Bakken Update: The Red Queen Is Just A Fairy Tale Part III [View article]
rlp2451,
The 24 hour IP rate was a generalization that I should have been more clear on. Because of the varied size of chokes 24 hour IP rates can be all over the board. So 24 hour IP rates or even 30 day IP rates can be misleading and should not be used to formulate an idea of production for the life of the well. Most production models use at the very least 90 day IP rates because of this. One thing I would say about arguments on depletion is the glass is half full or half empty. Unconventional wells produce a huge amount of resource in the beginning of well life. About half of all well production is produced in the first 5.5 years. These wells produce for 32 to 40 years. You can focus on the depletion number and the negative or you could focus on how quickly these wells pay back. This is a financial site and we focus on economics and how those economics will pay back investors. Try to keep in mind that some of the best oil companies in the world are developing the Bakken, and they aren't doing this because they are losing money. Have a great night and thank you for the comments.
Bakken Update: Is Whiting For Sale? Part I [View article]
I finally got a chance to look over the article, which I must say was a lot of work. The author does seem to have some knowledge in this area, and I do commend the time he took to do an article that took some time. Although there was a lot of info, I did think this info was missing some things, and could've done a much better job if he just bounced some questions of a couple of people that know what is going on the ground. The first problem with doing a general work in the Basin has to do with formation. There are a significant number of wells that have targetted the Red River and Madison formation. These wells are vertical and don't fit with his findings. He made an interesting point as to the average amount of oil produced per day per well. This average has not changed much since 2006, but we have to remember that wells, until recently had a very high rate of depletion. This is not to say the horizontal wells don't deplete quickly, because they do, but the change has been significant in producers like Kodiak, Burlington, Continental, etc. It has taken years for producers to find the value of using more and better proppant, more water, and increased stages. One of his points was that most of the sweet spots have been drilled, and this leads him to believe only poorer areas remain. This couldn't be further from the truth. Only a small fraction of the best areas have been worked. Looking at the map you will see one well drilled per mile to get the acreage held by production. It could be argued, each mile will support at least 8 wells in the better areas but QEP would argue it supports 12. Figure 6 was very interesting, as it proves my point that Whiting's use of less water and proppant is hurting long term production moreso than other producers. The 40% decline has to do with cheap well design and does not show what the majority of producers are doing and have done. I didn't like the use of Marathon either, as it has treated this play as an afterthought, and is focusing on other areas. Brigham on the other hand is a good choice, but should be noted that it wasn't just working the best areas and has considerable completions in shallower less productive areas that are much cheaper to drill. The idea that a larger number of wells need to be drilled to increase production is true, but he doesn't calculate these wells will only deplete to a certain point and produce the same rate for about a decade and a half. It also doesn't cover recompletions which are much less expensive and will increase production from these wells significantly. After that we will have waterfloods, which have been effective for EOG. Also, having no data after Aug of 2011 could have caused a big hole in this information. Around that time, most of the producers increased stages, water, etc. I think we would see the last year as a big move in the Bakken. When the price of oil needed was figured he said gas sales were marginal, but forgot about natural gas liquids which are definately not marginal. The question is, how much would this effect the price of oil needed? In northeast McKenzie County it is 11% of total well production. Prices move around a bit but look at this price as approximately $40/barrel. It would constitute about 5% of total production. Also, when looking at an oil price needed to make the Bakken viable there are other ways to look at this. Continental estimates EURs are 604 MBoe. This is the middle Bakken in North Dakota across its acreage. The cost to drill in deeper areas is about 10 to 11 million. In western Williams and southern Divide this number is about $2 million less. These areas are lower pressured and produce lower initial IP rates, but deplete at a slower wait. About half of all well production is produced in the first 5 to 5.5 years. Going back to the EUR of 604MBoe, we would get about 302 MBoe in the first five years. Of this about 270000 would be barrels of oil. Multiply this by $80 oil and you get $21.6 million in revenue. I would also remember the Kodiak has a Koala well the produced 1200 Boe/d for the first 90 days. Thats 108000 barrels of oil equivalent in three months.
