Outbound shipments of Eagle Ford Shale crude and condensate through the Port of Corpus Christi rose to 551,934 b/d in June from 341,824 b/d in June 2013, the most recent data released by the port showed. June shipments also rose 5% month on month, from 526,437 b/d in May.
Shipments have been on the rise this year, data on the port’s website showed. June’s shipments were 56% above January’s 353,192 b/d. The amount of crude and condensate shipped from the marine facility is listed in short tons in the port data.
A conversion rate of 277.24 lb/barrel was used to derive the b/d rate. The conversion rate is common for a 47 API barrel of light sweet crude such as that found in the Eagle Ford Shale. The Eagle Ford is a shale play of 20,000 square miles (12.8 million acres) about 70 miles from Corpus Christi, Texas.
The port’s proximity to the Eagle Ford provides a direct route for moving crude to domestic destinations on the US Gulf and East coasts, as well as Canada. Outbound shipments of crude and condensate are mainly sent to areas between Houston, Port Arthur and New Orleans; however, there have been a few shipments to the East Coast and Canada since August 2013.
Crude and condensate exporters that have continued to build additional storage and loading docks at the port include Martin Midstream, Trafigura, Nustar Energy, Plains Marketing and Flint Hills. US-flagged vessels that export out of the port are 600-630 feet in length overall, while foreign-flagged vessels are usually 700-900 feet in length.
According to the port’s harbor master, the cargoes are mainly carried on Panamax- and Aframax-sized ships. Outgoing shipments of crude and condensate rose in correlation with rising development in the Eagle Ford play.
June’s Eagle Ford oil production rose 27,305 b/d compared with May’s average to 1.40 million b/d, the US Energy Information Administration said in a July 14 report on drilling productivity. August’s Eagle Ford oil production is expected to rise 25,006 b/d compared with July’s average to 1.45 million b/d, the EIA said in the same report. This translates to an expected 31% year-on-year increase of 344,289 b/d in August.
Enbridge expects no delays for its $7 billion Line 3 replacement project despite the stop work order the Canadian National Energy Board issued earlier this month over environmental and safety concerns, a company spokesman said Wednesday.
An order from the NEB, released on its website Wednesday but issued on July 9, instructed Enbridge to cease work on the replacement project until certain environmental and safety measures were taken. “During the inspection of the Project it was observed that multiple construction mitigation measures committed to by Enbridge in its Environmental Protection Plan to conserve topsoil, control erosion and manage drainage were not implemented,” the NEB said.
The agency ordered Enbridge to take immediate steps to add proper signage and fencing as well as to create a plan for safe access for nearby landowner’s farm equipment. Enbridge was tasked with creating a plan by August 4 to address any new concerns, as well as to complete a reassessment of its EPP by the end of August. Enbridge had already begun work on the relevant sites when the order was initially issues, spokesman Graham White said.
The company expects to meet all of the NEB’s filing deadlines, he added. “Flood conditions in the spring and the heavy rainfall in late June prevented us from accessing the area with the equipment necessary to remedy the issues raised by the NEB and known to us as well,” White said. “Any issues that the NEB has identified as safety concerns will be dealt with immediately.”
White said there was no indication when NEB would ultimately rule on the company’s resubmitted EPP, but they nonetheless expected to complete the project on schedule, before the end of the year. The replacement project will expand the capacity of Line3 of the Canadian Mainline system, which runs from Edmonton, Alberta, to Superior, Minnesota, from 390,000 b/d to 760,000 b/d.
EU diplomats have started talks on European Commission proposals for possible targeted sanctions, including on energy technologies, against those involved in destabilizing Ukraine, an EC spokesman said Thursday.
“The talks are expected to continue next week,” EC spokesman Jonathan Todd told reporters in Brussels.
EU foreign ministers on Tuesday asked the EC to make proposals for possible sanctions in new areas, including sensitive energy technologies, access to capital and defense. EU energy commissioner Guenther Oettinger said Wednesday this could include the technologies needed for Russia’s offshore oil and gas exploration projects in the Arctic.
The push to extend sanctions to new areas reflects a general toughening of the EU’s attitude toward Russia and the pro-Russian separatists in Ukraine since a civilian Malaysian airplane crashed last week in the conflict zone in eastern Ukraine, killing all on board.
The EC’s proposals for new sanction areas would not be made public until national governments have decided what they want to do, Todd said. If they decide to go ahead, then the EU would have to change the legal basis for the sanctions to include the new criteria. This can be done in a matter of days if needed.
EU leaders had already agreed last Wednesday, before the plane crash, to extend the sanctions criteria to include Russian companies involved in destabilizing Ukraine. The EU has so far limited sanctions to visa bans and asset freezes on individuals. EU diplomats are therefore also discussing a new list of individuals and companies based on this extended criteria, which could be adopted this week, EU foreign affairs spokeswoman Maja Kocijancic said Thursday.
China’s total refinery throughput outstripped its crude oil imports and domestic production in June, implying there was a draw of about 255,000 b/d during the month, Platts calculations showed Thursday based on recently released government data.
This was the first drawdown on crude oil since March and compares with a stockbuild in May of 830,000 b/d. The level of stocks held by refiners in China is not disclosed. Platts calculates China’s net draw or build in crude oil stocks by subtracting refinery throughput from crude oil supply in a given month.
The latter volume takes into account net imports and domestic production of crude oil. The draw last month echoes data from China Petroleum Stockpile Statistics compiled by state-owned news agency Xinhua, which showed that commercial crude oil stocks in the country were down 2.3% at the end of June from a month earlier.
According to Xinhua, the dip in stocks came after two consecutive months of stockbuild in April and May. China’s domestic crude oil production in June was stable from a year earlier at 17.5 million mt or an average 4.28 million b/d, according to data from the National Bureau of Statistics released July 16.
Crude oil imports during the month rose 5% year on year to 23.28 million mt, or an average 5.69 million b/d, according to the General Administration of Customs on July 10. This means China’s total available crude oil supply in June, excluding stocks, was 9.97 million b/d in June.
Refinery throughput on the other hand, had risen 5.8% year on year to 41.83 million mt, or 10.22 million b/d, suggesting refiners had to dip into their inventories to make up the shortfall. In the first half of the year, however, China saw an overall build of 488,000 b/d as crude oil imports rose 10.2% year on year to 6.15 million b/d, outpacing the 2.9% increase in refinery throughput over the same period.
Analysts had previously attributed the recent rise in Chinese crude oil imports to probable stockpiling for the country’s strategic petroleum reserves. Two new sites with an estimated 39 million barrels of capacity are likely to have been completed in the first half of this year.
The stockbuild during the first half of the year is nearly triple the amount of crude oil that likely went into storage in H1 last year. Aggregating monthly data from Xinhua, China’s commercial crude stocks increased by 3.5% as of the end of June compared with the start of the year, according to Platts estimates.
Nigeria’s production could rise from 2.35 million b/d on average to a high of 3.13 million b/d by 2030 if the country addresses security challenges and implements the right reforms, according to McKinsey & Co.
The energy industry could contribute $108 billion by 2030, up from $73 billion in 2013, contributing $22 billion to gross domestic product by 2030. Natural gas output could grow by as much as 6% per year, adding $13 billion to gross domestic product by 2030, the New York-based company said in a report published Thursday.
Though oil is the mainstay of the Nigerian economy, the sector faces a myriad of challenges. Large scale oil theft together with weak investment in oil and gas exploration due to the lack of clarity over oil sector reforms, have prevented Africa’s top oil producer from pumping to its optimum capacity of 3.2 million b/d.
While many of Nigeria’s assets have low geological costs, the country may not be as competitive in attracting investment as it has been in the past. Though precise figures are unavailable, the best estimates suggest oil production fell 7% between 2011 and 2013, from 2.52 million b/d to 2.35 million b/d, according to McKinsey.
Slow government approvals can lengthen cycle times in both joint ventures and production-sharing contracts, which also hinder investment, the report said. While the government has raised domestic gas prices substantially in recent years, most domestic gas is still sold below the international market price, it said.
