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Mark Anthony
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Mark Anthony, is an IT professional and who had a scientific research background before joining the information revolution. Visit his blog: Stockology (http://stockology.blogspot.com/)
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  • The Real EUR Of EOG's Bakken Shale Wells

    SA author Michael Filloon wrote on the Bakken shale wells of QEP Resources (QEP). He projected an EUR up to 2 million barrels of oil equivalent. I disagree with his calculation. Real production data does not support his conclusion. I pick the first well listed in his article, No. 16637, owned by EOG resources (EOG), for a case study.

    Modeling Shale Well Declines

    Traditionally natural gas (UNG) producers use the classical Arps formula to model a conventional oil or gas well's production decline.

    As I discovered, and as many people pointed out, the classical Arps formula is not suitable for projecting shale well's decline patterns, as shale wells decline much faster than the formula projects in the long term. Specifically the terminal decline of Arps formula approaches zero, and the cumulative production it projects approaches infinity with a b-factor larger than 1.0. That's problematic, as in the long term, shale wells should decline a terminal decline rate above zero.

    Let's re-cap about the classical Arps formula and how I modified it:

    (click to enlarge)

    I am happy to find out that even though most producers insist on using the classical Arps formula, QEP does use the SAME modified Arps formula with a terminal decline term introduced. In that sense they agree with my own modeling method. I congratulate management of QEP for being a little bit more honest than Chesapeake (CHK) and Cabot Oil & Gas (COG).

    But even QEP used the same correct modified Arps formula as I do, and admitted a reasonable terminal decline rate, they still pushed for a set of parameters that gave a higher EUR (Estimated Ultimate Recovery) than what is realistically possible.

    Modeling Bakken Well No. 16637

    I extracted monthly production data from ND DMR web site. I did the calculation on a spreadsheet. Here are the comparisons. Note that both QEP and I used the same formula with four parameters: IP, D, b-factor and terminal decline rate Beta. I just disagree with QEP on what parameters provide the best fit. Here is QEP's model:

    (click to enlarge)

    According to the chart, here are QEP's parameters, versus mine:

    • QEP adopts IP = 724 BPD, D = 0.0035/day, B = 1.80 and Terminal decline rate Beta = 0.000228/day
    • I adopt IP = 1250 BPD, D = 0.020/day, B = 1.80 and Terminal decline rate Beta = 0.000280/day.

    Both QEP and I use the same b-factor of 1.80. I use slightly higher IP, slightly higher terminal decline rate beta. But the biggest difference is that QEP uses an extremely low initial decline rate, by the shale industry's standard. I think there is no justification for using such a low value of D. Shale wells decline extremely fast in the first few weeks. Other producer use a D ten times as higher.

    As I said, I agree with QEP in the formula used, I disagree with them in the specific fitting parameters. Let's see who fit the data better:

    (click to enlarge)

    It appears to me that my curve fit the actual production data much better. The QEP curve does not fit the well data very well.

    My speculation is that they know that they need a flat curve to obtain a higher EUR value. The more flat the curve is, the higher EUR it will calculate. Thus they probably deliberately pull the IP down to a much lower starting point.

    To compensate for a lower starting IP, they adopt a much smaller initial decline rate D, which makes the curve flatter.

    Finally, to further flatten the curve, they tried to fit the artificial local peak of production, at April and May of 2008, which resulted from re-fracing operation (re-stimulation). I believe the cur should follow the non-disturbed natural decline trend, instead of following the artificial temporary boost of production, to be realistic.

    The chart above shows that my curve following the real production down closely, while the QEP curve deviate on the higher side.

    (click to enlarge)

    The above chart, plotted in much longer time scale, and using logarithm scale, shows the deviation much better. Once again, my curve tracks the actual production data very closely. But the QEP curve clearly deviates from the real data and projects too high.

    As a result, when you integrate the cumulative production over time, QEP's curve would over-estimate while my curve gives the accurate projection. See below:

    (click to enlarge)

    As shown above, my parameters leads to accurate projection of the actual production. The QEP curve clearly deviates on the high side.