Oil Service Companies Are Cheaper, May Be Safe Way to Invest in Oil [View article]
Tom, Craig, and IgnisFatuus, I am very sorry for the mistake but I did not disclose the positions I have in both BEXP and KOG. I did send a message to the editorial team for this oversite to be fixed. I used both companies as an example not to say they were a poor investment, but to say they were very good investments that an investor may be wary of as they are more levered to the price of oil than an oil service company. Again I am sorry, and I thank those who gave me the benefit of the doubt, I appreciate it.
Bakken Update: Depletion Of The Top 20 Oil Producing Wells In The Bakken [View article]
rlp,
Its not misleading. No matter what the 24 hour or peak IP rate is, they would still produce the same amount of resource if the 90-Day IP rate is the same. There is too much focus on the depletion over a very short period of time, when the numbers that matter are how many barrels are produced for the full year. I suppose one could focus on how much less oil is produced over the first 90-days, but it does little to show how economic a well is. Besides, EOG wells do not produce huge IP rates in the Bakken (although some of their wells have been big) but these wells deplete slower and will catch up to the wells with bigger chokes. Focus should be placed on how quickly these wells pay back, as that is what we want to know with respect to our investment.
I appreciate it, its good to know you benefitted from this article. I will say it was easy to write, Sandridge (SD) is a great story. I bought into a position just after I wrote it. Have a great weekend.
I think the Dynamic acquisition is summed up by Mr. Ward quite well. During our discussion, he stated the purchase of Dynamic was one of value and not as much a perfect "fit" with respect to its holdings. When he calculated the acquisition in terms of oil, it was much cheaper than purchasing anything in the Permian.
He did the same thing when he purchased the Permian and Mississippian acreages. The Permian (conventional oil) was out of favor at the time, as everyone was buying tight gas assets. The Mississippian was thought to not be economic due to its very high water production. He was right about that asset as well.
I guess Dynamic was one of the same type of investments, and if history repeats itself this will turn out a winner as well.
Bakken Update: Continental Continues To Seek Better Differentials [View article]
Mark,
Your theory has some serious holes in it. You look at all production over a period of years without accounting for improvements in drilling and completions. The number of stages, amount of water and proppant, type of proppant are just a few variables that can affect the depletion curve. The biggest flaw is lateral length. If one of EOG's initial Parshall Field wells was 4500 feet in length how can you compare that to a 14000 foot lateral? If both EOG and CLR drill 400 wells (just a generic number) but EOG averages a lateral length of 5000 feet while CLR averages 10000 feet how is a comparison made. I know you want to provide an easy to use calculation to help investors calculate EURs, but you are probably just confusing the subject by offering something with little to know value.
Bakken Update: Is Whiting For Sale? Part I [View article]
DAP56, Thanks for your input, here is what Whiting said at its last quarterly earnings call transcript.
We have also initiated pad drilling and completions at Sanish. Combined with our DWOP program, which stands for drill wells on paper, white sand and sliding sleeve completions, pad drilling is providing efficiencies for drilling and fracture stimulation that lead to an estimated savings of $2 million per well. These factors enable us to drill and complete our Williston Basin wells for approximately $7 million.
Here is their estimates on Pronghorn wells:
Will Green - Stephens Inc., Research Division I wonder if we could touch on the Pronghorn, the first Pronghorn pad you guys drilled. Could you guys maybe give me an idea of where that pad came in cost wise?
Michael J. Stevens - Chief Financial Officer and Vice President Yes, we drilled -- drilling the first 2 wells, we drilled the 2 wells for $8.8 million. That's both wells. So that's $4.4 million per well. And so our -- what we're thinking is we should be able to get the fracs and everything, the facilities, everything done for about $2 million a copy. So we're thinking those wells are going to be in the range of $6.5 million, plus or minus, somewhere in there.
