North Dakota Bakken/Three Forks Scenarios

226 thoughts to “North Dakota Bakken/Three Forks Scenarios”

1. Hi Dennis,

   Thanks for this very elaborate analysis.

   Since you asked for “problems with the analysis”, I have a question/remark. I am not convinced by your figure 2. I am not a pro, so I may have misunderstood the current evolutions in Bakken. But, for what it’s worth, I understood that the decline rate of new wells is higher than the decline rate of older wells. That sounds plausible to me for an industry trying to reach positive returns as soon as possible. So I understood technological evolution lead to a quicker recovery of oil in the first year(s) after fracking a well. That means your 2018 curve should be steeper than your 2015 curve in the first 10/20/30 (?) months. Then cross the 2015 curve, then reach a lower limit indeed (e.g. 250 kb).

   EUR decrease is not only a shift downward, it’s also a shift leftward. It’s a rescaling of the curve resulting in a sharper ‘corner’.

   If, as I suppose, your model is a summation of future standard wells, the downslope must be steeper if you implement a leftward shift together with the downward shift. At the end you may resemble the symmetrical Hubbert curve.

   Or am I wrong?

   Greetings,

   Bruno Verwimp

   1. Hi Bruno,
      Edit(2/13/14) Did you see my comment further down with a chart using Enno’s data)?
      Both of the curves are Arps hyperbolic functions of the form
      q=qi/(POWER((1+b*di*t),(1/b))), the only thing that has changed from the Jan 2015 to the Jan 2018 cumulative curve is that qi is lower for the later curve. qi=13100, b=1,di=0.142 for Jan 2015 and qi is reduced to 9029 for Jan 2018. From 2008 to 2012 there has been no evidence that what you suggest may be happening has happened, the medium model uses the same hyperbolic output curve from April 2008 until Dec 2015 and the data through Nov 2013 matches the model well. What happens in the future is only a guess, yours may well be the better guess, but I would think we would see some evidence over a 4 year period (2008 to 2012). Also note that after 150 months I use exponential decline at the monthly decline rate of month 150 out to 1200 months. Hope that helps.

      1. Hi Dennis,

         Can you try using the curve fit I created about a month ago using the graph Ron provide me:

         2.718281828^(6.289439107718543 – 0.011543315289183781 x +
         0.00006035241819860633 x^2 – 1.9952239638304292*^-7 x^3 +
         3.962939760372318*^-10 x^4 – 4.923012495812217*^-13 x^5 +
         3.860008680236791*^-16 x^6 – 1.85110898087435*^-19 x^7 +
         4.939129575330045*^-23 x^8 – 5.5985240664919645*^-27 x^9)

         Here is the graph using this curve fit equation. I think this curve fit should be pretty close to the production slope of a real Bakken well. The total production over a six year period is 199,871 barrels. I’ve attached a graph of using the above curve fit equation for your reference.

         

         1. Hi Techguy,

            Could you put that formula in excel format so I can copy and paste, also could you refit using months rather than days, since my model is month by month, I actually use mid month so t=0.5, 1.5, 2.5,… Or you could download my spreadsheet and plug it in to the well profile sheet, but as I said it needs to be by month to work. Also my profile is about 224 kb at year 6 but does mot drop down to zero output at 2100 days, I think a more realistic profile might extend the slope from 1600 to 1900 in an exponential fashion, have you tried fitting a hyperbolic up to 6 years and then an exponential from year 6 to 15 or 20?

            1. Sorry with large number of posts recently I didn’t spot your post. If I understand you correctly, you have another data set in an excel sheet you want me to create a curve fit equation? I can do that. Since I saw the emails with Enno, did you have an updated sheet you wanted me to use? Can you post a link to the excel sheet you want me to use?

               Thanks!

2. Dennis has obviously put a ton of work into this post and I for one will need a good bit of time to digest it.

   Meanwhile—–I know that somebody has site that has an energy industry dictionary with a list of all or at least most of the acronyms used in the industry because I used to have it bookmarked but my old computer died and I can’t remember the name of it.

   Somebody help me out and thanks in advance as usual.

   1. Try here
      http://www.theoildrum.com/special/acronyms
      also
      http://en.wikipedia.org/wiki/List_of_oil_field_acronyms
      http://www.glossary.oilfield.slb.com/
      http://www.energyindustryphotos.com/oilfield_terms_and_slang_used_in.htm

      Lurk mode back on

3. Well presented analysis Dennis.

   I expect it’s off topic but the old grape vine tells me a number of conventional exploration/development plays have been deferred or cancelled outright owing to the North Dakota and Texas action. This seems logical; who really wants to drill a hole under kilometers of seawater anyway – especially if depletion rates are going to be in the 25% range?

   If deferred work was aimed at deep water, Alaska, or some God forsaken place such as off the Falkland Islands, for instance, some of these developments may never happen, economics given what they are. Perhaps someone has facts in this regard?

   To be honest I’ve been out-of-the-loop (apologies re all buzz words) for a long time now and I know it. However, if anyone has real information about current new-project allocation parameters this would contribute to the discussion.

   1. Different companies.

      The Exxons, Chevrons, Royal Dutch Shells and Totals do offshore work. Continental Resources are in the Bakken.

      This produces some bizarre reporting, btw. The majors are reporting declining production. Continental reports booming percentage gains, but it’s important to recognize they are growing from a low base. 50,000 bpd in a year following 25,000 bpd looks like 100%. Continental had total company production of about 70K boepd in 2011.

      In contrast Exxon has a goal of ADDING to already millions of boepd another 1.6 million boepd by 2016. Note Exxon bought XTO a few years ago and they are a natgas company so a big chunk of these barrels are not oil.

      But . . . the point is your question . . . the Bakken consumes resources mostly from companies that don’t do offshore work anyway.

4. Map: Water Competition for Shale Development in North America

   Go to the source to zoom in and get a clearer picture.

   

5. As I look at these curves I wonder if the limit on shale production will be non-geologic factors. For example, it appears that we have reached a bottleneck in distribution. Current LTO production is stealing transmission (rail and pipeline) from other things such as propane. Will we reach a transmission limit before we reach a geologic limit? Will railroads and pipeline companies build out more capacity given the lack of a long-term return on investment? If this turns out to be true, I think we could see a flattening and elongation of the production curve providing more sustained production over a longer period of time.

6. Posted by Jean Laherrere

   dear Ron
   Dennis wants to know what I think about USGS work
   I have studied the 2000 USGS report which is very good in delineating Petroleum Systems (thanks to IOCs in particular Exxon), but very poor in estimating undiscovered potential using only 6 values from only one geologist in their Seventh approximation sheet. From these 6 values they report a complete probability estimate through Monte Carlo simulations.
   see my comments on USGS past reports
   -Laherrère J.H. 2000 “Is the USGS 2000 assessment reliable ? “ Cyberconference by the World Energy Council, May 19, Strategic Options http://www.energyresource2000.com, or http://wwww.oilcrisis.com/laherrere/usgs2000/
   -Laherrère J.H. 2002 “Do the last 6 years production confirm the USGS forecast for the period 1996-2025?” http://www.hubbertpeak.com/laherrere/ConfUSGS_27_08.pdf
   -Laherrere J.H. 2012 « avis sur USGS Reserve growth » 22 Mai http://aspofrance.viabloga.com/files/JL_USGSreservegrowth2012.pdf
   Since 2000 USGS estimates the undiscovered resources but without assessing the past discoveries. They should estimate the ultimate reserves; adding the past production plus the remaining discovered mean reserves plus the undiscovered mean reserves

   Furthemore now they give the results but not the basis and the sources of their work (in contrary to the 2000 study where all the details were provided and in particular the seven approximation sheet.
   In 2000 study East Greenland was estimated at 47 Gb yet to discover was done without any seismic data and no well data: their mean estimate of 2000 is based because the minimum number of fields is taken as one when the 2007 study giving only 8.9 Gb with a minimum at zero; it was enough to change completely the Monte Carlo results

   on the last USGS 2013 Bakken study the mean value is 7.4 Gb for oil and 0.5 Gb for NGL.

   The USGS assessed technically recoverable continuous (unconventional) resources for six AUs defined in the Bakken and Three Forks Formations resulting in estimated means of 7,375 million barrels of oil (MMBO), 6,723 billion cubic feet of gas (BCFG), and 527 million barrels of natural gas liquids (MMBNGL) (table 2)

   Dennis wrote
   This conflicts with a recent (April 2013) USGS mean (F50) estimate of 8.4 Gb.
   F50 (or P50) is different from mean as it is shown in the table below
   Using P50 value is wrong because the decision of development is taken on the Net Present value based on mean values
   Most people do not realize that the arithmetic aggregation of field proved reserves does not represent the proved value of the countries or of the world, but a very underestimated value. All the reported world proved values by OGJ, EIA, BP are incorrect, being the sum of the countries!
   USGS F95 is not the arithmetic aggregation but a Monte Carlo result and it is different from the proved reserves defined as P90!

   I do not see a value of 8.4 Gb in the 2013 USGS study which does not estimate the ultimate but the yet to find

   I do not see a 6 Gb ultimate as being the minimum value

   In this 2013 study Bakken is described as a continuous type accumulation but also being economical only at sweet spots: it is a kind of contradiction.
   The big problem of shale oil or gas reserves estipate is that the volume of hydrocarbons generated by the soure-rock in the oil and gas kitchen is huge, but only a very small part (about 1%) is accumulated in conventionnal fields, the 99% is either lost to surface or still dispersed in the sediments or still left in the source-rock.
   Bakken production comes from a carbonate poor reservoir within the Bakken shale: the production does not come from the shales!

   I will trust USGS study whent they will estimate the ultimate using past discoveries, like I do using creaming curves and when they will publish the detail of their work.
   Past USGS forecasts of yet to find compared to present data do not present a good result!

   I remind that my forecast for a peak of North Dakota production in 2014 comes from two different approaches being the estimater of the ultimate from a Hubbert linearization of past production and also from a correlation with the shifted number of rigs (simiular with Montana), both approach being weak, but much better than the USGS estimate: there are based on known data graphs and not from estimates without any proof

   I agree with the comment on the slow decline. In the past Bakken peak productions in Montana and North Dakota the decline is as sharp as the rise (see in 1991 or 1960)

   http://aspofrance.viabloga.com/files/JL_Bakken2014.pdf

   best regards
   jean

7. Hi Mr Laherrere,

   I have read your work on the USGS 2000 Assessment, I had not read anything on the more recent Bakken estimate until now. Thank you.

   1. Dear Mr. Laherrere,

      You are correct that the 2013 Bakken/Three Forks Asssessment gives us the undiscovered technically recoverable resource(TRR). Could you correct any misunderstandings I may have?

      The total TRR is equal to the undiscovered TRR plus proven+probable reserves(2P)+ oil already produced. The USGS mean estimate for the North Dakota Bakken/Three Forks undiscovered TRR is 79% of the entire US Bakken/Three Forks or 5.85 Gb. To determine total TRR I estimate 2P=1P of about 2.1 Gb (from EIA North Dakota crude reserve change from 2007 to 2011), produced ND Bakken/Three Forks oil at year end 2011 was 350 million barrels (0.35 Gb). So the mean total TRR is 5.85+2.1+0.35=8.3 Gb. For F95, undiscovered TRR is 4.4*0.79=3.5 Gb, for F5 undiscovered TRR is 11.4*0.79=9 Gb to each of these 2.45 Gb needs to be added for total TRR so that F95=3.5+2.45=5.95 Gb (I rounded to 6 Gb) and F5=9+2.45=11.4 Gb.

      Note that the US proven reserve estimates are conservative so that 2011 2P Bakken/Three Forks reserves are likely somewhat higher than 2.1 Gb( I do not have access to a proper 2P reserve estimate but typically 2P>1P), the production data comes directly from the NDIC so we have a URR of at least 2.45 Gb, if there are no further discoveries after Dec 2011. Does it seem realistic that only 0.05 Gb of oil will be discovered when the USGS estimates that there is a 95 % probability that at least 3.5 Gb will be discovered in the North Dakota Bakken/Three Forks? I may be missing something very basic. I appreciate your patience.

8. In my opinion, looking at predictions versus results, the Hubbert Linearization (HL) method has been reasonably accurate in at least predicting major inflection points.

   Deffeyes, using HL, predicted that we would see a global Crude + Condensate (C+C) peak between 2004 and 2008, most likely in 2005. Following is a link to the 2002 to 2012 Global C+C Gap Chart:

   http://i1095.photobucket.com/albums/i475/westexas/Slide1_zpsddc49796.jpg

   Of course, my contribution to the Peak Oil debate has been in regard to net oil exports. In early 2006, based a HL analysis of the (2005) top three net oil exporters, I made the following statement:

   “As predicted by Hubbert Linearization, two of the three top net oil exporters are producing below their peak production level.   The third country, Saudi Arabia, is probably on the verge of a permanent and irreversible decline.   Both Russia and Saudi Arabia are probably going to show significant increases in consumption going forward.  It would seem from this case that these factors could interact this year produce to an unprecedented–and probably permanent–net oil export crisis.”

   Following is a link to the 2002 to 2012 Global Net Exports of oil (GNE*) gap chart:

   http://i1095.photobucket.com/albums/i475/westexas/Slide1_zps3161a25b.jpg

   I estimate that since 2005 we have already consumed about one-fifth of post-2005 Global CNE (Cumulative Net Exports).

   And then there is the “Chindia Factor,” as the supply of GNE available to importers other than China & India fell from 41 mbpd in 2005 to 35 mbpd in 2012.

   *Top 33 net oil exporters in 2005, total petroleum liquids + other liquids, EIA

   1. Incidentally, combined net oil exports* from the (2005) top three net oil exporters (Saudi Arabia, Russia, Norway) increased from 15.2 mbpd in 2002 to 18.6 mbpd in 2005, a rate of increase of 6.7%/year. At this rate of increase, they would have been at about 30 mbpd in 2012.

      Actual combined Top Three net exports in 2012 were 17.5 mbpd, a rate of decline of 0.9%/year, relative to 2005. The gap, between where they would have been at in 2012 at the 2002 to 2005 rate of increase in net exports and the actual 2012 value, is about 12.5 mbpd.

      *Total petroleum liquids + other liquids, EIA

      1. Jeffrey,

         Actually, I believe the Net Oil Exports will cause more havoc on the market as it pertains to price and supply & demand forces than overall Global Peak oil. Here is a chart I put together a year ago on Estimated Middle East Net Oil Exports.

         I utilized the data from BP Statistical Review 2013 Report, whereas I believe Jeff uses the EIA’s figures. Regardless, BP updated their 2011 figures and we can see that in 2012, Middle East Net Oil Exports declined:

         MIDDLE EAST FIGURES

         2011 Total Production = 27,988 kb a day
         2011 Total Consumption = 7,992 kb a day
         2011 Net Oil Exports = 19,996 kb a day

         2012 Total Production = 28,270 kb a day
         2012 Total Consumption = 8,354 kb a day
         2012 Net Oil Exports = 19,916 kb a day

         While the decline yoy is only 80 kb a day, it’s still a decline nonetheless. Even though Middle East production increased 282 kb a day in 2012 over 2011, consumption increased 362 kb a day.

         One of the most interesting trends in the chart is the steady increase of Middle East oil consumption. You will notice that even though oil exports declined substantially in the early 1980’s along with several dips during global recessions during the 2000 decade, oil consumption in the Middle East didn’t miss a lick — it just kept on increasing.

         If we assume a 1% annual decline rate of Middle East oil production (also used by Jeff in some of his Net Oil Export calculations) along with a similar rise in consumption, Net Oil Exports may fall 30% by 2024. I imagine the decline will be even greater, however the chart represents a conservative approach.

         steve

         

   2. WT,in 2005 there were 33 oil exporters . How many in 2013/2014 ? Who fell by the wayside ? The info would be appreciated .

      1. I used a 100,000 bpd cutoff as a definition of “Major” net oil exporter. In 2005, there were 33 countries that had net exports of 100,000 bpd or more, and they accounted for 99% of actual total global net exports.

         In 2012, 25 of the 33 still had net exports of 100,000 bpd or more. The other 8* had fallen below 100,000 bpd, and in a few cases, they had already slipped into net importer status. I believe that the only country that has been close to crossing the 100,000 bpd mark as a new major net exporter is Turkmenistan.

         In any case, here is a link to a chart showing the 2005 to 2012 rates of change in the ECI ratios for the (2005) Top 33 net exporters:

         http://i1095.photobucket.com/albums/i475/westexas/Slide1_zps5a656e89.jpg

         The ECI ratio is ratio of production to consumption. 26 of the (2005) Top 33 are trending toward, or have already arrived at, zero net oil exports, when the ECI ratio equals 1.0.

         *Argentina, Vietnam, Malaysia, Sudan, Denmark, Syria, Trinidad & Tobago, Yemen

         1. Jeffrey: Good morning. Most excellent analysis! I’m no mathematician nor statistician, nor anything else remarkable. However, I have sufficient common sense to have recognized the reality that would become, as you’ve shown here.

            I am curious if you have done, or if you might be aware of anyone else’s work on it, analysis of the impact of net exporters turning from export to import, specifically their effect on GNE (global net exports) still available at that time in the future? I presume that these countries’ entry into the competitive market for fuels will lead to first geometric, then exponentially rising prices, first as primary fuels, then as lesser substitutes when they are priced out of the market for primary (preferred or higher grade) fuels. We might presume that artificial price controls to somehow keep prices depressed might further erode any remaining reserves, leading to the Seneca Cliff referenced in the previous article’s comments (“EIA Quarterly Crude + Condensate Production Data,” Ron Patterson, January 31, 2014).

            1. What almost everyone (maybe 99.9999 . . . %) of the population, don’t understand is that we are, in my opinion, experiencing a sky high post-2005 Global CNE (Cumulative Net Exports) depletion rate.

               Consider the Six Country Case History*. Their production virtually stopped increasing in 1995. My premise is that 1995 is to the Six Country Case History as 2005 is to global data.

               Following are key Six Country 2002 data, relative to 1995 values:

               Six Country 2002 Values (as a percentage of 1995):

               Production: 93%
               ECI Ratio: 83%
               Net Exports: 65%
               Remaining CNE: 16%**

               1995 to 2002 Six Country Normalized Graph:
               http://i1095.photobucket.com/albums/i475/westexas/Slide1_zpsf0483ede.jpg

               *Six major net oil exporting countries that, since 1980, have hit or approached zero net oil exports, excluding China: Indonesia, UK, Egypt, Vietnam, Argentina, Malaysia (note that Vietnam, Argentina and Malaysia are also in the top 33 data base)

               **Estimated Post-1995 Six Country CNE, at the end of 2002, based on 1995 to 2002 rate of decline in the ECI Ratio, were 9 Gb; actual post-1995 CNE were 7.3 Gb

               Note that a 7% decline in production from 1995 to 2002 corresponded to an 84% decline in remaining Six Country post-1995 CNE, or a 1%/year production decline rate (1995 t0 2002) corresponded to a 26%/year post-1995 CNE depletion rate.

               Note that as Six Country production increased slightly from 1995 to 1999 (1999 production was 1.6% higher than 1995 production), post-1995 Six Country CNE fell by 53%.

               I estimate that from 2006 to 2012 inclusive, we burned through about one-fifth of Global post-2005 CNE. And of course, developing countries, led by China, were–at least through 2012–consuming an increasing share Global Net Exports of oil. At the 2005 to 2012 rate of decline in the ratio of Global Net Exports of oil to the Chindia region’s net imports, in only 16 years China and India alone would theoretically consume 100% of Global Net Exports of oil.

               The Cornucopians would argue that shale/tight plays will save the world. The key problem that I see is the probably low median production rate.

               The average Bakken production rate in the first half of 2013 was reportedly about 135 bpd (on the upslope of a the production profile). We don’t have a median production number, but I would think that it was probably around 60 to 70 bpd.

               I don’t see how median and average production rates like this will work in high cost areas like Siberia and the Middle East, especially when you consider that the Bakken is probably the best shale oil play in the US. Most other plays have been disappointing as far as commercial production goes, or they are far more gas prone.

            2. I should have said “contributing to the Seneca cliff,” rather than “leading to the Seneca cliff”.

               1. Meanwhile, back in reality for the 99.9999% no nothings, U.S. net imports of crude and product have declined by 6 million barrels per day since 2005.

                  http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=WTTNTUS2&f=4

               2. Yeah that’s a startling graph. But roughly half of that 6mbpd decrease is ‘demand destruction’ or ‘conservation’ not import replacement with domestic production. Yet the MSM much prefers the heroic story of muscular production revival and never mentions the drop in use.

                  We are also witnessing the magic of rationing by price altering behaviour. And altering it permanently.

9. USA TODAY:

   U.S. may be nearing oil independence

   http://usat.ly/1ngjl8Z

   Yea USA! USA! USA!

   AS IF! As if chanting it will make it come true.

10. First time poster, after having followed for a few years the great posts from others here, on TOD, and peakoil.
    I had some time recently, and was interested in doing a more detailed analysis of the North Dakota wells, as so much detailed info is available. Using the individual well reports from https://www.dmr.nd.gov/oilgas/mprindex.asp, I analyzed all the single wells in the reports since Jan 2008 until Nov 2013.

