OPEC has just published their latest Monthly Oil Market Report with the June production numbers. All data is in thousand barrels per day and is Crude Only.
All revisions in the May data were minor. The June OPEC Crude Only production was down 80,000 bp/d from May.
The big story in June was the invasion or Iraq. It has has only minor effect on production. Iraqi production was down 169,000 bp/d in June.
OPEC’s largest produce and the World’s largest exporter, Saudi Arabia, increased Crude production by 48,000 bp/d in June. There has been very little change in Saudi production in the last nine months.
All other OPEC producers had very little change from May to June. Charts of all 12 OPEC nations can be found on the OPEC Charts page.
The big story this month comes from Russia.
The JODI data, through April 2014, shows Russia peaked in December at 10,127,000 bp/d and down only 50 kb/d since then. But the worst is yet to come.
Moscow has confirmed Russia is in decline!
From Tass: Russia expects decline of oil export revenue in 2016
MOSCOW, July 07. /ITAR-TASS/. Russian finance ministry predicts a 156.4 billion roubles ($4.5 billion) decline in 2016 oil export revenue from the earlier figure stipulated in the federal budget law for 2014 and the planned period 2015 and 2016, says the Ministry’s draft federal budget for 2015-2017.
The decrease is due to the expected fall in oil production to 193.4 million tonnes from 206.4 million tonnes.
In 2015, the budget will receive 78.9 billion roubles less than expected earlier, as export will contract to 195.4 million tonnes from 202.6 million tonnes.
Those production numbers make no sense and are an obvious error. Russian production, for the last 12 months, July through June has averaged around 1,440,000 tons per day. That comes to about 530 million tons per year. The numbers could be export numbers, I am not sure. Or, they could be production numbers from Rosneft because that is almost exactly what they are producing. Rosneft is Russia’s largest producer and is 75% owned by the state.
It looks like both Jodi and the EIA, to convert tons to barrels, are using a number very close to 7 barrels per ton. The usual multiplier of 7.3 gives a number about 450,000 barrels per day higher than they are reporting.
And from UPI: Russian oil production expected to drop
MOSCOW, July 7 (UPI) –An anticipated drop in oil production by 2016 is expected to hurt the Russian economy, the Russian Finance Ministry said Monday.
The ministry said Monday it expects a $4.5 billion decline in oil export revenue because of an anticipated 6.3 percent drop in oil production from 2014 figures.
The ministry said the federal budget next year will receive about $2.2 billion less than expected because of a contraction in exports.
A report on the Russian economy from the World Bank in March said real gross domestic product growth in 2013 was 1.3 percent, compared with 3.4 percent in 2012. There’s a “confidence crisis” emerging within the Russian economy, the bank warned.
“In the past, the lack of comprehensive structural reforms was masked by a growth model based on large investment projects, continued increases in public wages, and transfers — all fueled by sizable oil revenues,” it said.
Russian energy exports last year accounted for more than 10 percent of GDP.
Unfortunately the EIA Russian export data only goes through 2010. However that is enough to show us what is happening. While Russian production kept rising Russian Exports kept falling. Notice that the left axis is exactly half the scale as the left axis. In 2010 Russia exported almost exactly half their production. And while production kept rising until peaking in 2013-2014, it is a good bet that exports kept falling. And we know, from the horses mouth, that they will fall considerably in the next two years. This is the Jeffrey Brown’s Export Land Model in action.
Russia reports daily oil production from their Central Dispatching Department.They report 5 days a week but I get six days by how much they gain or dropped on Monday. So the 25 day average is about one month. The huge spike down in July is not likely anything permanent. They do that from time to time. But this is the largest spike I have ever seen.
The above chart is for 2014 only. They dropped slightly every month except June. There was a very slight uptick in June but it looks like July will be a big down month. I am counting seven barrels per ton and get about the same figures as the EIA and JODI. However that may not be the exact multiplier I should be using.
