Dean has provided me with his latest update for Texas Oil and Natural Gas production. Texas C+C output has increased slightly over the first 3 months of 2016.
Texas C+C output was 3549 kb/d in March 2016, about 39 kb/d higher than February.
Texas crude output was 3079 kb/d in March 2016, about 29 kb/d higher than February.
Condensate output was 470 kb/d in March 2016, 11 kb/d higher than February.
Natural gas output in Texas was 24,690 MMCF/d, 309 MMCF/d higher than February.
Using RRC data, I determined the percentage of Texas C+C output produced in the Eagle Ford Shale from April 2012 to March 2016. This percentage was than multiplied by Dean’s estimate for Texas C+C output to get an estimate of Eagle Ford C+C output from April 2012 to March 2016. The Chart below compares the RRC data for the Eagle Ford with my estimate using Dean’s Texas C+C estimate.
Eagle Ford output was about 1390 kb/d in March 2016, about 20 kb/d higher than February. The annual decline rate from Feb 2015 to March 2016 was about 220 kb/d or roughly 15% per year. Since November 2015 Eagle Ford output has declined very little. The red data points are used for the trend line in the chart below.
Based on RRC data on Eagle Ford wells completed, there have been 1500 wells completed from Nov 1, 2015 to May 1, 2016, an average of 300 wells per month. This seems too high and may be another example of poor RRC data.
Enno Peters shared some Eagle Ford well data with me and I was able to develop better well profiles.
The chart below shows the average well profile for wells starting production from Jan 2009 to Dec 2012, for 2013 wells, and for wells starting production after 2013.
Newer wells are more productive over the first 20 months, but after that the well profiles are very similar.
The EUR for current wells is about 220 kb over a 15 year well life (I assume the well is abandoned at 6 bo/d). EUR is 150 kb at 36 months and 174 kb at 60 months.
If we assume a developed lease where all site development has been completed (pads, storage tanks, etc) and are looking at drilling a well in an open slot on an existing well pad, then well is paid for in 36 months (assuming $6.5 million to drill and complete the well, OPEX of $8/bo, royalty of 25%, and taxes of 7%) if the well head price is $72/b.
For a DUC, the completion costs are paid for (cost of $4.4 million) in 36 months under the same assumptions as above at a wellhead price of $51/b.
For the past 5 months there have been an average of about 160 new wells per month completed in the Eagle Ford. If we assume this completion rate falls to 140 new wells per month by May 2016 and remains at that level until 2020 we get the scenario below. An alternative scenario where completions fall to 90 wells per month by Oct 2016 and remain at that level until 2020 is also shown. I expect Eagle Ford output will be between these two scenarios until oil prices rise above $80/b for 6 months or more.
The Eagle Ford Gas Oil Ratio (GOR), which is casinghead gas divided by oil (crude) produced from March 2009 to March 2016 is shown in the chart below. In March 2016 the GOR was 2016 CF/b and the average GOR for the last 6 months has been 2025 CF/b.
My Eagle Ford estimate is compared with the DPR estimate (which includes non-LTO output from the Eagle Ford region) and the Drilling info estimate from the EIA. The estimates match fairly well through Dec 2015, but based on Dean’s estimate and data from the RRC on the percentage of total Texas output from the Eagle Ford play (39% in March 2016 and 43% in July 2015), Eagle Ford output has been relatively flat from Nov 2015 (1384 kb/d) to March 2016 (1386 kb/d).
According to the EIA oil directed rig count in the EF is about 30 rigs. At that rate of drilling it is hard to see the completion rate as high as indicated.
Hi R DeRoches,
There are a lot of DUCs to be completed. Lets guess about 900 in the Eagle Ford.
Let’s also assume the rig count remains at 30 and 2 wells per rig per month can be drilled.
At 115 completions per month (average of my two scenarios), we would need to use 115-60=55 DUCs per month and 900/55=16 months. Do you expect oil prices to remain low for more than 16 months?
I do not. If prices remain low, eventually completions may fall to 60 per month, I don’t think the low oil prices forever scenario is very realistic.
I think oil prices will start to rise at least by late 2017 and be at $80/b by mid 2018 (possibly higher).
I also could be very wrong. There are some very smart people that think that oil prices will remain under $60/b until 2019 or 2020. If they are correct, then my low scenario will indeed be too high.
Thinking a little more on this I realize that the pessimists and optimists agree that oil prices may be low long term. Over the medium term I expect oil prices will rise to at least $80/b and perhaps to $130/b by 2025, eventually oil prices will fall either because plugin hybrids and EVs gain market share or because of a second Global Financial Crisis(GFC).
Either of these two scenarios between 2030 and 2040 seems plausible, but I think oil prices will rise between 2017 and 2025, before levelling off at around $125/b. After that it is change or crash, hard to know how it plays out.
According to Baker Hughes, the latest oil rig count in the Eagle Ford is 27.
According to Rystad Energy, the inventory of drilled, but incompleted wells (DUCs)
in the Eagle Ford is around 1,000.
An earlier report by Rystad indicates that, as of December 2015, the number of DUCs in the EFS was only slightly above 1,000.
Therefore, with rapidly declining rig count, completion of the DUCs could not reverse the decline in Eagle Ford oil production.
To note, EOG, the largest operator in EFS, said earlier this year that it did not intend to ramp up output until oil prices stabilize at $6o.:
“Bill Thomas, chief executive at EOG Resources Inc., the largest landholder in Texas’s Eagle Ford shale formation, told attendees at an industry conference in Houston on Wednesday that his company won’t start boosting output the first time oil hits $60 a barrel.
“We’re going to make sure the market is in good shape, it’s balanced, and we’ve got a future,” Thomas said. “We don’t want to ramp it up and drive the price of oil down again.”
http://www.bloomberg.com/news/articles/2016-02-10/oil-explorers-can-t-turn-on-light-switch-to-boost-output-eog
Dennis,
As you may remember, I had said several times that the EIA/Drillinginfo and DPR data underestimates oil production in the Eagle Ford.
But I also doubt that Dean’s estimates for EFS or Texas are correct.
I think there was a decline in the first months of this year, probably not as steep as the EIA data shows.
Hi AlexS,
The estimates for the Eagle Ford are not Dean’s estimates, they are my estimates, if they are wrong Dean had nothing to do with them.
I think Dean’s estimates for Texas are likely to be correct, as you often note the EIA keeps revising their estimates upwards coming closer to Dean’s estimates.
Dean’s estimates have been quite consistent and although he was skeptical at first, he now thinks his estimate is pretty good.
Note how close my estimate for the Eagle Ford Shale is to the drilling info estimate through Dec 2015. Drilling info uses the RRC data plus the “pending file” which I do not have access to. I think you will find that over time the most recent three months of the drilling info file are a little too low due to the incomplete nature of the RRC statistics.
Time will tell.
One problem with my model is that I do not have access to up to date well data like the data that Enno Peters graciously shares for the Bakken.
I have used an average well for the 2013 to 2016 data set that Enno has shared with me in March for the Eagle ford. The well profile may have shifted up over time and I may be using too many wells if that is the case.
Note that EOG is conservative, there may be other companies that will complete wells at less than $50/b.
We don’t really have good data on how many wells are being added each month.
Chart below compares an EF estimate (EF1) using Dean’s estimate for Texas output and an EF estimate (EF2) using the EIA’s Texas estimate based on the percentage of Texas output produced in the Eagle Ford Play according to RRC data. Also included on the chart is the Drilling Info estimate which matches the EF1 estimate closely from April 2015 to Dec 2015.
Hi AlexS,
It may be that the best estimate is between Dean’s and the EIA. Neither of my scenarios shows output increasing, but the EIA has continually needed to increase its estimates. The drilling info estimate for the Eagle Ford is slightly higher than my estimate until Jan 2016.
For the 90 well per month estimate, we need 46 DUCs per month, if there are 800 DUCs we could go for 17 months at 27 rigs, or if 200 DUCs minimum must be maintained, then 13 months before completions would need to decrease or rigs increase.
Dennis,
Rystad Energy estimates, that the number of DUCs in EFS has decreased only marginally from from slightly above 1000 units in December 2015 to 1000 in April 2016 (see my comment above). With a significant decline in drilling activity, there was no increase in well completions in 1Q16.
Note, that this was the bottom of the cycle, with very low oil prices.
Yes, the EIA/Drillinginfo is constantly and significantly increasing its estimates for the Eagle Ford (see the chart below). And there will be further upward revisions. But I doubt that production there could have increased in the first several months of this year.
Hi AlexS,
I believe that nobody has very good data for Texas (including the RRC). There is a possibility that the Eagle Ford has had a very slight increase, just as in North Dakota there has been less of a decrease than was expected. Note that for the Eagle Ford output has basically been flat, the increases in Texas output comes from the Permian basin where the decrease in drilling and completion activity has decreased the rate of increase in output there, but there could have been a slight increase there. Maybe in the end output will be flat, note that the increase in Texas output from Nov 2015 (3458 kb/d) to March 2016 (3549 kb/d) has been only 91 kb/d or 2.6%. This is about a 23 kb/d average increase each month, considerably slower than the 51 kb/d average monthly increase from Jan 2014 to March 2015 (using EIA data).
Hi AlexS,
You said (in reference to the Eagle Ford play):
But I doubt that production there could have increased in the first several months of this year.
The estimates show increases in the Eagle Ford that are essentially statistical noise, output has basically been flat since November (within the margin of error). The increases in Texas output are from the Permian basin which has been increasing output at an average rate of about 20 kb/d each month since Jan 2015. So Texas output has risen as the Eagle Ford decline flattened since Nov 2015 while the Permian basin continued to increase.
I have more faith in Dean’s estimates than you, but we will have to wait to see how it plays out, oil prices will be key and those are difficult to predict (at least for me).
I have faith in Enno Peters’ estimates.
Eagle Ford – update until 2016-02
Hi Ron,
Enno is just using RRC data, do you have faith in those as well?
Hi Ron,
Also Enno’s data for the Eagle Ford is oil only, which for the past 3 months has been about 80% to 82% of C+C output in the Eagle Ford. My estimates are for C+C, to be compared with Enno’s estimates they should be multiplied by about 0.81 for the most recent 3 months.
Revisions in the EIA/Drillinginfo monthly LTO production statistics for the Eagle Ford (kb/d)
Hi Alex, find below the dynamics of my correcting factors, that is the total cumulative sum of the Texas RRC revised data for each month up to T-23 (I am sorry I’m not able to post the image here,this is why I post the link):
https://pbs.twimg.com/media/CjYybAmUkAISXo6.jpg
As you can see the dynamics is stationary so far; moreover, they are again coming back to the mean after the Jan2016 blip.
Therefore, there are only 2 possibilities:
1) either there is some (hidden) major problem with the Texas RRC data which is not yet fully reflected in the official data, and unfortunately I cannot do anything about it;
2) Texas oil production has increased a bit in the first months of 2016.
