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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 Ridiculous High EURs Of QEP Shale Wells

    I have written about the shale gas controversy. I questioned whether shale gas will ever be profitable. I predicted a looming debt crisis in the natural gas (as NG) sector due to capital destruction. I believe that NG producers tend to over-estimate EURs (Estimated Ultimate Recovery) of shale gas wells. If critics like Arthur Berman were correct, we have much less shale gas left to be produced.

    Once again, Seeking Alpa declined to publish my well researched article on shale gas. So I am posting here of the main point in a reduced form.

    SA author Richard Zeits alerted me when he noticed that production of Haynesville shale probably increased in June. He tried to explain it. He referenced a BG Group presentation and cited a presentation by QEP Resources (NYSE:QEP) for support.

    I disagreed with Richard's explanation.

    Impressive Haynesville Shale Well Performance

    QEP claims their Haynesville wells performed exceptionally well, with high IP and slow decline rate. See their Barclay presentation:

    (click to enlarge)

    An EUR of 6 to 8 BCF?! Their Haynesville type curve below:

    (click to enlarge)

    QEP used a low b = 0.4 and a very low initial decline rate D.

    b-factor = 0.4
    D = -ln(1-50.1%)/year = 0.695/year = 0.05793/month

    Chesapeake Energy (NYSE:CHK) type curve has a high b value and a very steep initial decline D:

    (click to enlarge)

    The Arps formula is explained below:

    (click to enlarge)

    CHK used 500 months well life to calculate EUR, with b = 1.351 and D = 0.75/month. Very different from QEP's.

    Who do you want to believe, CHK or QEP?

    Are These Haynesville Wells Really So Good?

    I decided to scrutinize QEP's actual production data to find out. I need production rates and well additions.

    Here is my calculation of the total production rate, assuming the wells comply with the QEP defined type curve:

    (click to enlarge)

    Oops, the result does not match the actual production! The wells did not follow QEP's type curves of IP=8.25MMCF/day and slow initial decline rate D (losing only 50% in a year).

    QEP operated 126 producing wells in Haynesville in Q2, with an average production rate of 340 MMCF/day. The average per well was 2.7MMCF/day. Consider that half of the wells are less than one year old, the 2.7 MMCF/day average is inconsistent with an IP of 8.25 MMCF/Day and first year decline of only 50%.

    Let me keep b = 0.4 but use higher D so first year decline = -81% as claimed by CHK, which is D=0.2/month. So I used these numbers to plot the chart again:

    (click to enlarge)

    Bingo! I got a perfect match with the actual production!

    I should explain that to obtain the above precise match, I did tweak the IPs a bit as following:

    • From Q1, 2009 to Q4, 2010, the IP = 8.25MMCF/day, except:
    • In Q1, 2010, the IP = 7 MMCF/day; In Q3, 2010 IP was only 6.
    • In Q1-Q4 of 2011, the IPs were 10, 5, 9, 11 MMCF/day.
    • In 2012 the IP reached 12 MMCF/day.

    The above IP assignments are inline with QEP's claim that they have achieved higher IPs in the most recently drilled wells.

    The Real Performance of QEP's Haynesville Wells

    I have modeled QEP's well declines to match actual production data successfully with these numbers:

    • Initial decline rate D = 0.2/month, or -90.93% annually.
    • First year production decline is -81.4%. This agrees with what other NG producers have been saying about Haynesville.
    • At IP = 8.25 MMCF/day, 300 month EUR is 2.046 BCF/well.
    • At IP = 12 MMCF/day, the EUR is at 3.0 BCF/well. At higher IP, the EUR will be proportionally higher.

    My EURs are far lower than predicted by QEP. They gave 6-8 MMCF per well. If my 2-3 BCF/well is correct, the $9M per well drilling cost suddenly looks prohibitively expensive!

    Do you believe QEP or do you believe me? The math does not lie!

    The statistics of the entire Haynesville also agrees with my EUR:

    (click to enlarge)

    There were 1402 production wells in LA Haynesville. Accumulated production was 4086.233 BCF, or 2.9 BCF/well. This average agrees with my EUR of 3.0 BCF much better that QEP's 6-8 BCF.

