Sep 29, 2011,
Saudi AramcoSaudi ArabiaGulf
DUBAI: Saudi Aramco is keen to develop unconventional gas resources to meet rising demand in Saudi Arabia, but production costs are still too high, a senior company official has said.
In its 2010 annual report published in June, 2011, Aramco said it has started evaluating tight gas and shale gas resources, with an initial focus on the North-West area of the world's largest onshore oilfield, Ghawar, as gas infrastructure is already in place.
"I think the (shale gas) industry made a big stride, especially in North America, bringing the prices of gas to $ 4 (per mmBtu)... We are heavily looking at unconventional gas at Saudi Aramco in a good number of areas within the Kingdom," Amin Nasser, Senior-Vice President for Upstream at the company, was quoted by Arab News as saying.
Technological advances, which slashed the cost of producing gas trapped in shale and tight rock formations has turned North America from a major gas importer to a potential exporter over the last few years, the report said.
However, in Saudi Arabia, the $ 0.75 per million British thermal units (mmBtu) industrial gas sales price -- a remnant from the days when Saudi had plenty of practically free associated gas coming from its vast oilfields to meet modest internal demand -- is still below the current cost of unconventional gas production in the advanced North American industry, making Saudi unconventional gas prospects unattractive for now.
"I think we have huge potential when it comes to unconventional gas... Price is an issue, however, we think we can bring it with(in) reasonable price compared to crude (oil)," Nasser said.
"Mark my words, in the near future you will see a lot of (unconventional gas) development in this region, there's plenty of gas, especially in the unconventional side. Hopefully with the right technology development, we can make it affordable," Nasser said.
Saudi Arabia burns millions of barrels of oil each year in power plants, because it does not have enough gas available to meet surging demand, reducing potential oil export revenues.
Nasser said his company is still trying to develop technologies to unlock unconventional gas resources despite the technical and economic challenges.
After completing a massive crude expansion programme in 2009, Aramco stepped up its search for non-associated gas to cater for demand growth of 7 per cent annually from the power generation and petrochemicals industry.
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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/)My blog:
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The Real Natural Gas Production Cost 10 comments
Oct 12, 2012 5:34 PM | about stocks: UNG, CHK, SWN, ECA,COG, EOG, SD, APC, QEP, XOM, ANR, ACIQ, BTU, CLD, WLT
I have written several articles on the shale gas controversy. In my last article, I analyzed the real decline of Fayetteville shale wells operated by Southwestern Energy (SWN). I decided to do more data analysis after I read SWN's detailed investor presentation.
I post this article here on my Instablog because SA decided that they would not accept any more of my articles for publication. Sad!
Is Natural Gas Cheap and Abundant?
There is a common myth within the investment community that the new horizontal drilling and hydraulic fracturing technologies opened the door for cheap and abundant natural gas (UNG) from shale. An NG supply glut since late 2011 pushed NG prices to decade lows, yet there was few sign that producers were cutting production in any significant way. This further supports the general consensus that at least some producers believe they could still make a profit at the record low gas prices.
Can shale gas really be produced cheaply as some claims? This question is critically important to coal investors. At a price of $3.00/mmBtu or lower, NG competes with coal for electricity generation. If NG producers can make a profit producing shale gas at $3.00/mmBtu, then the future of coal looks dim.
On the other hand, if NG producers can only make a profit at much higher gas prices, then the current depression in coal prices is only be temporary. This would mean there is a great opportunity to invest in the coal mining sector now.
My study convinced me that shale gas is non-economical unless the gas price goes much higher. Let me speak with data and facts.
SWN claims to the lowest cost shale gas producer in the industry. They operate mostly in Fayetteville, a shale play of low drilling cost due to shallow depth of the shale. Let's find out what is their real production cost of the shale gas.
The cost boils down to two things:
The lifetime cost of a shale wellThe EUR (Estimated Ultimate Recovery) per well.