    I projected that the EIR of well No. 16637 will likely be 500 MBOE. The QEP projection is 750 MBOE. The chart clearly agrees with me.

    Calculation and Discussion

    As of now, the well 16637 is a bit more than five years old, and has produced an accumulative 355.280 MBOE. Current production rate is 80 BOE/day. Current annual decline rate is -16% to -22%. Using -18% annual decline, and using 10 BPD as cut off, the well will produce another 145 MBOE, bring the total EUR to 500 MBOE.

    This well is NOT a typical or average Bakken shale well. If it is, even if the EUR is only at 500 MBOE, producers would make an incredible profit at $100/barrel oil price. Unfortunately that is not the case. The average Bakken shale well has a much lower IP and much lower EUR, even if they are equally cost to drill.

    As of October 2012, there are 6349 producing Bakken shale wells. They collectively produced 821.30 MBOE/day. There are 6077 wells which were also producing in September, and 272 new wells which first show up in October. The 6077 wells producing in both months collectively declined from 790.33 MBOE/day to 715.820 MBOE/day from September to October, or -9.5%/month. That is a daily decline rate of /month, or -0.33%/day. At this decline rate, these well's future production will be equivalent to 1/0.33% = 303 days worth of production at current rate of 716 MBOE/day, or 217 million BOE. Divided by well numbers, each well has an average of 35.7 MBOE remaining production. That does not look like a lot of value to me. At $90/barrel, that's a remaining production value of $3.2M each.

    Good luck drilling every well as productive as No. 16636, producers!

    I repeatedly pointed out that shale oil and gas producers tend to over-exaggerate productivity of their wells, under-estimate the well declines, and under-calculate the fair capital amortization cost, in order to pitch their investment case to banks and investors, so they can keep borrowing more money to keep drilling shale wells.

    In reality, even Bakken shale oil wells are hardly profitable at current oil prices and current development costs. My advice to investors is to do your own due diligence research and scrutinize the data. Avoid the hyped shale oil and gas sector. The sector you should get into, is the US coal mining sector. The meme that natural gas is replacing coal, is completely wrong. Natural gas will always be an important part of America's energy supply. But at fair cost, shale gas can not compete with the cheap king coal.

    The investment case in coal is made better as nearly 99% of investors made the wrong bet, as there is 75 times more market capital invested in the NG sector than in the US coal sector, while both sectors contribute about equal energy to the US economy.

    Imagine what happens when the looming debt crisis in the NG sector unfold, and shale gas production collapses, sending prices of both NG and coal much higher, and 75 more market capital in the NG sector now moves to coal sector instead. This is not an opportunity you get to see every year. Now is the best time to get into coal.

    Disclosure: I am long JRCC, ANR, ACI, BTU.

    Jan 08 10:10 PM | Link | 8 Comments
  • Financial State Of The Natural Gas Industry

    In the US natural gas (UNG) industry there are numerous players. Most of the producer are actively involved in the shale oil and gas development. What is the collective financial performance of the shale development industry as one group?

    I decided to survey a group of shale gas developer to sum their financial data together into one collective financial statement, including cash flow, income statement and balance sheet. The data comes from Yahoo Finance. I wrote a computer program so that I can retrieve and tabulate tens of thousands of data items at a click of a computer button, without spending hundreds of hours.