    I also calculated the combined decline rate of Haynesville based on production and well completion statistics. Here is the result:

    (click to enlarge)

    I obtained average IP of 6.5 MMCF/day, and combined decline rate of the whole Haynesville at -0.2%/day. So EUR = IP/D = 3.25BCF.

    Why the EUR Is Important to Both NG and Coal Companies

    I attempted to obtain a realistic EUR of the Haynesville shale wells using different methods. All of my estimates suggest that EUR is at slightly above 3.0 BCF/well. This is far lower than NG producers have been projecting. I believe my result has much stronger data support.

    This is important. Profitability of shale gas plays depends on not just the gas price, but also how much gas could be produced from a well. Whether the real EUR at Haynesville is 3 BCF or 6 BCF makes a huge difference to the producer bottom lines.

    The same question is even more important to coal mining companies. When the NG price is cheaper than $3/mmBtu, NG competes with coal for electricity generation.

    Investment Implications

    As long as NG producers can not make a profit at a NG price that is competitive against coal, the king coal is not dead. My research in different shale plays shows that the real EURs are far below what NG producers tried to make us believe. Here, once again, I showed that the producers own production data contradict their own projections.

    Shale gas can NOT be produced profitable and compete against coal. Coal is not dead. NG prices must go a lot higher. Can gas price realistically go high enough to allow NG producers to make a profit? I do not believe so.

    I believe investors should divest in the NG sector and invest in coal. If you hesitate, then consider these factors:

    • Current coal prices are very close to the profitable levels.
    • Current NG prices are already non-competitive against coal. Yet they still do not allow NG producers to make a profit.
    • Almost the entire investment community made a big mistake thinking that there is a paradigm shift of NG replacing coal.
    • Investors put 75 times more money in the NG sector than the coal sector, while the two generates the same amount of energy and are equally important to the US economy. This is probably the biggest portfolio imbalance in the energy investment history.

    There are not many US coal companies to buy. My favorites are:

    • Alpha Natural Resources (NYSE:ANR)
    • Arch Coal Company (NYSE:ACI)
    • James River Coal Company (JRCC)
    • Peabody Energy (NYSE:BTU)

    The discussions are also relevant to these issues in the NG sector:

    • EnCana (NYSE:ECA)
    • Cabot Oil & Gas (NYSE:COG)
    • EOG Resources(NYSE:EOG)
    • Southwestern Energy (NYSE:SWN)
    • Anadarko Petroleum Corp. (NYSE:APC)
    • SandRidge Energy (NYSE:SD)
    • Apache Corp. (NYSE:APA)

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

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

    Oct 08 10:13 AM | Link | 1 Comment
  • Did Haynesville Shale Production Increase In June?

    People invested in the US coal (NYSEARCA:KOL) and natural gas (NYSEARCA:UNG) sectors watch natural gas (or NG) production level closely for signs that it has started to drop. Fellow SA author Richard Zeits suggested that natural gas (or NG) production from Haynesville increased in June, reversing the decline since January 2012, defying the slow drilling activity in the area. He was puzzled by the reversal and tried to explain why. I think I have a simpler explanation of the anomaly.

    I am not just doing an exercise to analyze some data. I think that investors should pick apart what they see at first sight and analyze what is under the hood. Arthur Berman often criticized the NG industry for over-estimating EURs (Estimated Ultimate Recovery) and profitability of shale gas wells. Investors should study the data themselves to avoid falling into salesman pitches.