Estimating the Cost Per Well
Some NG producers provide well cost numbers. Always take their numbers with a grain of salt and ask: What costs were excluded?
SWN gave per well cost of $2.8M in 2011. They spent $2.2B in capital spending and completed 560 Fayetteville wells in 2011. $2.2B divided by 560 is $3.93M. So I think the real cost per well was $4M.
In the bigger picture, the top 40 NG producers spent roughly $128B capital spending in 2011. There were 16,000 wells drilled. So the industry wide average drilling cost was about$8M per well.
Modeling Fayetteville Well Declines
All shale gas wells are in continuous decline once they were brought into production. So estimating EUR is a matter of trying to project the production decline.
The industry uses the Arps formula to calculate EURs. Critics like Arthur Berman pointed out that the formula was never confirmed to be working in hydraulic fractured wells. The formula, when used with a high b-factor, often leads to grossly over-estimated EURs.
A good example is Barnett Shale. Chesapeake Energy (CHK) projected an EUR = 2.65 BCF using Arps formula. But after decades of development and 70% of the core area of Barnett already drilled, the cumulative production per well is only 0.663 BCF. That's only 1/4 of the projected EUR.
Here is an explanation of the Arps formula:
(click to enlarge)
How does Arps formula fit with Fayetteville well data? The SWN presentation contains this chart showing two type curves against actual production data:
(click to enlarge)
It looks to me that the two type curves do not fit the production data very well at all. So I painstakingly extracted data from the chart, based on the thick blue curve for all wells. I plotted the data with the Arps curves and my own model as below:
(click to enlarge)
Neither of the two Arps curves matched the well production data. But my model matched seamlessly. See the blow-up details:
(click to enlarge)
I discussed my decline model previously so I will not elaborate here. With an IP = 4.0 MMCF/Day, my model predicts an EUR of 1.75 BCF. So the EUR is rough 438 days or 1.2 years worth of IP production.
Calculating the Real Production and EUR of Fayetteville Wells
Encouraged by my model's seamless match to real production data, I went further to calculate the projected total production, based on SWN's well completion statistics:
Once again my result matches the actual production perfectly:
(click to enlarge)
My data model is validated! So let me calculate the EUR per well. Based on the SWN well chart, the average IP = 3.125 MMCF/day.
As explained, EUR is approximately 438 days worth of production at IP rate. So EUR = 438 days * 3.125 MMCF/day =1.37 BCF/well.
This number is way below what SWN believe their EURs are. But my number is consistent with my last estimate. In previous article, I argued that 1.56 new wells a day is needed to maintain a flat 1.95 BCF/day production. So one well is worth 1.95 BCF/1.5 = 1.25 BCF.
What is the Real Cost of Fayetteville Shale Gas?
If my numbers are right, we are talking about each well costs $4M from drilling to completion. It can produce 1.37 BCF in its lifetime. The well cost of the gas is $4M/1.37BCF =$2.92/mmBtu.
On top of that, SWN reported $1.13/mmBtu of finding and development cost, and $1.20/mmBtu of cash and operating cost.
But SWN calculated its F&D cost based on inflated EUR. Adjusted to realistic EUR, I think the F&D cost should double to$2.26/mmBtu.
The total comes to $2.92 + $1.20 + $2.26 = $6.38/mmBtu. That is the real cost of producing from the Fayetteville, the cheapest shale.
Cheap Natural Gas is an Illusion
I argued here and in the past that NG producers over-estimate the EUR of their wells. I am not the only critic. Even the USGSagrees. Please read this Huge Frack Surprise:
Southwestern Energy and Chesapeake Energy claim average EUR's in the Fayetteville of 2.4-2.6 Bcf. The Powers Energy Investor, an industry publication stated:
"To put into perspective how ridiculous Chesapeake's claims of 2.6 Bcf is, consider the following: of the company's 742 operated wells completed on the Fayetteville, only 66 have produced more than one Bcf and none have produced more than 1.7 Bcf. Chesapeake's average Fayetteville well has produced only 541 Mcf."
