Baker Hughes Incorporated announced today that the international rig count for January 2010 was 1,047, up 23 from the 1,024 counted in December 2009, and up 3 from the 1,044 counted in January 2009.
So despite the rash of announcement last year concerning budget cuts, we are back to where we were in January 2009. This shows that the impact of falling oil prices on upstream activity was only a temporary blip.
Interestingly however, the situation in the USA is not the same.
The US rig count for January 2010 was 1,267, up 95 from the 1,172 counted in December 2009 and down 286 from the 1,553 counted in January 2009.
This probably reflects the growing importance of natural gas in the US. With prices of that commodity still at very low levels, it may take a lot longer for drilling activity to recover.
BP Delivers on Promises in “Very Good” 2009 as 4Q Profits Jump 70 per cent
BP today reported a sharp year-on-year increase in fourth quarter profits as it announced that its oil and gas production increased by more than four per cent in 2009 and the company continued its industry-leading 17-year run of increasing reserves.
It was no doubt a good result, but the market was expecting more.
“They have disappointed relative to some reasonably high expectations,” said Christopher Wheaton, who manages about $400 million at Allianz RCM’s Energy Fund in London. “What’s really disappointing is the refining business, which has struggled.”
Complex energy conglomerates like BP are of course difficult to understand. However, the shortfall came from a fairly unsurprising place.
The miss was mainly due to BP barely breaking even in its refining business, one of the most advanced in the industry. Analysts had expected a weak quarter after average margins fell to their lowest level since the first quarter of 1995, but BP said its margins were even weaker than the average.
After the bumper profits of recent years, it is getting difficult to please the markets and the refining side of the business is really in the doldrums. BP has announced further cost cutting plans, but does not seem to be looking at disposals. To me this seems like the right strategy long term as the current market is oversupplied with refineries seeking new homes.
As I have said before, even as these companies generate Billions in profits, they face a very difficult future, and only the best run will be able to perform.
This news is from about a week ago, but I found it interesting on a number of levels.
KBR announced today that it has signed a Collaboration Agreement with BP to promote, market, and execute licensing and engineering services for the slurry bed residue and coal upgrading Veba Combi Cracker (VCC) Technology.
The first reason why I find it interesting is that this is a technology without a real track record, yet KBR thinks it worth investing in.
Until now there has only been one VCC plant in the world. It was subsequently shut down in 2000 due to unfavourable economic conditions.
There is another reason why it sound interesting.
VCC Technology is a hydrogen addition technology suitable for processing residuum into high-quality distillates or synthetic crude oil in the refining, upstream field upgrading and coal-to-liquids
It seems to be able to handle a huge range of feedstocks, which is not the case for the most popular deep cracking technology, coking.
Another advantage is the conversion rate. With the addition of hydrogen, the yield can exceed 100% of the feed, and there is no low value coke.
Given the increasing importance of heavy oils and perhaps coal as a feedstock, I am sure that KBR sees this first and foremost as an upstream upgrading technology. However, if proven there is big potential in refining as well, where the maximisation of high value products is paramount, and where petrocoke may one day be very difficult to dispose of.
My last post was on the potential of Venezuela’s heavy oil reserves. As if by magic, almost immediately we have news of a major new development. ENI and PDVSA are to form a Joint Venture to exploit a major heavy oil field.
Under the terms of the agreement, which will be finalized in the next 60 days and submitted to the relevant approvals, PDVSA will hold 60% and Eni 40% of a joint venture company (Empresa Mixta ) to develop the Junin 5 field which has 35 billion barrels of certified oil in place.
Despite the blusterings of Venezuela’s Caudillo, the country needs the knowhow of foriegners in order to exploit these reserves. This is made explicit in this deal.
The Technology Agreement will also provide PDVSA access to Eni’s gas shale experience in the US Barnett basin.
It is this knowledge that opens the door for ENI in this very difficult market. It is intellectual capital that will drive oil company profits in the future, including lots of knowledge that is not actually patentable, and resides in the grey matter of the operational staff. As such, the market has changed from one where access to reserves is the key, and this has major consequences for everyone in the business.
In a move likely to cause sleepless nights in Caracus, The U.S. Geological Survey has reassessed the size of recoverable reserves in Venezuela’s Orinoco Belt, and pronounced them much bigger than before.
The U.S. Geological Survey estimated a mean volume of 513 billion barrels of technically recoverable heavy oil in the Orinoco Oil Belt Assessment Unit of the East Venezuela Basin Province; the range is 380 to 652 billion barrels. The Orinoco Oil Belt Assessment Unit thus contains one of the largest recoverable oil accumulations in the world.
The reserves have not been exploited, originally due to their uneconomic nature. High oil prices combined with improving technology have changed the landscape however, and Venezuela is trying to put them back in play.
Recovery factor, or that percentage of the OOIP that is determined to be technically recoverable, was estimated from what is currently known of the technology for recovery of heavy oil in the Orinoco Oil Belt AU and in other areas, particularly California, west Texas, and western Canada.
As the recovery factor has gone up, so therefore have the size of the reserves.
The maximum recovery factor was estimated to be 70 percent, on the assumption that other recovery processes, in addition to horizontal drilling and steam-assisted gravity drainage, might eventually be applied on a large scale.
Once again, as if we needed reminding, reserves depend on technology as well as geology.
It is also a reminder that our future energy requirements depend on ever more difficult to recover crude. In such a market, technology leadership is where the money is. Its not what you have but what you can do with it that matters.
“I believe we have an opportunity to sit down as a cabinet and have that discussion and say, ‘As this thing starts to crank up again, are we going to change our policy of come one, come all into the development of the oil sands?”
This created a huge amount of discussion. Alberta has gained massively from oil sands development recently and stands to continue to do so in the future.