As my Latin ancestors would say, “tertium non datur” (“no third possibility is given”) 🙂
Question for shallow sand- How does $49.xx oil work for you?
Much better now than 2014.
Not good enough to drill new wells.
Cash flow positive.
Since 2014 have been able to cut expenses in all areas except:
1. Electricity (not counting shut in wells, of course, which we are now reactivating).
2. Annual well fees.
3. Ad valorem taxes.
4. Severance taxes.
5. Liability insurance.
Everything else costs less than 2015, which cost less than 2014.
Hard to believe, but likely May will have the highest monthly average price since July, 2015.
We are 18 months into the bust, which I feel became official Thanksgiving Day, 2014. The downturn started in June, 2014, so almost to the two year point since the price first turned.
Would like to see $55-65 WTI. Would be akin to 2005-2006, which were very good years for us, and which would not drag down the US economy IMO, as gas would be $2.50-2.60 range.
Think would see slight uptick in LTO activity, but nothing big.
Recall retail sales includes gasoline.
Brent above $50 today; WTI very close to it.
I still think a mild price correction is possible in the next month or two before upward trend continues in 2H 2016.
Shallow sand, do you think shut in stripper wells will re-start at these levels?
Agree with you that there will be some uptick in LTO activity later this year.
Overall U.S. C+C output will likely bottom by the end of 2016, rather than mid-2017, as expected by the EIA.
Yes, will restart shut in strippers, not all, but many. Summer weather will affect that also. Many wells shut down in winter out of necessity, likely were slow to be reactivated, but will come back online now.
Will be interesting to watch not only hz rig count, but vertical also. I sense there is a lot of balance sheet healing needed, plus a lot of caution given collapse post June, 2015.
Lack of vertical rigs will mean US onshore conventional will continue to decline.
Hi Shallow sand,
Won’t the reactivation of shut in strippers at least reduce the rate of conventional decline? I would think there might be some people out there that might drill some wells as prices improve. At $58/b, after a few months (say 4 months) of balance sheet repair would you be in a position to drill new wells or would you wait for $65/b?
Dennis. Each company is in a different situation.
Yes, reactivation will reduce conventional decline.
Note Hess has added three rigs in Bakken this week.
Hi Shallow sand,
I guess that was my point, some wells might be drilled by more aggressive (or desperate) companies and if that is the case the decline may stop. I doubt there will be enough to get US output to increase until we reach $75/b or more, but $60/b may result in flat output if we ever get there (Sept or Oct 2016 would be my guess).
Eagle Ford – Investor bait and prospective on FCF.
” The idea is that through staggered well laterals, Devon and BHP will be able to increase the number of wells the partnership brings online to 12 per section. Initial results have been promising, with production results on par with other top tier wells in the area.”
http://seekingalpha.com/article/3977818-devon-energy-generated-free-cash-flow-eagle-ford-operations
The EIA’s Monthly Energy Review is out today with production data for April. US C+C production fell 123,000 barrels per day in April to 8,915,000 barrels per day. US lower 48 fell 100,000 bpd while Alaska fell 23,000 bpd.
This data matches the weekly data very close. 8,915 K barrels per day is the average for April, not the production on the last day or the last week. The EIA has production for the third week in April at 8,767 K barrels per day. So it looks like US production will fall about the same amount in May as it fell in April, about 125,000 barrels per day.
US C+C production has fell 779,000 barrels per day since peaking one year ago in April.
That’s ok. Once Trump wins president he’s gonna go over to Iraq and get “our” oil.
After booting Chinese, Russian and European oil companies out of there, he is gonna produce the oil with the usa’s government owned oil company.
I forget what they are called. / sarc
Satan’s,
Trump announced that once he’s elected he’ll approve Keystone XL. He’ll also reduce those regulations that are holding back the oil industry.
KXL will make such a difference! I hear the Millennium calling.
Keystone XL will allow more Canadian extra heavy to move to the USA Gulf of Mexico refineries, which are equipped to handle this crude. This will back out Venezuelan faja tanker shipments, which will have to move on a long distance haul to India and China.
I’ve written about this subject before, a lot of what Obama does is helping the Cubazuelan dictatorship, which is allied with Iran, Russia, Belarus and North Korea. This tells me either Obama is mentally retarded or he’s a commie whose main focus is weakening the USA. Take your pick.
Fernando,
I don’t believe that Obamas decision on Keystone has anything to do with your focus on any kind of Venz/Cuba version of the world. Frankly, that is just not a priority of usa policy, whatever you may wish.
He just found the political fallout from all the farming landownwers, and populace concerned about wetland contamination from spills and global warming, to be too much of a headwind to make it worthwhile.
Not saying I agree with his decision, but thats version of reality it looks like from here.
The Cuban and Venez political problems aren’t the fault (or focus) of the USA. Maybe in 1950, but not 65 years later.
A lot of people seemed to get pissed at the USA if they perceive it as too involved in their country, or not involved enough. It seems like a no win scenario. Easy target for blame I suppose.
The vast majority of Americans have been ready for a “glasnost” with Cuba for about 30 years now. I guess that makes us all “retarded or commies” – so be it.
The “glásnost” isnt with Cuba, its with the Castro family dictatorship. By the way, im a US citizen, but i live abroad and my job has involved paying close attention at USA foreign policy.
I understand the Keystone issues he faced. Basically he found it easier to pander to the left than to increase USA energy security. The heavy oil continues to move into the USA, but it does so by tanker, and comes from Venezuela.
I also realize that USA foreign policy is mostly driven by a mix of the Israel lobby and imperialists who think the USA has to be the world’s police entity. The results are grim, as shown by the defeats the USA continues to suffer everywhere. Thus we see how the Cubazuelan problem has been allowed to fester to the extent that today Venezuela is facing disease and famine, driven by Obama’s friends in Havana.
I realize the average Anerican is mostly a dupe when it comes from these issues. They tend to swallow the junk the media serves, and dutifully become patriotic whenever the USA is going to make a blunder like invading Iraq.
So I’m not surprised the same kind of wise guys who crafted the message about the Iraq WMD are born again and convincing the American people that giving legitimacy to an enemy dictator and helping him colonize other nations is a fine idea.
I’m not going to address your perceptions about the world, other than to say we must be smoking very different herbs from each other.
Hi Ron, what do you think the actual (not average) production for the last day of May will be?
Somewhere between 8,730,000 and 8,740,000 bpd.
Note: The US weekly production numbers have historically been way off, creating huge corrections in some weekly numbers. That is huge jumps up or down to correct for past errors. But they seem to have gotten a lot better lately. Their weekly numbers now match pretty closely those of both the Petroleum Supply Monthly and the Monthly Energy Review.
The Petroleum Supply Monthly will be published Tuesday, May 31st with data for March.
It will be interesting to see the EIA data as it is updated, those last data points are mostly based on the weekly data which is pretty useless, the last good data point in that chart is Feb 2016 and that is an underestimate because the EIA may be underestimating Feb 2016 Texas output by 189 kb/d based on Dean’s analysis.
Hi Ron,
An alternative estimate for US C+C output is to use Dean’s estimate for Texas C+C instead of the EIA’s Texas C+C estimate and assume the EIA estimates for the rest of the US is correct.
The linear trend from April 2015 to Feb 2016 using a least squares linear fit declines at an annual rate of 270 kb/d over a 12 month period, the average output over that period is 9420 kb/d so the annual decline rate is about 2.9%. I ignore the final two data points from the Monthly energy review because these tend to be based on the weekly data and are usually not very accurate.
I will hold off on further estimates until the EIA’s Petroleum Supply Monthly comes out on May 31st with March data. They may revise February and revise their Texas production numbers. But there is just no chance, in my humble opinion, that they will be revised enough to match Dean’s estimate. I am betting it will be revised very little, that this survey will match the EIA’s Monthly Energy Review numbers of 9,038,000 barrels per day pretty closely. Perhaps a little higher but still below 9.1 million barrels per day.
And your trend line is crap. You start it two months before the peak, at a time when production was still surging upward.
Hi Ron,
As I said in my comment the trend line is based on the data from April 2015 to February 2016. The data is below for those months.
9670
9461
9322
9450
9445
9498
9432
9378
9330
9319
9315
The chart below shows the least squares linear fit which you can do yourself in Excel (just add a trend line and choose linear). You may not think this is the best way to do a trend line, but it is pretty standard practice.
The Japanese are paying 32,530 yen for a metric ton of oil today.
110 yen for a dollar, 295 usd for a metric ton, divide by 7.3 barrels, $40.51 for a barrel of oil in Japan today. Must get a discount when you buy 500,000 metric tons each day. They get all the breaks.
It’s Memorial Day weekend coming up, have to add ten cents at the pump, everybody is going some place to get away, everybody going some where to get away will be there too, might as well get another ten cents per gallon so they have to pay more to get there.
At 95,000,000 bpd gone each day, there is a lot of oil. There it was, gone.
“might as well get another ten cents per gallon so they have to pay more to get there.”
Unbelievable. I also checked, and Disneyland Hotels are charging twice that they did in December for the exact same room. And cottages in Maine are getting 10 times as much as they did in January, for the exact same cottage. It seems as if whenever demand goes up i.e., more people want the product, the price is raised for no reason at all. I know that you will not believe this, but they charged 10 times as much for Superbowl tickets as they did for regular season games – same stadium, same amenities, same game of football, same costs. I want a Congressional investigation of why that happens. Here, in Oklahoma City, they actually charge more to pay a round of golf on a weekend than during the week. Even the municipal courses. It is disgusting. I went to an evening movie and they charged more than for watching during the afternoon. This criminal activity has go to stop. We need something like communism to protect us from obvious price gouging.
next people will be queing for it
🙂
Here in France we are.
Raymond James says Saudi Arabia is lying about their production capacity.
Mystery: How much more oil can the Saudis really pump?
Mohammad Al Sabban, the former Saudi representative to OPEC until 2014, insists Saudi Arabia really has the ability to ramp up output to 12.5 million barrels a day.
Yet Al Sabban told Raymond James that only half of those barrels would be available immediately within days or weeks. The rest could take up to six months.
Raymond James thinks investors should take those claims with a grain of salt.
“We don’t buy the Saudi excess capacity argument,” the firm wrote.
Raymond James points to three reasons why they think Saudi is lying. I like #3 the best.
3.) Saudi rig counts are surging: There is a camp in the oil industry that believes Saudi Arabia’s oilfields have gotten so old that they aren’t as productive as they once were. For instance, the Ghawar field — the world’s largest with an estimated 75 billion barrels of oil — is over 60 years old.
Skeptics point to the fact that rig counts in Saudi Arabia have tripled over the past decade — even though output hasn’t gone up nearly as much. At the same time, Saudi stockpiles of oil have declined by around 30 million barrels since October 2015.
“If they only need to turn valves on to flood the market, why are Saudi oil inventories falling?” Raymond James asks.