Lack of a reliable power supply adds to the sector’s challenges. Installed generation capacity is 10,000 megawatts (MW), but current output is only 3,500-4,500 MW and demand widely expected to dramatically outstrip both. Terrorism poses a major challenge for Africa’s most populous country.
The Islamist group Boko Haram has been terrorizing Nigeria’s northeastern region in a five-year campaign of violence in an attempt to impose Islamic law in Nigeria Over the last 12 months, Nigeria has suffered the highest rate of fatal terrorist attacks in the world, according to global risk consultancy Maplecroft.
The International Monetary Fund on Thursday said 2015 global oil prices will drop less than it estimated earlier this year and warned that the risks of a price spike are growing. In an update to its World Economic Outlook, IMF projected 2014 oil prices will average $104.14/b, up slightly from 2013’s $104.07/b.
The agency, which bases its price estimates on an average of UK Brent, Dubai Fateh and WTI crude, projected that crude prices will fall 4.3% in 2015 to $99.62/b, 1.7% higher than it forecast in its April WEO update.
“Geopolitical risks have risen relative to April: risks of an oil price spike are higher due to recent developments in the Middle East, while those related to Ukraine are still present,” the agency said.
IMF projected global economic growth would be 3.4% this year, down from earlier projections of 3.7%, due to a weak first quarter, particular in the US, and a weakened outlook for numerous emerging markets. “In short, the recovery continues,” Olivier Blanchard, the IMF’s chief economist, said in a statement.
“But it remains weak, and is still in need of strong policy support to strengthen both demand and supply.” Global growth projections for 2015 remain at 4%, according to the IMF’s update.
“Downside risks remain a concern,” IMF said, stressing that increased geopolitical risks could head to “sharply higher oil prices.”
Nigerian crudes are continuing to fall sharply on weak demand from Europe and Asia, with the country’s flagship grade Qua Iboe dropping to a five-year low this week, sources said Thursday.
There is a sizeable overhang of August-loading cargoes, and the September loading programs have already started to emerge, putting further pressure on these grades. Refining margins in Europe have improved from where they were a few weeks ago, although sour crude margins look more appealing than those for sweet crude grades.
Sources said there were still around 15-17 August-loading stems still available and, with the September loading programs now emerging, differentials are likely to fall further and faster. Qua Iboe was assessed by Platts at Dated Brent plus $0.75/barrel Wednesday, the weakest differential since April 24, 2009.
“There is still some Bonny Light, Brass River, Bonga and Forcados [unsold for August] so it is still not clearing,” said one trader.
Sources also said that freight rates for Suezmaxes out of West Africa are still as high as Worldscale 105-110, adding that this has also been putting some pressure on the arbitrage to Europe.
However, some activity was seen in the last few days, with two Forcados August-loading stems heard sold to a Turkish refiner while a refiner in Ivory Coast had also bought this grade, sources said.
There was some talk that, with margins in the US still quite strong, refiners in the US might also look towards Nigeria and West Africa. “The majority of the light grades are still suffering and there is lack of demand for such grades,” said one trader. “With the shrinking of the WTI-Brent spread, some US refiners are talking with some of the players here.”
Posted by Max Byerly on Jul 24th, 2014 // No Comments
Repsol (NASDAQ:REPYY) released its earnings data on Thursday. The company reported $0.40 earnings per share (EPS) for the quarter, beating the consensus estimate of $0.28 by $0.12, AnalystRatingsNetwork reports.
Shares of Repsol (NASDAQ:REPYY) traded up 2.02% during mid-day trading on Thursday, hitting $25.27. 20,322 shares of the company’s stock traded hands. Repsol has a 52-week low of $22.56 and a 52-week high of $28.59. The stock’s 50-day moving average is $26.07 and its 200-day moving average is $25.75. The company has a market cap of $33.434 billion and a price-to-earnings ratio of 123.23.
A number of analysts have recently weighed in on REPYY shares. Analysts at Santander upgraded shares of Repsol from a “hold” rating to a “buy” rating in a research note on Monday, June 23rd. On a related note, analysts at Morgan Stanley upgraded shares of Repsol from an “underweight” rating to an “equal weight” rating in a research note on Wednesday, June 4th. Finally, analysts at Societe Generale upgraded shares of Repsol from a “hold” rating to a “buy” rating in a research note on Friday, May 9th. One research analyst has rated the stock with a sell rating, seven have given a hold rating and three have issued a buy rating to the stock. The stock presently has an average rating of “Hold”.
Repsol SA is a Spain-based integrated oil and gas company engaged in the exploration, production, refining, transportation and marketing of crude oil, natural and liquefied petroleum gas (NASDAQ:REPYY) and petrochemicals products, as well as the generation, transportation, distribution and supply of electricity.
By Maria Gallucci@mariagalluccim.gallucci@ibtimes.com
on July 24 2014 1:04 PM
U.S. refiners are processing oil at record levels this summer, thanks to the boom in North American energy production, expanding refinery capacity and falling operating costs. But all that extra gasoline doesn't mean less pain at the pump.
Refinery inputs totaled 16.8 million barrels of crude oil per day in each of the past two weeks, smashing the previous record from the summer of 2005, the U.S. Energy Information Administration (EIA), a federal statistics agency, said in its latest weekly petroleum report. Refineries produce motor fuels like gasoline and diesel as well as jet fuel, propane and petrochemical feedstocks, among other products.
“We’re pumping a lot of juice — these refineries are running hard,” Donald Morton, senior vice president at financial advisory firm Herbert J. Sims & Co., told the Wall Street Journal earlier this week.
Still, even as refineries churn out more gasoline and diesel products, don’t expect to pay any less at the pump this summer, Andy Lipow, a Houston-based oil industry consultant and president of Lipow Oil Associates LLC, said.
“Although refiners are running more, the fact is that world oil demand continues to grow," he told International Business Times. "The U.S. gasoline and diesel markets are linked to world oil prices.”
Refineries first hit record levels last week, when inputs totaled 16.6 million barrels a day, the most in weekly EIA data going back to 1989. Facilities in the U.S. Gulf Coast and Midwest regions in particular are contributing to this unprecedented rise, according to the EIA.
One key reason is the major uptick in Canadian and domestic crude oil production spurred by hydraulic fracturing and horizontal drilling technologies, Lipow said.
The boom has not only increased supplies, it has lowered costs for refiners, since raw domestic crude comes cheaper than supplies shipped in from overseas. On top of that, long-anticipated expansions in Gulf Coast states mean refiners can take in more crude, while cheap electricity from natural gas plants is lowering refiners’ operating costs nationwide, Lipow said. “It’s enabling U.S. refiners to be more competitive with refiners in other parts of the world,” including those in South America, Europe and Africa, he said.
That trend is likely to continue into the future as North American drillers produce more crude oil and refineries continue to expand their capacity. "If one looks at the long-term trend, the answer is we are going to be processing record amounts of crude oil over the next few years, more than we've previously done."
* South Stream pipeline, Yamal LNG rely on western technology
* EU proposes to target sensitive technologies in energy sector
* Pipelines, wells, drilling platforms are listed
By Henning Gloystein and Barbara Lewis
LONDON/BRUSSELS, July 24 (Reuters) - The European Union's proposed sanctions against Russia, targeting sensitive technology, take aim at Gazprom's huge South Stream gas pipeline project to Europe and Novatek's Arctic Yamal liquefied natural gas (LNG) facility.
A draft proposal outlines a package of targeted measures in the areas of access to capital markets, defence, dual use goods and sensitive technologies, EU diplomats said on condition of anonymity.
It makes clear any measures should not affect current energy supplies and that sanctions should be reversible.
But the list, if enforced, would delay major energy projects in the pipeline sector, which Russia dominates, and the fast-growing global liquefied natural gas (LNG) market, in which Russia is so far not a big participant.
The diplomats said the EU was considering restricting Russian access to piping used for building oil and natural gas pipelines, drilling pipes to extract oil and gas, floating or submersible drilling platforms, as well as floating cranes and dredging equipment.
That would likely halt or delay development of Gazprom's South Stream pipeline, planned to pump 63 billion cubic metres (bcm) of natural gas a year, equivalent to 15 percent of European demand, via the Black Sea into the EU later this decade, cementing Russia's position as the region's dominant gas supplier.
