A Guest Post by George Kaplan
EIA Reserves
EIA provides estimates of proved reserves based on information from the E&Ps on form EIA-23 for crude only, and also shows the categories for changes (discoveries, production, revisions etc.). This data with updates for 2016 has been due since November but so far has been twice delayed. BOEM make their own estimates for 2P (i.e. proved and probable) based on strict adherence to SEC/SPE rules (i.e. the reserve must be on production or be expected to be produced within five years). I think this usually comes out in May. In the absence of the latest EIA numbers I’ve presented the 2015 numbers with adjustments for subsequent production. There will be revisions and additional discoveries to include once the actual data is available though I think fairly small, especially for gas, but it will be interesting to see.
Despite excluding probable reserves and counting crude only, the EIA estimates have recently exceeded those from BOEM. It looks like a lot of the probable reserves were converted to proved through positive revisions in the period 2008 to 2011; i.e. possibly due to some price increases then, but also immediately following the SEC rule changes to exclude reserves without firm development plans, which may or may not be coincidental: the E&Ps may be less strict on applying the SEC/SPE rule, which they are allowed to do for large, long term projects. The BOEM estimates are pretty much flat over recent years as additions (which then become backdated “discoveries”) from new projects going through FID balance production, whereas EIA estimates are declining with revisions recently zero to negative.
Sales and acquisitions mostly balance out, sometimes with a year or so lag, though overall slightly positive, which I guess means the purchasers are able to get a bit more from the fields than the sellers. There are few extensions to conventional fields (unlike LTO where they are the largest positive factor) and discoveries have trended down significantly over the last three or four years (this would probably have happened a couple of years earlier but for the drilling hiatus caused by the Deep Horizon accident).
C&C Production
For November the production losses from Hurricane Nate have been recovered but more than 100 kbpd streamday was lost because of the subsea connector failure on LLOG Delta House Rigel template and the Shell Enchilada gas line failure. Total oil by BOEM was 1675 kbpd (up 211 kbpd m-o-m but down 16 kbpd y-o-y) and by EIA 1666 kbpd (up 209 kbpd from October, but down 21 kbpd y-o-y). Note that several leases did not report November numbers so I have had to estimate production based on data from the months before the hurricanes started to have influence.
New fields production has peaked for the time being, even allowing for the offline fields. Stampede might give it another boost once it comes on-line soon. The smaller additions are generally in decline, but there has been some in-fill additions for Horn Mountain, Holstein and Phoenix.
The large platforms, and Mars-Ursa should be considered with the ones listed, are holding and increasing production the best. I don’t know how much more there is to come, but certainly Tahiti and Atlantis have large brownfield developments in progress. The larger ones shown are around ten years old, which would normally be around the end of a plateau period, but equally they tend to have a lot of excess processing capacity. If nothing else some of them must be due for major turn-arounds in the next couple of years, which would take about as much production out for a year as Nate did.
The smaller, mature fields took a hit with Enchilada offline, but maybe not as big as might be expected given their continuing steep decline.
Shallow fields continue to decline. There was some headline news concerning Byron drilling the South Marsh Island 71 block, but it only has about 4,500 bpd capacity.
Recent News and Activity
The Enchilada pipeline is still offline with no date for restart published yet, which is keeping about 75 kbpd oil production offline from Baldpate, Salsa, Cardamom and Magnolia since early November. The workers injured in the incident have started proceedings against Shell for compensation due to safety failings. All these fields were in fairly steep decline so the production, and therefore revenue and interest, is only lost while they are offline rather than being deferred several years, as would be the case for a system on plateau. The subsea failure on the Rigel manifold feeding Delta House has resulted in Rigel, Otis and Son of Bluto 2 being off line for most of October and all of November (about 40 kbpd capacity). I have seen no news that this has been repaired. Without these two major unplanned outages November would just about have beaten the March record for production.
Anadarko relinquished the Phobos lease after poor appraisal well results. It had been the only qualified lease in the far south Sigsbee Escarpment lease area and was being planned as a long tie-back to Lucius.
Maersk Drilling has lain off workers that had been working on the Maersk Viking for ExxonMobil’s Julia field, which seems to have finished ramp-up although there had been plans for a phase II there. It had been in quite steep decline but there has been about 6,000 bpd increase in the flow over the last two months and it may be near a new peak. Stones drilling has also stopped, it has a nameplate of 40 kbpd but has only so far exceeded 30 for one month. Heidelberg drilling, too, has now stopped and it has achieved about 40 kbpd of a nameplate of 70 kbpd; phase II is due in 2021.
Tornado II started production in mid December at about 10 kbpd oil. Combined flow for Tornado/Phoenix is currently reported at about 21 kbpd oil, or net 8,000 bpd up on the average with Tornado I alone. There’s also been a big increase in the Horn Mountain lease, which has gone from less than 10 kbpd and declining in May, to now over 32 kbpd.
Two non-quantified discoveries have been announced as variously “major”, “significant” and “amongst our biggest”: Whale for Shell/Chevron, which does sound pretty big and is near the Perdido platform, and Ballymore for Chevron/Total, which is near Blind Faith. I suspect both will be tie-backs as the reason for concentrating on near field exploration was to save money on subsequent developments. Perdido has 100 kbpd nameplate and currently produces 66 kbpd, and Blind Faith has 60 kbpd with over 37 kbpd capacity available, and rising. Appraisal drilling is continuing on both, and that hasn’t always been as great as the initial announcements (e.g. Kaskida, Shenendoah and, recently, Phobos). I’m not certain, but think they both may count against last year’s discoveries and the announcements have been delayed to be immediately concurrent with the 2017 financial statements.
Wood Mackenzie was reported as giving predicted 2018 GoM deep-water production of 1935 kboepd, a new record. I think this is an average rather than a peak or exit rate, but I couldn’t find for sure. Note this is oil and gas (reported as including 80%, I think C&C only, but could be total liquids) and doesn’t include shallow water, which may be below 500’ (common industry limit) or 1000’ (BOEM limit), the report didn’t say. I don’t know why it was made so complicated, probably so they can declare a record of some kind that would help to try and sell the full report.
