My guess is that much of KSA will look a lot like the shabby end of Yemen before too long. This will perhaps strand some assets. Once the House of Saud fragments further among competing clans/factions (Faisal, Sudairi, Abdullah, Bin Sultans) things will hasten. Collapse is preceded by intra-elite rivalry over a shrinking pie, so to speak.
Caspian Report has a nice set on KSA if you look for them. Here’s one- https://youtu.be/9tHwvZ9XDLU
And another- https://youtu.be/hh8isVX3H9w
Hightrekker once commented something quite apt, along the lines of~ ‘And all this is probably like the Austrians in 1913 arguing about who their next Habsburg Ruler is going to be’.
From what I understand there are 4000 Saudi princes (a suspiciously round number, so likely an approximate). It all should make for a very bloody affair. Hopefully Iran will do the right thing and kick ’em while they’re down.
The US crude production numbers are surprising the heck out of me.
Rystads projections out to 2025 are staggering-
“Rystad has been one of the more bullish voices in terms of U.S. production growth, and thus far it has been vindicated. Its own forecasts have output rising close to 18 million barrels a day by 2025, assuming $65 a barrel, or more than 20 million a day at $75.”
U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to EIA’s latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy’s estimated August production of 11.2 million b/d, making the United States the leading crude oil producer in the world.
Hickory,
At low oil prices ($80/b or less in 2017$ for Brent crude), US output might rise to 13.5 Mb/d at most, with a best estimate of about 1.4 Mb/d by 2021 (which would be the peak in a low price scenario).
Note that my “low price” is roughly the same as the Rystad “high price”. They seem to be buying the hype in investor presentations, even a “high TRR” scenario (probability 95% that output will be lower than that resource level even at high oil prices, $150/b or more in 2017$) would only bring US output to about 14 Mb/d, far short of the 20 Mb/d predicted by Rystad at $75/b.
In short, Rystad is too optimistic by far. Output may increase a bit through 2022 and perhaps even through 2025 at “high oil prices” of $130/b or more, after that output will fall regardless of price (I assume oil prices above $200/b in 2017$ are not feasible).
Hickory
Slide #9 from the recent Continental presentation accurately captures a big reason behind much of these increases.
In contrast to much concern regarding ‘sweet spot depletion’ a few years back, prodigious production has actually increased dramatically over an expanding area due to ever improving innovations.
(The recent 9,000 foot lateral drilling in under 24 hours in the Marcellus – 100% in target zone – is but one example).
The implications of that slide #9 extend far beyond the Bakken as regions such as the Powder River, Tuscaloosa Marine, Uinta and others are increasingly viable for this high efficiency development.
Good point Coffee, there are certainly more big wells in the Bakken (and elsewhere) than a few years ago. Improving science and technology versus declining resources. Its hard to say what happens in the immediate future.
dclonghorn,
If we consider average well productivity for the Bakken, we have (from link below, click on well quality tab) the chart below, there has been a small increase in average EUR, this will end at some point.
From 2013 to 2017 the average well EUR increase from 300 kb to about 380 kb, from 2008 to 2013 there was little change in new well EUR. The increase is mostly due to high grading where only the most productive areas are seeing any well completion, eventually these areas will become saturated with new wells where any closer spacing is not profitable (lower EUR per well will simply result due to well interference). At that point average new well EUR will decrease in the play, you are no doubt aware that this is always the case for any oil field, but it is difficult in unconventional oil plays to predict with precision when this will occur.
Dennis, Coffee’s comment did not turn me into a shale cheerleader. I suppose I am more in the shale sceptic camp for the reasons you mention and others.
Nevertheless, I think Coffee’s comment was correct, it does appear that shale producers in the Bakken have expanded the area that produces exceptional wells. As one who underestimated shale’s viability before, I don’t want to repeat the same mistake.
As you note, it is difficult to predict when average well productivity in the Bakken (or anywhere) will occur. I had thought that current drilling levels would be inadequate to sustain 1.15 million bpd production levels, but somehow they are increasing production there. It does appear that for now, the shale operators are having some success.
How long that success will last depends not only on the operational decisions made, but macro factors such as debt, interest rates, and the economy will play out, and eventually Bakken production will decline. But for now…
And in a brief follow up …
I have not read Continental’s conference call transcript yet (Seeking Alpha provides them), but it seems the suit from Continental now feels they will recover – from present completions – 15 to 20 per cent of the OOIP.
That is huge as the norm was 3 to 5 per cent a few years back.
… and tentative plans are brewing to be be able to move 1.7 MMbopd out of the Bakken in future months via CBR, expanded pipeline flow, new builds, or some combination.
There was also concern about rig cannibalization and the permanent departure of workers. Guess not.
If we look at CLR’s Bakken wells in 2012 to 2014 and the 40 month cumulative it is about 154 kb. For all companies in the Bakken for the same 2012 to 2014 wells the average cumulative output is 165 kb with a likely EUR of about 300 kb over the life of the well.
The continental type curve is a joke, if we assume 70% of the boe is oil for the 1200 kboe type curve, that would be 840 kbo, almost 3 times the average EUR of the average 2012 to 2014 well. Lately the EUR of the average Bakken well may have increased a bit to perhaps 380 kb (most of this increase is over the first 20 months after that the wells have declined to the rate of the older wells).
The investor presentations are very selective about choosing the best wells to present, the reality is there are some really poor performers that still cost 8.5 million to complete, that is the reason CLR has about $6 billion in debt at the end of 3Q2018, at year end 2015 debt was about $7 billion, so at least they are slowly moving in the right direction, but at the rate they have paid off debt in the past 2.75 years, it will take another 14+ years to become debt free.
Problem is that tight oil is likely to peak well before 14 years, but rising oil prices might allow debt to be paid down more quickly. For the past 9 months net income was 0.79 billion, if all of this net income were used to reduce debt (assuming this level of net income continues) the debt could be paid off in 6 years, higher oil prices might allow a quicker pay down of debt.
Up until the 2013/2014 timeframe, Continental was largely engaged in the Land Grab phase of their planning wherein the 800,000 leased acres needed producing wells to maintain the leases (3 year expirations).
One part of this company’s plan was to ‘cookie cutter’ their completion process using 30 stage sliding sleeve design.This continued despite the general shift back towards plug and perf as Hamm felt the overall benefits obtained from the speed garnered with the familiarity would offset reduced production.
In addition, Hamm wanted a uniform metric with which to compare different well performances throughout their vast holdings to better evaluate the geology.
It has only been the past 2 years or so that they have been implementing 60 stage, high cluster, high proppant use alongside very restrictive flowback procedures.
These techniques, along with many others, are why newer wells are performing so much better than earlier ones.
BTW, if you follow Bruce Oksol’s site, you will see how the Three Forks is starting to shine with the possibility of eventually out producing the Bakken.
All of this bullshit is straight, I mean straight off Continental’s self servicing investor presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some common sense and think for yourself. As opposed to letting someone else do your thinking for you.
Watcher is correct, CLR’s credit rating, its credit score, so to speak, is so bad it could not in the real world buy a pickup truck without its mama co-signing the note. If its wells are sooooooo much better, why don’t they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year…in interest on long term debt if it didn’t have to? Never mind, you can’t answer that.
If you are not in the oil business and have never balanced an oil well’s checkbook in your life, which Coffee hasn’t, then you don’t know that higher productivity comes with a higher cost in the shale biz. The bottom line then is that the bottom line does not change…if it did the shale oil industry would be paying down some debt, right? Its not. Private debt is skyrocketing.
Are things getting better for the shale biz? Right. Case in point, the largest pure Permian Basin oil and associated gas producer, Concho, the genius behind a recent $8 billion dollar acquisition from RSP, LOST $199MM 3Q2018. Inventories are going back up, prices are down 18% the past month and what does the shale oil industry do?
It adds more rigs.
Productivity is not the same as profitability. In the real oil biz you learn that on about day six.
“If its wells are sooooooo much better, why don’t they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year…in interest on long term debt if it didn’t have to?”
I wonder about debt service, too.
When Dennis runs his scenarios he says that at a certain oil price, these companies will be quite able to pay down debt.
But will they? Or will they just pay themselves as much as they can as long as they can get away with it, and then declare bankruptcy and walk away.
I’ll take door two.
We had 5-6 years of the highest, sustained oil prices in history and the shale oil industry could NOT make a profit. People seem to think now things have changed for some reason, that the shale oil industry has now become more ethical, and temporarily higher productivity of wells, and some imaginary oil price off in the future (for most shale guys its now down in the mid to low $50’s) will allow them to pay down debt. Its absurd logic, but keeps people occupied, I guess, speculating about it.
I urge folks to ignore the guessing, and the lying, (Hamm’s 20% of OOIP in the Bakken is a big ‘ol whopper) and look at the shale industry’s financial performance over the past 10 years and decide for yourselves if it is sustainable or not.
One thing to add. The shale companies did all this in the lowest interest rate environment we have had in a long time. They could not pay off their debt or even put a dent in it. What is going to happen when their interest costs increase 30-50% over the next 2-3 years?
Reno,
If oil prices are low, there will be problems for those companies with higher debt levels. If oil prices increase to Brent at $80 to $90/b many of these companies will be ok, in my opinion.
Boomer,
There is a lot of money to be made in the Permian after 2025, about 200 billion in cumulative net revenue from 2025 (when all debt is paid to zero) and 2035 when cumulative net revenue is 200 billion. Those companies that are bankrupt lose out on this pay day. There is an incentive to remain in business, this is why many companies pay their executives with stock options, it aligns the incentives of shareholders and CEOs.
I really can’t see that all LTO debt will be paid to zero by 2025.
As far as I can tell, you might be the only person who believes that.
We’ve got some who think that debt will crash the industry, others who think terms will be renegotiated to keep the machine going as long as possible, others who think companies will focus on dividends rather than expanding operations (and perhaps only pay down the minimum debt they can get away with), and at least one (Watcher) who thinks governments will go to war or print money or something else to keep the oil flowing.
Boomer,
I was surprised as well. You may be correct that the debt will not be paid, but in a reasonable economic scenario.
Average well cost=9.5 million in 2017$
Oil Price (Brent) rises to $110/b by Feb 2027 and remains at about that level until 2040
Nominal annual discount rate 9.5%
Royalties and Taxes=32% (corporate taxes not included
Nominal annual interest rate 7.4%
Transport cost $4/b
Monthly OPEX (including G&A) is $2.3 times the monthly barrels produced plus $15,000 per well for downhole maintenance (monthly average),this is the fixed plus variable cost model suggested by Fernando and matched to Rune Likvern’s work on the Bakken for business costs.
Businesses can choose not to pay debt and go bankrupt, but they miss their share of 500 billion in potential cumulative net revenue after the debt is paid off. Other better oil companies will pick up assets on the cheap from businesses that choose the bankruptcy route and make a killing. The big boys (Exxon, Statoil, BP, Chevron) would have plenty of capital to make this happen should the opportunity arise.
I get that the numbers show the debt COULD be paid off.
But I see business and political decisions being made that don’t seem to be good decisions to me.
So I am not confident that the fossil fuel business will necessarily be conducted rationally.
And I have seen enough stock market and investment scams over the last 50 years to be inherently skeptical of them.
I was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in 2007 and gas prices were the highest they had ever been, it was not cash flow positive. It actually ate all the revenue from the rest of the company. Getting to be in the black for the play was always a year off. a decade later it never got there, they just got more and more debt sold more producing assets to pay for it to keep the shell game going and just got bought by Encanna. I have seen the same at every public company I have worked for, many of them survived the downturn only because costs dropped and so did the cost of debt. Now with increasing costs and cost of debt there will likely be many bankruptcies.
Coffeeguyzz,
The output of the wells from the past few years is a bit higher, but after 20 months the output of these newer wells is similar to that of the average 2012 to 2014 well after 20 months. What we have is very expensive wells (those extra 30 frack stages are not free) that produce maybe 20% more oil over their lives.
The Average EUR has increased from about 350 kb to 420 kb, in part from focusing on the sweet spots because of low prices and in part due to increased well cost associated with more frack stages and higher proppant levels.
I’ve said it before and will repeat, don’t believe the hype in investor presentations and ignore “boe” EUR estimates where the natural gas contributes very little to the bottom line, that is why most producers would rather flare the gas as it is more expensive to gather and transport than the revenue gained by doing so (in most of the ND Bakken/Three Forks).
Coffeeguyzz,
If we consider 2017-2018 Bakken and Three Forks wells.
The average 12 month cumulative for Three Forks wells was 151 kb, and for Middle Bakken wells it was 171 kb cumulative barrels produces at 12 months. Eventually Middle Bakken new well EUR will decrease and perhaps the Three Forks wells will outperform Middle Bakken wells at that point, for now based on average well data, Middle Bakken wells remain more productive on average compared to Three Forks average wells.
This is based on data gathered from Enno Peter’s shaleprofile.com
Yeah, I agree with Mike, Rystads announcements are mainly just self serving hogwash. Yes, oil production in the US looks to be close to 11.3 million for August. EIA’s reported production for Texas is only about 50k over my high estimate, so I see nothing to argue about. GOM is the main surprise, and George and others are better suited to comment on that. The understanding I had was that it was temporary. As far as Texas goes, I’m pretty sure it is the high, for awhile. Completions dictate how much oil comes out of the ground, not drilling rigs. That is for unconventional wells, not conventional. That is why I think the EIA’s DPR is a ridiculous measurement assessment. Apples and oranges. Articles that I have read indicate a significant decrease in completions in the Permian by the end of August. Texas production is not all about the Permian. A significant amount was contributed by the Eagle Ford and other areas. All completions have slowed to the point that by the end of September, they were at slightly over 60% of June’s completion numbers according to RRC statistics. Significant drop, and it will show up in following months. First years decline rates will assure that it will drop slightly from this point. $64 WTI won’t motivate it to expand to any extent. The next year will see US wavering along the 11.1 million barrel level, I still think. Unless, George thinks the GOM increase is somewhat permanent, which I doubt.
And try to locate a time in history when production is trending up, while completions are trending down. There is usually a several month lag by the time production slows. Takes a while to get out of the ground if they are completed towards the end of the month.
Don’t you just love simple logic? Like: fire burns, water is wet, stuff like that?
How do these projections (hogwash) help Rystad? By preaching the ‘good’ word to their paying audience? I don’t know their business.
They are a consulting business. How much business will they generate if they tell negative stuff?
I second that. Being from Norway myself, and having actually been working in consulting some years ago. It looks nice on paper, but the world is changing and it is wise to look out for deception and that is often the case in consulting (customer/revenue first and reality second).
Yeh, but they don’t score a lot of points with customers by being far off the mark on projections.
Guym,
Depends on the productivity per well, if you focus on the oil completions in the Permian basin, you can find a period where completions were decreasing and output was increasing as prices fell in 2014 and 2015. The vertical completions fell, but those were low productivity wells compared to horizontal completions so even with the fall in the completion rate output continued to increase.
Guym,
As an example, I looked at RRC data from 2015 for Permian output and oil completions (Districts 7C, 8, and 8A), completions were decreasing at 2.4 fewer completions per day (linear trend over Jan to Dec 2015) while output was increasing by 376 b/d each day on average over that period. See chart below.
Currently we may be seeing fewer vertical completions as smaller producers may be having difficulty moving their oil due to lack of pipeline space, the larger oil producers (who are mostly completing horizontal wells with higher average productivity) may not have reduced their completion rate very much, so the decrease in completion rate may not result in a fall in output and might result in the counterintuitive slight increase in output.
I do agree that the rate of increase in Permian basin output is likely to decrease in the coming months, but I think their may continue to be a small increase at perhaps and annual rate of 500 kb/d until new pipeline capacity comes online in the fall of 2019.
If we consider Permian C+C output vs well completion rate from Jan 2015 to Oct 2017 we get the chart below. Notice the increase in output of 480 kb/d in the first 10 months of 2017, with little increase in the well completion rate, possibly better well productivity might explain that finding. The trend for the well completion rate is an increase of 0.6 wells/month each month over the first 10 months of 2017, so basically flat.
There haven’t been many verticals since 2015. Apples and oranges. Do you think well productivity has increased 40% in the past six months??? And, as I said, Permian is not the only output in Texas. Almost a 200 drop in completions from June to Sept. will take a toll on production. At least, on production increases.
Based on the shaleprofile data it looks as if well productivity increased alot in 2016 and 2017 due to longer laterals and increased proppant intensity. 2018 well productivity looks to be trending pretty close to 2017, so the productivity gains from longer lats and increased proppant might have been exhausted by now. Therefore, comparing 2018 well completion numbers to any pre 2017 completion numbers won’t tell you much, but a comparison of 2018 and 2017 numbers should. In the 4 months ending in September 2018 completions grew year over year by almost 70% from 2017, hence the large assumed increase in production in the last four months of 2018. What is interesting though is that it looks like the free lunch from increased lats and proppant looks to be almost over, and any future increases in production must be the result of an increase in completion activity, which should result in some inflation for the service providers going forward. And, according to Schlumberger, if you adjust for the longer lats and increased proppant it actually appears that productivity is starting to trend down (and the increased usage of poor quality in basin sand will likely contribute to this as well)
I think EIA is a little high on monthlies, but not enough to argue with, so let’s use theirs for a comparison. From January to July, Texas production increased approximately 450kbpd. Using RRC production by District, Distrct one through three represented about 120kbpd of that increase, or about 25%. From May to July, that picked up to over 36% of the increase from May to July. That was the biggest bump. Wells from these districts will decline faster than the Permian districts. You can’t rely mostly on Permian statistics. If they cut down statewide, then it will go sideways or down. Eagle Ford, or Austin Chalk wells will have a higher initial output and a higher decline rate than the Permian, in general. And with the threat of $55 to $60 oil, there won’t be much interest.
Most of the analysis that is done on unconventional oil uses data pulled and manipulated by drilling info. EIA and everyone else. It may all be good, but I have some cognitive dissonance with some of the conclusions when compared to RRC data, which is supposed to be the source data. It was bought out months ago from some outfit out of San Francisco. I feel safer with RRC data.
Guym,
You are right I should look at all of Texas. The Permian is interesting though, the vertical completions decreased by quite a bit in 2015, but output in the Permian basin continued to increase. A big fall in Eagle Ford output over that period as horizontal completion rate decreased was the main reason for the fall in overall Texas output in 2015. There has been a bit of increase in Eagle Ford output of late, but it is possible that the lower completion rate for Texas overall is due to Permian oil transportation constraints, if there were any vertical completions before the pipeline constraints became a problem, today there is likely to be fewer. I don’t have a breakdown of vertical vs horizontal completions in the Permian basin.
The TX Permian basin vertical oil rig count has averaged about 33 rigs since Jan 2017 with a range of 27 to 40 rigs.
I take your word for it. Thank you, BTW. You are the only one left on this site that has any common sense regarding shale oil economics and the burden all that massive, massive amount of debt has on running a business where your assets decline at the rate of 28-15% annually. Everybody else seems mesmerized by productivity.
Who are you talking to in the comment above? If you put their name at the start of the comment it would be clearer.
There is a difference between a mature company and a smaller company that is growing. The tight oil industry has grown from producing very little oil to producing 6 Mbo/d (or 2 billion barrels of oil per year) when production stops increasing (2022 to 2025), tight oil companies will be able to reduce debt to zero as fewer wells will be completed so capital spending will decrease.
Boomer suggests debt will not be paid and companies will become bankrupt, this may be correct for the less well run companies, but better companies such as EOG or oil majors will be able to scoop up assets that are desirable at cheap prices and the oil will still be produced. For those investors that chose poorly run companies and lose money, that is the way the investment game has always been played.
Dennis.
Paying the debt off will depend very much on future oil and natural gas prices.
Once growth slows the companies will be companies operating many low volume wells. Investors will want these companies to pay dividends because they will not be in a position to grow. The operating costs will be higher, even though CAPEX will drop.
You are very confident prices will be high in the future. I suspect they will be volatile in the future, as they have been for the past 20 years.
So, on a company by company basis, timing will be critical, IMO.
Shallow sand,
The prices can be thought of as 3 year average prices, yes there will be volatility, my “low price scenario” has Brent Oil Price in 2017 $ never rising above $80/b. I cannot hope to predict the exact oil price and of course oil prices will be volatile, but the average over time allows a pretty good estimate.
Also a company by company model is a little too much work. I just do the industry average, some companies will be better and some worse than average.
It certainly is the case that oil prices have been volatile and I agree this will continue, but the three year trend in prices (centered 3 year average) has been up $7/b for the past year, my expectation is that this trend will continue and the 3 year centered average price will reach $80/b (in 2017$) by 2021 or 2022. The trend of oil prices will be higher, if the peak arrives by 2025 as I expect prices (3 year centered average oil price in 2017$) are likely to reach $100/b by 2024 or 2025.
Dennis.
I think company by company because I have an investment in a private company. I know how important timing is in the upstream industry to individual companies.
Likewise, I understand you aren’t all that interested in individual companies. No problem there.
On the price, I understand why you use different scenarios. However, the average price over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14 and 2015–17.
I was recently in a major city and saw more Tesla’s than I ever had, including my first Model 3 sighting.
Our little area now has two Model S, with the early adopter trading his 2012 for a 2018.
Shallow sand,
Pretty doubtful it will be $50/b over the next three years, in my opinion. If you believe that you should find another business 🙂 More likely is a gradual increase in oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price (today’s future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61 (Dec 2026). By Contrast the EIA’s AEO 2018 reference oil price scenario for Brent crude has the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too low.)
As always clicking on the chart give a larger view.
Dennis.
The price could be $50 from 2019-2021, and then $125 from 2022-2025. (Averages, of course).
So in that scenario I’d feel pretty bad if I sold out in say 2020.
Your models are ok, I have no problem with you doing them. We try to make a budget for every year.
However, the price is far too volatile to model anything very far into the future, just like we cannot budget past one year, and usually have to make adjustments to that.
Our price has dropped over $10 in less than one month. That makes a huge difference, yet that level of volatility is common and has been for many years.
What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the market prices of 2011-14, we would be bankrupt, absent having hedged everything for four years, which is very difficult to do.
On a flowing barrel basis, I have seen leases sell as low as $2,000 per barrel and as high as $180,000 per barrel in our basin from 1997-2018. That is what an oil price range of $8-140 per barrel will do.
Few companies with zero debt ever go BK. We would with WTI at $30 for about three years. Is that likely? No, but oil did drop below that level in 2016.
Shallow Sand,
The volatility is a big problem, there is no doubt of that. When imagining the “big picture”. I use the estimates of the EIA’s AEO as a starting point then add my personal perspective (that at some point oil output will peak.) Below is a chart with my guess from Dec 2014 for future Brent oil prices in constant 2014$, nominal Brent spot price is give for comparison.
Clearly my guess was not very good, the EIA guess from the AEO 2015 was also not great, but better than my guess. Future guesses will be equally bad.
What was your forecast in Dec 2014 for WTI?
Dennis.
In 2013 we assumed prices in a range of $60-120 WTI moving forward.
In June of 2014 when oil spiked up and we received $99.25 in the field, we suspected oil would fall and it began to. We again continued to assume $60 WTI would be a low.
We were dead wrong, of course.
Oil dropped again today. We will get $67 in the field for October sales paid in November. However, our price today is down to $56.50. That is about a $60,000 per month revenue hit to a small company which employs 8 full time employees, one part time employee office manager and utilized numerous contractors (rigs, electricians, etc.).
Corn here is $3.51 per bushel today. Less than a month ago it was $2.96 per bushel.
Yes, yes, a hedging program would mitigate the price volatility.
Until you actually try to hedge with money at risk, don’t talk to me about that. It’s about as easy as trading stocks. It is also very expensive due to the volatility. Or, if you do SWAPS or Collars, you need to put up a lot of margin money.
Shallow sand,
Hedging seems a risky business, not sure I would come out ahead by hedging. You are in a tough business, the volatility sucks. The silver lining is that prices will be increasing.
Shallow Sand Wrote:
“Paying the debt off will depend very much on future oil and natural gas prices.”
I don’t think so. When energy prices rise, so do prices of everything else, included interest rates. The only way the shale drillers could play off there debt is if the left large number of completed wells untapped (ie leave it in the ground) while taking advantage of cheap debt & low labor\material costs. Then selling the oil when prices & costs have soared above investment costs.
The issue is that as soon as a well is completed, they start producing, at market prices. Thus when oil prices rise most of the oil is already produced & drilling new wells (using more debt) does not pay down the old debt.
Also consider the costs shale drillers will need for decommissioning older\depleted well. I believe the cleanup cost is between $50K & $100K per drill site. To date have any shale drillers spent money on clean up for depleted wells yet, or is it all deferred (ie never going to happen)?
FWIW: I don’t believe any of the shale companies are in game for the long term. They are simply a modern Ponzi scam, taking investor money & providing an illusion of profitabity by selling a product below cost. They will continue to play the game until investor capital dries up.
I suspect that most shale drillers will go bust in the next 5 years when the bulk of their bonds come due & they won’t have the ability to refinance it or pay it off. If I recall correctly Shale drillers will need to payoff or refinance about $270B in high-yield bonds between 2020 & 2022.
Tech guy,
The price of oil can rise faster than the rate of inflation. I do my models in constant dollars, your implicit assumption is that the price of oil in constant dollars remains constant, historically this is not the case.
I surely agree that nobody knows the future price of oil, but if the “real” oil price increases to $80/b or higher in constant 2017$, and “real” well costs remain constant, the debt in the Permian basin can be paid off by around 2025.
As oil peaks I expect the real price of oil will rise to much higher than $80/b in 2017 $, probably more like $120 to $150/b. I would say $120/b+/-20 in 2027 is a reasonable guess for Brent oil prices in 2017 $ (13 month centered average price in June 2027.)
Hi Dennis,
Costs will go up for the Shale Drillers since it takes a lot of fuel to set up a new well. Think of all the transportation costs: Hauling equipement, site, prep, water tankers, and hauling crude to a refiner.
Bottom line, Shale drillers never turned a profit no matter what the price of oil was, They never made a profit even when Oil was around $120 bbl.
“the debt in the Permian basin can be paid off by around 2025. ”
I doubt it. Most of its is “High-yield” debt and interest rates likely to continues until the next recession hits, But when the recession begins, Oil prices will tank again. Its a lose-lose situation no matter which way you look at it.
If oil prices go significantly higher, I assume many of the companies will issue more equity and use it to pay off the debt early, depending, of course, upon the terms of the debt. I assume most, if not all of it may be paid off early by paying a slight premium to the bondholders.
This will dilute the existing shareholders, but the equity should be trading very high if oil prices were to rebound into the $80s+ for a considerable period of time.
Shallow sands,
How much has your average OPEX increased from 1998 to 2018? Or for the last 10 years.
Tech guy,
I assume interest rates are 7.5%, which is probably pretty close to the industry average, if we also assume the EIA’s AEO 2018 Brent reference oil price scenario, a “medium TRR” scenario consistent with USGS estimates for the Permian basin and other reasonable economic assumptions and also assume that new well EUR starts to decrease in Jan 2023 as sweet spots get fully drilled up we get scenario below. Debt paid back in 2027 and cumulative net revenue goes to 150 billion in 2017$ by 2032. Click on chart for larger view.
