Hedge Funds have been ‘contangoed’

Recent events may have pushed the Brent front month futures contract back towards US$108 per barrel; but there's no denying some have been 'contangoed'! Ukrainian tensions and lower Libyan production are hard to ignore, even if the latter is a bit of a given.

Nonetheless, for a change, the direction of both benchmark prices this month indicates that July did belong to the physical traders with papers traders, most notably Hedge Funds, taking a beating.

It's astonishing (or perhaps not) that many paper traders went long on Brent banking on the premise of "the only way is up" as the Iraqi insurgency escalated last month. The only problem was that Iraqi oil was still getting dispatched from its southern oil hub of Basra despite internal chaos. Furthermore, areas under ISIS control hardly included any major Iraqi oil production zone.

After spiking above $115, the Brent price soon plummeted to under $105 as the reality of the physical market began to bite. It seems European refiners were holding back from buying the expensive crude stuff faced with declining margins. In fact, North Sea shipments, which Brent is largely synced with, were at monthly lows. Let alone bothering to pull out a map of Iraqi oilfields, many paper traders didn't even bother with the ancillary warning signs.

As Fitch Ratings noted earlier this month, the European refining margins are likely to remain weak for at least the next one to two years due to overcapacity, demand and supply imbalances, and competition from overseas. Over the first half of 2014, the northwest European refining margin averaged $3.3 per barrel, down from $4 per barrel in 2013 and $6.8 barrel in 2012.

Many European refineries have been loss-making or only slightly profitable, depending on their complexity, location and efficiency. They are hardly the sort of buyers to purchase consignments by the tanker-load during a mini bull run. The weaker margin scenario itself is nothing new, resulting from factors including a stagnating economy and the bias of domestic consumption towards diesel due to EU energy regulations

"This means that surplus gasoline is exported and the diesel fuel deficit is filled by imports, prompting competition with Middle Eastern, Russian and US refineries, which have access to cheaper feedstock and lower energy costs on average. Mediterranean refiners are additionally hurt by the interruption of oil supplies from Libya, but this situation may improve with the resumption of eastern port exports," explains Fitch analyst Dmitry Marinchenko.

Of course tell that to Hedge Funds managers who still went long in June collectively holding just short of 600 million paper barrels on their books banking on backwardation. But thanks to smart, strategic buying by physical traders eyeing cargoes without firm buyers, contango set in hitting the hedge funds with massive losses.

When supply remains adequate (or shall we say perceived to be adequate) and key buyers are not in a mood to buy in the volumes they normally do down to operational constraints, you know you've been 'contangoed' as forward month delivery will come at a sharp discount to later contracts!

Now the retreat is clear as ICE's latest Commitments of Traders report for the week to July 15 saw Hedge Funds and other speculators cut their long bets by around 25%, reducing their net long futures and options positions in Brent to 151,981 from 201,568. If the window of scrutiny is extended to the last week of June, the Oilholic would say that's a reduction of nearly 40%.

As for the European refiners, competition from overseas is likely to remain high, although Fitch reckons margins may start to recover in the medium term as economic growth gradually improves and overall refining capacity in Europe decreases. For instance, a recent Bloomberg survey indicated that of the 104 refining facilities region wide, 10 will shut permanently by 2020 from France to Italy to the Czech Republic. No surprises there as both OPEC and the IEA see European fuel demand as being largely flat.

Speaking of the IEA, the Oilholic got a chance earlier this month to chat with its Chief Economist Dr Fatih Birol. Despite the latest tension, he sees Russian oil & gas as a key component of the global energy mix (Read all about it in The Oilholic's Forbes post.)

Meanwhile, Moody's sees new US sanctions on Russia as credit negative for Rosneft and Novatek. The latest round of curbs will effectively prohibit Rosneft, Novatek, and other sanctioned entities, including several Russian banks and defence companies, from procuring financing and new debt from US investors, companies and banks.

Rosneft and Novatek will in effect be barred from obtaining future loans with a maturity of more than 90 days or new equity, cutting them off from long-term US capital markets. As both companies' trade activities currently remain unaffected, Moody's is not taking ratings action yet. However, the agency says the sanctions will significantly limit both companies' financing options and could put pressure on development projects, such as Novatek's Yamal LNG.

No one is sure what the aftermath of the MH17 tragedy would be, how the Ukrainian crisis would be resolved, and what implications it has for Russian energy companies and their Western partners. All we can do is wait and see. That's all for the moment folks. Keep reading, keep it 'crude'!

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© Gaurav Sharma 2014. Photo: Oil pipeline © Cairn Energy

That other Canadian pipeline project

As its Keystone XL pipeline project continues to remain stuck in the quagmire of US politics, TransCanada gave details about plans to build a pipeline from Western Canada to Eastern Canada.

 

The so-called TransCanada Energy East line would have the capacity to bring 1.1 million barrels per day (bpd) of the crude stuff from the resource rich western provinces to refiners in the east. The idea is to replace foreign imports for the refineries in Quebec (as much as 92% in the state) and Atlantic Canada.

 

The pipeline, which would cost CAD$12 billion, shall run from Hardisty, Alberta, to a new receptor terminal in St John, New Brunswick. Upon completion, not only will the project reduce reliance on Middle Eastern and East African imports (thought to be in the region of 750,000 bpd for Atlantic Canada), but St John could actually become an exporting terminal for unused surplus. For all intents and purposes, this would be a colossal endeavour. Surely, the approval process won’t be as slow as Keystone XL, as the project enjoys support in the Canadian corridors of power and finds flavour with the public at large. Furthermore, the TransCanada Energy East pipeline would link about 3,000km of an already-built natural gas pipeline with roughly 1,400km of newly constructed pipeline.

 

A spokesperson for TransCanada said the company was confident of supplying oil to Quebec refineries by late 2017 and further on to New Brunswick by 2018. At a press conference detailing the plans, TransCanada's Chief Executive Russ Girling said, "This is a historic opportunity to connect the oil resources of western Canada to the consumers of eastern Canada, creating jobs, tax revenue and energy security for all Canadians for decades to come."

 

Indeed Sir! Reversing the east coast oil deficit into an export surplus would be one hell of 'crude' story. Canadian oil production is tipped to more than double by 2025 from its current level of 1.5 million bpd. Everyone from Saudi Arabia to the Venezuela is casting a nervous eye on Canada’s rise while domestic realisation is spurring projects such as the East to West pipeline. However, the Obama administration remains oblivious, or shall we say exceedingly slow, in letting the USA respond to this seismic shift by approving Keystone XL!

 

A summer approval was expected but has not materialised so far. Instead we are told that the US State Department will issue a final report on the project before the end of the year. On a related note, a report published by Moody’s late last month noted that most Canadian E&P companies are protected from volatile price differentials for heavy oil.

 

To provide context, the heavy oil differential is the difference in price between WTI, and the price at which heavy oil is sold, most commonly referenced to the Western Canadian Select (WCS) benchmark. These discounts have been volatile and sometimes pretty wide, especially since Q2 2012.