    Below you can see the average well performance of almost all wells in North Dakota, where I grouped them by the year of their first production. The first graph shows the cumulative production from the month of first production, per year when the well got started. The 2nd graph uses the same data to show the monthly output. I ignored gas production, and also ignored wells that had less than 1000 barrels of oil production in their first months. The cumulative oil produced from all these wells was 650 million barrels, and the average number of wells in each of the years : 411 (2008), 466 (2009), 661 (2010), 943 (2011), 1389(2012), 996 (2013). A small amount of wells was left out due to data garbage.

    Looking at the graphs, it is clear that the well performances have improved over the last years, but the progress seems to have stopped. It’s still impressive to see how quick the cumulative output rises, despite the huge declines, which allows these companies to quickly recoup their investments, at least so far. And using creative (sorry, standard) accounting, these companies write off the capital expenditures in 10 years or more, so profit looks even better.

    

    1. Enno Wrote:
       “And using creative (sorry, standard) accounting, these companies write off the capital expenditures in 10 years or more, so profit looks even better.”

       Can you elaborate on your last statement? In your opinion over the long term, is Bakken an unprofitable venture? I suspect that drillers may be using short term paper profits in order to get cheap loans. The company officers pocket their big salaries using paper profits and will eventually stiff the banks when they can no longer show profit as the maintenance and operating costs consume all their revenue. Would this assumption be inaccurate?

       1. First a disclaimer, I am not in the oil business, and am looking at this just with interest. My comment referred to the linear way of writing off capital expenditures over say 10 years, despite that I estimate that these wells produce half of their lifetime production within their first 2.5 years or so. I think accounting should be a conservative enterprise, and that clearly isn’t followed here.

          Is it/will it be profitable? I don’t understand their costs well enough to make that judgement. It was clear that a certain percentage of the wells in my analysis received some resurrections during their life, and I am not sure how expensive those operations were, or other maintenance on the wells. If those expenses are limited, then I think those current wells are indeed profitable. And indeed credit has been cheap lately, so that must have helped. Clear however is that all these companies have an increasing hangover of capex write-off building up that will hit their official profits, and that with oil below 70-75$ a barrel new wells are almost surely not profitable. They may get lucky if oil and gas prices keep trending higher and they have more options of getting the oil to their customers. I guess much more profitable are those companies supplying this boom. A bigger question, that Dennis tried to answer, is how many opportunities are there still left anyway.

          1. Fascinating analysis Enno. Until now I had assumed the idea that ‘sweet spots were drilled first’ was a correct one (in the sense that the most productive wells would go in first – say in 2009/2010). This assumption seems to have been undermined by your work which seems to indicate that well ‘efficiency’ was still increasing – at least until 2012/2013. That is not to say that the sweet spot analogy is flawed, just deferred – it seems that as of now (rather than say 2010) maximum well efficiency (or ‘sweetness’, chuckle) has indeed been reached. Unless of course on-going improvements in drilling technology can wring a little bit more out of fracking efficiency. Otherwise one might expect plots for 2014/15 wells etc to start to quickly fall below levels seen for the 2012/13 wells.

             1. Also I note from your second graph that wells drilled more recently (ie 20130 have considerably higher initial monthly production totals (almost twice that of wells drilled 5 years ago), but that their decline rates in the first few years are much greater. Fascinating.

                1. The higher initial output should help the economics of these wells considerably. The higher declines afterwards already caused the daily output of the 2013 wells to dip below the level of the 2011 wells during the same age.

                2. Why do the newer wells have higher initial production than old wells? Better fracking technique? This would then be consistent with the sweet spots getting drilled first. This may have already been answered, sorry if it has.

                3. Fracking at all doesn’t go back much more than 4-5 yrs on those wells, and if it did it would be only a few stages.

                4. Null Hypothesis and Andy,

                   Watcher is correct. The number of fracking stages has increased over time. This has made the newer wells more productive (higher EUR). Judging from Enno’s excellent data, over the period from 2007 to 2010 this process of finding the best number of fracking stages, length of laterals and types of proppant to use caused the average new well EUR to increase (a shift away from the horizontal axis of the cumulative output curve.) From 2010 to 2013 there was very little change in these cumulative output curves (up a little in 2011 down a little in 2012 and up a little in 2013). This suggests that this “improvement in technique” was largely finished by 2010. At some point soon the sweet spots will run out of room and EUR will decrease, we will only be able to see this about 12 months after it has occurred. My guess is that is may be beginning now and we will see this when we look at the results from 2014 wells in Feb 2015. It is however simply a WAG, I have no data suggesting such a decrease in new well EUR has begun. As Verwimp points out, my assumption that the shape of the well profile will not change may also be incorrect. If the shape changes so that the output declines more rapidly, then my scenarios may prove optimistic. I think it unlikely that ND Bakken output will be any lower than an ERR of 5 Gb, if the economy crashes and oil prices crash as well, I may be incorrect.

    2. Great work, Enno!
       @Dennis Coyne: This is exactly what I meant. The later curves are steeper in the beginning, but the 2012 and 2013 curves are already crossing the earlier curve(s). My statement “EUR decrease is not only a shift downward, it’s also a shift leftward. It’s a rescaling of the curve resulting in a sharper ‘corner’.” was a bit short. It should have been “EUR decrease indeed a shift downward, but it comes with a shift leftward. All together there is a rescaling of the curve resulting in a sharper ‘corner’.”

       1. Well, wait a minute.

          This continues to be really detailed tech analysis with entirely static presumptions.

          Fracking stage count is increasing. Well distances (between wells) is decreasing. Use of the multi well pads is becoming more common. And there is even talk of refracking, to say nothing of increasing depth to the Three Forks structures where most of the historical data is more shallow and different geology.

          It’s all just not a valid measurement or basis for prediction in general. Way too many things are being ignored. There would need to be a presumed increase in skill/technique built into the profiles, and who knows what that would be? Well, I don’t, but I know it’s not zero.

          A guy on ZH said something recently that caught my attention. Drill rig count is tracked but truck total is not. It may be a more powerful determinant to a lot of things than others. Truck count. Speed limit on the roads. Truck capacity. Maybe all more worthy of analysis than dollars.

          1. Exactly. This is why the Hubbert Linearization (HL)is so valuable. There is no need to keep track of production methodology, prices or anything but production. As the years go by and cumulative production increases it gets more and more accurate.

             The only real question is whether Laherrere’s derivation of URR from HL is premature. I think another year or two will confirm whether the slope defined by (P/QP,QP) points terminates at 2.5 billion barrels or not. Production per year would have to rise dramatically to significantly change the HL slope.

             1. I am skeptical of how realistic HL will be here and I appreciate Dennis Coyne’s pointing out that economic factors could throw the whole analysis off. I argue that the artificially low interest rates over the last 5 years or so, and the Wall Street ponzi schemes associated with it, have created an environment that has made tight oil production “profitable” (at least over the time frame the ponzi architects pay attention to) at oil prices that are too low. In a normal interest rate environment, this oil shouldn’t be profitable until, say, something closer to $200 for the sake of a number.

                This has drained America of much of its remaining oil supplies. And the financial ponzi scheme will end in the not too distant future with a blow-up of the dollar, I would say for sure within 2 years, so the economic factors affecting the HL curve could quite dramatically alter it from bell shaped. Basically, the oil that should become available at $200 in a normal interest rate environment won’t be there; it’s mostly already been pumped out at $100 over the last 5 years. So we could see a sharp drop in oil production in America after the financial system collapses, even with high oil prices, simply because credit will no longer be available to fund the next great oil ponzi scheme.

                Future oil production has been artificially brought back in time to the present to feed the machine, and America’s future is being robbed.

    3. Enno,

       That data is great! Thank you, any chance of sharing it? (In an excel file). If I am interpreting your charts correctly it looks like there has been very little change since 2010. I may have things relatively close because I used Rune Likvern’s data from 2011 wells as the basis for my well profile and may have overestimated output from 2008 and 2009 wells, based on your data.

       So my comments that the average new well has not changed much since 2008 is clearly wrong, but it looks like it may be close to correct for wells from 2010 to 2013 (there has been a little change but not much). In fact it looks like the 2012 wells track the 2010 wells and the 2013 wells track the 2011 wells with 2010 and 2012 less productive than 2011 and 2013. The shapes of these curves seem pretty similar to my eye. Have you tried to match them to an arps hyperbolic?

       1. Sure Dennis, just drop me an email and I’ll share it with you. I guess you or Ron should have access to my email info.

          I didn’t do any matching myself. I expect that all these profiles will end up looking all similar, but somewhat different. The profiles seem clear enough to make a reasonable estimate.

          1. Enno, I would really like to work on that data as well. If you are willing to share it, please send it to bruno underscore verwimp at hotmail dot com. Thanks!

11. I am about as far from being an expert on the oil industry as the east is from the west but I can claim to be a well informed layman due to having been a religious regular at TOD for the last four years it was active and after that following this site and a couple of others.

    Dennis is certainly right about the enormous uncertainties involved it estimating oil reserves; nobody with any real credibility can dispute him on this point.

    I don’t know enough to comment constructively on reserves but I do have something to say about the level to which the real price of oil may rise at some future time, and it’s obvious that price sets one of several upper limits on the price of oil, just as the cost of drilling and the availability of water set limits .

    Most people,or at least a lot of people these days , think real oil prices cannot go above some arbitrary limit, usually in the neighborhood of one hundred fifty dollars give or take ten bucks or so.

    They may very well be right because a higher price may cut so far into demand that only oil that is cheaper can be brought to market.This is a very powerful argument and I do not dispute that it will hold good for quite some time, perhaps even for a couple of decades.

    But a lot can happen and will happen over the next twenty years in both the efficiency and conservation arenas . The share of transportation energy contributed by oil will probably shrink dramatically for a number of reasons over this time span.

    For one , battery electric vehicles are going to grab a huge share of the auto and very light truck markets.
    I have been watching the emergence of new technologies for half a century and the way people adapt to them and it’s a cinch that the big battery industry is still in it’s infancy and that battery prices will continue to come down even as their capacity and durability continue to go up.

    If BEV’s don’t rule the road within the next two decades hybrids will simply because electricity is going the remain substantially cheaper than gasoline and the cost per mile driven advantage of owning a hybrid is going to grow every year from here on out. Of course it will be a few more years until pure electrics and hybrids are fully competitive on a cost basis but that time is surely coming.

    Hardly anybody realizes it just yet —-other than armchair futurists and old gear heads such as yours truly—- but hybrids are going in most cases to outlast a conventional car by a factor of two or more. This is because the engine is used only on longer drives and doesn’t even fire up on short trips- and it’s short trips that are the murderers of engines. There ain’t no stinking transmission. A Chevy Volt with a ”worn out ” battery that will propel the car only fifteen or twenty miles will still save the owner a substantial amount of cash especially if he lives relatively close to his job and the stores where he usually shops.His car might have the functional equivalent of only forty thousand miles on the engine when the odometer reaches four or five times that figure fifteen years from now.

    It is another cinch that people will get used to driving short range cars as the cost of gasoline goes up and disposable incomes go down. Any body who doubts this should stop a minute and contemplate just how quietly ten million or more young adults have moved back in with their parents and how many more have continued to double up roommate style rather than getting places of their own after finishing school.

    Railroads will be electrified; they don’t have to answer to any body when they decide to do so because their legal rights to manage their right of ways as they see fit are set in concrete and have been just about since day one.

    Long distance trucking is a dead man walking business; the trailers are going to be hauled on trains. Intermodal is the future of long distance freight.Truckers will pull the trailers the last couple of hundred miles.

    If natural gas stays significantly cheaper than oil a considerable number of heavy trucks will be built new to run on it and a lot of old ones will be converted because the cost savings are irresistible.

    NG refueling stations need not be built everywhere because most big trucks aren’t driven by cowboys consumed with wanderlust. They stick pretty close to the interstates if they do go a long way from home and just one station every three hundred miles on say I95 would be enough to meet the needs of many tens of thousands of trucks that travel more or less incessantly up and down that route.Ditto I81 and many other routes.I mention these two because I drive both of them and know something of where the trucks using them are bound as a matter of local interest.

    There’s plenty of space available on lots of large trucks to mount cng fuel tanks since the total weight of the truck determines how much cargo can be loaded and many types of cargo are so heavy that a quarter or even half of the space available cannot be used.

    And last but not least millions of trucks return to home base every night and can be refueled there for the next day’s use.

    A lot of farm tractors were built in times gone past to run on lpg because farmers in grain country could buy it cheaper than gasoline or diesel and because they use it in large quantities to dry grain any way– they have the infrastructure already in place and even on a ten thousand acre farm a tractor is seldom more than a fifteen minute drive from the maintenance shop and the fuel tanks.Big time farmers will go to lpg again if it stays cheaper than diesel.

    Some will laugh but there is nothing to stop ocean going ships from being built again to run on coal or maybe LNG depending on the relative prices of these fuels.

    Ships are larger than ever and as they get bigger they need proportionately smaller engines. There is a joke in the industry that goes to the effect that in another generation they will just hang a couple of outboards off the stern.

    Coal can be powdered and blown thru pipes for a couple of miles at least and getting it aboard a ship won’t be an insurmountable problem.I’m not predicting that this will come to pass but there’s nothing to prevent it if the price of bunker oil exceeds the price of coal by a wide enough margin.Older smaller ships will be operated at lower speeds to help offset higher fuel costs. New smaller ships may be optimized for lower more economical cruising speeds.

    Now my point is that as oil becomes ever more expensive it’s marginal utility will increase as the number of people using it in quantity shrinks . The folks who continue to use oil will be able to pay more in real money because they will get more utility out of a gallon and or because they will be able to pass along the cost of it.

    A railroad will not be able to electrify all its track except over a period of a decade or more.Some trains must continue to run on diesel, and given the cost of a new locomotive it will be economical to keep running old diesels until they are worn out—especially on routes that are not real busy. It won’t matter much if that diesel is fifteen bucks a gallon, it will still be the cheapest option until the route can be electrified.

    Likewise the Volt owner will be able to pay ten bucks a gallon for a tank of gas easier than I can pay four dollars to fuel up our old Buick because his tank will take him three or four times as far even after allowing for the cost of recharging his battery.

    I’m an orchardist -used to be any way– and never used much diesel compared to a farmer growing field crops but we never the less cut our use of diesel by a at least a quarter per bushel over the last couple of decades.

    My neighbors who used to plow and disc and then plant and cultivate now use less than a third as much fuel to get a crop of corn ready for the combine by means of herbicides and sod planting.

    The upshot of this long ramble is that I think that a decade or two down the road that the economy will be able to support an oil price in real money that is substantially higher than expected.

    How much higher I don’t know of course but I will venture a guess that in twenty years that oil will be selling for two hundred dollars a barrel in terms of present day money, and that the economy of the US and Canada and few other countries will have successfully adapted to this price .

    The rest of the world is probably anther story and a very sad one.

    If anybody is interested I posted a qualitative cost benefit argument as to why sewage may eventually be piped out of cities and to farming areas last night under the last previous article.

    The short version is that we may be compelled to do so no matter the expense due to the exhaustion of P and K resources and the rising cost of manufactured nitrates.

    Without NPK we’re toast.

    1. OFM –

       Your rambles are always interesting. They bring to mind Memmel of TOD’s earlier days (before you showed up?) but with much more clarity & coherence.

       As regards NPK, I agree with you completely, and just wanted to make note for folks who may not be familiar, that Joe Jenkins’ http://humanurehandbook.com/ is not only very informative in this regard, but one of the more entertaining books I’ve read.

       1. I just read that tonight! (the 10 pager).Very informative. Makes me want to rip up my mom’s septic tank and put in a composter.

          But, I digress from oil talk…

    2. Hi OFM,

       Also in that discussion I mentioned the possibility that the sewage could conceivably be piped to a fertilizer manufacturing facility that transforms this precious resource (human manure) into a critical input for agriculture. When natural gas gets very expensive due to scarcity this seems a likely path forward. I agree that without some solution to the fertilizer problem a lot of people will starve.

12. i’m just trying to make sense of it… and it does make sense, all of it, if you make certain assumptions about the quality of our imperial leadership…

    …i mean, going clear back to when the brits discovered oil in iran in 1908 and were deciding whether or not to switch from coal to oil to fuel their imperial enforcement machinery –aka the royal navy

    a lot has happened since then, but patterns are emerging… and i’m mortified that it’s taken me so long to figure this stuff out… stuff that’s most likely been common knowledge to a certain class of people forever

    .
    the basic premise, now, is preserving the empire for as long as possible… the fracking and tar sands and ultra-deep projects are symptoms of peak oil, and there’s serious doubt that the empire will survive peak oil…

    with a view towards preserving the empire, we’ve got to recover control of russian energy and restrict chinese access to energy

    those who’ve given up hope of preserving the empire long term still need to preserve the empire for as long as possible in order to prolong their opportunities to loot

13. Actually they may be preserving their very lives if you want to think in terms of empire.

    At any rate there really is a strong link between oil and empire and here is a link to a very good article explaining how it initially came about.Churchill didn’t figure out the calculus of oil versus coal himself but he does deserve the bulk of the credit for the Admiralty decision to switch.

    Just about anybody can understand why oil is such a superior fuel for a warship in ten minutes study of the linked ( below) article but not one man in a million has the leadership ability to force a bureaucracy such as the Royal Navy to change it’s ways.

    http://www.epmag.com/archives/digitalOilField/5911.htm

    1. Old Farmer Mac wrote:
       “If BEV’s don’t rule the road within the next two decades hybrids will simply because electricity is going the remain substantially cheaper than gasoline and the cost per mile driven advantage of owning a hybrid is going to grow every year from here on out”

       Electricity prices will be substantially higher than they are today. Power companies are reluctant to invest in clean energy because the subsidies are ending or being scaled back and they are reluctant to replace existing coal fired plants with NatGas since they expect prices for NatGas to rise substantially. Nuclear power expansion is dead (Fukashima) and there will be plant closures as the operating and maintenance costs become too expensive. For BEV’s to become a major player there would need to be a major investment in the trillions to upgrade the grid. I don’t see it happening.

       In my opinion, BEVs and hybrids will loose market share to much cheaper gasoline\diesel with substantially smaller engines. Hybrid and BEVs will be probably disappear except for the high end luxury market. Cars such as the Chevy Sprint (1986) that got about the same milage as today’s hybrids. Since Engine technology has improved since the 1980’s newer designs would out perform hybrid. Hybrids have significant conversion losses by converting mechanical energy of an engine into electricity and there are also losses storing electricity into the batteries. Hybrid and BEV only make sense if electricity remains cheap, and I don’t see that happening. FWIW: BEVs are really coal fired vehicles since the US still gets nearly half of its electricity from coal plants.

       A car using just small ICE engine would be signficantly lighter than a BEV or hybrid. Since these cars would not need lots of expensive electrical hardware it would be considerable cheaper to manufacture and maintain. As the cost of energy rises and wages stagnate, the majority of people will look for the lowest cost options. its unlikely that costs for hybrids, BEVs can completed with small ICE engine vehicles. I think we will start to see some high mpg low cost vehicles come to market in the next two to three years.

       Old Farmer Mac wrote:
       “The odds of such a leader emerging in any given country at any given time are remote , but if such a thing were to come to pass in let us say Germany a decade from now”

       I think the odds of batch of mad men leaders is very high, as the world slowly creates the same issues that catapulted extremists into power. Economically, the world is broke and deeply in debt. The origins of Hitler, Stalin, ToJo, etc started when the people were jobless and began starving because the great powers were also broke and deeply in debt.
       Countries around the world are consolidating control into strong centralized gov’ts that make it extremely easy for a mad man to seize total control. We see increasing radical leaders being elected in the West that make promises that can’t possibly be meet. Its just a matter of time before it begins again.

       Old Farmer Mac wrote:
       “Germany a decade from now, and that Germany were to be suffering miserably from high fossil fuel prices and spotty deliveries and the Germans”

       Its not Germany thats the problem, its France, Russia, the United States, China are the most likely to put another megalomaniac in power. Other nations such as the UK, Italy, Japan, etc may revert into a dictatorship too, but they lack the capability to start WW3. its possible that Japan and China could go to war, or Israel and Iran that triggers WW3, but the global destruction will occur between the major powers. Japan, Israel, Iran simply lack the miltary infrastructure to carry out a major miltary compaign.

       1. I think electricity will go up in price a lot slower than liquid fuels will (due to the large remaining coal reserves) so BEV’s will always have the lower energy cost advantage. If battery costs can be brought down then they could remain competitive overall.

          1. “I think electricity will go up in price a lot slower than liquid fuels will (due to the large remaining coal reserves”

             The EPA is forcing coal plants to be phased out. Only Hydro, Nuclear, Wind\Solar, and NatGas will be permitted, unless congress acts to block the EPA. There is a lawsuit going to the Supreme court this summer, but I doubt they will overturn the EPA.

    2. OFM, great link, concise summary of a story I already knew. Worth a look, especially the conclusion.

       And on your other points. I agree if you are saying that oil rationing will occur by price, and that this will cause profound changes in its use. Chief among these will no only be the use of much more economical vehicles but simply much less driving. Both of these trends are already observable. And we will adapt through every means possible: BEVs, hybrids, but I agree with Tech below especially much smaller much less thirsty ICE vehicle. Also, depending on local circumstances, LPG and CNG vehicles. But more than anything there just simply be much less driving.