Dennis, thank you for the lecture. The price of oil for all shale oil producers, save the biggest in the Eagle Ford getting paid on a WTI-LLS differential, is in the mid to low $50’s, a long way from your predictions of $80. Growth is nevertheless occurring for the same reason it always has…credit. I am sorry you don’t get that.
Major integrated oil companies will do not better in this shale shit then independents; in fact worse. They will not ‘scoop’ up 20 BOPD wells making 100 BWPD, declining 12% annually and headed for economic limits.
Some companies will survive, of course. This is not an investment sight, I thought, and we were discussing the health and well being of an entire sub-industry and its ability to meet its promises to the American people about our nations hydrocarbon future.
You have no clue whatsoever whether the US shale oil phenomena will be able to pay its debt down. You are guessing. And poorly, I might add.
The investment “game,” as you like to describe it, does not pertain to the shale phenomena. In that scheme, nobody has anything to lose, and everything to gain. Its all other people’s money and that fake “money” is taking away from our future, and our children’s future in the form of debt. Lenders are chasing yields, with government money; when nobody loses there is no “investment.” I am sorry you do not get that either.
Assuming hydrocarbon prices will rise based on high school level supply and demand theories, in the debt ridden, turbulent world we live in today, and fix all this mess is ridiculous.
Hi Mike,
Thanks for your lecture.
Supply and demand ultimately will determine prices, there can be short term fluctuations above and below the equilibrium price because stock levels can rise and fall, they cannot fall below the level needed to fill the pipelines though, that amount is essentially a zero level of stocks. I am using the Brent Oil price which is the de facto World Oil price (or it is what the EIA believes is the best choice). The spreads between Brent and he shale oil producers will fluctuate and will vary basin to basin, that is included in my model as transportation cost. The larger shale producers in the Permian basin will have pipeline space locked up to ship their oil at reasonable prices, only the small producers are getting hit with the low oil prices in the Permian.
In the long run the pipeline capacity will increase and the spreads will drop back to normal level in my opinion.
The publicly traded oil companies have stockholders that “invest” in those companies. The publicly traded investment firms and banks that buy the bonds and lend the money (for revolving credit lines and loans) to shale oil companies also have stock holders that invest in those companies. The companies that do a poor job of allocating capital will see the share price of their companies decrease as the poor allocation of capital becomes apparent. Either their behavior will change or the price of the stock will go to zero.
It is simply the way capitalism works.
As to the hydrocarbon future, my expectation is that oil output will peak and decline, I have been pretty consistent on that point.
An economic analysis with a very reasonable oil price scenario suggests the Permian basin oil companies as a group should be able to pay their debt. Low price scenario below has well head price at $73/b in 2017 $ in Jan 2020 with a maximum of $76/b in 2022 (price remains at that level until 2040. Well cost $9.5 million in 2017$, nominal discount rate of 9.5%. Nominal interest rate 7.5%.
Dennis, that is all just conjecture. Theory. In the safety of your own home, with nothing vested in this theory, it may make perfect sense to you. Out here, in the real world, its just wild ass, meaningless guesses. And confusing ones at that.
Learn which end of a work over rig to walk to, get a few blisters on your hands, lay awake hours every night worrying about making payroll, paying vendors, why one well is watering out so quickly and another is not pumping and what to do about it, what the price of oil actually IS and not what you think it will be in five years,…you’ll change your safe, cushy “theories” real fast. Some working interest in about a half dozen shale oil wells will change your entire outlook on life, promise you.
Mike,
Agreed, it is a simple model following the work of Rune Likvern, Paul Pukite, Enno Peters and others. For the Permian basin the economics can work, if my assumptions prove accurate. You are correct that I am guessing based on the estimates of the USGS, David Hughes, and the well economics that I have learned from you, Shallow Sand, and Fernando Leanme.
Current assumptions:
oil price in 2017 $ for Brent rises to $80/b by Feb 2027 and then remains at that level, transport cost $4/b, royalty and taxes 32%, nominal annual discount rate 9.5%, nominal annual interest rate 7.4% (for both the previous rates an annual inflation rate of 2.5% is assumed), OPEX (including G&A) is 2.3 times monthly barrels produced plus $15,000 per well each month (this last is based on Rune Likvern’s work on the Bakken, may not apply to Permian). A discounted cash flow in real (or constant) dollars for each well completed is done, Only wells with positive discounted net revenue over the life of the well are assumed to be completed based on assumed oil price scenario and fixed transport cost, well cost, royalties and taxes, interest rate, and discount rate ( all done in constant dollars). Well is shut in if net revenue is negative. OPEX for the average 2016 Permian well in 2017$/month/well in chart below. Wells get shut in at about 7 bo/d in this model, I also assume no revenue for natural gas as many producers are flaring all they are allowed so I assume associated natural gas revenue is marginal.
Click on chart for larger view.
Note that I agree with Mike that low oil prices “forever” will mean that the LTO industry will never be profitable. Neither Mike nor I know what future oil prices will be. The EIA’s low oil price scenario or even the average of the low and reference price scenarios from AEO 2018 would result in negative cumulative net revenue from now until 2080.
Mike thinks the low oil price scenario (or something less than the AEO reference oil price scenario) is the more likely case, I think peak oil in 2025 (or sooner) will lead to higher oil prices, close to the AEO reference case and perhaps higher.
>Supply and demand ultimately will determine prices
This is actually a doubtful claim — an empty platitude. “Ultimately” means in the long term, I guess, and as Keynes pointed out in the long term we will all be dead.
In the mean time oil is subject to wild swings in price that have little of nothing to do with the quantity available or the quantity required (or desired). For example prices skyrocketed in 2001-2003, although there was no significant change in the quantities involved.
Oil is subject to wild price swings because production costs are so much lower than the value to customers. For example, European markets chug along just fine paying $8 a gallon for gas, so “ultimately” $200 oil is probably no problem — the stuff is really useful to have around.
Needless to say, production costs are much lower. So what determines the price in the gap? Psychology. Panic about Republican war plans in the Mideast drove up prices in 2001. Financial panic drove them down in 2009. I suspect that numbness to political chaos in the Mideast ultimately brought the prices down to $30.
As long as there is so much “play” in the market, by which I mean difference between what consumers would pay in a pinch and what producers will accept in a pinch, it makes no sense to try to attribute price changes to quantities produced and consumed.
In a completely separate rant, I’d like to point out that you are confusing supply and demand with supply quantity and demand quantity. Demand is the amount of money consumers spend on a product, and it is significantly down since 2009.
The bottom line is that a lot less money is being spent on oil than was a few years ago. It’s the money, if anything, that determines the price, not the quantity. That’s just basic economics.
Supply and demand will probably determine prices, or at least average price over a long enough period, but prices don’t necessarily determine supply and demand given the long lead times for many projects and the inelastic response of a lot of oil use (and for LTO there appears to be a very tenuous connection at best).
George,
I agree in the short and medium term, but in the long term (more than 5 years), I think prices do influence both the amount of oil consumed and the amount of oil produced, there are very large lags in the system.
There is so much slack (waste) in the US, if the American consumer ever woke up to the unneeded extra costs put upon them they could crush the credit card, auto industry and the oil industry in short order. Demand here is propped up by extremely poor spending habits.
The real estate industry and home heating need a shakeup too.
The electric power industry is in for a rude awakening. They are already squirming.
Gone fishing,
I agree. This will become more apparent as fossil fuel prices rise and costs of alternatives continue to fall. The low fossil fuel prices in the US result in low incentives for people to make changes.
There is a ton of waste in the US energy system (and economic system).
Alimbiquated,
Correct I should use quantity of supply and quantity of demand. Often “supply” and “demand” are used as a shorthand. Quantity of supply equal to quantity of demand is a tautology, price will be determined by many factors including the expectations of market participants which depends upon psychology.
Consider the following thought experiment:
Let’s say actual quantities of C+C produced at $50/b for an average annual price is 30 Gb and let us also assume World stock levels are at “normal” levels and have been stable for the past 2 years. Over the next year the quantity of oil consumed increases to 31 Gb while production remains at 30 Gb (the extra consumption caused a stock decrease of 1 Gb over the course of the year).
Does the price of oil remain at $50/b (assume no new wars or recessions, start or end over the period under consideration)?
Dennis,
My claim is that the price would primarily depend on expectations of future supply and demand, which is obvious, I guess.
I read through your thought experiment, but I don’t see any indication of “play” in the market, which is what I am claiming exists. You postulate the oil price is $50/b, but what are production costs? $10/b? $100/b? This will obviously have some impact on prices.
And how much is the oil really worth to consumers? My claim was $200 in a low tax regime like currently in the US and China. I think that because cars and trucks are hugely useful, and because consumers in a high tax areas already pay the equivalent.
So I see no reason why prices should not get much higher than $50/b in your scenario. But I can imagine them falling as well. $30 oil didn’t stop companies from increasing production.
I think the American oil industry and the Republicans have been talking down the price of oil in recent years by bragging about “Saudi America” and the miracle of fracking.
The Republicans a deeply conflicted about what the price should be, sometimes blaming the Arabs for waging a price war to ruin the US industry, and sometimes bragging that America is the new OPEC. But the net effect of all the noise they have made has been to give people confidence that oil will be cheap for years to come. Wall Street seems convinced that there is a miracle happening anyway. Peak oil bashing is part of that.
That coupled with growing indifference to political crises in the Mideast following the Arab Spring are the biggest psychological factors currently. There are too many conflicts going on for non-experts to keep track of any more, and no clear good guys and bad guys for the media to hype.
I think something extraordinary would have to happen to get prices back near $100, like a huge war — maybe a Russian civil war, god forbid. I think it’s getting harder and harder for people to imagine an oil crisis. Hype about electric cars are a factor as well.
Alim- “And how much is the oil really worth to consumers? My claim was $200 in a low tax regime like currently in the US and China. I think that because cars and trucks are hugely useful”
I agree you on this, with one very big exception that is/will change the rules on this, and that being electric vehicles.
If oil is over $100 barrel for an extended time, the business and consumer push to electrify their transport needs will be strong and swift. The cost savings/mile will be very large. Each yr that goes by, the viability and options for EV’s grows, from bikes to trucks.
If you went to sleep for a decade, you would be shocked by the transition that has occurred, IMHO.
Its a matter of time(ing). If oil was over $100 for 5 yrs say, that is enough time for the economics to sink in and start to heavily influence to flow of money towards electrification.
Electrification is not all-or-none.
I have a plug-in hybrid van (made in USA and it is an excellent vehicle) for example. It goes about 30 miles on electricity, and can go another 360 on a full tank of gas. Since I’ve had it, just over 2/3rds of my miles driven have been electric (charged by solar on the roof), and 1/3rd gasoline. Future versions of this type of vehicle will likely have a bigger battery component that can go 60 miles on electricity. And perhaps someday, all electric. Most new vehicles in 5 yrs will be some degree of electric hybrid.
Of course there is play in the market, that is pretty obvious by looking at the historical price of oil (daily average spot price). Much of this movement is due to speculation by oil traders and their expectation of future oil prices. I think we agree on that point. The longer term oil price (say the 25 month centered moving average) will be determined more by economic fundamentals. If we assume in the short term (one to two years) production cost for the marginal (most expensive) barrel changes very little and that in my thought experiment the oil produced is equal to the oil consumed (because we have assumed stock levels are unchanged), then an increase in consumption to say 30.3 Gb (about a 1% increase which is the typical annual increase in C+C consumption lately) suggests oil price should increase since those 0.3 Gb of extra oil should be more expensive to produce and a rational oil company will not be willing to produce those barrels at a loss.
Running out of thread here, so I’ll try to kill two birds with one stone:
Dennis:
I think the only real difference between our positions is how much play we see in the market. But it’s anyone’s guess!
Hickory: I think you’re right that EVs will make oil seem expensive in a few years. It won’t really happen until battery supply starts catching up with demand, but then there will a a big bang (I boldly predict).
Both: EVs are reducing the play in the oil market.
So will 553 completions be enough to maintain production?
Lightsout,
It depends where the completions were and how productive those wells are, there are some completions that are vertical wells, not sure how many. Enno Peters has 295 horizontal oil wells completed in the Texas part of the Permian basin in April 2018, RRC has all Permian oil completions for TX Permian at 446 oil wells, which implies about 151 vertical oil wells were completed in April 2018. In June 2018 521 oil wells were completed in the Texas Permian basin, if we assume 150 of those wells were vertical wells, that would be 371 horizontal wells. In Sept lets guess only 50 vertical oil wells were completed, that implies about 309 horizontal wells were completed in Sept (62 fewer than June).
If I adjust my Permian model to reduce well completions by 60 from June to Sept and then assume the Sept rate continues until Dec 2018, Permian output continues to rise, but slowly (only increases by 55 kb/d from Sept 2018 to Dec 2018 or about 18 kb/d on average each month for the last 3 months of the year.)
Here in south Germany gas prices are now at 1.60€ / litre.
The water level in Rhein is still very low, so the tankers doesn’t come through. National reserve is tapped, and every truck that can transport gas does this around the clock.
EV drivers must be happy they bought an EV now!
Has this been a problem in the past?
Last summer similar dry was 2003 – and there the dry time was much shorter. I think it’s unique, at least you have to dig very deep in the past where oil consumption was on another level than now.
There was some rain last week, but not enough.
The next 2 weeks zero again according to the forecast. So the situation continues.
My cousin is on a boat ride up the romantic Rhine that she booked six months ago. It isn’t going well.
Global Vehicle miles traveled will grow by 60% in 2040
Since 2000 VMT has grown from 5 trillion miles to approximately 7 trillion miles. Since hybrid vehicles get all their power from diesel or petrol they will not reduce global oil demand because the increase in vehicle miles will overwhelm any efficiencies.
In US $ that is about 41 k, very nice, though I wonder about 300 miles of range at 64 kWhr. The US EPA range is 258 miles for the Kona, so that would be comparable to the 45k Tesla Model 3, though many prefer the SUV form factor over the sedan. Note that the Kona receives a government subsidy of about 4500 US$, if we assume the Tesla Model 3 is also eligible, the comparable price for the Model 3 “midrange” model is similar to the Kona at about 41.5k USD after incentives with similar range of 260 miles (EPA rating).
Also note that the Tesla range is quite conservative, at 10 C and slow speeds (80 km/hr) for the 310 mile range (EPA rating) Model 3 I get about 390 miles of range (dry roads).
The BBC analysed several electric car models for range, the Kona was closest to the advertised range. I think 270-280 miles.
You get 390 miles?
Hugo,
Only at slower speeds 60-80 km/hr, at motorway speeds more like 295 miles (or 472 km) at about 105 km/hr, faster speeds reduce range. Cold winter temps (-10 to 0 C) will likely reduce range, have only had the car a few weeks, I will update as I get more information. Over about 2700 km, I have averaged 241 Whr/mile or 150.6 Whr/km, the battery is 78 kWhr so about 324 miles (518 km) of range on a full charge, realistically one does not run it to zero, so probably 95% of this (308 miles or 492 km) would be the range.
Dennis
Keep us up to date. What State do you live in? Does it get that cold?
Tesla has pretty sophisticated battery management. When you plug in to charge the battery is gradually warmed to a safe temperature before charging begins. The car would probably not do well in Alaska or Northern Canada.
Hugo,
Yes. Average temperature in January is about -8 C (17 F).
Dennis
It will be interesting to see the range you get this winter.
I had not though of the wood stove trick 🙂
I was thinking of charging the battery just before leaving for work, so the battery is warm and heating the interior a bit while still plugged in, no plug at work so the efficiency on the ride home will not be good, but only 10 miles or so, so range won’t be an issue. For 10 months of the year this won’t be a problem, but Jan and Feb could be difficult, I will let you know.
Short motorway trip (210 km) at about -2C (28 F) resulted in about 15% higher energy consumption compared to an earlier trip at 13 C (55F). If the relationship is linear we may see a 30% hit at winter temps (-17 C) relative to 13 C (spring/autumn temperature where I live). I will let you know as I get more data, this last data point my wife was not warmly dressed, so more heat than perhaps necessary. In the winter we will dress warmly and only heat enough to keep winshield clear, if my partner allows.
While driving away from home you could preheat while the car is still at the tap – has it a timer heating you can program, perhaps even with the smartphone?
Only for driving back revolution in the car is programmed, then.
I remember – my first car was the VW Buss (the classic hippie van).
Driving in the winter with this mobile was special – the heating was going from the motor in the back all under the car to the front – and it liked to rust faster than your possiblity to buy and install spare parts.
So dime-sized holes in a frozen wind shield where the normal, gloves while driving have proved useful.
And it used gas like a modern pickup truck – in town 16-20 liter / 100 km.
Yes I preheated at home (to about 20 C), but at -2 C outside at night the car cools down pretty quickly so it helps a bit, but not as much as I had hoped over a 2 hour round trip, with a stop for dinner in between.
No timer for heating, only for charging, but there is a smartphone app that lets me turn on the heat before leaving without having to go out to do it, so yes heat it up while plugged in can help. We need to dress warmly, use seat heaters, mittens, hats, warm boots, etc. Blanket on lap would help because front of thighs gets cold.
It will be interesting to see how the Kona will stack up against the Bolt, in price and reviews.
They are extremely close in specs, and early reviews give them both very good marks.
The Kona is great. It takes at least 1.5 years to get in Norway subscribing to a waiting list. The battery capacity is just too good for middle of the range priced electric car. What is wrong with all the propoganda we are fed these days. I say, as I have done for some time, we are going to have a crisis long due, most likley autumn 2019 or into 2020. When is the question – well if the oil price is subdued the crisis is subduded (they way I think).
Am I the only one calling this bullshit? Exaggerated EIA data, with questionable production and import numbers. The US imports according to EIA are about 1 millon barrels/d lower than the data according to some of the tanker tracker numbers for a few weeks now. If OPEC (KSA) join forces with the US then this happens, and what next? I speak for deaf ears, so I better stop. But this low oil price environment is never going to last. Norway and Brazil production disappointment just maintenance and noice. Demand is going to go down, even if the price is low. The whole thing is just ridiculous, quote me on that when it all comes falling down.
I think it is really silly, nobody is interested. In a few months everybody is onboard. It is how psychology works, mass media and confirmation bias at bay. Pretty much defines the bottom of the oil price for now. No need to comment for some time.
EIA monthly output data is not bad. The stock numbers and such are not great and it is World stock levels that matter and the best data on that is from the IEA (still not very good). I agree oil prices will rise, hard to know when the market realizes that supplies are short, maybe in May or June 2019. OPEC and Russia seem to be producing full tilt, doubtful US output will increase enough to fill the gap.
I have a confidence problem when it comes to EIA if not the monthly output shows some weakness soon. The weekly figures are all over the place, and I don’t think they are very good. Still think the underreporting of imports and overreporting production from the weeklies are real and somewhat political; interesting to see if reporting change after midterm. I am just born sceptical and even more so when I learned that Trump likes to cheat during golf rounds (and I don’t even like to be cruel or tease anyone in any way).
Agree weekly data is not very accurate and much of the import and export data will be based on that. The monthly import export numbers are a little better for the EIA, but I focus on the output data, I figure the oil will move to where they can get the most money per barrel as it is all about profit.
K, I am not sure how all of this will unravel, or when. I tend to think, in time, it will be about mid year 2019, as Dennis says. EIA and IEA will rock along with the Permian song, until it is apparent, we are screwed. They have to, the alternative is panic, rising oil prices, damage to economies, etc. They can’t afford to be the one who says, “what clothes? The emperor is buck naked!”. I think the rationale for the “deception” is more fear than politics. What has me really curious, is what the “spin” is going to be when it does unravel. I tend to think it will just be more lyrics to the Permian song. Anything else, would be like absorbing the concept that the sun rises in the west.
Guym,
We are roughly on the same page as far as the Permian, output may go up a little, especially when there is more pipeline capacity, but the increase will be much less than forecast by some. Note that the EIA’s AEO 2018 actually has lower output than my “medium TRR and medium oil price” Permian basin scenario. Their “reference scenario” has unrealistically low oil prices which might be part of the reason, also it was written about a year ago, where I constantly update my scenarios as I get new information on output, well profiles, etc.
I would think that with a threat of less than $60 oil, it would go slightly down first, before climbing back up to what it is now. But, that’s just me. I’m not running these idiotic operations. If they overproduce at $60 oil, those Permian producers may getting a little over $40 a barrel with discounts. Or, shoot yourself in the foot with a shotgun. Discounts have dropped substantially since August, which is an indication production might be down, along with other RRC data. I’m guessing August is a high, and down somewhat from there.
“We lack resistance to the present.”
— Deleuze & Guattari
Guym,
If they are at capacity for pipeline and rail, then flat output would make sense, but sometimes these operations seem not to make sense. Maybe conventional output will decrease as much of this is from smaller producers who get lower prices for their oil.
Debt address.
Restrucure.
Equity conversion.
If you are a shale company and you owe money you cannot repay, you negotiate with the lender for better terms. It all comes down to the principal. Better terms might be covenant relaxation, change of payment schedule, or change of interest rate. All of those are pretty mild. A reduction in principal is hard to make happen, unless someone reimburses the lender in an obfuscated way, as obfuscated as possible.
If money had been borrowed from Exxon, the restructure might include an equity position in the shale company, though that requires Exxon to desire an equity position in a company that cannot pay its debts. That’s not impossible.
So once again, do not forget that if you have to have the oil, and you do have to have the oil, shale company indebtedness will not prevent that oil from flowing. Whatever must be done will be done.
But right now, how much of that LTO do we need? The faster we get it out, the lower the price of oil, and then the faster the depletion.
Facilitating more fracking with favorable terms makes no more sense to me than paying farmers to produce more food than is needed.
There is no money to be made from telling the truth in this instance.
In fact, for most of the interested parties, there is money to be made through lying, as Watcher implies.
Hence, no one tells the truth.
Since only a tiny percentage of us know that A) oil is finite and B) believe we are reaching an inflection point (and that tiny percentage includes, in my estimation, LTO drillers, who know and chose to lie), those selling LTO can lie with impunity. The concepts we bat around on this site- inelasticity of demand for oil, the differences in production costs for different types of oil, and the use of debt financing for LTO, to name what I think are the most important ones- are not mainstream at all.
To not facilitate more fracking would strand the LTO debt and let the cat out of the proverbial bag. The bankers and drillers will ride this one into the swamp, because one more year being paid $10 million bucks a year is one more year being paid $10 million bucks a year. (Maybe Mike has more accurate pay figures for LTO CEOs and Bankers. 🙂 )
To not facilitate more fracking would strand the LTO debt and let the cat out of the proverbial bag.
Bingo!
We have a winner—-
Some of you newer folks might not have been here too see it happen (assuming it really did happen) but there was a story, in ZH as I recall, that quoted the usual unnamed sources as having knowledge that the Dallas Fed had instructed local lenders to find ways to continue financing shale oil, despite the reality that the numbers could not support it. The price of oil at that time was about $40.
This was a pretty obscure subject, and not one that would typically achieve a worthiness of Zero Hedge. Now, the bar for ZH is not all that high, but at that time no one could see how those companies could remain solvent. The investing public had bigger fish to fry and largely didn’t care.
The point of this reminder is to note there is some precedent for finding ways to excuse all that debt.
It all boils down to this. What looks better a US economy carrying debt but producing 11mbopd or a US economy with less debt but producing 5 mbopd. Clearly the guys with their hands on the leavers of power have decided.
True, and we do make similar debt decisions throughout the economy. Superficially looks good, throw more wood on the fire so to speak. But the debt load is huge, as if you already cut down most of the forest (future growth and stability).
Those who are comfortable with highly leveraged fast growth, rather than slow, solid growth,
I ask you how you’ll feel about your asset pile when we go through massive dollar devaluation to ‘rationalize’ the debt? I’m pretty certain this will happen at a most inopportune time.
Hickory
I think we need to embrace the horror there will never again be slow solid growth.
I was being optimistic, for the fragile reader among us.
Lloyd, I agree with you, 5 X 5. Here is a good site to play with regarding salaries and compensations, https://www.salary.com/personal/executive-salaries/ Remember the shale industry is trying to clean up its “act” with regard to reserve base performance compensation packages for upper management, but that has only really happened in the past year or so. Previously, while debt was being kicked down the road, shareholders were losing their asses and EUR’s were (are) being grossly exaggerated, CEO’s were making a killing and are now home free now. Set for life. With nothing to lose if debt is not paid back. Bankers, I have no idea; there are brokerage houses that put lenders and borrowers together in CAPEX funding and M&A stuff that make enormous fees.
These sort of guys are sitting pretty, in the middle of a great distribution of wealth from the government (printed money creating more debt for our kids to cope with) to the shale industry to extract cheaper gasoline, jet fuel and fuel oil for the public. What a deal. What a big deal if all that debt just disappears, like Watcher thinks. That, I believe, would infuriate the American public, regardless of economic benefit.
Thanks, Mike! This is a cool toy. Now we type in Harold Hamm. We get a disambiguation page that makes us specify Harold G. Hamm, and then we get:
Harold G. Hamm
Executive Compensation
As Chairman of the Board and Chief Executive Officer at CONTINENTAL RESOURCES INC, Harold G. Hamm made $12,269,399 in total compensation. Of this total $1,210,589 was received as a salary, $3,404,829 was received as a bonus, $0 was received in stock options, $7,593,904 was awarded as stock and $60,077 came from other types of compensation. This information is according to proxy statements filed for the 2017 fiscal year. Bolding mine.
So I was in the right ball park.
Of course, $7.5 million of that is in junk stocks…nonetheless, $4.5 million a year is still well above food stamps.
A quick side question that came out of looking at Hamm’s compensation: he owns or controls 75% of Continental Resources stock.
Are most shale oil firms as narrowly held?
No. Very few are.
Hamm started out by driving a tank truck in the 1960s and grew his company from that.
It looks like another ultra deepwater project in the Gom is going to disappoint. Shell has taken $500+ million impairment on the Stones FPSO. It had a slow start-up and poor availability since, has so far not achieved it’s nameplate of 40 kpbd, and there are indications it may be declining with drilling operations now seeming to have stopped. It was originally a lease from SBM but Shell exercised an option to buy it, and then took it off station for three months. The issues look like a combination of reservoir performance and production system reliability.
1969 — High Seas: Hull of the ship Keo fails off the Massachusetts coast, spilling 8,820,000 gallons of oil in the Atlantic
They say fish oil is good for you.
Weekly inventories – it’s difficult to know what is happening without subscription data for floating stocks but someone somewhere usually mentions them…
Last week (Argus) – Oil product stocks held in independent storage within the Amsterdam-Rotterdam-Antwerp (ARA) trading hub fell by 2.6pc from a week earlier to a nine-week low of 5.3 millon tonnes, prompted by falling stocks of all recorded products.
Some Canadian heavy oil is being shut in due to low prices but the integrated companies don’t see those prices…
CALGARY HERALD Updated: November 1, 2018
On a conference call, Suncor CEO Steve Williams stressed his company has minimal exposure to widening differentials with ample processing capacity and pipeline access.