The USGS confirms these numbers again with the average EUR for Fayetteville wells coming in at 1.1 Bcf, significantly lower than 2.4-2.6. (more at the link)
The latest USGS report on shale EURs makes Arthur Berman look like an optimist! Here are the EUR numbers (in BCFs) from the report:
Barnett - median 0.7, average 1.0
Marcellus - median 0.8, average 1.158
Fayetteville - Median 0.8, average 1.104
Haynesville - Median 2.0, average 2.617
These numbers are in huge contrast to the rosy numbers that NG producers have been selling to investors over the years.
Wake up, people! The NG industry have spent more than half a trillion dollars over the decade to develop shale gas. So far they drilled 36,000 wells and produced 23,000 BCF of shale gas. That averages $13.9M per well and $21.74 per mmBtu of gas produced.
Shale gas is neither cheap, nor abundant!
Implications for investors
My conclusion is that energy investors made the biggest mistake in energy investment history, by placing 75 times more investment capitals in the NG sector, than in the coal sector. This happened because of the wide-spread myth that natural gas has become cheap and abundant, and that we are seeing a paradigm shift away from coal. The myth is false. It is not supported by data and facts.
This creates one of the biggest investment opportunity today. My advice is get out of the NG sector and get into the coal sector.
If I have to pick an NG producer that I like, I have to pick one which has low debts and low costs. After looking at the data, I like SWN best. They have relative low debt load. They have the lowest cost in the industry. Gas price has got to go much higher. SWN should be among the first to benefit.
But I would recommend coal stocks ahead of the NG producers:
Arch Coal Inc. (ACIAlpha Natural Resources (ANRJames River Coal Company (JRCC)Peabody Energy (BTUCloud Peak Energy (CLD
Disclosure: I am long ANR, ACI, JRCC, BTU.
Themes: natural gas, shale, oil, energy, commodity, coal,electricity Stocks: UNG, CHK, SWN, ECA, COG, EOG, SD, APC,QEP, XOM, ANR, ACIQ, BTU, CLD, WLT
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Seth Walters
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You can't just divide capex by wells to get well cost. A lot of yearly capex now is going to last much longer than 1 year. For example, the drilling equipment will keep running for many years I am sure.
13 Oct 2012, 07:44 AMReplyLike0
Mark Anthony
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Author’s reply » Seth:
My generalization is not an exact calculation. But it is accurate enough to estimate total cost per well, including both the cost directly relaed to wells, and the cost not related to each individual wells but is still part of the cost of shale development.
13 Oct 2012, 03:46 PMReplyLike1
Richard Zeits
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Mark,
It was a pleasure to read your article. Not everything I can agree with, but the amount of work that you have done on the analysis side and presenting the results is gargantuan and very rare from what I see in many other materials.
Just a few thoughts. I totally agree with you that the Arps formula does not necessarily describe real life well declines. In my view, it is really meant to be a "declining grid" to see where approximately a specific real curve belongs. And real curves cross the "gridlines" more often than not. There are several areas where there are obvious difficulties with using the Arps math. During the first few weeks (sometimes longer) fracked wells are in a "clean out" mode. The frac liquids congest the tubing and the flow rates are lower than the formula would suggest. The flow is restricted. I suspect you are using monthly data for parameter fitting starting months 2 or 3 and exclude the front end (just wanted to mention this). Another reason why Arps' formula is not a perfect tool, it is meant to describe a boundary-dominated flow. Many would argue that a boundary-dominated flow regime is not reached in shale wells until later in their lives. What we typically see is a transitory flow. Later on in a well's life the real decline curve should resemble a lot more closely one of the Arps formulas. Often companies choose an exponential decline version to stay conservative, or arbitrarily curtail the hyperbolic formula to avoid "explosive" EURs.