       Next change my household will almost certainly be going from two ICE cars to one smaller ICE. I thought a few years ago my next vehicle would be a BEV (not coal powered here), but it’s clear now that the math doesn’t stack up because of the capital cost. So unless that changes significantly more efficient smaller ICE looks like it hold its advantage, even at considerably higher oil prices. How? Because we are just using our existing cars less. We have become a four bicycle family (used for transport not sport) and a Transit using one. Using the cars only when necessary; when they are significantly advantageous, and it has been a really interesting discovery to find how how much of their use was out of habit. What people now feel is a necessity will change with the cost of its inputs.

       We can do this because we live in an relatively dense neighbourhood, although still suburban, with good proximity to important centres and Transit services. Both cycling amenity and Transit services are improving, as they are in most US metros, making this change possible. My guess is that the OECD nations can drop their consumption of oil really significantly simply because we currently waste so much now.

       North America and Australasia are the champions of this waste. It will be painful, there is so much sunk cost in the old now obsolete spatial order and most people are not early adopters like me. People mostly only change habits when forced. Price is what is forcing this change. And it is happening already.

       Consider the evidence offered by real estate markets. There have always been three critical aspects of residential property that determine value: location, scale (space), and building quality. In the sprawl age, the era of cheap oil, space was the master amenity as cheap and convenient personal travel by car made proximity less important, in fact location came, for pretty much the first time in history for the majority, to value isolation over proximity. Thus the invention of auto-dependent suburbia and the decline of inner cities.

       This value has already reversed. Proximity has reasserted itself as the vital definer of location, so now inner cities are reviving and gentrifying and pricing up, the poor are being pushed out to the ‘burbs. Poverty is increasingly suburban. And the reason this is happening is because driving is becoming unaffordable.

       See Alan Erenhalt’s The Great Inversion for the facts on this spatial change, and David Owen’s Green Metropolis on why urban centres can function well with much less oil input than suburban, ex urban, and country places.

       This post is getting too long, so in short I see the US functioning well, but much differently, on around half the 20mmbpd oil it was just recently. Just how long that will take to change shape and habits to fit this new reality and how painful it will be I can’t answer. But the beginnings of this change are already underway, tho it will take the next crisis before there is any possibility that it can be pursued consciously, especially by governments at all levels. Although smart cities are doing so now, and because price is forcing them.

       One thing that must change: that huge road building subsidy needs be shifted into Transit and Active modes. Like here the US gov is still building the infrastructure of the last age….

       And the timing and shape of the shale decline will be critical so thanks to Ron, Dennis, Jean, and you all for this great site.

       1. Patrick,

          Yes, we in US do use energy wastefully. But that waste is mostly built into the system at this point. It’s the point that James Howard Kunstler has made over and over — suburbia is a way of life with no future. You can’t take those dispersed suburban developments and move them closer to an urban center. For instance, driving ten miles from where I shop is wasteful, except that I have to shop and I happen to live ten miles away, so what choice do I now have?

          Yes, I could move to another home closer to transit and shopping, but then someone else would buy my house and be in the same situation. I could buy a more fuel efficient car, but then I would have to sell my current car to someone else. And while it’s true that car inventories turn over every 15 years or so, housing inventory never really turns over except by abandonment.

          Don’t get me wrong — people could save on energy more than they do now, but only marginally so. For the past 100 years we have built a society based on cheap energy and all that investment will be with us for as long as any of us can imagine. So what happens? Pretty much what may others have predicted — existing homes close to transit and shopping and jobs will become more valued and homes on the opposite end of the spectrum will decline in value. But we must all remember that once in decline, oil production declines forever. So even these “transition” effects will eventually be overwhelmed by the lack of energy resources. Then what?

          1. Calhoun,

             You have presented a succinct and accurate description of American reality where, owing to efforts initiated by Henry Ford, social order has been largely designed around the automobile. This same scheme is being emulated in much of China I might add. As one of the first steps in their modernization program the Chinese decided to build a freeway system “better that the one existing in the US”.

             Doug

             1. And Doug; yes and no. The Chinese have built an interstate system, they have also built the world’s best high speed rail network and it has radically transformed the experience of distance in that enormous country. Cheaper and better than flying. City centre to city centre. But the critical difference between China and the west is the urban density. Thankfully; because if those 1.3 billion were trying to live at the dispersal rates that we do in the west it would all be over for all of us already.

                Their challenge now is to shift electricity generation away from coal; they have been selling their own environment for economic uplift, and now have to correct this, not going to be easy. But they do have the advantage of a command economy, kind like the US had during the second world war; it can be very efficient and hold onto longer term goals. We will see.

                Also I think likely that their increase in oil use will flatten sharply at the next re-pricing. We all have our limits.

                1. Patrick,

                   Yes and no to you too. I spent about seven years in mainland China, on and off. My first trip took me to Yunnan Province near the border with Vietnam which is a pretty out-of-the-way area. We traveled on an amazing divided highway with majestic sweeping bridges crossing deep canyons – all brand new. There were virtually no other cars on the road. Seven years later, only seven, I had to return to the same region and there were traffic jams on this formerly deserted highway. So yes, I’m well aware of all the mass transit and subway construction activity, BUT everyone wants a car! The rich are probably the main buyers of Mercedes in the world — it’s a matter of power and prestige. So, don’t give China credit for environmental issues, at least not yet. I could go on and on and on about this.

                   Doug

                2. Doug, that is AMAZING. What a great illustration of the growth China has experienced. Does anyone see a brick wall ahead?

                3. Fascinating Doug, isn’t everything just on an extraordinary scale in China. Yup you’re right, but they will be priced right out of those cars again, as we will. When, and at what price, how suddenly, and how many of them are the only questions.

                   My guess is there like in the west this will not be over night, nor linear, synchronous, nor equitable. But also, importantly, not completely. In other words there will still be driving, and it will be more efficient without the lower value journeys in their way.

                   But my point is Shanghai for example that I visited a couple of months ago is going to be able to deal with this a lot better than Atlanta say. Because they have not only built driving infrastructure. Amazing subway; from nothing to the biggest in the world in just 15 years. The US is still rich, but China’ built environment looks more resilient to oil shocks.

          2. But it isn’t a matter of choice, it is happening. Ex-urban properties were the ones to sink underwater in the sub prime crisis, and more will sink further at the next one; there will be no one buying properties on the edge and they will go back to the desert. I know there is a huge sunk cost in an unsustainable spatial order, we have it here too. And I agree with Kunstler; the only issue is how fast, how painfully. It has to be said that his wonderfully written and dramatic predictions have been frustrated to date, but are already observably happening in an incremental way.

             You are not responsible for changing everyone or everything; by rationally changing your own situation you are changing the world. Looking around and deciding the scale of what’s required is impossible is simply a way to make it so.

             So how long do we have on the plateau? Is it another decade, because we’ve nearly had ten years, which has certainly surprised me and many others?

             1. Patrick,

                I’m picking this up from above because the column is thinning out.

                There’s not much we don’t agree on. Your perspective is colored, perhaps, by living in virtual paradise, mine by having spent a lot of time in third world countries, for sure. Fair enough. Also, I’m extremely concerned by global warming which, with positive feed backs, etc. probably dooms our kids and almost certainly our grandchildren.

                However, Ron’s blog is primarily about Peak Oil so maybe we should be focusing on different stuff. Jeff Brown is trying to teach us about depletion which is next on my list of imminent catastrophes; a good path to follow because there is real data out there.

                Of course I don’t have a bloody clue how things will play out but Ron is apt to cut us off soon, and rightly so, if we keep babbling about off topic issues. So, I’ve had my say.

                1. If Ron indulges me…Doug: Yes I think in fact we are agreeing furiously, and I thank you for your patience. And I take your point about my circumstances colouring my relative optimism. I have been to enough other places to keep coming home. And yes I can name a bunch that are certainly in overshoot and will only be have a whole lot of hurt in the coming years. Cairo, for example.

                   I also agree that climate change is of a whole different order as a crisis. And, frankly, it is both so vast and so unknowable that I don’t even try to comment on it. I’m just watching. And since when did observable phenomena become subject to the language of belief?

                   best wishes from an previously temperate but increasingly tropical Auckland.

             2. Doug and Patrick and Old Farmer Mac and everyone else.

                I am speaking for myself, (but Ron can chime in if he disagrees)but
                pretty much any topic related to peak oil is fine with me, I find the comments by Old Farmer Mac and the conversations between Doug and Patrick very interesting and pretty much on topic.
                Even though the focus of this blog is peak oil, I think talking about climate change, ecology and sustainability, and many other topics as well are fine. So unless Ron says differently discuss any topic that interests you.

       2. Patrick Wrote:
          “This value has already reversed. Proximity has reasserted itself as the vital definer of location, so now inner cities are reviving and gentrifying and pricing up, the poor are being pushed out to the ‘burbs. Poverty is increasingly suburban. And the reason this is happening is because driving is becoming unaffordable.”

          To a large extent, driving hasn’t become unafforable yet. Poverty is rising because the economy stinks (to put it mildly). People are losing there jobs as companies outsource or leverage technology to automate their jobs. There have been major changes in the past 15 years with have dramatically changed the business provide services and goods. For instance Brick and mortar retail has shifted to the Web. Radioshack is closing 500 stores, and Sears, JCPenny and others are also closing dozens of stores too. Virtually all manufacturing is now 90% or more automated. Assembly lines that employed hundreds if not thousands of workers is done by less than a dozen. These trends are not going to reverse but will continue on their current course. The only way to avoid poverty is to adapt to the changing economy and developed the skills that are in demand, or you can become self reliant so you do not depend on the economy to meet your living standards.

          Patrick Wrote:
          ” Thus the invention of auto-dependent suburbia and the decline of inner cities.”

          I think you are suggesting that the population will shift out of the suburbs and into the inner cities. I am not sure that is going to be correct. Most metropolitan cities are very expensive to live in. As jobs disappear it will become very difficult for many to live there. In my opinion, most cities will become very unpleasant. Crime, violence, disease and drug abuse will soar as the economy continues its downward spiral. As more people crowd into the cities there will more and more people chasing the same jobs, further causing higher unemployment. I think people living in the suburbs will likely remain there because they will not be able to afford to relocate into a city. I think the economy will suffer greatly before driving becomes unaffordable, and it won’t matter where you live because there won’t be any jobs in the cities or the burbs.

          Cars were only a small part of the reason why suburbia grew at the expense of cities. Even during the 1950’s Cities became expensive to live in and crime was significant. People left the cities because the quality of life was better. Also during the growth of the suburbia in the 1950 and even into the 1960’s Public transportation was readily available. People could walk or drive to train and bus stations in the suburbs to commute to their jobs in the city. It wasn’t until companies started moving jobs out of the cities (also escape costs and crime) that resulted in the dramatic expansion of people commuting by car. Once business moved jobs out of the cities and out of the reach of public transportation it forced people to use cars to commute. Today there are no industrial jobs or factories in major cities. Its too expensive to purchase the land and getting large volumes or resources need is very expensive. From my observations its appears that factories are relocating further away from cities to rural regions because of costs and regulations. I don’t believe we will see any resurgence of jobs returning to major cities. Either companies will continue to move manufacturing in rural regions or it will be outsourced overseas.

          As far as paper pusher jobs, these will largely disappear as software automation takes over. Technology and machine automation eliminated millions of factory jobs over the past 25 years. Software automation will repeat this for office jobs. The only people working in the skyscrapers will be the programmers developing better software automation to further eliminate office worker jobs.

          “. We have become a four bicycle family (used for transport not sport)”

          Consider that food calories are a heck of lot more expensive than fuel. Part of reason why we had the green revolution is because human and animal labor was replaced with machines which did not need to consume the large amount of food calories required to grow and harvest crops. If you live in the Suburbs or a city then all your food is brought in from thousands of miles. The amount of energy consumed using food will be a lot higher than using your car for transportation. Cycling is fine for exercise, but it does not save the planet or save energy. I would also discourage you from riding your bicycle on urban streets as your risks for getting seriously injured are high because of road traffic. All it takes is one careless driver, on a smartphone, to ruin your life or even end your life. Just yesterday, I read a story about a boy who was on his way to a store, riding on the sidewalk was killed when a stoned driver in a pick up truck, jumped the curve, and plowed into him killing him.

          My plan is to relocate to a rural region which is where the food and resources are. I can purchase 100+ acres at the fraction of a cost of a tiny Manhattan apartment and use that land to grow most if not all of my food. I will also have access to abundant energy resources (solar, wind and biomass fuels) that are inaccessible in suburbia or in cities. I will also be distant from the cities which will be become unsafe and unpleasant in the not so distant future.

          I think relocating into a city will lock you in a system which will be very difficult to escape. Once your are in a city you are at the mercy of future events and the resources you need to survive (food, water, energy) all must be imported from great distances. Should there be a failure of any delivery system, you will be placed in great danger as you have no recourse to available.

          1. I am not suggesting that people will only surge into existing inner cities but rather there will be a number of congruent changes, the beginnings of which are all observable now.

             1. Unfixable highly auto-dependant places will lose value and population.
             2. Many currently more dispersed places will intensify; ie will develop their own more walkable more intense cores: Sprawl repair. Where these places can conveniently be linked up with other centres and especially the centre of a big metro with a transit line, they will probably flourish.
             3. Already walkable, bikeable, more transit rich metros will thrive and double down on these attributes, but will suffer from dwelling cost pressures [see NYC, SF, Portland, Vancouver].
             4. At City level there will be power struggles between suburban power bases and inner city ones over investment [see Toronto].
             5. At nation level there will be power struggles between urban and ex-urban power bases [see everywhere]
             6. Rural areas will continue to lose population.
             7. Old industrial centres of the US will continue to lose population but will also change shape and densify and some will rebound at a lower population level, although will have the problem of the wrong infrastructure.
             8. More and more highways will be abandoned, or at least no longer maintained [not all of course], simply because they are the wrong fit for the age. [eg see Akron, Ohio, now]

             And some will move to the country in the hope of achieving autarky. Self-sufficiency. The good life! A timeless ideal. This will be hard, but some are doing it already and some will achieve it well. The most successful will have their own energy sources and either be really placed for connection to urban centres or have a really good system for powering not only their production but means of delivery and exchange. And they will either like isolation or be part of a community. These people will flourish too. But there just can’t be that many, physically impossible, and few have the skills anyway.

             I know many think this last way is the only real way to thrive in an energy constrained future but it isn’t working out that way. Autarky is hard, and we are social animals.

             It’s the in between that’s stuffed. If you have to drive to do everything- to get to work, to shop, to play, kids to school, to socialise, you are in a spatial order that will at the very least lose value as this decade unfolds. Simply because transport costs and dwelling + living costs are two sides of the same coin. Highly dispersed social orders are a direct function of cheap oil. Past their use by date. A limited moment in history. We spread out, and we’re bunching up again.

             And I have to correct you about suburbia. Yes it was first invented by the train and the tram, but train and tram built dormitory suburbs, although they can be distant from their economic base, still have to be compact and walkable. Built tightly around those stations which also became the commercial and social centres of these communities. It was the car that made the suburban world we all see around us now. The network of separated curving cul-de-sacs and the distant mall in its sea of asphalt. These places have everything dispersed at distances that are punishing and inefficient without the cheap and easy infrastructure of the automobile, particularly shopping and meeting others, but actually everything, especially the maintenance of its own lavish infrastructure. And the fate of this suburbia, auto-dependant suburbia, lies completely with the car. If driving stops; these places will be abandoned, unless they can be retrofitted for the next movement technology. Simple as that.

             Maybe that’s still a car, maybe that’s EVs, maybe that’s possible? Maybe there’ll be some crazy lightweight powerful battery [no sign of it yet] and maybe electricity will be too cheap meter [ditto]. More likely we are going to still rely on ICE machines for really important work [for the decades that those FF last] and otherwise mix it up with every other option: Much more walking, cycling, skyping, small EVs, like scooters and light cars, much much more Transit, return of the streetcar, the train, the trolly bus. And, a transformed spatial fix. And this is already happening, living in smaller dwellings, closer together. A fair bit of this is back to the future, but with much more electricity powered things. So closer now will not be as unhealthy and unpleasant as living in 19C tenements. I repeat all these trends are underway now, if you look, nowhere near complete, but underway.

             Climate snafus are the wild-card in all this, as they are in everything.

             1. And Techy. Cycling is simply the most efficient system of converting energy into travel:

                http://www.exploratorium.edu/cycling/humanpower1.html

                

          2. Patrick Wrote:
             ” Already walkable, bikeable, more transit rich metros will thrive and double down on these attributes, but will suffer from dwelling cost pressures [see NYC, SF, Portland, Vancouver]. Rural areas will continue to lose population.”

             I don’t think so. Cities depend on Jobs. This Wiki page shows the population moving to rural regions. Mostly because of Jobs related to drilling.
             http://en.wikipedia.org/wiki/List_of_U.S._states_by_population_growth_rate

             Consider that before the rise of fossil fuels most of the American population lived in rural America. When Fossil fuel provided a cheap source of energy people move into the cities because that where the cheap energy was accessible and where the jobs were. Presuming energy gets more expensive, jobs will disappear from cities and people will be forced to relocated closer to where the resources are. Today there is very little manufacturing in cities. For the past 40 years it moved to the suburbs, but now its moving out to rural regions. Even Tech production is moveing out. Apple, Google, MS, etc are all setting up datacenters in rural regions. Auto companies are building plants in rural southern states (Tennesse, Alabama, etc).

             Patrick Wrote:
             “If you have to drive to do everything- to get to work, to shop, to play, kids to school, to socialise, you are in a spatial order that will at the very least lose value as this decade unfolds. ”

             There will be few jobs and nothing to shop for as energy become expensive and rationed. Crime will soar and safety will become the dominate factor that curbs socialization in urban areas. If the cities are to survive, rural regions will need fuel to bring in food, water and other essential goods.

             Patrick Wrote:
             “And Techy. Cycling is simply the most efficient system of converting energy into travel:”

             You must have not read my statements about where the food come from! Your infographic only accounts for the energy burned to supply the power for transportation. You are not including the energy it takes to grow, harvest, prepare the food that originates 1000s of miles away. Consider that you consume 5000 calories of food to ride your bike for a day. How many calories does it take to run the farm equipment that plants, fertilizes, irrigates and harvest the food for those 5000 calories? Its probably about a 100 times the energy content of the food consumed. Just to get that food to the processing plant to the super market burned more diesel than it would have taken you to drive a car to your destination. Hopefully you understand what I am trying to explain to you. The infographic you attached is meaningless because it does not include and of the energy input costs to produce the food and deliver it before it can be consumed. If everyone in a city complete stopped using fossil fuels for transportation and used food instead (walking, biking), how much more food would need to be imported to sustain them? Double or perhaps triple the amount currently being consumed? I don’t know, but I am pretty sure if you need to consume more food to meet your walking/biking demands, Cities will need to import more food from rural regions than they do today. Usually higher demand leads to higher prices and will required more fossil fuel inputs to produce and transport it to the cities.

             Patrick Wrote:
             “A fair bit of this is back to the future, but with much more electricity powered things.”

             I don’t see it that way. I see a future with very unreliable electricity with constant rolling blackouts as the cost of electricity rises, declining paying customers reduce revenues, coupled with gov’t mismanagement. We are already seeing problems is some of big cities with frequent neighborhood blackouts, and this will get considerably worse as energy crisis begin to unfold. Unfortunately most modern high-rise building are unlivable without cheap electricity.

             Patrick Wrote:
             “This will be hard, but some are doing it already and some will achieve it well.”

             Yup. It beats starving and being forced to live in horrible living conditions that will unfold in urban regions. Remember that cities are completely dependent on the imported resources from rural areas. If you are correct, and the rural regions are depopulated, then who will produce the resources needed for the urban populations? Consider biking 20 miles or walking 10 miles to work, especially in summer heat or the winter isn’t easy either.

             I think what you envision of the future does not properly account for the economic and resource challenges that will occur as energy resources decline. Its going to impact a lot more than just the way we travel.

             1. Couple of quick points my pessimistic friend. The cyclist or the driver are both going to eat anyway. If they can’t because of collapse well then travel isn’t their biggest prob. I eat no more than before cycling for transport, but am fitter and, kind people say, slimmer: “Driving burns money and makes you fat. Riding burns fat and saves you money.”

                Can’t use shale boom caused people movements as typical of any trend; they are exceptions, not only globally, but even within US. Just as you can’t argue the Houston proves sprawl is sustainable. Sprawl in a oil boom place is possible, but neither makes it representative of most place nor sustainable. It will last as long as the boom then crash.

14. Speaking of Churchill again; the emergence of truly gifted leaders can have as much to do with the course of history as the physical realities of geography, geology, and technology at least in the short to medium term and possibly in the long term as well.

    It’s unfortunate that half of all the truly capable leaders of our species are madmen of one sort or another but let us suppose that a good one such as Churchill or a bad one such as Hitler were to emerge today in one of the top five or six countries in terms of resources and bend his country to his will ;and that his obsession will not be to create an empire, or defend an existing one.

    Let us consider the possibility that he or she clearly sees that we are well into overshoot and that the future of his country depends on a war footing effort to transition away from a fossil fuel powered economy and transition to renewable energy based economy.