.
Canadian Natural Resources — led by chairman Murray Edwards — reduced its heavy oil drilling and expects to shut in between 45,000 and 55,000 barrels of oil per day in November and December. https://calgaryherald.com/business/energy/varcoe-big-deal-for-encana-canadas-biggest-producer-urges-province-to-regulate-oil-output
Thank you, I asked about this issue in a pervious thread and all who replied wrote that this would not happen. I still wonder if shutting in production will have any major affect on Canadian output (or growth in the next year). How much needs to get shut in to get the diff down to $20-25? I don´t expect it to get down to $15 or so before new pipelines comes online.
I don’t know enough to have an informed opinion, I’m only looking at what happened last time.
Yes it would be interesting to know how high production is above transport capacity. The EIA and Statistics Canada often give different numbers for rail transport so I gave up trying to work it out.
Inventory build in August 2018 m/m was +6.6 million barrels, or +214 kb/day
Average monthly build over the last 12 months, +44 kb/day https://pbs.twimg.com/media/DoQBp5eWsAAJD4K.jpg
(still waiting for AER September numbers)
2018-11-06 (EIA STEO) Even though total U.S. refinery utilization was about average for this time of year, it was particularly low in the Midwest, Petroleum Administration for Defense District (PADD) 2. Four-week average refinery utilization for the week ending October 26 was 73%, which, if confirmed in EIA’s monthly data, would be the lowest utilization rate in the region for any month in EIA data back to 1985. https://www.eia.gov/outlooks/steo/marketreview/crude.php
Oilprice.com is running an article devoted to peak oil demand. It claims that only the developing world is increasing oil consumption. There is all sorts of talk about alternative energy this and that, and quotes of reports and studies that seem to have been issued by organizations of significant partiality aka renewables wackos.
The US oil consumption has not yet returned to pre-crisis levels, but it’s almost there and probably will get there this year, according to the bible. I don’t know why this article appeared. It seems to be compilation of wishful thinking.
This delay in getting back to the 2007 level would seem much more clearly a consequence of pretended economic recovery derived from that instrument of capitalism purity known as QE, rather than substitution for oil, primarily as evidenced by what appears to be consumption reaching the 2007 level this year. If there were relentless decline, it would be relentless, yes?
“If there were relentless decline, it would be relentless, yes?”
Classic!
2007 will be a tough reach. 3ish% increase. The overall point is increases have been consistent the last 6 yrs. No idea why the article suggests the developed world isn’t increasing.
So, it appears group think is now running along the lines of Goldman’s latest brilliance. That is, production will be up next year due to US and OPEC increases. Which will pull prices down. I suppose you can make an argument of that based upon current numbers. Consequently, WTI is down to $62. Perfect storm developing.
It’s all ok.
Everybody reading financial newspapers knows LTO can be produced for 30$/barrel with positive earnings, and is an endless bonanza.
Let’s see how the tightening of the FED plays out. On the longer time, easy credit to drill dry holes or to buyback stocks (or do other useless things) will dry out gradually. After 10 years of easy money it could come like a dealer strike to drug addicted.
If they don’t change it soon, this will be the most important chart for the big business and LTO:
Not a great article. Smells like it has some politics in it.
QE stopped. That was monetary stimulus. The deficit is now growing. $1T this FY will equate to 4.8% of GDP. This is fiscal stimulus.
This ain’t capitalism. If you are injecting 4.8% of GDP into the economy from govt spending excess over revs — and can manage only 3% GDP growth with that extra money coming in (from non capitalism mechanism) — then what the hell is wrong?
What’s wrong is capitalism failed in 2008 and the Obama years . . . errr, Bernanke years . . . didn’t resurrect it.
So will LTO be denied credit by rising rates? No.
The Fed’s own dot chart says growth will slow next year (when did we EVER see the Fed project slowing growth in the future?). If growth slows, no real reason for rates to rise, though this can fuzz up via position on the yield curve.
The most important thing to know about this from LTO’s perspective is that the Fed itself HAS OVERTLY SAID that this is new territory. They have no idea how the system will behave from the QE injection over a decade and now thoughts of “normalizing”. Fed Governors have made speeches urging people to realize that this is guesswork. They don’t know how it will work out. They will just go on making policy as if it’s based in solid understanding, and it’s not.
(Oh, one more thing. The gasps of horror at the suggestion that govt might interfere with an independent central bank like the Fed — y’all do realize there is nothing in the US Constitution that says the Fed must operate independently? There is no law of the universe that says this must be so. There is only orchestrated outrage (globally, not just the US) when a govt asserts some control. One wonders who started the outrage.)
Guym,
Reading at Oil Price, they suggest a 400 kb/d increase in tight oil output in August, possibly based on the poorly done DPR, actual EIA estimate for August tight oil output increase is 86 kb/d and for the past 6 months the average monthly increase has been 82 kb/d, I agree with you that this rate will slow down in the months ahead due to lower prices and Permian pipeline woes, maybe something closer to the Sept increase of 46 kb/d (or perhaps less) until Sept 2019.
As you expect, the shale cheerleading may lead to disappointment, continued falls in Venezeulan and perhaps Canadian output and robust economic growth may lead to eventual short supply. We need increases of about 800 kb/d annually (based on 1982 to 2017 C+C output history), OPEC is at it’s max, so is Russia and many nations have declining output (Mexico, China, UK, Venezuela, to name a few), US LTO increase of perhaps 600 kb/d over the Sept 2018 to Aug 2019 time frame will not get the job done. The World may finally get the message by May or June 2019.
Yeah, it had a chance to increase based on other shales than the Permian. It’s budget time for all calendar year companies, now. No impetus for much of a 2019 increase based on $62 oil. If Permian players push it, the discount could give them $45 oil. I do not see an 800k increase until maybe later in the fourth quarter. But, really I expect little to no increase the first half, so 800k would be pushing it. OPEC is NOT interested in increasing production to lower prices. That’s an inane supposition. Yeah, June or July.
I keep forgetting about the one pipeline oil addition to Cushing. Started Nov 1. Supposed to be operating at 300k to 350k of its max of 500k. There is a discount to Cushing, and an additional discount to MEH at the Gulf, so not much better off as far as discounts to MEH, just an outlet for excess. I have no idea if this will motivate more production, but completions per the RRC are back up to around 900 for Oct. The part I don’t know, are how many of those “completions” are actually completions that report shut in production, or Ducs. I know there are a bunch of ducs in the Eagle Ford by Marathon and XTO.
Canada, Alberta AER, Total Crude Oil and Equivalent Production at 3,438 thousand barrels per day in September, down -292 kb/day month/month
Up +254 kb/day from the average during 2017 which was 3,184 kb/day
Chart: https://pbs.twimg.com/media/DrWh2IBXgAAn7su.jpg
2018-11-07 (Reuters) – Imperial Oil Ltd said on Tuesday that it would go ahead with the construction of its C$2.6 billion ($2 billion) Aspen project in northern Alberta, the first new oil sand development to be greenlighted since 2013.
The Calgary, Alberta-based company, which is majority owned by Exxon Mobil, said it would start construction on the 75,000-barrel-per-day project in the fourth quarter of 2018 with first output expected in 2022.
The Aspen project will use new recovery technology to lower emissions and water use and improve project economics, the company said. https://www.reuters.com/article/us-imperial-oil-aspen/imperial-oil-to-build-new-canada-oil-sand-project-idUSKCN1NC01O
Hey Dennis,
….long time – no word.
How’s that $85 oil working?
I feel bad for Shallow Sand and the guys who’s livelyhood is tied to oil $….
Whopefuly, you do not block me this time…
Be well,
Petro
P.S.: hi SS, Ron et al… hope everybody’s doing well.
Current thinking on future oil prices, somewhere between low and high scenarios is my opinion, the medium case is my best WAG. Monthly spot price for Brent in Sept 2017 was $81/b in 2017$ (using CPI for real price estimate).
Resolving the issue would allow Iraq to export an additional 200,000 b/d…
2018-11-07 (Argus Media) The US administration has also pushed to resolve the dispute over the fields in Kirkuk that the federal government retook from the Kurdish autonomy in October 2017. Crude from those fields has effectively been trapped since then.
“We are deeply involved in trying to find a solution on Kirkuk oil,” Peek said, with another round of talks scheduled in Iraq next week. Resolving the issue would allow Iraq to export an additional 200,000 b/d, State Department special envoy on Iran, Brian Hook, said. Washington also has urged Saudi Arabia and Kuwait to restart production in their shared Neutral Zone, which US officials say could add 250,000-300,000 b/d to global capacity. https://www.argusmedia.com/en/news/1787538-iraq-can-import-energy-from-iran-us-says
2018-11-05 (Bloomberg) — Iraq’s semi-autonomous Kurds upgraded their oil export pipeline to accommodate future production growth from their region as well as from the contested Kirkuk area controlled by the central government in Baghdad. The pipeline’s capacity increased to 1 million bpd from 700,000, it said.
The KRG currently exports more than 400,000 bopd https://www.worldoil.com/news/2018/11/5/iraqs-kurds-add-pipeline-capacity-to-export-kirkuk-oil
2018-11-07 (Bloomberg) Ministers from the group gathering in Abu Dhabi this weekend will discuss the possibility of cutting production again next year, according to delegates, a move that would mark an abrupt end to six months of supply increases.
The group is responding to a worrying prospect: Even though U.S. sanctions on Iran are removing significant amounts of crude from world markets, a fresh surge of American shale oil threatens to unleash a new surplus in 2019. Some members are concerned that inventories are rising, said the delegates, who asked not to be named as the discussions are private. https://www.bloomberg.com/news/articles/2018-11-07/opec-ministers-meet-as-oil-s-slump-spurs-talk-of-another-u-turn
Saudis are NOT interested in increasing production to lower prices. Elections are over and any promises they made are fulfilled. The SPR draw will go away. No one will get excited over an inventory draw in Dec., as that is common. But, Jan. through May are times for inventory build. Be pretty interesting the next six months.
What is more or less certain, is that OPEC+Russia is controlling the Brent oil price. The theory of them wanting to keep oil prices in a price band to ensure what they think are fair prices makes sense. What this price band is exactly, nobody knows. 75-85 dollars?, 80-90 dollars?, or 75-95 dollars? The main thing is that they want a good price for their main export commodity and at the same time not stall demand growth and spur another recession. So I guess they will try to increase exports again if it reaches 90 dollars sometime in the next 6 months. Not that I think they could control the price forever like this, but probably until autumn 2019 if they strain spare capacity and inventory. Most likely they deliberately colluded with the US administration to ensure oil prices hit a low point around mid term elections. I could see Russia and Saudi not wanting democrats winning the Senate and helping by increasing production/drawing from inventory in Oct. So, if I am a betting man (and I can be somtimes), I would now bet on reduced exports from OPEC and oil prices hitting the ceiling of their price band in a couple of months time. There are already early signs on reduced exports, but it takes some time for it to show up in import and inventory numbers.
“What is more or less certain, is that OPEC+Russia is controlling the Brent oil price. The theory of them wanting to keep oil prices in a price band to ensure what they think are fair prices makes sense. What this price band is exactly, nobody knows. 75-85 dollars?, 80-90 dollars?, or 75-95 dollars?”
FWIW: I think Russia is going to slowly remove itself from the EU energy market as it continues to focus on the Asian markets. Especially in light of the higher Asian prices for Oil & NatGas, and the Anti-Russian Euro agenda. Russia completed a new Oil Pipe line to China this year(Russia can now export up to 600Kbpd to China) and will complete its NatGas Pipeline to China in 2019. Russia is also in talks with India to supply Oil or NatGas.
Yes, that makes sense. In Russia they feel they are too economically dependent on Europe. And Europe stays with the historic alliance with the US..but the problem is the threats from the aggressive US administration (I believe Russia is especially afraid of economic sanctions). So to diversify makes them more independent and also ensure better prices for their oil and gas exports.
“Russia completed a new Oil Pipe line to China this year(Russia can now export up to 600Kbpd to China) and will complete its NatGas Pipeline to China in 2019. Russia is also in talks with India to supply Oil or NatGas.”
Correct. But you have to get the relevant numbers: The NG pipeline to China costs around 50 billion USD according to Russian press releases, NordStream 2 around 10 billion USD.
The latter operates with a 50% higher pressure than the former, i.e. it costs Russia 7 times as much to deliver NG to China. And it is a save bet that China pays a lower price for the NG than the EU.
How much does Russia have to spend on Defense to counter NATO? Why supply your adversary with abundant energy when you can cut supply and let them deal with an economic crisis (thus forcing them to cut their defense spending).
China pays a lower price for the NG than the EU.
Not sure about that. Generally cost for energy in Asia are higher than the EU (excluding EU energy taxes). I believe Asia imports a significant amount of Liquidfied NatGas which is I am pretty sure is more costly than piped NG.
FWIW: Generally most business don’t do business when customers that make their live a living hell. Personally, I’ve fired dozens of customers who were not worth the trouble. I would imagine this applies at the national level too.
US crude oil production re-benchmarked up +0.4 to 11.6 million b/d, which is the STEO number for November.
So pipeline constraints doesn’t brake US production by any tiny amount, but instead even accelerate it?
Uh, that’s the EIA. They live in their own world. Doubt production is anywhere near that. From the few years I’ve been watching it, they have only come within 200k barrels a couple of times,
Hey Guy,
Confusion arise from not understanding very simple things in life. For example “hope” . EIA, IAE or Bloomberg or oil “analyst” on internet, or tarot card readers, or Nostradamus, they all project certain price of oil in future.
So they are hoping that that would be the price in future. But what they don’t understand is that hope is false. All hopes are false. To hope simply means to postpone.
To hope means your present is ugly and you want to avoid it for some beautiful future. Price of oil is ugly in the present so someone makes a prediction, model, print in some financial paper and try to make at least future beautiful. To hope means you don’t want to see the present. That’s all to it.
I don’t know where this +400 kb/day production growth has come from? According to the EIA’s DPR they forecast that production growth in the Permian has leveled out at around +50 kb/day per month – due to pipeline constraints.
In the Petroleum Balance Sheet, the Line (13) Adjustment is still high at: +467 kb/day
Permian Sunrise Pipeline – as I understand it this is +150 kb/d higher than Plains said earlier due to NuStar Energy taking 150 off at Wichita Falls. Plains has the new 500 kb/d Sunrise capacity from Midland to Wichita but only 200 kb/d available from Wichita to Cushing…
2018-11-07 (Argus Media) Plains All American Pipeline said its Sunrise crude pipeline expansion is moving 300,000-350,000 b/d, adding takeaway capacity out of the Permian basin.
The expansion from Midland, Texas, to Cushing, Oklahoma, went into service earlier this month, ahead of schedule using temporary generators. https://www.argusmedia.com/en/news/1788452-plains-moving-up-to-350000-bd-on-sunrise
Yeah, but the probability that production increased that much in one month with current activity levels is not very high. It alleviated some of the problem, and provided an outlet for a glut from previous overproduction. Discounts reflect that, now. I imagine it will go up some starting November, but not 350k immediately. Again, the more it goes up by this point, the more of a danger it hits larger discounts. Which is interesting, because as the decreased the discount to Cushing by about $10, Cushing prices are down by about $10, so no benefit for the last quarter, so far.
The Wichita pipeline serves three refineries, but not sure of each one’s capacity. Recent Cushing builds may be caused by some of this new outlet.
The supposed 400 kb/d in Permian, was a mistake by the author (Nick Cunningham), it was about a 410 kb/d increase for all US C+C output in Aug 2018. Permian was only up by about 40 kb/d in August and an average increase of 66 kb/d each month for the first 8 months of 2018. All US LTO increased by 85 kb/d in August 2018.
Also Permian output has increased 44 kb/d for the past 6 months, the previous 6 months had average output increase by 96 kb/d each month, on a annual basis the comparison is a 528 kb/d annual rate of increase vs a 1152 kb/d annual rate of increase.
Or, we are down the rabbit hole, and it’s getting curiouser and curiouser.
Eventually US C+C output is likely to surpass 12 Mb/d. For the past 12 months US C+C output has followed a trend with an annual rate of increase of 1649 kb/d, even if the rate slows to half this annual rate of increase, US output would reach 12 Mb/d by Sept 2019.
If the rate of increase continues at the rate of the past 12 months, then we reach 12 Mb/d in the first quarter of 2019, the EIA, splits the difference between these two guesses, which seems pretty reasonable, I would guess 2nd or 3rd quarter of 2019, depending on oil prices (higher prices would lead to earlier date).
In a major victory for environmentalists and indigenous rights groups, Judge Brian Morris of the District Court for the District of Montana overturned President Trump’s permit for the Canada-to-Texas pipeline, which the president signed shortly after taking office last year.
Morris’s ruling repeatedly faulted the Trump administration for reversing former President Obama’s 2015 denial of the pipeline permit without proper explanation. He said the State Department “simply discarded” climate change concerns related to the project.
The decision once again throws into doubt the future of the 1,179-mile Keystone XL, which for much of the decade since its proposal by TransCanada Corp. has been a lightning rod in national energy policy.
The Trump administration had tried to argue that federal courts didn’t even have the right to review Trump’s approval, saying that it extended from his constitutional authority over border crossings. The court rejected that argument.
In rejecting the permit, Morris relied mainly on arguing that State, the agency that analyzed the project, didn’t properly account for factors such as low oil prices, the cumulative impacts of greenhouse gases from Keystone and the Alberta Clipper pipeline and the risk of oil spills.
TransCanada and State did not respond to requests for comment. The Canadian company had planned to start construction work next year.
This means – a few more years with 20$ oil for Canadas oil miners?
Acceleration of export plans to Asia?
“Reader, suppose you were an idiot. & suppose you were a member of Congress. But I repeat myself. ”
UK reserves estimates for end of 2017 by Oil and Gas authority.
Oil and gas replacement ratio rose to 60%, which is a lot better than some recent zero and negative numbers, but the reserve decline is continuing (only one year since 1997 greater than 100% replacement).
R/P for 2P oil is still about 11 years for oil, but below 6 for gas now.
Overall 2P ultimate recovery is holding fairly steady but 3P has declined over the past few years (mostly with possible reserves being moved into contingent resources).
From their results and overall FID activity I don’t think th service companies and EPCs are having a particular boom but the IHS capital cost index has been on a gentle rise recently. The offshore drillers still seem to be suffering from some recent results.
This has to be economic problems, prices aren’t anywhere near high enough to be causing major demand destruction from just the oil.
And this is with production curtailment from Venezuela, Libya and Iran by failed states/policy decisions, rather than geologic constraints.
I think it has to do with the OPEC meeting. If you look at history the oil price is almost always driven down ahead of key meetings. It can have a number of objectives; enforce discipline among OPEC members, scare investments in the shale patch and expensive offshore undertakings and also be a show off among power people (“look who controls the oil price”). Because, this sustained drop can certainly not have very much to do with long term or even medium term fundamentals.
Or another angle is as some claim, the Saudis have been played by Trump and the strong oil rally in September. Depends on who controls the market. I tend to think OPEC control the physical market more and the US control the exchange and media/financial players influence more. If the played by Trump angle is the case, the OPEC/Saudi coming adjustement needs some time. It could also be that US interests are not to disturb the US oil industry again through too low oil prices, and that there will be some moderation from EIA after this strong downward pressure on oil price (assuming it is from OPEC) – but you never know with the administration now in charge.
Baker Hughes International Rig Count
Total up +13 to 1017 in October
Oil +18 to 798
Natural gas -3 to 187
Misc -2 to 32
Split: Land +10 to 810 and Offshore +3 to 207
Brazil -2 (-2 oil)
Offshore China -5 (-3 oil -2 gas)
Norway +5 (+5 oil)
OPEC
Algeria -3 (-1 oil -1 gas -1 misc)
Saudi Arabia +6 (+6 oil +1 gas -1 misc)
Venezuela +2 (+2 oil)
Yes, this rig count speaks volumes. The oil glut supply thesis is up for sale for anyone that wants to buy it. SA , Norway and Venezuela not having problems? Brazil waiting for higher oil prices? And China too maybe? etc.
WTI fell for the 10th straight trading session.
This was the first time in the history of the contract.
You see, that’s because there has never been a supply and demand situation in all history as exists now. And of course eliminating Iranian supply must necessarily reduce the price.
You already did figure it out shallow, as regards nymex. Those guys have a significant incentive in making sure nobody else figures it out, so analysts will talk about supply and who is burning what.
FYI, Venezuela has proposed to OPEC that OPEC embrace blockchain pricing. That certainly concentrates on their own Petro currency, which will never fly, but it is a Pandora’s Box situation in that if blockchain technology becomes the norm in pricing, that will be the end of all sanctions.
Watcher,
Note that Iranian supply is greater than was assumed a few weeks ago due to the many waivers granted by the Trump administration. Trump wanted to try to keep oil prices low before mid terms, later he will cut off the waivers for several nations that import oil from the Iranians. When oil prices rise, Trump will blame Pelosi.
“Trump will blame Pelosi.”, for everything.
Hickory,
Yes I think you are right.
The first thing out of the President’s mouth post mid term, joined by Pelosi, was — amid a deficit that is 4.8% of GDP . . . a commitment to join together in pursuit of infrastructure spending. This clearly shows the Democrats embrace the philosophy of Dick Cheney — “deficits don’t matter” (And notice she didn’t propose a tax increase?).
Oh, and suppose oil prices don’t rise?
Or if they did, suppose the GOP offers up a govt subsidy of them in say, February of 2020 as the election approaches. Will the Democrats oppose that with November coming? Why should they take that electoral risk — since they embrace “deficits don’t matter”.
The detailed numbers for Brazil through September were issued Friday – quite a big drop in production despite the new FPSOs ramping up because of some outages on two of the big produces in Santos. The offshore drilling rigs for October are down to six , the lowest I’ve seen, so there’s unlikely to be a big increase then but it depends month to month on what new wells are completed and what the availability is on the operating assets.
It’s difficult to know now whether to present stuff like this as good news or bad as we need to be pretty well off of fossil fuels by 2050 to avoid “catastrophe”, though I don’t think that is making one iota of difference to the decisions made in the oil industry, in fact it might even act as an impetus to avoid being left with stranded assets.
Interesting that voters in two Blue states rejected anti oil and gas ballot initiatives.
Colorado rejected the spacing law and Washington State rejected a carbon tax.
I agree the FF industry spent money against these, but these initiatives were striaghtforward.
Proposal 112 in Colorado wasn’t ideal in that it proposed a significant setback throughout the state rather than to let individual communities to decide what they want.
Gas and oil spent millions to convince voters that gas and oil are a driving economic force in the state. That was once true, but is no longer the case.
However, given that state government is now blue, and an increasing number of people are living next to current and proposed drilling sites, I think gas and oil leverage will go way down.
Plus in the last few weeks there have two fires at oil sites. Every time there is an explosion or a fire, all of which get coverage on the news, people are reminded of safety issues.
This conflict is not over by a longshot. In fact, a couple of days ago a city invited public comments about a proposal to drill under a lake that is a major water supply and recreation area. After one day, the drilling company abruptly withdrew the proposal.
Both Blue and Red in USA are still generally ultra consumers who want everything as cheap as possible, no matter what.
AZ also shot down a renewable energy mandate by over 2 to 1.
NV passed a similar initiative however, and FL approved an offshore drilling ban.
The price of gasoline was not the reason 112 didn’t pass. Oil and gas did not campaign on the idea that we need more oil.
They kept saying the setback would end gas and oil drilling in the state (which isn’t true since no current wells would be shut down), jobs would be lost, and the state economy would suffer.
But the opposition is likely to get stronger as more people live in proximity to the wells.
The cost of housing is a bigger issue in Colorado than the price of gasoline. So when housing developments and drilling sites overlap, the people in those housing developments protest.
It’s just a matter of time before there is a critical mass of unhappy home owners to severely restrict what gas and oil companies can do in their neighborhoods.
Colorado isn’t like North Dakota. Gas and oil aren’t big drivers of the state economy. And as more people move into the state, it becomes even less important.
So population increases and where they live will ultimately be the deciding factors. Drilling in suburban housing developments just isn’t very popular with all the people in those developments.
Boomer.
I know this isn’t oil related, but how has cannabis legalization went in CO?
I have some family in IL and it appears that is coming there very soon. Will be the only Midwestern State.
Is there still a lot of black market weed sold in CO? Has meth and opioid use changed any?
It’s gone well.
Opioid use appears to be down, though meth continues to an issue.
Some in law enforcement say to expect an increase in meth coming into the US from Mexico, as more states legalize cannabis.
Reason being there won’t be demand for Mexican cannabis, so meth has become, and increasingly will be imported by the cartels.
Easy to make, very addictive. Horrible drug. It seems to hit rural America very hard. Never see heroin arrests where we live, meth are weekly in a county well below 20,000 people.
I just found this. It’s recent and may answer some of your questions.
From that NPR article on Colorado meth use.
———
Contrary to the portrayal of meth production in popular TV dramas, the meth in Colorado these days is rarely cooked up in neighborhood basements from local drugstore ingredients. Instead, it’s mostly imported, often along the same routes as heroin.
“I would say almost 100 percent of our meth comes from Mexico,” says Tom Gorman, director of the Office of National Drug Control Policy’s Rocky Mountain High Intensity Drug Trafficking Area. Much of it is mass produced there, he says, in “superlabs.”
The increased setbacks would have greatly curtailed new drilling in Colorado. That is where the majority of the O&G company budgets are allocated to. The operations of existing wells are financially minor compared to new drilling costs,
Yeah, I think that was the idea, to curtail drilling.
I think having more localized control is better. Some communities would have stricter controls than others based on what community members want, but so far state government has shot down that idea.
But this fight will continue until there is less drilling in populated areas and fewer accidents.
Looks like KSA are going ahead with poduction cut voluntarily or otherwise.
Otherwise they would have to invest 2 digit billions into new spare capacity they don’t have but claim to have.
On the other hand – they have to do it anyhow, they can be really tested anytime now.
What’s all of the other claims, Irak extending production capacity over 5 mb/d, Nigeria over 3 (they wanted to have reached 4 already in 2015 according to an old wikipedia article).
The only thing possible to grow without limit is US LTO.
Of the 100 000 wells drilled globally in 2013, 4% were exploration or appraisal wells. In 2018, this share is expected to drop to only 2% of the 70 000 wells drilled. This trend can be observed across both the offshore and the onshore markets and across the globe.
In the offshore market share of exploration wells has changed from 35 to 24%. We’ve seen the most significant drop in South America as the Brazilian exploration market dried up during the downturn.
One reason for the drop is that there are fewer highly prospective areas, and where the might be oil and gas the wells are expensive. Despite advances in seismic and visualisation the chances of a successful well seem to be falling: two high impact frontier wells were announced dry today, one offshore Nova Scotia (I think maybe the last chance there after expensive misses by Marathon and Shell previously) and one in Gambia. The big drop in offshore proportion was 2013, when prices were much higher than now.