 

"We expect the differential to remain highly volatile. Even so, most producers of Canadian heavy oil draw some protection from their diverse products, low cost structures, or integration," said Moody's Senior Vice President Terry Marshall.

 

"The possible lack of significant new pipeline capacity to reach export markets and eastern Canadian refineries will have an impact on the growth of Canadian oil producers and will likely widen our $20 assumption for the differential," Marshall added. "This uncertainty will be a key consideration in upward rating movements for Canadian producers until the addition of incremental takeaway capacity is apparent."

 

According to the ratings agency, the pure bitumen producers such as MEG Energy and Connacher Oil and Gas will remain the hardest hit by wide differentials, because highly dense bitumen requires about 35% dilution and condensate generally sells at prices above WTI. The diluted bitumen then sells at the price of heavy oil.

 

Mining oil sands operations that upgrade their bitumen, such as those held by Canadian Oil Sands Limited (COSL), Canadian Natural Resources Limited (CNRL) and Suncor Energy, have no exposure to the heavy oil differential. That's because these operations produce synthetic crude oil (SCO), a light oil product that trades around WTI prices.

 

According to Moody’s, companies that produce a high component of heavy oil, such as Baytex Energy, lie between these two extremes, with full exposure to the differential, but minimal need to buy costly diluent in order to ship their product.

 

The largest companies, including CNRL, Suncor Energy, Husky Energy and Cenovus Energy, sell a diverse mix of products, limiting their exposure to the differential, the agency noted. Furthermore, Suncor, Cenovus and Husky all draw an additional advantage from mid-continent downstream refinery operations, which benefit from wide differentials.

 

The discount on the heavy crude reflects a supply and demand relationship based on the available heavy oil refinery capacity, and infrastructure constraints and bottlenecks, Moody's noted.

 

As heavy, light oil and SCO all utilise the same finite pipeline space, a back-up in the system affects all products to varying degrees. For what it’s worth, this underscores the importance of TransCanada’s latest pipeline foray.

 

Away from Canada, the US EIA says the country’s crude oil output could exceed imports as early as October; the first such instance since February1995. In its monthly Short-term Energy Outlook, the EIA also said US crude oil production increased to an average of 7.5 million bpd in July 2013; the highest monthly level since 1991.

 

The report also raised its forecast for Brent, and noted that spot prices will average US$104 a barrel over the second half of 2013, marginally above the $102 forecast last month. The forecast for 2014 was left unchanged at $99.75 per barrel. WTI will average $96.96 a barrel this year, the EIA said, up from the July projection of $94.65. The US benchmark grade will average $92.96 in 2014, up from the previous month’s estimate of $91.96. That’s all for the moment folks! Keep reading, keep it ‘crude’!

 

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© Gaurav Sharma 2013. Photo: Oil Refinery, Quebec, Canada © Michael Melford / National Geographic.

Hawaii’s crude reality: Being a petrohead costs!

In a break from the ‘crude’ norm for visits to the USA, the Oilholic packed his bags from California and headed deep out to the Pacific and say ‘Aloha’ to newest and 50th United State of Hawaii. It’s good to be here in the Kona district of the Big Island and realise that Tokyo is a lot closer than London.

It is interesting to note that Hawaii is the only US state still retaining the Union Jack in its flag and insignia. The whole flag itself is a deliberate hybrid symbol of British and American historic ties to Hawaii and traces its origins to Captain John Vancouver – the British Naval officer after whom the US and Canadian cities of Vancouver and Alaska’s Mount Vancouver are named.

What’s not good being here is realising that a 1.3 million plus residents of these northernmost isles in Polynesia pay the most for their energy and electricity needs from amongst their fellow citizens in the US. It is easy to see why, as part dictated by location constraints Hawaii presently generates over 75% of its electricity by burning Petroleum.

Giving the geography and physical challenges, most of the crude oil is shipped either from Alaska and California or overseas. Furthermore, the Islands have no pipelines as building these is not possible owing to volcanic and seismic activity. Here’s a view of one active crater – the Halema’uma’u in Kilauea Caldera (see above right). You can actually smell the sulphur dioxide while there as the Oilholic was earlier today. In fact the entire archipelago was created courtesy of volcanic eruptions millions of years ago. The Big Island’s landmass of five plates is created out of Mauna Kea (dormant) and Mauna Loa (partly active) and the island is technically growing at moment as Kilaueu still spews lava which cools and forms land.

So both crude and distillates have to be moved by oil tankers between the islands or tanker lorries on an intra-island basis. The latter  creates regional pricing disparities. For instance in Hilo, the commercial heart of the Big Island and where the tanker docking stations are, gasoline is cheaper than Kona by almost 40-50 cents per gallon. The latter receives its distillates by road once tankers have docked at Hilo.

The state has two refineries both at Kapolei on the island of O‘ahu 20 miles west of capital Honolulu – one apiece owned by Tesoro and Chevron. The bigger of the two has a 93,700 barrels per day (bpd) and is owned by Tesoro; the recent buyer of BP’s Carson facility. However in January Tesoro put its Hawaiian asset up for sale.

Tesoro, which bought the refinery for US$275 million from BHP Petroleum Americas in 1998, said it no longer fitted with its strategic focus on the US Midcontinent and West Cost. The company expects the sale to be completed by the end of the year. Its Hawaiian retail operations, which include 32 gas stations, will also be part of the deal. Chevron operates Kapolei’s other refinery with a 54,000 bpd capacity. Between the two, there is enough capacity to meet Hawaii’s guzzling needs and the pressures imposed by US forces operations in the area.

In this serene paradise with volcanic activity and ample tidal movement, power generation from tidal and geothermal is not inconceivable and facilities do exist. In fact, for the remaining 25% of its energy mix, the state is one of eight US states with geothermal power generation and ranks third among them. Additionally, solar photovoltaic (PV) capacity increased by 150% in 2011, making Hawaii the 11th biggest US state for PV capacity. However, it is not nearly enough.

One simple solution that is being attempted is natural gas – something which local officials confirmed to the Oilholic. The EIA has also noted Hawaii’s moves in this direction. Oddly enough, while Hawaii hardly uses much natural gas, it is one of a handful of US states which actually produces synthetic natural gas. Switching from petroleum-based power generation to natural gas for much of Hawaii’s power generation could lower the state’s power bills considerably as the massive disconnect between US natural gas and crude oil prices looks set to continue.

Strong ‘gassy’ moves are afoot and anecdotal evidence here suggests feelers are being sent out to Canada, among others. In August, Hawaii Gas applied for a permit with the Federal Government to ship LNG to Hawaii from the West Coast. While the deliveries will commence later this year, arriving volumes of LNG would be small in the first phase of the project, according to Hawaii Gas. At least it is a start and the State House Bill 1464 now requires public utilities to provide 25% of net electricity sales from renewable sources by December 31, 2020 and 40% of net electricity sales from renewables by December 31, 2030.

That’s all for the moment folks as the Oilholic needs to explore the Big Island further via the old fashioned way which requires no crude or distillates – its the trusty old bicycle! Going back to history, it was Captain James Cook and not Vancouver who located these isles for the Western World in 1778. Regrettably, he got cooked following fracas with the locals in 1779 and peace was not made between Brits and locals until Vancouver returned years later.