I don't remember exactly where, but its Sanish wells are in the $6.5 million range. I think about a half million less than its average in other areas.
The point that is generally missed when quoting well prices are what is being used. Well costs can be higher and still drive better IRRs. Most do not look out past the 90 day IP rate to figure production numbers, but this causes a lot of confusion because EURs can vary significantly. Whiting uses half as much proppant and it is pretty much all sand where a company like Kodiak that uses all the best stuff and plenty of it (4 million pounds and uses a mix of white sand and ceramic proppant). Kodiak also uses about twice the water. Kodiak's 24 hour IP rates may not be that much higher than a Whiting well, but that has more to do with Kodiak's generally using tighter chokes. When you get out to the 90 day IP rates, Kodiaks are double that of Whitings. Each company operates by a different set of principals, as where Kodiak wants to spend more now and get paid more later, where Whiting does all it can to keep costs down, but longer term its wells are not as good as Kodiak's. Although well costs have risen, water and proppant prices have decreased some. Trucking costs use to be $4/barrel and $150/hour, and we have seen some big time undercutting, which is helping as well. I am guessing we could see completion costs also pull back some. Each well is different in one way or another, so generalizing is difficult. Have a great night.
Bakken Update: Brigham's Completion Design Is One Of Best In The Williston Basin [View article]
jjed88,
I made a recent shift in my investments as a company I work with is setting up a couple of water depots to sell to the oil companies. I am helping to finance this, so I needed to liquidate some assets.
If it wasnt for this I would still own stock in KOG, TPLM, OAS, NOG, CLR. Those should all work well going forward. Given their hedges I think they will all be ok, but I would also exercise caution as we could see some very heavy volatility in the price of oil. We got great news from China today (or at least better than expected), but I hope their numbers are correct. Europe could be a mess for a while as well, so I would operate with tight stops in place if investing in smaller companies. Long term all are very good, and the Bakken differentials should see a big improvement by the end of the year.
Bakken And Western Canadian Select Differentials Will Improve [View article]
There are several plays that are interesting right now and the favorites seem to be the Anadarko Woodford, Niobrara (only in some areas), Mississippi Lime, Granite Wash, Utica, Barnett Combo, but I like the Wolfcamp. Low well costs with quite a few shallow payzones and high liquids content.
Recent Commentary on Northern Oil & Gas: A Short Retort - All Smoke, No Gun [View article]
Bakken Update: The Red Queen Is Just A Fairy Tale Part III [View article]
The 24 hour IP rate was a generalization that I should have been more clear on. Because of the varied size of chokes 24 hour IP rates can be all over the board. So 24 hour IP rates or even 30 day IP rates can be misleading and should not be used to formulate an idea of production for the life of the well. Most production models use at the very least 90 day IP rates because of this. One thing I would say about arguments on depletion is the glass is half full or half empty. Unconventional wells produce a huge amount of resource in the beginning of well life. About half of all well production is produced in the first 5.5 years. These wells produce for 32 to 40 years. You can focus on the depletion number and the negative or you could focus on how quickly these wells pay back. This is a financial site and we focus on economics and how those economics will pay back investors. Try to keep in mind that some of the best oil companies in the world are developing the Bakken, and they aren't doing this because they are losing money. Have a great night and thank you for the comments.
Bakken Update: Is Whiting For Sale? Part I [View article]
Figure 6 was very interesting, as it proves my point that Whiting's use of less water and proppant is hurting long term production moreso than other producers. The 40% decline has to do with cheap well design and does not show what the majority of producers are doing and have done. I didn't like the use of Marathon either, as it has treated this play as an afterthought, and is focusing on other areas. Brigham on the other hand is a good choice, but should be noted that it wasn't just working the best areas and has considerable completions in shallower less productive areas that are much cheaper to drill.