Onshore there are clearly very few places left that haven’t been explored and a drop to about zero exploration wells seems likely in the early 20s.
I wonder if Rystad has enough data on leasing activity to do a similar comparison for that, I think it would show a steeper drop.
Aren’t there onshore a few places where you can test at least LTO production? When there is some good rock somewhere it can be good to produce. Especially in countries where you don’t pay the supply crews for fracking that much (construction, truck drivers ) so you are cheaper than in developed countries.
I think the issue with LTO is more that the locations are known but the productivity and costs are questionable, so it’s not to do with exploration.
I don’t think at production in the USA – and with a more long duration strategy a good rock should be not more expensive than deep sea under salt production.
With land leased direct from government, and a planned logistic / fracking infrastructure without boom / bust prices I think it should be possible to produce cheaper than in Texas, same rock quality given.
But hat’s that got to do with exploration numbers – if the LTO location is known it’ doesn’t count as an exploration well if there’s new drilling there.
That I didn’t know.
If I know there is a big field, have a few production wells and now do exploration round about the field to look for sweet spots that’s no exploration anymore?
By definition of terms, in my opinion, there are no “exploratory” wells in resource plays. Initially there were step out wells to define the boundaries of the play, since then everything is simply development of the resource. Shaleco’s themselves tout thousands of “drillable locations” on their lease blocks and even the SEC allows for booking a portion of “type” EUR from proven but ‘non-developed,’ imaginary wells based simply on proximity to ‘proven, developed’ wells.
Booking those kinds of reserves of course does not take into consideration prices, or inflationary costs, or a host of other potential problems facing the shale phenomena in the future; it does, however, make for good Power Point presentations, press releases, reserve based compensations to management, etc. And most of all it distorts the reserve picture in America and gives consumers a false sense of hydrocarbon security. The “we have decades of shale oil and shale gas” bullshit also creates really stupid energy policies in Washington…like telling America it is no longer economically necessary to conserves its oil resources: https://www.oilystuffblog.com/single-post/2018/08/20/For-America-Conserving-Oil-Is-No-Longer-Economically-Imperative
Summary of OPEC+ JMMC meeting
Saudi energy minister Al-Falih: We have to wait for the best oil data and projections in December to make the best decision. The next meeting is December 5th.
The data analysis looked at during the OPEC/non-OPEC JMMC saw hints that there will need to be a supply reduction of ~ 1 million b/day from October levels
Russia is happy with what has worked for the last two years, and is happy to continue cooperation with OPEC
Oman oil minister: There is a consensus that the oil market is oversupplied
OPEC Secretary General: There is no doubt that 2019 will be challenging
Russia’s Energy Min Novak: Uncertainty around Iranian exports, trade wars to remain in 2019
– No decision on global output deal has been made in Abu Dhabi
UAE Energy Minister: OPEC to monitor market for next 3 weeks then decide on 2019 output – Ministry Tweet
If the EIA are right, then the US has increased production by +2 million b/day just this year.
Crude Oil Production Re-benchmarking Notice https://www.eia.gov/petroleum/supply/weekly/
Note that Weekly estimates are not revised so looking at weekly estimates over a long period is a waste of time. If we look at monthly data (which is revised and tends to be more accurate), from Aug 2014 to Aug 2018 US output increased at an annual rate of 615 kb/d each year on average. That is likely to be closer to the annual rate of increase from Aug 2018 to Aug 2021 in US C+C output.
Over the past year there has been a steep increase in output of 2100 kb/d, this rate of increase is not likely to continue, for the past 2 years the annual rate of increase was 1338 kb/d each year, after output fell by 200 kb/d from Aug 2014 to Aug 2016 due to low oil prices and fewer completed wells in the LTO sector relative to 2012 to 2014 and 2016 to 2018. A continued fall in oil prices may again result in a lower rate of increase in output (or even a decrease if WTI oil prices fall below $50/b).
If the glut of oil scenario that is currently in vogue actually occurs, US output will fall as oil prices crater. I doubt this will happen, but was wrong in November 2014 when I also thought the oil market would adjust but I was mistaken (or it took much longer to occur than I anticipated, 2.5 years rather than 6 months).
Oilprice.com is running an article saying US LNG will replace Russian piped gas in Europe. The key buzzphrase was
We will be competitive with pipeline gas, maybe even in price.
How cool.
Tellurian’s Driftwood project will produce the same as Yamal at half the construction cost and, presumably, much lower operational expenses.
Likewise, Driftwood is comparable in capacity to the 3 Curtis Island operations at 1/4 construction cost. Feed in gas will be much less expensive than the Aussie Coal Seam supplies.
The Delfin project project offshore Louisiana – utilizing 4 FLNGs – may be cheaper by a bunch than all the rest per metric tonne to construct (about 13 mtpa capacity … half Yamal and Driftwood).
While no one can reasonably expect LNG to ever overcome price/cost advantages of piped gas, that the global spot price for LNG has bounced around st the $8/$10 mmbtu level is nothing short of astonishing.
I have mentioned several times on this site that the attention placed on oil supply/availability is tending to overshadow the emergence of natgas on the global energy stage.
The recent announcement that a near billion dollar LNG facility is being proposed way up in the woods of northeast Pennsylvania almost strains credulity.
However, that was just announced by the same outfit that is already producing LNG just north of Miami, FL
Heck, even Massachusetts – that hotbed of opposition to all things hydrocarbon – may host a small LNG plant in Auburn in central MA.
The ongoing implementation of processes and hardware dealing with liquified methane is poised to upend the current paradigms of energy use and production.
The productivity, economics and efficiency gains of Driftwood LNG are impressive if achieve. IIRC Expected Target price we budgeted for FERC @Trunk line LNG was $7+ @evaporators in 1983. Supplier market since Algeria was the main exporter with long contracts. Little effort in cost control since it was cost plus.
What has any of that to do with . . . “we’ll be competitive, even in price.”
Watcher,
Lower costs of production (which includes capital cost) can reduce price.
yeah you miss the point too
the phrasing, how else is one competitive
“I have mentioned several times on this site that the attention placed on oil supply/availability is tending to overshadow the emergence of natgas on the global energy stage.”
I agree with you, Coffee. Even as a transportation fuel (which I think is a poor usage of natural gas), natural gas could displace a significant portion of oil usage. I seriously considered a natural gas powered Honda GX a few years back. But chose not to based on a lack of infrastructure for re-fueling and reduced range.
I still think EV’s are superior to ICE vehicles (regardless of fuel type) or will be once a reasonably priced EV powered pickup and SUV are available. If oil is significantly eliminated as a transportation fuel, it will be plentiful for its other uses in chemicals etc.
If the natural gas supply truly is growing as Coffee indicates, maybe all of the angst over a declining oil supply are overblown.
Songster
One word … MOFs.
Check out the recent articles in Scientific American to get just a glimpse of where this is all headed.
When cutting edge MOFs the size of a pea have comparable internal surface area to two football fields, amazing stuff is gonna happen.
The Iranians claim to have achieved the “Holy Grail” of CNG storage wherein a standard size fuel tank – at 500 psi rating – full of MOF adsorbant can compare favorably with a 15 gallon gasoline tank.
Sub 500 psi will allow homeowners to fill up with their residential natgas supply.
Coffeeguyzz,
The natural gas resource is not unlimited, if natural gas comes to dominate the transportation sector, natural gas supply will peak very quickly. In that case natural gas becomes very expensive and will be unable to compete with wind, solar and EVs due to its higher cost.
Now zzzz is an expert in physics to0?
Just reading what he has written, it sounds like a MOF will absorb Natural Gas molecules and somehow keep it in a compressed state, therefore turning NG into a kind of CNG. I understand that it works very similar to the way that activated carbon works as an absorbent for gas. The ratio of equivalent volume to absorber volume does look quite high.
But then you think, why not just use the MOF to absorb renewable hydrogen gas instead of dirty finite non-renewable NG?
And how do we currently produce hydrogen on an industrial scale? Reality is a bitch.
True, zzzz the cornucopian.
I was thinking more along the lines of treating H as a storage medium for localized renewable energy conversion.
Quiet One
Check out Nikola Motors website, or – more precisely – the story posted on August 8, 2018 from Gas World describing a Norwegian outfit building the world’s largest electrolyzer plant to produce hydrogen.
Nel ASA is that company’s name and I have no idea if or even how that stuff works.
Best leave that to the physics’ experts of which this board clearly contains a few … so long as they not be snoozing too much.
I don’t know if I am the right one to answer you. It is cheapest to produce hydrogen by using natural gas. But more long term and environmental friendly is hydro power and then using electrolysis of water. And this is great in some way but costs maybe 2-3 times more than transportation fuels today (using hydro power) in addition to some storage/pressurisation challenges. And saftey issues e.g. in ships and airplanes. Not saying it can not be overcome. In Norway they see a big potential for this in an energy crisis environment. Buses, trucks, ships and airplanes in order of difficulty (the last option probably being somewhat unrealistic).
Saudi Arabia plans to reduce oil supply to world markets by 0.5 million barrels per day in December, its energy minister said on Sunday, as the OPEC power faces uncertain prospects in its attempts to persuade other producers to agree a coordinated output cut.
Yeah, Saudis and opec will decrease production dramatically to counter ghost production figures by the EIA. Should be interesting in a few months.
2018-11-12 (Twitter) Donald J. Trump – Hopefully, Saudi Arabia and OPEC will not be cutting oil production. Oil prices should be much lower based on supply! https://twitter.com/realDonaldTrump
Wonder what oil price Donald Trump thinks is correct?
All I see is he wants it below $60 WTI based on the chart.
But how much lower?
Maybe he believes EOG’s 2016 $30 WTI profitability BS.
Seems he is ignoring nat gas. Wonder why?
Yes I don’t understand the tweet, especially as an OPEC cut would potentially give US exporters a larger market share. And WTI is already a full $10 lower than Brent. And so I’m guessing that the tweet means less $business for US companies. And a new inventories glut would see $WTI back down to 50 and below. A new refinery designed for LTO might do more keep US gasoline prices low???
He’s just fucking around with everybody. Republicans seem to like it.
just read “3.10 Crunching the numbers: are we heading for an oil supply shock?” in the WEO (p.156). They more or less conclude that a “supply shock” is likely and unavoidable (is it then really a shock?).
According to the presentation US oil production has to grow to round about 20 mb/day until 2025 to avoid undersupply. Not an easy task, even with inexhaustable ressources.
The most interesting part of the graph is in how much they estimate future decline rates of current production. Wow!
They have Growth from other sources (at current project approval rates) – but that depends on finding stuff to meet those approval rates and/or having sufficient back log. Neither of those things are remotely happening at the moment, so decline will be faster for conventional. In-fill drilling may step up in the short term if prices are high enough but then the decline will be even quicker.
Integrating the US LTO production growth that they have surely exceeds by someway the current EIA reserve estimates unless everything drops to zero pretty quickly after 2025.
What possible use is any of this to the people who pay money for the report other than to cover their collective BAU promoting (and therefore biosphere destroying) arses?
They don´t forecast LTO to increase as much as in the figure. It´s rather illustrating “call on shale” i.e. how much LTO needs to increase to meet BAU demand growth. The report is fairly transparent on this point and state that US LTO resource base needs to be much larger than assumed for this to happen.
There are several other shortcomings in the report including: stating that the gap is (only) a result of to risk adverse cost mgm in E&P and more capital investment will solve it, also they do not have “a best guess” supply scenario.
From the summary conclusions the impression is they don’t have any clear answers, maybe they are realising there are none: There is no single solution to turn emissions around: renewables, efficiency & a host of innovative technologies, including storage, CCUS & hydrogen, are all required
The future pathway for energy is open: governments will determine where our energy destiny lies
George Kaplan,
I agree the growth from other projects of 17 Mb/d from 2017 to 2025, seems a highly unlikely scenario. Perhaps infill drilling and contingent resources and “possible” reserves might allow some of this to occur, but 17 Mb/d seems like too much. In addition, it is not clear how much of World 2P C+C reserves are undeveloped, so some of this “Growth from other sources” may simply be from 2P undeveloped reserves.
Coal plants make up one-third of CO2 emissions today and half are less than 15 years old;
policies are needed to support CCUS, efficient operations and technology innovation – what a load of delusional bollocks, they forgot the bit about changing the laws of physics. And so keen are they on it that they included it three times in the summary.
The growth in LTO output shown in that first IEA chart (first link in Energy News comment above) is an increase of about 15 Mb/d from 2017 to 2025, it is possible we might see a 2 to 3 Mb/d increase in US LTO output over that period, but that 15 Mb/d increase from 2017 levels is patently absurd.
But this graph is just LTO filling their projected “demand” projection.
In their summary towards policy makers they write :
“« The risk of a supply crunch looms largest in oil. The average level of new conventional crude oil project approvals over the last three years is only half the amount necessary to balance the market out to 2025, given the demand outlook in the New Policies Scenario. US tight oil is unlikely to pick up the slack on its own. Our projections already incorporate a doubling in US tight oil from today to 2025, but it would need to more than triple in order to offset a continued absenceof new conventional projects. »”
(taken from : http://petrole.blog.lemonde.fr/2018/11/01/minuit-et-quart/#comment-31865 , I don’t have access to this summary)
And what is kind of “funny” is that they are also saying that oil will reach a “demand peak” in 2040 (due to electric cars etc), which is the bit taken by most “MSM media”, like for instance : https://www.timeslive.co.za/motoring/news/2018-11-13-oil-demand-is-under-increasing-threat-from-electric-cars-and-cleaner-fuels/
Just correct the Permian reserves from 40 GB to 400 GB, and the US oil industry can take over the world. It’s just numbers on a powerpoint presentation.
I think they have just projected the 2.5 mb/d increase from 2018 they have measured up to the infinity.
OPEC Citing Secondary Sources, Says Its October Crude Oil Output Rose +127,000 B/day M/M To 32.90 million B/day, Despite Lower Iranian Output
some highlights https://pbs.twimg.com/media/Dr4EX4ZX4AA9Fdd.jpg
Somewhere recently I read something that I thought said that new debt has just about equalled the amount used for share buybacks – I’m not sure over what period or what exact location(s) but now I can’t find it. Anybody else seen something like that?
Couldn’t find what I was looking for but found this below.
Share buybacks are in the trillions per year and rising significantly this year in US following the tax cuts, 3Q numbers look likely to be the highest ever. It’s maybe one reason why all the new debt gas not led to high inflation.
The oil industry is one of the biggest players for buybacks, especially the IOCs, and this year more the non US companies like Total, Shell and BP, but Anadarko has an expanded program as well. The people that benefit the most (maybe the only ones to benefit in the long run) are executives with stock options. After the 1929 crash buy backs were seen as part of the problem and banned, I don’t know when they started again.
The Economist has called them “an addiction to corporate cocaine.” Reuters has called them “self-cannibalization.” The Financial Times has called them “an overwhelming conflict of interest.” In an article that won the HBR McKinsey Award for the best article of the year, Harvard Business Review has called them “stock price manipulation.” These influential journals make a powerful case that wholesale stock buybacks are a bad idea—bad economically, bad financially, bad socially, bad legally and bad morally.
And so the floodgates opened. The resulting scale of share buybacks is mind-boggling. Over the years 2006-2015, Lazonick’s research shows that the 459 companies in the S&P 500 Index that were publicly listed over the ten-year period expended $3.9 trillion on share buybacks, representing 54% of net income, in addition to another 37% of net income on dividends.
I did not see this superdive in oil prices coming. Many succeed in business by being unscrupulous. And in the oil market a relatively minor surplus (or deficit) of barrels in the marketplace at any one small time window can drive prices to wild extremes. If this is a wise move by those behind it – probably not.
Why it is not? If a free market is supposed to work like intended, the price is the main signal for the market players. High prices makes an incentive for investments, higher production, conservation and alternative solutions at the same time; to distort that makes the whole market inefficent and price volatility in the future will most likely also be too high. The whole thing will taste bad.
This is a way of life for oil producers in the US.
This is why Mike, and to a lesser extent, I, give Dennis such a hard time about his graphs and projections.
$8-140 in 19 years.
$25-$99.25 from 6/14 to 2/16.
$28-$140 from 7/08 to 2/09.
Volatility baby. A drop of $20 in 3 weeks is nothing. Wake me when we hit $40s Friday.
Be careful what you wish for shallow.
I am well aware that on a short term basis the price can range from $10 to $200.
It just takes a few months of prices significantly below OPEX to go bankrupt.
Would be something to go BK with no debt. We were thinking that way in 2016.
You have to have debt to go bankrupt.
So you operate at a loss. You fund it. Out of pocket, or via borrowing.
Only after you have that borrowed debt on the books can you expunge it via BK.
Not if entity runs out of cash and you don’t want to put personal assets up or borrow.
Ask Trump.
You are forgetting the P & A liabilities.
Shallow sand,
It s certainly the case that I do not know future oil prices. The scenarios always state the assumptions. Lower oil prices result in lower output.
SS,
remember my earlier posts: “… in the end there will be spikes of the wave, up and/or down … and then kaboom.”
You may not hit $40 by Friday, but you sure as shooting will hit $0 sooner than you think.
Time is relative body, if you travel C – becomes 0/nonsensical.
Read your posts from 2014, how panicked you were then .
Lately, you/we have ridden the upside part of the wave.
We are going down now. Wait till we reach the trough… (hint: there won’t be any…. $0).
I suspect you wont be slipin, you will be awake when that Friday arrives…. if you catch my drift.
be well,
Petro
India – PPAC – Consumption of Petroleum Products (‘000 Metric Tonnes)(without LPG)
October is up +4.5% higher than October 2017
Average consumption for the first 10 months of 2018 is up +5.1% higher than same period in 2017
Chart: https://pbs.twimg.com/media/Dr6ED8oWoAAyTny.jpg
We have talked about whether debt in the US is manageable. The WSJ had an article Monday on the rising federal debt.
“Debt as a share of gross domestic product is projected to climb over the next decade, from 78% at the end of this year—the highest it has been since the end of World War II—to 96.2% in 2028, according to CBO projections. As the overall size of our debt load grows, so too do the size of interest payments.”
Definitional claptrap. The ratio is over 100%. It has always been quoted as total debt. Now, since the number is over 100%, the definition changes to exclude liabilities (aka debt) held in the various trust funds, like Social Security and Medicare. When people have SS contributions extracted from their paychecks that money buys bonds and those bonds are parked. They are debt. Soon or maybe already that money contributed flows out as benefits and maybe there’s a net negative flow now, but that doesn’t matter. The trust fund is in bonds.
Those were always included in the amounts quoted in the past. But now that they have caught up to and exceed US GDP, gotta redefine them. Note that when debt/GDP is quoted for other countries, their trust funds are included.
Quoting: By law, income to the trust funds must be invested, on a daily basis, in securities guaranteed as to both principal and interest by the Federal government. All securities held by the trust funds are “special issues” of the United States Treasury.
It’s debt. It’s included. The US debt/GDP ratio is over 100%.
(I cannot see in the highlights if they have adjusted World Supply for the drop in Iranian exports, because so far exports have decreased more than production. I guess that they must have?)
IEA: Shipments Of Iranian Oil In October Were 1.8 Mln Bpd, Down 900,000 Bpd Vs May, Still Unclear How Far Exports Will Fall
2018-11-14 (Saxo Bank) Natural Gas at $4.4 mmbtu trades at the highest level for this time of year since 2009. Carried higher by strong momentum in response to US cold snap, stocks at a 15-year seasonal low and expectations for a modest 32 bcf injection in Thursday’s EIA Report. https://pbs.twimg.com/media/Dr9fzFYXQAENZMM.jpg
Hearing comments on business news that oil drop due in part to rotation into natural gas and due to one very large trader long oil getting hit with margin calls big time and being forced to liquidate.
Obviously I don’t know but it looks like speculators have been selling their paper barrels for the last few weeks. The number of paper barrels net long (yellow line) has come back down to the longer term range.
Saudi Update October 2018
http://crudeoilpeak.info/saudi-update-october-2018
Nice Saudi update unfortunately without Ghawar. Are there any hypothetical models for Ghawar?
To put it mildly, I’m not an expert on where to find info Ghawar. Perhaps brighter minds will chime in.
http://peakoilbarrel.com/closer-look-saudi-arabia/
http://crudeoilpeak.info/category/saudi-arabia
My guess is that much of KSA will look a lot like the shabby end of Yemen before too long. This will perhaps strand some assets. Once the House of Saud fragments further among competing clans/factions (Faisal, Sudairi, Abdullah, Bin Sultans) things will hasten. Collapse is preceded by intra-elite rivalry over a shrinking pie, so to speak.
Caspian Report has a nice set on KSA if you look for them. Here’s one-
https://youtu.be/9tHwvZ9XDLU
And another-
https://youtu.be/hh8isVX3H9w
Hightrekker once commented something quite apt, along the lines of~ ‘And all this is probably like the Austrians in 1913 arguing about who their next Habsburg Ruler is going to be’.
From what I understand there are 4000 Saudi princes (a suspiciously round number, so likely an approximate). It all should make for a very bloody affair. Hopefully Iran will do the right thing and kick ’em while they’re down.
30/10/2018
Saudi Update October 2018
http://crudeoilpeak.info/saudi-update-october-2018
thanks for the great article Mushalik
Indeed
The US crude production numbers are surprising the heck out of me.
Rystads projections out to 2025 are staggering-
“Rystad has been one of the more bullish voices in terms of U.S. production growth, and thus far it has been vindicated. Its own forecasts have output rising close to 18 million barrels a day by 2025, assuming $65 a barrel, or more than 20 million a day at $75.”
https://www.bloomberg.com/opinion/articles/2018-11-01/u-s-oil-production-the-shale-boom-makes-a-new-mexico
I guess it’s time to break out the champagne!
U.S. monthly crude oil production exceeds 11 million barrels per day in August
U.S. crude oil production reached 11.3 million barrels per day (b/d) in August 2018, according to EIA’s latest Petroleum Supply Monthly, up from 10.9 million b/d in July. This is the first time that monthly U.S. production levels surpassed 11 million b/d. U.S. crude oil production exceeded the Russian Ministry of Energy’s estimated August production of 11.2 million b/d, making the United States the leading crude oil producer in the world.
Hickory,
At low oil prices ($80/b or less in 2017$ for Brent crude), US output might rise to 13.5 Mb/d at most, with a best estimate of about 1.4 Mb/d by 2021 (which would be the peak in a low price scenario).
Note that my “low price” is roughly the same as the Rystad “high price”. They seem to be buying the hype in investor presentations, even a “high TRR” scenario (probability 95% that output will be lower than that resource level even at high oil prices, $150/b or more in 2017$) would only bring US output to about 14 Mb/d, far short of the 20 Mb/d predicted by Rystad at $75/b.
In short, Rystad is too optimistic by far. Output may increase a bit through 2022 and perhaps even through 2025 at “high oil prices” of $130/b or more, after that output will fall regardless of price (I assume oil prices above $200/b in 2017$ are not feasible).
Hickory
Slide #9 from the recent Continental presentation accurately captures a big reason behind much of these increases.
In contrast to much concern regarding ‘sweet spot depletion’ a few years back, prodigious production has actually increased dramatically over an expanding area due to ever improving innovations.
(The recent 9,000 foot lateral drilling in under 24 hours in the Marcellus – 100% in target zone – is but one example).
The implications of that slide #9 extend far beyond the Bakken as regions such as the Powder River, Tuscaloosa Marine, Uinta and others are increasingly viable for this high efficiency development.
Good point Coffee, there are certainly more big wells in the Bakken (and elsewhere) than a few years ago. Improving science and technology versus declining resources. Its hard to say what happens in the immediate future.
dclonghorn,
If we consider average well productivity for the Bakken, we have (from link below, click on well quality tab) the chart below, there has been a small increase in average EUR, this will end at some point.
https://shaleprofile.com/2018/10/18/north-dakota-update-through-august-2018/
From 2013 to 2017 the average well EUR increase from 300 kb to about 380 kb, from 2008 to 2013 there was little change in new well EUR. The increase is mostly due to high grading where only the most productive areas are seeing any well completion, eventually these areas will become saturated with new wells where any closer spacing is not profitable (lower EUR per well will simply result due to well interference). At that point average new well EUR will decrease in the play, you are no doubt aware that this is always the case for any oil field, but it is difficult in unconventional oil plays to predict with precision when this will occur.
Dennis, Coffee’s comment did not turn me into a shale cheerleader. I suppose I am more in the shale sceptic camp for the reasons you mention and others.
Nevertheless, I think Coffee’s comment was correct, it does appear that shale producers in the Bakken have expanded the area that produces exceptional wells. As one who underestimated shale’s viability before, I don’t want to repeat the same mistake.
As you note, it is difficult to predict when average well productivity in the Bakken (or anywhere) will occur. I had thought that current drilling levels would be inadequate to sustain 1.15 million bpd production levels, but somehow they are increasing production there. It does appear that for now, the shale operators are having some success.
How long that success will last depends not only on the operational decisions made, but macro factors such as debt, interest rates, and the economy will play out, and eventually Bakken production will decline. But for now…
And in a brief follow up …
I have not read Continental’s conference call transcript yet (Seeking Alpha provides them), but it seems the suit from Continental now feels they will recover – from present completions – 15 to 20 per cent of the OOIP.
That is huge as the norm was 3 to 5 per cent a few years back.
… and tentative plans are brewing to be be able to move 1.7 MMbopd out of the Bakken in future months via CBR, expanded pipeline flow, new builds, or some combination.
There was also concern about rig cannibalization and the permanent departure of workers. Guess not.
Why isn’t Continental’s credit rating better than 1 notch above junk?
If we look at CLR’s Bakken wells in 2012 to 2014 and the 40 month cumulative it is about 154 kb. For all companies in the Bakken for the same 2012 to 2014 wells the average cumulative output is 165 kb with a likely EUR of about 300 kb over the life of the well.
The continental type curve is a joke, if we assume 70% of the boe is oil for the 1200 kboe type curve, that would be 840 kbo, almost 3 times the average EUR of the average 2012 to 2014 well. Lately the EUR of the average Bakken well may have increased a bit to perhaps 380 kb (most of this increase is over the first 20 months after that the wells have declined to the rate of the older wells).
The investor presentations are very selective about choosing the best wells to present, the reality is there are some really poor performers that still cost 8.5 million to complete, that is the reason CLR has about $6 billion in debt at the end of 3Q2018, at year end 2015 debt was about $7 billion, so at least they are slowly moving in the right direction, but at the rate they have paid off debt in the past 2.75 years, it will take another 14+ years to become debt free.
Problem is that tight oil is likely to peak well before 14 years, but rising oil prices might allow debt to be paid down more quickly. For the past 9 months net income was 0.79 billion, if all of this net income were used to reduce debt (assuming this level of net income continues) the debt could be paid off in 6 years, higher oil prices might allow a quicker pay down of debt.
Up until the 2013/2014 timeframe, Continental was largely engaged in the Land Grab phase of their planning wherein the 800,000 leased acres needed producing wells to maintain the leases (3 year expirations).