Moving away from history, yours truly leaves you with a peaceful view of Punaluʻu or the Black Sand beach (see above left)! It is what nature magnificently created when fast flowing molten lava rapidly cooled and reached the Pacific Ocean. According to a US Park Ranger, the beach’s black sand is made of basalt with a high carbon content. It is a sight to behold and the Oilholic is truly beholden! On a visit there, you have a 99.99% chance of spotting the endangered Hawksbill and Green turtles lounging on the black sand. For once, yours truly is glad there are no bloody pipelines in the area blotting the landscape. More from Hawaii later - keep reading, keep it ‘crude’!

© Gaurav Sharma 2012. Photo 1: Halema’uma’u, Kilauea Caldera. Photo 2: Punaluʻu - the Black Sand beach, Hawaii, USA © Gaurav Sharma 2012.

Talking geopolitics & refineries at Platts event

Following on from earlier conversations with contacts in the trading community about the direction of the Brent crude price versus geopolitics, the Oilholic extended his queries to the Platts Energy Risk Forum, held in London earlier this week. At the event, Dave Ernsberger, global editorial director of oil coverage at Platts, summed-up the market mood as we near the final quarter of 2012 (see graphic above, click to enlarge). “This year has been one of two realities, namely the dire economic climate and upward geopolitical risk. H1 2012 saw anxiety about a war in the Middle East and H2 sees renewed fears of a demand slowdown,” he told delegates.

“The oil price is poised to break away from the mean – but which way? So far it has been chained and shackled in the US$15-20 range either way falling below US$90 and rising above US$115 over the course of this year. The threat of an Iran versus Israel conflict which might draw the US in by default has not gone away. On the other hand a European recession could bring a new oil price crash. Additionally, there is a perception that supply-demand and spare capacity scenarios are not what they are made out to be,” Ernsberger added.

Over a break in proceedings, the Oilholic quizzed the Platts man about the actual influence of the geopolitical or instability premium on the price of the crude stuff and market conjecture about it being broadly neutral for 2013.

“I think the current geopolitical dynamic is fairly well understood at this point. The big touching points which are at play for instance, but not limited to, the US-Iran-Israel issue and the China-Japan and Asia Pacific energy politics have been with us for a while. I feel it is hard to see how those geopolitical arenas will evolve significantly in 2013 because we are at a stalemate point. In a sense, if you look forward they should be neutral,” Ernsberger said.

However, both of us were in agreement that one always needs to be careful about a geopolitical trigger as a single tiny flashpoint could offset the placidness. But from where Ernsberger and the Oilholic sit at present – geopolitical influences are in a kind of suspended animation for next year. The Platts Energy Risk Forum also noted that demand forecasts for 2012 have stabilised and that Chinese demand, on a standalone basis, had slowed considerably. As such, the price outlook for 2013 is overwhelmingly bearish.

One unintended result of the European crisis brings us to another area of interest - refining. Platts noted that the EU-wide recession is speeding up refinery closures. It suggested that 3 to 5 million barrels per day (bpd) of oil refining capacity is under immediate threat of closure or actually did close recently. Additionally, an estimated 7 million bpd needs to close to adjust for more efficient refining in Asia and Middle East. But the closures are lifting refining margins over the short-term in a business that remains volatile (see graphic above right, click to enlarge). Ernsberger also brought forth a very valid observation for the readers of this humble blog – the striking similarity between the survival (or vice versa) statistics within the refining and civil aviation sectors.

“Refining and aviation are two industries where it’s a race to the bottom! There is so much competition in both these industries that basically whatever environment you are operating in – even if you are operating in India or China – it’s a race to the bottom…Typically, what you’ll find is that every company would try and stay in the business as long as it can and will only leave when it runs out of money. It’s also why refining and aviation have more bankruptcies than any other sector I can think of,” he said.

At the same forum, it was also a pleasure running into Dr. Vincent Kaminski, a former Enron executive who repeatedly raised strong objections to the financial practices at the company prior to its scandal-ridden collapse in 2002. In the aftermath of the scandal, Dr. Kaminski was praised for being among the voices of reason at a company riddled with malpractices. (For background read Bethany McLean and Peter Elkind’s brilliant book – The Smartest Guys in the Room)

Dr. Kaminski, who is an academic on the faculty of Houston’s Rice University at present, told the forum that by the time of its collapse Enron had mutated from an energy company to one which traded practically everything and one which was not alone in devising trading strategies based on exploiting geographical constraints.

“Energy markets have evolved over the last 20 years into an integrated global system. Markets for different physical commodities form what can be called a tightly coupled system. While market participants learn and adjust their behaviour in order to survive and prosper in a changing world, the system itself evolves and remains far removed from a stable equilibrium at any point in time,” he added.

Dr. Kaminski also dwelt on the Shale Gas revolution in the US which was decades in the making but transformed the country's energy landscape upon fruition leading to the availability of natural gas in abundance and a dip in gas price-contracts (see graphic on the left, click to enlarge). “As US production sky-rocketed, conventional wisdom about the possibility of LNG shortages barely five years ago was turned on its head. By April 2012 we even noted a sub-US$2/mBtu front-month settlement on the NYMEX,” he added.

Later in the afternoon, Dr. Kaminski told the Oilholic that US LNG import terminals currently being prepped to export gas in wake of the shale bonanza could one day be sending tanker-loads to Europe in direct competition with Qatar and Russia.

“On the flipside for the US consumer, the moment a viable gas export market is established for US gas, the impact on the country’s domestic gas market would be a bullish one. That is the nature of market forces,” he added.

When asked about the prospects of shale prospection in Europe – most notably in Poland, Ukraine, Sweden and the UK – Dr. Kaminski said he was a ‘realist’ rather than a ‘sceptic’. “What happened in the US, did not take place overnight. Technology, legislative facilitation and public will – all played a part and gradually fell into place. I do not see it being replicated in Europe over the short term and certainly not with the speed that some are hoping it would,” he concluded.

Just as the Oilholic was winding down from a discussion on shale with Dr. Kaminski, it seems the UK Institution of Mechanical Engineers (IMechE) was talking up the economic benefits of a British Shale Gale! In a policy statement circulated to parliamentarians, the IMechE said shale gas was ‘no silver bullet’ for UK energy security but will provide long-term economic benefits in the shape of thousands of jobs.

Dr. Tim Fox, Head of Energy and Environment at IMechE and lead author of the shale gas policy statement, said, “Shale gas has the potential to give some of the regions hit hardest by the economic downturn a much-needed economic boost. The engineering jobs created will also help the Government’s efforts to rebalance the UK’s skewed economy.”

However, Dr. Fox added that shale gas "is unlikely to have a major impact on energy prices and the possibility that the UK might ever achieve self-sufficiency in gas is remote." 

IMechE projects that 4,200 jobs would be created per year over a ten-year drill programme. The engineering skills developed could then be sold abroad, just as the oil and gas experience built up in North Sea oilfields is now being sold across the world. Well, we shall see but that’s all for the moment folks! Keep reading, keep it ‘crude’!