    Hitler was one of history’s worst mad men of course but the fact remains that under his leadership Germany went from flat broke and badly to utterly impoverished in terms of many basic resources to owning the most powerful and technically advanced war machine in history in well under a decade.

    The odds of such a leader emerging in any given country at any given time are remote , but if such a thing were to come to pass in let us say Germany a decade from now, and that Germany were to be suffering miserably from high fossil fuel prices and spotty deliveries and the Germans were to decide to go all out on energy efficiency, conservation, and renewables?

    Who can say what they might accomplish in another decade after that?

    1. If any country in the world is likely to be the victim of a bad leader who taps into their worst instincts, propelled by economic distress, high fossil fuel prices and spotty deliveries, it is the United States. I’m just waiting to hear the politicians rail against propane exports in the wake of the current propane shortage. In fact, the whole push to expand exports of propane, NG, and crude oil will serve as fodder for politicians hungry for an issue to work to their advantage.

       We, as a country, are in a very bad psychological state today, even with relatively low energy prices. Very few people feel secure even if they have a decent job, which is becoming increasingly rare. Let those energy prices go up substantially, pulling the economy down, and the howls of “do something” will become deafening. Especially since we’ve been told for many years now that we are becoming the new Saudi Arabia of oil and have one hundred years of NG. The cognitive dissonance will take us over the collective edge. Then see who steps in to lead us out of the desert.

    2. Re: Hitler, it is impressive what a full blown Keynesian stimulus can do for the economy…

       See for example:

       http://en.wikipedia.org/wiki/Economy_of_Nazi_Germany

15. OPEx per barrel isn’t appropriate. I realize its used all the time but a more useful parameter is cost per barrel plus cost per well. Cost per barrel includes a function of water and gas produced.

    Production also has to include all marketed products.

    Finally, hyperbolic curves really shouldn’t be used if they project very low decline rates. Wellbore hydraulics tends to kill the wells before they get into that territory.

    1. Fernando: “Finally, hyperbolic curves really shouldn’t be used if they project very low decline rates. Wellbore hydraulics tends to kill the wells before they get into that territory.”

       I agree. My guess is that 10 years hence at least 90% of currently producing Bakken wells will be down to 10 bpd or less, or will be plugged and abandoned.

16. Anybody see the New York Times yesterday?

    Not that it is news to us, but that it is there in the MSM finally —

    1. Oops!

       Too Much Winter, Not Enough Propane

       http://nyti.ms/1ixVW2D

    2. Great article — the reactions of the customers and their elected representatives gives just a taste of what is ahead when gasoline and heating oil really get expensive. Perhaps the most predictable part is the claim of price gouging. It never ceases to amuse me how people who champion the free market then complain when the market works as it should to ration limited supply.

       There will now be investigations and committee meetings and hearings and a few unfortunate (and perhaps deserving) business people will be raked over the coals. Government subsidized programs and new regulations will be put into place to make sure “this doesn’t happen again!”

       One thing is certain — at no time will anyone mention that peak oil is the culprit. Yes, it was peak oil that brought the fracking crowd to North Dakota creating a gush of expensive oil that now competes with propane for transportation. But, no, the cause will be put squarely on the need for more energy distribution capacity and more storage capability. It’s a bandaid, but not a bad one. It will help for a while. The question is who will pay for it? One entrenched interest will be pitted against the other and the politicians will gingerly attempt to walk a line that gets them re-elected.

       In the meantime, expect individuals to pony up for bigger propane tanks this spring and lay in a lot of cord wood. Just another step down the road.

    3. Even as prices recede, the consequences of recent weeks could linger, and some propane customers said they were looking for possible alternatives.

       In northeast Nebraska, Andrew Freudenburg said he had already chosen an alternative fuel for his home in Stanton County. He prefers to chop and burn wood.

       “It’s a lot of wood and a lot of work,” said Mr. Freudenburg, 29.

       But his rationale is simple: “The wood is cheaper.”

       An alternative fuel… but not an alternative. Stupid humans!

       BTW, where are the forests in Nebraska?

17. anyhow… it’s just a matter of power versus decency… maybe that’s all it’s ever been

    once you abandon decency, all you got left is game theory… calculating the odds

    “what can i get away with?”

    1. Dude. WHAT are you talking about?

       1. for one thing, i’m talking about the imperial financial apparatus being propped up by opium for close to two hundred years

18. Amid Epic Drought, South America’s Largest City Is Running Out Of Water

    By Emily Atkin, Climate Progress, on February 7, 2014 at 4:02 pm

    If it doesn’t rain in Sao Paulo, Brazil in the next 45 days, the system that provides half the city’s drinking water will run dry.

    Sao Paulo is South America’s largest city, and is currently experiencing its worst drought in 50 years. So far, the drought has hurt corn and cotton crops, driven up prices of sugar and orange juice, interrupted production of beer and paper, and left cattle and goats to starve.

    — snip —

    “I would have already shut off the tap” to consumers on a controlled basis, PCJ Consortium project manager Jose Cezar Saad told Reuters. “Because in reality, the big problem isn’t even today, it’s the normal dry season that we’re going to face starting in May and June.”

    The drought and resulting threat to water supply is also putting a damper on outlooks for the World Cup, which is supposed start in Sao Paulo on June 12 — right in the middle of normal drought season. If rains resume in late February or March, the city should be able to avoid a major water crisis.

19. Southwest England’s Flooded Counties Get More Heavy Rain

    By Alex Morales, Bloomberg, Feb 9, 2014 5:10 AM ET

    Large parts of southern England face more rainfall and winds of as strong as 80 mph (129 kilometers an hour) as the Royal Marines, police and fire teams evacuated homes after flood defenses were breached.

    Following two months of rain and storms that have drenched the U.K., two severe flood warnings were in force across England and Wales today along with 181 medium-risk warnings and almost 271 low-risk alerts, the Environment Agency said.

20. California Drought Impact Seen Spreading From Fires to Food Cost

    By Jennifer Oldham and Michael B. Marois, Blooomberg, Feb 7, 2014 12:00 AM ET

    The fallout may be felt on grocery shelves throughout the country in the coming months as prices of artichokes, celery, broccoli and cauliflower could rise at least 10 percent, said Milt McGiffen, a vegetable specialist at the University of California at Riverside. The state grows more than 80 percent of the nation’s supply of these crops.

    California saw an almost 50 percent increase in wildfires last year from 2012, setting a record. Governor Jerry Brown has ordered 125 additional firefighters hired for the northern part of the state and will keep seasonal firefighting forces in the south on the job longer.

    Lost revenue in 2014 from farming and related businesses such as trucking and processing could reach $5 billion, according to estimates by the California Farm Water Coalition, an industry group. Californians must consider their long-term water habits, said Kevin Starr, author of the seven-volume “Americans and the California Dream.”

    — snip —

    “They invented California through water engineering — which is great as long as you have water to engineer,” said Starr, a history professor at the University of Southern California. “The greater Palm Springs area has over 700,000 people in it and what did Mother Nature intend? Probably 7,000.”

    1. Hard to imagine why anyone would think fracking California would be a sensible thing to do!

21. Ethanol Evangelist Shrugs Off Volatility to Build Powerhouse

    By John Lippert and Mario Parker, Bllomberg, Feb 7, 2014 12:00 AM ET

    Senators Dianne Feinstein, a California Democrat, and Tom Coburn, an Oklahoma Republican, want to scrap mandates for corn-derived ethanol entirely. Ethanol consumes 44 percent of U.S. corn only to inflate food prices, harm the environment and potentially damage engines, Feinstein says. Rising U.S. crude output diminishes the need for ethanol, says Scott Faber, vice president of government affairs for the Washington-based Environmental Working Group.

    “Ethanol is bad news for anyone who eats, drives a car or cares about the environment,” Faber says.

22. Shale: miracle, revolution or bandwagon?

    Investors are far from certain to make money from shale

    Terry Smith, Financial Times, February 7, 2014 1:27 pm

23. If, at some unknown point in the future, the marginal barrel of oil costs $X dollars to produce and the economy can only expand (i.e. GDP) if oil costs $X-Y dollars, these pretty graphs will be for nought.

    1. Sometimes I feel as if we spend far too much time looking at the dead horse’s ass, instead of figuring out where were going to find the next horse!

       They are pretty graphs though.

24. The housing-market impacts of shale-gas development

    Lucija Muehlenbachs, Beia Spiller, Christopher Timmins, 9 February 2014
    Vox, Research-based policy analysis and commentary from leading economists

    Compared to coal and oil, shale gas offers the prospect of greater energy independence and lower emissions of carbon dioxide and other pollutants. However, fracking is controversial due to the local externalities it creates – particularly because of the potential for groundwater contamination. This column presents evidence on the size of these externalities from a recent study of house prices. The effect attributable to groundwater contamination risk varies from 10% to 22% of the value of the house, depending on its distance from the shale gas well.

25. Now We Know: Ethanol Caused the 2008 Financial Crisis and the Little Depression
    Published February 7, 2014, Brian Wright, Uneasy Money

    In the latest issue of the Journal of Economic Perspectives, now freely available here, Brian Wright, an economist at the University of California, Berkeley, has a great article, summarizing his research (with various co-authors including, H Bobenrieth, H. Bobenrieth, and R. A. Juan) into the behavior of commodity markets, especially for wheat, rice and corn. Seemingly anomalous price movements in those markets – especially the sharp increase in prices since 2004 — have defied explanation. But Wright et al. have now shown that the anomalies can be explained by taking into account both the role of grain storage and the substitutability between these staples as caloric sources. With their improved modeling techniques, Wright and his co-authors have shown that the seemingly unexplained and sustained increase in world grain prices after 2005 “are best explained by the new policies causing a sustained surge in demand for biofuels.”

26. Do Oil Prices Predict Inflation?

    Mehmet Pasaogullari and Patricia Waiwood, Federal Reserve Bank of Cleveland

    Some analysts pay particular attention to oil prices, thinking they might give an advance signal of changes in inflation. However, using a variety of statistical tests, we find that adding oil prices does little to improve forecasts of CPI inflation. Our results suggest that higher oil prices today do not necessarily signal higher CPI inflation next year, although they do help to explain short-term movements in the CPI.

    Conclusion

    Our objective was to test the value of adding oil prices to various models that forecast both CPI and core CPI inflation. Although this exercise was technically rather simple, it yielded some interesting results.

    Adding oil prices improved forecast accuracy for a very small number of forecast variations. The only cases where they seem to help are for forecasts of CPI inflation in recent decades, and only when we use leads of oil prices. In contrast, oil prices do not help to forecast core CPI inflation in any model or time period. Our results suggest that higher oil prices today do not necessarily signal higher CPI inflation next year, although they do help explain short-term CPI movements.

    —————-

    Personally, I don’t think rising oil prices are inflationary… they have the opposite affect which is to stifle the economy and depress inflation.

    Stop tying the economy to a dependency on fossil fuels by committing to reducing energy demand with sweeping energy efficiency measure and investing in good public transit systems. Then we might get Western economies out of this depression, otherwise they’ll just continue to stagnate at present oil prices.

    1. What he said. Yes.

    2. Hi aws,

       I agree, carbon taxes would help as well. Unfortunately in the US we are in the minority of people who would elect public officials that could make this a reality. Once the decline begins, maybe that will change, but probably not until we get to Great Depression 2, sooner would probably be better because without a crisis no significant change will occur. Of course the changes that do occur may not be positive, hopefully we will turn left (towards FDR) and not right (towards Hitler).

27. Cochin reversal project creates pipeline pressures

    October 30, 2013 – By Kevin Yanik, LPGas

    Although Cochin’s reversal is an inconvenience of sorts for suppliers, Kinder Morgan’s flow reversal on the pipeline speaks to a unique opportunity.

    “The shale development has really changed the way products are flowing across the country,” says Karen Kabin, vice president of business development at Kinder Morgan.

    Leider echoes Kabin’s sentiment about the supply shift.

    “I’ve been at this for 40 years, and I haven’t see anything quite like this – not since the disruptions we had during the oil embargo in the 1970s, when we would see allocations and limitations of what you would buy,” he says. “Not since then has there been something that has affected us this greatly.

    “With the shift of product around the world and propane in the United States, there was a need to push more product through the pipeline to Ontario or over by Detroit. Now, with the advent of the Marcellus [basin] and the gas they’re getting, the need isn’t quite there. It’s more like they have gas to send the other way. The whole dynamics have changed.”

    Eastern North American gas and propane supply will be placed fully on the shoulders of the Marcellus next winter. Not sure those shoulders are strong enough.

    Midwest Propane Prices Push Record as Pipelines Can’t Catch Up

    By Eliot Caroom and Naureen S. Malik, Bloomberg, Jan 22, 2014 1:43 PM ET

    The Midwest pipeline supply situation may be worse next winter, when Kinder Morgan plans to have reversed its Cochin pipeline to carry light condensate to Alberta, Canada, said Joe Rose, president of Propane Gas Association of New England, by phone yesterday.

    “That will be next year’s catastrophe,” Rose said.

    Map: Kinder Morgan Cochin Reversal Project

    Funny… It used to be that hydrocarbon gas liquids flowed out of Alberta!

    

28. aws is is tired of looking a dead horse in the ass, although he likes the pretty graphs

    he thinks we should be looking for the next horse

    the problem is, it looks like we’re fresh out of horses unless rossi’s e-cat pans out, and that’s your basic long shot

    so we’ll be loaded in a dogcart to hell

    .
    the whole thing is irrational … any sane government would be warning us… carter tried in 1977, but failed, and was replaced by ronnie… feel-good ronnie, who gets a couple hundred marines blown up in lebanon and the next day, invades grenada, defended by three cuban laborers armed with shovels and a burro… big victory wipes the lebanon marines off the news… but that’s how it works, isnt it?

    .
    it’s the lying that bothers me… they know… the deniers know, so why are they lying? …are they guilty of something? …what are they guilty of?

    was their response to peak oil and global warming so despicable that they’ve got to deny peak oil and global warming’s existence?

    .
    it’s all just too despicable, too chickenshit, to survive… so that’s why they’re making all these preparations for a police state…

    then they can quit lying and pretending

29. what’s our purpose? .. .education? ,,,who are we trying to educate?

    cant we point out why bakken is so limited compared to conventional fields in… say, east texas?

    can we point out that it’s gonna be tough to frack enough of south texas and north dakota to make those fields produce as if they were conventional wells?

    maybe i’m stupid enough to be confused…. something tells me i’ve got a lot of company

    something tells me that these sophisticated models are not much good to common people who are trying to understand what’s happening

    1. Our purpose?I presume you mean as members of this forum?

       The very first thing that one must understand to understand humanity is that we are tool using talking monkeys–well apes actually, but “monkeys” gets the idea across better. So far as any one other than theologians can determine ,neither we nor any other life form has any purpose.

       The theologians think we were put here to tickle the vanity of gods who although they are omnipotent for some reason cannot be happy without a cheering section that can be treated worse than dirt if the eternal cheering isn’t loud enough and consistent enough.Personally I find their arguments unconvincing to put it mildly.

       I don’t like it but my own personal conclusion is that we just are, that we don’t have any “purpose”. We are simply biological machines controlled by biological computers programmed to accomplish one basic task and that is to make copies of ourselves. In the last analysis, this is the only discernible goal of any living thing, although “goal” is a poor word to use in this case because it implies “conscious” and ” purpose”.

       Nobody knows why any of this is so but on the other hand nobody has come up with any explanation that fits the known facts as well.

       Once you have gotten your head around this basic concept you have crossed the bridge of fools that separates the handful of well educated monkeys capable of clear thinking from the teeming troop and are thereby initiated into the brotherhood of true knowledge as a novice.

       Perhaps one person in a thousand eventually earns his novice robe.

       A certain number of novices gradually rise thru the ranks of the initiated and become leaders and educators. In this forum you have happened upon a small band of monkeys in the process of educating itself and making an ineffectual effort to educate and warn all the other monkeys about the figurative leopards and boa constrictors that get their living by eating monkeys.

       We initiates mostly don’t expect the other monkeys to pay us any attention until reality slaps them upside their monkey skulls with leopard paws and boas squeeze the breath out of them.

       Nevertheless a few monkeys will listen and do something to save themselves .

       Welcome to the clubhouse of the initiated monkeys!

       Everything will eventually be made clear to you if you without faltering follow your intellect and continue to think rather than focusing on your wants and desires like a small child as most monkeys will do even unto the end as they slowly disappear down the gullet of the boa constrictor of reality.

       There is in the very end no escaping all the many figurative predators out there but a careful monkey has a much better shot at leaving copies of himself to feed the predators of the future.

       Sooner or later some combination of our figurative enemies will get the last one of us but that is the eventual fate of all species and nothing to get too excited about in the here and now since there is nothing we can do about it.

       It probably won’t come to pass for a very long time on the monkey time scale.

       But in the meantime it is mandated (by the programming hard wired into your brain) that you to do what you can to get the overshoot message across to any particular monkeys that you happen to be fond of as best you can.

       But don’t expect them to listen unless they are seekers of knowledge and potential initiates. Maybe one out of a thousand will take the message seriously before the leopard is on his back.

       Do not be surprised at this failure to listen.Every monkey you will ever meet has been subjected to a steady lifelong stream of gloom and doom messages that have proven to be of the little boy crying wolf variety.

       Consequently he no longer even bothers listening to such messages, never mind acting on them.

       1. our only hope is education

          but education implies a certain amount of truth

          but the truth is intolerable

          so we’re stuck…

          .
          thank you old farmer mac

       2. Mac,

          Almost by definition humans have an awareness of themselves lacking in other species. I’m not sure this is true and sometimes my dog seems smarter than me; he’s certainly smarter than my neighbors. But, if we are conscious of our mortality, or transience, then “religion” seems a logical development because then we don’t automatically cease to exist — following a relatively short life! Right? This spiritual stuff appears universal so maybe it’s hard wired into brains, human brains anyway. Trouble is, illogical thinking goes along with this package, most of the time, as in we tend to believe what we want to believe; as a species.

          Now if this doesn’t get me banned, barred and precluded from Ron’s blog nothing will.

          Doug

          1. ol” mac says there’s no purpose to life, and maybe here isnt

             but meanwhile, the neocons seem to think they have a purpose… at least, an interim purpose

             …which seems to consist of achieving “benevolent global hegemony” by killing off anyone who resists their benevolence

             .
             that doesnt seem to be consistent with humanity surviving long enough to figure out what our purpose might be, if there is one
             .
             .
             .
             oh well

             There is a theory which states that if ever anybody discovers exactly what the Universe is for and why it is here, it will instantly disappear and be replaced by something even more bizarre and inexplicable.

             There is another theory which states that this has already happened.

             ` Douglas Adams

             1. You guys will eventually find that you can’t convince people with small children that Occam’s Razor, war and mass death, is compelling.

                2. http://petapixel.com/assets/uploads/2012/09/napalm.jpg

                3. “..people with small children…”

                   love makes the world go ’round

                   you got to love your particular little slice of humanity enough to breed

                   but you got to steer that love in the right direction, dont you?

                   you got to love your particular slice of humanity so much that you can rationalize killing the kids of the “other”

                   the “other” are, afer all, out to get you

                4. I don’t actually believe there is no purpose to life because my monkey brain is not programmed to allow me to believe that, even though that is the most logically compelling conclusion that can be arrived at in the outer layer where rational thinking occurs. But that layer isn’t the boss of the human monkey. Our fundamental life processes such as breathing are controlled by the brain stem and our behavior is mostly controlled by our midbrains which is why we are so prone to act so much like other mammals-which have well developed mid brains but not much of that more recently evolved wrinkled up outer layer where abstract thinking occurs.

                   Now the fact that I don’t buy the god hypothesis does not mean that I think religion has no value. Under the circumstances that have prevailed thru our known history religion has contributed enormously to the enhanced survival of it’s adherents more often than not.

                   If it weren’t for the social glue provided by the religion my family has practiced over the last few centuries I most likely wouldn’t be here myself.

                   I am as easily moved to tears as anybody by pictures of napalmed children or even the thought of such a thing.

                   I have been moved to tears simply by the beauty of a flawless spring day just watching life reawaken on the farm after a hard winter wherein I buried a brother and a sister and my Mom.

                   Life goes on.

                   But yes–we have succeeded to the point that for the last few thousand years the biggest threat to our own survival is no longer the leopard and the boa constrictor but rather our fellow man.

                   And the way the evolutionary game works is that when too many creatures of any given sort are competing for a limited supply of territory and food then the young of the tougher and meaner parents inherit the earth –at least temporarily.

                   Let us pray that things do not come to such a pass but if either of us is compelled–or believes we are compelled— by necessity to kill strangers to ensure the survival of our own children the odds are very very high that neither of us will hesitate.

                   We will hesitate only a little longer before we kill people we know under such circumstances.

                   When we are acting collectively in large groups we will sometimes kill preemptively in what we refer to as a war of aggression.If history is any guide a number of wars will be fought within the next half century over the control of oil, coal, farmland and other resources.

                5. …so the neocons’ push towards “benevolent global hegemony” by employing “full spectrum dominance” is politically and historically correct…

                   …as is their “nuclear primacy”, which supposedly enables us to do unanswered nuke first strikes on russia and china

                   .
                   “my god, man! …we’re only protecting the nest!”