Currently (early February) there are forty-nine deep-water well related operations in progress reported by BSEE. Thirty-four are drilling related, with five pre-drilling for future projects and four on unnamed fields (so wildcats or appraisals). Of the fifteen running tools one is for P&A on Tick, which is fairly shallow water. Numbers in brackets on the production charts show the number of listed activities for each field. There is no current indication that the increased oil price is leading to increased drilling and the Baker Hughes count of active rigs has actually fallen slightly recently, though there may be signs of an uptick in non near field wildcats, but probably still early to say.
Future Production Scenarios
Below is an updated projected scenario (i.e. guess) for future production. The curves are adjusted so the total production in each section equals the estimated reserves for those fields from BOEM numbers for January 2016 less any production since then. Their estimates for this year (showing January 2017 numbers) have not yet been issued. For projects under development and discoveries I’ve used the E&P numbers for reserves, production and start-up where available or just made a guess. Numbers in brackets are nominal crude and condensate nameplate capacity for the expected development. I’ve included some nominal new discoveries with total reserves of 500 mmbbls, but may have to change that once the Whale numbers are announced.
I’ve also shown the 2018 BOEM production forecast, which I don’t fully understand. For instance they have on-line production suddenly dropping about 400 kbpd this year, but being made up with contingent numbers, which I would have assumed is possible development but can’t be; but also can’t be planned start-ups because there is nothing like that amount due this year. They also have a large amount of new discoveries that come on line very quickly – i.e. ten years to bring on line 800 kbpd, which would be some combination between eight big discoveries and eighty smaller tie backs. Nothing in recent history of exploration success or lease sales, or usual cycle times for deep-water projects, would suggest that is likely.
EIA STEO has its normal steady exponential rise, now extended through 2019, with bites out for hurricane season.
Off Topic Finish
Black domestic cats might be about to start to go extinct, as they don’t show up well on Instagram and the like. In one Bristol, UK rescue centre all forty cats that haven’t found homes are black. Owners of black cats are being particularly encouraged to get them neutered. The world is turning upside down.
George,
Thanks for another great post.
What is the cumulative production for the 18 or so years in your GOM C&C Projection chart?
Cumulative GOM production up to the start of your chart – April, 2017, is about 20 Gb (from 1947 through 2016 actually, but close enough). GOM production at the end of your chart is about 300 kbopd/day or so, as per my estimate.
If I assume a 5% annual decline from 2035-2050, production is at about 139 kbopd in 2050, and the cumulative production from 2035-2050 is about 1.2 Gb. (If I go out to 2060, it only adds another .4 Gb).
So, we can take about 21.2 Gb (20 + 1.2) plus the cum production from your chart and get a good EUR for the GOM at least through 2050.
I have a much higher decline rate than 5% in the run down period, so a lower reserve then, but numbers are below in Gb. I also double counted a couple on some things – e.g. Stampede and Big Foot are in BSEE reserves but I’ve also got them in new production, and might have the same for some new LLOG and Anadarko wells.
So that comes to an EUR of about 29 Gb for the GOM through 2050.
George, I think your bottoms-up projection is the most well-founded that I’ve seen, and provides a very reasonable mid-case estimate. BOEM’s most recent projection, to which you provide a link, only goes through 2027, is, in my opinion, too rosy in that it predicts more “yet-to-be-discovered” resources than recent exploration successes can justify.
The ranges that I published in my 2016 post of 30-37-47 Gb were too strongly influenced by BOEM’s estimates of UTRR (undiscovered technically recoverable resource).
If I were to revisit my ranges, I would probably revise them downward to something like 27-31-36 Gb, or so. I am still a bit more bullish on both future exploration than you, and also, see a strong likelihood that a few of the abandoned developments will eventually get developed.
Thanks. The only thing I’d say with certainty is that I am wrong. I try not to make predictions about discoveries and left anything like that off the last time, and wish I had done again, then it makes it easier for people to apply their own estimates. So maybe ignore my new discoveries and treat the rest as a lower limit, especially past 2027.
I think I’ve also probably got the decline after 2018 too steep for the larger platforms – one of the problems with the way BOEM report against leases rather than fields is that new and mature production can get lumped together and I tend to treat them all as if they are the same (older) age; but I don’t have the data to do much else.
I’d agree some of the abandoned leases could be revived but I don’t know at what price or if they’d need some new technology (I think maybe better/cheaper HP/HT equipment, some seem to be in the 15k to 20k tree range now, possibly with sand and erosion issues, and maybe outside the temperature range for even duplex steels – which I appear to have forgotten, but think was around 125°C).
Impressive! Thanks for the post.
IEA Oil Market Report: 19 January 2018 – now available to non-subscribers
Download pdf file from here: https://www.iea.org/oilmarketreport/omrpublic/currentreport/
Chart for OECD gasoline stocks on Twitter: https://pbs.twimg.com/media/DVDgpduX4AAThT8.jpg
XOM Exxon Mobil 83.26 -5.85 -6.56%
I’ve not been following earnings but I read this on Twitter…
On the Exxon call, analyst points out company generated ~ same amount of cash in the fourth quarter as it did in the previous quarter, even though oil prices rose significantly. “What’s going on?” he asks.
Exxon cites one-time issues, such as tax and impairments.
Exxon share price is down more than 5%. That kind of decline is very rare. If it holds, would be biggest drop in 7 years. Note that crude prices are up 34% in last six months, while $XOM is barely up in that time.
Reporter Tweet: https://twitter.com/bradnews/status/959456221127495680
No doubt refinery margins narrowed in Nov and Dec when the GoM refineries restarted after the hurricane outages.
I note that XOM lost $60 million on US upstream in Q4, 2017, after removing the one time effect of the US corporate tax cut.
This compares to Chevron, which posted earnings of $360 million on US upstream in Q4, 2017, again, after removing the US corporate tax cut effect. That may seem like a lot, but represents just 17 cents per share.
