The price for a barrel of oil fell on word that more production was coming from key OPEC members, but a report from the International Energy Agency (IEA) says the drop may not last because Middle East oil producers are facing a shortfall in investments.
A Bloomberg survey of oil companies, producers and analysts show production from members of OPEC rose in May by 75,000 barrels per day (bpd), to 29.98 million. Production levels were boosted by a 70,000 bpd output from Saudi Arabia, its first increase this year.
Even more oil is expected this week from Libya, which has struggled to keep production levels close to the pre-civil war mark.
More oil from key OPEC producers pushed the price of Brent crude, the global benchmark, to around $108.4 per barrel, a relative low point when compared with prices so far this year.
The price of oil can influence everything from corporate earnings to inflation. For consumers, higher oil prices usually means higher gasoline prices, which can deplete cash that would be normally reserved for things like groceries. A lower price per barrel, then, means more money to spend on other things.
A June 3 report from the IEA said a major portion of the estimated $40 trillion in investments needed to keep the lights on through 2035 will need to come from Middle East oil producers. Without those investments, oil prices may increase.
Right now, OPEC production is up against the glut of oil coming from North American shale. Oil supplies from non-OPEC producers are expected to increase by more than 4 million bpd between 2013 and 2018, with much of that coming from North America. That relieves some of the pressure on OPEC, which meets around 40 percent of the world's oil demand.
OPEC Secretary-General Abdalla el-Badri has cautioned, however, that the addition of non-OPEC oil supplies to the global market “should be viewed as a periodic shift."
By the mid-2020s, the North American shale boom cycle will bust and Middle East oil producers will need to pick up the slack, the IEA's report concluded.
The IEA also said a lot of the money needed in the future will be used just to keep current oil production levels static. An estimated $8 trillion will be needed for energy efficiency to make up for the expected decline from maturing oil and gas fields.
The price per barrel of oil tripled during the six-month oil embargo from Arab members of OPEC in the 1970s. The IMF said global inflation rose to 7 percent in part because of the embargo, compared with 4 percent in 1972.
"If investment doesn't pick up as needed, we will have much more volatile oil markets, and in the 2020s we will have higher oil prices," IEA Executive Director Maria van der Hoeven said.
By Daniel J. Graeber of Oilprice.com
If the Middle East fails to invest adequately in its oil fields, global oil prices could spike by an additional $15 per barrel in the 2020s. That comes from the International Energy Agency in a new report assessing global energy investment needs through 2035.
The report estimates the investment in energy required to meet global demand over the next several decades. For example, $1.6 trillion was spent on energy supplies across the globe in 2013. That figure is expected to climb to $2 trillion annually over the next 20 years, with more than half of the annual sum going to offset declining production. In other words, the world will be forced to cough up over $1 trillion each year just to keep energy production flat.
While those figures are hard to fathom, they point to a future in which fossil fuels – oil in particular – become more expensive as cheaper reserves decline and producers go after harder-to-reach resources.
The U.S. has become infatuated with shale oil and gas, and has been lulled into a false sense of confidence because of rising oil production in North Dakota and Texas. The oil industry has been busy convincing the American public that we are destined for energy “superpower” status.
It is true that U.S. oil production has risen to its highest levels in over 20 years, but it may be short-lived. The IEA predicts that tight oil production in non-OPEC countries “starts to run out of steam in the 2020s.” After U.S. shale oil begins to fizzle out, the world “becomes steadily more reliant on investment in the Middle East” to meet demand growth.
But the problem is that the Middle East may not be up to the task. The IEA projects that the Middle East will need to lift its production from around 28 million barrels per day (bpd) currently to 34 million bpd by 2035. This will require billions of dollars in new investment.
But the national governments in question – which largely control oil within their territories instead of private companies – cannot necessarily be counted upon, according to the IEA. “There are competing government priorities for spending, as well as political, security and logistical hurdles that could constrain production,” the report says, in what could be the understatement of the year.
The Middle East will “need to invest today if not yesterday,” the IEA’s chief economist, Fatih Birol said, because oil projects have lead times of about seven years. So in order to make up for declining tight oil production in places like the U.S., as well as meet rising demand, the Middle East needs to be preparing today for its 2020 production.
More to the point, the IEA predicted in a 2013 report that nearly half of total oil production growth between now and 2035 would come from just two countries – Iraq and Brazil. Iraq has succeeded in boosting its production to 3.6 million bpd, the highest level in 30 years, but its ability to nearly triple its oil production over that timeframe – which the IEA is counting on – is suspect, to say the least.