    The Importance of Haynesville Shale

    Haynesville shale wells are the most productive among all US shale plays, although the well decline rates are also high. Its cost per well is also the highest as producers need to drill much deeper there. Haynesville was the top producing shale play last year. It was taken over by Marcellus only recently. So Haynesville is very important to US NG producers. See the EIA chart below:

    The well count and cumulative productions of major shale plays:

    (click to enlarge)

    Haynesville is one of 10 key plays of Chesapeake Energy (NYSE:CHK):

    (click to enlarge)

    Some NG producers active in Haynesville include:

    • CHK stopped most of drillings in Haynesville. For all dry gas plays, CHK started 2012 with 50 rigs, averaged 38 rigs in Q1. They will average 12 rigs in H2 of 2012, with 2 in Haynesville.
    • Exxon Mobil (NYSE:XOM) has a joint venture with EnCana in the area with 10,800 acreages. They also acquired XTO Energy (XTO).
    • EnCana (NYSE:ECA) drilled a 22,350 feet (record depth) Sabine well and two wells of 7500 and 8000 feet record lateral lengths.
    • Cabot Oil & Gas (NYSE:COG) was active there and acquired 24 wells recently. They sold some non-operated units in May.
    • Forrest Oil (NYSE:FST) owns 163,000 acres in the area with two rigs operating. It re-deployed the only Haynesville rig to work in oil-rich Cotton Valley interval in east Texas as well.
    • EXCO Resources (NYSE:XCO) has a gross production is 1.219 BCF per day. They had 22 rigs last year, cut to 7 in May 2012.
    • Comstock Resources (NYSE:CRK) completed 84 wells in 2011 and had 14 wells waiting for completion by year end.
    • PetroQuest Energy (NYSE:PQ) shifted its attention to Cotton Valley. A recently completed well had an IP of 3.8 MMCF/day of gas.
    • Goodrich Petroleum (NYSE:GDP) participated in three non-operated new wells with impressive IP of 14.438 MMCF/day.
    • SM Energy (NYSE:SM) canceled drilling of four wells planned in 2012.
    • Kinder Morgan (NYSE:KMP) acquired $855M of Haynesville assets from PetroHawk Energy (NYSE:HK) in May 2011. In Q2-2012 they saw "below budget" production volume in the play.
    • Gastar Exploration (NYSEMKT:GST) stock lost -25.1% on Oct. 3 as CHK filed a lawsuit against the company.

    Richard's Discussion of Haynesville Shale

    Richard cited EIA data and this chart:

    (click to enlarge)

    The chart shows daily NG production rate of the Louisiana portion of the Haynesville Shale. The production peaked at the beginning of January 2012 and started to decline. But then it reversed to go up in June 2012. Why did it reverse?

    Richard thought that the relationship between active rig counts and the subsequent production volumes was broken. He explained the decline since January as due to producers shut in some gas wells due to low NG prices. He believed that by June, some producers decided to re-open some of the shut-in wells. Thus production increased again. If that was true, then we could see slow and gradual production decline in Haynesville in the near term.

    It is true that reduced drillings do not immediately lead to a drop in new well completions. But the correlation between well completions and production volume is so basic it could not have broken down, except for possible shut-ins as mentioned by Richard. But I think there is a simpler explanation of the June production anomaly.

    Take EIA Data with a Grain of Salt

    When looking at EIA data releases, people would think those are accurate and authorial numbers carefully reported by producers and tallied up by EIA. That is not the case. Most EIA data is calculated using math models based on raw data that may not be complete or accurate. Some data comes from private research organizations like BenTech who does not have official data collection authority. You can often find inconsistencies between different EIA data sources.

    For example, EIA releases weekly and monthly coal productions. The 8 month total for 2012 was 684.777M tons. The period was one day short of 35 weeks. The 35 weekly productions totaled 673.184M. Subtracting one day of 2.862M tons, it results in 670.322M tons. That is lower than the monthly totals by 14.5M tons! This large discrepancy is equivalent to 210 BCF in terms of NG. Investors would freak out when the NG storage number was only 2 BCF off their consensus. Why nobody has noticed the difference between the EIA weekly and monthly coal productions?

    When look at the EIA chart of NG gross withdrawal from Louisiana, I noticed that the June number was marked with an R that stands for "revised". From time to time, EIA may decide to revise a particular month's numbers, without necessarily revising the previous month as well. This might have distorted the month-to-month comparison. The month to month change could seem like an increase when it was actually a decrease. This often happens when you revise one number but do not revise the other number next to it.