Fossil industry is the subprime danger of this cycle
The epicentre of irrational behaviour across global markets has moved to the fossil fuel complex of oil, gas and coal. This is where investors have been throwing the most good money after bad.
The cumulative blitz on exploration and production over the past six years has been $5.4 trillion, yet little has come of it. Output from conventional fields peaked in 2005. Not a single large project has come on stream at a break-even cost below $80 a barrel for almost three years.
“What is shocking is that upstream costs in the oil industry have risen threefold since 2000 but output is up just 14pc,” said Mark Lewis, from Kepler Cheuvreux. The damage has been masked so far as big oil companies draw down on their cheap legacy reserves.
“They are having too look for oil in the deepwater fields off Africa and Brazil, or in the Arctic, where it is much more difficult. The marginal cost for many shale plays is now $85 to $90 a barrel.”
Comments from a Landman
This past week I have been communicating with a Landman, now an independent but worked for several years for a major oil company. He has asked to remain anonymous and also not to name the major oil company he worked for. So I will just call him “Landman” and his company “Big Oil”. Apparently most of his career has been spent working the Permian Basin. Also, Landman’s comments seem to confirm what is conveyed in the above article. That is that there is a lot of irrational behavior going on in the oil patch.
I became interested in peak oil while I was trying to understand what happened to my natural gas business. I never saw the shale gas train coming and it hit me right between the eyes. Then I started reading everything that Art Berman published and that led me to the Oil Drum which led me to your blog.
The last 5 years have been pretty dismal in the gas business and I don’t play with borrowed money.
Peak oil became apparent to me when I started to grasp the ramifications of the proved reserve reports by the industry in their SEC 10k filings. Ultimately proved reserves pay all the bills in the oil patch.
I worked 18 years for Big Oil. Booked Reserve replacement was a very rigorous, conservative and disciplined process. Significant new field discoveries (100 MM BBL elephants) happened about 10 years apart in North America. I am only aware of 2 during my career and both were natural gas.
As a general rule, Big Oil replaced it’s produced reserves every year. But reserve replacements happened mostly because the reservoir engineers used field extensions, step out wells, and behind pipe pay zones to replace the produced reserves.
It was the legacy fields in the Permian Basin that financed Big Oil’s international, Alaskan and OCS exploration efforts. That could only happen with a strong balance sheet.
Every 35 year career geologist and engineer that I know and work with in the Permian Basin knows that the 90% of the horizontal wells completed today are not economic. But these wells are not dry holes either and industry is very good at parsing their press releases.
A good seat of the pants criteria for evaluating an unconventional resource play is to ask where and how many good vertical wells have been drilled in the play over the years.
If you can’t find historical, economic wells with solid cumulative production, then technology is not likely to save your ass.
And another post:
I want to clarify that the 2 100 mm bbl discoveries I mentioned were in the Onshore Lower 48. Big Oil also found smaller discoveries in the Lowe 48 that helped the reserve replacement. Big Oil also found many larger discoveries in the OCS ( Outer Continental Shelf and Deep Water).
When I started, Big Oil Upstream was divided into an Exploration Department and Production Department.
The Land Department was part of the Exploration Department but provided land services to the production department as needed. Each had their own budgets for drilling wells. If exploration made a discovery, it had to prove to the production department that it was commercial. That was done by drilling additional confirmation wells maybe shooting more seismic, and log and core analysis of the reservoir rock.
It the discovery was commercial,the asset was transferred to the Production department for development.
If the production department was not convinced the discovery was commercial it would not accept the asset. Non commercial assets might be retained if no additional costs were incurred but more frequently farmed out to smaller independents.
The arguments could be fiercely contested since management bonuses depended on the outcome.
Most years Big Oil replaced just a few % more than it produced. But if the reservoir engineers were too liberal in their interpretations, then next year could be a real SOB for reserve replacement. So I think they they always kept a little in their back pockets for the lean years. That is just my opinion for what it’s worth.
Big Oil also had major legacy assets in other areas of the lower 48 that helped pay the bills in the frontier and international areas.
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