"If Europe's engineering partners are prevented from work on any of the big Russian oil or gas projects because of the sanctions, they are almost certainly going to be delayed," said one advisory source that works on Russian energy projects.
Gazprom's main partners in South Stream are Italy's Eni , France's EDF, Austria's OMV and Germany's Wintershall, which is a subsidiary of German chemical giant BASF.
Already, the European Commission, the EU executive, has suspended negotiations on making South Stream conform with EU legislation.
South Stream relies heavily on European know-how to be built, such as through a contract with Italy's Saipem to work on one of four parallel South Stream pipelines due to cross the Black Sea.
YAMAL TOO
The proposed sanctions would also likely hit Novatek's Yamal LNG export project.
Novatek's main partners in the project are France's Total , a specialist in deep-sea drilling, and China's CNPC.
French oil services company Technip, which won the engineering, procurement and construction contract for Yamal LNG last May warned earlier on Thursday about the risk that sanctions against Russia could interrupt income flows from the Siberian project, sending its shares down more than 8 percent. [ID: nL6N0PZ10I]
EU diplomats were meeting on Thursday to debate tighter sanctions, but were expected to meet again next week before taking any final decision.
Energy Commissioner Guenther Oettinger said on Wednesday that the EU should not give Russia technical help to develop Arctic oil and gas fields if Moscow failed to help to defuse the Ukraine crisis.
Novatek, which has seen one of its shareholders hit by U.S. sanctions, is the main developer of the Arctic Yamal peninsula LNG export project, which plans to export 16.5 million tonnes of LNG a year.
The project's gas is so far in the Arctic North that it requires the use of specialised technology, often provided by Western partners. (Additional reporting by Michel Rose in Paris, editing by David Evans and William Hardy)
By Nick Cunningham | Thu, 24 July 2014 22:06 | 0
A city council in Maine took action on June 21 that all but blocks off another export route for Canada’s oil sands. The South Portland City Council voted 6-1 to block the export of oil from its waterfront, citing concerns about local air and water pollution.
The vote potentially kills off a larger plan by the oil industry to connect Alberta’s oil sands to the Atlantic Coast. South Portland, Maine is a key piece of the puzzle because it is home to the end of a pipeline that runs between the coast and Montreal. The pipeline currently only runs in one direction – it accepts oil imports and sends it northwest to Montreal.
Although plans were in the preliminary stages, the owner of the pipeline, Portland Pipe Line Corporation, had been considering a proposal to reverse the flow. This would allow oil sands to flow east to the coast.
But if completed, the project would require the construction of two large smokestacks, which would be needed to burn off toxic chemicals before the oil could be loaded onto ships. The combustion stacks would emit benzene, a carcinogen, and other harmful air pollutants into South Portland communities.
The prospect of a mini-surge of industrialization on the South Portland waterfront led to strong local opposition. A few hundred residents packed a June 21 town meeting that saw the city council vote on legislation that forbids the bulk loading of oil onto ships. When the legislation was approved, those in attendance erupted into applause.
Portland Pipe Line Corporation said the council’s move “would clearly be preempted by federal and state law,” and that it was an “illegal ordinance.” Supporters, including members of the council, are confident the ban will withstand legal scrutiny.
“I’d like to take this opportunity to plead with the [Portland Pipe Line Corp.] and Waterfront Coalition: Please do not fight this ordinance,” Councilor Tom Blake said. “This ordinance is the will of the people … All you’re going to do is alienate yourself even further.”
Oil producers in Canada’s oil sands are finding it increasingly difficult to get their product to market. Other routes have not proved any easier.
The Keystone XL pipeline, which would carry oil from Alberta to the Gulf of Mexico, has been in limbo for more than six years. It has been ground up in regulatory and political hell, and due to a groundswell of local opposition working in conjunction with national environmental groups, the issue was pushed to the top of the agenda in the U.S. Congress. And once an issue becomes controversial in Congress, partisan gridlock usually sets in.
The oil industry and its allies have long argued that blocking Keystone XL would accomplish nothing because Canada would simply ship the oil to China via their own west coast. And with Keystone XL on ice for now, Enbridge is trying to fulfill that promise. It is seeking to build the Northern Gateway pipeline, which would take Alberta oil to the west coast of Canada.
Canadian Prime Minister Stephen Harper – an ally of the industry – approved that route on June 17. However, a week later, the Canadian Supreme court handed down a major victory for First Nations tribes in and around the Canadian oil patch. The decision granted native tribes much greater power over major infrastructure projects. And with many of them voicing opposition to Northern Gateway, the west coast route for Canada’s oil sands could be in danger.
That is why the South Portland decision could be so important. With Keystone XL up in the air, the Gulf Coast route is uncertain. With empowered native tribes in Canada opposed to the Northern Gateway pipeline, the route to Canada’s west coast is in doubt.
Now, a relatively easy route to the Atlantic Coast – by reversing existing pipelines – could be blocked.
That means oil sands companies may have to continue to do what they have been doing: shipping much of their production by rail. But that is proving to be more costly than expected. As costs rise and the vast oil sands reserves are blocked in every direction they turn, production may have to be cut back. And this is exactly what environmentalists have been arguing for all along.
By Nick Cunningham of Oilprice.com
By Chris Dalby | Thu, 24 July 2014 21:53 | 0
As the heir-in-waiting to the title of world’s largest economy, China finds itself in a strange position in terms of its oil consumption.
In September 2013, China became the biggest net importer of crude, beating out the U.S. for the first time. This came as no surprise, given how rapidly China’s thirst for oil has grown, although landing in top place happened a little ahead of U.S. Energy Information Agency (EIA) predictions that it would take place in 2014. However, where the U.S. has been shoring up its own internal production, China has lagged behind. Between 2011 and 2014, U.S. oil production rose by 31 percent, as opposed to China, which saw its own production increase by a little more than 5 percent over that time. This leaves China utterly dependent on oil imports, a vulnerable position to be in at a time when its economy is beginning to wobble.
China’s demand for black gold is only set to increase, causing it to spend a staggering $500 billion a year on imports by 2020, according to Wood Mackenzie. This increase is being fueled largely by an explosion in car ownership. But who will be the faithful bartender, refusing to cut China off?
In the first six months of 2014, Iran’s oil exports to China shot up by 48 percent over 2013, reaching 630,000 barrels a day (bbl/d). This might represent only 10 percent of the country’s international crude imports, but it sends a clear message. Unburdened by the need to look tough against unsavory regimes, China has made it clear that it will continue to rely on Tehran for the foreseeable future. This is a stunning reversal from 2010-2011, when China tried in vain to fight sanctions on Iran at the United Nations’ Security Council. It ultimately relented under pressure from Russia, when even Moscow could no longer deny the seriousness of Iran refusing to provide guarantees about its nuclear program
This led China to turn to two other regions of the world to shore up its oil supply. Africa had long been a trusted source with Angola, Libya and Sudan being seen as regular contributors. However, ongoing troubles in Libya, Sudan and South Sudan have made Beijing nervous. Rightly foreseeing the consequences that an unsteady oil flow would have on market confidence in the Chinese economy, the government has sought to shore up relations with trusted partners like Angola, the second largest source of oil imports to China. Iraq and Venezuela have also benefited from Beijing’s renewed attention.
While this has been happening, a coincidental trend has made these countries even more welcoming to Chinese advances: the United States’ own production levels have made it less reliant on its traditional foreign oil partners. The result has been swift and immediate. Besides imports from Iran going up 48 percent, those from Iraq went up 50 percent in 2013. Forty percent of Angolan exports now go to China, as opposed to just 15 percent to the U.S., while Venezuela has sworn it will double its provision of oil to China from 500,000 bbl/d to 1 million over the next few years.