    I do not know whether my explanation is correct or not. I do not know why EIA revised the June number, or by how much they had revised it. But I do know the Occam's Razor. The production drop early in 2012 might be fully accounted for by the slow down in well completions. If so, there were probably no production shut-ins. Thus there was no production re-opens in June, either. Let's find out.

    New Well Additions and Production Growth

    Shale wells are known to have steep production declines once they are brought online. NG producers keep drilling new wells to replace lost production due to declines. When producers add wells faster than needed to maintain flat production, the production will grow. If they add wells too slow, then the production will drop. So:

    Production Growth = (New Productions) - (Well Declines)

    With a reasonable well decline rate D and a new well IP (Initial Production rate), and with known well counts, I constructed a spreadsheet to calculate the total daily production rate and compare with the data. Here is the comparison:

    (click to enlarge)

    Knowing only the weekly well count, my calculation matched the production data perfectly. It shows that the production rate was accounted for by only the well additions and natural declines. It did not need contributions from well shut-ins and re-opens.

    (click to enlarge)

    The above shows how production is correlated to well completions. Note the total production includes 1.2 BCF/day of conventional gas production that declines much slower.

    The two parameters I used are:

    • Per well IP = 6.5 MMCF/day
    • Well decline rate D = -0.2%/day

    I am confident that the two number I chose are correct. If these two numbers were a bit higher or lower, the peak production would not have reached nearly 7.0 BCF as it did. More over, the way that the curve turned from growth to drop would not match.

    Significance of Decline Rate and Average IP

    Analyzing the profitability model of the NG industry is difficult. The cost and the productivity are not directly correlated. NG producers spend up-front money to drill gas wells and bring them to produce gas for decades. How much the wells can produce will not be known until well into the future. Analysts have struggled to understand the profitability models of NG producers. It does not help that producers love to pitch exceptionally good wells drilled at sweet spots. We have to look at the whole picture and examine the production history of shale plays in order to avoid the salesman pitches.

    We see NG companies fly all sorts of numbers of EURs, IPs and well decline models around. You never know how much you can trust those numbers, or how well they represent the average wells in a shale play. My simple method relies on only the historic production rates and well completion rates of a shale play. It provides accurate results of average IP and average decline rate D. Then IP divided by D tells you the average EUR per well. I urge people to study it.

    I have written several pieces about shale gas. I explained why the EUR estimates given by NG producers tend to be much higher than they should be. I scrutinized EURs from several different angles:

    • The earliest shale gas play, Barnett Shale, was proven to perform way below the industry's initial expectations, yielding only 0.663 BCF/well so far, versus the expected 2.5 BCF.
    • The Arps formula, when given a b-factor higher than 1.0, diverges to infinity. Thus it is not suitable for projecting long term shale well productions. But NG producers love to fit well production data with Arps type curves of high b-factor, and extrapolate the formula 40-50 years into the future. They do so to obtain high estimates of EURs.
    • Based on reasonable recovery factors, Marcellus and other shale plays have lower EURs than the NG industry projected.
    • The production rates of a shale play, when correlated to the well completion rates, as discussed here, provide a more realistic metrics to calculate IP, decline rate, and EUR. Such results are much lower than projected by NG producers.

    I welcome more debates on the controversy on shale gas.

    Investment Implications

    The decline in Haynesville production was real. It was the result of slowing rig activity and subsequent slowing of well completion rate. Investors do not need to be pessimistic about the NG price outlook. I believe that even Marcellus Shale is beginning to decline soon.

    My calculation shows we need 2 new wells per day to maintain flat production at Haynesville. Using my method, the EUR roughly equals to IP divided by decline rate D. EUR = 6.5 / 0.2% = 3.25 BCF/well. Of course that is only my take. CHK projected a much higher EUR of 6.5 BCF. That is a huge difference that could decide if Haynesville shale is profitable at $4 or $8 per mmBtu.

    The debate on shale gas EURs and profitability is important. There is a widely accepted belief that the so-called shale gas revolution is a paradigm shift that kills coal. People believe coal is being replaced by cheap and abundant shale gas. This false myth is the reason why the investment community dedicated 75 times more money in the NG sector than in coal. The NG industry has accumulated more than half a trillion dollars of debts since it first ventured into shale gas development. I believe that there is a debt crisis looming in the NG industry. I believe people have invested in the wrong energy sector.