One part of this company’s plan was to ‘cookie cutter’ their completion process using 30 stage sliding sleeve design.This continued despite the general shift back towards plug and perf as Hamm felt the overall benefits obtained from the speed garnered with the familiarity would offset reduced production.
In addition, Hamm wanted a uniform metric with which to compare different well performances throughout their vast holdings to better evaluate the geology.
It has only been the past 2 years or so that they have been implementing 60 stage, high cluster, high proppant use alongside very restrictive flowback procedures.
These techniques, along with many others, are why newer wells are performing so much better than earlier ones.
BTW, if you follow Bruce Oksol’s site, you will see how the Three Forks is starting to shine with the possibility of eventually out producing the Bakken.
All of this bullshit is straight, I mean straight off Continental’s self servicing investor presentation bullshit, Coffee. You need to wrap your head around some SEC filings, use some common sense and think for yourself. As opposed to letting someone else do your thinking for you.
Watcher is correct, CLR’s credit rating, its credit score, so to speak, is so bad it could not in the real world buy a pickup truck without its mama co-signing the note. If its wells are sooooooo much better, why don’t they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year…in interest on long term debt if it didn’t have to? Never mind, you can’t answer that.
If you are not in the oil business and have never balanced an oil well’s checkbook in your life, which Coffee hasn’t, then you don’t know that higher productivity comes with a higher cost in the shale biz. The bottom line then is that the bottom line does not change…if it did the shale oil industry would be paying down some debt, right? Its not. Private debt is skyrocketing.
Are things getting better for the shale biz? Right. Case in point, the largest pure Permian Basin oil and associated gas producer, Concho, the genius behind a recent $8 billion dollar acquisition from RSP, LOST $199MM 3Q2018. Inventories are going back up, prices are down 18% the past month and what does the shale oil industry do?
It adds more rigs.
Productivity is not the same as profitability. In the real oil biz you learn that on about day six.
“If its wells are sooooooo much better, why don’t they pay some of that $6 billion plus dollars of debt back? I mean really, who in their right mind would actually WANT to pay $420MM a year…in interest on long term debt if it didn’t have to?”
I wonder about debt service, too.
When Dennis runs his scenarios he says that at a certain oil price, these companies will be quite able to pay down debt.
But will they? Or will they just pay themselves as much as they can as long as they can get away with it, and then declare bankruptcy and walk away.
I’ll take door two.
We had 5-6 years of the highest, sustained oil prices in history and the shale oil industry could NOT make a profit. People seem to think now things have changed for some reason, that the shale oil industry has now become more ethical, and temporarily higher productivity of wells, and some imaginary oil price off in the future (for most shale guys its now down in the mid to low $50’s) will allow them to pay down debt. Its absurd logic, but keeps people occupied, I guess, speculating about it.
I urge folks to ignore the guessing, and the lying, (Hamm’s 20% of OOIP in the Bakken is a big ‘ol whopper) and look at the shale industry’s financial performance over the past 10 years and decide for yourselves if it is sustainable or not.
One thing to add. The shale companies did all this in the lowest interest rate environment we have had in a long time. They could not pay off their debt or even put a dent in it. What is going to happen when their interest costs increase 30-50% over the next 2-3 years?
Reno,
If oil prices are low, there will be problems for those companies with higher debt levels. If oil prices increase to Brent at $80 to $90/b many of these companies will be ok, in my opinion.
Boomer,
There is a lot of money to be made in the Permian after 2025, about 200 billion in cumulative net revenue from 2025 (when all debt is paid to zero) and 2035 when cumulative net revenue is 200 billion. Those companies that are bankrupt lose out on this pay day. There is an incentive to remain in business, this is why many companies pay their executives with stock options, it aligns the incentives of shareholders and CEOs.
I really can’t see that all LTO debt will be paid to zero by 2025.
As far as I can tell, you might be the only person who believes that.
We’ve got some who think that debt will crash the industry, others who think terms will be renegotiated to keep the machine going as long as possible, others who think companies will focus on dividends rather than expanding operations (and perhaps only pay down the minimum debt they can get away with), and at least one (Watcher) who thinks governments will go to war or print money or something else to keep the oil flowing.
Boomer,
I was surprised as well. You may be correct that the debt will not be paid, but in a reasonable economic scenario.
Average well cost=9.5 million in 2017$
Oil Price (Brent) rises to $110/b by Feb 2027 and remains at about that level until 2040
Nominal annual discount rate 9.5%
Royalties and Taxes=32% (corporate taxes not included
Nominal annual interest rate 7.4%
Transport cost $4/b
Monthly OPEX (including G&A) is $2.3 times the monthly barrels produced plus $15,000 per well for downhole maintenance (monthly average),this is the fixed plus variable cost model suggested by Fernando and matched to Rune Likvern’s work on the Bakken for business costs.
Businesses can choose not to pay debt and go bankrupt, but they miss their share of 500 billion in potential cumulative net revenue after the debt is paid off. Other better oil companies will pick up assets on the cheap from businesses that choose the bankruptcy route and make a killing. The big boys (Exxon, Statoil, BP, Chevron) would have plenty of capital to make this happen should the opportunity arise.
I get that the numbers show the debt COULD be paid off.
But I see business and political decisions being made that don’t seem to be good decisions to me.
So I am not confident that the fossil fuel business will necessarily be conducted rationally.
And I have seen enough stock market and investment scams over the last 50 years to be inherently skeptical of them.
I was a former employee of Newfield, when we were drilling gas wells in the Arkoma Basin in 2007 and gas prices were the highest they had ever been, it was not cash flow positive. It actually ate all the revenue from the rest of the company. Getting to be in the black for the play was always a year off. a decade later it never got there, they just got more and more debt sold more producing assets to pay for it to keep the shell game going and just got bought by Encanna. I have seen the same at every public company I have worked for, many of them survived the downturn only because costs dropped and so did the cost of debt. Now with increasing costs and cost of debt there will likely be many bankruptcies.
Coffeeguyzz,
The output of the wells from the past few years is a bit higher, but after 20 months the output of these newer wells is similar to that of the average 2012 to 2014 well after 20 months. What we have is very expensive wells (those extra 30 frack stages are not free) that produce maybe 20% more oil over their lives.
The Average EUR has increased from about 350 kb to 420 kb, in part from focusing on the sweet spots because of low prices and in part due to increased well cost associated with more frack stages and higher proppant levels.
I’ve said it before and will repeat, don’t believe the hype in investor presentations and ignore “boe” EUR estimates where the natural gas contributes very little to the bottom line, that is why most producers would rather flare the gas as it is more expensive to gather and transport than the revenue gained by doing so (in most of the ND Bakken/Three Forks).
Coffeeguyzz,
If we consider 2017-2018 Bakken and Three Forks wells.
The average 12 month cumulative for Three Forks wells was 151 kb, and for Middle Bakken wells it was 171 kb cumulative barrels produces at 12 months. Eventually Middle Bakken new well EUR will decrease and perhaps the Three Forks wells will outperform Middle Bakken wells at that point, for now based on average well data, Middle Bakken wells remain more productive on average compared to Three Forks average wells.
This is based on data gathered from Enno Peter’s shaleprofile.com
Yeah, I agree with Mike, Rystads announcements are mainly just self serving hogwash. Yes, oil production in the US looks to be close to 11.3 million for August. EIA’s reported production for Texas is only about 50k over my high estimate, so I see nothing to argue about. GOM is the main surprise, and George and others are better suited to comment on that. The understanding I had was that it was temporary. As far as Texas goes, I’m pretty sure it is the high, for awhile. Completions dictate how much oil comes out of the ground, not drilling rigs. That is for unconventional wells, not conventional. That is why I think the EIA’s DPR is a ridiculous measurement assessment. Apples and oranges. Articles that I have read indicate a significant decrease in completions in the Permian by the end of August. Texas production is not all about the Permian. A significant amount was contributed by the Eagle Ford and other areas. All completions have slowed to the point that by the end of September, they were at slightly over 60% of June’s completion numbers according to RRC statistics. Significant drop, and it will show up in following months. First years decline rates will assure that it will drop slightly from this point. $64 WTI won’t motivate it to expand to any extent. The next year will see US wavering along the 11.1 million barrel level, I still think. Unless, George thinks the GOM increase is somewhat permanent, which I doubt.
June completions
http://www.rrc.state.tx.us/media/46402/ogdc0618.pdf
July completions
http://www.rrc.state.tx.us/media/46805/ogdc0718.pdf
August completions
http://www.rrc.state.tx.us/media/47577/ogdc0818.pdf
Sept completions
http://www.rrc.state.tx.us/media/47968/ogdc0918.pdf
This is a very definite trend. From 914 oil completions in June to 553 oil completions in September.
Of course, no one needs to take my word for it. They can compare Texas production numbers:
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/production-data/texas-monthly-oil-gas-production/
To historical completion numbers here:
http://www.rrc.state.tx.us/oil-gas/research-and-statistics/well-information/monthly-drilling-completion-and-plugging-summaries/archive-monthly-drilling-completion-and-plugging-summaries-archive/
And try to locate a time in history when production is trending up, while completions are trending down. There is usually a several month lag by the time production slows. Takes a while to get out of the ground if they are completed towards the end of the month.
Don’t you just love simple logic? Like: fire burns, water is wet, stuff like that?
How do these projections (hogwash) help Rystad? By preaching the ‘good’ word to their paying audience? I don’t know their business.
They are a consulting business. How much business will they generate if they tell negative stuff?
I second that. Being from Norway myself, and having actually been working in consulting some years ago. It looks nice on paper, but the world is changing and it is wise to look out for deception and that is often the case in consulting (customer/revenue first and reality second).
Yeh, but they don’t score a lot of points with customers by being far off the mark on projections.
Guym,
Depends on the productivity per well, if you focus on the oil completions in the Permian basin, you can find a period where completions were decreasing and output was increasing as prices fell in 2014 and 2015. The vertical completions fell, but those were low productivity wells compared to horizontal completions so even with the fall in the completion rate output continued to increase.
Guym,
As an example, I looked at RRC data from 2015 for Permian output and oil completions (Districts 7C, 8, and 8A), completions were decreasing at 2.4 fewer completions per day (linear trend over Jan to Dec 2015) while output was increasing by 376 b/d each day on average over that period. See chart below.
Currently we may be seeing fewer vertical completions as smaller producers may be having difficulty moving their oil due to lack of pipeline space, the larger oil producers (who are mostly completing horizontal wells with higher average productivity) may not have reduced their completion rate very much, so the decrease in completion rate may not result in a fall in output and might result in the counterintuitive slight increase in output.
I do agree that the rate of increase in Permian basin output is likely to decrease in the coming months, but I think their may continue to be a small increase at perhaps and annual rate of 500 kb/d until new pipeline capacity comes online in the fall of 2019.
If we consider Permian C+C output vs well completion rate from Jan 2015 to Oct 2017 we get the chart below. Notice the increase in output of 480 kb/d in the first 10 months of 2017, with little increase in the well completion rate, possibly better well productivity might explain that finding. The trend for the well completion rate is an increase of 0.6 wells/month each month over the first 10 months of 2017, so basically flat.
There haven’t been many verticals since 2015. Apples and oranges. Do you think well productivity has increased 40% in the past six months??? And, as I said, Permian is not the only output in Texas. Almost a 200 drop in completions from June to Sept. will take a toll on production. At least, on production increases.
Based on the shaleprofile data it looks as if well productivity increased alot in 2016 and 2017 due to longer laterals and increased proppant intensity. 2018 well productivity looks to be trending pretty close to 2017, so the productivity gains from longer lats and increased proppant might have been exhausted by now. Therefore, comparing 2018 well completion numbers to any pre 2017 completion numbers won’t tell you much, but a comparison of 2018 and 2017 numbers should. In the 4 months ending in September 2018 completions grew year over year by almost 70% from 2017, hence the large assumed increase in production in the last four months of 2018. What is interesting though is that it looks like the free lunch from increased lats and proppant looks to be almost over, and any future increases in production must be the result of an increase in completion activity, which should result in some inflation for the service providers going forward. And, according to Schlumberger, if you adjust for the longer lats and increased proppant it actually appears that productivity is starting to trend down (and the increased usage of poor quality in basin sand will likely contribute to this as well)
I think EIA is a little high on monthlies, but not enough to argue with, so let’s use theirs for a comparison. From January to July, Texas production increased approximately 450kbpd. Using RRC production by District, Distrct one through three represented about 120kbpd of that increase, or about 25%. From May to July, that picked up to over 36% of the increase from May to July. That was the biggest bump. Wells from these districts will decline faster than the Permian districts. You can’t rely mostly on Permian statistics. If they cut down statewide, then it will go sideways or down. Eagle Ford, or Austin Chalk wells will have a higher initial output and a higher decline rate than the Permian, in general. And with the threat of $55 to $60 oil, there won’t be much interest.
Most of the analysis that is done on unconventional oil uses data pulled and manipulated by drilling info. EIA and everyone else. It may all be good, but I have some cognitive dissonance with some of the conclusions when compared to RRC data, which is supposed to be the source data. It was bought out months ago from some outfit out of San Francisco. I feel safer with RRC data.
Guym,
You are right I should look at all of Texas. The Permian is interesting though, the vertical completions decreased by quite a bit in 2015, but output in the Permian basin continued to increase. A big fall in Eagle Ford output over that period as horizontal completion rate decreased was the main reason for the fall in overall Texas output in 2015. There has been a bit of increase in Eagle Ford output of late, but it is possible that the lower completion rate for Texas overall is due to Permian oil transportation constraints, if there were any vertical completions before the pipeline constraints became a problem, today there is likely to be fewer. I don’t have a breakdown of vertical vs horizontal completions in the Permian basin.
The TX Permian basin vertical oil rig count has averaged about 33 rigs since Jan 2017 with a range of 27 to 40 rigs.
I take your word for it. Thank you, BTW. You are the only one left on this site that has any common sense regarding shale oil economics and the burden all that massive, massive amount of debt has on running a business where your assets decline at the rate of 28-15% annually. Everybody else seems mesmerized by productivity.
If folks think I am biased (my “parade” was over 20 years ago) look see what Rune Likvern says here: https://www.oilystuffblog.com/single-post/2018/11/01/Cartoon-Of-the-Week.
Mike,
Who are you talking to in the comment above? If you put their name at the start of the comment it would be clearer.
There is a difference between a mature company and a smaller company that is growing. The tight oil industry has grown from producing very little oil to producing 6 Mbo/d (or 2 billion barrels of oil per year) when production stops increasing (2022 to 2025), tight oil companies will be able to reduce debt to zero as fewer wells will be completed so capital spending will decrease.
Boomer suggests debt will not be paid and companies will become bankrupt, this may be correct for the less well run companies, but better companies such as EOG or oil majors will be able to scoop up assets that are desirable at cheap prices and the oil will still be produced. For those investors that chose poorly run companies and lose money, that is the way the investment game has always been played.
Dennis.
Paying the debt off will depend very much on future oil and natural gas prices.
Once growth slows the companies will be companies operating many low volume wells. Investors will want these companies to pay dividends because they will not be in a position to grow. The operating costs will be higher, even though CAPEX will drop.
You are very confident prices will be high in the future. I suspect they will be volatile in the future, as they have been for the past 20 years.
So, on a company by company basis, timing will be critical, IMO.
Shallow sand,
The prices can be thought of as 3 year average prices, yes there will be volatility, my “low price scenario” has Brent Oil Price in 2017 $ never rising above $80/b. I cannot hope to predict the exact oil price and of course oil prices will be volatile, but the average over time allows a pretty good estimate.
Also a company by company model is a little too much work. I just do the industry average, some companies will be better and some worse than average.
It certainly is the case that oil prices have been volatile and I agree this will continue, but the three year trend in prices (centered 3 year average) has been up $7/b for the past year, my expectation is that this trend will continue and the 3 year centered average price will reach $80/b (in 2017$) by 2021 or 2022. The trend of oil prices will be higher, if the peak arrives by 2025 as I expect prices (3 year centered average oil price in 2017$) are likely to reach $100/b by 2024 or 2025.
Dennis.
I think company by company because I have an investment in a private company. I know how important timing is in the upstream industry to individual companies.
Likewise, I understand you aren’t all that interested in individual companies. No problem there.
On the price, I understand why you use different scenarios. However, the average price over the next three years could be $100 or $50 WTI. Pretty much close to what we saw 2011-14 and 2015–17.
I was recently in a major city and saw more Tesla’s than I ever had, including my first Model 3 sighting.
Our little area now has two Model S, with the early adopter trading his 2012 for a 2018.
Shallow sand,
Pretty doubtful it will be $50/b over the next three years, in my opinion. If you believe that you should find another business 🙂 More likely is a gradual increase in oil prices as we approach peak oil, the futures strip is likely to be wrong on oil price (today’s future strip). For Brent futures the current strip goes from $73/b (Jan 2019) to $61 (Dec 2026). By Contrast the EIA’s AEO 2018 reference oil price scenario for Brent crude has the spot price at $87.50/b in 2026, chart below has their scenario (which I think may be too low.)
As always clicking on the chart give a larger view.
Dennis.
The price could be $50 from 2019-2021, and then $125 from 2022-2025. (Averages, of course).
So in that scenario I’d feel pretty bad if I sold out in say 2020.
Your models are ok, I have no problem with you doing them. We try to make a budget for every year.
However, the price is far too volatile to model anything very far into the future, just like we cannot budget past one year, and usually have to make adjustments to that.
Our price has dropped over $10 in less than one month. That makes a huge difference, yet that level of volatility is common and has been for many years.
What oil prices were you modeling in June, 2014 for 2015-17? Our timing was very fortunate to say the least. Many leases bought 1997-2005. Had we bought the same leases 2011-14 for the market prices of 2011-14, we would be bankrupt, absent having hedged everything for four years, which is very difficult to do.
On a flowing barrel basis, I have seen leases sell as low as $2,000 per barrel and as high as $180,000 per barrel in our basin from 1997-2018. That is what an oil price range of $8-140 per barrel will do.
Few companies with zero debt ever go BK. We would with WTI at $30 for about three years. Is that likely? No, but oil did drop below that level in 2016.
Shallow Sand,
The volatility is a big problem, there is no doubt of that. When imagining the “big picture”. I use the estimates of the EIA’s AEO as a starting point then add my personal perspective (that at some point oil output will peak.) Below is a chart with my guess from Dec 2014 for future Brent oil prices in constant 2014$, nominal Brent spot price is give for comparison.
Clearly my guess was not very good, the EIA guess from the AEO 2015 was also not great, but better than my guess. Future guesses will be equally bad.
What was your forecast in Dec 2014 for WTI?
Dennis.
In 2013 we assumed prices in a range of $60-120 WTI moving forward.
In June of 2014 when oil spiked up and we received $99.25 in the field, we suspected oil would fall and it began to. We again continued to assume $60 WTI would be a low.
We were dead wrong, of course.
Oil dropped again today. We will get $67 in the field for October sales paid in November. However, our price today is down to $56.50. That is about a $60,000 per month revenue hit to a small company which employs 8 full time employees, one part time employee office manager and utilized numerous contractors (rigs, electricians, etc.).
Corn here is $3.51 per bushel today. Less than a month ago it was $2.96 per bushel.
Yes, yes, a hedging program would mitigate the price volatility.
Until you actually try to hedge with money at risk, don’t talk to me about that. It’s about as easy as trading stocks. It is also very expensive due to the volatility. Or, if you do SWAPS or Collars, you need to put up a lot of margin money.
Shallow sand,
Hedging seems a risky business, not sure I would come out ahead by hedging. You are in a tough business, the volatility sucks. The silver lining is that prices will be increasing.
Shallow Sand Wrote:
“Paying the debt off will depend very much on future oil and natural gas prices.”
I don’t think so. When energy prices rise, so do prices of everything else, included interest rates. The only way the shale drillers could play off there debt is if the left large number of completed wells untapped (ie leave it in the ground) while taking advantage of cheap debt & low labor\material costs. Then selling the oil when prices & costs have soared above investment costs.
The issue is that as soon as a well is completed, they start producing, at market prices. Thus when oil prices rise most of the oil is already produced & drilling new wells (using more debt) does not pay down the old debt.
Also consider the costs shale drillers will need for decommissioning older\depleted well. I believe the cleanup cost is between $50K & $100K per drill site. To date have any shale drillers spent money on clean up for depleted wells yet, or is it all deferred (ie never going to happen)?
FWIW: I don’t believe any of the shale companies are in game for the long term. They are simply a modern Ponzi scam, taking investor money & providing an illusion of profitabity by selling a product below cost. They will continue to play the game until investor capital dries up.
I suspect that most shale drillers will go bust in the next 5 years when the bulk of their bonds come due & they won’t have the ability to refinance it or pay it off. If I recall correctly Shale drillers will need to payoff or refinance about $270B in high-yield bonds between 2020 & 2022.
Tech guy,
The price of oil can rise faster than the rate of inflation. I do my models in constant dollars, your implicit assumption is that the price of oil in constant dollars remains constant, historically this is not the case.
I surely agree that nobody knows the future price of oil, but if the “real” oil price increases to $80/b or higher in constant 2017$, and “real” well costs remain constant, the debt in the Permian basin can be paid off by around 2025.
As oil peaks I expect the real price of oil will rise to much higher than $80/b in 2017 $, probably more like $120 to $150/b. I would say $120/b+/-20 in 2027 is a reasonable guess for Brent oil prices in 2017 $ (13 month centered average price in June 2027.)
Hi Dennis,
Costs will go up for the Shale Drillers since it takes a lot of fuel to set up a new well. Think of all the transportation costs: Hauling equipement, site, prep, water tankers, and hauling crude to a refiner.
Bottom line, Shale drillers never turned a profit no matter what the price of oil was, They never made a profit even when Oil was around $120 bbl.
“the debt in the Permian basin can be paid off by around 2025. ”
I doubt it. Most of its is “High-yield” debt and interest rates likely to continues until the next recession hits, But when the recession begins, Oil prices will tank again. Its a lose-lose situation no matter which way you look at it.
If oil prices go significantly higher, I assume many of the companies will issue more equity and use it to pay off the debt early, depending, of course, upon the terms of the debt. I assume most, if not all of it may be paid off early by paying a slight premium to the bondholders.
This will dilute the existing shareholders, but the equity should be trading very high if oil prices were to rebound into the $80s+ for a considerable period of time.
Shallow sands,
How much has your average OPEX increased from 1998 to 2018? Or for the last 10 years.
Tech guy,
I assume interest rates are 7.5%, which is probably pretty close to the industry average, if we also assume the EIA’s AEO 2018 Brent reference oil price scenario, a “medium TRR” scenario consistent with USGS estimates for the Permian basin and other reasonable economic assumptions and also assume that new well EUR starts to decrease in Jan 2023 as sweet spots get fully drilled up we get scenario below. Debt paid back in 2027 and cumulative net revenue goes to 150 billion in 2017$ by 2032. Click on chart for larger view.
Dennis, thank you for the lecture. The price of oil for all shale oil producers, save the biggest in the Eagle Ford getting paid on a WTI-LLS differential, is in the mid to low $50’s, a long way from your predictions of $80. Growth is nevertheless occurring for the same reason it always has…credit. I am sorry you don’t get that.
Major integrated oil companies will do not better in this shale shit then independents; in fact worse. They will not ‘scoop’ up 20 BOPD wells making 100 BWPD, declining 12% annually and headed for economic limits.
Some companies will survive, of course. This is not an investment sight, I thought, and we were discussing the health and well being of an entire sub-industry and its ability to meet its promises to the American people about our nations hydrocarbon future.
You have no clue whatsoever whether the US shale oil phenomena will be able to pay its debt down. You are guessing. And poorly, I might add.
The investment “game,” as you like to describe it, does not pertain to the shale phenomena. In that scheme, nobody has anything to lose, and everything to gain. Its all other people’s money and that fake “money” is taking away from our future, and our children’s future in the form of debt. Lenders are chasing yields, with government money; when nobody loses there is no “investment.” I am sorry you do not get that either.
Assuming hydrocarbon prices will rise based on high school level supply and demand theories, in the debt ridden, turbulent world we live in today, and fix all this mess is ridiculous.
Hi Mike,
Thanks for your lecture.
Supply and demand ultimately will determine prices, there can be short term fluctuations above and below the equilibrium price because stock levels can rise and fall, they cannot fall below the level needed to fill the pipelines though, that amount is essentially a zero level of stocks. I am using the Brent Oil price which is the de facto World Oil price (or it is what the EIA believes is the best choice). The spreads between Brent and he shale oil producers will fluctuate and will vary basin to basin, that is included in my model as transportation cost. The larger shale producers in the Permian basin will have pipeline space locked up to ship their oil at reasonable prices, only the small producers are getting hit with the low oil prices in the Permian.
In the long run the pipeline capacity will increase and the spreads will drop back to normal level in my opinion.
The publicly traded oil companies have stockholders that “invest” in those companies. The publicly traded investment firms and banks that buy the bonds and lend the money (for revolving credit lines and loans) to shale oil companies also have stock holders that invest in those companies. The companies that do a poor job of allocating capital will see the share price of their companies decrease as the poor allocation of capital becomes apparent. Either their behavior will change or the price of the stock will go to zero.
It is simply the way capitalism works.
As to the hydrocarbon future, my expectation is that oil output will peak and decline, I have been pretty consistent on that point.
An economic analysis with a very reasonable oil price scenario suggests the Permian basin oil companies as a group should be able to pay their debt. Low price scenario below has well head price at $73/b in 2017 $ in Jan 2020 with a maximum of $76/b in 2022 (price remains at that level until 2040. Well cost $9.5 million in 2017$, nominal discount rate of 9.5%. Nominal interest rate 7.5%.
Dennis, that is all just conjecture. Theory. In the safety of your own home, with nothing vested in this theory, it may make perfect sense to you. Out here, in the real world, its just wild ass, meaningless guesses. And confusing ones at that.
Learn which end of a work over rig to walk to, get a few blisters on your hands, lay awake hours every night worrying about making payroll, paying vendors, why one well is watering out so quickly and another is not pumping and what to do about it, what the price of oil actually IS and not what you think it will be in five years,…you’ll change your safe, cushy “theories” real fast. Some working interest in about a half dozen shale oil wells will change your entire outlook on life, promise you.
Mike,
Agreed, it is a simple model following the work of Rune Likvern, Paul Pukite, Enno Peters and others. For the Permian basin the economics can work, if my assumptions prove accurate. You are correct that I am guessing based on the estimates of the USGS, David Hughes, and the well economics that I have learned from you, Shallow Sand, and Fernando Leanme.
Current assumptions:
oil price in 2017 $ for Brent rises to $80/b by Feb 2027 and then remains at that level, transport cost $4/b, royalty and taxes 32%, nominal annual discount rate 9.5%, nominal annual interest rate 7.4% (for both the previous rates an annual inflation rate of 2.5% is assumed), OPEX (including G&A) is 2.3 times monthly barrels produced plus $15,000 per well each month (this last is based on Rune Likvern’s work on the Bakken, may not apply to Permian). A discounted cash flow in real (or constant) dollars for each well completed is done, Only wells with positive discounted net revenue over the life of the well are assumed to be completed based on assumed oil price scenario and fixed transport cost, well cost, royalties and taxes, interest rate, and discount rate ( all done in constant dollars). Well is shut in if net revenue is negative. OPEX for the average 2016 Permian well in 2017$/month/well in chart below. Wells get shut in at about 7 bo/d in this model, I also assume no revenue for natural gas as many producers are flaring all they are allowed so I assume associated natural gas revenue is marginal.