Of course, China’s geopolitical skills are too finely honed for this not to come at a price for oil producing countries. Earlier this week, Venezuela’s President Nicolás Maduro and China’s President Xi Jinping signed a raft of agreements that will see Beijing build infrastructure and housing, as well as selling goods such as electronics to Caracas. But stunningly, Venezuela is not expected to pay for these in cash, but in oil. This precise round of agreements costs it 100,000 bbl/d. China’s masterful oil bargaining is now laid bare for all to see. A doubling of exports to China will see Venezuela exert major efforts to please its trading partner, but the economic assistance it is getting in return has been dismissed as being little more than petty cash, which will not stop the Venezuelan economy’s descent into recession.
Unlike Angola and Venezuela, Saudi Arabia seems to have been left out of China’s new oil-buying bonanza. It accounts for a very respectable 19 percent of China’s oil imports, and is the country’s top oil trading partner, but this level is remaining steady from 2013 to 2014 at 1.17 million bbl/d, but this looks set to drop in the future. Two new refineries in Western China will be running on crude obtained from Russia and Central Asia, but not Saudi Arabia. This shutting out effectively leaves Riyadh unable to renegotiate its contributions. Traders feel that this situation is not due to any animosity but because of China refusing to be too close to one single supplier.
Being so spoilt for choice, one would imagine China would feel secure about its oil future. But its behavior nearer to home seems to point to just the opposite. It is widely believed that China’s territorial posturing in the South China Sea is hiding a country in need of rapid resource grabbing. In May, Vietnam was alarmed when a massive oil rig belonging to CNPC appeared in its waters, near the Paracel Islands, which Beijing claims control of. The issue escalated rapidly until the offending rig was moved back to Hainan Island on July 15. This seems to show that no matter how much oil China obtains through realpolitik, it would still much rather secure its own sources. What price it is willing to pay for that goal has yet to be revealed.
By Chris Dalby for Oilprice.com
By Gail Tverberg | Thu, 24 July 2014 21:09 | 0
The standard way to make forecasts of almost anything is to look at recent trends and assume that this trend will continue, at least for the next several years. With world oil production, the trend in oil production looks fairly benign, with the trend slightly upward (Figure 1).
If we look at the situation more closely, however, we see that we are dealing with an unstable situation. The top ten crude oil producing countries have a variety of problems (Figure 2). Middle Eastern producers are particularly at risk of instability, thanks to the advances of ISIS and the large number of refugees moving from one country to another.
Relatively low oil prices are part of the problem as well. The cost of producing oil is rising much more rapidly than its selling price, as discussed in my post Beginning of the End? Oil Companies Cut Back on Spending. In fact, the selling price of oil hasn’t really risen since 2011 (Figure 3), because citizens can’t afford higher oil prices with their stagnating wages.
The fact that the selling price of oil remains flat tends to lead to political instability in oil exporters because they cannot collect the taxes required to provide programs needed to pacify their people (food and fuel subsidies, water provided by desalination, jobs programs, etc.) without very high oil prices. Low oil prices also make the plight of oil exporters with declining oil production worse, including Russia, Mexico, and Venezuela.
Many people when looking at future oil supply concern themselves with the amount of reserves (or resources) remaining, or perhaps Energy Return on Energy Invested (EROEI). None of these is really the right limit, however. The limiting factor is how long our current networked economic system can hold together. There are lots of oil reserves left, and the EROEI of Middle Eastern oil is generally quite high (that is, favorable). But instability could still bring the system down. So could popping of the US oil supply bubble through higher interest rates or more stringent lending rules.
The Top Two Crude Oil Producers: Russia and Saudi Arabia
When we look at quarterly crude oil production (including condensate, using EIA data), we see that Russia’s crude oil production tends to be a lot smoother than Saudi Arabia’s (Figure 4). We also see that since the third quarter of 2006, Russia’s crude oil production tends to be higher than Saudi Arabia’s.
Both Russia and Saudi Arabia are headed toward problems now. Russia’s Finance Minister has recently announced that its oil production has hit and peak, and is expected to fall, causing financial difficulties. In fact, if we look at monthly EIA data, we see that November 2013 is the highest month of production, and that every month of production since that date has dropped from this level. So far, the drop in oil production has been relatively small, but when an oil exporter is depending on tax revenue from oil to fund government programs, even a small drop in production (without a higher oil price) is a financial problem.
We see in Figure 4 above that Saudi Arabia’s quarterly oil production is quite erratic, compared to oil production of Russia. Part of the reason Saudi Arabia’s oil production is so erratic is that it extends the life of its fields by periodically relaxing (reducing) production from them. It also reacts to oil price changes–if the oil price is too low, as in the latter part of 2008 and in 2009, Saudi oil production drops. The tendency to jerk oil production around gives the illusion that Saudi Arabia has spare production capacity. It is doubtful at this point that it has much true spare capacity. It makes a good story, though, which news media are willing to repeat endlessly.
Saudi Arabia has not been able to raise oil exports for years (Figure 5). It gained a reputation for its oil exports back in the late 1970s and early 1980s, and has been able to rest on its laurels. Its high “proven reserves” (which have never been audited, and are doubted by many) add to the illusion that it can produce any amount it wants.
In 2013, oil exports from Russia were equal to 88% of Saudi Arabian oil exports. The world is very close to being as dependent on Russian oil exports as it is on Saudi Arabian oil exports. Most people don’t realize this relationship.
The current instability of the Middle East has not hit Saudi Arabia yet, but there is increased fighting all around. Saudi Arabia is not immune to the problems of the other countries. According to BBC, there is already a hidden uprising taking place in eastern Saudi Arabia.
US Oil Production is a Bubble of Very Light Oil
The US is the world’s third largest producer of crude and condensate. Recent US crude oil production shows a “spike” in tight oil productions–that is, production using hydraulic fracturing, generally in shale formations (Figure 6).
If we look at recent data on a quarterly basis, the trend in production also looks very favorable.
The new crude is much lighter than traditional crude. According to the Wall Street Journal, the expected split of US crude is as follows:
There are many issues with the new “oil” production:
- The new oil production is so “light” that a portion of it is not what we use to power our cars and trucks. The very light “condensate” portion (similar to natural gas liquids) is especially a problem.
- Oil refineries are not necessarily set up to handle crude with so much volatile materials mixed in. Such crude tends to explode, if not handled properly.
- These very light fuels are not very flexible, the way heavier fuels are. With the use of “cracking” facilities, it is possible to make heavy oil into medium oil (for gasoline and diesel). But using very light oil products to make heavier ones is a very expensive operation, requiring “gas-to-liquid” plants.
- Because of the rising production of very light products, the price of condensate has fallen in the last three years. If more tight oil production takes place, available prices for condensate are likely to drop even further. Because of this, it may make sense to export the “condensate” portion of tight oil to other parts of the world where prices are likely to be higher. Otherwise, it will be hard to keep the combined sales price of tight oil (crude oil + condensate) high enough to encourage more tight oil production.
The other issue with “tight oil” production (that is, production from shale formations) is that its production seems to be a “bubble.” The big increase in oil production (Figure 6) came since 2009 when oil prices were high and interest rates were very low. Cash flow from these operations tends to be negative. If interest rates should rise, or if oil prices should fall, the system is likely to hit a limit. Another potential problem is oil companies hitting borrowing limits, so that they cannot add more wells.
Without US oil production, world crude oil production would have been on a plateau since 2005.
Canadian Oil Production
The other recent success story with respect to oil production is Canada, the world’s fifth largest producer of crude and condensate. Thanks to the oil sands, Canadian oil production has more than doubled since the beginning of 1994 (Figure 10).
Of course, there are environmental issues with respect to both oil from the oil sands and US tight oil. When we get to the “bottom of the barrel,” we end up with the less environmentally desirable types of oil. This is part of our current problem, and one reason why we are reaching limits.
Oil Production in China, Iraq, and Iran
In the first quarter of 2014, China was the fourth largest producer of crude oil. Iraq was sixth, and Iran was seventh (based on Figure 2 above). Let’s first look at the oil production of China and Iran.
As of 2010, Iran was the fourth largest producer of crude oil in the world. Iran has had so many sanctions against it that it is hard to figure out a base period, prior to sanctions. If we compare Iran’s first quarter 2014 oil production to its most recent high production in the second quarter of 2010, oil production is now down about 870,000 barrels a day. If sanctions are removed and warfare does not become too much of a problem, oil production could theoretically rise by about this amount.