© Gaurav Sharma 2012. Graphic 1: Platts dated Brent – January 2011 to August 2012 © Platts September 2012. Graphic 2: International cracking margins snapshot © Platts / Turner Mason & Co. September 2012. Graphic 3: US Natural Gas futures contract © Dr. Vincent Kaminski, Rice University, Texas, USA /Bloomberg.

The world according to ENOC, Jebel Ali & more

If you could think of one participant in the Dubai economy that exemplifies a bit of a detachment from its debt fuelled construction boom turned bust, then the Emirates National Oil Company (ENOC) is certainly it. The Oilholic has always been one for contrasting Dubai’s debt fuelled growth with neighbour Abu Dhabi’s resource driven organic growth. However, ENOC is a somewhat peculiar exception to the recent Dubai norm or some say form.

 

Since becoming a wholly owned Government of Dubai crown company in 1993, ENOC has continued to diversify its non-fuel operations while playing its role as a custodian of whatever little crude oil reserves the Emirate holds. The history of this NOC dates to 1974. Today it is among the most integrated (and youngest) operators in the business, though not necessarily profitable in a cut throat refining and marketing (R&M) world.

 

While it has no operations in neighbouring Abu Dhabi, ENOC has moved well beyond its Dubai hub establishing a foothold in 20 international markets and other neighbouring Emirates over the years. In case, you didn’t know or had never heard of ENOC, this Dubai crown company has a majority 51.9% stake in Dragon Oil Plc; a London-listed promising upstart. Dragon Oil’s principal producing asset is the Cheleken Contract in the eastern section of the Caspian Sea under Turkmenistan’s jurisdiction.

 

Despite trying times for refiners ENOC’s Jebel Ali Refinery, situated 40km southwest of Dubai City, is the crown company’s crown jewel. Planned in 1996 and completed by 1999, the Jebel Ali refinery’s processing capacity currently stands at 120,000 barrels per day (bpd). It processes condensate or light crude to myriad refined products which get exported as well as feed in to ENOC's own domestic supply chain.

 

ENOC says an upgrade of the refinery was carried in 2010 at a cost of US$850 million. The refinery dominates the landscape of the Jebel Ali free trade zone accompanied by a sprawling industrial estate and an international port. The Oilholic is reliably informed that the latter is among the largest and busiest ports in the region playing host to more ships of the US Navy than any other in the world away from American shores.

 

While being able to host aircraft carriers is impressive, what’s more noteworthy from a macroeconomic standpoint is the fact that the Jebel Ali Free Trade Zone as a destination exempts companies relocating there from corporate tax for fifteen years, personal income tax and excise duties. It’s a privilege to have visited Jebel Ali and also by ‘crude’ coincidence witness ENOC sign a joint venture agreement with Saudi Arabia’s Aldrees Petroleum & Transport Services Company (Aldrees) for setting up service stations in different locations across the latter.

 

The equal-staked venture will see service stations in Saudi Arabia feature ENOC’s regional marquee brand products. The first station is expected to open early next year, with the number of sites rising to 40 in due course. Given that ENOC needs to buy petroleum from international markets as Dubai does not produce enough of the crude stuff, the move has much to do with cost mitigation on the home front.

 

ENOC is forced to sell fuel at Dubai petrol pumps well below the price it pays for crude and refining costs. For instance, over 2011 fuel sales losses at ENOC were thought to be in the US$730-750 million range. So here’s a NOC with profitable non-fuel businesses but troubling fuel businesses looking for ‘crude’ redemption elsewhere. That’s all for the moment folks; a final word from Dubai later! Keep reading, keep it ‘crude’!

 

© Gaurav Sharma 2012. Photo 1: ENOC Bur Dubai Office, UAE. Photo 2: Jebel Ali Refinery and Industrial Estate, Dubai, UAE © Gaurav Sharma 2012.

The South Sudan question & other crude matters

Where South Sudan fits in the oil world has troubled ‘crudely’ inclined geopolitical analysts for some time now. The country celebrated the first anniversary of its creation on July 9th. But there is little to cheer about yet for South Sudan which inherited over 75% of parent Sudan’s proven oil reserves but is overtly reliant on the latter’s infrastructure to bring it to market. Sources with expertise as well as anyone with a modicum of interest in current events would agree that South Sudan’s outlook is bleak at best and abysmal at worst following decades of conflict. That’s notwithstanding a prolonged border dispute with the North, 170,000-plus refugees and tension over oil revenues which have only just shown signs of easing.

While it is early days, on August 4th a Reuters’ flash stating that the North and South sides had pulled back from the brink of war and finally agreed on oil transit payments was widely welcomed from trading floors to the Office of US Secretary of State Hillary Clinton. And what has emerged so far is a relief for everyone from Elf to Total, from OMV to CNPC; the Chinese being the biggest players in Sudan. Of the seven exploration blocks, CNPC is majorly involved with four in case you didn’t know.

Yet deep down everyone, not least the Oilholic, is pragmatic enough to acknowledge that the time to uncork the champagne is not here yet. This humble blogger was not in the Ethiopian capital of Addis Ababa where the agreement was reached, but courtesy dispatches from kindred souls in diplomatic circles it is known that South Sudan agreed to pay North Sudan just over US$9.05 per barrel for usage of its transport, supply and logistics infrastructure to move the crude stuff to Port Sudan.

However, nearly a fortnight on from the announcement, we still await an announcement about when the South will resume oil exports which were stopped in January. That said North Sudan will receive US$3 billion as compensation for revenue lost in that period.

The agreement is not the end of South Sudan’s problems. Without even having meaningfully exploited its precious resources, the world's newest nation is already a case study for the resource curse hypothesis. With oil production having only begun in 2005 and anti-graft measures either side of the border being ‘less than worse’, it can be safely concluded that South Sudan is more likely to resemble a 1970s Nigeria than a 2012 Botswana.

If the Americans press South Sudan to act on graft they are labelled as arrogant, the South Africans as patronising, the Brits as colonials and so on in populist circles even if the government is partially listening. The Chinese way to calm the situation either side of the disputed border and improving things is by offering to buy the crude stuff at above existing market rates (as they did in February).

Clue – nothing is going to change meaningfully anytime soon. Alas, with a production peak for existing facilities forecast for 2020, a turnaround is needed and fast! At least a plan to move away from overreliance on the North by building a pipeline to Kenya is a positive if it materialises. Happy Belated Birthday South Sudan!

Away from Sudanese problems, but sticking with the African continent – Nigeria has signed an ‘initial’ agreement with USA’s Vulcan Petroleum Resources Ltd.; a Vulcan Capital Management SPV, to build six new oil refineries worth US$4.5 billion. If ‘initial’ becomes ‘final’ and the deal materialises, it would add to the four refineries Nigeria already has increasing refining capacity by 180,000 barrels per day.

For a country which is Africa’s largest oil exporter but a net importer of refined distillates, the Oilholic has always opined that seeing is believing. So we’ll believe when we see and greet the announcement with cautious optimism.