Of course, US upstream is more than shale oil, and I assume some of this lackluster performance is due to natural gas prices continuing to be low. Both took asset impairments on US gas production.
However, the oil price recovery in Q4 was apparently not enough to make either’s US upstream operations very profitable. This is significant as the two combined produce over 1 million BO of oil and NGLS per day in the US.
25,520.96 -665.75 (2.54%)
Bloodbath
I think it’s the refining business results that the investors don’t like. Maybe that is the real impact of lighter oil in the USA, not that it can’t be refined at all but that it can’t be refined at a decent profit.
One time costs to get where they can, or normal incremental costs? Why would they do it at all, if it was normal?
Could be that by summertime, we could start seeing gasoline prices rise, as the current gas supply indicates it will be strongly drawn on by then. Diesel already is. Pump prices higher, refinery gets better profits, right?
Is t it fairly normal that refineries suffer as prices of oil goes up, especially when they can’t transfer it on to the consumer, yet? Just guessing.
https://www.cnbc.com/2018/02/01/refinery-ceo-sees-global-gasoline-demand-rising-in-2018.html
Looks like gas prices will rise soon.
Looks like one of those boom or bust times for refineries,
Okay, this is old thinking.
“Investors” aren’t involved. It’s high frequency trading computers who are interested only in what their competition is doing. They do combat with each other and if there is any array of deterministic parameters for what price they offer or demand, it is 90% combat and 10% headlines.
Latest data I saw said 75% of all trades on the exchanges are now high frequency. A good portion of the other 25% are dictated by fund asset allocation and won’t care about day to day news.
All that being said, the sinking tide will drop all boats floating on it.
Hi Watcher,
While I must admit that I don’t take your stuff seriously all the time, I do read you carefully, because every once in a while you have something to say that throws a lot of light into dark corners.
And you certainly have a way of coming up with little known facts.
I suppose most of us are familiar with the fact that most trades on the stock exchanges these days are high frequency machine trades, the seventy five percent you mention. And we know that the brokerages earn a razor thin but reliable profit on average on these trades, which is why they make so many of them.
But I have never seen any figures on what it costs a brokerage to do this, or how big the profits are, or how much it costs all the rest of us.
Tell us more, if you know more about this. Might be best to take it over to the other thread from here though.
EN on IEA- They are laying all their predictions on a weak demand increase of 1.3 million bpd, and an increase in US production of 1.1 million bpd. Shying away from predicting a decrease in Venezuela. Insane. The highways are jammed with trucks burning diesel, now.
They admit that 4th quarter 2017 was bleeding at one million barrels a day, already. That was also Goldman’s take.
Ok, I’ll try mine, and see how much closer I come to actual. Demand up 1.7 million bpd, US increases .7 million bpd, and Venezuela drops .3 million bpd. Which leaves us drawing more than 1 million per day for 2018. That leaves oil prices at ?.
Guym,
Higher than $60/b, if your estimate is correct.
Yeah, well it’s not much of a stretch of the imagination, either. That’s what demand basically was last year, and likely to get better, in the US, anyway. 700k per day is your estimate, and most likely a good number, though maybe a little high. EIA not expecting 1.1 million increase until 2019. 300k drop from Venezuela is a low estimate by many. Some expecting more. But, who knows, Ecuador can still surprise. Oops, forgot they are with OPEC, so big push from them is out. Especially, from just one rig.
Part of the problem in comparing IEA estimates with EIA is from the fact that IEA estimates growth (by the end of the year), and EIA says average production. At ten million at the end of the year, and an average production of 10.3, EIA is possibly implying that production will increase 600k to the end of the year. IEA’s estimate is 1.1 million by the end of the year. That’s double, and frankly just pulled out of their posterior. EIA has global growth averaging 1.7 mbd.
It might also be of interest to some here that ConocoPhillips lost $102 million on US lower 48 upstream in Q4, 2017, but did earn $396 million with regard to Alaska during the same period.
Maybe this is because COP spent almost two thirds of its corporate CAPEX in the lower 48 in Q4, over $900 million. They have really cranked up spending on lower 48 while cutting everywhere else. Crude oil production for COP really jumped in the lower 48 from Q3 to Q4, but is still down from 1H of 2016, probably due to divestitures.
Given the very high amount of CAPEX required to grow production in the lower 48, it continues to remain to be seen if my preferred $55-65 WTI price band is enough to cause new lower 48 production (shale oil) to be profitable on the whole.
I am enjoying the current price, however, and would be very happy if WTI remained at the upper end of that band throughout 2018.
$55 to $65 is enough to make holders of good sweet spots to make a little profit, all the rest suck wind. I think EOG’s guideline of $8 million a year gross the first year before drilling is a good guideline. So, at $65, the well has to expect to produce? At least, 123,000 barrels of oil the first year. At $55 it’s about 146,000 barrels the first year. But, it has to be a consistent price for a long enough period to know it will continue. EOG based theirs on oil at $40, and I haven’t heard them change that, yet. Although, I know they are drilling in spots that don’t, just to hold leases. Though, there are better wells, elsewhere, to offset those. Even at that, they are only within the profitable side. They will never make a killing at $65.
The economics of this are apparent. You have to keep drilling the same number of wells to keep up, and grow a little. To do that, you have to recoup your capital to drill another. At $8 million, you can. They keep 75% of the 8 million, which is 6, or less after expenses.
Considering gravity deducts, percentage of total production hedged, transportation deducts, etc. nobody is getting paid 65 dollars. At $60, after royalty deducts, incremental lift costs per BO, G&A costs, production and property taxes and interest expense per BO (including legacy debt) the current shale oil netback barrel is $26-28. An $8M well (that’s cheap for todays 18M pound 40 stage frac’s,) will require a little south of 300K BO to payout.