The problem that the minister wishes to address however is the volatility of activity. In the last couple of years, the oil sands patch has gone from boom to bust. This was primarily due to oil prices. However, it is also due to the massive inflation in costs that went together with the boom, costs that could not be borne as oil prices fell.
The idea seems to be that by controlling investment, this volatility can be decreased. The suggestion is generating a lot of criticism. This is a very relevant one.
That gets into a very tricky situation for government, if that is the case, just simply because they’ll be put into a position to determine why some projects should proceed ahead of others
The idea is not without its merits, but in practise it is just not going to work.
The problems that were created by the boom, were primarily shortages of things like labour, and lack of infrastructure capacity. When looking at how royalties are paid, and what is done with the income, perhaps the provincial government could do more to tackle these problems, rather than try to slow development. In fact the current slow down gives a great opportunity to reassess what could be done better.
It would be a shame if the current opportunity were to be missed, as better management of the next boom would ensure that the benefits better extend to everyone in the province.
Today’s theme is Brazil, simply because a number of unrelated stories nicely illustrate the rise of that country as an energy giant. Brazil is the most fashionable thing in the industry.
First up we have an update on drilling in the sub salt, by one of the fortunate first movers.
BG Group (25%) and partners Petrobras (65% and operator) and Galp (10%) have announced the conclusion of the formation test on the Iara well (1-BRSA-618-RJS or 1-RJS-656) in the BM-S-11 appraisal area in the Santos Basin pre-salt, offshore Brazil.
The tests proved the exploration potential of the area by producing light 28° API oil and confirmed the estimated recoverable volumes for Iara to be in the order of 3 to 4 billion barrels of light oil and natural gas
There have been many rumours and conspiracies over the size or availability of these reserves, so good news is welcome.
The daddy in that partnership is in the news for other reasons as well. On one hand it is expanding refining capacity.
A ceremony that will include President Luiz Inacio Lula da Silva will mark the start of construction at Bacabeira in the northern state of Maranhao, Petrobras said. Work on the refinery is expected to be completed in September 2013.
Brazilian state energy giant Petroleo Brasileiro is in talks to buy a stake in Portugal’s Galp Energia, Mines and Energy Minister Edison Lobao confirmed Wednesday.
This would give Petrobras a entrance into the downstream market in Europe. However Petrobras is being coy.
Petrobras, whishes to clarify the news published by the Brazilian and international press regarding: potential acquisition of the stakes held by ENI S.p.A. in Galp Energia; possible partnerships with Galp Energia in the exploration segment; and contracts for oil products distribution in Europe. The Company clarifies that it is always analyzing investment opportunities in Brazil and abroad that are aligned to the strategies set forth in its Business Plan, but that in this case there is no negotiation in progress.
As they have pursued Galp in the past, there is probably something going on.
Meanwhile, the company has released its reserve data for 2009.
On December 31st, 2009 Petrobras’ Proved Reserves of oil, condensate and natural gas amounted to 14.865 billion barrels of oil equivalent (boe), a decrease of 1.5% in relation to last year figures.
The number will no doubt rise as they continue to work in the subsalt.
A few years ago, few peopl outside the industry had ever heard of Petrobras. In a few years time, you will be hard pressed to find someone who is ignorant of them.
We are familiar with the plotline. In the middle of winter, Russia demands higher prices for its energy exports to its neighbour, and threatens to shut the pipeline if its demands are not met.
Russian oil flows to one of two Belarussian refineries could be suspended within 24 hours because oil firms are unwilling to confirm volumes due to a ongoing pricing dispute, Russia’s pipeline monopoly said.
Once again, we see that Russia sees energy as a source of power, not just a business. The dispute is not just a problem for Belarus either.
Last year, Moscow allowed Minsk to import 20 million metric tons of oil, of which 14.5 million metric tons Minsk re-exported to Europe.
“This is a bilateral dispute between Russia and Belarus. The European Commission expects all sides to honor the commitments both in terms of transit and oil supplies to European citizens,” said Mark Gray, a spokesman for the European Commission.
The European Union receives about 10 percent of its oil via the Druzhba pipeline, which crosses Belarus.
Once again, Eastern and Central Europe may see supply problems.
As always, the Russian argument is not without its merits, and there is no reason why Russia should subsidise cheap energy to its neighbours. However, Russia is cleary abusing its position in order to increase its control over the energy markets. The signal that it is sending out to Europe (if its boneheaded politicians will listen) is that Russia cannot be trusted.
McMoRan Exploration Co. announced today a discovery on its Davy Jones ultra-deep prospect located on South Marsh Island Block 230 in approximately 20 feet of water.
In shallow water, but at great depth below the sea bed, is a huge reserve just waiting to be exploited.
McMoRan’s Co-Chairman, James R. Moffett, said: “Davy Jones log results confirm our geologic model and indicate that the previously identified sands in the Wilcox section on this large ultra-deep structure encompassing four OCS lease blocks (20,000 acres) provides significant additional development potential which, upon confirmation development drilling, could make Davy Jones one of the largest discoveries on the Shelf of the Gulf of Mexico in decades.
With the volume of oil imports that the USA is making, any new discovery is welcome. It seems unbelievable that so much of the US coastal area is off limits. Who knows what might be discovered otherwise.
Rig count numbers are out for December 2009.Though down on a year ago, the rig count continues to grow as companies have overcome their reluctance to invest upstream.
The worldwide rig count for December 2009 was 2,509, up 100 from the 2,409 counted in November 2009 and down 712 from the 3,221 counted in December 2008.
Interestingly, by far the biggest YonY variation was in the USA, down 34%, versus a worldwide (excluding the US) total of just 7%. So we can see that drilling in the USA is far more price sensitive than elsewhere.