Hi Ron, thanks for the links to those interesting articles. I really like your blog. It’s clearly the best oil production website going. Thanks too to Denis for carrying the torch. Saudi Arabia is of great interest to me. I hope you’re well and I wish not to be a burden but I’m interested to know if you’ll/or Denis’ll keep the monthly OPEC Chart up to date with the OPEC MOMR? I read the MOMR and await it every month like a kid counting down Christmas. I think the first hints of catastrophe will be hidden one day in a MOMR.
I wish you the best Ron. thanks a lot sharing your points of view.
Hi Survivalist,
For now Ron will keep updating the OPEC data. When he stops, I will continue and hopefully he will share his spreadsheet with me because reproducing it would be a lot of work.
Oil fields are never as productive once the first barrel moves out of the reservoir (the exception being wells which have to clean up after we pump water, mud, acid, and sand during completion). I see gobs of writing about Saudi fields which imply the authors think they are somehow magical, and can produce oil on and on forever.
Hey people, this is really a great article. Shale oil industry a ‘Ponzi scheme’ or can it boom again?
One analyst told CNBC that he doubted the very foundation of the U.S. shale oil industry which he said had been founded and expanded on cheap money and had effectively been a “Ponzi scheme” – an investment operation that generates returns for older investors by acquiring new investors.
“I think in ten years’ time someone is going to write a great book and make a great movie about the shale industry in the U.S. because I think it is, quite frankly, one of the biggest Ponzi schemes known to mankind,” Gavin Wendt, founding director & senior resource analyst at MineLife, told CNBC on Thursday.
“There Will Be Sand”
I drink your Shamrock Shake.
Light tight oil can be ok if the oil price allows the project to make money.
The risky aspect of the “shale” wells was the hyperbolic decline, how the water and gas oil ratio evolves over time, and whether the hyperbolic would flatten out to allow a long profitable production period. This story isn’t really finished, but it seems to me that, if they use pad drilling, avoid excessive cost increases, and oil prices are above $100 per barrel, they do ok. It’s not great, but it feeds the kids.
…and oil prices are above $100 per barrel, they do ok.
Hey, I don’t think anyone would question whether or not they would do okay at prices above $100 a barrel. It prices below that that they have problems with. Especially in the $50 to $60 range.
Hi Ron,
I agree. In fact I think they can make a profit at $80/b on average wells drilled on existing pads in the ND Bakken/TF and Eagle Ford (Probably Permian also but I do not have any data there). On think that people miss on the “break even” oil price is that it includes a discount rate (I use 15%) on future cash flows, this is essentially the return on investment. So “breakeven” means that the well makes a 15% profit, this seems to be missed by some people.
To me break even is at the cost of capital, including shareholder returns. Say you finance half at 7 %, and shareholders are happy with a long term 8 % return. Your cost of capital is 7.5 %
The use of a 15 % rate is not sanitary, it leads to poor decisions. If what you are trying to do is include risk, then risk the production, reserves, costs, whatever.
Hi Fernando,
Interesting. So breakeven should use a return rate equal to the cost of capital, that makes sense.
What king of rate of return do most companies look for before going forward with a project?
Essentially by using a 15% real discount rate, if the real cost of capital (adjusted for inflation) is 7.5%, the real rate of profit for the project would be 7.5%.
Or do companies look for a price deck that is x Constant dollars above the breakeven?
Yes. I would not drill at $60 per barrel unless the well can hold a lot of acreage. But $60 sure seems to be swell to complete those deferred wells we discussed in the past, when the price was $35.
Long term, this seems to be a play suitable for smarter companies which understand pad developments and can control costs. It’s not for those tasseled loafer carpetbaggers who only know how to do PowerPoint.
Hi Fernando,
For the DUCs, on a point forward basis they improve cash flow at $52/b or higher.
Hi all,
I found the percentage of Texas C+C output from the Permian Basin using RRC data, estimated conventional Permian basin output at about 520 kb/d for the Jan 2015 to March 2016 period and deducted this from the Permian Basin output (assumed no conventional decline, the value was held contast at 520 kb/d over this period).
Two estimates were created: Permian 1 uses Dean’s estimate for Texas C+C and multiplies by the % of Texas output from the Permian and then deducts 520 kb/d, Permian 2 is similar but uses the EIA Texas C+C estimate. Also included is the Drilling info Permian estimate which includes TX and New Mexico Permian output. I adjusted this by assuming all of the increase in New Mexico C+C output since Jan 2012 was from the New Mexico(NM) Permian Basin.
The average monthly NM C+C output from Jan 2002 to Dec 2011 was 174.25 kb/d, this value was deducted from NM C+C output from Jan 2012 to Feb 2016 to estimate NM Permian LTO C+C output. The NM Permian estimate was deducted from te Drilling info estimate for the TX and NM Permian to obtain a TX Permian Basin LTO C+C estimate. Using the Permian 1 estimate (which I believe is best), Permian basin output has increased by about 20 kb/d on average from Jan 2015 to March 2016. There has undoubtedly been some conventional decline in the Permian over that period, but I do not know how much, if that has been included LTO C+C increases would have been higher than 20 kb/d each month. Chart below.
Thanks for the post & data, Dean & Dennis.
I just posted a presentation on shale oil production in Montana, here.
Despite the low total volume of production, it presents an interesting case of two boom and bust cycles, as shale oil production already got well underway by 2003 in Montana.
Dennis
I liked your article entitled “Texas Update May 2016 And Eagle Ford Output Estimate”. I am particularly interested in the chart entitled “Well Profiles Eagle Ford”. I have been tracking the Niobrara play in Colorado in a similar fashion since the inception of the play in 2010.
If you could email the actual numbers used in the “average well after 2013” trace, I would send you a chart (and the numbers) of Niobrara production for this same time period. It will be VERY interesting to compare the two plays at this level of detail.
Perhaps of similar interest to you will be the comparison of the pre multi-stage-fracking wells (drilled in the 1990’s) with the muti-stage fracking wells that I have assembled for the Niobrara (drill post 2010). This data is EXTREMELY interesting.
RegardsArnie Ostrander
Arnie
Enno Peters has a great site that tracks the Niobrara. Just for reference. His link is posted above your comment.
Hi Arnie,
Thanks. I will post a link to an excel file with Bakken Well Profiles and Eagle Ford well profiles that were developed using data shared with me by Enno Peters.
The Eagle Ford data is something new that Enno had just begun when sharing the data so he cautioned that it might not be accurate, so the well profile should also be treated with caution.
Texas data is particularly tricky because most wells are on leases with multiple wells, often the wells did not begin producing on the same date. Unlike North Dakota which reports individual well data, Texas only reports the data by lease. So if on lease A well #1 started producing 12 months ago and well #2 started producing yesterday, from today into the future we have to estimate how much oil was from well 1 and how much from well 2.
Enno has somehow developed an algorithm to do these estimates automatically (he is very clever and must have some skill programming), but it is possible the estimates are inaccurate.
Caveat Emptor.
https://drive.google.com/file/d/0B4nArV09d398ZC1YcjZSUU1fb2s/view?usp=sharing
If you would still prefer an e-mail let me know.
Peak Oil 2.0: Is It Time to Panic?
On Friday, May 13, IHS Energy released an alarming new study. It found that the volumes of oil and gas discovered outside of the U.S. last year were the lowest since 1952.
Oil alone set a record low, with only 2.8 billion barrels of oil equivalent found during 2015.
The vast majority of large, conventional undiscovered oil and gas fields are offshore. Unfortunately, these fields are uneconomical to develop with oil prices below $80 per barrel.
That’s why a few years ago, when prices first dipped under $60, many oil companies refocused their efforts. They bet big on U.S. shale.
Now, many are regretting that decision. Most shale basins – other than the Permian – are losers at current WTI prices. (Though there are some winners, as I showed you here.)
There are various often optimistic estimates for undiscovered oil, but whether undiscovered reserves are 100 or 700 Gb doesn’t really matter, as only a fraction of them are going to be found within 50 years, and if we still need them then we probably really are screwed in more ways than one. On average discoveries have been dropping every year since a peak in the sixties. There have been a few years which buck the trend (e.g. 2010 above), but mostly we are at the tail end of a normal, or slightly negatively skewed normal distribution and finds will continue to fall. Last year discoveries were 2.8 Gb; this year we’ll be lucky to find a half of that, even natural gas hasn’t been great so far. In the medium term oil price doesn’t make much difference to the discovery curve shape; finds were generally falling between 2010 and 2014 even as budgets increased. In the past some of the larger fields were found in low price periods (e.g. Thunder Horse, Kizomba in the late ‘90s), but not now. Although there may be a few Johann Sverdrops around, mostly large new reserves will need to come from frontier regions. Since 2010 such areas have had an 8% success rate and since 2007 only contributed about 6 Gb. according to REP State of Exploration report.
This year budgets have been cut by over 70% compared to 2014, which obviously has an impact but, in a falling discovery trend, cuts make less difference than might be expected. The best prospects will always be drilled first, so (say) a 50% cut in budget only delays exploration in a particular field by a year or two. Technological improvements in seismic, drilling and reservoir modelling tend to increase the decline rate by bringing forward the better discoveries.
Companies will not invest in exploring prospects now that might only pay out if oil reaches a putative price at $200 in ten year time, especially when a) wells are costing $20 to over $100 million each with only a 20 to 50% chance of success, and b) the company is fighting for it’s life as production and reserves continually decline (the effective IRR in such conditions is very high, irrespective of what actual interest rates are). Marathon have stopped exploring, BP seem to be going the same way, Shell probably should stop given how bad they are at it, Exxon has traditionally (and maybe apocryphally) more exploration success on Wall Street than in the field. The places left to explore are not good compared to even the fairly recent past, with either poor reservoir prospects or inhospitable environments (e.g. the Arctic, offshore Canada, Bight Basin Australia, all of which have recently seen very expensive exploration projects delayed or stopped because of equipment damage due to bad weather). Maybe governments will need to backstop exploration, but at the moment the opposite is happening with national oil companies looking more towards private money for funding and technical input (e.g. Pemex, PetroBras, Iran, Iraq) whist also expecting to give less back from any eventual production profits (Angola, Nigeria, Iraq, Ecuador, Qatar). Very likely some moratorium areas will be opened up again.
In terms of a near term peak, new discoveries now don’t mean much either, if they can be quickly developed they are too small to make much difference and in the unlikely event they are really significant, they are probably ten years away from full plateau production.
Hi George,
There are plenty of proved plus probable reserves that have been discovered by not developed yet. Oil prices will rise and the reserves will be developed. The rise in prices will also change the estimates of proved, probable, and possible reserves and some resources that are currently in the contingent resources category will be reclassified as possible resources. This assumes demand for oil eventually peaks and decreases, but that demand falls more slowly than supply so that oil prices continue to increase in the future. There is likely to be a limit to such an increase (roughly 5% of GDP spent on oil) and there will also be a limit on the increase in reserves.