Time to payout is an important metric in well economics, as Shallow has said; ultimately however nothing is more important that ROI vs. time. If the best you can hope for in your business model (using real EUR’s, not fakes ones) is 1.5: 1 over 15-18 years, …you can NEVER stop borrowing money, not even to stay even. That is why the shale oil industry has since its inception had to outspend revenue by enormous margins. It was a doable business model at $90, if debt was paid back at payout; now, with legacy debt, the price has to be $85 and above, for a sustained period of time, to get out of debt AND ever meet the true definition of profitable.
Yeah, with costs going back up, 8 million may be right. EOG had it closer to 6 with the “efficiency” gains of robbing service companies. $90 to $100 is necessary for shale to survive over time, I readily agree, and not all would be smart enough to make it even at that price. At this price, it is a debt manufacturing machine.
Your using all costs, I was just looking at incremental costs of one well. Still, your explanation supports why they are barely sliding into barely black, rather than black with a lot of digits. Of course it helps you get to the barely black ink, if you continue to sell those acres you paid $800 for with thousands of percents markup on them to other companies intent on increasing debt.
Mike, that is my point. WTI averaged $55.37 in Q4, yet the two largest oil companies in the US, XOM and CVX, who I might add both own tremendous legacy HBP acreage and minerals, particularly in the PB, still did not do so hot in US upstream earnings. Nor did the third largest, COP, who also has mucho legacy acreage and minerals.
The shale independents are mostly going to make more EPS Q4 than in any quarter in the last three years, but it won’t be earth shattering.
Of course I am paying attention to all of this due to my own conventional investments, which did pretty darn well last quarter, thankfully.
This has been a 3 year tough old slog, and I thank those here who have put up with me whining about it.
For everyone in the world involved in oil and gas production, individuals, companies and countries alike, it has been a tough slog the past 4 years. It has NOT been for the US shale industry simply because it has taken advantage of a liberal monetary system in America and borrowed itself up to its hard hat. Its grown (keeping prices depressed), but its fake growth.
Major integrated E&P’s like Exxon and Chevron are moving to the Permian Basin simply because there is very little oil left in the world that will not be horrendously expensive, and, at best, marginally profitable to produce. It does not mean that the Permian has better economics, it simply means its easier to develop with mass manufacturing methods, and faster to get money back than say, deep water projects that often take 5-7 years or more to find and get to market. Exxon spent $6B for the Bass Brother’s goat pasture in New Mexico; look at their wells and ask yourself how is Exxon going to do better and if another $15 a barrel really helps all that much. Independent E&P’s will show positive earnings for 4Q17 and thru 18, maybe, but it won’t be enough to get them out of debt.
As to America putting all of its hydrocarbon eggs into the Permian Basin basket, by mid summer we are going to know, finally, how bad the water situation is in West Texas and the affect it is going to have on growth.
Noted at the very end of the previous thread. This month, as I recall, is when those folks up in Alaska were to do some drilling in Smith Bay west of Prudhoe to confirm and add detail to their supposed discovery.
I see no mention of anything online.
I think Caelus didn’t find anyone to provide backing so it was delayed another year. Eni are drilling a long reach well from a man made island somewhere up there.
I smell distrust.
http://www.searchanddiscovery.com/documents/2017/10968he/ndx_he.pdf
This is really abbreviated, but indicates the layers in the Permian are not as homgeneous as many indicate. Seems like it should be in National Geographic – Seals and migration.
Guym, I have read this paper; it is interesting and it is important. Organic shales are the ovens that cook the goodies in all of America’s hydrocarbon producing basins. Those goodies have been migrating vertically and horizontally for tens of millions of years and this migration is what loaded overlying sediments where traps exist that have now been drilled up and are nearing depletion. Seal integrity and migration pathways out of unconventional shale beds make volumetric calculations of OOIP, or OGIP, and recovery factors, pretty meaningless. It is also a big factor in how unpredictable, and unreliable estimating technically recoverable shale oil and shale gas reserves are.
Enno Peter’s data for EagleFord through October is out:
https://shaleprofile.com/index.php/2018/02/02/eagle-ford-update-through-october-2017/
I guess this has been discussed here before but it looks like it’s winding down now. 25 to 30 spuds per month but 60 to 80 completions. There are 627 DUCs and I’d guess they need about 4 to 6 months inventory to allow efficient working, so 240 to 480 minimum at this level. That means they have around six months (+/-; i.e. to around May/June) at current activity levels until they would be seeing monthly reductions in completions each month (or they’d need to start drilling more wells).
Time from spud to completion is still pretty good in the Eagle Ford. Completions will probably pick up some this year at current prices. Still a lot of gas left in the tank in the Eagle Ford. Which won’t show up much until the price is closer to $100. I think at $65, it won’t decrease much.
U.S. Monthly Ending Stocks of Crude Oil + Total Petroleum Products
(excluding butane from the total made a difference in November because butane stocks decreased -10 million barrels)
Chart of crude oil on Twitter https://pbs.twimg.com/media/DVN7p0bWsAEqwQe.jpg
It’s not really a comparative tale, as we are now exporting a lot more crude and products since 2014. Are we above average, average, or below average based upon what’s going out, and what will be going out by June? As it is currently still going down, at a period of time it is normally increasing, my bet would be below “average”. Gasoline/diesel export is expected to increase this year, a bunch.
Feb 2nd, 2018 – S&P Global Platts Analytics estimates that excess stocks of oil in storage have largely already drained and that the rebalancing is more or less complete, taking into account the growth in demand over the last three years and line-fill volumes required for new infrastructure builds.
https://www.platts.com/latest-news/oil/london/analysis-opecs-success-may-be-its-own-undoing-26884372?
Chart https://pbs.twimg.com/media/DVRR30DXcAAJ7o9.jpg
EIA Year/Year Change in US Crude Oil Production & Net Imports.