The idea that a larger number of wells need to be drilled to increase production is true, but he doesn't calculate these wells will only deplete to a certain point and produce the same rate for about a decade and a half. It also doesn't cover recompletions which are much less expensive and will increase production from these wells significantly. After that we will have waterfloods, which have been effective for EOG. Also, having no data after Aug of 2011 could have caused a big hole in this information. Around that time, most of the producers increased stages, water, etc. I think we would see the last year as a big move in the Bakken.
When the price of oil needed was figured he said gas sales were marginal, but forgot about natural gas liquids which are definately not marginal. The question is, how much would this effect the price of oil needed? In northeast McKenzie County it is 11% of total well production. Prices move around a bit but look at this price as approximately $40/barrel. It would constitute about 5% of total production.
Also, when looking at an oil price needed to make the Bakken viable there are other ways to look at this. Continental estimates EURs are 604 MBoe. This is the middle Bakken in North Dakota across its acreage. The cost to drill in deeper areas is about 10 to 11 million. In western Williams and southern Divide this number is about $2 million less. These areas are lower pressured and produce lower initial IP rates, but deplete at a slower wait. About half of all well production is produced in the first 5 to 5.5 years. Going back to the EUR of 604MBoe, we would get about 302 MBoe in the first five years. Of this about 270000 would be barrels of oil. Multiply this by $80 oil and you get $21.6 million in revenue. I would also remember the Kodiak has a Koala well the produced 1200 Boe/d for the first 90 days. Thats 108000 barrels of oil equivalent in three months.
Oil Service Companies Are Cheaper, May Be Safe Way to Invest in Oil [View article]
I am very sorry for the mistake but I did not disclose the positions I have in both BEXP and KOG. I did send a message to the editorial team for this oversite to be fixed. I used both companies as an example not to say they were a poor investment, but to say they were very good investments that an investor may be wary of as they are more levered to the price of oil than an oil service company. Again I am sorry, and I thank those who gave me the benefit of the doubt, I appreciate it.
Investing in the Bakken (Part I): 8 Companies With a Market Cap Under $1B [View article]
You are totally right about the pullback, its just a matter of when. But when it does happen I am loading up. Have a great day.
It's About Time Halliburton Got Some Love [View article]
Bakken Update: Depletion Of The Top 20 Oil Producing Wells In The Bakken [View article]
Its not misleading. No matter what the 24 hour or peak IP rate is, they would still produce the same amount of resource if the 90-Day IP rate is the same. There is too much focus on the depletion over a very short period of time, when the numbers that matter are how many barrels are produced for the full year. I suppose one could focus on how much less oil is produced over the first 90-days, but it does little to show how economic a well is. Besides, EOG wells do not produce huge IP rates in the Bakken (although some of their wells have been big) but these wells deplete slower and will catch up to the wells with bigger chokes. Focus should be placed on how quickly these wells pay back, as that is what we want to know with respect to our investment.
My Take On SandRidge [View article]
I appreciate it, its good to know you benefitted from this article. I will say it was easy to write, Sandridge (SD) is a great story. I bought into a position just after I wrote it. Have a great weekend.
My Take On SandRidge [View article]
I think the Dynamic acquisition is summed up by Mr. Ward quite well. During our discussion, he stated the purchase of Dynamic was one of value and not as much a perfect "fit" with respect to its holdings. When he calculated the acquisition in terms of oil, it was much cheaper than purchasing anything in the Permian.
He did the same thing when he purchased the Permian and Mississippian acreages. The Permian (conventional oil) was out of favor at the time, as everyone was buying tight gas assets. The Mississippian was thought to not be economic due to its very high water production. He was right about that asset as well.
I guess Dynamic was one of the same type of investments, and if history repeats itself this will turn out a winner as well.
Bakken Update: 2013 Top Bakken Stock Picks [View article]
Always great hearing from you. I appreciate all the time you spend reading my articles.
