The latest EIA Drilling Productivity Report shows that Eagle Ford legacy oil production decline is fast approaching 100,000 barrels per day. In other words, it takes 97,000 barrels per day of new production that needs to be added each month, just to keep oil production flat. When the EIA first started releasing these monthly reports in October, 2013 it took 80,000 barrels per day that needed to be added each month in new production to keep field production flat.
Note: The data is from the EIA drilling productivity report. The graph shows the difference between Eagle Ford, where legacy production decline is increasing at a fast pace, which requires an equally fast-paced response from drilling, which needs to continue increasing in order to stay ahead, and Bakken where for now both rate of legacy decline and monthly production from new well additions are stable.
For now, new production coming on line each month is more than enough to offset the legacy production decline. For the month of March, the EIA forecasts an increase of 34,000 barrels per day coming from Eagle Ford. The addition of new production coming from drilling activities will total 131,000 barrels per day in March, which is an increase of 26,000 compared with the October 2013 report, when 105,000 barrels per day in new production was forecast for November. As should be expected, this increase is due to a continued increase in the number of wells being drilled each month. Data on the issue of new drilling permits from the Texas Railroad Commission shows that in 2013, 4,500 permits were issued, while in the previous year it was 4,100. As of the end of the third quarter drilling permit issuance was running below the 2012 average, which means that in the last quarter of 2013 there was a higher than average issue of new drilling permits. The EIA data which shows a slight increase of the total number of drills operating in the field confirms the fact that drilling activity picked up in the past few months.
We should also mention that the pad drilling technique is adding to the speed with which new wells are being completed, because these drilling rigs are more easily moved from one drilling site to the next. This means that the number of wells brought into production per drilling rig is on the rise. If we are to go by the Texas Railroad Commission data on drilling permits issued, it seems Eagle ford wells are being added at a pace of about 500 per month. There were 503 permits issued in January, therefore, it seems to be the current pace. If we were to take into account that there are about 300 drilling rigs operating in the Eagle Ford according to the EIA and it now takes less than 15 days to drill a well according to industry claims, we would get a higher number, in the 600 range, which is most likely not true.
The finite field:
The EIA estimated last year that about 22,000 wells will ultimately be drilled in the Eagle Ford. According to Texas Railroad Commission data, over 12,000 were already drilled and we are now seeing a pace of roughly 500 new wells drilled every month. I have no doubt that new sweet spots and new extensions to the field will be discovered. There will also be some innovative solutions to increasing well saturation density level. Perhaps all these things will lead to a doubling of the EIA estimate. Having said that, even if all these things will happen, at current drilling pace, 45,000 wells would be drilled by 2020. It is quite obvious at this point that it will not happen so soon - by my own estimate in the next two years, the number of new wells drilled each month will start declining and with it, so will production.
Field decline probable before field breaks even:
By my rough estimate, by the end of 2014 total liquids and gas sold since 2010 will amount to about $131 billion in value. Based on the assumption of 5,500 wells being drilled this year, cumulative wells drilled since 2010 will amount to 17,900. At an assumed cost of $8 million per well on average, the total cost of drilling alone comes out to $143 billion.
Eagle Ford yearly revenue from oil & gas and yearly drilling costs
|2010||37 m/b x $65 = $2.4 bill||640 BCF x $4 = $2.6 bill||$8.1 bill|
|2011||100 m/b x $80 = $8 bill||910 BCF x $4 = $3.7 bill||$22.6 bill|
|2012||220 m/b x $80 = $17.6 bill||1.37 TCF x $2.75 = $3.8 bill||$33 bill|
|2013||360 m/b x $85 = $31 bill||1.92 TCF x $4 = $7.7 bill||$35.2 bill|
|2014||510 m/b x $85 = $43 bill||2.56 TCF x $4.5 = $11 bill||$44 bill|
Notes: The average price of Eagle Ford liquids is about $10 a barrel lower than WTI spot price, because many liquids are in fact not crude oil, but NGLs, which on average have a lower price. For 2014, I assumed the price to remain at 2013 levels and average daily production for the year at 1.4 mb/d. Liquids and gas volume produced yearly are derived from EIA charts. Yearly drilling costs are derived from yearly drilling permits issued as presented by the Texas Railroad Commission.
This number does not include many other operational costs, such as interest on debt, land lease, building up of infrastructure related to operations aside from drilling, royalties and taxes, administrative costs and many other expenses involved in such operations. It is likely that 2014 will most likely be the year that the field will break even. If Eagle Ford field were to avoid a peak in 2015 and thereafter, perhaps there would be a net profit and if it were to go on for long enough, perhaps the net loss incurred in the 2010-13 period would be recuperated and then a net financial gain would be achieved. As we see the number of wells already drilled piling up, we have to realize that the time to recuperate the costs involved in producing oil and gas from Eagle Ford is running out.