Click on chart for larger view.
Note that I agree with Mike that low oil prices “forever” will mean that the LTO industry will never be profitable. Neither Mike nor I know what future oil prices will be. The EIA’s low oil price scenario or even the average of the low and reference price scenarios from AEO 2018 would result in negative cumulative net revenue from now until 2080.
Mike thinks the low oil price scenario (or something less than the AEO reference oil price scenario) is the more likely case, I think peak oil in 2025 (or sooner) will lead to higher oil prices, close to the AEO reference case and perhaps higher.
>Supply and demand ultimately will determine prices
This is actually a doubtful claim — an empty platitude. “Ultimately” means in the long term, I guess, and as Keynes pointed out in the long term we will all be dead.
In the mean time oil is subject to wild swings in price that have little of nothing to do with the quantity available or the quantity required (or desired). For example prices skyrocketed in 2001-2003, although there was no significant change in the quantities involved.
Oil is subject to wild price swings because production costs are so much lower than the value to customers. For example, European markets chug along just fine paying $8 a gallon for gas, so “ultimately” $200 oil is probably no problem — the stuff is really useful to have around.
Needless to say, production costs are much lower. So what determines the price in the gap? Psychology. Panic about Republican war plans in the Mideast drove up prices in 2001. Financial panic drove them down in 2009. I suspect that numbness to political chaos in the Mideast ultimately brought the prices down to $30.
As long as there is so much “play” in the market, by which I mean difference between what consumers would pay in a pinch and what producers will accept in a pinch, it makes no sense to try to attribute price changes to quantities produced and consumed.
In a completely separate rant, I’d like to point out that you are confusing supply and demand with supply quantity and demand quantity. Demand is the amount of money consumers spend on a product, and it is significantly down since 2009.
The bottom line is that a lot less money is being spent on oil than was a few years ago. It’s the money, if anything, that determines the price, not the quantity. That’s just basic economics.
Supply and demand will probably determine prices, or at least average price over a long enough period, but prices don’t necessarily determine supply and demand given the long lead times for many projects and the inelastic response of a lot of oil use (and for LTO there appears to be a very tenuous connection at best).
George,
I agree in the short and medium term, but in the long term (more than 5 years), I think prices do influence both the amount of oil consumed and the amount of oil produced, there are very large lags in the system.
There is so much slack (waste) in the US, if the American consumer ever woke up to the unneeded extra costs put upon them they could crush the credit card, auto industry and the oil industry in short order. Demand here is propped up by extremely poor spending habits.
The real estate industry and home heating need a shakeup too.
The electric power industry is in for a rude awakening. They are already squirming.
Gone fishing,
I agree. This will become more apparent as fossil fuel prices rise and costs of alternatives continue to fall. The low fossil fuel prices in the US result in low incentives for people to make changes.
There is a ton of waste in the US energy system (and economic system).
Alimbiquated,
Correct I should use quantity of supply and quantity of demand. Often “supply” and “demand” are used as a shorthand. Quantity of supply equal to quantity of demand is a tautology, price will be determined by many factors including the expectations of market participants which depends upon psychology.
Consider the following thought experiment:
Let’s say actual quantities of C+C produced at $50/b for an average annual price is 30 Gb and let us also assume World stock levels are at “normal” levels and have been stable for the past 2 years. Over the next year the quantity of oil consumed increases to 31 Gb while production remains at 30 Gb (the extra consumption caused a stock decrease of 1 Gb over the course of the year).
Does the price of oil remain at $50/b (assume no new wars or recessions, start or end over the period under consideration)?
Dennis,
My claim is that the price would primarily depend on expectations of future supply and demand, which is obvious, I guess.
I read through your thought experiment, but I don’t see any indication of “play” in the market, which is what I am claiming exists. You postulate the oil price is $50/b, but what are production costs? $10/b? $100/b? This will obviously have some impact on prices.
And how much is the oil really worth to consumers? My claim was $200 in a low tax regime like currently in the US and China. I think that because cars and trucks are hugely useful, and because consumers in a high tax areas already pay the equivalent.
So I see no reason why prices should not get much higher than $50/b in your scenario. But I can imagine them falling as well. $30 oil didn’t stop companies from increasing production.
I think the American oil industry and the Republicans have been talking down the price of oil in recent years by bragging about “Saudi America” and the miracle of fracking.
The Republicans a deeply conflicted about what the price should be, sometimes blaming the Arabs for waging a price war to ruin the US industry, and sometimes bragging that America is the new OPEC. But the net effect of all the noise they have made has been to give people confidence that oil will be cheap for years to come. Wall Street seems convinced that there is a miracle happening anyway. Peak oil bashing is part of that.
That coupled with growing indifference to political crises in the Mideast following the Arab Spring are the biggest psychological factors currently. There are too many conflicts going on for non-experts to keep track of any more, and no clear good guys and bad guys for the media to hype.
I think something extraordinary would have to happen to get prices back near $100, like a huge war — maybe a Russian civil war, god forbid. I think it’s getting harder and harder for people to imagine an oil crisis. Hype about electric cars are a factor as well.
Alim- “And how much is the oil really worth to consumers? My claim was $200 in a low tax regime like currently in the US and China. I think that because cars and trucks are hugely useful”
I agree you on this, with one very big exception that is/will change the rules on this, and that being electric vehicles.
If oil is over $100 barrel for an extended time, the business and consumer push to electrify their transport needs will be strong and swift. The cost savings/mile will be very large. Each yr that goes by, the viability and options for EV’s grows, from bikes to trucks.
If you went to sleep for a decade, you would be shocked by the transition that has occurred, IMHO.
Its a matter of time(ing). If oil was over $100 for 5 yrs say, that is enough time for the economics to sink in and start to heavily influence to flow of money towards electrification.
Electrification is not all-or-none.
I have a plug-in hybrid van (made in USA and it is an excellent vehicle) for example. It goes about 30 miles on electricity, and can go another 360 on a full tank of gas. Since I’ve had it, just over 2/3rds of my miles driven have been electric (charged by solar on the roof), and 1/3rd gasoline. Future versions of this type of vehicle will likely have a bigger battery component that can go 60 miles on electricity. And perhaps someday, all electric. Most new vehicles in 5 yrs will be some degree of electric hybrid.
Ford, for example, is planning swift electrification of its fleet-
https://www.reuters.com/article/us-autoshow-detroit-ford-motor/ford-plans-11-billion-investment-40-electrified-vehicles-by-2022-idUSKBN1F30YZ
Alimbiquated,
Of course there is play in the market, that is pretty obvious by looking at the historical price of oil (daily average spot price). Much of this movement is due to speculation by oil traders and their expectation of future oil prices. I think we agree on that point. The longer term oil price (say the 25 month centered moving average) will be determined more by economic fundamentals. If we assume in the short term (one to two years) production cost for the marginal (most expensive) barrel changes very little and that in my thought experiment the oil produced is equal to the oil consumed (because we have assumed stock levels are unchanged), then an increase in consumption to say 30.3 Gb (about a 1% increase which is the typical annual increase in C+C consumption lately) suggests oil price should increase since those 0.3 Gb of extra oil should be more expensive to produce and a rational oil company will not be willing to produce those barrels at a loss.
Running out of thread here, so I’ll try to kill two birds with one stone:
Dennis:
I think the only real difference between our positions is how much play we see in the market. But it’s anyone’s guess!
Hickory: I think you’re right that EVs will make oil seem expensive in a few years. It won’t really happen until battery supply starts catching up with demand, but then there will a a big bang (I boldly predict).
Both: EVs are reducing the play in the oil market.
So will 553 completions be enough to maintain production?
Lightsout,
It depends where the completions were and how productive those wells are, there are some completions that are vertical wells, not sure how many. Enno Peters has 295 horizontal oil wells completed in the Texas part of the Permian basin in April 2018, RRC has all Permian oil completions for TX Permian at 446 oil wells, which implies about 151 vertical oil wells were completed in April 2018. In June 2018 521 oil wells were completed in the Texas Permian basin, if we assume 150 of those wells were vertical wells, that would be 371 horizontal wells. In Sept lets guess only 50 vertical oil wells were completed, that implies about 309 horizontal wells were completed in Sept (62 fewer than June).
If I adjust my Permian model to reduce well completions by 60 from June to Sept and then assume the Sept rate continues until Dec 2018, Permian output continues to rise, but slowly (only increases by 55 kb/d from Sept 2018 to Dec 2018 or about 18 kb/d on average each month for the last 3 months of the year.)
Here in south Germany gas prices are now at 1.60€ / litre.
The water level in Rhein is still very low, so the tankers doesn’t come through. National reserve is tapped, and every truck that can transport gas does this around the clock.
EV drivers must be happy they bought an EV now!
Has this been a problem in the past?
Last summer similar dry was 2003 – and there the dry time was much shorter. I think it’s unique, at least you have to dig very deep in the past where oil consumption was on another level than now.
There was some rain last week, but not enough.
The next 2 weeks zero again according to the forecast. So the situation continues.
My cousin is on a boat ride up the romantic Rhine that she booked six months ago. It isn’t going well.
Global Vehicle miles traveled will grow by 60% in 2040
https://www.businesswire.com/news/home/20171113006466/en/Future-Cars-2040-Miles-Traveled-Soar-Sales
Since 2000 VMT has grown from 5 trillion miles to approximately 7 trillion miles. Since hybrid vehicles get all their power from diesel or petrol they will not reduce global oil demand because the increase in vehicle miles will overwhelm any efficiencies.
http://www.ev-volumes.com/country/total-world-plug-in-vehicle-volumes/
This year the world has 96,000,000 more petrol and diesel vehicles trundling along the roads of India, China and practically everywhere else.
Fully electric vehicles are the only solution and the Hyundai Kona electric is the best for me in terms of cost and range.
https://www.autocar.co.uk/car-review/hyundai/kona-electric/first-drives/hyundai-kona-electric-64kwh-premium-se-2018-uk-review
In US $ that is about 41 k, very nice, though I wonder about 300 miles of range at 64 kWhr. The US EPA range is 258 miles for the Kona, so that would be comparable to the 45k Tesla Model 3, though many prefer the SUV form factor over the sedan. Note that the Kona receives a government subsidy of about 4500 US$, if we assume the Tesla Model 3 is also eligible, the comparable price for the Model 3 “midrange” model is similar to the Kona at about 41.5k USD after incentives with similar range of 260 miles (EPA rating).
Also note that the Tesla range is quite conservative, at 10 C and slow speeds (80 km/hr) for the 310 mile range (EPA rating) Model 3 I get about 390 miles of range (dry roads).
The BBC analysed several electric car models for range, the Kona was closest to the advertised range. I think 270-280 miles.
You get 390 miles?
Hugo,
Only at slower speeds 60-80 km/hr, at motorway speeds more like 295 miles (or 472 km) at about 105 km/hr, faster speeds reduce range. Cold winter temps (-10 to 0 C) will likely reduce range, have only had the car a few weeks, I will update as I get more information. Over about 2700 km, I have averaged 241 Whr/mile or 150.6 Whr/km, the battery is 78 kWhr so about 324 miles (518 km) of range on a full charge, realistically one does not run it to zero, so probably 95% of this (308 miles or 492 km) would be the range.
Dennis
Keep us up to date. What State do you live in? Does it get that cold?
https://electronics.stackexchange.com/questions/263036/why-charging-li-ion-batteries-in-cold-temperatures-would-harm-them
Gonefishing,
Tesla has pretty sophisticated battery management. When you plug in to charge the battery is gradually warmed to a safe temperature before charging begins. The car would probably not do well in Alaska or Northern Canada.
Hugo,
Yes. Average temperature in January is about -8 C (17 F).
Dennis
It will be interesting to see the range you get this winter.
Some owners in colder areas have real problems.
https://teslamotorsclub.com/tmc/threads/lousy-range-cold-weather.105476/
I did wonder why so many second hand Nissan leafs are for sale that are only a year old. The owners were very disappointing with it’s winter range.
http://sam-koblenski.blogspot.com/2013/08/a-year-and-half-with-nissan-leaf-part-3.html
The newer more powerful battery will obviously have improved performance.
Hugo,
Will let you know. There are a number of tricks to improve range, but very cold weather is indeed a problem (January where I live).
Wood stove addition. Install every winter.
🙂
@GoneFishing:
Do it right, drive with bio fuel:
https://der-siebte-sprung.de/holzvergaser/
Gonefishing,
I had not though of the wood stove trick 🙂
I was thinking of charging the battery just before leaving for work, so the battery is warm and heating the interior a bit while still plugged in, no plug at work so the efficiency on the ride home will not be good, but only 10 miles or so, so range won’t be an issue. For 10 months of the year this won’t be a problem, but Jan and Feb could be difficult, I will let you know.
Short motorway trip (210 km) at about -2C (28 F) resulted in about 15% higher energy consumption compared to an earlier trip at 13 C (55F). If the relationship is linear we may see a 30% hit at winter temps (-17 C) relative to 13 C (spring/autumn temperature where I live). I will let you know as I get more data, this last data point my wife was not warmly dressed, so more heat than perhaps necessary. In the winter we will dress warmly and only heat enough to keep winshield clear, if my partner allows.
While driving away from home you could preheat while the car is still at the tap – has it a timer heating you can program, perhaps even with the smartphone?
Only for driving back revolution in the car is programmed, then.
I remember – my first car was the VW Buss (the classic hippie van).
Driving in the winter with this mobile was special – the heating was going from the motor in the back all under the car to the front – and it liked to rust faster than your possiblity to buy and install spare parts.
So dime-sized holes in a frozen wind shield where the normal, gloves while driving have proved useful.
And it used gas like a modern pickup truck – in town 16-20 liter / 100 km.
Yes I preheated at home (to about 20 C), but at -2 C outside at night the car cools down pretty quickly so it helps a bit, but not as much as I had hoped over a 2 hour round trip, with a stop for dinner in between.
No timer for heating, only for charging, but there is a smartphone app that lets me turn on the heat before leaving without having to go out to do it, so yes heat it up while plugged in can help. We need to dress warmly, use seat heaters, mittens, hats, warm boots, etc. Blanket on lap would help because front of thighs gets cold.
It will be interesting to see how the Kona will stack up against the Bolt, in price and reviews.
They are extremely close in specs, and early reviews give them both very good marks.
https://pushevs.com/2018/06/27/chevrolet-bolt-ev-vs-hyundai-kona-electric/
The Kona is great. It takes at least 1.5 years to get in Norway subscribing to a waiting list. The battery capacity is just too good for middle of the range priced electric car. What is wrong with all the propoganda we are fed these days. I say, as I have done for some time, we are going to have a crisis long due, most likley autumn 2019 or into 2020. When is the question – well if the oil price is subdued the crisis is subduded (they way I think).
Am I the only one calling this bullshit? Exaggerated EIA data, with questionable production and import numbers. The US imports according to EIA are about 1 millon barrels/d lower than the data according to some of the tanker tracker numbers for a few weeks now. If OPEC (KSA) join forces with the US then this happens, and what next? I speak for deaf ears, so I better stop. But this low oil price environment is never going to last. Norway and Brazil production disappointment just maintenance and noice. Demand is going to go down, even if the price is low. The whole thing is just ridiculous, quote me on that when it all comes falling down.
The data I got to bring is OPEC with increased production last month (anyone surprised?) https://uk.reuters.com/article/oil-opec-survey/table-opec-oil-output-rises-by-390000-bpd-in-october-reuters-survey-idUKL8N1XB3C4. Still the latest EXPORT numbers from OPEC are a complete reversal. Seems like the Khashoggi pressure didn’t work as well as intended (It sure worked for a while though).
I think it is really silly, nobody is interested. In a few months everybody is onboard. It is how psychology works, mass media and confirmation bias at bay. Pretty much defines the bottom of the oil price for now. No need to comment for some time.
EIA monthly output data is not bad. The stock numbers and such are not great and it is World stock levels that matter and the best data on that is from the IEA (still not very good). I agree oil prices will rise, hard to know when the market realizes that supplies are short, maybe in May or June 2019. OPEC and Russia seem to be producing full tilt, doubtful US output will increase enough to fill the gap.
I have a confidence problem when it comes to EIA if not the monthly output shows some weakness soon. The weekly figures are all over the place, and I don’t think they are very good. Still think the underreporting of imports and overreporting production from the weeklies are real and somewhat political; interesting to see if reporting change after midterm. I am just born sceptical and even more so when I learned that Trump likes to cheat during golf rounds (and I don’t even like to be cruel or tease anyone in any way).
Agree weekly data is not very accurate and much of the import and export data will be based on that. The monthly import export numbers are a little better for the EIA, but I focus on the output data, I figure the oil will move to where they can get the most money per barrel as it is all about profit.
K, I am not sure how all of this will unravel, or when. I tend to think, in time, it will be about mid year 2019, as Dennis says. EIA and IEA will rock along with the Permian song, until it is apparent, we are screwed. They have to, the alternative is panic, rising oil prices, damage to economies, etc. They can’t afford to be the one who says, “what clothes? The emperor is buck naked!”. I think the rationale for the “deception” is more fear than politics. What has me really curious, is what the “spin” is going to be when it does unravel. I tend to think it will just be more lyrics to the Permian song. Anything else, would be like absorbing the concept that the sun rises in the west.
Guym,
We are roughly on the same page as far as the Permian, output may go up a little, especially when there is more pipeline capacity, but the increase will be much less than forecast by some. Note that the EIA’s AEO 2018 actually has lower output than my “medium TRR and medium oil price” Permian basin scenario. Their “reference scenario” has unrealistically low oil prices which might be part of the reason, also it was written about a year ago, where I constantly update my scenarios as I get new information on output, well profiles, etc.
I would think that with a threat of less than $60 oil, it would go slightly down first, before climbing back up to what it is now. But, that’s just me. I’m not running these idiotic operations. If they overproduce at $60 oil, those Permian producers may getting a little over $40 a barrel with discounts. Or, shoot yourself in the foot with a shotgun. Discounts have dropped substantially since August, which is an indication production might be down, along with other RRC data. I’m guessing August is a high, and down somewhat from there.
“We lack resistance to the present.”
— Deleuze & Guattari
Guym,
If they are at capacity for pipeline and rail, then flat output would make sense, but sometimes these operations seem not to make sense. Maybe conventional output will decrease as much of this is from smaller producers who get lower prices for their oil.
Debt address.
Restrucure.
Equity conversion.
If you are a shale company and you owe money you cannot repay, you negotiate with the lender for better terms. It all comes down to the principal. Better terms might be covenant relaxation, change of payment schedule, or change of interest rate. All of those are pretty mild. A reduction in principal is hard to make happen, unless someone reimburses the lender in an obfuscated way, as obfuscated as possible.
If money had been borrowed from Exxon, the restructure might include an equity position in the shale company, though that requires Exxon to desire an equity position in a company that cannot pay its debts. That’s not impossible.
So once again, do not forget that if you have to have the oil, and you do have to have the oil, shale company indebtedness will not prevent that oil from flowing. Whatever must be done will be done.
But right now, how much of that LTO do we need? The faster we get it out, the lower the price of oil, and then the faster the depletion.
Facilitating more fracking with favorable terms makes no more sense to me than paying farmers to produce more food than is needed.
There is no money to be made from telling the truth in this instance.
In fact, for most of the interested parties, there is money to be made through lying, as Watcher implies.
Hence, no one tells the truth.
Since only a tiny percentage of us know that A) oil is finite and B) believe we are reaching an inflection point (and that tiny percentage includes, in my estimation, LTO drillers, who know and chose to lie), those selling LTO can lie with impunity. The concepts we bat around on this site- inelasticity of demand for oil, the differences in production costs for different types of oil, and the use of debt financing for LTO, to name what I think are the most important ones- are not mainstream at all.
To not facilitate more fracking would strand the LTO debt and let the cat out of the proverbial bag. The bankers and drillers will ride this one into the swamp, because one more year being paid $10 million bucks a year is one more year being paid $10 million bucks a year. (Maybe Mike has more accurate pay figures for LTO CEOs and Bankers. 🙂 )
To not facilitate more fracking would strand the LTO debt and let the cat out of the proverbial bag.
Bingo!
We have a winner—-
Some of you newer folks might not have been here too see it happen (assuming it really did happen) but there was a story, in ZH as I recall, that quoted the usual unnamed sources as having knowledge that the Dallas Fed had instructed local lenders to find ways to continue financing shale oil, despite the reality that the numbers could not support it. The price of oil at that time was about $40.
This was a pretty obscure subject, and not one that would typically achieve a worthiness of Zero Hedge. Now, the bar for ZH is not all that high, but at that time no one could see how those companies could remain solvent. The investing public had bigger fish to fry and largely didn’t care.
The point of this reminder is to note there is some precedent for finding ways to excuse all that debt.
It all boils down to this. What looks better a US economy carrying debt but producing 11mbopd or a US economy with less debt but producing 5 mbopd. Clearly the guys with their hands on the leavers of power have decided.
True, and we do make similar debt decisions throughout the economy. Superficially looks good, throw more wood on the fire so to speak. But the debt load is huge, as if you already cut down most of the forest (future growth and stability).
Those who are comfortable with highly leveraged fast growth, rather than slow, solid growth,
I ask you how you’ll feel about your asset pile when we go through massive dollar devaluation to ‘rationalize’ the debt? I’m pretty certain this will happen at a most inopportune time.
Hickory
I think we need to embrace the horror there will never again be slow solid growth.
I was being optimistic, for the fragile reader among us.
Lloyd, I agree with you, 5 X 5. Here is a good site to play with regarding salaries and compensations, https://www.salary.com/personal/executive-salaries/ Remember the shale industry is trying to clean up its “act” with regard to reserve base performance compensation packages for upper management, but that has only really happened in the past year or so. Previously, while debt was being kicked down the road, shareholders were losing their asses and EUR’s were (are) being grossly exaggerated, CEO’s were making a killing and are now home free now. Set for life. With nothing to lose if debt is not paid back. Bankers, I have no idea; there are brokerage houses that put lenders and borrowers together in CAPEX funding and M&A stuff that make enormous fees.
These sort of guys are sitting pretty, in the middle of a great distribution of wealth from the government (printed money creating more debt for our kids to cope with) to the shale industry to extract cheaper gasoline, jet fuel and fuel oil for the public. What a deal. What a big deal if all that debt just disappears, like Watcher thinks. That, I believe, would infuriate the American public, regardless of economic benefit.
Here is a good site to play with regarding salaries and compensations, https://www.salary.com/personal/executive-salaries/
Thanks, Mike! This is a cool toy. Now we type in Harold Hamm. We get a disambiguation page that makes us specify Harold G. Hamm, and then we get:
Harold G. Hamm
Executive Compensation
As Chairman of the Board and Chief Executive Officer at CONTINENTAL RESOURCES INC, Harold G. Hamm made $12,269,399 in total compensation. Of this total $1,210,589 was received as a salary, $3,404,829 was received as a bonus, $0 was received in stock options, $7,593,904 was awarded as stock and $60,077 came from other types of compensation. This information is according to proxy statements filed for the 2017 fiscal year. Bolding mine.
So I was in the right ball park.
Of course, $7.5 million of that is in junk stocks…nonetheless, $4.5 million a year is still well above food stamps.
A quick side question that came out of looking at Hamm’s compensation: he owns or controls 75% of Continental Resources stock.
Are most shale oil firms as narrowly held?
No. Very few are.
Hamm started out by driving a tank truck in the 1960s and grew his company from that.
It looks like another ultra deepwater project in the Gom is going to disappoint. Shell has taken $500+ million impairment on the Stones FPSO. It had a slow start-up and poor availability since, has so far not achieved it’s nameplate of 40 kpbd, and there are indications it may be declining with drilling operations now seeming to have stopped. It was originally a lease from SBM but Shell exercised an option to buy it, and then took it off station for three months. The issues look like a combination of reservoir performance and production system reliability.
1969 — High Seas: Hull of the ship Keo fails off the Massachusetts coast, spilling 8,820,000 gallons of oil in the Atlantic
They say fish oil is good for you.
Weekly inventories – it’s difficult to know what is happening without subscription data for floating stocks but someone somewhere usually mentions them…
2018-11-05 (SEB Bank) Weekly stock data for US + EU + Sing + Floating (table 1 below) have declined strongly over the past three weeks and are now down 40 m bl year to date.
Table & chart on this web page: http://ravarumarknaden.se/towards-the-end-of-the-sell-off-no-business-below-usd-70-bl/
Last week (Argus) – Oil product stocks held in independent storage within the Amsterdam-Rotterdam-Antwerp (ARA) trading hub fell by 2.6pc from a week earlier to a nine-week low of 5.3 millon tonnes, prompted by falling stocks of all recorded products.
An update on Nigerian oil production
2018-10-29 (Rystad Energy) Considerable investments needed to maintain Nigeria’s production levels
Nigeria’s oil production is expected to remain stable in the short to medium term, with new projects offsetting the decline from mature fields.
https://www.rystadenergy.com/newsevents/news/newsletters/EandP/eandp-newsletter-october-2018/
Some Canadian heavy oil is being shut in due to low prices but the integrated companies don’t see those prices…
CALGARY HERALD Updated: November 1, 2018
On a conference call, Suncor CEO Steve Williams stressed his company has minimal exposure to widening differentials with ample processing capacity and pipeline access.
.
Canadian Natural Resources — led by chairman Murray Edwards — reduced its heavy oil drilling and expects to shut in between 45,000 and 55,000 barrels of oil per day in November and December.
https://calgaryherald.com/business/energy/varcoe-big-deal-for-encana-canadas-biggest-producer-urges-province-to-regulate-oil-output
Thank you, I asked about this issue in a pervious thread and all who replied wrote that this would not happen. I still wonder if shutting in production will have any major affect on Canadian output (or growth in the next year). How much needs to get shut in to get the diff down to $20-25? I don´t expect it to get down to $15 or so before new pipelines comes online.
I don’t know enough to have an informed opinion, I’m only looking at what happened last time.
Yes it would be interesting to know how high production is above transport capacity. The EIA and Statistics Canada often give different numbers for rail transport so I gave up trying to work it out.