Bakken Update: EOG Wells Model EURs Over 2 Million Barrels Of Oil [View article]
Bakken Update: Continental Continues To Seek Better Differentials [View article]
Your theory has some serious holes in it. You look at all production over a period of years without accounting for improvements in drilling and completions. The number of stages, amount of water and proppant, type of proppant are just a few variables that can affect the depletion curve. The biggest flaw is lateral length. If one of EOG's initial Parshall Field wells was 4500 feet in length how can you compare that to a 14000 foot lateral? If both EOG and CLR drill 400 wells (just a generic number) but EOG averages a lateral length of 5000 feet while CLR averages 10000 feet how is a comparison made. I know you want to provide an easy to use calculation to help investors calculate EURs, but you are probably just confusing the subject by offering something with little to know value.
Bakken Update: Is Whiting For Sale? Part I [View article]
Thanks for your input, here is what Whiting said at its last quarterly earnings call transcript.
We have also initiated pad drilling and completions at Sanish. Combined with our DWOP program, which stands for drill wells on paper, white sand and sliding sleeve completions, pad drilling is providing efficiencies for drilling and fracture stimulation that lead to an estimated savings of $2 million per well. These factors enable us to drill and complete our Williston Basin wells for approximately $7 million.
Here is their estimates on Pronghorn wells:
Will Green - Stephens Inc., Research Division
I wonder if we could touch on the Pronghorn, the first Pronghorn pad you guys drilled. Could you guys maybe give me an idea of where that pad came in cost wise?
Michael J. Stevens - Chief Financial Officer and Vice President
Yes, we drilled -- drilling the first 2 wells, we drilled the 2 wells for $8.8 million. That's both wells. So that's $4.4 million per well. And so our -- what we're thinking is we should be able to get the fracs and everything, the facilities, everything done for about $2 million a copy. So we're thinking those wells are going to be in the range of $6.5 million, plus or minus, somewhere in there.
I don't remember exactly where, but its Sanish wells are in the $6.5 million range. I think about a half million less than its average in other areas.
The point that is generally missed when quoting well prices are what is being used. Well costs can be higher and still drive better IRRs. Most do not look out past the 90 day IP rate to figure production numbers, but this causes a lot of confusion because EURs can vary significantly. Whiting uses half as much proppant and it is pretty much all sand where a company like Kodiak that uses all the best stuff and plenty of it (4 million pounds and uses a mix of white sand and ceramic proppant). Kodiak also uses about twice the water. Kodiak's 24 hour IP rates may not be that much higher than a Whiting well, but that has more to do with Kodiak's generally using tighter chokes. When you get out to the 90 day IP rates, Kodiaks are double that of Whitings. Each company operates by a different set of principals, as where Kodiak wants to spend more now and get paid more later, where Whiting does all it can to keep costs down, but longer term its wells are not as good as Kodiak's. Although well costs have risen, water and proppant prices have decreased some. Trucking costs use to be $4/barrel and $150/hour, and we have seen some big time undercutting, which is helping as well. I am guessing we could see completion costs also pull back some. Each well is different in one way or another, so generalizing is difficult. Have a great night.
Bakken Update: Brigham's Completion Design Is One Of Best In The Williston Basin [View article]
I made a recent shift in my investments as a company I work with is setting up a couple of water depots to sell to the oil companies. I am helping to finance this, so I needed to liquidate some assets.
If it wasnt for this I would still own stock in KOG, TPLM, OAS, NOG, CLR. Those should all work well going forward. Given their hedges I think they will all be ok, but I would also exercise caution as we could see some very heavy volatility in the price of oil. We got great news from China today (or at least better than expected), but I hope their numbers are correct. Europe could be a mess for a while as well, so I would operate with tight stops in place if investing in smaller companies. Long term all are very good, and the Bakken differentials should see a big improvement by the end of the year.
Bakken And Western Canadian Select Differentials Will Improve [View article]