                   .
                   googling: “nuclear primacy” “first strike” russia china

                6. you can take the boy out of the cave, but you cant take the cave out of the man

                   good deal

             2. Speaking of big questions about the Universe: To assert that the big bang, a spark supposedly from nothingness, could generate mass and infuse it with energy is to suspend the first law of thermodynamics, the law of conservation; energy cannot be created or destroyed.

                But if there are equal amounts of two forms of mass that can hold and release energy, then the other form could have transferred its energy into the mass at the moment of the big bang. But of course that would mean that other form of matter, consciousness (spirit-soul, a form of matter relative to the 5th dimension) would have been reduced to minimal energy (minimal thought), and in the aftermath be on a course of ectropy (disorder to order, infused into microbes, working it’s way up the evolutionary ladder of higher thought level species, to eventually compress into gods in the distant future), while mass has entropy (order to disorder). So as stars release energy consciousness uses that energy to ascend to higher energy/thought levels back in the direction from whence it came, god consciousness. So just as there are many black holes (the final compression of mass) there are many gods (the final compression of consciousness).

                In this manner the Universe would cycle energy, which of course goes against the 2nd law of thermodynamics, that perpetual motion machines are not possible, but that is a universe with only one form of matter that can hold and release energy, mass. With two, the rules change and a perpetual flow of energy is possible.

                It also easily explains how the 4th dimension, the fabric of space-time was generated. If there are equal amounts of two forms of matter, then the 4th is generated in the big bang as a mix point, an intermediary dimension composed of both forms of matter’s forces spread out over space and time. This would mean not only is mass distorting the 4th but so is your consciousness, which is the constant pressure on it forcing it to ascend to higher thought levels. But alas, it doesn’t happen unless those onion layers of thought are penetrated, and maybe the best way to achieve that is through calamity, i.e. the coming collapse.

                Elanor Roosevelt said, “It is just as likely we live many lives as we live one life.” So maybe this stage of human consciousness is merely a step along the way. It would be nice to think humanity, the souls now experiencing the coming cliff could learn something from this period of denial, hatred, greed, war, exploitation, manipulation, vindictiveness, etc. and come back in future lives to take responsibility for their earlier failure by living at a higher thought level, more in balance with the biosphere.

                Well, I can’t prove it so it is merely conjecture, but it does propose a middle ground between science and theology that would explain a lot. For example what about the millions of stories about people getting a sense someone they love is in trouble, only to find out later their timing was correct. It’s impossible, right? But it’s not impossible if there is a 4th d. as proposed above with thoughts passing through it. It would also explain the phenomenon known as the 100th monkey, Jung’s collective unconscious, precognition, etc.

                1. “Speaking of big questions about the Universe: To assert that the big bang, a spark supposedly from nothingness, could generate mass and infuse it with energy is to suspend the first law of thermodynamics”

                   Well the theory goes that anti matter was created to balance it out and this anti-matter exists in another universe or another dimension which is not visible to us. This does sound a bit like black magic to me, since there is no way to prove or disprove it.

                   The bigger issue is the mass paradox. Mass causes gravity. The more mass there is the higher the escape velocity. If you have a mass large enough the escape velocity exceeds the speed of light in which no matter or energy can escape. If the universe began at a single point. It would have never expanded because gravity would have collapsed the entire mass into a singularity. Cosmologist use the theory of inflation to suggest that the event of the big bang was superluminal and expanded millions of times faster than the speed of light. which does make any sense either.

                   History has shown that humans are terribly wrong in understanding physics and how things were created. For instance the earths age was revised a few dozen times, from thousands, to million to eventually 4.5 Billion years which didn’t happen until 1956. Undoubtedly, we still lack the tools need to understand how the universe was formed.

                   I will go out on a limb and suggest that I haven’t the slightest understanding of how the universe really formed AND nobody else does either. We simply lack sufficient data to create a proper model. It wouldn’t surprise me that at some point a breakthrough will be made, and everyone will wonder how could we have been so wrong or stupid to believe in the big bang! We probably have the same understanding of the universe as people understand the relationship between the Sun and earth. Less than a thousand years ago the theory was that the Sun revolved around the Earth. Today we all wonder how our ancestors could have been so completely wrong. The answer is simple, they lacked sufficient tools and data to understand it.

30. anyhow, here’s my contribution to beautifying the cyberscape….

    full size
    http://www.freeimagehosting.net/newuploads/g94yk.jpg

    1. Nicely integrated & zero-scaled graph. Excellent perspective. Thanks!

31. Reuters headline from February 8, 2014 5:24 PM:

    Will we ever see the day when sales of these vehicles decline even when they sell them at razor thin profit margins?

    1. Ooops! without a preview function I had no idea what my attempts at using HTML tags would look like. The above post was supposed to have a headline that served as a link with some quoted text below and my comment under that. My comment ended up as the link text and nothing else showed up! I assumed that I couldn’t use the tags in the same way that I used to use them on TOD. Is there somewhere I can go to see how to use HTML formatting on this blog?

       1. The links will occur automatically, but I usually just put the web address. Images can only be posted by using the “select an image for your comment” box, just one image per post, but you can use MSWord and screen clipping to cram a couple of images into one png or jpg file if you wish. We don’t have SuperG here to do fancy stuff.

          http://wpbtips.wordpress.com/2010/05/23/html-allowed-in-comments-2/

          The link above explains what works, I haven’t tried them all.

       2. Ok, here goes.

          Found a web page that showed exactly what I wanted. It’s more like TOD than I thought.

          So, with that, let me try again:

          Reuters headline from February 8, 2014 5:24 PM:

          GM, Ford dealers boost discounts on big trucks

          But inventories of unsold trucks have been building at both automakers. At the end of January, Ford had a four-month supply of F-150s, while Chevrolet’s supply of Silverados had climbed to five months. A two-month supply is considered ideal.

          GM’s pickup sales also fell in January, partly the result of bitter weather and partly because the company has yet to begin selling heavy-duty versions of the 2014 Silverado and Sierra.

          Combined sales of the Chevy and GMC pickups plunged 17 percent to 40,044, while Ford’s F-Series sales dipped 1 percent to 46,536. A year ago, before their overhaul, the Silverado and Sierra together outsold the F-series in January.

          Heavier incentive spending on the big trucks is likely to cut into profits at both companies, although full-size pickups remain among the most profitable vehicles in the industry.

          Full-size pickups and sport utility vehicles account for more than two-thirds of U.S. automakers’ global pre-tax earnings, even though they make up just 16 percent of North American vehicle production.

          Will we ever see the day when sales of these vehicles decline even when they sell them at razor thin profit margins?

          1. Nice job, you found the same web page that I did.

       3. Hello Islandboy!

          It makes my day when another old TOD hand shows up and I’m sure everybody else feels the same way.

32. One for Doug:

    http://oilprice.com/Energy/Crude-Oil/Oil-Drilling-Disappointment-for-Anadarko-off-New-Zealand.html

    1. Thanks Patrick.

33. I added 2007 to the data, and wanted to create a similar insightful graphs as I saw earlier from Rune Likvern to show the total contribution of past wells to current output. As you can see, recent production is taking a larger % of the current output when time goes by, due to the ever increasing decline rates, where we already saw that 2013 wells decline 60% in the first year this will be even more extreme in 2014.
    25 million of the 29 million barrels of crude reported by ND in Nov 2013 is included, as some wells are not reported as individual wells, or missing/incorrect data had me to leave them out. 2007 also contains everything pre-2o07, which is very little anyway, relatively.

    

    1. These analyses are really excellent, excellent work, Enno. Great job.

       Just out of curiosity, what did you use to export the data from the monthly report PDFs into a more usable form? I have tried to do this in the past, but have personally come up short on finding a functional method.

       1. Thanks Wes. I initially also thought it would not be so easy, but after I copied one report to a text file, I realized that they are very consistent in structure(same structure from 2007 until now), and not too difficult to parse. After that I downloaded the other reports, copied each to a text file (total half hour work), and used the same parser to read all of them. I didn’t use excel though, as I guess it won’t be able to handle the almost 400.000 well report records, and it’s not easy to add more structure to it.

34. Comments from Henry Groppe about shale oil and Iraq.

    http://www.middlefield.com/pdf/resource/012914.pdf

    1. That guy is 87.

    2. Don,

       Thanks for that link, very interesting.

35. If I’m eyeballing this graph correctly,and understand what it shows about fifty percent of the total ND production last year came from last years new wells. It’s hard to imagine how anybody who sees this can expect tight oil production to keep rising sharply more than another half decade or so but people will believe anything so long as they want to.

    Here’s a link about current Russian plans for exploration and production in the Arctic.
    It looks as if Rosneft is going to build in house shipyards for the express purpose of building drilling platforms.
    http://oilprice.com/Energy/Energy-General/Russias-Rosneft-to-Build-Arctic-Seagoing-Vessels.html

    1. As noted up the thread, the average oil production rate for Bakken wells in the first half of 2013 was about 135 bpd. Since, as you noted, the average is distorted* by (temporarily) new high production rate wells, the median rate has to be quite a bit lower–I would guess that the median is in the 60 to 70 bpd range.

       And the median production rate would be the killer in higher cost operating areas like Siberia and the Middle East–compounded by the fact that not all shale/tight plays are commercial, and those that are commercial tend to be more gas prone that oil prone.

       *Assume 11 wells with the following bpd production:

       10, 20, 30, 40, 50–60–70, 80, 90, 100, 1,000

       The average production rate would be 141 bpd, but the median production rate would be 60 bpd. In higher cost producing areas, the bulk of these wells might be non-commercial, with maybe two or three wells (or maybe just one well) being a commercial producer. Also, in higher cost areas, they won’t get any long term benefit from the hyperbolic “tail” of production.

       1. I looked at the data for the median well in Nov 2013. If you look at all individual wells, that were actually producing (some are permanently, or temporarily not producing) :
          average bpd : 141
          average barrels per month : 3693 (not all wells produced all days)
          median bpd : 93.33

          But as you say, the variation is still very extreme, which the average didn’t show at all. The top 10% produced more than 290 bpd, while the bottom 30% produced less than 52.

       2. Jeff,

          Do you have any information on, or feeling for, which significant country will be next in making the exporter-to-importer transition? To my mind this is as important a PO metric as any. I expect you’d agree. It’s interesting to monitor how this process is playing out in affected countries; of course there are always mitigating circumstances. Clearly Egypt and Argentina are in disastrous straights with Indonesia not far behind.

          From personal observations (was in Hanoi last Fall) I know Vietnam is coping fairly well, at least at the moment. Of course, the VN economy is growing from a low base and people there are especially resourceful. The UK is possibly a more interesting case, at least to me. From the hype, and on the surface, the economy is well into recovery mode. However, even in bonny Scotland, where I also spent some time last year, people, especially in rural areas, were complaining about how high fuel (gas) costs were rapidly eroding the viability of their farm operations. Of course farmers are chronic complainers but similar grievances are common all the way to London.

          Anyway, I look forward to your views on these matters.

          Doug

    2. Hi Old Farmer Mac,

       It’s a little tricky because you have to look at the area under the curve from Nov 2012 to Oct 2013 (the most recent 12 months). It is probably easiest to just look at a single month such as Oct 2013, and for that month you are correct, about half the output was from well that began producing in 2013. If you look at the nov 2012 to oct 2013 output more than half is from 2012 and 2013 wells, but 2013 wells alone would be about 30 % of total output over the last 12 months shown on that chart.

36. Hi all,

    Enno has shared his Bakken well data and using an Arps hyperbolic to fit the average data from 2010 to 2013,
    I get qi=10893 b/month, b=1.4, and Di=0.173 for an average well profile. At 115 months from first output I assume an exponential decline at a 7 % annual rate, the 30 year EUR is 381 kb. Also of interest is Bruno Verwimp’s suggestion that the shape of the well profile (determined by b and Di) is likely changing. I tested this by looking at how the average well profile matches 2008, 2009, and 2010 data when only the qi parameter is changed in the hyperbolic equation. With b=1.4 and Di=0.173 for all 3 years, I find qi is 7692 barrels per month for 2008, 9348 barrels per month for 2009, and 10641 barrels/month for 2010. The match with the data is pretty good as shown in the chart below. The average well profile for 2010-2013 data is the dashed line (which is almost on top of the 2010 line so is hard to see).

    

    1. When I used the average well profile I gave above the results for the Bakken Model where model output is compared to actual NDIC total oil production data for the Bakken, the results were not very good, the model underestimated output. So I derived the shape of the well profile from Enno’s data (b and Di parameters of the Arps hyperbolic) and then adjusted qi to get the model to match the data through Nov 2013. So b=1.2 and Di=0.17 match Enno’s data pretty well when qi =11750 barrels per month. To match the NDIC monthly production data for all of the Bakken qi=13200 barrels per month. It is not clear to me why there is this difference. One possibility is that there is a problem with the tails of the curves where wells that were producing go to zero, but perhaps Enno treats these as missing data and the zero production level at the tail is not averaged with the wells with nonzero production. If this is correct it would cause the tails to look flatter than they really are.
       Maybe Enno can chime in on how he dealt with wells that stopped producing after 36 months, were months 37 through 48 entered as a zero in the spreadsheet or left blank?
       Thanks.

       1. In the 2nd set of data, where I added the 2007 data, I also added 0-production records for wells that were no longer reported, for the rest of the reporting period, thereby indeed slightly reducing the size of the tail. However, my recommendation is to not do the modelling too precise, as many wells don’t behave as nicely as the (non-existing) average well. E.g., I see for about 20% of the wells a quite clear sign that efforts were undertaken to significantly boost the production again, somewhere during it’s life. In some cases that increased production to a higher level than the initial level, probably due to additional drilling or other methods. There may be more efforts that are not so clear as well. Production tends to jump up and down in many wells, and many wells have at least a couple of months of no production somewhere, or worse, a few months of “confidential” (0 reported) production. I try to filter those cases out from now onwards.
          One strong doubt I have is whether the 30 year production period is realistic. As others also mentioned, probably many wells become uneconomical once they reach 10-20 bpd, and will be shut in. I see that 7% of the producing wells produce less than 20 bpd, and 2.3% less than 10 bpd, while 20% of the wells produce between 20 and 50 bpd. My estimate is that many wells already reach that level after about 10 years. I would therefore also not be surprised when the total well production will be much less than you estimate, perhaps a 100K less over it’s lifetime. Perhaps others have more insight in this.

          1. Hi Enno,

             I agree that a 30 year well life is likely to be unrealistic. However, the many of the older Bakken wells which started producing between 1980 and 1990, did in fact produce for close to 30 years, and definitely for at least 20 years. For the wells that started producing in 2007 we only know the average well profile out to 6 years and can only guess at the well profile beyond that point. The well profile changed from 2007 to 2010, the EUR increased and the cumulative output curve shifted upward, but the shape remained very similar as I showed in my chart covering 2008 to 2010. Assuming that the 2007 average well profile gives a good estimate of the shape of the average well profile for 2010 to 2013 average wells, we have a good guess at output out to 6 years. I have assumed that the hyperbolic profile only continues out to 9.5 years and that the decline rate then becomes exponential. I have no idea about the economics of stripper wells, at 20 years these wells would have paid for themselves and would probably be sold off to small operators, if my well profile is correct thay would still be able to produce 12 barrels per day at 20 years, but I would think that OPEX would increase (in dollars per barrel) at such low rates of production. On the other hand my model for the older wells (prior to multistage fracking of horizontal wells in the ND Bakken or before 2005) suggests about 3 barrels per day at 20 years for those old wells so perhaps the 2008 to 2013 wells will still be going at 20 years, heck at 30 years the model gives 5 barrels per day for the average 2010-2013 well. It could be that the horizontal wells are more costly to produce when they each stripper well status.
             It would be interesting to hear the thoughts of some oil industry pros.

          2. Hi Enno,

             You also said 2.3% of wells produce less than 10 bpd. Are you talking about ND Bakken wells, and are those wells that started producing before 2007?
             It would probably be best to filter out wells which clearly have been reworked.
             Also in the spreadsheet you sent me there was a sheet 1 and another named “new”. I had initially thought that the main difference with the “new” sheet was that 2007 data was added, I was mistaken.

             As I am trying to find an “average well” for 2010 to 2013, I need well counts as well as output for your yearly well profiles, “sheet 1” included this, but “new” did not. Also is there any chance I could get a spreadsheet with the well data for 2010 to 2013 so I could try to do some of the filtering myself. My guess is it would be huge, but if you mostly include the raw data, (to keep the spreadsheet of manageable size), I could do the processing as I know how to use a spreadsheet. (Though I am not as skillfull a programmer as you because
             there is no way I could have pulled out this data the way that you have.) Again thank you for sharing what you have so far.

             1. Hi Enno,

                I re-read your e-mails and realize that what I requested is not possible.
                Would it be possible to include something similar to columns k through q of “sheet 1” in v3 of the spreadsheet you sent me for the “new” worksheet, I assume the well counts must have changed because the well profiles changed from “sheet 1” to “new”.

                I was also wondering how you handle confidential wells. Usually they are confidential for the first 1 to 3 months and then are reported after that. Lets say well x is confidential for 2 months starting in Jan 2013 and that output starts being reported in March 2013, do you leave months 1 and 2 blank and report months 3 to 11 or do you treat the well as having started production in March 2013? To me it would be more accurate to do it by the first method or to simply exclude wells that started production under confidential status from the analysis.

                Finally, the first month of production is a problem because the number of days of production can vary from 1 to 31, do you take barrels per day and multiply by 365.25/12 for the first month of production?

                1. Hi Dennis,

                   Let me try to get to each of your points 🙂
                   1) <10 bpd wells. I see that about half of those wells started in or before 2007. 20% from 2008, and the rest from the years after.
                   2) "It would probably be best to filter out wells which clearly have been reworked." I tried to find an easy way to identify that, but it is not. It may be possible to filter out the easiest cases, but that is probably just a minority. I think that with this data we should not aim for perfection, as guessing at incorrect/missing data is in my experience a hopeless task.
                   3) I can get you a spreadsheet, will email you about this.
                   4) Confidential wells : they are reported as having 0 production. Most indeed start with a few months of confidentiality, although there are all kinds of other cases as well. Also here, it's best not to guess what actually happened; the first month real production is reported, and if it is higher than 1000 pb in the month, I count it as the starting month. Sure, it will be slightly off, but at least we know we're off, and there is no foolproof way to correct it.
                   In future analyses I will at least try to filter wells out that have confidential months after their starting month, as I expect those to cause bigger distortions. I would not exclude all confidential wells, as about half of the wells start under confidentiality.
                   5) First month of production. I just take the first month in which the well produces in total more than 1000 barrels, independent on how many days it ran. Also here, of course all kinds of cases happen, but on average I will not be wrong with more than a month, so the effect is not big.

                2. Enno,

                   Thank you. I agree trying to do what I am asking with such a large data set is very difficult and likely to introduce as many problems (or possibly more) as it might solve.

                   It is nice to get these clarifications because it explains one possible reason that my estimate of the average well tends to underestimate overall output when I match it with the actual number of producing wells and actual output as reported by the NDIC for the entire Bakken/Three Forks.

                   My reasoning is that the early months tend to have the highest output and I will assume that half of the wells start production with 2 months listed as confidential. If we treat month 3 as month 1 in our data file, we have taken two of the most productive months and essentially zeroed them out because the data is not reported. This will tend to cause an underestimate of the actual output from average well (which as you pointed out earlier does not really exist it is just a theoretical construct).
                   Where you have the actual data, you could correct any incorrect impressions I may have.

                   One last question, at roughly what point does it look like they shut in the more recent wells (after 2006), 5 b/d, 3b/d? I am sure it is variable, I was looking for a rough average.

                3. Hi Dennis,
                   as we’re doing right now, let’s continue our discussion for now by email. This thread is getting old. At another time, I’ll share an update with the forum again.

37. Anyone want to bet that when the Bakken rolls over some redefinitions take place of what is oil or what is a month or what is production or what is this or that to corrupt the numbers and further render projections suspect?

    1. Speaking of which, this from ZH:

       http://www.zerohedge.com/news/2014-02-11/golden-age-gas-possibly-interview-iea

       The incompetent IEA chieftess gave an interview and said this:

       “OP: Are there any other ways around the “crude wall” aside from lifting the export ban?

       IEA: As we wrote in our January 2014 Oil Market Report, much of the LTO is produced in the form of lease condensate, which is most optimally processed in a condensate splitter. There is currently only one such facility in the United States, although at least five others are in various stages of planning and construction.

       I mention this issue because one could imagine a scenario under which lease condensate is excluded from the crude export restriction. The US Department of Commerce, which enforces the export ban, includes lease condensates in the definition of crude oil. However, this definition could be changed, or the Commerce Department could simply issue lease condensate export licenses at the behest of the President.”

       1. Previously in the interview she was leaning on — these are matters for the US internally and we don’t comment blah blah blah and then WHAM . . . she just happens to know the agency enforcing the ban and how to redefine words to make it happen.

          What a scam.

       2. IEA: As we wrote in our January 2014 Oil Market Report, much of the LTO is produced in the form of lease condensate,

          Well there you have it!

          Nice catch Watcher.

          1. Also from the OMR…

             the 525 kb/d Northern Gateway Pipeline, received conditional approval in December. The federal government’s Joint Review Panel approved the project, which would carry crude from Alberta to a British Columbia port, subject to 209 conditions and final ratification by the federal government. The pipeline will have a reverse‐flow pipeline constructed beside it in order to import as much as 193 kb/d of diluents.