Unusually high number of PADD2 refineries offline, coming back soon
Chart: ScotiaBank & Bloomberg https://pbs.twimg.com/media/DrSaLRMUwAAsbOC.jpg
According to the Oil Sands Magazine, Alberta storage capacity is 78 million barrels (up from 75) I guess that it’s nearly full
Link https://www.oilsandsmagazine.com/projects/crude-oil-storage-terminals
Inventory build in August 2018 m/m was +6.6 million barrels, or +214 kb/day
Average monthly build over the last 12 months, +44 kb/day
https://pbs.twimg.com/media/DoQBp5eWsAAJD4K.jpg
(still waiting for AER September numbers)
2018-11-06 (EIA STEO) Even though total U.S. refinery utilization was about average for this time of year, it was particularly low in the Midwest, Petroleum Administration for Defense District (PADD) 2. Four-week average refinery utilization for the week ending October 26 was 73%, which, if confirmed in EIA’s monthly data, would be the lowest utilization rate in the region for any month in EIA data back to 1985.
https://www.eia.gov/outlooks/steo/marketreview/crude.php
Oilprice.com is running an article devoted to peak oil demand. It claims that only the developing world is increasing oil consumption. There is all sorts of talk about alternative energy this and that, and quotes of reports and studies that seem to have been issued by organizations of significant partiality aka renewables wackos.
The US oil consumption has not yet returned to pre-crisis levels, but it’s almost there and probably will get there this year, according to the bible. I don’t know why this article appeared. It seems to be compilation of wishful thinking.
This delay in getting back to the 2007 level would seem much more clearly a consequence of pretended economic recovery derived from that instrument of capitalism purity known as QE, rather than substitution for oil, primarily as evidenced by what appears to be consumption reaching the 2007 level this year. If there were relentless decline, it would be relentless, yes?
“If there were relentless decline, it would be relentless, yes?”
Classic!
2007 will be a tough reach. 3ish% increase. The overall point is increases have been consistent the last 6 yrs. No idea why the article suggests the developed world isn’t increasing.
2018-11-06 (ClipperData) Europe’s imports of US crude oil, up to October
Chart: https://pbs.twimg.com/media/DrUZl5dWwAIw6Gr.jpg
So, it appears group think is now running along the lines of Goldman’s latest brilliance. That is, production will be up next year due to US and OPEC increases. Which will pull prices down. I suppose you can make an argument of that based upon current numbers. Consequently, WTI is down to $62. Perfect storm developing.
It’s all ok.
Everybody reading financial newspapers knows LTO can be produced for 30$/barrel with positive earnings, and is an endless bonanza.
Let’s see how the tightening of the FED plays out. On the longer time, easy credit to drill dry holes or to buyback stocks (or do other useless things) will dry out gradually. After 10 years of easy money it could come like a dealer strike to drug addicted.
If they don’t change it soon, this will be the most important chart for the big business and LTO:
https://www.investopedia.com/insights/how-will-fed-reduce-balance-sheet/
Not a great article. Smells like it has some politics in it.
QE stopped. That was monetary stimulus. The deficit is now growing. $1T this FY will equate to 4.8% of GDP. This is fiscal stimulus.
This ain’t capitalism. If you are injecting 4.8% of GDP into the economy from govt spending excess over revs — and can manage only 3% GDP growth with that extra money coming in (from non capitalism mechanism) — then what the hell is wrong?
What’s wrong is capitalism failed in 2008 and the Obama years . . . errr, Bernanke years . . . didn’t resurrect it.
So will LTO be denied credit by rising rates? No.
The Fed’s own dot chart says growth will slow next year (when did we EVER see the Fed project slowing growth in the future?). If growth slows, no real reason for rates to rise, though this can fuzz up via position on the yield curve.
The most important thing to know about this from LTO’s perspective is that the Fed itself HAS OVERTLY SAID that this is new territory. They have no idea how the system will behave from the QE injection over a decade and now thoughts of “normalizing”. Fed Governors have made speeches urging people to realize that this is guesswork. They don’t know how it will work out. They will just go on making policy as if it’s based in solid understanding, and it’s not.
(Oh, one more thing. The gasps of horror at the suggestion that govt might interfere with an independent central bank like the Fed — y’all do realize there is nothing in the US Constitution that says the Fed must operate independently? There is no law of the universe that says this must be so. There is only orchestrated outrage (globally, not just the US) when a govt asserts some control. One wonders who started the outrage.)
Guym,
Reading at Oil Price, they suggest a 400 kb/d increase in tight oil output in August, possibly based on the poorly done DPR, actual EIA estimate for August tight oil output increase is 86 kb/d and for the past 6 months the average monthly increase has been 82 kb/d, I agree with you that this rate will slow down in the months ahead due to lower prices and Permian pipeline woes, maybe something closer to the Sept increase of 46 kb/d (or perhaps less) until Sept 2019.
As you expect, the shale cheerleading may lead to disappointment, continued falls in Venezeulan and perhaps Canadian output and robust economic growth may lead to eventual short supply. We need increases of about 800 kb/d annually (based on 1982 to 2017 C+C output history), OPEC is at it’s max, so is Russia and many nations have declining output (Mexico, China, UK, Venezuela, to name a few), US LTO increase of perhaps 600 kb/d over the Sept 2018 to Aug 2019 time frame will not get the job done. The World may finally get the message by May or June 2019.
Yeah, it had a chance to increase based on other shales than the Permian. It’s budget time for all calendar year companies, now. No impetus for much of a 2019 increase based on $62 oil. If Permian players push it, the discount could give them $45 oil. I do not see an 800k increase until maybe later in the fourth quarter. But, really I expect little to no increase the first half, so 800k would be pushing it. OPEC is NOT interested in increasing production to lower prices. That’s an inane supposition. Yeah, June or July.
I keep forgetting about the one pipeline oil addition to Cushing. Started Nov 1. Supposed to be operating at 300k to 350k of its max of 500k. There is a discount to Cushing, and an additional discount to MEH at the Gulf, so not much better off as far as discounts to MEH, just an outlet for excess. I have no idea if this will motivate more production, but completions per the RRC are back up to around 900 for Oct. The part I don’t know, are how many of those “completions” are actually completions that report shut in production, or Ducs. I know there are a bunch of ducs in the Eagle Ford by Marathon and XTO.
Canada, Alberta AER, Total Crude Oil and Equivalent Production at 3,438 thousand barrels per day in September, down -292 kb/day month/month
Up +254 kb/day from the average during 2017 which was 3,184 kb/day
Chart: https://pbs.twimg.com/media/DrWh2IBXgAAn7su.jpg
Upgraded down -245 kb/day month/month
Non-upgraded -46 kb/day month/month
Crude Oil + Condensate +3 kb/day month/month
https://pbs.twimg.com/media/DrWifgtWoAcY0-m.jpg
Canada, Alberta AER, crude oil closing stocks at 75,250 thousand barrels in September.
(August was revised up to 75,281)
https://pbs.twimg.com/media/DrWitXxX4AAqi8Q.jpg
2018-11-07 (Reuters) – Imperial Oil Ltd said on Tuesday that it would go ahead with the construction of its C$2.6 billion ($2 billion) Aspen project in northern Alberta, the first new oil sand development to be greenlighted since 2013.
The Calgary, Alberta-based company, which is majority owned by Exxon Mobil, said it would start construction on the 75,000-barrel-per-day project in the fourth quarter of 2018 with first output expected in 2022.
The Aspen project will use new recovery technology to lower emissions and water use and improve project economics, the company said.
https://www.reuters.com/article/us-imperial-oil-aspen/imperial-oil-to-build-new-canada-oil-sand-project-idUSKCN1NC01O
Hey Dennis,
….long time – no word.
How’s that $85 oil working?
I feel bad for Shallow Sand and the guys who’s livelyhood is tied to oil $….
Whopefuly, you do not block me this time…
Be well,
Petro
P.S.: hi SS, Ron et al… hope everybody’s doing well.
Current thinking on future oil prices, somewhere between low and high scenarios is my opinion, the medium case is my best WAG. Monthly spot price for Brent in Sept 2017 was $81/b in 2017$ (using CPI for real price estimate).
Resolving the issue would allow Iraq to export an additional 200,000 b/d…
2018-11-07 (Argus Media) The US administration has also pushed to resolve the dispute over the fields in Kirkuk that the federal government retook from the Kurdish autonomy in October 2017. Crude from those fields has effectively been trapped since then.
“We are deeply involved in trying to find a solution on Kirkuk oil,” Peek said, with another round of talks scheduled in Iraq next week. Resolving the issue would allow Iraq to export an additional 200,000 b/d, State Department special envoy on Iran, Brian Hook, said. Washington also has urged Saudi Arabia and Kuwait to restart production in their shared Neutral Zone, which US officials say could add 250,000-300,000 b/d to global capacity.
https://www.argusmedia.com/en/news/1787538-iraq-can-import-energy-from-iran-us-says
2018-11-05 (Bloomberg) — Iraq’s semi-autonomous Kurds upgraded their oil export pipeline to accommodate future production growth from their region as well as from the contested Kirkuk area controlled by the central government in Baghdad. The pipeline’s capacity increased to 1 million bpd from 700,000, it said.
The KRG currently exports more than 400,000 bopd
https://www.worldoil.com/news/2018/11/5/iraqs-kurds-add-pipeline-capacity-to-export-kirkuk-oil
Platts OPEC oil production survey for October
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/110718-saudi-arabia-uae-set-all-time-crude-output-highs-as-opec-oct-total-dips-to-3304-mil-b-d-platts-opec-survey
Table https://pbs.twimg.com/media/DrZPut3W4AEV5FZ.jpg
2018-11-07 (Bloomberg) Ministers from the group gathering in Abu Dhabi this weekend will discuss the possibility of cutting production again next year, according to delegates, a move that would mark an abrupt end to six months of supply increases.
The group is responding to a worrying prospect: Even though U.S. sanctions on Iran are removing significant amounts of crude from world markets, a fresh surge of American shale oil threatens to unleash a new surplus in 2019. Some members are concerned that inventories are rising, said the delegates, who asked not to be named as the discussions are private.
https://www.bloomberg.com/news/articles/2018-11-07/opec-ministers-meet-as-oil-s-slump-spurs-talk-of-another-u-turn
Saudis are NOT interested in increasing production to lower prices. Elections are over and any promises they made are fulfilled. The SPR draw will go away. No one will get excited over an inventory draw in Dec., as that is common. But, Jan. through May are times for inventory build. Be pretty interesting the next six months.
What is more or less certain, is that OPEC+Russia is controlling the Brent oil price. The theory of them wanting to keep oil prices in a price band to ensure what they think are fair prices makes sense. What this price band is exactly, nobody knows. 75-85 dollars?, 80-90 dollars?, or 75-95 dollars? The main thing is that they want a good price for their main export commodity and at the same time not stall demand growth and spur another recession. So I guess they will try to increase exports again if it reaches 90 dollars sometime in the next 6 months. Not that I think they could control the price forever like this, but probably until autumn 2019 if they strain spare capacity and inventory. Most likely they deliberately colluded with the US administration to ensure oil prices hit a low point around mid term elections. I could see Russia and Saudi not wanting democrats winning the Senate and helping by increasing production/drawing from inventory in Oct. So, if I am a betting man (and I can be somtimes), I would now bet on reduced exports from OPEC and oil prices hitting the ceiling of their price band in a couple of months time. There are already early signs on reduced exports, but it takes some time for it to show up in import and inventory numbers.
“What is more or less certain, is that OPEC+Russia is controlling the Brent oil price. The theory of them wanting to keep oil prices in a price band to ensure what they think are fair prices makes sense. What this price band is exactly, nobody knows. 75-85 dollars?, 80-90 dollars?, or 75-95 dollars?”
FWIW: I think Russia is going to slowly remove itself from the EU energy market as it continues to focus on the Asian markets. Especially in light of the higher Asian prices for Oil & NatGas, and the Anti-Russian Euro agenda. Russia completed a new Oil Pipe line to China this year(Russia can now export up to 600Kbpd to China) and will complete its NatGas Pipeline to China in 2019. Russia is also in talks with India to supply Oil or NatGas.
Yes, that makes sense. In Russia they feel they are too economically dependent on Europe. And Europe stays with the historic alliance with the US..but the problem is the threats from the aggressive US administration (I believe Russia is especially afraid of economic sanctions). So to diversify makes them more independent and also ensure better prices for their oil and gas exports.
“Russia completed a new Oil Pipe line to China this year(Russia can now export up to 600Kbpd to China) and will complete its NatGas Pipeline to China in 2019. Russia is also in talks with India to supply Oil or NatGas.”
Correct. But you have to get the relevant numbers: The NG pipeline to China costs around 50 billion USD according to Russian press releases, NordStream 2 around 10 billion USD.
The latter operates with a 50% higher pressure than the former, i.e. it costs Russia 7 times as much to deliver NG to China. And it is a save bet that China pays a lower price for the NG than the EU.
How much does Russia have to spend on Defense to counter NATO? Why supply your adversary with abundant energy when you can cut supply and let them deal with an economic crisis (thus forcing them to cut their defense spending).
China pays a lower price for the NG than the EU.
Not sure about that. Generally cost for energy in Asia are higher than the EU (excluding EU energy taxes). I believe Asia imports a significant amount of Liquidfied NatGas which is I am pretty sure is more costly than piped NG.
FWIW: Generally most business don’t do business when customers that make their live a living hell. Personally, I’ve fired dozens of customers who were not worth the trouble. I would imagine this applies at the national level too.
EIA U.S. Petroleum Balance Sheet
http://ir.eia.gov/wpsr/overview.pdf
Saxo Bank chart summary: https://pbs.twimg.com/media/DraQ5-PWwAERJ8D.jpg
US crude oil production re-benchmarked up +0.4 to 11.6 million b/d, which is the STEO number for November.
So pipeline constraints doesn’t brake US production by any tiny amount, but instead even accelerate it?
Uh, that’s the EIA. They live in their own world. Doubt production is anywhere near that. From the few years I’ve been watching it, they have only come within 200k barrels a couple of times,
Hey Guy,
Confusion arise from not understanding very simple things in life. For example “hope” . EIA, IAE or Bloomberg or oil “analyst” on internet, or tarot card readers, or Nostradamus, they all project certain price of oil in future.
So they are hoping that that would be the price in future. But what they don’t understand is that hope is false. All hopes are false. To hope simply means to postpone.
To hope means your present is ugly and you want to avoid it for some beautiful future. Price of oil is ugly in the present so someone makes a prediction, model, print in some financial paper and try to make at least future beautiful. To hope means you don’t want to see the present. That’s all to it.
I don’t know where this +400 kb/day production growth has come from? According to the EIA’s DPR they forecast that production growth in the Permian has leveled out at around +50 kb/day per month – due to pipeline constraints.
In the Petroleum Balance Sheet, the Line (13) Adjustment is still high at: +467 kb/day
Permian Sunrise Pipeline – as I understand it this is +150 kb/d higher than Plains said earlier due to NuStar Energy taking 150 off at Wichita Falls. Plains has the new 500 kb/d Sunrise capacity from Midland to Wichita but only 200 kb/d available from Wichita to Cushing…
2018-11-07 (Argus Media) Plains All American Pipeline said its Sunrise crude pipeline expansion is moving 300,000-350,000 b/d, adding takeaway capacity out of the Permian basin.
The expansion from Midland, Texas, to Cushing, Oklahoma, went into service earlier this month, ahead of schedule using temporary generators.
https://www.argusmedia.com/en/news/1788452-plains-moving-up-to-350000-bd-on-sunrise
Yeah, but the probability that production increased that much in one month with current activity levels is not very high. It alleviated some of the problem, and provided an outlet for a glut from previous overproduction. Discounts reflect that, now. I imagine it will go up some starting November, but not 350k immediately. Again, the more it goes up by this point, the more of a danger it hits larger discounts. Which is interesting, because as the decreased the discount to Cushing by about $10, Cushing prices are down by about $10, so no benefit for the last quarter, so far.
The Wichita pipeline serves three refineries, but not sure of each one’s capacity. Recent Cushing builds may be caused by some of this new outlet.
The supposed 400 kb/d in Permian, was a mistake by the author (Nick Cunningham), it was about a 410 kb/d increase for all US C+C output in Aug 2018. Permian was only up by about 40 kb/d in August and an average increase of 66 kb/d each month for the first 8 months of 2018. All US LTO increased by 85 kb/d in August 2018.
Also Permian output has increased 44 kb/d for the past 6 months, the previous 6 months had average output increase by 96 kb/d each month, on a annual basis the comparison is a 528 kb/d annual rate of increase vs a 1152 kb/d annual rate of increase.
Insanity reigns.
https://oilprice.com/Energy/Crude-Oil/US-Oil-Production-Is-Set-To-Soar-Past-12-Million-Bpd.html
Or, we are down the rabbit hole, and it’s getting curiouser and curiouser.
Eventually US C+C output is likely to surpass 12 Mb/d. For the past 12 months US C+C output has followed a trend with an annual rate of increase of 1649 kb/d, even if the rate slows to half this annual rate of increase, US output would reach 12 Mb/d by Sept 2019.
If the rate of increase continues at the rate of the past 12 months, then we reach 12 Mb/d in the first quarter of 2019, the EIA, splits the difference between these two guesses, which seems pretty reasonable, I would guess 2nd or 3rd quarter of 2019, depending on oil prices (higher prices would lead to earlier date).
Norway terminal shut down.
https://www.oedigital.com/component/k2/item/17551-breaking-tanker-frigate-collision-shuts-down-norwegian-oil-gas-to-europe?utm_source=AOGDigital-ENews-2018-11-08&utm_medium=email&utm_campaign=OEGDigital-ENews
Judge blocks Keystone XL pipeline
By Timothy Cama
https://thehill.com/policy/energy-environment/415862-judge-blocks-keystone-xl-pipeline
In a major victory for environmentalists and indigenous rights groups, Judge Brian Morris of the District Court for the District of Montana overturned President Trump’s permit for the Canada-to-Texas pipeline, which the president signed shortly after taking office last year.
Morris’s ruling repeatedly faulted the Trump administration for reversing former President Obama’s 2015 denial of the pipeline permit without proper explanation. He said the State Department “simply discarded” climate change concerns related to the project.
The decision once again throws into doubt the future of the 1,179-mile Keystone XL, which for much of the decade since its proposal by TransCanada Corp. has been a lightning rod in national energy policy.
The Trump administration had tried to argue that federal courts didn’t even have the right to review Trump’s approval, saying that it extended from his constitutional authority over border crossings. The court rejected that argument.
In rejecting the permit, Morris relied mainly on arguing that State, the agency that analyzed the project, didn’t properly account for factors such as low oil prices, the cumulative impacts of greenhouse gases from Keystone and the Alberta Clipper pipeline and the risk of oil spills.
TransCanada and State did not respond to requests for comment. The Canadian company had planned to start construction work next year.
This means – a few more years with 20$ oil for Canadas oil miners?
Acceleration of export plans to Asia?
“Reader, suppose you were an idiot. & suppose you were a member of Congress. But I repeat myself. ”
— Mark Twain: Manuscript note, c.1882.
https://www.ogauthority.co.uk/media/5122/oga_reserves__resources_report_2018.pdf
UK reserves estimates for end of 2017 by Oil and Gas authority.
Oil and gas replacement ratio rose to 60%, which is a lot better than some recent zero and negative numbers, but the reserve decline is continuing (only one year since 1997 greater than 100% replacement).
R/P for 2P oil is still about 11 years for oil, but below 6 for gas now.
Overall 2P ultimate recovery is holding fairly steady but 3P has declined over the past few years (mostly with possible reserves being moved into contingent resources).
https://ihsmarkit.com/Info/cera/ihsindexes/index.html
From their results and overall FID activity I don’t think th service companies and EPCs are having a particular boom but the IHS capital cost index has been on a gentle rise recently. The offshore drillers still seem to be suffering from some recent results.
Oil rout is getting very ugly.
Brent 69.50
WTI 59.30.
ND Light Sweet 46.30 (!)
Canada Index 25.77
WCS: 13.20 (!!!)
This has to be economic problems, prices aren’t anywhere near high enough to be causing major demand destruction from just the oil.
And this is with production curtailment from Venezuela, Libya and Iran by failed states/policy decisions, rather than geologic constraints.
I think it has to do with the OPEC meeting. If you look at history the oil price is almost always driven down ahead of key meetings. It can have a number of objectives; enforce discipline among OPEC members, scare investments in the shale patch and expensive offshore undertakings and also be a show off among power people (“look who controls the oil price”). Because, this sustained drop can certainly not have very much to do with long term or even medium term fundamentals.
Or another angle is as some claim, the Saudis have been played by Trump and the strong oil rally in September. Depends on who controls the market. I tend to think OPEC control the physical market more and the US control the exchange and media/financial players influence more. If the played by Trump angle is the case, the OPEC/Saudi coming adjustement needs some time. It could also be that US interests are not to disturb the US oil industry again through too low oil prices, and that there will be some moderation from EIA after this strong downward pressure on oil price (assuming it is from OPEC) – but you never know with the administration now in charge.
Baker Hughes U.S. weekly rig count
Oil: +12 to 886 rigs total
Natural Gas: +2 to 193
Permian +5, Cana Woodford -9
Oklahoma +4, New Mexico +4
http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother
Table: https://pbs.twimg.com/media/DrlIvzNW4AAfDv9.jpg
Baker Hughes International Rig Count
Total up +13 to 1017 in October
Oil +18 to 798
Natural gas -3 to 187
Misc -2 to 32
Split: Land +10 to 810 and Offshore +3 to 207
Brazil -2 (-2 oil)
Offshore China -5 (-3 oil -2 gas)
Norway +5 (+5 oil)
OPEC
Algeria -3 (-1 oil -1 gas -1 misc)
Saudi Arabia +6 (+6 oil +1 gas -1 misc)
Venezuela +2 (+2 oil)
Yes, this rig count speaks volumes. The oil glut supply thesis is up for sale for anyone that wants to buy it. SA , Norway and Venezuela not having problems? Brazil waiting for higher oil prices? And China too maybe? etc.
WTI fell for the 10th straight trading session.
This was the first time in the history of the contract.
You see, that’s because there has never been a supply and demand situation in all history as exists now. And of course eliminating Iranian supply must necessarily reduce the price.
You already did figure it out shallow, as regards nymex. Those guys have a significant incentive in making sure nobody else figures it out, so analysts will talk about supply and who is burning what.
FYI, Venezuela has proposed to OPEC that OPEC embrace blockchain pricing. That certainly concentrates on their own Petro currency, which will never fly, but it is a Pandora’s Box situation in that if blockchain technology becomes the norm in pricing, that will be the end of all sanctions.
Watcher,
Note that Iranian supply is greater than was assumed a few weeks ago due to the many waivers granted by the Trump administration. Trump wanted to try to keep oil prices low before mid terms, later he will cut off the waivers for several nations that import oil from the Iranians. When oil prices rise, Trump will blame Pelosi.
“Trump will blame Pelosi.”, for everything.
Hickory,
Yes I think you are right.
The first thing out of the President’s mouth post mid term, joined by Pelosi, was — amid a deficit that is 4.8% of GDP . . . a commitment to join together in pursuit of infrastructure spending. This clearly shows the Democrats embrace the philosophy of Dick Cheney — “deficits don’t matter” (And notice she didn’t propose a tax increase?).
Oh, and suppose oil prices don’t rise?
Or if they did, suppose the GOP offers up a govt subsidy of them in say, February of 2020 as the election approaches. Will the Democrats oppose that with November coming? Why should they take that electoral risk — since they embrace “deficits don’t matter”.
The detailed numbers for Brazil through September were issued Friday – quite a big drop in production despite the new FPSOs ramping up because of some outages on two of the big produces in Santos. The offshore drilling rigs for October are down to six , the lowest I’ve seen, so there’s unlikely to be a big increase then but it depends month to month on what new wells are completed and what the availability is on the operating assets.
It’s difficult to know now whether to present stuff like this as good news or bad as we need to be pretty well off of fossil fuels by 2050 to avoid “catastrophe”, though I don’t think that is making one iota of difference to the decisions made in the oil industry, in fact it might even act as an impetus to avoid being left with stranded assets.
Interesting that voters in two Blue states rejected anti oil and gas ballot initiatives.
Colorado rejected the spacing law and Washington State rejected a carbon tax.
I agree the FF industry spent money against these, but these initiatives were striaghtforward.
Proposal 112 in Colorado wasn’t ideal in that it proposed a significant setback throughout the state rather than to let individual communities to decide what they want.
Gas and oil spent millions to convince voters that gas and oil are a driving economic force in the state. That was once true, but is no longer the case.
However, given that state government is now blue, and an increasing number of people are living next to current and proposed drilling sites, I think gas and oil leverage will go way down.
Plus in the last few weeks there have two fires at oil sites. Every time there is an explosion or a fire, all of which get coverage on the news, people are reminded of safety issues.
https://www.thedenverchannel.com/news/local-news/fire-burns-at-oil-and-gas-site-in-weld-county-smoke-seen-for-miles
This conflict is not over by a longshot. In fact, a couple of days ago a city invited public comments about a proposal to drill under a lake that is a major water supply and recreation area. After one day, the drilling company abruptly withdrew the proposal.
https://www.denverpost.com/2018/11/08/standley-lake-drilling-highlands-withdraw/
Boomer.
Both Blue and Red in USA are still generally ultra consumers who want everything as cheap as possible, no matter what.
AZ also shot down a renewable energy mandate by over 2 to 1.
NV passed a similar initiative however, and FL approved an offshore drilling ban.
The price of gasoline was not the reason 112 didn’t pass. Oil and gas did not campaign on the idea that we need more oil.
They kept saying the setback would end gas and oil drilling in the state (which isn’t true since no current wells would be shut down), jobs would be lost, and the state economy would suffer.
But the opposition is likely to get stronger as more people live in proximity to the wells.
The cost of housing is a bigger issue in Colorado than the price of gasoline. So when housing developments and drilling sites overlap, the people in those housing developments protest.
It’s just a matter of time before there is a critical mass of unhappy home owners to severely restrict what gas and oil companies can do in their neighborhoods.
Colorado isn’t like North Dakota. Gas and oil aren’t big drivers of the state economy. And as more people move into the state, it becomes even less important.
So population increases and where they live will ultimately be the deciding factors. Drilling in suburban housing developments just isn’t very popular with all the people in those developments.
Boomer.
I know this isn’t oil related, but how has cannabis legalization went in CO?
I have some family in IL and it appears that is coming there very soon. Will be the only Midwestern State.
Is there still a lot of black market weed sold in CO? Has meth and opioid use changed any?
It’s gone well.
Opioid use appears to be down, though meth continues to an issue.
http://www.cpr.org/news/story/opioid-drug-screens-decline-in-colorado-but-marijuana-rates-beat-the-national-average
This recent article says the the biggest problem states with legal marijuana face are tourists.
https://www.westword.com/marijuana/colorado-oregon-and-alaska-share-similar-problems-regarding-social-marijuana-use-10976021
This is another recent article and it mentions the benefits in not treating it as a crime.
https://420intel.com/articles/2018/10/26/how-legal-marijuana-changed-colorado-and-could-change-michigan
I personally don’t use it (too expensive) but I know quite a few people who are happy about the business prospects both in Colorado and elsewhere.
It will become legal nationally before long because so many people use it and a lot of established businesses see dollar signs.
It would sure be good if people just used it instead of meth.
It seems anyone who uses meth also uses cannabis.
Of course, many just use cannabis.
Tough to find people to work these days who can pass a drug test.
Relatives who manage leases have fired employees before due to meth use.
Opioids get the headlines, but meth is still the scourage or rural America.