    The Collective Financial Statement of 30 Shale Gas Developers

    Here is the result I got after tallying everything together into three tables: cash flow, income statement and balance sheet:

    (click to enlarge)

    I picked the companies from NGSA's top 40 NG producers list, with big oil and foreign names removed. The 30 companies surveyed are:

    1. Chesapeake Energy (CHK)
    2. Anadarko (APC)
    3. Devon Energy (DVN)
    4. Southwestern Energy Co. (SWN)
    5. WPX Energy Inc. (WPX)
    6. EOG Resources (EOG)
    7. Occidental (OXY)
    8. Apache (APA)
    9. Ultra Petroleum (UPL)
    10. QEP Resources (QEP)
    11. Cabot Oil & Gas (COG)
    12. EQT Resources (EQT)
    13. Exco Resources (XCO)
    14. Range Resources (RRC)
    15. Newfield Exploration (NFX)
    16. Noble Energy, Inc. (NBL)
    17. Pioneer Natural (PXD)
    18. Marathon (MRO)
    19. Cimarex Energy (XEC)
    20. SM Energy Company (SM)
    21. Plains Exploration & Production Co. (PXP)
    22. Quicksilver Resources (KWK)
    23. Forest Oil (FST)
    24. Linn Energy (LINE)
    25. Energen Resources Corp. (EGN)
    26. SandRidge Energy (SD)
    27. W&T Offshore, Inc. (WTI)
    28. Unit Corporation (UNT)
    29. MDU Resources (MDU)
    30. Stone Energy (SGY)

    Further, the production data is not shown in the above table. The total NG production rates of these 30 companies are listed below:

    (click to enlarge)

    Let's have a look at the numbers.

    What kind of Numbers Can We Trust?

    I repeatedly warned people that NG producers routinely over-estimate EURs (Estimated Ultimate Recovery) of their shale wells and grossly under-calculated the fair amortization of their capital expenditures in developing shale wells. Productions from shale wells fall far below projections in the long term, as wells decline faster than projected by the classical Arps formula. Drilling shale wells is very capital intensive. Producers love to pitch rosy pictures in order to attract investment money and bank loans so they can continue to drill wells. How do we know if the industry is realistic or not in making those long term production projections?

    We cannot look at just the models. Any one can propose a model and cherry pick good wells to show how legitimate these models are. We cannot look at just the shale wells that producers pitched in their press releases. Out of tens of thousands of wells drilled, there are always some wells with exceptional performance.

    What numbers told by producers can we trust?

    We need to look at the totals with little room for fuzzy math. If you look at just a subset of the data, those numbers could be carefully selected and tailored to make them look good. But the company-wide or industry-wide numbers, the totals that the producers file in their SEC reports, are more reliable.

    If a producer says that one rig drills one will in 6.5 days and costs only $3.2M per well, and that the wells have an initial production of 750 BOE/Day, I will hold these numbers with skepticism. There are too much fuzzy room in how they come up with such averages. The "average" numbers can not stand up when they are checked against the total figures. Ask them: If one well costs $3.2M and they spent $500M in capital spending, shouldn't there be 156 new wells? Why there were only 80 completed? If 80 new wells each brings in 750/Day, production should gain 60 MBOE/Day. Why it gained only 4 MBOE/Day quarter-over-quarter? And so on.

    If they say that they have 22 rigs in operation; completed 80 wells in the quarter; and incurred capital spending of $500M; and that production grew from 66 MBOE/day to 70 MBOE/day. Such numbers are more likely accurate. These totals have no room of manipulation. They must be reported as they are. If they spent $500M, they cannot claim they spent $400M or $600M. If they completed 80 wells, they cannot say 79 or 81. If production was 66 MBOE/Day, they cannot say it was 67 MBOE/day.

    So I spent time to get the total figures in the two tables above.

    Data Analysis and Discussion

    The 30 companies listed produced gas at 20.874 BCF/day in Q2 2012, versus the US total of 68.9 BCF/day. So they represent 30% of the US NG production sector. But these 30 companies represent almost the entire US shale gas industry, as they are picked from the top 40 US producers, with only a few big oil companies removed. The total gas production from these producers was 20.874 BCF/day. That roughly equals to total US shale gas production, 26 BCF/day, minus royalty payments of about 20%, or 5.2 BCF/day.

    Total capital spending averaged $225.866M/day in 2011, and increased to $243.253M/day in first half of 2012. How much production gain did they achieve after such heavy spending?