China has relatively more stable oil production than Iran. One concern now is that China’s oil production is no longer rising very much. Oil production for the fourth quarter of 2013 is approximately tied with oil production for the fourth quarter of 2012. The most recent quarter of oil production is down a bit. It is not clear whether China will be able to maintain its current level of production, which is the reason I mention the possibility of a decline in oil production in Figure 2.
The lack of growth in China’s oil supplies may be behind its recent belligerence in dealing with Vietnam and Japan. It is not only exporters that become disturbed when oil supplies are not to their liking. Oil importers also become disturbed, because oil supplies are vital to the economy of all nations.
Now let’s add Iraq to the oil production chart for Iran and China.
Thanks to improvements in oil production in Iraq, and sanctions against Iran, oil production for Iraq slightly exceeds that of Iran in the first quarter of 2014. However, given Iraq’s past instability in oil production, and its current problems with ISIS and with Kurdistan, it is hard to expect that Iraq will be a reliable oil producer in the future. In theory Iraq’s oil production can rise a few million barrels a day over the next 10 or 20 years, but we can hardly count on it.
The Oil Price Problem that Adds to Instability
Figure 13 shows my view of the mismatch between (1) the price oil producers need to extract their oil and (2) the price consumers can afford. The cost of extraction (broadly defined including taxes required by governments) keeps rising while “ability to pay” has remained flat since 2007. The inability of consumers to pay high prices for oil (because wages are not rising very much) explains why oil prices have remained relatively flat in Figure 3 (near the top of this post), even while there is fighting in the Middle East.
When the selling price is lower than the full cost of production (including the cost of investing in new wells and paying dividends to shareholders), the tendency is to reduce production, one way or another. This reduction can be voluntarily, in the form of a publicly traded company buying back stock or selling off acreage.
Alternatively, the cutback can be involuntary, indirectly caused by political instability. This happens because oil production is typically heavily taxed in oil exporting nations. If the oil price remains too low, taxes collected tend to be too low, making it impossible to fund programs such as food and fuel subsidies, desalination plants, and jobs programs. Without adequate programs, there tend to be uprisings and civil disorder.
If a person looks closely at Figure 13, it is clear that in 2014, we are out in “Wile E. Coyote Territory.” The broadly defined cost of oil extraction (including required taxes by exporters) now exceeds the ability of consumers to pay for oil. As a result, oil prices barely spike at all, even when there are major Middle Eastern disruptions (Figure 3, above).
The reason why Wile E. Coyote situation can take place at all is because it takes a while for the mismatch between costs and prices to work its way through the system. Independent oil companies can decide to sell off acreage and buy back shares of stock but it takes a while for these actions to actually take place. Furthermore, the mismatch between needed oil prices and charged oil prices tends to get worse over time for oil exporters. This lays the groundwork for increasing dissent within these countries.
With oil prices remaining relatively flat, importers become complacent because they don’t understand what is happening. It looks like we have no problem when, in fact, there really is a fairly big problem, lurking behind the scenes.
To make matters worse, it is becoming more and more difficult to continue Quantitative Easing, a program that tends to hold down longer-term interest rates. The expectation is that the program will be discontinued by October 2014. The reason why the price of oil has stayed as high as it has in the last several years is because of the effects of quantitative easing and ultra low interest rates. If it weren’t for these, oil prices would fall, because consumers would need to pay much more for goods bought on credit, leaving less for the purchase of oil products. See my recent post, The Connection Between Oil Prices, Debt Levels, and Interest Rates.
Because of the expectation that Quantitative Easing will end by October 2014 and the pressure to tighten credit conditions, my expectation is that the affordable price of oil will start dropping in late 2014, as shown in Figure 13. The growing disparity between what consumers can afford and what producers need tends to make the Wile E. Coyote overshoot condition even worse. It is likely to lead to more problems with instability in the Middle East, and a collapse of the US oil production bubble.
Conclusion
I explained earlier that we live in a networked economy, and this fact changes the way economic models work. Many people have developed models of future oil production assuming that the appropriate model is a “bell curve,” based on oil depletion rates and the inability to geologically extract more oil. Unfortunately, this isn’t the right model.
The situation is far more complex than simple geological decline models assume. There are multiple limits involved–prices needed by oil producers, prices affordable by oil importers, and prices for other products, such as water and food. Interest rates are also important. There are time lags involved between the time the Wile E. Coyote situation begins, and the actions to fix this mismatch takes place. It is this time lag that tends to make drop-offs very steep.
The fact that we are dealing with political instability means that multiple fuels are likely to be affected at once. Clearly natural gas exports from the Middle East will be affected at the same time as oil exports. Many other spillover effects are likely to happen as well. US businesses without oil will need to cut back on operations. This will lead to job layoffs and reduced electricity use. With lower electricity demand, prices for electricity as well as for coal and natural gas will tend to drop. Electricity companies will increasingly face bankruptcy, and fuel suppliers will reduce operations.
Thus, we cannot expect decline to follow a bell curve. The real model of future energy consumption crosses many disciplines at once, making the situation difficult to model. The Reserves / Current Production model gives a vastly too high indication of future production, for a variety of reasons–rising cost of extraction because of diminishing returns, need for high prices and taxes to support the operations of exporters, and failure to consider interest rates.
The Energy Return on Energy Invested model looks at a narrowly defined ratio–usable energy acquired at the “well-head,” compared to energy expended at the “well-head” disregarding many things–including taxes, labor costs, cost of borrowing money, and required dividends to stockholders to keep the system going. All of these other items also represent an allocation of available energy. A multiplier can theoretically adjust for all of these needs, but this multiplier tends to change over time, and it tends to differ from energy source to energy source.
The EROEI ratio is probably adequate for comparing two “like products”–say tight oil produced in North Dakota vs tight oil produced in Texas, or a ten year change in North Dakota energy ratios, but it doesn’t work well when comparing dissimilar types of energy. In particular, the model tends to be very misleading when comparing an energy source that requires subsidies to an energy source that puts off huge tax revenue to support local governments.
When there are multiple limits that are being encountered, it is the financial system that brings all of the limits together. Furthermore, it is governments that are at risk of failing, if enough surplus energy is not produced. It is very difficult to build models that cross academic areas, so we tend to find models that reflect “silo” thinking of one particular academic specialty. These models can offer some insight, but it is easy to assume that they have more predictive value than they do.
Unfortunately, the limits we are reaching seem to be financial and political in nature. If these are the real limits, we seem to be not far away from the simultaneous drop in the production of many energy products. This type of limit gives a much steeper drop off than the frequently quoted symmetric “bell curve of oil production.” The shape of the drop off corresponds to (1) the type of drop off experienced by previous civilizations when they collapsed, (2) the type of drop-off I have forecast for world energy consumption, and (3)Ugo Bardi’s Seneca cliff. The 1972 book Limits to Growth by Donella Meadows et al. says (page 125), “The behavior mode of of the system shown in figure 35 is clearly that of overshoot and collapse,” so it tends to come to the same conclusion as well.
By Gail Tverberg of Our Finite World
By Sabrina Valle and Mario Sergio Lima Jul 25, 2014 3:17 AM GMT+0700
Petroleo Brasileiro SA (PETR4)’s vessel suppliers are urging Brazil to ease limits on foreign-built equipment as orders from the state-run company fall behind schedule at local yards, people familiar with the proposal said.
A group of shipbuilders met with government officials in Brasilia last week to propose changes to national content rules that would allow them to have more construction and engineering work done in Asia, three people with direct knowledge of the request said, asking not to be named because the talks aren’t public. They propose investments they make in local shipyards be taken into account when calculating how much equipment made overseas can go into the vessels, the people said.
Petrobras, the biggest oil producer in waters deeper than 1,000 feet (305 meters), is counting on the delivery of floating platforms and drill ships to develop the biggest oil finds in the Americas this century and double output by 2020. Most Brazilian companies hired to supply the units aren’t yet fully capable of building them after shipyard construction delays and cost overruns.