Kind of suprises me the shale boom hasn’t been somewhat derailed by meth addiction. Have heard some not so good stories.
This is what found out about meth in Colorado.
https://www.npr.org/sections/health-shots/2018/07/14/628134831/a-surge-in-meth-use-in-colorado-complicates-opioid-recovery
Some in law enforcement say to expect an increase in meth coming into the US from Mexico, as more states legalize cannabis.
Reason being there won’t be demand for Mexican cannabis, so meth has become, and increasingly will be imported by the cartels.
Easy to make, very addictive. Horrible drug. It seems to hit rural America very hard. Never see heroin arrests where we live, meth are weekly in a county well below 20,000 people.
I just found this. It’s recent and may answer some of your questions.
https://www.skyhinews.com/news/legalizing-marijuana-doesnt-appear-to-have-created-a-colorado-crime-wave-according-to-state-report/
From that NPR article on Colorado meth use.
———
Contrary to the portrayal of meth production in popular TV dramas, the meth in Colorado these days is rarely cooked up in neighborhood basements from local drugstore ingredients. Instead, it’s mostly imported, often along the same routes as heroin.
“I would say almost 100 percent of our meth comes from Mexico,” says Tom Gorman, director of the Office of National Drug Control Policy’s Rocky Mountain High Intensity Drug Trafficking Area. Much of it is mass produced there, he says, in “superlabs.”
The increased setbacks would have greatly curtailed new drilling in Colorado. That is where the majority of the O&G company budgets are allocated to. The operations of existing wells are financially minor compared to new drilling costs,
Yeah, I think that was the idea, to curtail drilling.
I think having more localized control is better. Some communities would have stricter controls than others based on what community members want, but so far state government has shot down that idea.
But this fight will continue until there is less drilling in populated areas and fewer accidents.
Looks like KSA are going ahead with poduction cut voluntarily or otherwise.
http://saudigazette.com.sa/article/547777
Otherwise they would have to invest 2 digit billions into new spare capacity they don’t have but claim to have.
On the other hand – they have to do it anyhow, they can be really tested anytime now.
What’s all of the other claims, Irak extending production capacity over 5 mb/d, Nigeria over 3 (they wanted to have reached 4 already in 2015 according to an old wikipedia article).
The only thing possible to grow without limit is US LTO.
LESS APPETITE FOR EXPLORATION DRILLING
https://www.rystadenergy.com/newsevents/news/press-releases/fs-less-appetite-for-exploration-drilling/
Of the 100 000 wells drilled globally in 2013, 4% were exploration or appraisal wells. In 2018, this share is expected to drop to only 2% of the 70 000 wells drilled. This trend can be observed across both the offshore and the onshore markets and across the globe.
In the offshore market share of exploration wells has changed from 35 to 24%. We’ve seen the most significant drop in South America as the Brazilian exploration market dried up during the downturn.
One reason for the drop is that there are fewer highly prospective areas, and where the might be oil and gas the wells are expensive. Despite advances in seismic and visualisation the chances of a successful well seem to be falling: two high impact frontier wells were announced dry today, one offshore Nova Scotia (I think maybe the last chance there after expensive misses by Marathon and Shell previously) and one in Gambia. The big drop in offshore proportion was 2013, when prices were much higher than now.
Onshore there are clearly very few places left that haven’t been explored and a drop to about zero exploration wells seems likely in the early 20s.
I wonder if Rystad has enough data on leasing activity to do a similar comparison for that, I think it would show a steeper drop.
Aren’t there onshore a few places where you can test at least LTO production? When there is some good rock somewhere it can be good to produce. Especially in countries where you don’t pay the supply crews for fracking that much (construction, truck drivers ) so you are cheaper than in developed countries.
I think the issue with LTO is more that the locations are known but the productivity and costs are questionable, so it’s not to do with exploration.
I don’t think at production in the USA – and with a more long duration strategy a good rock should be not more expensive than deep sea under salt production.
With land leased direct from government, and a planned logistic / fracking infrastructure without boom / bust prices I think it should be possible to produce cheaper than in Texas, same rock quality given.
But hat’s that got to do with exploration numbers – if the LTO location is known it’ doesn’t count as an exploration well if there’s new drilling there.
That I didn’t know.
If I know there is a big field, have a few production wells and now do exploration round about the field to look for sweet spots that’s no exploration anymore?
By definition of terms, in my opinion, there are no “exploratory” wells in resource plays. Initially there were step out wells to define the boundaries of the play, since then everything is simply development of the resource. Shaleco’s themselves tout thousands of “drillable locations” on their lease blocks and even the SEC allows for booking a portion of “type” EUR from proven but ‘non-developed,’ imaginary wells based simply on proximity to ‘proven, developed’ wells.
Booking those kinds of reserves of course does not take into consideration prices, or inflationary costs, or a host of other potential problems facing the shale phenomena in the future; it does, however, make for good Power Point presentations, press releases, reserve based compensations to management, etc. And most of all it distorts the reserve picture in America and gives consumers a false sense of hydrocarbon security. The “we have decades of shale oil and shale gas” bullshit also creates really stupid energy policies in Washington…like telling America it is no longer economically necessary to conserves its oil resources: https://www.oilystuffblog.com/single-post/2018/08/20/For-America-Conserving-Oil-Is-No-Longer-Economically-Imperative
Summary of OPEC+ JMMC meeting
Saudi energy minister Al-Falih: We have to wait for the best oil data and projections in December to make the best decision. The next meeting is December 5th.
The data analysis looked at during the OPEC/non-OPEC JMMC saw hints that there will need to be a supply reduction of ~ 1 million b/day from October levels
Russia is happy with what has worked for the last two years, and is happy to continue cooperation with OPEC
Oman oil minister: There is a consensus that the oil market is oversupplied
OPEC Secretary General: There is no doubt that 2019 will be challenging
Russia’s Energy Min Novak: Uncertainty around Iranian exports, trade wars to remain in 2019
– No decision on global output deal has been made in Abu Dhabi
UAE Energy Minister: OPEC to monitor market for next 3 weeks then decide on 2019 output – Ministry Tweet
News release 1: https://pbs.twimg.com/media/DrvK6xqU0AUNJPY.jpg
News release 2: https://pbs.twimg.com/media/DrvK6xrVAAAQZ7A.jpg
In terms of Btu (not barrels), the USA is now a net energy exporter
BofAML Chart: https://pbs.twimg.com/media/DrzAEqmWwAA2A90.jpg
Trade balance $billion https://pbs.twimg.com/media/DrzAN6dW4AADJZm.jpg
If the EIA are right, then the US has increased production by +2 million b/day just this year.
Crude Oil Production Re-benchmarking Notice
https://www.eia.gov/petroleum/supply/weekly/
Note that Weekly estimates are not revised so looking at weekly estimates over a long period is a waste of time. If we look at monthly data (which is revised and tends to be more accurate), from Aug 2014 to Aug 2018 US output increased at an annual rate of 615 kb/d each year on average. That is likely to be closer to the annual rate of increase from Aug 2018 to Aug 2021 in US C+C output.
Over the past year there has been a steep increase in output of 2100 kb/d, this rate of increase is not likely to continue, for the past 2 years the annual rate of increase was 1338 kb/d each year, after output fell by 200 kb/d from Aug 2014 to Aug 2016 due to low oil prices and fewer completed wells in the LTO sector relative to 2012 to 2014 and 2016 to 2018. A continued fall in oil prices may again result in a lower rate of increase in output (or even a decrease if WTI oil prices fall below $50/b).
If the glut of oil scenario that is currently in vogue actually occurs, US output will fall as oil prices crater. I doubt this will happen, but was wrong in November 2014 when I also thought the oil market would adjust but I was mistaken (or it took much longer to occur than I anticipated, 2.5 years rather than 6 months).
Related to hydrocarbon security
https://www.zerohedge.com/news/2018-11-11/us-confident-it-can-compete-europes-gas-market
Oilprice.com is running an article saying US LNG will replace Russian piped gas in Europe. The key buzzphrase was
We will be competitive with pipeline gas, maybe even in price.
How cool.
Tellurian’s Driftwood project will produce the same as Yamal at half the construction cost and, presumably, much lower operational expenses.
Likewise, Driftwood is comparable in capacity to the 3 Curtis Island operations at 1/4 construction cost. Feed in gas will be much less expensive than the Aussie Coal Seam supplies.
The Delfin project project offshore Louisiana – utilizing 4 FLNGs – may be cheaper by a bunch than all the rest per metric tonne to construct (about 13 mtpa capacity … half Yamal and Driftwood).
While no one can reasonably expect LNG to ever overcome price/cost advantages of piped gas, that the global spot price for LNG has bounced around st the $8/$10 mmbtu level is nothing short of astonishing.
I have mentioned several times on this site that the attention placed on oil supply/availability is tending to overshadow the emergence of natgas on the global energy stage.
The recent announcement that a near billion dollar LNG facility is being proposed way up in the woods of northeast Pennsylvania almost strains credulity.
However, that was just announced by the same outfit that is already producing LNG just north of Miami, FL
Heck, even Massachusetts – that hotbed of opposition to all things hydrocarbon – may host a small LNG plant in Auburn in central MA.
The ongoing implementation of processes and hardware dealing with liquified methane is poised to upend the current paradigms of energy use and production.
The productivity, economics and efficiency gains of Driftwood LNG are impressive if achieve. IIRC Expected Target price we budgeted for FERC @Trunk line LNG was $7+ @evaporators in 1983. Supplier market since Algeria was the main exporter with long contracts. Little effort in cost control since it was cost plus.
What has any of that to do with . . . “we’ll be competitive, even in price.”
Watcher,
Lower costs of production (which includes capital cost) can reduce price.
yeah you miss the point too
the phrasing, how else is one competitive
“I have mentioned several times on this site that the attention placed on oil supply/availability is tending to overshadow the emergence of natgas on the global energy stage.”
I agree with you, Coffee. Even as a transportation fuel (which I think is a poor usage of natural gas), natural gas could displace a significant portion of oil usage. I seriously considered a natural gas powered Honda GX a few years back. But chose not to based on a lack of infrastructure for re-fueling and reduced range.
I still think EV’s are superior to ICE vehicles (regardless of fuel type) or will be once a reasonably priced EV powered pickup and SUV are available. If oil is significantly eliminated as a transportation fuel, it will be plentiful for its other uses in chemicals etc.
If the natural gas supply truly is growing as Coffee indicates, maybe all of the angst over a declining oil supply are overblown.
Songster
One word … MOFs.
Check out the recent articles in Scientific American to get just a glimpse of where this is all headed.
When cutting edge MOFs the size of a pea have comparable internal surface area to two football fields, amazing stuff is gonna happen.
The Iranians claim to have achieved the “Holy Grail” of CNG storage wherein a standard size fuel tank – at 500 psi rating – full of MOF adsorbant can compare favorably with a 15 gallon gasoline tank.
Sub 500 psi will allow homeowners to fill up with their residential natgas supply.
Coffeeguyzz,
The natural gas resource is not unlimited, if natural gas comes to dominate the transportation sector, natural gas supply will peak very quickly. In that case natural gas becomes very expensive and will be unable to compete with wind, solar and EVs due to its higher cost.
Now zzzz is an expert in physics to0?
Just reading what he has written, it sounds like a MOF will absorb Natural Gas molecules and somehow keep it in a compressed state, therefore turning NG into a kind of CNG. I understand that it works very similar to the way that activated carbon works as an absorbent for gas. The ratio of equivalent volume to absorber volume does look quite high.
But then you think, why not just use the MOF to absorb renewable hydrogen gas instead of dirty finite non-renewable NG?
Sure enough, that’s what they are doing:
Record High Hydrogen Storage Capacity in the Metal–Organic Framework Ni2(m-dobdc) at Near-Ambient Temperatures
zzzz, you snooze you lose!
And how do we currently produce hydrogen on an industrial scale? Reality is a bitch.
True, zzzz the cornucopian.
I was thinking more along the lines of treating H as a storage medium for localized renewable energy conversion.
Quiet One
Check out Nikola Motors website, or – more precisely – the story posted on August 8, 2018 from Gas World describing a Norwegian outfit building the world’s largest electrolyzer plant to produce hydrogen.
Nel ASA is that company’s name and I have no idea if or even how that stuff works.
Best leave that to the physics’ experts of which this board clearly contains a few … so long as they not be snoozing too much.
I don’t know if I am the right one to answer you. It is cheapest to produce hydrogen by using natural gas. But more long term and environmental friendly is hydro power and then using electrolysis of water. And this is great in some way but costs maybe 2-3 times more than transportation fuels today (using hydro power) in addition to some storage/pressurisation challenges. And saftey issues e.g. in ships and airplanes. Not saying it can not be overcome. In Norway they see a big potential for this in an energy crisis environment. Buses, trucks, ships and airplanes in order of difficulty (the last option probably being somewhat unrealistic).
Saudi Arabia to cut oil output by half-a-million barrels per day
Saudi Arabia plans to reduce oil supply to world markets by 0.5 million barrels per day in December, its energy minister said on Sunday, as the OPEC power faces uncertain prospects in its attempts to persuade other producers to agree a coordinated output cut.
Yeah, Saudis and opec will decrease production dramatically to counter ghost production figures by the EIA. Should be interesting in a few months.
2018-11-12 (Twitter) Donald J. Trump – Hopefully, Saudi Arabia and OPEC will not be cutting oil production. Oil prices should be much lower based on supply!
https://twitter.com/realDonaldTrump
Wonder what oil price Donald Trump thinks is correct?
Think?
Trump tweet timeline with $oil price from Platts
https://pbs.twimg.com/media/Dr1PusGXgAIw6qS.jpg
It’s made the front cover of WSJ
https://pbs.twimg.com/media/Dr1SlIZWoAIlX7U.jpg
All I see is he wants it below $60 WTI based on the chart.
But how much lower?
Maybe he believes EOG’s 2016 $30 WTI profitability BS.
Seems he is ignoring nat gas. Wonder why?
Yes I don’t understand the tweet, especially as an OPEC cut would potentially give US exporters a larger market share. And WTI is already a full $10 lower than Brent. And so I’m guessing that the tweet means less $business for US companies. And a new inventories glut would see $WTI back down to 50 and below. A new refinery designed for LTO might do more keep US gasoline prices low???
He’s just fucking around with everybody. Republicans seem to like it.
World crude oil production growth depends on how much US LTO grows. Growth from other sources already negative (at current project approval rates)
IEA chart: https://pbs.twimg.com/media/Dr4GrCCWoAAl14R.jpg
IEA World Energy Outlook 2018
Free slides https://www.iea.org/media/presentations/WEO2018-Presentation.pdf
IEA Sees Risk Of Sharp Tightening Of Oil Markets In 2020s
just read “3.10 Crunching the numbers: are we heading for an oil supply shock?” in the WEO (p.156). They more or less conclude that a “supply shock” is likely and unavoidable (is it then really a shock?).
According to the presentation US oil production has to grow to round about 20 mb/day until 2025 to avoid undersupply. Not an easy task, even with inexhaustable ressources.
The most interesting part of the graph is in how much they estimate future decline rates of current production. Wow!
They have Growth from other sources (at current project approval rates) – but that depends on finding stuff to meet those approval rates and/or having sufficient back log. Neither of those things are remotely happening at the moment, so decline will be faster for conventional. In-fill drilling may step up in the short term if prices are high enough but then the decline will be even quicker.
Integrating the US LTO production growth that they have surely exceeds by someway the current EIA reserve estimates unless everything drops to zero pretty quickly after 2025.
What possible use is any of this to the people who pay money for the report other than to cover their collective BAU promoting (and therefore biosphere destroying) arses?
They don´t forecast LTO to increase as much as in the figure. It´s rather illustrating “call on shale” i.e. how much LTO needs to increase to meet BAU demand growth. The report is fairly transparent on this point and state that US LTO resource base needs to be much larger than assumed for this to happen.
There are several other shortcomings in the report including: stating that the gap is (only) a result of to risk adverse cost mgm in E&P and more capital investment will solve it, also they do not have “a best guess” supply scenario.
From the summary conclusions the impression is they don’t have any clear answers, maybe they are realising there are none:
There is no single solution to turn emissions around: renewables, efficiency & a host of innovative technologies, including storage, CCUS & hydrogen, are all required
The future pathway for energy is open: governments will determine where our energy destiny lies
George Kaplan,
I agree the growth from other projects of 17 Mb/d from 2017 to 2025, seems a highly unlikely scenario. Perhaps infill drilling and contingent resources and “possible” reserves might allow some of this to occur, but 17 Mb/d seems like too much. In addition, it is not clear how much of World 2P C+C reserves are undeveloped, so some of this “Growth from other sources” may simply be from 2P undeveloped reserves.
Coal plants make up one-third of CO2 emissions today and half are less than 15 years old;
policies are needed to support CCUS, efficient operations and technology innovation – what a load of delusional bollocks, they forgot the bit about changing the laws of physics. And so keen are they on it that they included it three times in the summary.
The growth in LTO output shown in that first IEA chart (first link in Energy News comment above) is an increase of about 15 Mb/d from 2017 to 2025, it is possible we might see a 2 to 3 Mb/d increase in US LTO output over that period, but that 15 Mb/d increase from 2017 levels is patently absurd.
But this graph is just LTO filling their projected “demand” projection.
In their summary towards policy makers they write :
“« The risk of a supply crunch looms largest in oil. The average level of new conventional crude oil project approvals over the last three years is only half the amount necessary to balance the market out to 2025, given the demand outlook in the New Policies Scenario. US tight oil is unlikely to pick up the slack on its own. Our projections already incorporate a doubling in US tight oil from today to 2025, but it would need to more than triple in order to offset a continued absenceof new conventional projects. »”
(taken from : http://petrole.blog.lemonde.fr/2018/11/01/minuit-et-quart/#comment-31865 , I don’t have access to this summary)
And what is kind of “funny” is that they are also saying that oil will reach a “demand peak” in 2040 (due to electric cars etc), which is the bit taken by most “MSM media”, like for instance :
https://www.timeslive.co.za/motoring/news/2018-11-13-oil-demand-is-under-increasing-threat-from-electric-cars-and-cleaner-fuels/
Just correct the Permian reserves from 40 GB to 400 GB, and the US oil industry can take over the world. It’s just numbers on a powerpoint presentation.
I think they have just projected the 2.5 mb/d increase from 2018 they have measured up to the infinity.
OPEC Citing Secondary Sources, Says Its October Crude Oil Output Rose +127,000 B/day M/M To 32.90 million B/day, Despite Lower Iranian Output
some highlights https://pbs.twimg.com/media/Dr4EX4ZX4AA9Fdd.jpg
Annual supply changes for selected countries in 2019
https://pbs.twimg.com/media/Dr4bjQNX4AAJ9iy.jpg
OPEC crude oil production based on secondary sources
https://pbs.twimg.com/media/Dr4dqEQX0AUYyhj.jpg
Essay on oil by Tim Clarke
End of the Oilocene: the roar of the oil-fizzle dragon king
http://www.feasta.org/2018/09/20/end-of-the-oilocene-the-roar-of-the-oil-fizzle-dragon-king/
Excellent.
Thanks
Somewhere recently I read something that I thought said that new debt has just about equalled the amount used for share buybacks – I’m not sure over what period or what exact location(s) but now I can’t find it. Anybody else seen something like that?
Couldn’t find what I was looking for but found this below.
Share buybacks are in the trillions per year and rising significantly this year in US following the tax cuts, 3Q numbers look likely to be the highest ever. It’s maybe one reason why all the new debt gas not led to high inflation.
The oil industry is one of the biggest players for buybacks, especially the IOCs, and this year more the non US companies like Total, Shell and BP, but Anadarko has an expanded program as well. The people that benefit the most (maybe the only ones to benefit in the long run) are executives with stock options. After the 1929 crash buy backs were seen as part of the problem and banned, I don’t know when they started again.
Why It’s Raining Share Buybacks On Wall Street:
https://www.forbes.com/sites/stevedenning/2018/03/25/why-its-raining-share-buybacks-on-wall-street/#52e7b5da3346
The Economist has called them “an addiction to corporate cocaine.” Reuters has called them “self-cannibalization.” The Financial Times has called them “an overwhelming conflict of interest.” In an article that won the HBR McKinsey Award for the best article of the year, Harvard Business Review has called them “stock price manipulation.” These influential journals make a powerful case that wholesale stock buybacks are a bad idea—bad economically, bad financially, bad socially, bad legally and bad morally.
And so the floodgates opened. The resulting scale of share buybacks is mind-boggling. Over the years 2006-2015, Lazonick’s research shows that the 459 companies in the S&P 500 Index that were publicly listed over the ten-year period expended $3.9 trillion on share buybacks, representing 54% of net income, in addition to another 37% of net income on dividends.
https://oilprice.com/Energy/Energy-General/Saudis-Scramble-To-Stop-Oil-Price-Slide.html
It will be mid 2019, before it is apparent that EIA’s projections are severely flawed.
Or possibly not
https://www.zerohedge.com/news/2018-11-13/crude-crashes-saudi-abandons-opec-production-curbs
I did not see this superdive in oil prices coming. Many succeed in business by being unscrupulous. And in the oil market a relatively minor surplus (or deficit) of barrels in the marketplace at any one small time window can drive prices to wild extremes. If this is a wise move by those behind it – probably not.
Why it is not? If a free market is supposed to work like intended, the price is the main signal for the market players. High prices makes an incentive for investments, higher production, conservation and alternative solutions at the same time; to distort that makes the whole market inefficent and price volatility in the future will most likely also be too high. The whole thing will taste bad.
This is a way of life for oil producers in the US.
This is why Mike, and to a lesser extent, I, give Dennis such a hard time about his graphs and projections.
$8-140 in 19 years.
$25-$99.25 from 6/14 to 2/16.
$28-$140 from 7/08 to 2/09.
Volatility baby. A drop of $20 in 3 weeks is nothing. Wake me when we hit $40s Friday.
Be careful what you wish for shallow.
I am well aware that on a short term basis the price can range from $10 to $200.
It just takes a few months of prices significantly below OPEX to go bankrupt.
Would be something to go BK with no debt. We were thinking that way in 2016.
You have to have debt to go bankrupt.
So you operate at a loss. You fund it. Out of pocket, or via borrowing.
Only after you have that borrowed debt on the books can you expunge it via BK.
Not if entity runs out of cash and you don’t want to put personal assets up or borrow.
Ask Trump.
You are forgetting the P & A liabilities.
Shallow sand,
It s certainly the case that I do not know future oil prices. The scenarios always state the assumptions. Lower oil prices result in lower output.
SS,
remember my earlier posts: “… in the end there will be spikes of the wave, up and/or down … and then kaboom.”
You may not hit $40 by Friday, but you sure as shooting will hit $0 sooner than you think.
Time is relative body, if you travel C – becomes 0/nonsensical.
Read your posts from 2014, how panicked you were then .
Lately, you/we have ridden the upside part of the wave.
We are going down now. Wait till we reach the trough… (hint: there won’t be any…. $0).
I suspect you wont be slipin, you will be awake when that Friday arrives…. if you catch my drift.
be well,
Petro
India – PPAC – Consumption of Petroleum Products (‘000 Metric Tonnes)(without LPG)
October is up +4.5% higher than October 2017
Average consumption for the first 10 months of 2018 is up +5.1% higher than same period in 2017
Chart: https://pbs.twimg.com/media/Dr6ED8oWoAAyTny.jpg
Delhi – Retail Selling Price of Petrol – Indian Oil Corporation Ltd
Chart: https://pbs.twimg.com/media/Dr6EL1ZWsAAs2LK.jpg
https://fred.stlouisfed.org/series/M12MTVUSM227NFWA/
Study this and imagine you can explain it.
We have talked about whether debt in the US is manageable. The WSJ had an article Monday on the rising federal debt.
“Debt as a share of gross domestic product is projected to climb over the next decade, from 78% at the end of this year—the highest it has been since the end of World War II—to 96.2% in 2028, according to CBO projections. As the overall size of our debt load grows, so too do the size of interest payments.”
Definitional claptrap. The ratio is over 100%. It has always been quoted as total debt. Now, since the number is over 100%, the definition changes to exclude liabilities (aka debt) held in the various trust funds, like Social Security and Medicare. When people have SS contributions extracted from their paychecks that money buys bonds and those bonds are parked. They are debt. Soon or maybe already that money contributed flows out as benefits and maybe there’s a net negative flow now, but that doesn’t matter. The trust fund is in bonds.
Those were always included in the amounts quoted in the past. But now that they have caught up to and exceed US GDP, gotta redefine them. Note that when debt/GDP is quoted for other countries, their trust funds are included.
Quoting: By law, income to the trust funds must be invested, on a daily basis, in securities guaranteed as to both principal and interest by the Federal government. All securities held by the trust funds are “special issues” of the United States Treasury.
It’s debt. It’s included. The US debt/GDP ratio is over 100%.
Bloomberg, Emerging Market high yield corporate USD debt maturities. 2022 is the peak year for refinancing.
Bloomberg chart: https://pbs.twimg.com/media/Dra2Ic3VAAAziNd.jpg
Bloomberg, cost of US debt, estimated annualized payments.
https://pbs.twimg.com/media/DrZHJY0WsAA3uLe.jpg
The IEA sees an implied stock build of 2 million b/day in the first half of next year, all things being equal
IEA chart: https://pbs.twimg.com/media/Dr86mFLWwAIHt5Z.jpg
Some highlights: https://www.iea.org/oilmarketreport/omrpublic/
(I cannot see in the highlights if they have adjusted World Supply for the drop in Iranian exports, because so far exports have decreased more than production. I guess that they must have?)
IEA: Shipments Of Iranian Oil In October Were 1.8 Mln Bpd, Down 900,000 Bpd Vs May, Still Unclear How Far Exports Will Fall
2018-11-14 (Saxo Bank) Natural Gas at $4.4 mmbtu trades at the highest level for this time of year since 2009. Carried higher by strong momentum in response to US cold snap, stocks at a 15-year seasonal low and expectations for a modest 32 bcf injection in Thursday’s EIA Report.
https://pbs.twimg.com/media/Dr9fzFYXQAENZMM.jpg
Natural Gas January has been up to $4.95 today
http://quotes.ino.com/charting/index.html?s=NYMEX_NG.F19.E&t=&a=&w=&v=d3
Hearing comments on business news that oil drop due in part to rotation into natural gas and due to one very large trader long oil getting hit with margin calls big time and being forced to liquidate.
Obviously I don’t know but it looks like speculators have been selling their paper barrels for the last few weeks. The number of paper barrels net long (yellow line) has come back down to the longer term range.
Saxo Bank – The combined Brent and WTI long has reached a 16-mth low at 420k lots, down 663k lots from the March record
chart: https://pbs.twimg.com/media/DruHunoWwAA_LhZ.jpg
seasonal https://pbs.twimg.com/media/DruFT88WsAYGDoG.jpg
November 14th 2018 (EIA – Today In Energy) U.S. crude oil and natural gas production increased in 2017, with fewer wells
https://www.eia.gov/todayinenergy/detail.php?id=37492