             Funny how Alberta now has to import light hydrocarbon liquids.

             1. Hi aws,

                You realize, I hope, that the condensate is imported to Alberta so they can get the tar sands to flow in pipelines after they mix the bitumen(aka tar sands) with the condensate. This is not anything new or unexpected. It is hard to move landlocked extra heavy oil.

          2. Well, Ron did find a legit Platts article comparing Bakken diesel and kerosene content to Louisiana Sweet’s content (though the original point was a comparison to Nigerian fractions — maybe LS is known to be so and not the right yardstick, dunno.).

             So this doesn’t put anything altogether to bed, but it is a damning phrase from her. My focus was on the willingness to redefine things to get a result desired. The graph folks could be setting themselves up for a disaster, but that should not deter anything. Awareness suffices.

          3. This is not a change in definition for the EIA. For a very long time the US has reported C+C output which means crude plus lease condensate.

             1. You missed the point. The change would be to separate them and define condensate as NON CRUDE to allow export.

                1. Hi Watcher,

                   I intended that as a response to AWS and should have been clear about who I was responding to.

                   I did in fact miss the point as I skimmed through too fast and interpreted aws’s comment backwards.

                   aws wrote:

                   “IEA: As we wrote in our January 2014 Oil Market Report, much of the LTO is produced in the form of lease condensate,

                   Well there you have it!

                   Nice catch Watcher.”

                   And earlier you had talked about redefining stuff when the Bakken declines (if I interpreted that correctly), I missed the exports part and how that redefinition was to allow exports of condensate.

                   The EIA seems to be moving more and more towards the total liquids definition, so stuff is going to be redefined in whatever way the government thinks best.

                   It would be nice if liquid fuel was reported in Energy terms rather than by volume or mass.

                   Sorry for not reading more carefully, I did indeed miss the point.

       3. From IEA’s January 2014 Oil Market Report … (p.26 sidebar, pdf)

          Much of the LTO is produced in the form of lease condensate, which is most optimally processed in a condensate splitter. There is currently only one condensate splitter in the US, although at least five others are in various stages of planning and construction.

          — snip —

          An additional outlet to expand exports under current legislation would be to exclude lease condensate from the crude oil export restrictions. The US Department of Commerce, which enforces the export ban, includes lease condensates in the definition of crude oil. However, this definition could be changed, or the Commerce
          Department could simply issue lease condensate export licences at the behest of the President.

38. IIrc, the first time I encountered this political card trick Nixon was prez and unhappy with the housing start data.

    So somebody decided that house trailers are houses and presto, the house starts looked great for the republicans in the upcoming elections.

    The first time this sort of thing was actually recorded it was most likely on a clay tablet with a stylus.

    If this were a political site I could post a number of current examples of this trick of renaming things for partisan or special interest ends.

    I’m inclined to think Watcher is right this time.

    In my estimation it doesn’t really matter much either way insofar as our US oil supply is concerned because oil is about as fungible and as easily substituted from one supplier to another as any commodity so long as transportation is available and there is still plenty of it being actively bought and sold on international markets. If it gets to the point that we can’t import enough to make up for any exported oil, then the law against exporting oil will be renewed because that is the way our political game is played at this point in time.

    Unfortunately if exports are allowed then the happy go lucky camp will trumpet it to the moon like coyotes as evidence that happy motoring is back and here to stay.This will in turn have the extremely ill effect of setting back energy efficiency and conservation substantially.

    The bigger they are the harder they fall. When the inevitable oil crunch finally arrives the folks who championed exports are going to look like the proverbial hooker in church and you won’t hear a peep from them about the virtues of free trade in oil.

39. Oglala Sioux vow to stop Keystone XL on the ground if Obama won’t say no

    Indigenous group has been touring United States and Canada offering direct action training to nations committed to standing with the Sioux.

    Erin Flegg, Vancouver Observer, Posted: Feb 6th, 2014

40. CGA Canadian gas storage levels

    

41. LIAT bleeding Barbados dry

    In the post, Mr MacLellan highlighted the parlous state of LIAT’s finances which have resulted in the build-up of alarmingly large payable balances, including huge arrears to aircraft lessors and late payment of employee salaries. The stark reality is that LIAT cannot pay its bills and suppliers have been left holding the bag…..[snip]

    There is no credible prospect of a turnaround at LIAT under the current board, management and policies. In fact, with regional travellers shunning LIAT because of repeated service failings and increased competition as eloquently detailed by Mr MacLellan, LIAT’s financial performance is likely to deteriorate further. Barbados will be forced to provide annual subsidies to LIAT in the form of transfers from the Treasury or loan guarantees at a rate that would pay the salaries of 500 public servants for a year.

    Another casualty of Peak Oil? I submitted a comment suggesting just that and further suggesting that without a significant and sustained increase in world oil production, “There is no credible prospect of a turnaround at LIAT”, period.

    It has dawned on me that we are now living through the slow motion train wreck that is, Peak Oil. If the masses only knew! I have been trying to do my part to raise awareness in my neck of the woods by using the words “Peak Oil” whenever I can or describing aspects of the problem or otherwise trying to arouse curiosity in the minds of readers of the comments section of my local newspaper. In a comment to a recent article outlining a suggestion by one of our opposition senators that the country “should consider limiting parents to two children”, I actually suggested that the person to whom I was responding do an Internet search for “albert bartlett arithmetic population and energy”, in order to better understand the point I was trying to make.

    Surprisingly, it seems more of my comments are being passed by the moderators at that newspaper. Either they are softening their “see no evil, hear no evil, print no evil” stance or I am getting better at crafting my comments or a bit of both!

42. DC:

    1. Nice work. I appreciate the effort to put together a framework. Doesn’t guarantee being right and we should consider other estimates also, but it’s good stuff. For one thing, it allows creating scenarios or even doing formal sensitivity analysis. (I saw a module in Excel that would do this for M&A valuations…you feed in the 10, 50, 90 estimates for different factors…and then the module actually calculates all the different combinations and gives you distributions and sensitivities.)

43. DC:

    2. I think LaH gave you some very nice feedback on geology, but I would NOT feel bad about no matching his linearization. That’s based off of a couple years (somewhat arbitrary in decision) and is a very, very simple model. And we have seen the Hubbard linearizations be drastically off the last few years.

    1. I’m also happy to see you using some of the USGS research. I assume that you have seen this report on decline rates?

       pubs.usgs.gov/of/2013/1109/OF13-1109.pdf

       I have a little bit of a hard time with the super pessimistic estimates for ultimate recovery, given how off everyone has already been on the Bakken production rampup (just reading through old TOD posts and the like). Yeah, Continental is a promoter…but still there estimate is one to consider. And ND state was pretty brave (and early) in estimating the rampup that they did when everyone thought it would be crazy to get into the 700-1.2 MM bpd range. So, just be wary of the promoters…but also of people who hang out in a community called “peak oil”. 😉

44. DC:

    3. I think the price is OFF (much too high). You should use the futures price for oil in your model. After all, that’s the market guess…like a Vegas line. That’s how investors evaluate the play. Even if you think “the market is wrong”, you can still hedge. You can even look at the price guess thread in the peak oil forum and people are basically betting close to the futures estimate (not 140!).

    I think price has a huge role in the Bakken and it is not impossible that we return to 40/bbl oil (not likely, but not meteor falling on your roof unlikely). IT IS PROBABLY MORE UNCERTAIN THAN THE GEOLOGY. We’ve even (in 2008) had one example of a price crash restraining drilling. You could also do a 10, 50, 90 for pricing (I think this can even be estimated with puts and calls), or just some scenarios. But really strongly urge you to think of price as one of the major drivers of the model.

    I think WTI, Cushing is a good metric to use. Any decisions on export restraints or the dropping of them are already incorporated in that metric, so you don’t need separate factors. Also, the composition of the oil is almost identical to WTI. Obviously, there’s a transport offset (to Cushing), but that’s already in your model.

    I’m really not a financier (just a civilian Internet commenter). But here is WTI futures chart:

    http://www.cmegroup.com/trading/energy/crude-oil/light-sweet-crude.html

    It varies daily and there is some connection of current and futures price (e.g. current price has recently edged up a few dollars and so has futures price). But basically it has looked similar in shape for a few weeks. The “betting money” is that we have a gradual ramp down of about 20 dollars over the next 5 years. Note that these are nominal dollars, so since your model is in real dollars (I think), prices are actually declining even more than what is shown (in real dollars).

    In any case, the 140 is really unrealistic. I like the Maguerri 65 (real) dollars much more. As far as extending later, I would just do a constant value after the last data point. If you want to get super fancy, you could try fitting some hyperbola or exponential and see if there is an asymptote.

    1. Hi Nony,

       Maugeri’s estimates are very optimistic, Mr Laherrere’s are very pessimistic, clearly you are more optimistic than I am. I think you may have not looked at the EIA’s AEO 2013 reference oil price scenario very carefully. In 2020 the scenario suggests $110/barrel (2013$) for Brent. Brent is the proper metric for the marginal barrel which is competing with imported oil at coastal refineries on the East and West Coast, the $140 per barrel is for 2033, I am pretty sure the futures market for 2033 is pretty thin and not likely to give a good estimate of future prices that far out (the EIA’s guess is likely to be wrong as well). Maugeri’s estimates for oil price and output are not credible in my opinion, prices of $65/ barrel in 2013$ in 2033, is that your call? So we will have to disagree, I actually think that if 2% worldwide growth or higher is maintained (on average) until 2033, that $140/barrel (2013$) is likely to be too low an estimate. In addition if prices were $65 per barrel (2013$) as Maugeri estimates then output will be much lower because wells will not be profitable, so keep in mind that the economics suggests that if the USGS estimates are correct (mean undiscovered TRR for ND Bakken/Three Forks of about 5.9 Gb) and prices are as low as Maugeri estimates, the economically recoverable reserves will be much lower than what I have estimated (assuming well costs do not fall below $7 million for drilling and fracking and transport costs, OPEX, and royalties and taxes remain close to present levels.

       http://oilpeakclimate.blogspot.com/2013/09/update-to-north-dakota-bakken-three.html

       The post linked above covers the TRR estimates which are for North Dakota only, which is about 79% of total US Bakken/Three Forks undiscovered TRR according to the April 2013 USGS Bakken/Three Forks assessment. See links in my blog post.

       Also on futures markets see
       https://www.stlouisfed.org/publications/cb/articles/?id=831

       Futures markets do not do a very good job of predicting future prices. Consider betting lines for the superbowl in 2033, would anyone expect these to give them useful information? In the cornucopian world oil prices will always be lower in the future, in the doomer World the forecast is the same, but for very different reasons (economy in chaos, negative growth so very low demand for oil). Reality will be that oil prices will fluctuate up and down as they have since 2000, but the trend (5 year average real oil price) will be up, unless the more pessimistic scenarios (a permanent global economic crash where the economy is unable to find any substitutes for scarce fossil energy resources) is proven correct, my position is between these two fantasylands (cornucopian and doomer). Of course those with different positions than me believe that my position is a fantasy as well, (most here would call me hopelessly cornucopian).

       1. A. I’m well aware that a lower price means less oil extracted from the reservoir. Even though I have a cornie heart, I go with data.

          B. Use the futures price as your baseline. It could be off high or low, but really…it is the betting estimate. We could be 40…or we could be 140, but why not make the central case based on the actual market indication?

          C. If you think you are smarter than the market itself, bet on the futures themselves and just ignore exploration and the Bakken.

          D. By making the base case, the futures market price what you do is constrain your model to looking at the play itself. Otherwise, you are confounding views on price (which depends on global supply and demand) into your model about a local play. Separate variables…it is better analytical method.

          E. Go ahead and run a base, high, and low case. That way you can keep your “gut” feeling on price in the model, but segregated to a variance case.

       2. F. Also, re Magueri: $80 times 5 years of inflation is pretty close to 65 (although I’m not sure if Magueri uses real or nominal in his discussion). 140 is way out there and is in the opposite direction of the futures markets. Could it happen? Sure. But you are confounding a bet on global supply and demand (i.e. you think you are smarter than the markets) with the Bakken itself. Why not make base on the expected (i.e. futures) price. That is how anyone investing would make their decision.

45. 4. The WACC you have there is very unreasonable. 15% is quite high. Sometimes companies will do things like requiring models to assume a high WACC (because they think other estimates will be padded). I was at a company that required using 12% (reality would have been 8% for them). But I definitely disagree on doing this for external estimates (and internal, but definitely external should reflect reality not an arbitrary WACC).

    I’ve actually calculated this stuff from scratch (industry betas, term structure, etc.). But let’s just look at some already calculated industry WACCS:

    http://pages.stern.nyu.edu/~adamodar/New_Home_Page/datafile/wacc.html.htm

    Petroleum production is 8.6% (as of JAN 2013). And when you think about this play, the “years out” when the well is just declining and getting milked is pretty stable and risk free. And much more than exploration (but of course this play is getting pretty well understood, just by drilling…well at least the upper part).

    Note that this WACC includes nominal dollars. I’ve seen top consulting firms make the mistake of using real dollars in the model estimates and then a normal WACC. Problem is that that includes implied inflation, which is implicit double discounting. Probably easiest thing is just to have the whole model in nominal dollars (then you don’t need to adjust the futures prices either).

    1. According to oil industry pros 10 to 15 % is the norm for these kinds of calculations, I could use 10 % it does not really change things a whole lot, real dollars makes more sense to me, currently inflation is pretty low and that is likely to continue. I really do not think that futures prices will accurately predict oil prices in the future, beyond maybe one year out, in fact the prices that I use (which reflect east coast refinery gate prices which is the most relevant to the marginal barrel) are below current Brent prices (which is close to east coast refinery gate prices) until 2020.

       Another reason that the oil industry would tend to use a higher discount rate is due to the volatility of oil prices which makes investment more risky. Oil firms require a higher rate of return from their capital investments to mitigate such risks, Rockman (who posts a lot a peakoil.com) suggested 10% to 15% as the discount rates typically used, I used 15% to make the estimate more conservative, in earlier analyses at my blog (such as the analysis linked to above) I used a discount rate of 12.5 %, the analysis does not change very much. See chart below(from my blog post in Sept 2013) for ERR and note this is with transport costs at $9/ barrel, and a discount rate of 12.5%, and lower royalty and taxes of 20%, but included other costs of $3/barrel which was zero in this recent post (paid for by natural gas and NGL sales) all of these costs are in real(2013)$.

       

       1. Agree to disagree. Everything you wrote was already pre-rebutted.

       2. Nony,

          See the following 2011 Federal Reserve Bank paper on oil price forecasts, especially the conclusion.

          http://www.federalreserve.gov/pubs/ifdp/2011/1022/ifdp1022.htm
          A couple of quotes from the conclusion of the paper:

          “We provided evidence that at horizons up to six months suitably designed unrestricted vector autoregressive models estimated recursively on ex-post revised data tend to be more accurate out of sample than the no-change forecast of the real price of oil. There also is strong evidence that recursively estimated AR and ARMA models have lower MSPE than the no-change forecast, especially at horizons of 1 and 3 months. At longer horizons, the no-change forecast of the real price of oil typically is the predictor with the lowest MSPE. These results are robust to the use of real time data.”

          “More commonly used methods of forecasting the nominal price of oil based on the price of oil futures or the spread of the oil futures price relative to the spot price cannot be recommended. There is no reliable evidence that oil futures prices significantly lower the MSPE relative to the no-change forecast at short horizons, and long-term futures prices often cited by policymakers are distinctly less accurate than the no-change forecast.”
          End of quotes.

          Basically the assumption of no change in oil prices would be more accurate than using oil futures prices when the time horizon is longer than 12 months.

          One last quote: “We also found strong evidence that after 1973 the real price of oil is predictable in population based on fluctuations in global real output, as suggested by standard economic theory.”

          So if we assume that global real output will increase over the next 20 years (on average, obviously this rate of growth will vary over time), then we would expect oil prices to rise as well, my guess is that the economic models that are used by the EIA, reflect their estimate of future global real output and its effect on oil prices.

          1. I’ll go read it, but the likelihood that some discussion paper from the Fed has more validity than 100 years of intuitions on efficient market theory is pretty fracking low. If they really think that, then easy money can be made by betting versus the futures markets. I ain’t buying that. Base case is what the market has determined. That discussion paper is available to every quant on Wall Street and hedge funds have huge amounts of money to bet on any opportunity.

             1. Ok futures markets are always correct. If you say so Nony. Efficient market theory, of course must be correct, because every one has perfect information, right? The paper is quite long and the main argument is that nobody can really predict the price of oil, especially long term. The futures markets are just bets on future prices, when you look at the data from past futures markets and compare to spot prices at those future dates, in every case more than 12 months into the future, a bet on no change in price would have been more accurate than using futures markets. You may be correct that the EIA estimate is incorrect (somehow you seem to be missing that prices in my model 7 years out are equal to current prices (for Brent which is the relevant metric for refiner acquisition cost). As I suggested the aim was to be balanced, and not be accused of being too pessimistic. Currently the futures market predicts $105/barrel for Brent in Dec 2014, the price is currently about $108, I think it will be close to this level in real terms in Dec 2014 and the futures market price which will be lowered from its nominal value to perhaps $103/barrel in real terms will be too low, I think the price of Brent crude is more likely to be $107/barrel or higher in real terms (Jan 2013$) in Dec 2014.

                What period is that WACC calculated for? Note that the industry average may not reflect costs for the firms operating in the Bakken, my guess is that Exxon or Chevron have a lower WACC than continental resources. Also note that whether to invest in new wells relates more to the marginal cost of capital which will be higher than the WACC as the profit maximizing firm will be investing up to the point where marginal cost is equal to marginal revenue.

                So we will continue to disagree.

                The first paper I linked to from the St. Louis Fed is quite short and explains why futures markets tend to have lower prices than current spot prices.
                From that paper:”In general, there is a marked tendency for futures prices to lie below spot. In the jargon of commodity futures markets, this is known as “backwardation.” Backwardation in the oil futures market is related to a consideration known as “convenience yield,” the marginal benefit of holding a commodity in reserve. For oil, the convenience yield lies in the option-value of allowing oil to remain in the ground. By not pumping oil in the first place, the owner of an oil field retains the option of increasing production at a later date. An unanticipated need for oil in the future is often more conveniently and less expensively met by pumping additional oil, rather than buying it on spot markets. The presence of a convenience yield acts to push futures prices below spot prices.

                Storage costs and interest costs provide an opposing effect on the relationship between spot and futures prices. Unless one has direct access to an oil production facility, a promise to deliver oil in the future requires the purchase of oil on the spot market, the interest cost of borrowing to finance that purchase, plus storage costs. The interest costs and storage costs comprise the total carrying cost of oil. When carrying costs exceed convenience yields, futures prices should exceed spot prices-and vice versa. ”

                So the price of a futures contract depends on several things, the expected future price of oil, interest costs and storage costs for oil, and the “convenience yield” which is the option value of leaving oil in the ground so that it is available to pump at a later time to meet unanticipated needs (oil in the bank as it were).

                1. 1. I’m WELL AWARE of the implicit arbitrage of high futures prices to current prices and how storage, etc. create a linkage. I didn’t even have to go there, I know it.

                   2. You are mischaracterizing my remarks. I already SAID that the markets are not perfect predictors. They are just your best base case. They are what anyone investing would use and the deconvolute bets on global supply/demand from a local play.

                   3. I’ve given you the feedback. At this point, we are starting to argue freshman level finance and econ.

                   P.s. If you really believe the price will be 140, please make a bet with me. No kidding, I will bet tens of thousands of dollars against you. Do you believe it enough to bet on it?

                2. No I will not bet on 140 will you bet on the futures price in 2020, note again that the price in my model is $108 in
                   2013$ in 2020. A bet on prices in 2033 would be foolish.
                   Thanks for the feedback, and yes you seem so certain of futures markets as being the best source of future predictions that economic arguments will not convince you. There are many economic models which suggest that you are incorrect. I suppose that the economists at the EIA and the Fed probably know less than you, but I am certain that they know more than me, I do appreciate you trying to teach me about the futures market.
                   I think markets are great, but I don’t think they are perfect (and nor have you said that they are, but I think you have more faith in them than me.)

                   December 2019 the Brent futures price is $91.18, if we deflate that we get $80.77 in 2013$, if inflation were only 2% each year, so would you bet on $80.77 and I’ll take $106.14, which is what my model has for Dec 2019?

                3. I’m not even arguing, just a clarification question. I thought you were modeling real 140? I.e. even higher in nominal dollars.

                4. 95% confidence intervals on price (from the markets themselves). It’s a wide band (the market is even saying it’s not “sure”). But the center is the center…

                   http://www.eia.gov/forecasts/steo/images/Fig1.png

                5. I must say I found this quite an interesting discussion. I think both positions are quite well defendable.

                   Myself, after giving this some thought, would agree with Nony that the futures market should be the starting point for the assumption on future oil prices as otherwise you should definitely explain in your analysis why you deviate from what most market participants expect. However, I agree with Dennis that the oil futures market after 1-2 years is very thin, basically there are very few opinions in the market about it. I saw the Continental Resources for future oil prices used something like the futures price 1-2 years out, and then added 3% annually. They didn’t explain this, and there may be more approaches, but I found that quite reasonable, and seems to be in the middle of both of your positions.