Sinaval, the industry group representing Brazil’s largest shipyards, didn’t respond to e-mails seeking comment on the proposal.
“In highly complex projects, it’s common to identify delays in stages of the construction process, without any impact on the final deadlines for delivery of the units,” Petrobras, based in Rio de Janeiro, said in an e-mailed response to questions. “Suppliers can alter the construction strategy, including the hiring of products and services abroad, as long as in agreement with and authorized by Petrobras and in compliance with local content rules.”
Rousseff’s Idea
Brazilian President Dilma Rousseff helped draft legislation that increased the requirement for locally made equipment in Petrobras contracts 11 years ago -- when she was the energy minister to her predecessor and mentor Luiz Inacio Lula da Silva -- in a bid to revive the country’s shipyards. The front-runner for the October presidential elections, Rousseff has heralded the revival of Brazil’s shipbuilding industry as an example of job-creation policies.
More than 10 shipyards are being built or expanded in Brazil to supply the oil industry, mainly because of contracts from Petrobras.
In the proposal presented last week, the ship suppliers are seeking to include the construction of dockyard infrastructure such as piers and cranes as part of the calculation of minimum local content requirements, the people said.
Petrobras rose 0.2 percent to 20.31 reais at the close in Sao Paulo.
To contact Bloomberg News staff for this story: Sabrina Valle in Rio de Janeiro at svalle@bloomberg.net; Mario Sergio Lima in Brasilia Newsroom at mlima11@bloomberg.net
To contact the editors responsible for this story: Carlos Caminada at ccaminada1@bloomberg.net Steven Frank
German Utilities Bail Out Electric Grid at Wind’s Mercy
By Julia Mengewein Jul 25, 2014 6:01 AM GMT+0700
Germany’s push toward renewable energy is causing so many drops and surges from wind and solar power that the government is paying more utilities than ever to help stabilize the country’s electricity grid.
Twenty power companies including Germany’s biggest utilities EON SE and RWE AG now get fees for pledging to add or cut electricity within seconds to keep the power system stable, double the number in September, according to data from the nation’s four grid operators. Utilities that sign up to the 800 million-euro ($1.1 billion) balancing market can be paid as much as 400 times wholesale electricity prices, the data show.
Germany’s drive to almost double power output from renewables by 2035 has seen one operator reporting five times as many potential disruptions as four years ago, raising the risk of blackouts in Europe’s biggest electricity market while pushing wholesale prices to a nine-year low. More utilities are joining the balancing market as weak prices have cut operating margins to 5 percent on average from 15 percent in 2004, with RWE reporting its first annual loss since 1949.
“At the beginning, this market counted for only a small portion of our earnings,” said Hartmuth Fenn, the head of intraday, market access and dispatch at Vattenfall AB, Sweden’s biggest utility. “Today, we earn 10 percent of our plant profits in the balancing market” in Germany, he said by phone from Hamburg July 22.
Price Plunge
In Germany’s daily and weekly balancing market auctions, winning bidders have been paid as much as 13,922 euros to set aside one megawatt depending on the time of day, grid data show. Participants stand ready to provide power or cut output in notice periods of 15 minutes, 5 minutes or 30 seconds, earning fees whether their services are needed or not.
German wholesale next-year electricity prices have plunged 60 percent since 2008 as green power, which has priority access to the grid, cut into the running hours of gas, coal and nuclear plants. The year-ahead contract traded at 35.50 euros a megawatt hour on the European Energy Exchange AG in Leipzig, Germany.
The country’s lawmakers last month backed a revision of the country’s clean-energy law to curb green subsidies and slow gains in consumer power prices that are the second-costliest in the European Union. Chancellor Angela Merkel’s energy switch from nuclear power aims to boost the share of renewables to at least 80 percent by 2050 from about 29 percent now.
Power Premium
Jochen Schwill and Hendrik Saemisch, both 33, set up Next Kraftwerke GmbH in 2009 to sell power from emergency generators in hospitals to the power grid. Today, the former University of Cologne researchers employ about 80 people and have 1,000 megawatts from biomass plants to gas units at their disposal, or the equivalent capacity of a German nuclear plant.
“That was really the core of our founding idea,” Schwill said by phone from Cologne July 21. “That the boost in renewable energy will make supply more intermittent and balancing power more lucrative in the long run.”
Thomas Pilgram, who has sold balancing power since 2012 as chief executive officer of Clean Energy Sourcing in Leipzig, Germany, expects the wave of new entrants to push down balancing market payments.
“New participants are flooding into the market now, which means that prices are coming under pressure,” Pilgram said. “Whoever comes first, gets a slice of the cake, the others don’t because prices have slumped.”
Increased Competition
German grid regulator Bundesnetzagentur welcomes the increase in balancing market participants.
“That’s in our interest as we want to encourage competition in this market,” Armasari Soetarto, a spokeswoman for the Bonn-based authority, said by phone July 18. “More supply means lower prices and that means lower costs for German end users.”
The average price for capacity available within five minutes has dropped to 1,109 euros a megawatt in the week starting July 14, from 1,690 euros in the second week of January, Next Kraftwerke data show. Payments for cutting output within 15 minutes dropped to 361 euros from 1,615 euros in January.
The number of participants has increased as the country’s four grid operators refined how capacity is allocated. In 2007, the grids started one common auction and shortened the bidding periods. Since 2011, power plant operators commit their 5-minute capacity on a weekly basis instead of a month before.
Balance Payments
Balancing-market payments to utilities totaled 800 million euros last year, similar to the amount in 2012, grid data show. Utilities were asked to reserve 3,898 megawatts this week, which compares with Germany’s total installed power generation capacity of 183,649 megawatts as of July 16. One megawatt is enough to power 2,000 European homes.
Tennet TSO GmbH, Germany’s second-biggest grid operator, told power plant operators to adjust output 1,009 times to keep the grid stable last year, compared with 209 times in 2010. The interventions, used alongside the balancing market, are expected to be as frequent this year as in 2013, Ulrike Hoerchens, a spokeswoman for the Bayreuth, Germany-based company, said by phone on July 23.
To adapt to volatile supply and demand, RWE invested as much as 700 million euros on technology for its lignite plants that allow the units to change output by 30 megawatts within a minute. The coal-fired generators were originally built to run 24 hours a day.
RWE’s lignite generators, which have a total capacity of 10,291 megawatts, are flexible enough to cut or increase output by 5,000 megawatts on a sunny day, when power from solar panels floods the grid or supply vanishes as skies turn cloudy, according to Ulrich Hartmann, an executive board member at RWE’s generation unit.
“Back in the days, our lignite plants were inflexible, produced power around the clock and were always earning money,” Hartmann in Bergheim, Germany, said in a July 9 interview. “Now they are as flexible as gas plants.”
To contact the reporter on this story: Julia Mengewein in Frankfurt at jmengewein@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net; Dan Stets at dstets@bloomberg.net Andrew Reierson, Rob Verdonck
By Sandrine Rastello and Eric Martin Jul 24, 2014 11:15 PM GMT+0700
The International Monetary Fund lowered its outlook for global growth this year as expansions weaken from China to the U.S. and military conflicts raise the risk of a surge in oil prices.
The world economy will advance 3.4 percent in 2014, the IMF said, less than its 3.6 percent prediction in April and stronger than last year’s 3.2 percent. Next year growth will be 4 percent, compared with an April forecast for 3.9 percent, the fund said.
“Global growth could be weaker for longer, given the lack of robust momentum in advanced economies” even as interest rates stay low, the IMF said in an update to its World Economic Outlook report. “Monetary policy should thus remain accommodative in all major advanced economies.”
The IMF report reflected a world rattled by geopolitical risks that have risen since April, including the potential for “sharply higher oil prices” because of recent Middle East unrest.
Growth in emerging markets is projected to be 4.6 percent this year, compared with an April forecast for 4.9 percent, the IMF said.
China’s economy is seen growing 7.4 percent this year, less than the 7.5 percent forecast in April, the IMF said. Next year, growth in the world’s second-largest economy with slow further, to 7.1 percent, the Washington-based fund said, less than its forecast in April for 7.3 percent growth.