PXD chart for their increase in oil exports
https://pbs.twimg.com/media/DVbJUzyW0AAlSLJ.jpg
Will be interesting to see if this goes ahead….
https://www.reuters.com/article/us-saudi-aramco-ipo/in-aramco-ipo-china-talks-crucial-for-choice-of-listing-venue-sources-idUSKBN1FL5BW
At best, production from one year old horizontals are going to produce in year two about one half of first year production. If 2017, we had about a 700 million barrel a day increase, those wells are going to be producing 350 million barrels. Logic would say that to increase it another 350 million barrels to equal 700 million, then we would have to up completion capacity by 50%. That doesn’t count other legacy declines. I think that is possible, but a stretch at $65, which it is likely to stay at until big draws starting in May.
I think production may look like it is increasing at a much faster rate the first quarter, like last year, but that was related to zipper fracs.
It sounds like the higher $WTI price is starting to make a difference in the Bakken…
2018-02-05 Hess Corp. plans to increase drilling & completions in the Bakken. Last year they drilled 85 wells, and brought 68 online. They’re adding rigs, from the 4 rigs running now to 6 by the end of the year. And this year they’re planning to drill 120 Bakken wells and bring 95 online.
2018-01-16 North Dakota oil production will set new oil output record sometime in the first half of 2018: Lynn Helms
Right now last week’s optimism about oil isn’t holding.
https://www.cnbc.com/2018/02/05/energy-stocks-head-for-worst-2-day-performance-in-2-years.html
Somebody did not program the computerized trade programs to have optimism. Massive amount of positive info on the economy, and the computers go into clinical depression. Are there any studies of serotonin levels in trade programs? Maybe, they have kept the hardware in cool dark places too long.
Dow has lost 1500+ points (actually close to 2000) in the last two trading sessions.
Tomorrow will be the test.
Sounds like Russia’s supply of light sweet grades might have reached some sort of limit, at least for now?
2018-02-05 – Reuters – The Russian energy ministry and oil pipeline monopoly Transneft both acknowledge the problem of weak Urals quality.
Data on Urals chemical composition, obtained by Reuters from industry sources, showed the oil exported to Europe this month is near the bottom end of the quality range allowed under a standard set by Russia’s state standards agency Rosstandart.
Russia’s energy ministry acknowledged that the quality of Urals had been declining for the past several years, but said that was due to the depletion of old oilfields.
https://uk.reuters.com/article/russia-oil-urals-quality/europe-shuns-russian-oil-as-boost-of-chinese-flows-hits-quality-idUKL8N1PS0KH
Started fracking at Yamal-Nenets
2018-02-05 Russia – Tazovsky region of the Yamal-Nenets – First deep oil well flows at 1,800 b/d at the Messoyakhaneftegaz, a joint venture between Rosneft and Gazprom Neft, completed the construction of the first operational horizontal well for deep layers of the East Messoyakhskoye field. The initial production rate of 250 tons of oil per day confirmed the high potential for the development of deep horizons of Messoyakhskoye fields.
After hydrodynamic and field-geophysical studies at Messoyakha, a multi-stage hydraulic fracturing of the formation will be carried out for the first time in such a well.
Messoyakhaneftegaz plans to commission ten more deep wells.
https://www.rosneft.ru/press/news/item/189659/
Alberta AER, more oil, the total production in December is up +73 kb/day month/month and +319 kb/day year/year. Storage tanks are filling, not sure how they are going to sell all this?
Platts chart – WCS discount to WTI: https://pbs.twimg.com/media/DVTv3TLW0AEG2ND.jpg
Alberta production split crude oil & bitumen: https://pbs.twimg.com/media/DVWKRj9WsAA_QAj.jpg
Alberta AER, Closing Inventories at 68 million barrels
Oil Sands Magazine puts Alberta oil storage capacity at 75 million barrels
http://www.oilsandsmagazine.com/projects/crude-oil-storage-terminals
GoM News: Stampede has been started up. They have most wells predrilled (plan is 6 producers on gas lift and 4 water injectors) so should ramp up fairly quickly, depending on overall availability.
I also had a look at gas production. Hadrian South has dropped about 80% of production since June, and not because of hurricanes as Lucius, through which it is produced, has been largely unaffected. By BOEM reserve estimates they are down to about the last 10% of gas. This is a bit earlier than predicted, but then they had been producing about 10 kboed more than originally planned at plateau. There’s also been a big chunk taken out from Llano and Baldpate/Salsa with the Enchilada pipeline disruption, but they were on quite steep decline anyway. All sectors shown below are in overall decline so next year could be 100 kboed down on this. I don’t know how Wood Mackenzie can predict overall growth in deep water oil and gas production through this year and next, given this trend.
Offshore Engineer has shut up shop. I thought one or two of the offshore magazines/blogs would have to close, but I didn’t expect that one. Sounds like they got flooded out and insurance didn’t pay up.
So, now inflation has “ reared its ugly head”, and workers and bond holders will demand higher incomes. Yes, that would affect the stock market negatively. My thought is, it’s way past time for that, so the “correction” is likely to continue. It will make it tough for the oil companies to raise money, and they will have to make incomes rise to get new workers. Maybe slowing production down. The strong will survive, the weak will perish. That will, ultimately, negatively affect the price of crude? If a recesssion hits, and we have demand of 1 million vs 1.7 million, will we still ever catch up on production? To be continued….
No evidence of inflation beyond that contrived. The wage numbers last week derived from shorter workweek, not pay raises.
Yeah, I would say contrived is the word most descriptive.
Watcher wrote: “No evidence of inflation beyond that contrived. ”
Not exactly considering the Dow was near 26K before this week’s selloff, Home & auto prices up. Investors and consumers snap up assets, mostly using debt. That said the increase in spending was exclusively cause by credit expansion, similar to the credit expansion of 2004-2008.
EIA Short-Term Energy Outlook released today
https://www.eia.gov/outlooks/steo/
World liquids production forecast for December 2018
They forecast an increase of +2.6 million barrels per day
Mostly due to the USA +1.6 million barrels per day, (US split: +1 mb/d crude oil +0.6 mb/d NGLs)
Canada +0.5 mb/d (If rail can take that much?)