    In one year from Q1 of 2011 to 2012, production increased from 18.997 BCF/day to 20.413 BCF/day, a gain of 1.416 BCF/day. The average daily gain is 3.88 MMCF/day. That is a rather modest production gain for an average of $226M/day capital spending.

    In first half of 2012, production went from 20.345 BCF/day in Q4 2011 to 20.874 BCF/day in Q2 2012, gaining 0.529 BCF/day in 182 days. The average daily gain is 2.91 MMCF/day, thanks to the $243M per day capital spending.

    That's $83.50 spent to gain just one CF per day production. You read it right, one cubic feet per day. At $3.35 per thousand cubic feet today, $83.50 can buy 24925 cubic feet of gas, or 68 years worth of production at 1 CF/day. The new production of any shale well hardly last 2 years, let alone 68 years. As I summarized before, a shale well likely will produce about 500 days worth of production at its IP (initial daily production) rate.

    Of course, the bulk of $243M spent per day does not contribute to production gain. It was spent merely to bring in new production to counter the decline from existing wells. Let's calculate how much is spent maintaining the production, and how much is spent growing it.

    Using my 500 days rule of thumb, or -0.20%/day collective decline, the existing 20.6 BCF/day (average of H1 2012) production rate will lose 0.20% per day, or 41.2 MMCF/day. Net production gain is 2.91 MMCF/day. So new production must have brought in 44.11 MMCF/day capacity, with 41.2 MMBCF/day lost to the declines, resulting in a net gain of 2.91 MMBCF/day. But $243M/day spent to gain 44.11 MMCF/day new production capacity is still expensive. Since the new capacity will bring in a lifetime production worth 500 days of initial production rate, 44.11 MMCF/day is worth 22 BCF.

    The capital cost of the gas is $243M/22BCF = $11.05/mmBtu!!! The shale gas industry loses money at gas price below double digits!

    Conventional Gas Wells vs Shale Gas Wells

    How did the US NG Industry fund the shale gas development if it is such a huge money losing adventure? The answer begins to emerge once you look at the US conventional gas production:

    (click to enlarge)

    For years, the US NG industry has maintained flat conventional gas production at roughly 1500 BCF/month. But it started to decline in 2007 at a rate of losing 7% per year. The NG industry was able to maintain flat conventional production by continuous conventional gas well drillings, as shown in the chart below:

    (click to enlarge)

    From 2000 to 2008, the industry was adding an average of 15,280 conventional wells per year to maintain conventional gas production at a flat 1500 BCF/month. That averaged 42/day new wells to maintain 50 BCF/day production. Based on fair replacement, each conventional well has a lifetime production of about 50/42 = 1.25 BCF. The decline rate of conventional wells after 2007, was 7%/year, or -0.02%/day. On each day existing conventional wells lost 0.02%*50 BCF/day = 0.01 BCF/day. The lost production is replaced by 42 new wells. So the well IP (initial production) was (1/42)*0.01 BCF/day = 0.238 MMCF/day:

    • Conventional wells have an effective IP of 0.238 MMCF/day.
    • The initial decline is much less steep than shale wells.
    • They settle to the long term slow decline much faster.
    • Collective decline of all conventional wells is -0.02%/day.
    • The well has an EUR=1.25BCF, or 5000 days worth of IP.
    • Drilling cost is much cheaper. You only need to drill a hold straight down. No horizontal laterals to drill. No fracking.

    Let's compare those metrics with the shale gas wells:

    • Shale wells have a typical IP of 3.0 MCF/day.
    • They start with very steep decline for a year or so.
    • After the initial decline, the decline rate slowly drops.
    • Collection decline rate of all shale wells is -0.2%/day.
    • The well has a typical EUR = 1.5 BCF, or 500 days of IP.
    • Drilling cost is much higher than conventional wells. You have to drill the horizontal laterals. You have to do multi-stage fracking.

    Here are the differences. Shale wells have remarkably high IPs ten times higher than a conventional gas well. But they also decline ten times faster. So by the end of their life cycles, shale wells do not deliver much higher EURs than conventional gas wells.