Royal Dutch Shell first victim, will not be the last.
Last year Royal Dutch Shell (RDS.A) reported a second quarter write-down of over $2 billion due to disappointing results in one of their liquids rich shale projects. I wrote an article in response, pointing out that Shell invested in leasing a 100,000 acre property in Dimmit county, which a paper released by the Society of Petroleum Engineers in 2012 shows to be one of the counties with a median production per well, which is below the average for the Eagle Ford field. Shell did not reveal then where the write-down was warranted due to poor performance, but since then, it was revealed that the property is being put up for sale.
Chesapeake Energy (CHK) is heavily invested in the Eagle Ford (link). About half of all oil production for this firm comes from the Eagle Ford. It holds 380,000 net acres and already drilled about 1,000 wells. Currently it operates 11 rigs as of the latest information, while production of oil is about 60,000 barrels per day. The eleven rigs can drill about 20 wells in a month's period, for a cost of about $7 million each, for a total monthly cost of about $140 million. The value of total oil sold in a month is about $162 million, assuming a sale price of $90/barrel, which leaves about $22 million per month to cover other expenses, such as royalties and taxes, lease costs, infrastructure costs, administrative costs and so on.
It is true that Chesapeake's cost of drilling a well declined significantly in past years, from $9 million per well to $7 million currently. At the same time however we need to recognize the fact that geology of the formation is now well enough known to facilitate the targeting of sweet spots when drilling, which means that the best sites are being drilled right now, leaving on average less profitable places to drill for later.
It is also true that wells which were drilled in the past few years will probably continue to produce for years or even decades to come, albeit at a much lower rate. In theory, if we were to ignore continued drilling costs, production from existing wells should continue to bring in additional revenue every year, with no cost of drilling involved.
While the example of Chesapeake Energy is one that leaves a question mark in regards to whether it will recover its total investments and costs associated with its Eagle Ford investments, there are other investments, which seem to defy logic. Devon Energy (DVN) acquired 82,000 acres in November, 2013, including production infrastructure of 53,000 barrels of oil equivalent per day from GeoSouthern Energy for $6 billion (link). The lease cost per acre of undeveloped property, which is yet to be drilled comes in at around $50,000. The maximum well saturation thought to be possible is one well per about 50-60 acres, so the land lease cost per well comes in at around $3 million.
Adding in all other costs, including the cost of drilling makes it hard to see how this venture can ever end in a net profit. Devon Energy sees the end game based on assumptions of average ultimate recovery rates per well of 800,000 BOE, which is what they actually expect to see according to their official release in regards to this acquisition. It is true that the SPE paper released in 2012 singles out DeWitt County as by far the best producer per well, with median production at almost 400,000 BOE expected to be ultimately produced. The big difference in industry expectations for ultimate production per well and more impartial sources is quite large as we can see. The study is two years old now, so it can be argued the data is outdated and therefore irrelevant. It still has the advantage of impartiality in my view, which within the context of a tendency on the part of companies in shale resources to exaggerate the size of resources and the potential production per well. The SPE study is just as relevant as data provided by companies.
Shale oil and gas is a hybrid between drilling and mining operations.
At the end of 2014, we will be wrapping up the fifth year of fracking driven production boom in the Eagle Ford, which will most likely bring total liquids production into the 1.5 mb/d range and natural gas in the 8 billion cubic feet per day range. It is an impressive achievement given that just a decade ago shale oil and gas resources were not considered to be viable, aside from a sweet spot here and there, which was never going to add significantly to the US, never mind the global supply of oil and gas.
The fact that after five years of development, and that we are most likely approaching the halfway point of the total wells ultimately drilled in the formation total revenue derived from the sale of oil and gas will not even cover the total cost of drilling to the end of 2014, should be cause for worry. As we look at individual companies and review total drilling costs versus total revenue, we see that even in the happy case of Chesapeake, revenues barely cover the costs of drilling month to month. This means that there is little left to go towards recuperating the wide gap left from previous years of operation, when revenue was not even coming close to matching drilling costs as well as all other costs involved.
The reason why this is a worrying trend is because unlike conventional field development, shale oil and gas requires constant drilling at a high pace just to keep production going. It is in some ways similar to a coal mine, where in order to get more coal out of the ground we have to keep digging. If we stop digging, the coal stops surfacing from underground. The difference in the case of shale projects is that after the first two years of very steep well production decline, production does continue at a much smaller flow rate compared to initial production rate. It is perhaps this hope that following the initial steep decline rate experienced during the first two years of well production, the well decline rate will slow down significantly enough to keep production going for perhaps a few decades at a rate high enough to justify allowing the well to continue to produce. We have no way of knowing for certain how long the tail end of shale oil and gas well production will last, but if the expected decades of continued well flow will not materialize, it is possible that many firms will never recover all the costs of developing Eagle Ford.