    I emphasized many time in the past that natural gas is bullish, as is coal. NG supply and demand is rebalancing just as I predicted. I also said that the coal sector is the better sector to leverage on rising prices of coal and NG. The reason is that coal producers are not far away from seeing profitable coal prices, but shale gas is still deeply non-profitable for NG producers. I will stick to my coal stocks.

    But I do not think that shale gas will be dead. It is an important part of our energy supply. But NG prices must go much higher to allow shale gas to be produced profitably. NG producers with low debt loads and thrift well drilling costs would survive and thrive.

    I like Southwestern Energy (NYSE:SWN) after looking at its balance sheet. Its debt was $3.988B in Q2-2012. That is low by industry standard. It did incur high capital spending each quarter. But that did not result in high debt load. I don't know how they operated so efficient without borrowing a lot of debts. I would study this company more when I have time, and write about it.

    COG is another NG producer I would like to exam. Its Q2-2012 revenue was $265.657M on $66.695M cost. How could its cost be so low relative to its revenue? I wish to study more on that.

    But again, now is time to stick to coal companies, not NG producers. Opportunity in the NG sector comes after the looming debt crisis in the sector unfolds and takes its preys. We are not there yet.

    The above discussions are also relevant to these equity issues:

    • NG players: Southwestern Energy [SWN]
    • Anadarko Petroleum Corp. (NYSE:APC)
    • SandRidge Energy (NYSE:SD)
    • Apache Corp. (NYSE:APA)
    • EOG Resources (NYSE:EOG)
    • WPX Energy Inc.(NYSE:WPX)
    • Coal players: Arch Coal Inc. (NYSE:ACI)
    • Alpha Natural Resources (NYSE:ANR)
    • James River Coal (JRCC)
    • Peabody Energy (NYSE:BTU)
    • ETFs: United States Natural Gas [UNG]
    • Market Vector Coal ETF [KOL]

    Disclosure: I am long ANR, ACI, JRCC, BTU. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

    Tags: ACI, ANR, APA, BTU, CHK, COG, EOGQ, KOL, SWN, UNG, WPX, ECA, APC, commodities
    Oct 05 5:09 PM | Link | 4 Comments
  • The Real Marcellus Shale Gas Production

    Investors bullish in coal (NYSEARCA:KOL) and natural gas (NYSEARCA:UNG) expect to see significant drop in natural gas (or NG) production soon. They are frustrated at the lack of production decline in the latest EIA data. We know that low NG prices forced producers to reduce rigs drilling for gas. They moved the rigs to drill wells rich in oil/liquid instead. Why the NG production has not dropped?

    The Marcellus Changed Everything

    We need to look at Marcellus Shale closely to find the real decline of NG production in the US. As RBN Energy discussed, there was rupture in the space-time continuum:

    As the chart shows, NG production from Marcellus was still growing. But production from everything else was declining. The growth in Marcellus canceled out the decline from elsewhere, leaving only moderate decline of overall US production.

    People speculated that as producers move to oil/liquid rich plays, the increased by-product gas production from the oily wells can cancel out the drop in dry gas production. That is NOT the case. Most oil/liquid rich plays, like Eagle Ford or Bakken, are lumped into "everything-else", which is in decline. The growth in Marcellus, a dry gas play, was what stopped US NG production from falling.

    Here is an EIA chart of shale gas productions from different areas:

    As shown, the rapid growth leveled off by Dec. 2011. But Marcellus production continued to grow, leading to a flat total production.

    Marcellus Growth Already Leveled Off

    Marcellus is mostly in Pennsylvania. Most of its production is from PA. EIA noted fewer daily well starts in PA recently:

    EIA commented:

    On average, 5 horizontal natural gas wells were started each day in 2011. In 2012, the new horizontal well count generally remained above 4 per day through April, but has fallen steadily thereafter. In July 2012, operators began drilling, on average, only 2.5 horizontal natural gas wells each day.