Russia’s Slump
Among developing economies, the biggest reduction in forecasts was for Russia’s growth, which was downgraded to 0.2 percent from 1.3 estimated previously amid capital flight caused by its involvement in the conflict in Ukraine.
The IMF’s Russia forecasts exclude the effects of recent sanctions the U.S. has imposed on the country and don’t take into account any that the European Union might take, IMF chief economist Olivier Blanchard said at a press conference in Mexico City today. “These sanctions could probably further decrease the growth rate of Russia,” he said.
In Japan, the economy’s projected 1.6 percent advance this year may be followed by 1.1 percent from in 2015, “mostly due to the planned unwinding of fiscal stimulus,” the IMF said.
In the 18-country euro region, Italy and France were cut while Spain was revised higher to 1.2 percent, up from 0.9 percent.
U.S. Slowdown
Most of the downgrade for this year in developed economies was due to the U.S., which was cut to 1.7 percent from an April prediction of 2.8 percent because of a first-quarter contraction. The forecast for 2015 was unchanged at 3 percent. The IMF issued its U.S. forecasts yesterday.
In prepared remarks, Blanchard said the U.S. economy is forecast to grow 3 percent to 3.25 percent for the rest of the year. He indicated the fund agrees with Federal Reserve plans to wind down stimulus.
“The current plans, namely the end of tapering later this year and increases in the policy rate from the middle of next year, are appropriate,” Blanchard said. “But the timing of the increase in the policy rate may have to be adjusted.”
Blanchard also addressed concerns about the potential for excessive risk taking associated with extended periods of low interest rates.
“We agree that, in some financial markets, valuations appear perhaps optimistic,” Blanchard said. “But, overall, we do not see a systemic threat to financial stability, mainly because of lower leverage in both banks and, to the extent we can measure it, in non-banks as well.”
To contact the reporters on this story: Sandrine Rastello in Washington at srastello@bloomberg.net; Eric Martin in Mexico City at emartin21@bloomberg.net
To contact the editors responsible for this story: Chris Wellisz at cwellisz@bloomberg.net Brendan Murray
By Dan Murtaugh Jul 25, 2014 1:13 AM GMT+0700
Gulf Coast crude weakened the most in six months versus global prices after a rally this month amid record demand from refiners put pressure on fuel margins.
Light Louisiana Sweet for August delivery weakened by $2.86 a barrel to a premium of $1.66 versus European Dated Brent at 2:08 p.m., according to data compiled by Bloomberg. August delivery will stop trading tomorrow. The premium versus U.S. benchmark West Texas Intermediate sank $2.45 to $1.30 a barrel. September LLS was valued at about $3.35 over WTI, according to broker PVM.
The 3-2-1 crack spread on the Gulf Coast, a rough estimate of the profit from turning LLS into gasoline and diesel, fell to $1.17 a barrel yesterday, the lowest since December 2012. It rebounded to $4.74 today.
“We expect further weakness in LLS,” Amrita Sen, the chief oil market analyst for Energy Aspects Ltd. in London, said by phone. “The only way to balance the U.S. system is for crude prices to fall until you incentivize refinery runs again.”
The drop followed a rapid run-up in Gulf Coast prices as refineries two weeks ago processed the most crude since at least 1992. LLS jumped from a $1.49-a-barrel discount to Brent on July 15 to a $4.52 premium yesterday, the highest level since July 22, 2013.
The jump in prices is drawing more crude cargoes to the Gulf Coast, including at least four tankers from West Africa since July 16, according to lists of charters compiled by Bloomberg. Prior to that there hadn’t been a booking reported since July 3.
Cargo Imports
Weak Brent prices and high refinery runs in the U.S. had made it economic to ship some distressed Atlantic cargoes to Gulf Coast refineries, Vienna-based JBC Energy said in a July 21 research note.
“We are now beginning to see some opportunities for prompt trans-Atlantic arb -- something that has been exceedingly rare in the shale boom era,” JBC said.
An average of 890,000 metric tons is set to load in the four weeks including the week of July 27, the most in two months, according to data compiled by Bloomberg.
Gulf Coast refiners processed 8.62 million barrels a day during the week ended July 18, near the record 8.65 million two weeks before.
The amount of crude in storage in the Gulf Coast divided by refinery runs, a measure of how well-supplied the market is, fell to 23 days last week, the lowest level since February.
LLS is a low-sulfur, or sweet, crude of similar quality to West Texas Intermediate, the U.S. benchmark priced in Cushing, Oklahoma, and Brent, which most waterborne oil is priced against.
Historical Premium
From 1983 to 2011, LLS averaged an annual premium of 88 cents to $4.80 a barrel over Brent, as refineries on the Gulf Coast depended on foreign oil.
The U.S. shale boom, which increased crude production 63 percent in the past five years, has brought more domestic oil to the Gulf Coast, eliminating the need for most light, low-sulfur crude imports. LLS sank to an all-time low $16.58 discount versus Brent on Nov. 27.
The recent shift to a premium caught many by surprise, Andrew Lebow, senior vice president at Jefferies Bache LLC in New York, said by phone.
“Incredibly, sweet looks like it’s tight, which would be completely the opposite of market expectations,” he said. “We always thought the next sweet barrel would be easily available.”
To contact the reporter on this story: Dan Murtaugh in Houston at dmurtaugh@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Bill Banker
Oil Draft Regulations for South Africa ‘Ready in Weeks’
By Paul Burkhardt Jul 24, 2014 11:09 PM GMT+0700
Draft regulations on oil and gas exploration in South Africa will be ready within weeks so that companies can comment on the proposed rules, Mineral Resources Minister Ngoako Ramatlhodi said.
“May well be that the industry is satisfied, is comfortable with the regulations,” Ramatlhodi said in an interview today on the Eirik Raude, a drilling rig hired by Total SA (FP) that’s in waters off the country’s southern coast. The government would then “move forward, allow them to do more drilling,” he said.
Proposed changes to South Africa’s 2002 Mineral and Petroleum Resources Development Act include giving the state the right to a free 20 percent stake in all new energy ventures and to buy an unspecified additional share at an agreed price. Total, Exxon Mobil Corp. (XOM) and Anadarko Petroleum Corp. (APC), who also have stakes in offshore prospects, are among those that have objected to the law on the grounds that it is too vague and will undermine their businesses.
“It’s the government’s position, which must then be negotiated with stakeholders,” Ramatlhodi said. “They must make an input into that. Eventually we have to agree.”
Total, with partner Canadian Natural Resources Ltd. (CNQ), holds exploration rights in Block 11B/12B, about 175 kilometers (109 miles) off the coast in the Outeniqua Basin, where it’s drilling a deepwater well.
Total has “communicated to me that it would be quite important that we settle the bigger issues going forward quickly, which would allow them to do more,” Ramatlhodi said. A draft law may be three to four weeks away, he said.
Karoo Shale
The Paris-based oil company is drilling its first well off South Africa’s continental shelf. Work will take three to four months and cost as much as $200 million, Total Exploration and Production head for South Africa Henry Delafon told reporters. The well has a targeted depth of 3,500 meters (11,500 feet) in water 1,500 meters deep.
The minister said on July 15 that South Africa should consider drafting separate laws to regulate the fledgling oil and gas industry, which includes exploring shale deposits in the arid inland Karoo region. While parliament passed amendments to the MPRDA earlier this year, Ramatlhodi asked President Jacob Zuma to hold off on signing them into law pending a review by a committee.
“We don’t want a situation where the minister sits in his office without involving people who are putting money in the sea or in the Karoo,” he said.
Extract Concessions
Ramatlhodi took over from Susan Shabangu as mineral resources minister in May, after the African National Congress extended its two-decade rule in elections that month.
“The planned ministerial review panel provides a rare window of opportunity for upstream companies to extract concessions on the bill’s onerous terms,” Anne Fruhauf, southern Africa analyst at New York-based risk adviser Teneo Intelligence, said in an e-mailed response to questions.
“Growing ANC concern over lagging economic growth and investment may also help international oil companies, to extract regulatory concessions,” Fruhauf said.