If we exclude extra heavy oil (XH) resources (API<10), the USGS estimates about 3600 Gb of C+C-XH and Jean Laherrere about 2200 Gb, the average of these is 2900 Gb, my medium scenario is 2800 Gb, low is 2500 Gb and high is 3100 Gb for C+C-XH.
All of these seem unreasonable to you, what do you think of Jean Laherrere's 2013 estimate of 2200 Gb?
http://aspofrance.viabloga.com/files/JL_2013_oilgasprodforecasts.pdf
Where are proved plus probable RESERVES that have yet to be developed? Chicontepec? Kashagan? Beaufort Sea? Yamal? Offshore Sakhalin? East Siberia? African rift? Falkland Islands? What are you calling reserves? I’m curious as to where you think we can go in the next ten years.
Hi Fernando,
I meant proved developed producing reserves (and should have said that, sorry), so in the US for example there were about 68 Gb of proved plus probable (F50) reserves at the end of 2014, but only 25 Gb of these reserves were proved producing reserves.
So about 37% of US proved plus probable reserves are proved developed producing (PDP) reserves.
For my medium oil shock model (2800 Gb of C+C less extra heavy (API Gravity <10)) there are about 348 Gb of producing reserves at the end of 2010 for the World and based on Jean Laherrere's estimate 2P reserves were about 850 Gb at the end of 2010, so that would be about 41% of World 2P reserves were producing at that time. I believe Laherrere my have underestimated 2P reserves a bit and think they may have been 950 Gb in 2010 and the World PDP to 2P ratio was about 37% (similar to the US 2014 level). I assume the 2800 Gb URR will be reached by a combination of discoveries and reserve growth (mostly reserve growth).
My guess is about 250 Gb of discoveries and 450 Gb of reserve growth after 2010.
I do not have a bottom up analysis, just a simple model.
Chart below shows PDP in millions of barrels (left axis) for a 2800 Gb URR C+C-XH Oil shock model. Extraction rate is from PDP reserves.
Hi Fernando,
Chart below shows discoveries (including backdated reserve growth), output and new producing reserves (reserves that start producing in any year). Producing reserves are cumulative and each year output is subtracted and “new producing reserves” are added to the cumulative total.
It looks as if the latest discovery numbers temporarily placed the data below the dispersive discovery curve. I had around 6 and your curve is around 7 for 2015, but this new data is 2.8.
http://www.azimuthproject.org/azimuth/files/dispersiveshock.gif
Dispersive discovery is a stochastic expected-value model and the actual data will jump around because of randomness, but it does look like it is on the right track to follow the decline.
Hi WHT,
Also there tends to be reserve growth and my interpretation of the dispersive discovery curve is that it includes backdated reserve growth. I agree on the stochastic nature of the discovery process. Some years will be above the model and others will be below.
I am always amazed at how well your model works, an impressive piece of work by you. Thanks for sharing it.
…Smaller producers are going out of business left and right. As a result, we are going to have to dig into reserves to fill the gap. This will, in turn, boost prices… making it possible for Big Oil to finance new offshore projects.
It may be years before we see oil prices at their pre-recession levels. But even a slight boost will make a short-term production increase feasible.
That means Peak Oil 2.0 should still be a long way off.
Good investing,
Oh yeah, since Peak Oil is such a looooong way off! I’m rushing out to put all my remaining funds in fossil fuels!
Thanks for pointing that out Fred. Great sales pitch…
“We aren’t finding anymore oil, so you should invest in finding more oil”.
Peak Oil is a long way off….It is almost a year behind us!!!
Cue Jeffrey Brown for one of his pre-packaged comments on how conventional oil peaked in 2005.
Jeff? Jeff? crickets chirping?
I’d say that for the most part Jeff has it correct. As usual.
http://euanmearns.com/a-new-peak-in-conventional-crude-oil-production/
It appears that by tripling the rig count in OPEC Middle East and pumping for all they’re worth they have managed to get an extra million barrels a day out of the ground and the 2005 peak was surpassed. However, Euans analysis only subtracts NA LTO and Syncrude from world total to measure global conventional production. There is also the matter of unconventional from Venezuela and off shore that IMHO should also be subtracted from world total to get a more accurate measure of world conventional production.
I like this article also.
http://crudeoilpeak.info/world-outside-us-and-canada-doesnt-produce-more-crude-oil-than-in-2005
I agree. I think Jeff is on the money. I hope my post didn’t suggest otherwise.
I actually wish he would continue posting.
Saudi Prince – $100 – Never Again ??
The Number is $80 … or 2.x Yergans .. IHS says so
Everyone in the States have a fine Memorial Day weekend.
Of Interest will be Inventories levels forward.
Image – Hit or Miss ?
Recall the explorations budgets of the majors were cut Januaryish 2014, 6 mos before the price slide.
Venezuela news: yesterday, the National Assembly approved a resolution declaring all government contracts with foreign entities had to be reviewed by them (as per the Venezuelan constitution). They said they would inform all foreign embassies, and let them know that all contracts which failed to go through this step would be considered invalid.
The ones who seem to face the biggest risk are Rosneft’s purchase of 24 % of the shares in Petromonagas. But the ongoing negotiations with Halliburton and other service companies are also at risk.
Maduros Colombian nationality has resurfaced after the bogus a Supreme Court overrode a constitutional article, which says that dual nationality holders can’t be president. As far as I can tell Maduro simply lacked the nationality needed to meet constitutional requirements. This makes him illegitimate.
In other news, I’m getting information that Venezuelans are really going hungry, the amount of looting is increasing, and the electricity and water problems continue.
I am jonesin’ for some more gas already today. The tank gauge is moving down towards the E mark and if I don’t get some gas, I’ll be stranded somewhere along the way. It will not be good, then I’ll have barn fever after a couple of hours out there and want to go home. It will be tragic just sitting there in the vehicle and need some gas. I can go varoom, vroom, vroom, but it won’t do any good.
The work won’t get done, everything will be all wrong at that point.
I have to fill up the tank before anything happens. Today, right now, or it all goes to hell in a hurry.
The same thing happens every day, all over the world. Hundreds of millions of humans every single day expect to have some kind of refined product from crude oil stocks every doggone day of the week.
Always jonesin’ for some more and it doesn’t stop.
If that doesn’t happen, the news will be worse than bad.
Even on Fridays, the ineluctable conclusion, buy some gas so you don’t run out.
“Trump Vows To Undo Obama’s Climate Agenda In Appeal To Oil Sector”
“Until Thursday, Trump had been short on details of his energy policy. He has said he believes global warming is a hoax, that his administration would revive the U.S. coal industry, and that he supports hydraulic fracturing – an environmentally controversial drilling technique that has triggered a boom in U.S. production.”
http://www.huffingtonpost.com/entry/donald-trumps-energy-plan_us_574858c1e4b055bb1171e801
“Climate change is an urgent threat and a defining challenge of our time—and Hillary” “will set bold, national goals that will be achieved within ten years of her taking office”:
1. Generate enough renewable energy to power every home in America, with half a billion solar panels installed by the end of Hillary’s first term.
2. Cut energy waste in American homes, schools, hospitals and offices by a third and make American manufacturing the cleanest and most efficient in the world.
3. Reduce American oil consumption by a third through cleaner fuels and more efficient cars, boilers, ships and trucks.
https://www.hillaryclinton.com/issues/climate/
http://www.slate.com/articles/business/the_juice/2016/05/the_windpower_expo_demonstrated_that_wind_energy_is_finally_corporate_and.html
According to this link, the domestic wind industry expects to double it’s capacity by 2020. This might be a little optimistic, give them another year or two to be sure.
Wind is already providing about five percent of our domestic electricity. With double the capacity, that contribution will approach ten percent. With more interconnections, the contribution may exceed ten percent, because there will be less curtailment of temporary excess demand. With more long distance hvdc lines there will be more spots physically and politically suitable for pumped hydro.
Bad news for folks with gas to sell. Wind and solar power are probably not going to keep the price of gas from going up, but the price of gas will not go up AS MUCH.
Ditto for oil, once the electric car industry really gets rolling. It might not be big enough to keep the price of oil from going UP, but electric cars and ligh trucks will surely keep the price from going up AS MUCH AS FAST as depletion inevitably cuts into supply.
Battery tech might even get good enough that larger trucks that stick close to home base can be electrified economically. A lot of delivery trucks such as the ones used at big box stores in or near cities seldom go more than twenty to thirty miles from the home store, and they could be recharged while being reloaded, at least to some extent.
The problem isn’t the USA. The problem areas are such as Pakistan, India, and places like that. Or say poor Jamaica. They haven’t got that much money, nor do they have the space or conditions to use lots of renewables.
Money is obviously a problem in India and Pakistan, but otoh paying for imported fossil fuel is a problem too. I don’t see SPACE being a problem in either country. I have not checked on their wind resources, but they are big enough they ought to have at least some excellent wind sites. Ditto sun shine, it may be that monsoon rains are troublesome in large parts of India but otherwise……….
Jamaica doesn’t have a lot of good wind sites, but the sun surely does shine there, hot and bright, and reliably. I can’t see them failing to find space for solar farms. A few acres generates a hell of a lot of electricity, which is a damned sight more valuable than a few acres of fruit or vegetables.
They can import food cheaper than they can import fuel to burn to produce electricity over the long run in my estimation, but I have not been there and don’t know a lot about tropical agriculture. So I might be wrong about the economics of food versus energy there.
In any case there are plenty of roofs that can be used as production sites, and plenty of places that can be roofed over and used two ways such as solar production plus parking, or open market space, outside workshop space, recreational space, etc.
That is certainly true Fernando.
Some places are are in big trouble if imported energy gets tight/expensive.
The USA imports 14% of it total energy (as of 2013), whereas
Japan imported 94%, S. Korea 83%, Ireland 83%, Italy 76%, Turkey 72%, Germany 62% , for example.
http://data.worldbank.org/indicator/EG.IMP.CONS.ZS?order=wbapi_data_value_2013+wbapi_data_value&sort=desc
Some of these places have little prospect for the kind of big local deployment of wind and solar like the SW USA, and many don’t have big coal reserves they can fall back on. Or lots of money to pull it off.
Japan is the poster child for post industrial decline on so many fronts. I say this with a heavy heart as my wife is Japanese. I visit Japan once a year every year and have for the past 2 decades from my observations it has really started to snow ball in the last five years. The most noticable aspect is all the old people. But the basic infrastructure roads, bridges and all those tunnels are starting to show lack of maintainance.
Hi Hickory,
Most of the countries on your list (Turkey may be the exception), have plenty of money to develop wind and solar power. At this point coal fired power generation is not the most economical in many places, as coal output peaks (within 15 years) coal prices will rise while the price of solar and wind continues to fall.
Possibly in less developed nations they will go for coal, but it will be a mistake over the long term. Wind, Solar, hydro and geothermal will be cheaper.
“They haven’t got that much money, nor do they have the space or conditions to use lots of renewables.”