    Capital Destruction in the US NG Industry

    It puzzles me how the US NG industry manage to fund development of shale gas for these years, if the adventure is deeply unprofitable?

    Let me return to the collective financial statements of the top 30 USNG producers as presented above. Let's look at the cash flows from beginning of 2009 to end of Q3, 2012, or for 3.75 years:

    • Capital expenditures were $265.539B, or $194M/day.
    • Cash flow from operations $224.590B, or $164M/day.
    • Cash flow from financing was $47.441B, or $35M/day.
    • Cash and cash equivalent change $6.79B, or $5M/day.

    So the Cash flow from operations were short $30M/day to fund the well drillings and developments. The deficiency was funded by net borrowing and stock selling to the tune of $35M/day.

    But that is not the entire picture. The $224.590B net cash from operations, or $164M/day, sounds like too high to me. These 30 producer produced an average of less than 20 BCF of gas per day. According to EIA, well head gas price during those 45 months averaged $3.72/mmBtu. So producers took home no more than $74.4M/day from gas sells, not including operation costs and SG&A. How did they report a net positive cash flow of $164M/day?

    The operating cash flow is much higher than gas sells revenue as producers have revenues from oil and from foreign businesses. Take Apache for example. APA received only 45% of its revenue from N. America operations. The other 55% comes from overseas. Yet APA spent 62% of its capital expenditure in NA, only 38% overseas.

    Here is the problem, the conventional oil and gas, and foreign operations are profitable. But the profits they generate is not spent to grow the profitable business. Instead they are spent to grow the unprofitable US shale projects.

    The profitable portion of business does not receive the capital it needs to maintain and grow business. So the profitable business is shrinking. Instead, money is spend to grow the non-profitable US shale projects. Good money is thrown after bad money. This can be seen from APA's Q3 2012 result compared with one year ago:

    • Total oil production dropped from 343.4 to 341 MBOE/day.
    • Foreign oil production dropped from 210 to 192.9 MBOE/day.
    • Domestic oil production grew from 120.4 to 133.0 MBOE/day.
    • Most of the growth happens at Bakken (7.9 to 17.0 MBOEPD) and Permian (51.4 to 60.8 MBOEPD).
    • The really profitable part of APA's domestic oil play, GOM shelf, dropped from 45.1 to 38.6 MBOE/day.

    What did APA gain in allowing its profitable part of business to decline, for lack of capital investment, as they spend the capital instead to grow the non-profitable Bakken and Permian plays?

    The same problem exists in the entire US NG industry. Conventional gas is still the bulk of US gas production, contributing 40 BCF/day. Shale gas contributes 26 BCF/day. But my previous chart show that in 2007, the industry completely abandoned its decade long efforts of drilling conventional gas wells to maintain flat production. They turned their entire effort to drill shale gas wells, leaving conventional wells to decline at 7%/year.

    Mean while, as conventional gas wells continue to decline as they receive no capital spending, they still generate a lot of revenue. That revenue is spent to subsidize the shale developments.

    This is throwing good money at bad money. This is capital and value destruction. How much good money do they throw away? When the industry stopped investing in conventional gas (CG in brief) plays in 2007, the CG sector produced 50 BCF/day and declined at 7% annual rate, or -0.02%/day. At that decline rate, the existing CG wells can produce 50/0.02% = 250 TCF of gas before they are depleted. At $4/mmBtu of gas price, those CG assets are worth one trillion dollars of future revenue, at only little cost of maintenance. Today, CG production dropped to 40 BCF/day, with 200 TCF of gas remaining, or worth $800B. The CG sector already generated $200B of revenue which was wasted in the shale plays with no profits.

    The NG industry is on an unsustainable path of capital destruction.

    Investment Implications

    There is an ongoing capital destruction in the shale industry. It will lead to production collapse in the near future, which will send gas price much higher. But what kind of gas price will allow the shale industry to generate $243M cash flow a day, net of costs, from 20 BCF/day worth of shale gas production, in order to maintain current capital spending at $243M/day? The gas price need to be in the double digits. Will such gas price be sustainable? I doubt it.