                6. It’s like leaving it constant in real dollars (given 3% inflation).

                7. Hi Nony,
                   The inflation rate has not been 3% annually for quite a while. From 2002 to 2013 the average was about 2.4% for the CPI (all urban consumers).

                   Also something that I realized since you brought this up and I checked the newer AEO 2014 for the real price forecast, they do follow the futures prices out to about 2019, what I did for simplification is choose this low point and left prices flat from Jan 2013 to August 2015 and then allowed them to rise at a constant rate that matched the EIA forecast pretty well. So essentially I was already using futures prices out to mid 2015 without realizing it. Based on research by the Fed, futures prices are not a very good predictor of future spot prices, a better predictor is to assume prices don’t change.
                   Like you said the 3% is likely just an inflation estimate so beyond a couple of years they are just predicting flat real prices.

                   Enno,

                   Thanks for the comment I agree it is an interesting discussion and I thank Nony for teaching me a little about futures markets. As I pointed out and Nony said he was well aware (so I don’t think he disputes it), there is more information in a futures contract price than just the future expected spot price, so the idea that this is the best way to estimate future spot prices would only be correct after taking these other factors into account. When you actually look at what futures prices were 5 years ago and what actual spot prices turned out to be 5 years later, it turns out that the futures contract prices do not predict future spot prices very well. I do agree that it may be the best thing we have for 12 months or so, beyond that flat real prices is the best guess because the futures markets get very thin a few years out.

                8. 1. do what you want. I’ve given you the feedback.

                   2. Almost any econ professor will say that the futures market is your best guess (even if it has a bad record…it’s still the best guess). They will take basic EMH over some random Fed discussion paper in a heartbeat. But do what you want.

                   3. 2.4% is pretty close to 3%. Maybe they rounded. Or maybe they used the implied future inflation (from bonds and such) rather than historical. It’s true in approximation. I mean 2.4% versus 3?

                   4. Your chart has real price going up. Not nominal. So in 2018, you have about 102/bbl real (or 115/bbl nominal). And the futures market prices it at 80. 115-80=35. Pretty big delta.

                9. Hi Nony,
                   Edit: interesting paper on Efficient Markets Hypothesis (EMH) at link below:
                   http://citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.167.5720&rep=rep1&type=pdf

                   Bottom line, not all economists concur with the assessment that the EMH should be taken as given.

                   I thank you for your feedback. Brent futures are $95/ barrel in Dec 2018, not $80/barrel. Bakken oil competes with imported crude on the East and West coasts so Brent is the appropriate price not WTI. So the difference is $118 in Dec 2018 in my model in nominal terms assuming 2.5% inflation (avg rate since 2002) vs $95. This($95/barrel) is likely a worse estimate despite EMH (which not all economists agree with) than current prices which are about $110/barrel. If we account for inflation, the nominal price in 2018 would be $124, so maybe my price scenario through 2018 is about right(or too low).

                   The AEO uses futures prices out to about 2017, in AEO 2013 which was the reference scenario I was using the futures prices may well have been different, but when I update my price scenario to the AEO 2014 reference case, the numbers will be a little lower.

                   The current Brent futures price for July 2017 is $95, in the AEO 2014 the nominal 2017 price is $99, this difference is no doubt due to the AEO 2014 being produced last fall.

                   Can you give me some references that suggest that futures markets 5 years forward are the best predictor of future spot prices, I think you may not be correct? Short term I agree, long term I do not.

                   I am curious about your thoughts on global supply and demand, because clearly this will affect prices. I am thinking that you would guess that at current real oil prices there will never be insufficient supply of oil. If that is your position I disagree, real prices will need to rise in order for supply and demand to balance, the AEO scenario is as good a guess on that as any. The idea that real oil prices will decrease or even remain flat from now until 2040 is not credible.

                   Finally I checked my model prices in Dec 2015 vs Brent Futures the difference in that case is $102/barrel (nominal) for my model in Dec 2015 vs $100/barrel for Brent futures, this might be an appropriate limit for using Brent futures as an estimate of future spot prices.

                   Interesting discussion thanks.

46. 5. Also, not sure if the USGS estimate includes Montana or not, but just something to watch for. Do you want to calculate all US Bakken/TF or just the ND part.

    1. Just ND see my comment above and the sept 2013 post at my blog for more details.

       1. thanks. I figure it was in there, but I just didn’t read close enough. 🙂

          Wanted to make sure you didn’t under/over count. 🙂

          1. Nony,

             Sorry for seeming defensive about your suggestions. Using the futures market as a guide over the short term makes sense, my analysis does this for Brent prices in real terms out to mid 2015 and then follows the AEO 2013 (roughly) out to 2030, I then extend the 2015 to 2030 rate of increase out to 2040. Actually my price scenario just takes the minimum AEO 2013 brent price (from 2019) and uses that price from Jan 2013 to Aug 2015, then follows the AEO scenario. The point being that futures prices are already being used over the short term, as far as I understand, futures prices for 2033 do not exist.

             On the annual discount rate, your criticism was based on the WACC for all oil firms of 8.6 %. Two concerns would be that this would vary from small to large firms (generally being lower for smaller firms) and as you are WELL AWARE is not the appropriate metric anyway, we should be talking about MCC (marginal cost of capital). Generally the MCC>ACC, so we would expect the MCC for smaller oil firms to be higher than the WACC for all oil firms.
             I agree with the criticism that using real costs and revenues eliminates inflation so the discount rate should be lower by 2.5 % for inflation (2.4% is the average inflation rate since 2002). Oil industry guy tell me 10 to 15% discount rates are usually used in the analyses they see, lets say 12.5% makes sense. Those analyses are no doubt in nominal terms so my analysis should use 10 % to account for using real revenues and costs.

             The main point is that although I don’t agree with you in full, I appreciate the criticism, please keep it coming.

             1. I’ll get back to you with some more discussion on the topics. Not meant to be argumentative (or to drive you to change), but since I get the impression you want to chat it out.

                1. Again, Thank you.

                   Not sure if you saw my last comment on page 3.

                   You have certainly given a lot of food for thought.

                   Your feel for prices beyond 2019 would be interesting. As far as I can tell there are no futures contracts beyond Dec2019. Would flat prices make sense to you from 2019 to 2040, continue the trend downward (if the real price was decreasing 2% per year just continue that out to the future? I would make this a low case because although you seem to place great faith in EMH and the implication that futures markets are the best guess, I have reservations. My understanding of the underlying analysis which leads to EMH is that future prices are modeled best by a random walk so that a guess that there will be no change in real price would make sense, that would be my base case and I could use the EIA’s AEO prices as a high case. You are no doubt aware that it is economists that do these AEO price forecasts.

                2. Yeah, I saw it. I’m actually trying to get caught up. I fired off without reading some of your work in full. I really don’t think it changes my remarks much, but figured if I really want to engage I should read up more. So I started with the USGS report. And then had to look up definitions on Wiki. And then realized I was looking at the fact sheet, not the report. 😉

                   For a lot of things, I can anticipate how I will respond: EMH and CAPM are really “orthodox”. Get a little discouraged with having to debate/explain them as (a) I’m not a finance/econ professor (b) you don’t have basic grounding, (c) somehow people think they know more than they really do…on the Internet. All that said, I probably should read the Fed paper before dismissing it (as a singular study versus the bulk of work, ignoring arbitrage arguments, in sample versus TRULY out of sample [i.e. after the paper written], and “do you wanna bet” remarks). 🙂

                   I am finding some interesting things that you will want to probably take a look at, regardless of freshman econ/finance discussion. Like the FEB Continental presentation has some good charts on the chemical makeup of the oil.

                   So…thanks for your kind demeanor, even if we have different views.

47. Great comments Nony, thanks for sharing your balanced view. I also fully support your idea on the importance of the oil price in all this. The USGS report was a very good read.

    1. Thanks man. You have good stuff too.

48. December production was down. Not making any specific point on it (weather was bad). Just sharing the data point, hot off the Internetz.

    http://www.startribune.com/business/245552281.html

49. First greenfield refinery in US in 30 years.

    http://www.vernwhittenphotography.net/wes1113/

    1. (pic 33)

50. DC:

    I may have to go back to work (not in oil), doing some contract consulting. Good for me/society, but much more stressful than playing on blogs.

    Again, good effort and nice model. I meant to take the time to really read through it more and the supporting USGS stuff, but can’t commit to that. In particular, have not had time to think through/parse all the assumptions in structure of the model (what are the input, what are the outputs).

    Some stray parting thoughts (do with as will, sorry if it is a critical “dump”):

    1. Format:

    a. Please hit the carriage return twice for new paras (to get a blank line). Also, separate the figures from text with blank line above and below. (I know a tiny nit, but really this stuff is kinda dense conceptually so walls of text make it worse).

    b. Also, if you perhaps had some block diagram of the model, that would help with the understanding. (Maybe I’m tired, but I struggled to really read it…just fessing up!).

    c. Also a tabular list of inputs: price (t), USGS case, costs, etc. And then a list of calculated intermediate outputs and the final output (I assume that is production (t)).

    d. I think if you had a working Word document (updated as you tweak the model), that would be best. Hard to have all the info in a blog post. But you could link that (perhaps as a pdf, update as needed) and just write a teaser blog post. Or maybe a dedicated web page.

    2. Structure: I think you need more of a full factorial of cases. There’s probably a way to structure this in Excel with a “control panel” (having the inputs) or with macros. I’m not a jock on that, but lots of people are. But 3 cases for price as well as 3 cases for geological would be good.

    3. Price: I would do a high, low, medium case (at least).

    a. A lower than futures based
    b. Futures-based (For the extension, just leave either real or nominal $$ constant. Don’t care which)
    c. Constant real, from now.
    d. AOE medium (current)
    e. An even more doomer one (perhaps AOE high?)

    If 5 is too many, you could chose b, d, e.

    Another option would be something based off of the EIA percent likelihood of price: note this is not an estimate, it’s actually derived from the market options themselves:

    http://www.eia.gov/forecasts/steo/images/Fig1.png

    And I don’t know how you extend it, but intuitively it should keep getting broader, but obviously less than linearly.

    4. Real/nominal:

    a. I think there is some confusion of real versus nominal with you. Options are valued in nominal, not real. They are bought on margin (very high leverage) and are settled with currency at the future time. It’s not like you buy the future option now with today’s dollars. And they’re valued the same way for both the short and long! So, the futures value for 2020 is the market’s guess at what oil will be priced in 2020 dollars.

    b. Also, you had some comments about how real price changed over time in your model, but they didn’t seem to match your figure (which is annotated as “real price”).

    5. EMH: It’s a very fundamental, philosophical thing. And sure, you can find all kinds of papers about people saying they found a flaw in EMH. But how interesting is it to publish a paper that says EMH is right? EMH is really orthodox and has some pretty powerful fundamental reasons behind it (basically arbitrage opportunities).

    I would be leery of isolated industry studies saying that estimates (or constant real or whatever) outperform futures. I doubt they will extend into future performance, but are just happenstance from past statistical variation and cherrypicking/Bonferoni error.

    I really doubt that even an EMH-naysayer econ professor would be willing to step up to the table and put $50,000 on FED paper assumption versus me taking the futures market. Market estimates are like democracy: screwed up, but better than the alternative.

    6. 15% WACC is really high. I mean really, really high for almost any industry. (And it’s ~17-18% since you are using real revenue/cost in your model for the future years and thus double discounting inflation).

    I don’t think it’s a good cost of capital for something as relatively defined as infilling the Bakken basin (which perhaps has an even lower risk than overall industry production…remember it is “mining” and is easily shut down or restarted if price moves…not like a deep water well.) If 8.6% is giving you heartaches, use 10% as a compromise. It’s sort of halfway between the oil production and oil services WACCs. And is within the “Rockman interval”. 😉

    I already said that I don’t think much of company dictated discount rates. I’ve been at a big commodity company and they mandated 12% in their models…but it’s just some stupid big company rule. And NPV models have lots of levers for manipulation (watch me dream up synergies! ;)) You have to assume that over time, industries return their cost of capital no less/no more. That’s the way outside analysis should figure things. (I advocate it also for internal valuations: please see Copeland’s book Valuation which is the bible for this sort of thing and what it says about company discount rates.)

    The Rock has seen some things go down in the industry, knows geology and oil companies. And is very kind to those less knowledgeable and I appreciate him on the boards. But he’s not a economist. So “Rock said so”…well it’s not his area of expertise.

    15% is just really, really mean and harsh. Would not use it for a dotcom. Even if it is not changing the answer much, because of the high well decline rates, it just hurts me to see you using that as an assumption. Just shows a poor “feel” for this sort of thing.

    I have never used MCC and it gets minor mention in Copeland’s Valuation or Brealey and Myers book Corporate Finance. I actually had to look it up (not a case of me knowing well)! Everyone uses WACC for valuations. For companies with optimized capital structures, MCC will equal WACC (I think, based on my recent reading…I am not a finance professor.) I would avoid using the term marginal cost of capital as it can lead to some logical fallacies (for example rating projects versus the source of financing…doing things like saying using own cash flow is riskless, etc.)

    7. Reference price: I sorta like WTI since it also incorporates an estimate of “shut in crude”. And we really do have a situation of shut in light crude. There’s a differential and it is cheaper in the US, than worldwide. I think Brent spot prices are London (not sure).

    Also, it’s just a bit closer in composition to Bakken oil. Although Brent is not bad, definitely a light sweet crude. LLS is the closest, chemically and in refinery yields. From what I read Bakken oil is actually slightly better in terms of value to the refiner than any of them, although LLS is close and we are talking a couple bucks difference.

    There is a reference price at Minnesota pipeline entrance that is probably best proxy for the Bakken overall pricing. I think you have to pay some service for it, though. And I don’t know if it has futures. Really, the thing is complicated with some stuff going by train, pipeline, different coasts, etc. And it seems like companies try to move it around to whoever is best at the time. No strong preference here, just blathering.

    8. Gut feel for supply and demand: I’m wishy washy, with no fire in the belly. More like humility of I don’t have a bias. (Not like the dotcoms or Enron, when I had very strong intuitions and insights that they were way overvalued, with some smoke and mirrors and MBAs thinking their poop did not stink going on.)

    If you’d asked anyone in the 70s if we would crack OPEC and have 20 years of dirt cheap oil, they would have looked at you like you were a Martian. Remember Jimmy Carter’s synfuels project (kerogens)? The oil business has seen booms and busts before. (And from the Texas oil man’s perspective, a bust is not “world running out of oil”, it is “too damned much oil, price crashing”.) I’m not saying it will happen…and obviously a community that calls itself peak oil will be doubtful of that…but you have to factor some chance of it. We have seen things like this happen.

    Then again, price is high now and has been for 6 years. That is very unusual/interesting/sucky for consumers.

    The drop to 40 in 2008 is also curious. Was that a short term belief in long term supply being better? Or was that some aspect of OPEC slipping? Even with a global recession, one would not expect a 140 to 40 drop…because the current price needs to include the long term value of a depleting resource (IOW, better to leave it in the ground).

    I really lack the analysis to say if OPEC is exerting market power (being a functioning cartel) or is pumping full out. IOW, could we have the repeat of 70s to 80s impact (especially with a supportive political regime…remember US oil production at the margin was a big factor in cracking OPEC and getting them to start cheating with each other.)

    Then again, US tight oil came out of nowhere. Sure, Rock can say we knew there would be hard to get oil at high prices…but who drew a prediction curve showing 3 million Bpd (in about 3 years ramp) in the US? No one. So there are just uncertainties. Show me the Gail chart that had the LTO coming in. Or IEA or whatever. No one had it in mid 2000s…all they had was sands. And then Picollo predicted 150-225 M bpd, back in 2008ish. Rune predicted 600-700 M, back in JAN2013. So, just beware predictions from promoters OR from doomers.

    Look at US gas. People were building import terminals for gosh sakes. And the long term futures were above 10. Now the long term futures are 4.50-5. Shale gas really has been a HUGE development and game changer. Much more so than LTO. (And that’s not oil…just my point is, things can change radically…there is uncertainty.)

    I guess my gut is something like 75 real in the far off future. (basically extend the futures price). But with some risk of 30 or 150.

    1. Hi Nony,

       I appreciate you taking the time to do a detailed criticism/analysis. I don’t have time at present to respond in detail, but I may do so later so check back. A few things we continue to disagree about and/or I am not being very clear which I will mention briefly, but much of what you said about format and several price scenarios I agree with, there is definitely room for improvement.

       On gut feel for future real prices we are on opposite ends of the spectrum. I would suggest that oil production will peak at some point (2020 to 2030 would be my guess), I also think that the decline may be relatively slow (1% or less for 10 to 20 years). If that is correct, I would be quite surprised to see real oil prices decrease once oil output stops rising. Perhaps you envision substitutes for liquid fuels making rapid progress so that they fall in price relative to petroleum powered transportation or that there is a radical adjustment in consumer preferences?

       I guess the exercise boils down to whether one believes that the market is always right.

       Have you heard the joke about the two economists walking down the street and they come upon a $100 bill on the sidewalk? As the first economists starts to bend down to pick it up, the second says, “Don’t bother, if it were real someone would have already picked it up.”

       You seem to have sold faith that the futures market gives the best estimate of future oil prices, but during the Enron fiasco and dot.com bubble, you lost faith in the EMH, in the sense that you thought the market had it wrong. I also am unclear with how the EMH explains speculative bubbles, such as the housing market before the financial crisis. There are a lot of economic orthodoxies which seem very right, except in those cases where they are very wrong.

       On real prices, I am not confused, the prices in my chart were for AEO 2013 (with the real oil prices adjusted to 2013$), I used the minimum price up to Dec 2015 and then picked a % increase which closely matched the reference scenario. I did this for simplicity because it did not look like price would be a limiting factor until around 2015, when Bakken oil might peak and lower supply was surmised to lead to higher prices (in line with EIA estimates).

       I have more faith in the economists at the EIA than you.

       Finally why use Brent rather than WTI? Much of the Bakken oil goes to the East and west coast by rail, for oil going to East coast refineries Brent prices are much closer to the refinery gate prices than WTI. So lets say Brent is $110 per barrel, and it costs $12/ barrel to ship the oil to the East coast refinery, the net revenue (before royalyies, taxes, and OPEX costs) is $98/ barrel (which is pretty close to the WTI price), to me the analysis makes more sense using Brent and transport costs, if I used WTI prices, I would eliminate the transport cost, it really is a wash.

       I understand very well that futures are in current dollars. For example Brent future for Dec 2019 is currently about $91/barrel, that is about 6 years away and assuming 2.5% inflation over the next 6 years that would be $78/ barrel in Jan 2013$. If we extend this rate of decrease in price out to 2029 we get $45/barrel in Jan 2013$ and if we extend it out to 2039 we get $26/barrel (this is about a 5 % decrease in real oil price per year, which is the rate of decrease from Jan 2014 to Dec 2019.) Is this what you had in mind for the far future? Or does leaving the price unchanged from $78 in Dec 2019 to Dec 2039 make more sense? We get no guidance from futures markets beyond Dec 2019, and the market is pretty thin for Dec 2019, I think guidance beyond 2015 is pretty shaky.

       See chart below for AEO 2013 price scenarios in May 2013$

51. Forgot Chart sorry

    

    1. looks like a good spread. Fine. Run the model and do the full factorial of price/geology. Should be interesting how date/amount of peak as well as total extraction vary for the 9 cases.

       1. Hi Nony,

          I will probably just do 2 cases, 8.4 Gb (USGS Mean) and 11 Gb (NDIC mean), I could do the 6 Gb case, but I think that is the least interesting. I did a quick scenario with flat real oil prices at $85/barrel and discount rate at 6.5 % (equivalent to 9% if nominal prices/costs were used assuming 2.5% inflation). ERR from 1953 to 2073 ends up at 6 Gb with those assumptions and my other assumptions (well costs fall to 7 million by 2017, royalties and taxes 26.5% of wellhead revenue{which is refinery gate price minus transport costs}, OPEX at $4/barrel and transport costs at $12/barrel.)

          TRR in this case is 8.4 Gb and I used Enno’s data to develop a new well profile, peak is about 1.2 MMb/d in 2017 if EUR begins to decrease by June 2014 and reaches a maximum annual rate of EUR decrease of 14% in June 2015 (these are pure guesses, so far there is no evidence of EUR decrease, but we really won’t be able to see a decrease until 12 months after it begins.)

52. No worries man.

53. Here’s my gut (oops I mean Bayesian estimatation! ;)).

    1. Basically just by eyeballing the 2012 versus 2013 increase. Even without the bad winter and a “normal DEC decline”, 2013 had lower absolute increase than 2012. So, something like:

    2012 increase: 250k
    2013 increase: 175k (if it had been only half the DEC decline)
    2014: increase: 75k
    2015 increase: -50k

    So kissing 1 million bpd in some month of the late fall of 2014, but then finishing just below it. Top calander year, being something like 930 kbpd, 2014

    EOG also notes the lower rise rate in Bakken (see their March investor presentation). Of course, they can preen since they basically kicked everyone’s asses by doing the Eagle Ford in 2010. But still, it’s just evident.

    2. Some soft caveats in the other direction:

    *Rig count for 2014 is starting to increase over 2013. This shows increased investment in the area and probably, given increase pad drilling is actually more activity than one would think. In JAN-FEB2014, I was seeing a pattern for rigs like 2014=2013=180, 2012=200. Last few days it seems more like 2014=190, 2013=180, 2012=200.