I’d be the first to admit that Jamaica hasn’t ” got that much money” but, on the space, I refer you to the satellite picture below. It shows a 2.34 square kilometer square in the center of the picture, superimposed on the capital city, Kingston. About 15 km directly east of the square is the old capital, Spanish Town and half way between Kingston and Spanish Town but slightly to the south is the dormitory community of Portmore. All three areas are heavily built up and I estimate at least 25% of the area that is not dedicated to roads and parking could be roof space.
The square in the picture represents the area that could generate 350 MW, a little more than the island’s peak power demand of about 600 MW. According to data at this web page, the island’s insolation (solar resource) varies from a low of 4.25 kWh/m²/day in December to a high of 6.68 kWh/m²/day in April. An official government web page, An Overview of Jamaica’s Electricity Sector, list some interesting data, including the fact that the island consumed 3,009,428 MWh in 2014. Using a figure of 2000 kWh/m2/year from this solar map of Jamaica would mean that Jamaica would need roughly 1,500 MW of installed PV capacity to generate all the electricity consumed. That is, an area roughly 4.3 times the 2.34 square km area shown (10 km2), could generate all the electricity consumed on the island.
So if one were offered 20 square kilometers of land suitable for growing sugar cane, can anybody here come up with a means of generating 3,009,428 MWh per year, using that land area apart from PV? I put it to you that a solar farm would probably generate more revenue than any legal crop you could grow on that land.
As a side note, according to this subheading at the Wikipedia page on Jamaica, ” Just 20% of imported fuels are used for road transportation, the rest being used by the bauxite industry, electricity generation, and aviation.” (bold mine). This is the reason I keep bringing up electricity generation on a Peak Oil blog. It is relevant to other island jurisdictions like Hawaii, Puerto Rico and the Dominican Republic as well.
99.9% of wind is Centralized Energy – Can not compete with PV Distributed Generation. Many factors will make “The Synchronous Grid” increasingly Brittle. Look @ what the Gov has done to everything else.
“Battery tech might even get good enough that larger trucks that stick close to home base can be electrified economically” – it’s good enough now – Battery @ $300 per kWh starts to shine with Fuel > $2.00 per Liter. It’s the cost of Go Juice as much as it is Battery Cost.
LT: EV’s are good at $7.50 per US gallon ($2 per liter)? Could take a while…
Said Shine. Bet consumers freq out at $5 USG and drivers try to flock to EV’s. But significant battery capacity does not yet exist. How many Giga Factories will be built? 1.21 Gigawatts worth? Lot’s of Action on the Battery front.. but hell.. may take more than a decade to build out capacity = of a single Giant Oil Field.
http://www.investors.com/news/technology/tesla-sets-opening-celebration-of-all-important-gigafactory/
OFM. I get you in if you can fly to the desert. I’d love if they schedule round Burning Man .. har..
Awesome, I would be there for sure, if I could get away.
But I am on a four hour leash- afraid to leave the house longer than four hours and even then checking in by phone due to ancient old Daddy.
No travel- but since this meant shutting down outside work, plenty of time to play on the net and work on my book.
Electric-car energy density to approach gasoline by 2045: report
http://www.greencarreports.com/news/1104121_electric-car-energy-density-to-approach-gasoline-by-2045-report
By 2045….Only 30 more years to go!!!
I sure hope oil doesn’t peak and start declining in the mean time….Ooops!!!!!!
Hi Satan’s best friend,
What will happen to oil prices when oil peaks and declines? Assume that demand for oil continues to grow at 1% per year if oil prices had remained at $70/b.
Let’s assume you guessed oil prices correctly (given the assumptions), what happens to demand for non ICEV personal transportation?
Under reasonable assumptions oil supply will decline by 1% to 2% from 2025 to 2045. One could imagine that oil prices will adjust to the correct level so that demand for oil will fall by exactly the amount that supply falls, in fact economic theory suggests this should be the case.
A combination of substitution and less use of personal transportation may allow the economy to continue to function, though it will be different.
One thing people seem to miss is that there is no such thing as business as usual (BAU). BAU is constantly changing, think about BAU in 1965, is BAU in 2016 the same? I would say no.
Does anybody expect that BAU in 2045 will be the same as 2016? I hope most readers here do not, I certainly don’t.
I find it interesting that some LTO producers indicated they would add rigs at $50 WTI, and the price is settling in at $49 WTI.
Mr. Sheffield, Mr. Hamm and Mr. Thomas: Please revise your statements to, “We will add rigs at $65 WTI and we will pull more rigs from the field at $55 WTI.” That should lock in a $55-$65 price band which will make us, and consumers happy. IMO it is not enough for you, but until you admit that, you will have to live with those prices. At least that band is better than a $49 ceiling.
I told you all that your “break even claims” would drive the price lower and lower, but you did not get the hint until WTI dropped below $30.
Mr. Thomas tried to come up with a story about doing business at $30 (competing with OPEC), until Rune, Mike and I looked at EOG’s statement of net future cash flows in the back of the EOG 2015 10K. When I plugged in $30 WTI, (and $1.75 natural gas) I came up with negative net future cash flows exceeding $2 billion dollars. Yes, no PV10. ZERO.
You CEO’s have a lot more power than you realize. This is unfortunate for the rest of us, who have had to put up with the worst oil and natural gas prices since 1998-99.
Yes, I understand that these three individuals do not have complete control over the oil markets, but they and some of their peers have a lot more than they realize.
I have been following oil prices daily for 19 years. Hype means a heck of a lot more than it should, unfortunately, and has been getting far worse as the years go by.
I know my comments may sound crazy to some, and I do not entirely believe them myself, but it would be interesting to see what would happen if these three all had a joint press conference and stated my suggestion. I doubt the oil price would drop.
Question: What is worse than going bankrupt during a downturn?
Answer: Going bankrupt twice during the same downturn.
http://oilpro.com/post/24720/hercules-offshore-files-bankruptcy-second-time-downturn?utm_source=DailyNewsletter&utm_medium=email&utm_campaign=newsletter&utm_term=2016-05-27&utm_content=Article_2_txt
Hercules Offshore Files For Bankruptcy For The Second Time This Downturn
Offshore services provider Hercules Offshore has filed for Chapter 11 bankruptcy protection for the second time during this downturn. Last August, the company filed for protection and emerged from bankruptcy in November.
The filing is part of the company’s restructuring support agreement with its lenders, also announced Friday, which seeks to “maximize value for the Company’s stakeholders and provide a smooth transition for employees, customers and suppliers through an orderly sale of the Company’s assets.”
Baker Hughes rig count is out.
Oil rigs: -2
Gas rigs: +2
Oil rigs:
Bakken, Eagle Ford, Cana Woodford : -1 each
Permian, Niobrara: unchanged
Eagle Ford now has 26 oil rigs; Bakken: 22
Surprising increase in Granite Wash oil rigs from 2 at the end of April to 6 now (+2 for the week)
So with $50 secured still nobody is pulling any rigs, yet. Hmmm. So all the talk about pulling the rigs from yard at $45 last year was just that – talk. Or maybe the reason was to “talk” the price little bit more down at that time. And that “talk” does not work this time around.
As Shallow Sand pointed out above, that “talk” still deters prices from crossing the $50 threshold.
Shale companies’ CEOs have convinced the market that after prices settle firmly above $50 there will be a massive return of drilling and completion of LTO wells.
Just a few quotes from Reuters:
“People are worried crude production will come roaring back at these prices,” said Phil Flynn, energy markets analyst at the Price Futures Group in Chicago.
“Dominick Chirichella, senior partner at New York’s Energy Management Institute, said U.S. crude output could rise by an estimated 300,000 to 400,000 barrels per day as shale producers put drilled but uncompleted wells, or DUCs, into production.
The slide in the U.S. oil rig count has virtually halted as well, with just 2 rigs idled this week, data from industry firm Baker Hughes showed on Friday. ”
http://www.reuters.com/article/us-global-oil-idUSKCN0YI01L
“With the price of oil finally touching $50 a barrel this week, producers and speculators have been loading up on options to protect themselves from a downside risk, signaling there are still some jitters surrounding the recent rally.”
http://www.reuters.com/article/us-usa-crude-options-idUSKCN0YI23R
“A climb above $50 per barrel could spur producers, particularly U.S. shale drillers, to revive scrapped operations, which could bloat supplies and trigger a new selloff, analysts said.”
http://www.reuters.com/article/us-global-oil-idUSKCN0YH01R
I have long ranted on the stupidity of building a business model based on borrowing money to drill marginally profitable shale oil wells with the belief that oil prices would stay high, and stable for the model to work. I still marvel at the fallacy of it, really.
It is the still the same knotheads running the same shale oil business and they clearly have not gotten any smarter. The more they boast about “ramping back up” at 50 dollars, the less likely it is that anyone is going to give them the money TO ramp back up, and drive oil prices back down again, the more certain it is that Russia and the KSA will keep oil prices below 50 dollars. The real number is over 85 dollars a barrel, but the US LTO industry is too dumb, and too desperate for more capital, to keep their mouths shut, as Shallow points out. Its actually kinda funny to watch; like a comedy of errors.
The US LTO industry’s porch lights are on but nobody is home.
Mike, at least they quit lying about being able to make money below $30 WTI.
Otherwise you and I would be joining them in BK, LOL.
I just wish they’d lie $10 higher.
Alex ” Shale companies’ CEOs have convinced the market that after prices settle firmly above $50 there will be a massive return of drilling and completion of LTO wells.”
If the US oil market is 50/50 (shale/nonshale) how come so called “market” always hears what Shale CEO has to say? I don’t buy this. Something bigger is going on.
“If the US oil market is 50/50 (shale/nonshale) how come so called “market” always hears what Shale CEO has to say?”
1) Investment cycle in shale oil and gas production is much shorter than in conventional O&G industry (4-5 months from well spud to first production vs. several years).
2) LTO sector is thought to be more price-sensitive because of its weak financials.
3) MSM likes to quote shale CEOs as they are generally less conservative and cautious, more aggressive and arrogant than management of “traditional” oil companies
“I don’t buy this. Something bigger is going on”
The market needs a pause after an oil price rally from mid-$20s in February to high $40s now. Historically, there was no cyclical rebound in oil prices without short-term downward price corrections.
$50 is symbolic, but convenient level at which a rising trend in oil prices can temporarily stall before resuming in the second half of the year.
Potential recovery in LTO output is just one justification for such a pause. Others include: return of the Canadian oil; end of excessive supply outages from Nigeria and elsewhere; price war between Iran and Saudi Arabia for market share; concerns about higher interest rate and potentially stronger US$; slowdown in China, etc.
Keep in mind my comments above are somewhat in jest.
I do think traders are looking to see if rigs are added at this level.
Further, just because rigs are added does not mean those rigs will drill profitable wells. It only means the companies drilling still have access to cash.
AlexS makes a good point, the majors CEOs do not make specific statements compared to the LTO independents.