Brazil +0.35 mb/d
Well to get to that, production will need to almost double, as the wells that were drilled last year will produce half. Most likely, legacy declines will need to be banned. Meaning that support services will need to increase by almost 100%. Canada would be willing to sell their oil for a song. Pipelines would need to be completed a year ahead of schedule, RRC will need to allow unlimited flaring, and so forth. It could happen for $55 a barrel, yeah I can see that.
The EIA has raised it’s US crude oil production estimates, they now see January 2018 higher than the weekly numbers. A chart to show the change between the January & February STEO forecasts
And yet crude inventories are drawing at the time of year when they usually increase the most…
EIA STEO – Crude oil inventories in the United States declined by 6 million barrels during the first four weeks of 2018 in contrast to a five-year average build of 14 million barrels during those four weeks.
https://www.eia.gov/outlooks/aeo/pdf/AEO2018_FINAL_PDF.pdf
Anadarko.
“However, he emphasized that extra money will go toward increasing shareholder dividend payouts and share buybacks rather than further trying to boost oil and gas production volumes.”
https://www.chron.com/business/energy/article/Anadarko-posts-1-billion-profit-from-tax-law-12556173.php
Anadarko own 50% of the Baldpate leases which have been hit with the Enchilada shutdown. They’ve reduced their capital spend for this year as a result. They only have about 300 mmbbls reserves undeveloped, a lot of which I think might be tied up with potential LNG offshore Mozambique; so they may not have many options for increasing production even if they wanted to. Nevertheless they are obviously being driven by shareholders more than most E&Ps at the moment and a lot of their recent announcements sound like coming from a company in gradual liquidation. The Enchilada losses also seem to be impacting Hess as they are still losing money, shedding jobs and trying to sell some assets.
Total are spending $5 billion on share buy backs. I’m pretty sure not so long ago they (but might have been ENI) were a bit disparaging of other majors doing buybacks and were promoting how they themselves were exploration and growth oriented.
WESTWOOD INSIGHT: WHY SO MANY OIL AND GAS PROJECTS FAIL TO PRODUCE AS PLANNED
https://www.westwoodenergy.com/news/westwood-insight/westwood-insight-many-oil-gas-projects-fail-produce-planned/
Partly an advert for their services, but it gives an indication of how risky oil investment for a known discovery can still be and/or how much needs to be spent on drilling to reduce the risk. Just about as many outperform us underperform – but this is still an issue as it means the CAPEX has been apportioned optimally.
International oil rig count at 737, up +7 month/month and +65 year/year
(without North America, also no data for onshore China)
Baker Hughes – International Rig Counts for Jan 2018
IEA – Oil Market Report – Table 3 – WORLD OIL PRODUCTION (includes NGLs)
International Offshore Rig Count – Baker Hughes
Twitter https://pbs.twimg.com/media/DVbhj1HWAAA0cws.jpg
You beat me to it, but the interesting figures for me are: 1) Saudi rig count decline appears to be accelerating for both oil and gas; 2) Offshore rigs still showing no sign of recovery – down 10 y-o-y, and actually another six if US is included.
NIGERIA TOPS COUNTRIES WITH LARGEST REMAINING DEEPWATER OIL RESERVES
Another way of looking at this is that all the deep water recoverable reserves in the top ten countries represent about 10 months of global production.
Mexico and Guyana should kick Australia and Ghana off the list sometime in the next couple of years.
Platts – OPEC’s crude production averaged 32.46 million b/d in January, a rise of 60,000 b/d from December, as gains by Saudi Arabia and Nigeria more than offset Venezuela’s continued slide in output, an S&P Global Platts survey showed Wednesday.
https://www.platts.com/news-feature/2017/oil/opec-guide/index
Table on Twitter https://pbs.twimg.com/media/DVboFloXUAA5Brm.jpg
Chart of Venezuela’s crude output
https://pbs.twimg.com/media/DVboryOWkAAZV1s.jpg
Shale Reality Check, update by David Hughes, partly in response to EIA latest AEO report, but must have been written before that came out.
http://www.postcarbon.org/wp-content/uploads/2018/02/Hughes_Shale-Reality-Check_Winter-2018.pdf
“A corporation cannot be ethical; its only responsibility is to turn a profit!”
— Milton Friedman, Chicago hoodlum
EIA is just speeding up when the price spike will occur with its BS.
What am I missing here? Why would you waste time banning something that’s not possible?
“We have an absolute right under our state police power to ban this practice before it ever starts,” Young said. “The time is now to do this. Let’s don’t wait until, as Sen. Simmons said, companies do start fracking and then you’ve got existing uses and you’ve got permits in place. We don’t want that. We want to stop it now before it can start.””
Does fracking have ANY application where there is no low clay shale? Or might there be some down deep?
http://www.pnj.com/story/news/politics/2018/02/06/senators-try-again-ban-fracking-florida/311389002/
Looks like there are a couple of potentials:
http://www.ogj.com/articles/print/vol-110/issue-3/exploration-development/sunniland-shale-an-emerging.html
From Link.
“This part of Florida commenced conventional oil production in the early 1940s from the upper part of the self-sourced Sunniland formation, a porous, early Cretaceous limey marlstone.”
I assume You can’t hydro-frack porous very well. I was under the impression (??) that frackable brittle low clay shale was unique to inland since it formed in freshwater beads.
Entire article did not copy. What they were looking at was the lower sunniland, which was shale, not limestone like the upper. Also, of interest was a lower shale called pumpkin, as I recall. Also,
https://pubs.usgs.gov/dds/dds-069/dds-069-a/REPORTS/SFB1995.pdf
I assume that FL legislature means to ban “high volume horizontal well fracks?”
I get worried at times when the blanket phrase “ban fracking” is used.
I pulled a ticket the other day on a well we drilled and completed during the high price period. We perforated 8’ of pay, acidized the well with 250 gallons and fractured the well with 3,000 gallons of water and 3,000 pounds of sand.
Two quick anecdotes along those lines.