    *The EOG presentation (and I sort of trust EOG to be a little less cheerleaderish than CLR/Hamm) talks about new techniques driving back some interest into the Bakken.

    3. Based on gestalt of 1 and 2, I edge myself up and say monthly peak in mid 2015 of 1.1 MM bpd. Peak calendar year is 2015 at 1 MM bpd.

    1. Also, I do think Helms is telling the truth about what companies are planning in terms of continued drilling. Also, EOG presentation says 8 years of drilling remaining in their Bakken acreage.

54. I do think that the post-peak will be more plateu-ish than the peaker meme community would assume. Not a shark fin, not even a “other side of the bell curve”. Rationale:

    1. Even with admittedly steep individual declines, the more time goes by, the more the population starts to include wells that are in lower declines. Imagine a single year of drilling 1500 wells and then stopping cold, versus 10 years of drilling 1500 wells and stopping cold.

    2. There will be some tapering in of less drilling and of drilling marginal wells (lower IPs). Not a stopping cold.

    3. Refracking of select wells. I’m not sure what the criteria will be (the big wells justifying it, or doing them checkerboard to stimulate several wells or some feature of local geology). But I think it will be something like some of the wells justifying refracks…not all, not none.

55. In terms of price assumptions, I think the play is more take-off limited now or just logistics limited. So, while there is price sensitivity, my intuition is that it may not be as readily observed as people think. If oil goes to 150, they can’t ramp up to 50% more production. Similarly if we drop down to 80, a lot of the infill drilling is still profitable, just not as high return. At 60, you would see very significant contraction of drilling. At a prolonged 40, the whole play turns off (we sort of saw this in 2008 already).

    1. take-off, logistics, and geology limited.

       1. Hi Nony,

          My scenarios do account for the lower decline rate of the older wells. In fact the well profile that I use, extends out to 100 years and assumes that once a well starts producing it never shuts down (so it is a little on the optimistic side in that sense). The TRR models assume that economics is not a factor, but that eventually the drilling stops at about 45000 wells or so, this could be increased, but would have little effect because I am assuming the USGS estimates are correct, more wells would just result in more of a new well EUR decrease to keep total TRR at the USGS mean estimate.

          I don’t assume higher prices result in a take off in production, just that the number of wells added would decrease more slowly if prices were higher because drilling would be profitable for a longer period. Once profitability per well gets below about $1 million (2013$) per well the number of new wells added are decreased gradually so that profits remain positive for each average new well added. The only way a plateau could be maintained is for prices to move higher, you think that prices will not move higher (judging by futures prices), so a plateau would be unlikely unless the refracking of wells becomes important. This is certainly a possibility, I believe it is probably on the order of 3 to 5 million dollars per well and the question is how much of a return in increased output would result, I do not know the answer to this question, perhaps some of the investor presentations you have looked at would shed some light. My models do not account for this effect and I do not know if it will be of great significance going forward. I might be able to get Enno to dig some of this (refracking data) out of the NDIC data, so it is definitely worth looking at.

          On the infill drilling being profitable at $80/barrel, that depends on what the EUR is for the infill drilled wells, at $85 (2013$)/barrel you need about 200 kb 30 year EUR for breakeven at a 6.5% discount rate, this might work in the best sweet spots, but there is not unlimited space for infill drilling. At $60 (2013$) I think things shut down.

          Note that the parts of my curves that are sharkfin-like are where profits are zero for new wells. I assume (perhaps incorrectly) that these companies are not in business to lose money, if expected profits ore zero or negative, new wells will not be drilled.

          I could try to create a case where a plateau is reached, but it would require prices that are not at all in line with the futures market. In fact the AEO reference scenario that you thought was unreasonably high, did not result in a plateau, though perhaps with a lower discount rate it might.

56. Those comments were just totally gut, DC. Not really even going off of your model. And when I say plateu-ish, I mean “ish”. More reacting to the doomers who think it will turn off like a light switch, will decline fast as it grew.

    I think if refracking were going to be huge, we would already be seeing more of it. For instance with companies that have limited acreage and got in early.

    Couldn’t find a lot on Google, but here is one article:

    http://www.thebakken.com/articles/274/redefining-the-bakken (scroll down)

    But, I think that the insight about gas is interesting. It seems like much more shale gas plays are working out than oil and that refracking works there and we really can just hold NG long term at sub-5 $. It’s a much easier molecule to wander around though. So, not a lot of confidence that it works out as easy.

    Here’s some blogging about re-fracking, but note the wells are basically failed wells or single fracks. I think that is pretty different than refracking a normal well and will just help a little:

    http://themilliondollarway.blogspot.com/2013/12/re-fracking-in-bakken-case-studies-with.html

    If you go to one of his linked earlier blog posts and read down into the comments, there’s a lot of talk about costs. I would imagine it is pretty similar to an original frack, but then again, they are doing the super-multi-stage on wells that only had single frack from a long time ago. If you refracked a multistage well, could you use less stages on second time? Donno.

    1. Another negative view on refracks:

       http://bismarcktribune.com/bakken/oil-gusher-draws-attention/article_0b25e29e-7ad6-11e2-bcb7-001a4bcf887a.html

    2. Hi Nony,

       I think I know less about the refracking than you. I did not assume you based your comments on my model, which is hard to figure out for most. The TRR part is relatively straightforward, I take an average well and assume at first (from 2008 to 2013) it does not change over time (an approximation which works pretty well from 2010 to 2013 based on Enno’s data). It is also assumed that all wells are average wells. From the NDIC we know how the number of producing wells changes from month to month, for simplicity I assume that no wells are shut down in the Bakken so if 10 wells are added in Jan 2008 I assume production from those 10 wells is 10 times the average well from the first month until month 1200 (where the output from these 10 wells declines over those 1200 months), if 12 new wells are added in Feb 2008, I follow the same procedure, and I do this for all 72 months out to Dec 2013.

       Then the guessing begins about the future, lately I have been assuming 175 wells will be added each month and I have assumed the EUR of the average well decreases starting in Dec 2014 (this is an arbitrary guess) and the rate of EUR decrease gradually increases to a 14.5 % annual rate 18 months later( also arbitrary) and the 14.5% rate of decrease in new well EUR is chosen to make the TRR match the USGS mean.

       When attempting to determine economically recoverable resources the price, well costs, discount rate, taxes and royalties, OPEX, and transport cost assumptions are used to find the net present value of future cash flows from an individual well’s production. This is compared to the real well cost, if NPV>well cost then profits from that well are positive (point forward basis). As EUR decreases due to sweet spots running out of room, profits approach zero and fewer new wells are added, this is what causes the decline on the other side of the peak. If there is no EUR decrease, the plateauish scenario would be correct. A rise in oil price would also mitigate the decline because the rise in prices would help to offset the decrease in EUR.

       Scenario below uses AEO 2013 reference case oil prices and a discount rate of 7.5% on the USGS mean TRR case of 8.4 Gb, ERR is 7.8 Gb and is plateau-ish up to 2021, but prices do not rise fast enough (about $105/barrel in 2021) to keep profits positive and wells added decrease in response (note change in slope of # wells curve).

       

       1. Might be like that. Like mining a vein of ore. Once you’re done, you’re done. And a step change drop down.

          175/month sounded a little high. I get 148/month in 2012 and 2013 from the ND pdf on monthly statistics. I just took the DEC wells working for each year, then subtracted from previous and divided by 12 (Hope this formats over OK.)

          Year prod wells delta well/mo
          2007 446 na na
          2008 868 422 35
          2009 1332 464 39
          2010 2064 732 61
          2011 3275 1211 101
          2012 5048 1773 148
          2013 6824 1776 148

          1. Hi Nony,

             I am more of an optimist than you realize, I thought wells/year would continue to increase (to NDIC mean forecast) to about 2100 wells/year. As your table shows the trend has been up, but perhaps 1800/year is as high as it will go.

             I didn’t want to be accused of being a pessimist,I was going for something realistic. Are you doubtful that wells per year will increase in the future? Note that I use atual data through Dec 2013, 175 wells/month is for Jan 2014 to about August 2020 in the 7.8 Gb ERR scenario. The natural gas assumptions are that if offsets interest costs, this is only an approximation, but works approximately for Continental, clearly as Natural gas prices change this may not work as well. The model focuses on oil, for the most part the oil companies are not making a lot of money on Natural Gas in ND. The model is far from perfect, but if everything is included it would be a little unwieldy.

             Your point that a Natural gas price increase will change things, is correct, it could result in less drilling for oil (as natural gas becomes more profitable

             1. While I think the last few days blip up of rig count is interesting, I guess I would go with 150/month.

             2. I don’t remember making that point (honest). What I said was that if you just show the itemized one time and per barrel costs, that it will make it easier for people with more knowledge and less time to engage. It’s purely a presentation thing. I just thought if you make it visual, you will get more engagement. No biggie.

                FWIW, I think it would take some rather hefty gas prices to make rig availability a problem in the Bakken. I see summer gas being 4-5 for the next few years.

       2. This is a little “peel me a grape”, but I think if you displayed the capital and per barrel costs and price in some sort of table, that that might make it easier for people to engage and to challenge the numbers (and for you to get insight from people with more info). I would go ahead and explicitly put your gas assumption down in the table (who knows maybe either value is challenged and it’s not a perfect offset).

          1. agree on the presentation, and I misinterpreted your nat gas comment. I see you just want it explicitly in the economic assumptions and think a table would be nice. In the future I will do that in comments it does not work well because pre tags don’t work. I may update at my blog at some point, and could mention your helpful comments if you wish (but you had said earlier you would rather remain anonymous.) If your thinking has changed let me know, I like to give people credit, but also realize that people like their privacy.
             If its on my blog no one will see it 😉

             1. You’re a nice guy. Nah, no attribution, man. You’re doing the work. A little kibitzing is easy.

57. Some commentary on downspacing versus completion skill:

    http://info.drillinginfo.com/well-spacing-bakken-shale-oil/

    a. perhaps you can use it to model lowe production/well.

    b. Interesting the competing factors they see.

    1. Hi Nony,

       On the 150 wells/month, u r such a pessimist 😉

       I have read the drilling info piece, thanks. Interesting that the 2000 foot spacing is about 450 acres if we assume 10,000 foot laterals, this coincides almost exactly with the USGS model which assumes 440 acre spacing.

       As you have pointed out (and I agree), whether 70% reduction in average EUR will be profitable depends a lot on prices.

       1. Yeah, I’m such a pinko peaker. 😉 Not.

          Good point about the downspacing assumptions versus acreage. I have heard multiple people say that interference starts at 2000 ft, so I think the analysis is basically right. My bet is they are pretty serious about doing the downspacing further (enough different companies are looking at it, starting to test it).

          I guess in a simple sense, you can think about it like: I pay for 2 wells ($16 MM) and get the production of 1.5 wells. Is it worth it? The incremental investment (8MM) is only driving the production of 0.5 wells. Probably is if oil is 100 and isn’t if oil is 75.(made up numbers, but that’s how the function works).

          In terms of how companies organize their work, would assume that they will drill the non-downspaced wells first. Better NPV and also, leaves you some optionality (can decide to do the downspacing if price is high or not do it if price isn’t…a couple years down the road.)

          Of course, some of their pad drilling economics work better if they drill them all at the same time (the walking rig and all that). But that’s another trade-off and for that matter, you could drill the well and hold off on the frack until later.

          Whole thing seems a little more like farming, mining than wildcatting. They will have their spreadsheets open and will develop the play to try to maximize $$$, with a lot less uncertainty about geology than normal (it’s a continuous sheet of rock). When these different companies talk about their multi-year plans, I really believe them now. (And that doesn’t mean the plans can’t change based on price, learning, etc. But they really are thinking about development through at least 2020.)

          1. Hi Nony,

             The mining analogy is not perfect in the following sense, although there are not a lot of dry holes, the productivity of individual wells varies a lot. I simplify my models by assuming all wells are average, but if you look at the USGS Bakken well EUR chart below, you will see that (except for the Elms Coulee-Billings Nose and Northwest transitional in Montana) 80% of the wells are in the 100 kb to 500 kb EUR range with a median around 300 kb.

             So there is some risk {unless they are only going to drill high producers 😉 }, you lay down your $9 million for a well and you might get 100 kb or 500 kb, mining for coal may work this way, but I don’t think so. I think the upfront investment to find the coal may be smaller.

             Bottom line, just because there are very few dry holes does not mean there is no risk, though probably less risk than conventional(though I think with modern 3D seismic the risk is much lower for conventional these days than in the past.)

             

             1. OK and agreed. But from a corporate perspective it doesn’t matter that much. They’ll try to optimize every hole, but the bean counters will just be fine with the overall population of good/bad wells. It’s not like doing a mega-project with significant uncertainty about the development itself. Maybe it’s more like life insurance where some people die early and some don’t. 😉

                P.s. According to Helms, 85% of the holes are financially productive at current pricing and down spacing.

                1. I concur. Less risk than a megaproject, but with volatile oil prices, possible future decreases in new well EUR, and no guarantee that any individual company’s wells will be average or better, a real rate of return at close to S&P 500 long term returns seems a pretty thin margin. I am not a finance professor either, but it seems on the optimistic side, no?

                2. I wouldn’t worry about if it is grim or ungrim, but just do your analysis how you’ve been doing it. At the end of the day, they are not going to produce oil that is uneconomic to produce (do negative NPV projects) nor will they leave oil in the ground that is economical to get out (leave positive NPV projects undone). Pulling too much oil out is burning capital. Leaving too much in is leaving money on the table. I think your general approach is fine.

                   I wouldn’t feel bad for the companies doing this work, currently. The ones who got in at the beginning took a risk and wrapped up acreage that is paying off for them handsomely. The people that own those mineral rights are becoming millionaires. And people (from roughnecks to engineers to managers) are earning a living.

58. Hi Nony,

    A quick scenario with 150 new wells per month from Jan 2014 to Nov 2021, with wells added reduced after that, peak 2017 at about 1.1 MMb/d and ERR=7.8 Gb from 1953 to 2073. Using same assumptions as scenario above for economics, TRR= 8.4 Gb, and max annual rate of EUR decrease is 11.3%. Note again I use AEO 2013 ref scenario for real oil prices and 7.5% annual discount rate. See chart.

    

    1. Thanks. They are all looking pretty similar to me. 1-1.2 MMbpd peak, and within next 1-3 years. Production less than 500 M bpd about 10-14 years from now.

       Not to make your life harder, but I would think that if the geology is the same, but you lower drilling rate should move the date where the wells start dropping in IP to be later. After all, you left some oil for later. Not sure how you are modeling that. Probably something like making the well quality decrease a function of total extracted or of well areal density.

       1. Hi Nony,

          The model is not terribly sophisticated, but I did think of that. See chart below. And then look at my explanation.

          The chart shows new well EUR (blue line and left vertical axis scale) and the annual rate of decrease in new well EUR. It is assumed that the rate of decrease in new well EUR increases from 0 to 11% over an 18 month period and then remains fixed at that level while wells continue to be added at 150 wells per month.

          In late 2021 as profits decrease fewer wells are added and the rate of decrease falls to about 4 %. This coincides with a drop in new wells added from 150 wells/month to 50 wells per month so the rate of decrease in new well EUR also drops by a factor of 3.

          In reality it is unlikely to be so simple, but that is how I did it. In simple terms, if the addition of 100 new wells per month results in a 10% annual rate of decrease in new well EUR, then the addition of 50 new wells per month should lead to a 5% annual rate of decrease in new well EUR.

          

          1. OK. (we crossposted) I would actually code it together though. So, if you vary the new well rate for whatever reason than it just ripples through as a function. Should be just connecting the sheets of Excel.

59. Hi Nony,

    Another scenario with a new well profile based on Enno’s data and with real oil prices at $80/barrel (2013$) from Jan 2013 to Jan 2041, note that these low prices only effect the scenario after 2018 (oil is profitable at $80/barrel up to mid 2018). Also EUR decrease begins in June 2014, and reaches maximum annual rate of decrease of 13% in June 2015. TRR is 8.4 Gb, economic assumptions same as always, except price as noted above and discount rate is 7.5% (same as scenario above from 3/3/3014).

    Also note that the new well profile is higher than previously. In earlier scenarios EUR=354 kb, the new well profile has EUR= 389 kb. Peak is about 1.1 Mb/d in 2017, but ERR=5.5 Gb from 1953 to 2073 vs 7.8Gb using the AEO 2013 reference oil price scenario. So prices make a big difference, as you and others noted.
    Chart below.

    

    1. On a meta level, they are all looking pretty similar, DC.

       I think you ought to make the EUR decrease for new wells less deux ex machine. If they drill slower for logistical reasons or even economic ones, then that leaves more oil in the ground. I guess there are a couple things happening with time: movement into the non-sweet spots (marginal wells) and downspacing in the sweetspots (also marginal wells). I really don’t think it would take much work to make your EUR decrease function just be a function of the oil extracted.

       If you slow down the drilling, but leave the well quality decrease the same, that makes no sense. I don’t know if you are doing this, but if so…

       ***

       Anyhow, I guess it points out the importance of the EUR decrease assumption within your modeling. I think the more you can go back and bulk that up the better.

       And I wouldn’t feel bad about that. It’s very normal in M&A modeling (valuations) to start out with a very simple model. One with some back of the envelope calcuations (e.g. revenue increasing at 3% or whatever). Then you make it more complex with time (maybe show the different segments). And you start adding in facts where there were guesses (or at least analyses where there were guesses, even commissioning some market research or the like).

       It really is an iterative process. At least how I’ve done it. And you can direct more attention to refining the model and researching the factors of most importance.

       There’s kind of some good reasons for doing this:
       *It (hopefully) gives you a better knowledge of the NPV as you build complexity and layer in real inputs.
       *Even if it doesn’t, just constructing the thing and researching the factors teaches you things about the business, the industry that are useful for operations.
       *It gives you a quick answer in case you need a quick decision.
       *It settles down the managers and the valuation team so they are not spinning their wheels and getting analysis paralysis.

       ***

       Sorry for the segue and not completely relevant. But I have a didactic bent 🙂

60. Do you know why Continental decline curve is so much bigger than USGS? I think USGS curves were like ~300. And Continental’s is 600. (I think EOG is 550). Is it lateral length difference? Producers being overly optimistic (or the converse, govt too negative?) Or that Continental/EOG have better acreage (IOW curve similar but IP higher)? Or something about USGS assuming downspacing and producers looking at current spacing?

    I’m also interested if there is any info on how decline curve varies by initial IP or area or completion rate. IOW, is the curve itself the same, just with different start points.

    I think a lot of insights are driven from vertical wells from the 50s, but not sure how much these can tell us about b factor and matrix production and the like (but perhaps they can). Also was wondering about Montana production. I realize that is a little passé now, and that the completion technology has improved. But there is a longer shale play history there, so can we maybe get insights just about curve shape (IOW this whole issue of the change from hyperbolic to exponential, matrix production, when does it happen).

    1. Hi Nony,

       I don’t know what Continental or EOG’s decline curves look like. In the past I looked at the decline curve published by the NDIC, and when it is used in my model (replacing the decline curve based on actual data from Rune Likvern or Enno Peters) the results are not good see

       http://oilpeakclimate.blogspot.com/2013/04/bakken-model-suggests-7-billion-barrels.html#more

       and chart below.

       My guess is that the decline curves for a “typical well” should really be called “a very good well”, so they are optimistic. I think the USGS took data from all wells and estimated an average decline curve, note that the mean EUR in the best assessment unit (AU) in the USGS study was about 360 kb for an EUR30 (30 year), the other AUs were about 250-300 kb. The well profile that I use keeps changing as I get better data from Enno Peters, but the latest has been about 350 kb (and previously it averaged between 350 and 400 kb).

       Note that your insight about well profiles from older wells is correct, they probably do not apply.

       Also we only have decent data from 2008 to 2013, so beyond 5 to 6 years we are really guessing as to what the decline rate will be. Montana might provide some insight, but I haven’t seen any data.

       Finally, there is the issue of more and more frack stages being used as time goes on, at some point the law of eventually diminishing returns may kick in. I have read about some wells with 60 frack stages (I don’t know how common this is), at some point the extra cost does not result in enough extra output to justify itself, but I do not know where this point is and whether it has been reached.
       All of this (and eventually running out of room in the sweet spots) makes the “average well” a moving target which is pretty hard to hit.

       On the 1/b exponent of the hyperbolic, based on older wells, keep in mind that Art Berman has used this type of analysis for years on the shale gas plays, with good success. The LTO plays could be different, but I doubt it as the same model was used for conventional oil and gas, now extended to shale gas, and likely to give relatively good results for LTO as well.

       But I am not a geologist or geophysicist, so I could be wrong.

       see next comment for chart.

61. Chart that I forgot is below

    

62. I think USGS says that they assume a shift from hyperbolic to exponential. anyone modeling it as purely hyperbolic is probably being too harsh. I was watching a video of Art Berman and he seems kind of mean to the shales. 😉 Also, with gas, they apparently do have enough data and they really do see the two step model. Rocks says there is no production from the matrix, but USGS and other sources talk about matrix production “when it turns” (goes exponential). I don’t think any of that changes your work, since you are using USGS numbers anyways.

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