In the end, the markets will trade on US inventories (which are given too much weight IMO) and on US production (also given too much weight and prone to error).
Alex, you gave me 3 reasons why ” so called “market” always hears what Shale CEO has to say?”
I will give you one that trumps all 3.
Since when Wall Street started to have a love affair with absolute and proven money losers that shale is? (and you can throw Tesla there for good measure) . Aren’t we daily conditioned in life to love only winners? 🙂
The reasons why losers are relentlessly cheered this time we can find in the fact that NA oil production of Gucci type of shale+oil sands reached 7mbd. That is unsustainable from the perspective of consumption level in NA. Our global economy as debt infested Enterprise Starship needs to have soft landing in the best case scenario. But any abrupt and hard landing will have only losers among elites: some will be small losers and some will be big losers. And you can clearly see this internal power struggle between potential small and big losers among elites in this political elections cycle. They are at each other’s throats.
BH and NDgov seem to be getting further away. 22 v 29. I know some will be MIRU, a couple of re-entries, but it is hard to justify a 7 rig difference. Next week, I feel we must get an increase in the BH count for the Bakken.
As Alex mentioned last week, we are certainly seeing a bottoming of the rig count, if nothing else.
Had Texas continued to produce 350 million barrels per year, the oil market maybe would have avoided the price drop and the resulting upheaval.
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/production-data/historical-production-data/crude-oil-production-and-well-counts-since-1935/
Just too much oil added to the stockpiles. 153,000 wells in 2007 to 193,000 in 2016 produced too much oil. Texas has been giving away good Texas crude, lower production would have been a better strategy.
It will remain a buyer’s market as long as too much oil is produced and temporarily has no place to go.
OK we have someone else who needs to be booted off the forum for gross incivility. There was so much excellent stuff posted during the last day and then … not good.
If we all remember to NEVER respond to a truly uncalled for NASTY comment, it makes it easy for Dennis to ban the person who made it. Something about the software makes it hard for him after a response is posted.
Hi Don Wharton,
If there is a comment you find offensive, you will need to let me know the author(as listed under name) and Date and time listed for the comment.
I don’t see the comment you are referring to.
Mine, I am sure. Most people that benefit directly from shale oil and natural gas, for instance royalty owners that receive income revenue from shale wells, free and clear of all costs, or people with vested interested in shale stocks, and most definitely people who are relying on the shale industry for employment do not want to hear about the abysmal lack of profitability or how dire the financial situation is for shale oil and gas companies. They cannot fully grasp that hydrocarbon extraction in America is a business and for oil and natural gas to be produced, the business must succeed.
Hi Mike,
I thought your comment was fine. You have strong opinions, that is good.
In my view you are plenty polite, I hope I come across that way as well.
I have learned a ton from you and always look forward to your comments.
Thank you, Dennis. You are indeed always polite.
Mike,
Let me assure you that you were not the person posting an offensive comment. The comment is question included sodomy without any lubrication in a way to cast aspersion on those who differed from him politically.
To Dennis, the comment in question was gone when I next refreshed the web page. Thanks to you or Ron for cleaning it up.
Thanks, Don. We’re good, sir.
Mike
Thanks should go to Ron.
Anyone can email me at dcoyne78 at gee male dot com, though I don’t always check my mail as often as I should, sometimes nasty comments will get through.
As old Farmer Mac said earlier, if nobody responds it is easier for me to delete them (without messing up the comment thread).
When comments are very nasty (like your description of the offensive comment) that person will be banned.
Unfortunately this is the curse of Ron creating such a wonderful space for discussion, it attracts all kinds.
“Energy Security Partners LLC confirmed this week that they’ve engaged in preliminary talks concerning what would be the nation’s first full-scale gas-to-liquids project but have not been able to reach an agreement concerning possible incentives from the state to help fund the $3.7 billion processing facility.”
“The project, considered by some to be the “holy grail” of the alternative energy sector, would turn cheap natural gas into premium quality petroleum products such as diesel, gasoline and jet fuel using a proprietary technology first developed by the Nazi war machine in World War II.”
http://talkbusiness.net/2016/03/aedc-energy-group-engaged-in-preliminary-talks-on-3-7-billion-pine-bluff-gtl-project-no-word-on-incentives/
US Again a Nat Gas importer for 2016? Anyone have Links tracking Production vs Consumption?
US natural gas production and consumption (bcf/d)
source: EIA Short-Term Natural Outlook, May 2016
Annual averages
From Art’s Presentation linked last Post. Included in Dry Gas?? So the Free Fallin Shale gas component is 4/6 … ~ 66% of the Total. ??
http://peakoilbarrel.com/eias-annual-energy-outlook-seneca-cliff/#comment-570973
U.S. dry shale gas and total dry gas producion (bcf/d)
According to the EIA statistics, U.S, dry shale has production peaked at 43,5 bcf/d in February 2016. In March, it was down 0.9% and in April, 1.9% m-o-m. The numbers are preliminary estimates and could be revised (upward, like LTO?).
In any case, I wouldn’t call that “free fall”.
Shale gas as % of total U.S. dry natural gas production
Thanks! So far appears conventional output has fallen % more than Tight Gas .. Possibly because Tight is young and where the action has been.. So Supply-Demand balance likely depends on how well tight wells mature and their replacement ratio.
US conventional dry gas production (bcf/d)
AlexS
I have depicted all natural gas cycles from 1999 to present in the below chart. All cycles show a characteristic pattern (in 2003, 2005, 2008 distorted by hurricanes):
– when the price (green line) falls, drilling (red line) follows down in line with production (blue line) at a certain time lag;
– lower production induces a higher price, which in turn increases drilling and production;
Natgas has a very stiff demand (nobody wants to freeze in the winter), yet also a stiff supply curve, which causes massive price spikes – up over 250% in 2000. The price spike in 2000 had serious consequences for monetary policy and the stock market in 2000. It has been the trigger for the burst of the tech bubble in 2000 and even Greenspan discussed the causes of the price spike.
However, the price spikes got lower over time, yet in 2013/14 it has been more ferocious than in previous cycles.
As the pressure for rising prices builds up in the current cycle due to the massive price and consequent drilling slump, production starts already to respond. In the right corner of below chart you can see the recent deep slump of natgas production (blue line), which is the deepest slump what I know (except from the influence of Hurricanes). The current production decline started in December 2014 – when production hit 11% year over year growth – at a monthly rate of 1%. However the decline rate in May 2016 jumped to 2.5%, which I would call certainly ‘freefall’.
As the FED production rates are delayed and only available until February 2016, I have used data from Bentekenergy, who reported the lowest year to date rate of just 70.1 bcf/d Monday last week.
Heinrich Leopold,
The EIA numbers are slightly different, but they also indicate a drastic change in dry gas production trend.
The recent monthly estimate for May 2016 from May STEO is 74.55 bcf/d, down from the recent peaks of 75.42 bcf/d in September 2015 and 75,28 bcf/d in February 2016.
However the most recent weekly number for May is 73.5 bcf/d.
I think we will know the exact number several months from now.
But it is already clear that low nat. gas prices take a toll on production volumes.
US dry natural gas production
source: EIA STEO May 2016
AlexS,
In all natgas production cycles (1997-1999, 2000- 2003, 2005-2007, 2008-2010, 2012-2014, ) production followed a drilling slump, the remaining question is how deep the decline will be.
This time the drilling slump is particularily steep and wide by over 60% year over year decline and this now for over half a year. So, the trend for natgas production decline can only accelerate over the next few months.
Should drilling resume by next week, it would take at least half a year until production can rise again.
There is another explanation for the deep slump in April/May: When oil fell to 26 USD/barrel in February, natural gas liquids fell to record lows and in some cases companies had to pay for their production of natural gas liquids.
Therefore companies produced more wet gas which contained more natural gas liquids, which contributed to the production rise in February. However, when oil prices went up in May, companies could sell again natural gas liquids and produced as a consequence much less natgas in May.
In the light of all the above data, it is wishful thinking by the EIA to predict a dry natgas production of over 76 bcf/d for next year.
I think the Nazi effort was due to desperation from lack of oil to run their war machine. Extreme circumstances. Hopefully the company has achieved better than the 50% efficiency of older conversion methods. Maybe they use this method. https://www.technologyreview.com/s/410611/natural-gas-to-gasoline/
If not, they are going to waste half the energy making the liquid fuel.
This might be a good test case for a future when oil is less abundant.
Here is a link to Ugo Bardi discussing the implications and facts of EROEI over at Resilience. He wrote it in response to Hall’s piece concerning the very low value EROEI Hall came up with.
http://www.resilience.org/stories/2016-05-24/but-what-s-the-real-energy-return-of-photovoltaic-energy
I posted a long comment about the day to day implications of this issue there under my own name, which I use in some forums. In others I use some other handles.
As a purely practical matter in the day to day world we live in TODAY, EREOI is simply NOT an issue. Nobody except academics and people s hanging out in energy related forums gives a hoot. If oil is expensive, and gas is cheap, and the spread is wide enough, gas to liquids will work and nobody will give a damn- again excepting a few people such as members of this forum.
We really do have energy to burn these days, and MONEY to burn, as is amply demonstrated by the sky being full of jets hauling people hither and yon mostly for the fun of it, and the parking lots full of six thousand pound trucks used to fetch beer and maybe a boxed piece of furniture once in a long while.
At some future point in time, circumstances will CHANGE, and gas will get to be FAR more valuable than it is today, in terms of dollars and cents. Electrified cars will dominate, and people who want gas to heat their homes and to manufacture nitrates will bid up the price of it to the point it is no longer profitable to manufacture synthetic liquid fuel from gas. THEN EREOI will actually matter in the real day to day world we live in.
If solar electricity gets to be cheap enough, EREOI simply won’t matter any more , because the feed stock energy is for all intents and purpose inexhaustible. The sun is going to outlast us naked apes, lol.
And while it seems very far fetched to say so, it is no longer out of the question to consider the possibility that the manufacture of such goods as solar cells can be almost entirely automated, with virtually all the materials going into them being recycled at some point.
If you can set a defacto perpetual motion machine running turning out copies of itself, well, pv panels might eventually get to be as plentiful as as crabgrass. LOL.
Resistance is futile. PV and wind will triumph.
EROEI matters as it starves the civilization. As more and more resources are used to obtain energy and the energy quality keeps falling, less and less energy is available to actually do real and valuable work as well as all the “unnecessary” things that make up civilization.
Unless of course, you believe in no limits to growth and fossil energy.
Resistance is futile. PV and wind will triumph.
Correction, not will triumph, but have already triumphed!
I also strongly disagree with OFM that EROEI doesn’t matter. Actually it very much matters because as EROEI for fossil fuels is in a continual decline EROEI for renewables is climbing. Investing in oil and gas is becoming less and less profitable and coal has no chance at all.
Solar and wind on the other hand are becoming better options.