    Here is the actual data of new horizontal well starts in PA:

    (click to enlarge)

    As fewer wells are started, fewer wells will soon be completed and put into production. So the production should level off soon. The EIA data already show the trend. PA production grew rapidly from January to April. But by August, it was almost flat from July level:

    (click to enlarge)

    The red line is my calculation based on raw PA gas production data. The chart shows that daily production grew only 1.3% higher from July to August. The growth has leveled off. Is it going to drop soon?

    Fewer Well Starts Leads to Production Drop Soon

    I explained in the past that shale gas wells decline fast. Producers must keep adding new wells to replace lost productions. When they slow down adding new wells, total production will start to drop.

    But there is a time delay from reduction of drillings to reduction of new well completions. Last year it took about three month from well spud to completion. Today there is a growing backlog of nearly 1000 Marcellus wells already drill but not completed yet. The time from spud to production has grown to five or six month.

    Some analysts worried about the large backlog of Marcellus wells waiting for completion. They believe that even if producers stop all drillings now, when new pipelines are completed, a flush of new gas production will be put online, flooding the market with a supply glut.

    I believe the opposite is happening. The reason there is a growing backlog is that producers do NOT want to rush wells into production in a low price environment. Most completion crews are working to bring oil/liquid rich wells online first, leaving dry gas wells behind.

    So to the bulls, the growing backlog of wells is a good thing, not a bad thing. As long as the producers do not rush to complete these wells all at once, there will be no flush of new supply. The EIA data already shows that the Marcellus production growth is leveling off. The question is will it turn into a decline soon? We do not know yet.

    My take is that even the new pipelines will come online soon, new wells can be connected all at once. Completion crews still in the area have to work on the wells one at a time. I believe there are not enough completion crews in Marcellus. The data shows they are only starting 2.5 new wells per day now. If most drilling teams are working some where else, most of the completion crews must be at some where else, too. If they do not have resource to bring wells online fast enough to fight the declines, production will fall soon.

    Marcellus Gas Production Projected Based on Well Starts

    Knowing number of new well starts each month, I can estimate how many wells are completed in each month. I can then calculate the monthly production rates, based on reasonable decline rates of existing wells and reasonable IPs (Initial Production Rate) per well. My calculation is matched against production data from PA DEP. As they do match, I must have used the correct decline rates and IPs.

    (click to enlarge)

    The above shows my projected PA daily gas production rate. The thick smooth long lines are the total production rates in BCF/day. The zigzag lines tell how steep the wells decline, and how new wells in each month brought the total production up against the declines.

    The red up arrows stand for new production each month. An arrow for 100 new wells per month is put on the chart for reference. You can see how steep the production would have fallen had there been no new well additions.

    PA Shale Well Production For Six Month Periods (BCFs)
    Six Month ProductionH1-2010H2-2010H1-2011H2-2011H1-2012
    PA DEP Data138272435631895
    My Calculation140276436630895
    Discrepancy+1.4%+1.5%+0.2%-0.2%+0.0%
    Daily Decline-0.8%-0.7%-0.5%-0.4%-0.3%
    IP (MCF/well)2.53.03.53.64.3

    My calculation matched the six month production data from PA DEP. I assumed these reasonable parameters:

    • Combined daily decline rate of existing wells went from -0.8% in H1-2010 and gradually trended down to -0.3% in H1-2012. Early combined decline rate was higher because most wells were new. As the wells aged, the combined decline rate slowed down.
    • Per well IP remains at roughly 3-4 MCF/day, starting at a low 2.5 MCF/day and increased to 4.3MCF/day recently. This was due to producers moving to the more productive sweet spots.

    What do these numbers tell us?

    Discussion and Investment Implications

    NG producers must work hard to maintain production as shale wells decline fast. Even a moderate slowing in adding new wells will result in falling production.

    Currently existing Marcellus wells are losing 0.3% of production daily, or losing 67% annually. At 5.85 BCF/day production rate, the decline is 16.5 MCF/day each day. Average well IP is 4.3 MCF/day. So to counter the decline, about four new wells per day are needed.

