of natural gas having fallen the company which drilled last years wells with say 160 rigs decides to cut back to 110 rigs in the same vein as Chesapeake. Then if the 160 rigs drilled 2,500 wells in 2008, the rig production is about 15.6 wells/year. So the number of wells drilled this year at that rate, but with the lower number of rigs, will be 1,718. At 90% success rate this gives 1,546 new wells at 363 kbd and 2,250 old wells at 218 kbd. The total is roughly 1.0 bcf/day. In other words the company will see a 20% drop in production next year. It gets a little worse in 2011. Consider that if the same number of wells are generated in 2010, then we have 1,546 wells at 363 kbd and 1,546 wells at 218 kbd, so the production drops to 0.9 bcf, at which it stabilizes, if the success rate and well production rates remain constant. As a matter of reality it is likely that they will drop.
To revert back to real numbers the Baker Hughes rig counts for 27 Feb, 2009 had 1,243 rigs operating in North America, of which 78% were gas (970). Of the total some 37% (460) were drilling horizontal wells. Incidentally the site presents these in a rather informative graphic:
Source Baker HughesIt is interactive and, for example, by selecting for the Williston Basin find that there are 34 rigs drilling, that they are all drilling for oil, and that 89% of them (30) are drilling horizontal wells.
Source Baker HughesThis is a much faster and more visual understanding of the data than the old way of downloading spreadsheets, which is the way you still have to look to find, for example, that in January Saudi Arabia had 46 rigs drilling for oil, and 28 drilling for natural gas. But it still leaves me wondering what that one rig is doing drilling a geothermal well in Illinois.
Well enough for crystal gazing for today, as I mentioned this is just an illustrative example of what might happen in the none-too-distant future. It is not accurate since some companies are cutting back harder on rig counts than I have suggested, success rates are not all the same (it has been suggested that as an industry average only 28% of the gas shale wells make a profit at a reasonable price for gas). But it might help understand why it is very unlikely that gas prices will remain as low as they are now for very long.
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