    Investors are better off staying away from the NG sector. Do not be lured back into the NG sector just because gas price is going higher. The sector that will benefit most from the capital destruction in the NG sector, and from rising gas price, is the US coal mining sector.

    I have urged people to buy coal stocks for a long time now. The current setup for a big coal rally is much better than the conditions existed at the onset of the 2007-2008 coal rally. This time it will bring more profit to people willing to hold their coal positions firm.

    Based on the first 11 months data, China will import 265M tons of coal in 2012, up 45% from last year's 182.4M tons. The naysayers still call it a China demand slow down when China coal import grows at 45%? For the first 11 month, China generated 707.8 billion TWH of hydro-electricity, a gain of 149.2 TWH versus last year, saving China 82M tons of coal demands. This one time weather anomaly will not repeat in 2013. China will need 82M tons more coal just to compensate for hydro-electricity falling back to normal, on top of demand grow. At 4B tons per year demand, any demand grow is huge to the international coal trade market of 800M tons a year.

    I am sticking to my coal stocks, and I look for opportunity to short NG players when the time is right, when we reach a high gas price.

    Disclosure: I am long JRCC, ANR, ACI, BTU.

    Dec 24 11:26 AM | Link | 9 Comments
  • The True Economy Of Bakken Shale Oil

    I have written repeatedly on SA to warn people that the shale oil and gas developers tend to use unreliable production models to project unrealistically high EURs (Estimated Ultimate Recovery) of their shale wells. They then use the over-estimated EURs to under-calculate the amortization costs of the capital spending, in order to report "profits", despite of the fact that they have to keep borrowing more money to keep drilling new wells, and that capital spending routinely out pace revenue stream by several times.

    When the capital costs are fairly amortized, most shale oil and gas development projects are deeply non-profitable. Even the Bakken shale oil, regarded as the most profitable shale play under current pricing environment, is not profitable. Let me use real data from Whiting Petroleum (WLL), the second largest Bakken shale oil developer, to demonstrate the real economy in Bakken shale.

    Let the Real Numbers Tell The Real Story

    Putting aside the shenanigans of how to properly model a shale well's production decline over time, I think the actual numbers that are indisputable will tell the true story:

    • How much does a producer spend on capital spending.
    • How much is the daily production volume.
    • How much the production gained due to capital spending.
    • What's the cost without considering the capital spending.

    While any one can say anything about models, the above items are very specific real numbers that producers must report to SEC as they are, with little room for manipulation or speculation.

    My idea is that the well drilling and development capital spending can be considered to serve two things:

    1. To compensate for the lost production due to depletion.
    2. To expand business and grow the daily production rate.

    I think the portion of capital spending that counters the shale well declines and maintains the production at the current level, replaces the loss of value due to depletion and amortization. This portion of capital spending should be the fair amount of amortization costs.

    What portion of the capital spending compensates for depletion? What portion is for growth of production? We know new wells drilled should be roughly proportional to the capital spending. Thus the production rate gained is proportional to capital spending. Part of the production rate gained merely compensate for the decline and does not show up in total production growth. The remaining part of new production rate gained shows up as growth. If we know the generate decline rate of existing production wells, we can calculate the percentage of these two portions.

    Case Study on Whiting Petroleum

    I choose to do a case study on WLL as they are the second largest Bakken shale developer with a long history in Bakken, and a previous case study on their Federal 14-24H well gave me a good idea how fast their wells decline.