To contact the reporter on this story: o contact the reporter on this story: Paul Burkhardt in Johannesburg at pburkhardt@bloomberg.net
To contact the editors responsible for this story: John Viljoen at jviljoen@bloomberg.net Ana Monteiro
By Patrick Donahue Jul 24, 2014 9:13 PM GMT+0700
July 24 (Bloomberg) –- Bloomberg View Columnist Leonid Bershidsky discusses the world’s impression of Russia and what Putin can do to reverse the negative public opinion. He speaks to Mark Barton on Bloomberg Television’s “Countdown.” (Source: Bloomberg)
German Chancellor Angela Merkel should be prudent in seeking sanctions on Russia aimed at shaking President Vladimir Putin’s support for Ukrainian rebels, the head of a business lobby tied to her party said.
As the European Commission makes proposals that could include curbs on Russian access to capital markets, the comments by Kurt Lauk hint at Merkel’s balancing act between outrage over the downing of Malaysia Airlines Flight 17 and German companies reluctant to jeopardize ties with Russia.
Lauk, who heads the Christian Democratic-linked Economic Council in Berlin, joined Merkel in backing expanded sanctions against Russia in an interview, while saying the economic impact on Europe’s biggest economy must be weighed.
Waging Financial War
“She is prudent enough to realize that as soon as the sanctions have an effect, for the next five to 10 years we have to rebuild the damage that has been done on all sides,” Lauk said yesterday. “You have to be prudent.”
Germany imports more than a third of its oil and gas from Russia and is the European Union’s top exporter to Russia. Amid U.S. pressure to punish Russia after 298 people died on the jetliner shot down over Ukraine on July 17, EU foreign ministers called two days ago for measures that could hit “access to capital markets, defense, dual-use goods, and sensitive technologies, including in the energy sector.”
Putin’s Price
“If the EU can act in unison politically it will have an impact on Putin,” Andreas Schockenhoff, a lawmaker in Merkel’s Christian Democratic Union, told reporters today. “We had to set up this process in a way that Putin realizes there’s a price to pay for destabilization in Europe.”
Merkel views the decision as a sign of EU determination “to intensify the sanctions that unfortunately are necessary” and wants “quick decisions on this,” Georg Streiter, a German government spokesman, said yesterday.
Russia’s economy has already been damaged by asset freezes and travel bans imposed by the EU earlier during the conflict over Ukraine, Lauk said. He cited the auto industry, retail and wholesale companies.
“The Russian population is getting poorer” by the existing sanctions, said Lauk, whose group has about 11,000 members.
President Barack Obama’s administration last week barred some Russian companies from accessing U.S. equity or debt markets for new financing with a maturity beyond 90 days.
“It’s easier for the United States to call for sanctions than Europe,” Lauk said, citing 190 billion euros ($256 billion) in outstanding European debt in Russia. “The question is, whom do you want to sanction?”
“We really have to make a good analysis and this is what the European Commission now has to do -- how to stop Putin’s Russia supporting terrorists with weapons,” Lauk said, referring to the 28-member EU’s executive body.
To contact the reporter on this story: Patrick Donahue in Berlin at pdonahue1@bloomberg.net
To contact the editors responsible for this story: Alan Crawford at acrawford6@bloomberg.net Tony Czuczka, Chad Thomas
By Priyanka Sharma Jul 24, 2014 7:22 PM GMT+0700
Traders booked the most tankers in eight months to ship diesel and heating oil to Europe from the U.S. Gulf, where refining is surging as a consequence of America’s rising crude production.
Oil companies either booked or plan to charter 16 tankers to transport cargoes on the route for loading during the next two weeks, according to the survey of six people involved in the trade yesterday. That compares with nine last week and is the highest count since Nov. 6.
The highest U.S. oil production in more than two decades means Gulf Coast refineries are processing close to the most fuel ever. A ban on exporting most crude means the nation’s plants can tap cheaper supplies than their European counterparts. Tankers taking those refined fuels across the Atlantic Ocean are earning the most for the time of year since at least 2012.
“There has been a strong increase of product being shipped from the Gulf Coast to Europe,” George Los, senior market analyst Charles R. Weber Co., a shipbroker in Greenwich, Connecticut, said by e-mail yesterday. “The month is on course to conclude at a record high.”
West Texas Intermediate crude, the U.S. grade for which futures are traded in New York, costs about $5 a barrel less than Brent, the benchmark for plants in Europe, according to data on the ICE Futures Europe exchange.
Refining Surge
Refineries in the Gulf of Mexico processed 8.62 million barrels a day of crude in the week to July 18, the highest for the time of year in Energy Department data starting in 1992. The all-time high was 8.65 million barrels a day on July 4. Total U.S. refining rates of 16.81 million barrels a day are also close to a record.
Tankers on the trade route to Amsterdam from Houston earned $12,106 a day yesterday, according to data from the Baltic Exchange, a publisher of freight prices based in London. That’s the highest for the time of year since at least 2012.
Derivatives to hedge July-to-September freight costs on the route traded at about $26 a metric ton yesterday, compared with as less than $20 a ton at the start of June, according to the exchange’s data.
The 16 ships are known as Medium Range tankers, for which standard cargo sizes are 38,000 metric tons. That implies exports of about 325,000 barrels a day. Nine of the charters have already been arranged and seven are anticipated cargoes.
While shipments to Europe from the U.S. are accelerating, those in the opposite direction are in decline. Traders hired or plan to hire 17 ships for the trade route, four fewer than the same week in 2013 and the least for the time of year since 2012, Bloomberg surveys show.
To contact the reporter on this story: Priyanka Sharma in London at psharma142@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net James Herron
By Jake Rudnitsky Jul 24, 2014 5:10 PM GMT+0700
Russia’s crude exports on tankers are poised to fall to the lowest in at least six years as a government push to improve and expand domestic refineries means more oil is exported as fuels like diesel.
Seaborne crude shipments from the world’s biggest energy exporter via the state-run pipeline system in August will fall 9.2 percent from this month to 2.215 million barrels a day, according to loading programs obtained by Bloomberg News. That’s the lowest since Bloomberg began tracking the data in 2008. Russia’s two biggest crude terminals, Primorsk and Novorossiysk, will both export the least on record.
Russian oil companies are refining more crude domestically after President Vladimir Putin pushed them to spend billions of dollars modernizing plants. Output of diesel and fuel oil are the highest since at least 2009, Energy Ministry data show. This puts pressure on European refiners who are already receiving less Russian crude as flows are diverted to China, which has been less critical of the Kremlin’s role in Ukraine, according to KBC Energy Economics.
“This trend of falling crude exports means we’re finally seeing results from the refinery modernization push,” Alexander Nazarov, an oil analyst at OAO Gazprombank in Moscow, said by phone. “Refining is picking up and crude output has peaked.”
Russia produced 10.55 million barrels of crude in June, up 0.1 percent from a month earlier in the first increase since January, according to the Energy Ministry’s CDU-TEK unit. The country’s refineries operated at the highest rate in two years on June 26, with offline daily processing capacity falling to 26,000 metric tons, before rising to 48,500 tons on July 23, according to CDU-TEK.
European Dependence
“Less crude and more products out of Russia will create problems for the European refining sector,” Ehsan Ul-Haq, senior market consultant at KBC Energy Economics in Walton-on-Thames, England, said by phone.
European refiners have struggled to turn a profit as the recession curbed demand for fuel, more efficient plants opened in Asia and the Middle East, and the boom in U.S. oil production closed a major export market. The biggest wave of closures since the 1980s has left the region more dependent on foreign imports of fuel.
Developed economies in Europe got 44 percent of their net oil imports last year from Russia, according to the Paris-based International Energy Agency.
Leaders in Europe are considering proposals for new sanctions today against Russia as officials begin downloading data from the voice recorders of the Malaysian Air jet that was downed last week in Ukraine, killing 298 people. Since the annexation of the Ukrainian region of Crimea in March, Europe and the U.S. have held back from imposing restrictions on Russia’s exports of oil and gas, which provide half the country’s budget.
To contact the reporter on this story: Jake Rudnitsky in Moscow at jrudnitsky@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net James Herron, John Deane