I’m sure there are many who still disagree with me but in this case they are wrong. 🙂
Agreed, I think of solar, wind, efficiency gains and behavior modifications as the first step toward a more biologically sustainable system. The technology will give us time to convert to a long term condition of stability and sustainability. Biological control and integration is imperative, otherwise humans will just go back to being … the dumbest smart thing on the planet.
HI FRED,
No doubt I failed to make my point clear. I am NOT arguing that EREOI does not matter in any ultimate sense, or that we should ignore the implications of the concept, or any thing along that line.
I AM pointing out that in the day to day world we live in, the energy in coal is worth less than the energy in gas, which is worth less than the energy in oil. The energy in all these is worth less than an equivalent amount of electrical energy which can be used at least three or four times more efficiently to run a motor , compared to an infernal combustion engine- if the electric motor can be used for the job in mind.
Ordinarily you GET IT quickly, so I MUST be having a bad day .
😉
You go off jet setting around the world, perhaps for good reasons, perhaps not.I VERY seldom fly and have NEVER flown for pleasure.
I won’t argue about your consumption of jet fuel, or airport infrastructure, or wear and tear on jet liners. I know air travel is actually cheap, compared to the other options currently available to long distance travelers.
Besides which, I am to be perfectly honest, not very good at conserving gasoline. I could cut my trips to town down by half, but I LIKE going to town, and having a cup of coffee in the book store, and sitting around for a while at the tractor garage where there are other old farmers drinking cokes and eating peanuts, lol.
I must also admit I could get by with less air conditioning, and I could fix the leak in my solar domestic hot water system, and so conserve quite a bit of electricity. Hopefully I will get around to that chore sometime soon.
EREOI will not get any serious consideration by businessmen, politicians, economists, old farmers, or jet setters until energy gets to be in truly short supply.
When the day comes than the energy in gas has economic utility equal to the economic utility of the energy of oil, (which CAN BE ROUGHLY MEASURED BY PRICE) then at that time we will value the energy in gas as highly as we value the energy in oil.
I am perfectly willing to pay about five times to ten times as much for gasoline or diesel fuel, on a energy equivalent basis , as I will pay for gas.
WHY? Because gasoline and diesel fuel make my truck and tractor go. Gas WON’T.
I can easily substitute firewood for gas, because the only way I have any DIRECT use for gas would be as a heating fuel for my house, since I don’t need it to dry grain, etc.
(I do use very small amounts of propane, acetylene, etc in my shop.If I lived in a place where gas is readily available, I could run a converted tractor or stationary generator or feed mill or irrigation pump on gas. For THOSE uses, gas would be worth as much as oil on an energy equivalent basis to me. If I were still using oil heat, I could substitute gas if gas were cheaper on an energy equivalent basis. This would have the effect of forcing the price of gas up and the price of oil down, on the basis of EROEI!!!!!!!!!!!!!! EROEI would MATTER on a day to day practical basis. )
At some point, the GAP between the economic value of oil and gas as measured by energy content will begin to close, because we WILL gradually use more gas as a substitute for oil, thereby increasing the RELATIVE value of gas compared to oil.
In the LONG run I agree that whatever we may or may not accomplish in terms of industrial civilization will be LIMITED by EREOI.
BUT that day is a LONG way off, decades at least.
As Gandalf put it, we have to decide what we can and will do in the here and now.
Our grand children and great grandchildren will have to take EROEI seriously. They may literally have to decide whether a cubic meter of gas is worth more to them burnt to move a car down the road, or keeping warm, assuming they have cars that will run directly on gas and gas furnaces in houses at fifty years from now.
For NOW, it matters not a tinker’s damn if we invest the energy content of a billion barrels of oil into renewables that generate a piss poor EROEI.
( Note that I don’t agree that the EROEI of renewables is piss poor. I think it is actually fairly good to decent, and ADEQUATE to run a new paradigm next generation business as usual economy. It won’t be an energy intensive economy, of course. )
WHY? Because we are going to piss away the energy in that billion barrels of oil jetsetting, and fetching beer, and racing automobiles, and heating and cooling poorly insulated houses, and driving to the store for groceries twice a week instead of once a week, etc etc etc.
Halls inclusion of the lunch of coal miners into the EROEI figure he calculated may be accurate, but it is for now at least, IRRELEVANT. The coal miner would eat anyway, the coal would be mined anyway, and the energy in the coal mostly wasted ANYWAY.
Hopefully I have managed to get my point across this time.
Pricing is dependent upon the economics of extraction, refining, etc. and the biggest point of all, competition. When comparing pricing, oil has little competition in transport areas, and is therefor an isolated system. Basically, even if oil costs twice as much, with no competition the price will be paid. Civilization is being held hostage by oil and the ICE.
If other competitive liquids show up, oil will start to lose it’s stranglehold. As electric vehicles grow in numbers, oil will also have it’s grip loosened.
It just so happens we are at the inflection points for oil and other fossil fuels, so they will lose their usefulness to civilization as they become unavailable.
Everything possible will be done to transistion away from fossil fuels, over time. The process has started already, actually been in process for decades.
The shift in EROEI of fossil fuels is due to the depletion of fossil fuels, plain and simple. The shift away from fossil fuels will be due to a combination of depletion effects and climate effects.
Changing the climate is rolling the dice as far as species continuing, even us. But our collective alarm bells aren’t going off with that information, so we will have to use price and diminishing production as a substitute for the human cognitive inability to act upon a distributed danger.
Changing EROEI is important now. Due to civilization being hostage to fossil fuels, the diminishing EROEI is steadily starving civilization. But the effects are widely distributed and again we come up against most humans not being capable of reacting to distributed changes and dangers.
It’s amazing to me, since most people do not really like change and fight against it.
Ok, got it! 🙂
I just composed a LONG rant trying to explain my point . It disappeared into the ether. Don’t know why. I have made PRECISELY the same arguments Fred has just made , EXCEPT I pointed out that EROEI is not very important NOW. I totally agree that it will be very important, critically important, later, and I totally agree about the falling eroei of fossil fuels and the rising eroei of wind and solar power, etc.
Hi Gone fishing,
There are limits to growth and fossil fuels. These are not a problem as long as one believes that human population will peak and decline and that human desires are not unlimited. At some point in the future we will reach a steady state where human needs are fulfilled at some lower population level (maybe 500,000 million to 1 billion). This will be a sustainable society where 99% of human waste is recycled and very little mining of the earth’s resources will be needed.
Probably 500 years in the future, but something to work towards.
“These are not a problem as long as one believes that human population will peak and decline and that human desires are not unlimited. At some point in the future we will reach a steady state where human needs are fulfilled at some lower population level (maybe 500,000 million to 1 billion). ”
Going from 7 billion people to 1 billion people isn’t a problem?
I would hate to see what a problem is!
Perhaps a Zombie invasion.
thanks!
If World average total fertility ratios fall to 1.5 births per woman by 2150 population will fall to 1 billion by 2300.
Thanks for the data Dennis.
That chart doesn’t suggest it won’t be a problem though.
What is going to happen to the economy if 6 billion “gradually” disappear?
A lot less sales at McDonalds…That’s for sure!
Hi Satan’s Best Friend,
Of course there will be fewer McDonald’s.
I expect the World will be much different in 2300 than in 2016, just as 1732 was very different than today.
I agree that such a transition will be far from easy, but not impossible.
I have a new post on the Permian, here.
Thanks Enno,
Interesting how good the wells in Texas were in 2010, didn’t get back to that level until 2015.
Hi Enno,
What do you think accounts for the big difference between your Permian estimate and that of Drilling Info? Maybe the vertical wells in the Texas Permian?
Dennis,
For New Mexico the data is very clear, and I didn’t have to estimate / filter anything.
For Texas the situation is totally different; there is a lot of old & new production, and individual well production has to be estimated. My goal is to show the performance of horizontal wells in the major shale basins. For the Permian in Texas, my data covers about 80% of the horizontal wells now, and none of the (> 100.000) vertical wells. That explains why the total production I report is much lower than the EIA. As mentioned above, I don’t aim to cover all production.
Hi Enno,
Yes the EIA seems to consider LTO output as fracked wells in a tight oil play and does not distinguish between horizontal and vertical wells.
On the 20% of horizontal wells in the Texas Permian that you don’t cover, are these older wells, maybe before 2008?
More grief in the gas cloud.
http://trib.com/news/state-and-regional/ultra-petroleum-files-for-bankruptcy/article_4b7ef57c-e433-5e7b-a5a1-a4b05d3f46da.html
‘Ultra Petroleum, Wyoming’s largest natural gas company, filed for bankruptcy late Friday in the Southern District of Texas.’
The HY instruments have risen with oil’s price despite the reports of BK and default. All it takes is the last trade of the day being higher.
Energy returned on energy invested can be simplified. An acetylene torch packs a punch when you want to cut through inch and a quarter iron. The torch is going to heat and cut the steel in less than a minute, the amount of energy used to cut the steel is much less than the amount of somatic energy used to cut through a piece of iron that thick with a hack saw, the energy returned is an arm that is not hurting for six days and loss of sleep. All you needed was some oxygen, acetylene, a blow torch, let the magic happen, your problem is solved with some heat, not an arm that becomes worn out in no time and a few cuss words to boot. Might even inadvertently cut your finger with the hack saw too, you’ll have to stop and find a bandaid along with cleaning the cut finger wound.
Use a cutting torch, you’ll save a lot of energy (energy returned). Just expounding on how energy can be returned by not using somatic energy, use some ‘extrasomatic’ stuff, a resource and some brainpower will work wonders. Using your arm too much can cause a pain in the neck, you will wish you had used a cutting torch.
Call it energy saved on energy not invested, har.
Other than that, there can be one barrel of oil returned on two barrels used, invested, until it is all gone. You’re investing two barrels to return one barrel, so you will be falling behind at a rapid rate, but who cares? ?
Give us this day our daily oil.
Just expounding on how energy can be returned by not using somatic energy, use some ‘extrasomatic’ stuff, a resource and some brainpower will work wonders.
Sure you can also procure a recycled fresnel lenses from an old TV which someone will pay you to cart away and you can get some free 2 x 4s by dumpster diving at some neighbor’s house remodeling job and build yourself a contraption that on a nice sunny day will certainly melt steel.
Just be careful don’t set your neighbor’s house on fire 🙂
There are some people who regularly read this blog who are much more mathematically and statistically inclined than I. So, for those of you who are, maybe you could tell me what you think of the following thoughts.
I follow US conventional production. I have been surprised at the C + C declines seen in what I call the non LTO states. Those would be all but TX, NM, CO, ND, OH and PA.
I note that KS and OK have reportedly had significant LTO activity, but both have had declines similar to the non LTO states. The monthly EIA numbers seem to back up my view of OK and KS horizontal wells, which is that they do not produce significant amounts of oil. For example, CO seems to be holding up much better than OK, despite that CO horizontal wells do decline very steeply, per Enno’s data. If the STACK, SCOOP, Meremac, etc are such strong oil producers, why the large OK percentage decline?