1. Friend operator of ours could not get one small mineral owner to lease because he is “against fracking.” Owns less than 1% of minerals. Well frac would be similar to what I described above.
2. Another friend of ours cannot get a “Royalty company” located in Houston, TX to sign a lease because they are demanding no less than a 1/5 royalty and no less than $2,500 per net mineral acre. Again, own a small interest.
In both of the above cases, the mineral owners will be “non-consent” and will get nothing for years, if ever, just like the unfortunate souls who went non-consent in the Bakken.
So, let’s please differentiate between fracking vertical and horizontal, and between the “hot shale basins” where OPM is king v the conventional where operator cash rules.
we completed a well last month in the Woodford, 8 hr rate of 1100BOPD 41 gravity. just confirming (again)there is oil in the woodford in OKLA? this well is not unusual in the local area and and if it compares to older wells completed in the last year will produce +200,000BO in one year and @$60 per BBL payout will be ~10 months. well cost 9.5million. from a career standpoint being involved in such a project puts a big smile on this oil “person” face? ban fracking makes about as much sense as banning sex and drugs
Enjoy it while it lasts. Your business dies in 5 years.
I can do this math in my head and know that it doesn’t work. $2-$5 deduct, 75% NRI, $7k-13k per month loe, gas flaring, etc.
In Florida, they mean to ban fracking outright. They’ve got pretty fragile limestone bedrock there; they don’t want the fracking fluid to get anywhere near it. And we’ve learned not to trust the assurances regarding well linings, which are frequently shoddy. 🙁
The theft whereby landowners who don’t consent simply have their minerals stolen and their properties trashed anyway is really disgraceful. Hopefully the end of oil & gas will mean the end of this.
You are wrong. Shales are deposited in deep marine basins.
Very little notice is being given to EOG’s Eagles Ranch 14H-1 well targeting the Austin Chalk in Avoyelles parish, LA.
Depth has been reported as 16,700′ and 16,300 feet by different sources. Whichever is correct, that is a great accomplishment to drill and fracture a 5,000 lateral at those depths.
Initial production reports are positive. The upcoming quarterly conference call may provide more info.
The Tuscaloosa Marine Shale is below the AC in this area.
After drilling/completing 60 wells, the operators were just starting to crack the code when low pricing brought everything to a halt.
EOG has been drilling Austin Chalk in Karnes County Tex, with initial rates at over 5k bpd. Killer wells, with less decline rates less than Eagle Ford.
US ending stocks February 2nd
Crude oil up approx +1.9 million barrels
Oil products up +8.1 mb
Overall total, up +10 mb
Natural Gas: Propane & NGPLs down -6.6 mb
The total build in January, for oil + oil products is approx half the average build in the years 2015 to 2017
February and March are usually the big refinery turn around months. In the past EIA have issued a report on expected outages, but I don’t see one due in their list this year. This may have been a last splurge to increase product stocks though I have some doubts whether the actual storage numbers jump around like this or some of it’s just noise from the way the reports come in for such a short time scale.
For anyone new who wants to see the effect of refinery maintenance, gasoline stocks usually top in February. Although I guess this means that crude will build unless there is a decrease in net imports.
BEIJING, Feb 8 (Reuters) – China’s crude oil imports in January rose 20 percent year-on-year to a record 40.64 million tonnes, or 9.57 million barrels per day (bpd), according to data from the General Administration of Customs on Thursday.
https://www.reuters.com/article/china-economy-trade-oil/china-imports-record-crude-oil-volumes-in-january-idUSL4N1PY1UC
If they continue with this speed, they’ll burn any oil Texas Tea & Co can queeze out of the ground.
Guess that’s the main point, demand is far outpacing production. The EIA’s recent increase in weekly production would mean Texas would have had to increase production about 300k since November. Two months. Complete insanity. Even if they were able to increase a million barrels in 2018, it wouldn’t be enough. Cushing is at 37 million, so none of this is realistic. More EIA fantasy.
…especially when they keep up this speed several years.
Fracking and drilling is one thing – but after a certain point midstream has to expand by big numbers, too. And export ports. And water cleaning. And gas pipelines (or simply burn all this “useless” stuff) And intermediate store, the whole infrastructure. Double digit billion $ investments.
And that all for a few years until Permian core areas are drilled up – after this this crazy production speed will have to come down, simply because every new hole delivers less.
I agree. Very strange numbers being reported by ria since the hurricanes. What is going on?
Chinese are smart people. Gathering nuts for a very long winter. Obviously, the price is not too high to them, when the consider alternatives.
Chinese teapot refineries were approved increased import quotas for 2018. So this increase in import for January was to be expected. The quotas were increased due to high demand during 2H2017. There are som lag times working now affecting the market sooner or later, but hard to see EIA’s (or IEA) view on the oil market to be a very neutral one.
Thanks for the info Kolbeinh. So, it is pretty much for fairly current expected demand, not SPR. Its not neutral. It is designed to keep the price of oil low, so that the economy fairs better. Short sighted, though. Let the price of oil rise in a more natural manner, enabling capital to be input into longer term projects, other than US shale. $60 won’t be enough for shale or other high price sources, leaving us with a huge spike coming. Then, it will be high enough to develop, but the lead time may cause the economies to stumble quite a bit. Especially, when they realize that US shale will never get to where they are projecting, and that the winning lottery ticket they thought they were holding does not match with the winning number.
GuyM, hard to disagree with your thoughts.
When it comes to the China spike in imports, the most important two reasons would be that 1. chinese state owned refineries increased product exports (e.g. diesel) in the region and were unable to meet domestic demand towards the end of last year. 2. demand growth in China was stronger than expected in 2017.
And the third reason could be increased SPR, probably the least important reason. So the spike in imports makes sense; the increase is very high.
Reuters February 8th – U.S. crude flowing to Asia is a major trend in global oil trading
U.S. producers now export between 1.5 million and 2 million barrels of crude a day, which could rise to about 4 million by 2022. The nation’s output is expected to account for more than 80 percent of global supply growth in the next decade, according to Paris-based International Energy Agency.