Moving to some corporate news which also has an African flavour, its emerged that Edinburgh-based independent upstart Melrose Resources has announced a merger with Ireland’s Petroceltic. Both companies will now merge operations in North Africa along with Black Sea and the Mediterranean.

The new company will have Petroceltic’s branding and will be headquartered in Ireland. The merger values Melrose at £165 million with Petroceltic shareholders having a 54% stake in the merged company and Melrose shareholders having the rest. Sounds like a sound move!

Finally, a new computer virus is doing the rounds targeting energy infrastructure being dubbed by the security firms as the “Shamoom” attack. A notice from Symantec (available here) describes the virus as “a destructive malware that corrupts files on a compromised computer and overwrites the MBR (Master Boot Record) in an effort to render a computer unusable.”

On Wednesday, Saudi Aramco said it was subject to a virus attack but did not acknowledge whether it was a Shamoom attack. A spokesperson said Aramco had now isolated its computer networks as a precautionary measure while stressing that the attack had no impact on its production. Virulent times in the crude world. That’s all for the moment folks! Keep reading, keep it 'crude'!

© Gaurav Sharma 2012. Photo: Oil worker © Shell

A Californian emission law, refiners & Muir woods

When in town, spending a few hours watching shipping lanes in the San Francisco bay area is an old pastime of the Oilholic’s, especially when it comes to spotting oil tankers which bring in some of the crude stuff to the area's refiners.

This morning, while sitting on Pier 39, yours truly spotted three pass by along with a few loaded containers - all following a well practised drill moving along a designated route under the Golden Gate Bridge, past Alcatraz Island before turning away left. Away from eye-view and the rather tranquil shipping lanes, there is local trouble at the mill for the already beleaguered refiners who have to contend with overcapacity and stunted margins.

It comes in the shape of a gradual but steady implementation of California's (relatively) new environmental regulations by 2020. This piece of regulation is known as California's Global Warming Solutions Act a.k.a. the AB 32, the central objective of which is to reduce Californian greenhouse gas emissions to 1990 levels by 2020.

According to the California Air Resources Board, in 2013 it will begin enforcing a state-wide cap on greenhouse gas emissions. The cap-and-trade programme coupled with the Low Carbon Fuel Standard would give California some of the most stringent air quality and emissions laws in the USA, although a spokesperson refused to describe it as such.

Ratings agency Moody’s believes refining and marketing (R&M) companies Tesoro, Alon USA, Phillips 66 and Valero are particularly exposed to the gradual implementation of the new environmental rules.

"California's increasingly stringent environmental regulations will challenge refiners over the next decade, increasing operating costs and negatively impacting refined product demand. These new rules will reduce cash flow that could be used for debt repayment or strategic growth and could discourage refiners from investing in California," says Gretchen French, a senior analyst and Vice President at Moody’s.

Among the majors, Chevron which has a significant refinery capacity in California, is likely to feel the impact most among its peers. Nonetheless as ratings agencies generally tend to rate integrated oil & gas companies higher than R&M only companies, Chevron should have no immediate concerns. The company's long-term debt is rated by Moody’s Aa1 with a stable outlook according to a communiqué dated March 27th.

The agency believes Chevron's ratings reflect its significant scale and globally integrated operations, its diversified upstream reserves and production portfolio, and a strong financial profile, which is underpinned by strong cash flow coverage metrics, low financial leverage, robust capital returns, and a conservative approach to shareholder rewards.

Furthermore, Chevron's strong liquidity profile is characterised by free cash flow generation, ongoing asset sales proceeds, and a large cash position. Chevron's liquidity is further supported by US$6 billion of unused committed credit facilities due in December 2016. Moody's does not expect the new rules to affect the ratings for Tesoro, Alon, Phillips 66 or Valero either over the near to medium term, but the new standards could limit credit accretion.

"Well diversified companies with high financial flexibility and strong liquidity will shoulder the new burdens and weaker demand most easily. Refiners with efficient cost structures and high distillate yields will retain the greatest advantage," French says.

Additionally, a pool of commentators here in the Bay Area seem to suggest that most players – especially Tesoro and Valero – have had a fair bit of time to indulge in regulatory risk mitigation. This piece of legislation was to be expected as California has admirably been a state keen on conservation, forestry and the environment.

The “Father of the US National Parks” – John Muir – an author, naturist and an early advocate of preservation of wilderness in the USA did most of his life’s important work here in California’s Sierra Nevada mountain range. In 1908, Muir who also founded one the country’s most important conservation organisation – the Sierra Club – had a national park named after him. This amazing redwood forest - the Muir Woods National Monument near San Francisco - now provides joy to countless visitors among whom the Oilholic was one this afternoon.

More than six miles of trails are open for visitors to experience an easy walk on the valley floor through the primeval redwood forest. Though the forest is naturally quiet, the Oilholic is in agreement with the US National Park Service, that people are key to preserving the ancient tranquillity of an old-growth forest in our noisy, modern world. That’s all for the moment folks! Keep reading, keep it ‘crude’!

© Gaurav Sharma 2012. Photo 1: Oil Tanker in the San Francisco Bay Area shipping lane. Photo 2: Valero Pump. Photo 3: Collage of Muir Woods National Monument, California, USA © Gaurav Sharma.

Three Months, Three Cities, Three ‘crude’ reports

The three cities being – Delhi, Doha and Vienna, the three reports being Oilholic’s work on Latin American Offshore, Shale Oil & Gas and Refineries projects outlook, research for which was spread over December, January and February from the 20th World Petroleum Congress to the 160th OPEC Meeting to the streets of ‘crude’ Delhi.

The last of the three reports was published by Infrastructure Journal on Feb 29th and while the analysis in the reports remains the preserve of the Journal’s subscribers, the Oilholic is more than happy to share a few snippets starting with the Latin American offshore landscape, which shows no signs of a post ‘Macondo’ hangover [1].

In fact, the month of May, will be a momentous one for the region’s offshore oil & gas projects market in general and Brazil in particular, as the country would dispatch its first shipment of oil from ultradeepwater pre-sal (‘below the salt layer’) sources. The said export consignment of 1 million barrels destined for Chile is a relatively minor one in global crude oil volume terms. However, its significance for offshore prospection off Latin American waters is immense.

When thinking about Latin American offshore projects think Brazil; think Brazil and think Petrobras’ Lula test well in the Santos basin, named after the former president, which is producing 100,000 barrels per day (bpd). Almost over a third of the Chilean consignment originated from the Lula well according to the Oilholic’s sources.

What should excite project financiers, corporate financiers and technical advisers alike is the fact the company expects to pump nearly 5 million bpd by 2020 and its ambitious drive needs investment.

However, ignoring other jurisdictions in the region and focussing only on Brazil, its promise and problems would be a fallacy. Others such as Argentina, Columbia and prospection in Falkland Islands waters are worth examining, the latter especially from the standpoint of corporate financed asset acquisitions.