    According to the data, new well starts in July fell to 2.5/day. That is far below the 4/day threshold to maintain production. Since production was flat in August, the well completion rate must have dropped to 4/day in July as well. Due to the large backlog of wells waiting for completion, depending on how many completion crews are working to bring these wells online, Marcellus production may or may not start to fall rapidly.

    But since productions from else where are already falling, a mere slow down in Marcellus growth means a falling total NG supply in the US. The latest EIA data shows that the gross withdrawal dropped to 79.243 BCF/day in July from 80.720 BCF/day in June, or dropped by 1.83%. That supports my notion that US NG production is falling.

    Using the smart method I discovered, the EUR (Estimated Ultimate Recovery) per well can be estimated by dividing IP by the decline rate D of all existing wells in the play:

    EUR = IP/D = 4.3MCF / 0.3% = 1.43 BCF/well

    My EUR is far lower than what Chesapeake Energy (NYSE:CHK) projected:

    (click to enlarge)

    I believe my method is logically correct. My EUR, 1.43 BCF, is consistent with actual Marcellus performance so far. There were 2312 wells drilled and 1530 BCF cumulative gas production in PA Marcellus by the end of 2011. That averaged only 0.66 BCF/well. My EUR is also consistent with EUR estimate based on recovery factor.

    Invest in Coal, Not NG

    As Marcellus production starts to drop soon, the US NG supply will fall off a cliff, natural gas prices will go much higher, allowing coal prices to go higher as well. But people should not be lured into the NG sector just because natural gas prices are higher. They should invest in the coal-mining sector, instead.

    The US investment community made the biggest energy investment mistake in history, by abandoning coal and rushing to the hype of cheap and abundant shale gas in the US. Judged by market capitals, investors put 75 times more money into the NG sector than the coal sector. In reality both sectors produce the same amount of energy for the US economy. Both are equally important.

    The myth that "cheap and abundant natural gas is killing coal" is so widely accepted that even people around me who did not trade stocks have heard about it and they believed it. I had a hard time convincing them that the myth is false.

    The shale gas is neither cheap nor abundant. We only need to look at two things: It's been nearly two decades since the NG ventured into shale plays. The industry has accumulated 23 TCF of shale gas production. But they have also accumulated $500B of debts related to shale. That is a debt load of nearly $22/mmBtu of gas produced. Had gas prices been $2/mmBtu or $3/mmBtu higher, the industry would have taken home $46B or $69B more revenue. It would not have made a difference in the industry's $500B collective debts.

    What would you think if the US coal sector had accumulated half a trillion dollars of debts after producing coal for two decades? Patriot Coal went bankrupt for a mere $600M of debts, not $600B. I foresee a looming debt crisis of the NG industry. The debts must be resolved in one of two ways. Either NG prices go to ridiculous high levels and stay there sustainable, so the industry makes enough profits to pay off the debts before the gas runs out. If that does not happen, then many NG producers and banks in the shale business will go belly up.

    I continue to advise people to invest in the coal sector, not the NG sector. The discussions here are relevant to the following issues:

    • NG players: Cabot Oil & Gas (NYSE:COG)
    • Chesapeake Energy [CHK]
    • Southwestern Energy (NYSE:SWN)
    • SandRidge Energy (NYSE:SD)
    • Anadarko Petroleum Corp. (NYSE:APC)
    • Apache Corp. (NYSE:APA)
    • EOG Resources (NYSE:EOG)
    • WPX Energy Inc.(NYSE:WPX)
    • Coal players: Arch Coal Inc. (NYSE:ACI)
    • Alpha Natural Resources (NYSE:ANR)
    • James River Coal (JRCC)
    • Peabody Energy (NYSE:BTU)
    • ETFs: United States Natural Gas [UNG]
    • Market Vector Coal ETF [KOL]

    Disclosure: I am long ANR, ACI, JRCC, BTU. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it (other than from Seeking Alpha). I have no business relationship with any company whose stock is mentioned in this article.

    Tags: ACI, ANR, APA, APC, BTU, CHK, COG, EOGQ, KOL, SD, SWN, UNG, WPX, commodities
    Oct 02 1:27 PM | Link | 19 Comments
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