Also, the DUC is limited to the LTO industry, as is borrowing money to drill unprofitable wells. There have been under 50 vertical land rigs running, per Baker Hughes, for some time. If LTO had reacted in the same way conventional did, immediately shutting down in early 2015, would US production now be looking to fall below 8 million? Therefore, given LTO seems to have finally put on the brakes after Q1, should we see similar, or even more pronounced declines in the LTO states in 2016?
Final thought. At some point, wont LTO be required to reduce debt principal? If Wall Street were to determine same necessary, couldn’t we easily see a couple million barrels per day of LTO drop in production, as almost all cash flow goes to principal reduction?
The companies have, per their own reports, years of locations left. However, it will take years to pay down debt principal, at least under the assumption of lower for longer prices.
shallow sand,
C+C production in Oklahoma (kb/d):
– virtually flat LTO output, despite all the talk about SCOOP, STACK, etc.;
– declining conventional production
I agree SS. I think the companies that survive will return to a more “traditional” oil and gas business model that rewards shareholders with dividends rather than growth. I think wall street and equity investors will demand it this time around. The view of some in the financial press that the “boom” will return with a given price is just not the experience I have seen after a bust this large. I think it has been pointed out here before and you would agree, the first thing a company will do as prices rise is begin to rework/re-complete existing wells fix any broken infrastructure that has been deferred, they will pay down debt, fix or strengthen their balances sheets and get more comfortable with production trends and price stability. There are a handful of US companies that have increased capex as Art Berman pointed out in a recent artical but industry wide capex is expected to be down 3 years in a row. I do not see a new “boom” any time soon, if ever again. I do forecast a return to normalcy as prices recover.
texas tea,
I think that, with significantly lower capex and very low production growth (vs. 2011-2014) shale companies will be able to spend within cash flows. And with higher oil prices they will be able to generate positive cash flows and gradually pay down debt.
However paying down all debt will take a lot of time.
A good example is CLR. Despite low oil prices and sharply reduced operating cash flow, the company was able to reduce cash burn to just $3 mn in 4Q15 and $80 mn in 1Q16 from the peak of $745 mn in 1Q15. If and when oil prices recover, CLR will likely be able to generate positive free cash flows, but only with very modest capex and volume growth.
The company’s net debt is now $7.2 bn and debt ratios look rather weak (as of 31st March 2016):
Net debt/equity: 161%
Net debt / annualized EBITDAX: 5.8x
Most of CLR’s debt has long maturities, and the company’s will likely be able to renegotiate part of its debt, if needed. Still, the accumulated debt burden will remain very high for a long period of time.
Continental Resources quarterly cash flow ($ million):
The problem is that drilling within their cash flows will not increase production enough to offset well declines to continue paying off the debt. These companies put reserve growth above all else. Including profitability.
The bottom line is these companies drilled a lot of wells that will never payout or that will just break even.
fellows, just quick note on Ok LTO. Scoop in terms of development is way behind the Eagle ford and Bakken. It was “discovered” much later and the oil leg of the Woodford has just not been developed yet. It is there and according to CLR single well break-even is in the mid forties. I do not know the areal extent relative to the other LTO plays. There is also a zone called the springer which is 90% oil, it too will be developed with higher prices. So I would say Oklahoma LTO production will increase in time as oil prices rise, I do not know how these two zone will compare with other LTO plays in terms of ultimate play wide reserves. Newfield also has a new Ok presentation out.
texas tea,
Just compare how rapidly 3 big shale plays, especially Eagle Ford, were increasing production at the early stage of development.
SCOOP, STACK and Springer can be good for individual companies, but they cannot be compared with the big ones in terms of overall LTO resource and production potential. They are in the class of Utica liquids.
BTW, 3-4 years ago there was a lot of talk about Utica oil window, but today Utica remains primarily a gassy play.
Similarly, despite some oil windows, Oklahoma shales, as a group, remain primarily a gassy play (see chart below; mcf/kboe ratio: 6:1):
AlexS, I do not disagree with your analysis. The high liguid Oklahoma Woodford shale gas will be has some of the better ROI’s of all shale plays and has been the focus of the biggest players including CLR and MRO during the 2 year price downturn. At this point in the development, there are only a handful, 7 I think, of fully developed units with 3 in the SCOOP high liquids portion of the Woodford, 2 in the oil portion of the Woodford and 2 in the Springer. Each of these units have been drilled with different well densities, lateral lengths, frac stages etc to attempt some form of optimization. To quote from the MRO presentation, they are beginning to “prepare for the development stage.” The oil window of the woodford is much more than just talk. I have drilled wells, I have RI and WI interest in wells, and MRO is currently drilling one and will skid the rig to another next month in the “oil leg”. So my point is charts do very will showing what the past has been, but be prepared to see a increase in LTO production in Okla along with natural gas liquids and rich high BTU gas as prices improve. The ratios exhibited in your charts may or may not change as that will be dependent on the price of each commodity over time.
texas tea,
CLR’s operations in OK are mostly focused on liquids. All of its rigs there are classified as oil rigs. Yet, more than 2/3 of its production is natural gas
Continental Resources Oil and gas production in the SCOOP play
AlexS, I would not put to much emphasis of the classification/designation of a rig being a oil or gas rig. The issue here is granularity, I have more than your charts exhibit and while it is true CLR is focusing on liquids, as opposed to dry gas, there are portions of the Woodford reservoir that are 30% liquids, 50% liquids and 75% liquids. The area of the highest well density to date is in the 30% liquids (wet gas) because the higher expected BOE to be produced, not the 75% liquids where the expected BOE recovery will be comparatively less. This may be due to the over pressured nature of the reservoir (more recoverable cubic feet of gas per acre foot) relative to liquids or it may also be the relative viscosity’s of each or a combination of both factors. Even in the wet gas portion of the Woodford it has been my personal experience that the higher liquids production is in the 1st year or so of the well and tapers off rather quickly as a percentage of the total BOE being produced. That is a rather small sampling however.
I think those in this discussion are aware of this, but to clarify again my complaint.
OK horizontal plays may be economic. That is not my issue. My issue is that the companies are classifying them as producing primarily oil. Look at the name SCOOP. South Central Oklahoma OIL Province.
Some of the wells are prolific gas producers. I do not find many prolific oil producers, and a high percentage of the wells completely stop producing oil after 12-24 months.
AlexS. Thank you for the data!
I’ve been out of the Industry for decades and not sure of definitions. Staying away from Carbon Chemistry Is wet Gas = NGL’s which can be liquid at “room Temp” under pressure and Dry Gas = “Natural Gas” which are never liquid at “room Temp”?
Longtimber I am unaware of any official industry designation, but as it relates to SCOOP, wet gas is defined by a couple of operators as 1.35BTU gas. The wells drilled in the wet gas portion of the Woodford produce about 20-30% LTO, and operators such as MRO strip out the NGL which increases the total percentages of liquids produced. But it remains true as to both SS and AlexS point, natural gas will be a higher percentage of the total BOE produced in those areas. One other quick point as it relates to the charts provided by AlexS, the Cana Woodford as oppose to the SCOOP Woodfood has been a largely uneconomic dry gas play, but was “discovered” 3 or 4 years earlier. In testimony before the Oklahoma Corporation Commission (OCC) Marathon testified within the lower oil leg of the Scoop Woodford they anticipate to recover 4,273,000BO and 34BCG gas from a 1280acre unit for their permits for increased density wells. At the current well density in the area those reserves will be recovered from 6-8 multisection wells with laterals ranging from 7500′-10,000′. Time will tell if they are correct.
Thanks. Energy of dry gas only well flows is accurately measured with mass spec breakout & mass flow. Processing & Energy measurement of wet more involved. Simplest wet vs dry gas explanation I’ve found
http://www.glossary.oilfield.slb.com/Terms/d/dry_gas.aspx
Perhaps some logic as some might classify a “true” or “pure” “gas” well as only a dry gas well.
texas tea,
I found in Marathon’s recent presentation that their estimated 2P oil and gas resources in the SCOOP and STACK plays are 1,435 MBOE
copy:
In 1Q 2016 their production in Oklahoma resource plays averaged 27 net MBOED; 4% below 4Q 2015 and only slightly above early 2015 levels.
The share of crude and condensate in Marathon’s production in Oklahoma resource plays is only 19% vs. 83% in the Bakken and 60% in total MRO output in US resource plays.
19% of 27 MBOED is only 5,000 b/d
Marathon’s 2016 1Q production mix:
The STACK play may be better. Chesapeake recently sold their acreage position for over $10,000 per acre.
Including production. The “per net mineral acre” thing is a shale ploy that takes away from value placed on production and shifts it to hypothetical, over exaggerated PDNP/PUD value. It makes both buyer, and seller, feel better about themselves and makes it appear better to an unsuspecting public and the seller’s share holders wanting to know whatzzup with even more asset liquidation than they have already been forced to endure. This shale stuff is suppose to be a miracle, right? SCOOP and STACK or two gas plays that are over hyped on the basis of BOE conversions. If I am wrong, check the 6:1 BTU BS at the door, give us a PV10 number on the value of gas in that play and let us do the math ourselves. Shallow and Alex are not dumb, they’ll sort it out. CHK sold that stuff because it is junk.
“The fall in discovered volumes for conventional oil outside North America [to just 2.8 billion barrels, the lowest level since 1952] has been steady and dramatic during the last few years. We’ve seen four consecutive years of declining oil volumes, which has never happened before. The bottom has completely fallen out for conventional exploration, and the result portends a supply gap in the future that is going to be challenging to overcome. In the current cost-cutting environment, the outlook for 2016 discovery volumes is not likely to be better, either.”
Leta Smith, director, IHS Energy, upstream industry future service
http://www.ogj.com/articles/2016/05/ihs-conventional-discoveries-outside-n-america-drop-to-lowest-level-since-1952.html
At 80 M BPD consumption, that’s 35 days of oil.
hey wharf rat- not fade away?
Thanks for very intersting graph of oil wells profile, but I thought about what ammount of oil is being produced at each moment with some wells starting and some wells becoming to decline?
I illustrated it in an image below with step between each well starting 2 week . At moment when a first ( for instance new 2013 ) well finished its production new wells start at this time and if draw cross section line at this moment then some part of each consecutive profile gets under the cross section line but if sum up all these parts we’ll get whole well profile. The total ammount of oil produced at each moment is equal the area of one oil well profile multiplied by ammount of wells. So it’s looks like the overal ammount of oil is proportional to simply ammount of wells at each given moment of time if consider of course constant well profile.
Edit. Sorry for my crooky english . I aint native speaker.
The Texas Department of Transportation has assembled a task force to study the roads situation and look for funding options. By June, the task force plans to convene a meeting of local governments, law enforcement, oil and gas regulators and industry leaders to develop recommendations for state lawmakers. There is currently no state law to give counties the authority to mandate additional road repair fees on companies having drilling permits.