    Here are the financial numbers of recent four quarters of WLL:

    Key Financial Data of Whiting Petroleum
    Period2012 Q32012 Q22012 Q12011 Q42011 Q3

    Average Per Day

    Av. Per Barrel
    Prod/Day (BPD)826208070080747707007067078692 
    Revenue($M)521.2492.76558.7492.03468.575.657$71.88
    Op. Cost($M)172.74168.98183.51153.31144.721.859$23.62
    Cap Ex. ($M)1612.561069.38539.551804.311311.1313.769$174.98

    Amortized($M)

    179.59160.59156.12127.34122.891.709$21.71

    Note that I removed items not directly related to well drilling and production, like gains or losses of asset sell, gains and losses from financial hedge contracts etc.

    For each BOE that WLL produced, it brought home $71.88. Subtracting $23.62 operating costs and $21.71 amortization of capital cost, the net gain from the barrel is $26.55/Barrel. Sound like a very profitable performance, right?

    But is it fair that they spend $174.98/barrel on capital spending but amortized only $21.71/barrel of that cost? Where does the bulk of capital spending go? How much production growth did WLL gain from that capital spending?

    In one year from Q3 2011 to Q3 2012, the daily production grew from 70670 BPD to 82620 BPD, or 16.91%. The daily production growth was +0.0428%/day.

    As I discussed before, Bakken shale wells collectively decline about -0.2% each day, or that newly added production rate may bring in roughly 1/0.2% = 500 days worth of current production rate in the future. So I use the -0.2%/day natural decline rate to calculate.

    To go from -0.2% decline below 0.0% to +0.0428% growth above 0%, the difference is 0.2428%. The portion of growth equals to 0.0428%/0.2428% = 17.628%. The portion that counters the well decline is 82.372%.

    Thus, 82.372% of the daily capital spending, or $11.342M, was spend merely to maintain production at average level of 78692 BPD. That should be the fair amortization amount. It averages to $11.342M/78692BOE = $144.12/Barrel amortization cost.

    The remaining 17.628% of daily capital spending, or $2.427M/day, was spend to boost average production by 0.0428% in a day. That's a production gain of 78692 BPD * 0.0428% = 33.68 BPD. The cost to grow each Barrel per day production, is $2.427M/33.68 = $72061.

    As I explained, each 1 BPD of initial production gain can be expected to bring in 500 days worth of production, or 500 barrels. So capital spending to gain one future barrel is $72061/500 = $144.12/barrel.

    Notice that both the amortization cost of current barrels and the capital spending on future barrels both comes to the same number, $144.12/barrel. Those are very expensive barrels of oil.

    This is not all the cost of the Bakken shale oil. It is only the capital cost portion. The operating cost was $23.62/barrel. So the real total cost is $23.62 + $144.12 = $167.74/barrel.

    But WLL takes home only $71.88/barrel in revenue. That leaves WLL in $96 in loss per barrel. That is the true economy of the Bakken shale oil play.

    Discussions and Investor Implications

    I have written many articles to point out that there are mounting evidences to suggest that the US shale oil & gas industry has systematically exaggerated EURs and under-calculated the fair amortization of the capital costs as the wells deplete much faster than their projections. Thus you can not take the profit or loss number reported by these companies at face value, because they have not fairly accounted for the reasonable amortization costs.

    There has been a widely spread and mistaken meme that the so called shale gas revolution brings cheap and abundant natural gas to the USA, thus it brings about the demise of the US coal industry. I keep hearing people singing the song that:

    "Coal is dead. Cheap and abundant natural gas is replacing coal"

    Nothing is further from the truth! I hope that by looking at the true capital and armortization costs, by looking at the rapidly growing debts in the shale industry, people should finally realize that shale gas and shale oil is not cheap at all, nor are they abundant. In the long term, coal is still the king of fossil energy. Calling coal dead is way premature. This presents an excellent opportunity for investors to jump into the coal sector to reap huge profits in a coal rebound. The profit potential is huge, because there is now a disparity of 75 times more money invested in the shale oil and gas industry versus that invested in the coal sector. When every one bets on the other side, you'd better on the other side of the market. I am holding my coal stocks firm, I advice you to do the same.

    Disclosure: I am long JRCC, ANR, ACI, BTU.

    Dec 17 3:23 PM | Link | 5 Comments
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