Much of the increased flow will go to China, the world’s top importer and, since November, the largest buyer of U.S. crude other than Canada.
Chen Bo, president of Unipec – China’s largest buyer of U.S. crude – told Reuters that the firm expects to double U.S. imports this year to 300,000 bpd as it seeks to expand sales in Asia and find new customers for U.S. exports in other regions, including Europe.
Unipec – the trading arm of Asia’s largest refiner, state-owned Sinopec – is also considering long-term crude supply deals with U.S. pipeline and terminal operators. The firm may also partner with such firms to expand and improve U.S. export infrastructure, Chen said in an interview.
“U.S. crude flowing to Asia is a major trend in global oil trading,” Chen told Reuters.
Separately, China’s state-owned chemical and oil conglomerate Sinochem Group plans to open a trading office in Houston later this year to source U.S. crude for China’s independent refineries, five sources familiar with the plans told Reuters.
https://www.reuters.com/article/us-usa-oil-record-flows-analysis/texas-flood-u-s-oil-exports-pour-into-markets-worldwide-idUSKBN1FS0NP
It sounds like Venezuela has enough imported diluent for it’s oil production to continue?
2018-02-08 Reuters – PDVSA’s oil purchases – typically used for refining and blending its heavy crude for export markets – declined to almost none during the second half of last year as the company used most of its cash to pay bondholders and avoid a default.
PDVSA has received in recent weeks 1.73 million barrels of U.S. West Texas Intermediate and DSW crudes, and 1.44 million barrels of Russia’s Urals crude at Curacao’s Bullenbay terminal, according to the PDVSA’s internal data and Reuters vessel tracking data, almost the same volume imported in all of 2017.
https://www.reuters.com/article/us-venezuela-crude-imports-exclusive/exclusive-venezuela-resorts-to-swaps-to-get-oil-imports-for-curacao-refinery-idUSKBN1FS2UR?il=0
Wonder what happens to US shale if stock market implodes, bringing WTI down with it and slamming shale equity and debt.
Seems this could impact production forecasts for 2018 and 2019?
I think the production forecasts are already a farce. Oil price going down will reduce whatever production was being forecast for 2018. In the investment arena, perception is 90%, reality is 10%. So, if the perception is that inflation is rising, then money for new drilling just got more expensive. The stock market correction was long overdue, and markers of the economy appear strong. That doesn’t mean it will still not have an immediate, short term negative consequence to oil prices, and drilling. Obviously, it already has for oil prices. Upstream oil companies seem intent on shooting themselves in the foot, so they will keep losing feet, apparently.
Shallow,
I have been saying this for several months now. I believe we are going to see a serious correction in the markets. Unless the Fed changes its policy and starts QE4, oil prices will continue lower with the Stock market.
steve
I do also, but it is just observation of conditions around me.
https://oilprice.com/Latest-Energy-News/World-News/US-Looks-To-Sell-15-Of-Strategic-Petroleum-Reserve7201.html
About 10 trillion $? By then, less than a day’s worth of world consumption. But if we sell it all, we knock out the national debt, and have some left over to buy- more oil. Heck, if we can’t cut down on spending, we can always sell Alaska back to the Russians, the Louisiana Purchase back to the French, Texas and California back to Spain, or make a deal with England on the Eastern Seaboard. What about Fort Knox? World’s biggest garage sale! Good thing I am an independent, I can pass on voting Republican next time.
Heck, we won’t need it, we have the Permian to gush, forever, so I guess we have to keep Texas, or, at least, six counties in Texas that has more oil than ghawar.
It should be 10 billion. 100 million times $100 a barrel by then. Surely, not enough to pay off the national debt. So, maybey Fort Knox would help?
GuyM Wrote:
“00 million times $100 a barrel by then. Surely, not enough to pay off the national debt. So, maybey Fort Knox would help?”
No. the US has at least $70 Trillion in unfunded liabilities (mostly entitlements). Before the debt can be paid down, it need to cut and cap spending which I don’t think will ever happen. Recall that Spain was the richest country in the world about 500 years ago. It was producing vast amounts of Precious metals from the New World. It was also the biggest debtor and when bankrupt because it could not control its spending.
Fort Knox is mostly empty as the US gov’t sold off most of its gold reserves. Nixon removed the US from dollar gold reserve in 1971 when it couldn’t meet obligations.
There is no way out of the US’s financial problems without a default. It simply owes too much and has an aging population that is going to drag the economy for the next two decades.
Selling US Oil reserves won’t work because the US is dependent on them. The US would never get $100 bbl and if it sold oil it would depress oil prices. The winners would foriegn Oil consumers not US citizens. There is no way the strategic Oil reserve can payoff the national debt.
GuyM Wrote:
“we can always sell Alaska back to the Russians, the Louisiana Purchase back to the French, Texas and California back to Spain, or make a deal with England”
Selling of US land to broke nations would not work. England, Spain & France are dead broke, Russia economy is about the size of Italy and cannot possible afford to buy Alaska back.
So, this bullshit about “unfunded liabilities” and “entitlements” is flat out nonsense.
The US *prints money*. At the Bureau of Engraving and Printing. The US doesn’t owe *anything* denominated in any other currency.
“Debt” denominated in a currency you can print isn’t debt. It’s just money. T-bills are basically just money. Calling it debt is essentially fake. Congress could wipe out the “national debt” overnight with an accounting convention by replacing Treasury Bills with Treasury Notes.
The only risk of money-printing is inflation, but we aren’t printing nearly enough money to cause inflation.
Ok, new theory on using pending lease data file. Noted most was added to the second month of pending data, will small increment in third month. Goes along with RRC laws regarding when royalty owners are paid on new wells. Pulling current Oct production from the production file and adding it to the second month of pending lease data, I come up with 3,745, and EIA’s for Oct is 3,767. Oct current is when it was last reported when Nov production was reported, or two months of reporting. To be continued….