The EUR estimate is very, very sensitive to the chosen decline rate, as both you and I have discussed. Fortunately, there is a way around it, at least in my opinion. Let's think of the wells in terms of their "cash flow decline curves." To make it easier for the moment, let's use a high, let's say, 15% discount rate. The first several years will dominate the life-long economics, particularly if the curve you are using in your analysis is steeper than Arps'. When you compare the two NPVs, they should be identical on the "actual" part of the trajectory, and will diverge on the "tails." Because of the discounting, you will notice that the economic difference is not too dramatic.
Moving to the cost analysis, I agree that there are costs beyond the direct well costs. Drill & complete has been $2.8MM per well for the Fayetteville. on top of that there are many other components to the capex. Some spending is related to the pipes, but those I believe are accounted for in another op segment. Some costs are related to "new ventures," outside of Fayetteville. The latter is, in my view, the most underappreciated component of doing the E&P business. But it does not relate in this case to the marginal cost of drilling in the Fayetteville that you are analyzing.
Further, when you arrive at a much higher F&D cost, why not simply plug it in instead of DD&A in SWN's income statement? You will arrive at a much cleaner surrogate of their op cost, I think. I do not think you would get to $6, it will be a bit lower. Better still, you can use your decline curve, which is the most valuable part of this entire exercise, to model cash flow from a typical well to see at what price it would break even on your assumed threshold rate of return. 10% is too all-forgiving, 15% if perhaps adequate given the maturity of the play, 20% is a bit too much to wish for. Importantly, SWN's royalty rate is very low. It gives them an edge.
13 Oct 2012, 12:50 PMReplyLike2
Mark Anthony
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Author’s reply » Richard:
Nice comment of yours. I agree with what you said. I especially like the idea of calculating a "cash flow decline curve". I actually did an exercise like that before. Read here:
http://seekingalpha.co...
Maybe I can polish that a bit more and see what we get when we plug in the numbers obtained in this article.
Finally, the industry experts know Arps formula tend to over-estimate the EURs. Too many evidence points to that. If they are honest to themselved, I think they could have done a much better job of modeling future declines of shale wells, given the data accumulated so far. But they did not. They continue to pitch high EUR values to investors and banks. I think there is some vested interest here, just as many people have criticized.
Have you had a chance to look at this one page sumary page of all US shale plays:
http://bit.ly/PQz6qy
I like your data analysis as well. But the difference is you are willing to take what teh industry claims at face values. But I am more skeptical and would like to probe under the hood to find out the real numbers.
14 Oct 2012, 11:15 AMReplyLike1
dividend_growth
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Your claim of "EUR = 438 days * IP" is blatantly false.
15 Oct 2012, 04:34 AMReplyLike1
dnpvd51
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I think your articles are important. In some ways they could use some polishing perhaps and maybe the tone could be tempered a bit, but they are certainly among the best on SA.
17 Oct 2012, 12:02 PMReplyLike1
Mark Anthony
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Author’s reply » dnpvd51:
Thanks for your complimentary. I put a lot of effort in getting the facts right, because the right investment strategy counts on getting the facts right and sticking to your conviction. I am happy that my readers find my articles useful. I wish the SA editors re-consider their decision to out-right ban me for publishing any more articles. There are too many pure nonsenses on SA. My articles should be the kind of fresh air they desperately need to have and keep.
It is boring that even my comments are now moderated.
17 Oct 2012, 06:15 PMReplyLike1
pe221749
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Why did you get banned. I trully enjoy reading your articles. Hopefully, you can tell them to take the ban off!
1 Nov 2012, 02:22 PMReplyLike2
Scooter-Pop
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Same Here, Hear?
1 Nov 2012, 04:52 PMReplyLike0
sharmar
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Mark,
This is a little dated but I just read this article. Good analysis but your recommendation of long on coal might not consider the fact that a lot of coal power plants in NA are slated for retirement beginning in 2015. That will lead to much lower demand for coal in the US. Now exports to Asia might be an option to consider for coal, but I don't know how far that will go with global carbon regulations. Thought