Data always helps in contextualising the market movements. Using the present Infrastructure Journal data series on project finance, which commenced in 2005, figures certainly suggest the sun is shining on the Brazilian offshore industry. Of the 15 Latin American offshore projects on record which reached financial close between October 2006 and Sept 2011, 13 were Brazilian along with one apiece from Panama and Peru (Click on pie-chart above to enlarge). With a cumulative deal valuation of just under US$9.3 billion, among these Brazil’s Guara FPSO valued at US$1.2 billion led the way reaching financial close in June 2011.

The year 2010, was a particularly good one for Brazil with five projects reaching financial close. Over the last three years, sponsors of offshore projects in the country have been consistent in approaching the debt markets and bringing three to five projects per annum to financial close, with 2011 following that trend.

Moving on to the Oilholic’s second report, for all intents and purposes, Shale oil & gas prospection has been the energy story of the last half decade and Q1 2012 would be an apt time to scrutinise the ‘Fracks’ and figures[2].

To say that shale gas has altered the American energy landscape would be the understatement of the decade, or to be more specific at least half a decade. Courtesy of the process of hydraulic ‘fracking’, shale gas prospection – most of which was initially achieved in the US by independent upstart project developers – has been an epic game changer.

US shale gas production stood at 4.9 trillion cubic feet (tcf) by end-2011, which is 25% of total US production up from 4% in 2005. Concurrently, net production itself is rising exponentially owing to the shale drive according to the EIA.

Project finance aside, it is in the corporate finance data where the shale story is truly reflected – i.e. one of a steady rise both in terms of deal valuation as well as the number of projects. From four corporate infrastructure finance deals valued at US$1.89 billion in 2009, both data metrics posted an uptick to seven deals valued at US$8.35 billion in 2010 and 10 deals valued at US$7.58 billion in 2011 (Click on bar-chart above to enlarge).

However, a short term global replication of a US fracking heaven is unlikely and not just because there isn’t a one size fits all model to employ. While American success with shale projects has not escaped the notice of Europeans; financiers and sponsors in certain quarters of the ‘old continent’ are pragmatic enough to acknowledge that Europe is no USA. The recent shale projects bonanza stateside is no geological fluke; rather it bottles down to a combination of geology, American tenacity and inventiveness.

Europe’s best bet is Poland, but European shale oil & gas projects market is unlikely to record an uptick between 2012 to 2017 on a scale noticed in North America in general and the USA in particular between 2007 and 2012. The financing for shale projects – be it corporate finance or project finance – would be a slow, but steady trickle rather than a stream beyond North America.

Finally, to the Refineries report, given the wider macroeconomic climate, refinery infrastructure investment continues to face severe challenges in developed jurisdictions and Western markets[3]. Concurrently, the balance of power in this subsector of the oil & gas infrastructure market is rapidly tipping in favour of the East.

Even if refinery investment of state-owned Chinese oil & gas behemoths, which rarely approach the debt markets, is ignored – there is a palpable drive in emerging economies elsewhere in favour of refinery investment as they do not have to contend with overcapacity issues hounding the EU and North America.

For some it is a needs-based investment; for others it makes geopolitical sense as their Western peers holdback on investing in this subsector. The need for refined products is often seen superseding concerns about low refining margins, especially in the Indian subcontinent and Asia Pacific.

Industry data, empirical, anecdotal evidence and direct feedback from industry participants do not fundamentally alter the Oilholic’s view of tough times ahead for refinery infrastructure. As cracking crude oil remains a strategic business, investing in refinery infrastructure reflects this sentiment, investor appetite and financiers' attitudes.

According to current IJ data, investment in refinery infrastructure via private or semi-private financing continues to remain muted; a trend which began in 2008. In fact, 2011 has been the most wretched year since the publication began recording refinery project finance data.

Updated figures suggest the year 2010, which saw the artificial fillip of Saudi Arabia’s mega Jubail refinery project (valued at US$14.04 billion) reach financial close, has been the best year so far for refinery project finance valuation despite closing a mere two projects. However, industry pragmatists would look at 2008 which saw ten projects valued at US$9.39 billion as a much better year (Click on bar-chart above to enlarge).

From there on it has been a tale of post global financial crisis woes with the market struggling to show any semblance of a recovery and most of the growth coming from non-OECD jurisdictions. In 2009, three projects valued at US$4.79 billion reached financial close, followed by two projects including Jubail valued at US$15.04 billion in 2010, and another two projects valued at US$1.49 billion in 2011. By contrast, the pre-crisis years of 2005, 2006 and 2007 averaged US$6.71 billion in terms of transaction valuations.

A general market trend in favour of non-OECD project finance investment in refineries is obviously mirrored in the table of the top deals between 2005 and 2011 (above). Of the five, four are in non-OECD countries – led by Jubail Refinery (Saudi Arabia) valued at US$14.04 billion which closed in 2010, followed by Guru Gobind Singh Bhatinda Refinery, India (valued at US$4.69 billion, financial close – 2007), Jamnagar 2 Refinery, India (US$4.50 billion, financial close – 2006) and Paradip refinery, India (US$2.99 billion, financial close – 2009).

Only one deal from an OECD nation, which is a very recent member of the club, made it to the top five, namely Poland’s Grupa Lotos Gdansk Refinery Expansion valued at US$2.85 billion which reached financial close in 2008. Simply put, the future of infrastructure investment in this sub-component of the oil & gas business lies increasingly in the East wherein India could be a key market. That’s all for the moment folks! Keep reading, keep it ‘crude’!

NOTES:

[1] Latin American Offshore O&G Outlook 2012: Brazil’s decade, By Gaurav Sharma, Infrastructure Journal, January 17, 2012. Available here.

[2] Shale Oil & Gas Outlook 2012: The ‘Fracks’ and figures, By Gaurav Sharma, Infrastructure Journal, January 25, 2012. Available here.

[3] Refinery Projects Outlook 2012: ‘Cracking’ times for Eastern markets, By Gaurav Sharma, Infrastructure Journal, February 29, 2012. Available here.

© Gaurav Sharma 2012. Graphics: Pie Chart 1 – Latin American Offshore Project Finance transactions (October 2006 to Sept 2011), Bar Chart 1 – Number of Shale Corporate Finance transactions (2009-2011), Bar Chart 2 – Refinery Project Finance Valuation (2005-2011) © Infrastructure Journal.

EU’s Iran ban, upcoming Indian adventure & Cairn

Earlier on Monday and in line with market expectations, the European Union agreed to impose an embargo on the import of Iranian crude oil. The EU, which accounts for 20% of Iran’s crude exports, now prohibits the import, purchase and transport of Iranian crude oil and petroleum products as well as related finance and insurance. All existing contracts will have to be phased out by July 1st, 2012.

In response, Iran declared the ban as "unfair" and "doomed to fail", said it will not force it to change course on its controversial nuclear programme and renewed threats to blockade the Strait of Hormuz. Going into further details, EU Investment in as well as the export of key equipment and technology for Iran's petrochemical sector is also banned.

A strongly worded joint statement by British Prime Minister David Cameron, French President Nicolas Sarkozy and German Chancellor Angela Merkel says, “Until Iran comes to the table, we will be united behind strong measures to undermine the regime’s ability to fund its nuclear programme, and to demonstrate the cost of a path that threatens the peace and security of us all.”

That’s all fine and yes it will hurt Iran but unless major Asian importing nations such as China, India and Japan decide to ban Iranian imports as well, EU’s ban would not have the desired impact. Of these, China alone imports as much Iranian oil as the EU, Japan accounts for 17% of the country’s exports, followed by India (16%) and South Korea (9%).

So until the major Asian economies join in the embargo, both EU and Iran will end up hurting themselves. As a Sucden Financial note concludes, “Unless a deal can be agreed unilaterally, it is likely that the weak European economies could suffer from firmer crude prices whilst relatively robust Asian economies might benefit from preferential crude trade agreements.”

China is unwilling to follow suit while it is thought that Japan and South Korea are seeking supply assurances from other sources before reacting. India’s response had been lukewarm in the run-up the EU’s decision. Now that the decision has been made, it will be interesting to note how the Indian government responds. The Oilholic is heading to India this week (and for better parts of the next) and will try to sniff out the public and government mood.

Meanwhile, Fitch Ratings has said the EU embargo will increase geopolitical risk in the Middle East region supporting high oil prices. The agency considers blocking the Strait of Hormuz - the world's most important oil chokepoint - to be a low-probability scenario and believes any obstruction to trade routes would have a short duration if it did actually transpire.

Arkadiusz Wicik, Director in Fitch's European Energy, Utilities and Regulation team and an old contact of the Oilholic’s, feels that the EU ban on Iranian oil is largely credit neutral for EU integrated oil and gas companies. "The cash flow impact of the ban may be negative for refining operations, but should be positive or neutral for upstream operations," he says.

The most likely scenario is that the EU embargo will result in higher oil prices. However, prices may not necessarily increase markedly from current levels as some of the risks related to the EU ban on Iranian oil appear factored in already.

A new Fitch report further notes the ban is likely to have a moderately negative impact on EU refiners as high oil prices may further erode demand for refined products in Europe. This would worsen the already weak supply-demand balance in European refining. The embargo may also change oil price spreads in Europe as Iranian crude imports would likely be replaced with alternative crude, which may be priced at a lower discount to Brent than Iranian crude oil.

EU refiners' security of oil supply is unlikely to be substantially affected by an Iran ban. There are alternative suppliers, such as Saudi Arabia (which has said it is able and willing to increase oil production to meet additional demand), Russia and Iraq. Libyan oil production is also recovering. Iranian oil accounted for just 5.7% of total oil imports to the EU in 2010, and 4.4% in Q111. Furthermore, the sanctions will be implemented gradually by July 1st, 2012, which should give companies that use Iranian crude oil time to find alternative suppliers, the report notes.

Southern European countries - Italy, Spain and Greece - are the largest importers of Iranian crude oil in the EU. A rise in oil prices could be further bad news for these countries, which already face a weak economic outlook in 2012.

“The impact of the new US sanctions signed into law late last year against Iran is difficult to predict at this stage. It is not certain whether Asian countries, which are by far the largest importers of Iranian crude, accounting for about 70% of total Iranian oil imports, will substantially reduce supplies from Iran in 2012 and replace them with other OPEC sources as a result of the new US sanctions,” the Fitch report notes further.

The agency’s report does make one very important observation – one that has been doing the rounds in the City ever since news of the ban first emerged – that’s if Asian reduction is substantial, in combination with the EU ban, it could considerably lower OPEC's spare production capacity. In such a scenario, the global oil market would have less flexibility in the event of large unexpected supply interruptions elsewhere, potentially sending oil prices much higher than current levels.

Moving away from the Iranian situation, Cairn Energy has sold a 30% stake in one of its Greenland exploration licences to Norway’s Statoil. The UK independent upstart spent nearly £400 million in exploration costs last year with little to show for it as no commercially exploitable oil or gas discovery was recorded. While the percentage of the stake has been revealed, neither Cairn nor Statoil are saying how much was paid for the stake. Nonetheless, whatever the amount, it would help Cairn mitigate exploration costs and risks as it appears to be in Greenland for the long haul.

Elsewhere, there is positive and negative news on refineries front. Starting with the bad news, shares in Petroplus – Europe’s largest independent refiner – were suspended from trading on the Swiss SIX stock exchange on Monday at the company’s request. As fears rise about Petroplus defaulting on its debt following an S&P downgrade last month and yet another one on January 17th, looks like the refiner is in a fight for its commercial life.

Lenders suspended nearly US$1 billion in credit lines last month which prevented Petroplus from sourcing crude oil for its five refineries. However, it had still managed to keep refineries at Coryton (Essex, UK) and Ingolstadt (Germany) running at reduced capacity. Late on Monday, Bloomberg reported that delivery lorries did not leave the Coryton facility and concerns are rising for the facility’s 1000-odd workforce. PwC, which has been appointed as the administrator of Petroplus' UK business, said on Tuesday that it aims to continue to operate the Coryton facility without disruption. The Oilholic hopes for the best but fears the worst.

Switching to the positive news in the refineries business, China National Petroleum Corp, Qatar Petroleum and Royal Dutch Shell agreed plans on January 20th for a US$12.6 billion refinery and petrochemical complex in eastern China. Quite clearly, hounded by overcapacity and poor margins in Europe, the future of the refineries business increasingly lies in the Far East on the basis of consumption patterns. That’s all for the moment folks. Keep reading, keep it ‘crude’!

© Gaurav Sharma 2012. Photo: Oil tanker © Michael S. Quinton / National Geographic.

Of ConocoPhillips & the integrated model

Is the integrated model of operations incorporating a mixed bag of upstream, midstream and downstream assets ‘dead’ for oil & gas majors given that so many of them have put refining & marketing (R&M) assets up for sale in the last half decade? The question of raises some fierce emotions! Some say it’s not dead, some (including the Oilholic) say it is and others simply say it is on “life support.” The wider market and quite a few delegates here at the 20th WPC point to one company's move which typifies the market dilemma – that's ConocoPhillips.

The US major's announcement in July that it will be pursuing the separation of its exploration and production (E&P) and R&M businesses into two separate publicly traded corporations via a tax-free spin-off R&M to its shareholders did not surprise the Oilholic and those who think the integrated model is no longer in vogue.

As many are watching what unfolds at ConocoPhillips, it is worth turning one’s attention to what its Chief Executive Jim Mulva had to say amid a cacophony of soundbites in Doha. Mulva intends to retire once his company’s split is complete and will be replaced by Ryan Lance as head of the split upstream business.

He notes that ConocoPhillips will spend close to US$14 billion on E&P in 2012 with the majority of the stated capital invested in unconventional projects in North America – namely the Canadian oil sands and liquids rich shale plays (Eagle Ford shale, Permian, Bakken and Barnett prospection fields). From these, the outgoing Chief Executive expects “competitive returns”. The company also hopes to remain active in Indonesia, Malaysia and Kazakhstan and is not giving up on the North Sea.

In fact, it will invest more on existing and new prospects in the North Sea’s Greater Britannia, Greater Ekofisk fields and Jasmine and Clair ridge projects. However, moving away from E&P, ConocoPhillips will divest between US$15 to US$20 billion in assets by Q4 2012. Some, but not all, proceeds will be used to finance a recently announced US$10 billion share buy-back.

Mulva has been as clear as he can be on his company's forward planning. The wider market will now be watching how things pan out for the split companies. However, nothing the Oilholic has heard at the 20th WPC fundamentally alters his initial thoughts - that the integrated model is in deep trouble in Western jurisdictions.

© Gaurav Sharma 2011. Photo: ConocoPhillips exhibition stand at the 20th Petroleum Congress © Gaurav Sharma 2011.

ConocoPhillips’ move is a sign of crude times

US major ConocoPhillips' announcement last Friday that it will be pursuing the separation of its exploration and production (E&P) and refining and marketing (R&M) businesses into two separate publicly traded corporations via a tax-free spin-off R&M to COP shareholders does not surprise the Oilholic. 

Rather, it is a sign of crude times. Oil majors are increasing turning their focus to the high risk, high reward E&P side of things rather than the R&M business where margins albeit recovering at the moment, continue to be abysmal. Most oil majors  are divesting their refinery assets, and even BP would have done so, regardless of the Macondo tragedy forcing its hand towards divestment. 

ConocoPhillips’ decision should not be interpreted as a move away from R&M – nothing in the oil business is either that simple or linear. However, it certainly tells us where its priorities currently lie and how it feels the integrated model is not the best way forward. This is in line with industry trends as the Oilholic noted last November. 

Meanwhile, following the announcement, ratings agency Moody's says it may review ConocoPhillips' ratings for possible downgrade with approximately US$19.6 billion of rated debt being affected. This includes A1 senior unsecured and other long-term debt ratings of the parent company and its rated subsidiaries. 

Tom Coleman, Moody's Senior Vice-President notes that the distribution to shareholders of the large R&M business could weaken the credit profile of ConocoPhillips and result in a downgrade of its A1 rating. 

"Our review will focus on the company's capital structure following the spin-off, including the potential for debt reduction by ConocoPhillips, along with its financial policies and growth objectives going forward as a stand-alone E&P company," he concludes. 

The wider market is waiting to get a clearer understanding of the oil major’s plans for debt reduction, capital structure and financial policies as an independent E&P. Continuing with corporate deals, BHP Billiton made a strategic swoop for Petrohawk Energy. The cash acquisition, also announced last Friday, to the tune of US$12.1 billion, will give it access to shale oil and gas assets across Texas and Louisiana. BHP’s latest move follows its earlier decision to buy Chesapeake Energy's Arkansas-based gas business for US$4.75 billion. 

Meanwhile, figures released by Brazil’s Petrobras for the month of June indicate that the company’s domestic production rose 3.5% on an annualised basis. The results were boosted by the resumption of production on platforms that had been undergoing scheduled maintenance in the Campos Basin, and startup of a new well connected to platform Jubarte field's P-57 in the Espírito Santo section of the Campos Basin. The Extended Well Test (EWT) in the Campos Basin's Aruanã field also started up in late June.

However, its international output was down 5.6% on an annualised basis due to operating issues and tax payments in Akpo, Nigeria. Petrobras' average oil and natural gas production (both domestic and overseas) amounted to 2,641,508 barrels of oil equivalent per day (boed), 2.13% up on the total figure for May 2011. 

Finally, European woes are weighing on the crude markets. With the NYMEX August crude futures contract due to expire on Wednesday, intraday trading at one point, 1045 GMT to be precise, saw it down 0.31% or 33 cents at US$96.91 a barrel. Concurrently, the September ICE Brent futures contract was down 0.6%, 74 cents at US$116.44 a barrel. 

© Gaurav Sharma 2011. Photo 1: COP Refinery & Oil Platform collage © ConocoPhillips

Talking Refinery Infrastructure on CNBC

This week marked the culmination of almost a month and a half of my research work for Infrastructure Journal on the subject of oil refinery infrastructure and how it is fairing. Putting things into context, like many others in the media I too share an obsession with the price of crude oil and upstream investment. I wanted to redress the balance and analyse investment in the one crucial piece of infrastructure that makes (or cracks) crude into gasoline, i.e. refineries. After all, the consumer gets his/her gasoline at the gas station – not the oil well. The depth of Infrastructure Journal's industry data (wherein a project’s details from inception to financial close are meticulously recorded) and the resources the publication made available to me made this study possible. It was published on Wednesday, following which I went over to discuss my findings with the team of CNBC’s Squawk Box Europe.

I told CNBC (click to watch) that my findings suggest activity in private or public sector finance for oil refinery projects, hitherto a very cyclical and capital-intensive industry currently facing poor margins, is likely to remain muted, a scenario which is not going to materially alter before 2012.

The evidence is clear, integrated oil companies have and will continue to divest in downstream assets particularly refineries because upstream investment culture of high risk, high rewards trumps it.

Growth in finance activity is likely to come from Asia in general and surprise, surprise India and China in particular. It is not that margins are any better in these two countries but given their respective consumers’ need for gasoline and diesel – margins become a lesser concern.

However, in the west, while refiners’ margins remain tight, new and large refinery infrastructure projects would see postponements, if not cancellations. In order to mitigate overcapacity, a number of mainly North American and European refiners or integrated companies will shutdown existing facilities, albeit quite a few of the shutdowns will be temporary.

Geoff Cutmore and Maithreyi Seetharaman probed me over what had materially changed, after all margins have always been tight? Tight yes, but my conjecture is that over the last five years they have taken a plastering. On a 2010 pricing basis, BP Statistical Review of World Energy notes that the 2009 refining average of US$4.00 per barrel fell below the 2008 figure of $6.50 per barrel; a fall of 38.5%. In fact, moving away from the average, on an annualised basis, margins fell in all regions except the US Midwest last year while margins in Singapore were barely positive.

Negative demand has in effect exasperated overcapacity both in Europe and North America. BP notes that global crude runs fell by 1.5 million bpd in 2009 with the only growth coming from India and China where several new refining capacities, either private or publicly financed, were commissioned. Its research further reveals that most of the 2 million bpd increase in global refining capacity in 2009 was also in China and India. Furthermore, global refinery utilisation fell to 81.1% last year; the lowest level since 1994.

In fact does it surprise anyone that non-OECD refinery capacity exceeded that of the OECD for the first time in 2009? It doesn’t surprise me one jot. I see this trend continuing in 2010 and what happens thereafter would depend on how many OECD existing refineries facing temporary shutdown are brought back onstream and/or if an uptick in demand is duly noted by the OECD nations. A hope for positive vibes on both fronts in the short to medium term is well...wishful thinking.

Refineries were once trophy assets for integrated oil companies but in the energy business people tend to have short memories. Alas, as I wrote for Infrastructure Journal (my current employers) and told CNBC Europe (my former employers), now they are the unloved assets of the energy business.

© Gaurav Sharma 2010. Photo 1: Gaurav Sharma on Squawk Box Europe © CNBC, Nov 10, 2010, Photo 2: Oil Refinery Billings, Montana © Gordon Wiltsie / National Geographic Society