That means that oil prices could spike much higher by the 2020’s. The IEA estimates it could be $15 per barrel more as a result, but that could be wildly optimistic. Just to take one example, the IEA predicted in its 2002 World Energy Outlook that oil prices would remain flat for a decade or so, hitting $21 per barrel in 2010, after which prices would “rise steadily to $29 in 2030.”
Accurate forecasting is difficult, but that’s the point: Unanticipated geopolitical events can disrupt or entirely shatter our assumptions about what the future will look like.
All this is to say that we can’t count on adequate supplies (at a price we are willing to pay) to meet demand indefinitely. U.S. tight oil won’t solve all of our problems, despite what the industry says, nor will the traditional producers of the Middle East.
By Nick Cunningham of Oilprice.com
Prices of Russian domestic crude for June loading and delivery were lower compared with May due to the higher export duty and because supply was deemed sufficient, trading sources said Tuesday.
Western Siberian barrels traded between Rb14,000-14,300/mt ($400-408/mt) compared with Rb14,600/mt for the previous month. Prices fell between Rb200-600/mt, depending on crude grade and transportation, sources said. “The export duty went up and Brent went down,” a source said.
Russia raised the June export duty on its main Urals crude export blend to $385/mt from $376.10/mt in May. The higher export duty pushes down the export netback, which is used as a gage by domestic traders for the price of domestic crude.
Brent futures were trading at around $111/barrel at the start of the June Russian domestic trading window, but gradually fell into the $109’s/b. Pipeline prices were down as much as Rb600/mt, with railcar volumes seeing around a Rb200/ mt drop, traders said.
Rosneft awarded its regular monthly tender for Udmurtia crude at Rb14,530-14,600/ mt, down Rb600/mt from May volumes. The tender typically sets the tone of the subsequent spot trading. But the start of spot trading was slightly postponed after Lukoil, Russia’s largest independent crude producer, reported a fire at an oil treatment plant at its Usinskoye oil field in the North Russian Komi Republic.
While production was halted, traders were uncertain whether the fire would result in shortages. After the fire was extinguished and production resumed, however, healthy volumes of Usa crude changed hands on the floor of the St. Petersburg Exchange.
The grade from the Timan-Pechora region traded at Rb14,150-14,160, down from a Rb14,500-14,700/mt range last month. Overall supply was perceived to be ample, even though a host of Russian refineries had restarted after maintenance.
“There were no shortages,” a trader said. As trading drew to a close, however, slight shortages were reported due to renewed buying by the Mariisky refinery, which restarted after almost a year, sources said.
Prices of light crude were also edging higher, traders said. Light crude has been increasingly feeding into the Tuapse refinery, after it increased its capacity following a large-scale upgrade, traders said.
The premium of Indonesian Minas crude to front-month July ICE Brent futures rose to a four-week high of 48 cents/barrel Tuesday on strong buying interest during the Platts Market on Close process. Minas — also known as Sumatran Light — was assessed at $109.11/b, up $2.43/b from Monday when it was at a $3.00/b discount to July ICE Brent futures.
The premium was last higher on May 2, when it was assessed at plus $0.96/b. Minas, which has a gravity of 35.3 API and a 0.09% sulfur content, is typically used as a direct-burning crude by Japanese utilities for thermal power generation.
During the MOC process Tuesday, western trading house Glencore was seen bidding a 25,000 barrel Minas partial for July loading, but was left standing at the 0830 GMT close.
Trading sources said overall demand for medium sweet Indonesian grades, such as Minas, has been weak due to lower requirement from Japanese utilities. But some incremental demand from power utilities is expected with the start of the summer months in Japan, one trader said.
“[As] no nuclear plant will restart [soon], I believe there will be certain demand for direct burning crude,” said a sweet crude trader. Minas is fuel oil-rich (58%) and yields a fair amount of gasoil (19.2%) and kerosene (12.4%). It also yields 9.4% naphtha.
The Minas field, on the eastern coast of Sumatra in the South Sumatra basin, produces around 150,000-160,000 b/d, according to market sources.
NYMEX July crude settled 19 cents higher at $102.66/ barrel Tuesday, confined to a narrow 52-cent trading range but with support from expectations that US crude inventories fell last week.
ICE July Brent settled 1 cent lower at $108.82/b. In products, NYMEX July ULSD settled 1.15 cents lower at $2.8658/gal and July RBOB ended 12 points lower at $2.9487/gal.
US commercial crude stocks are expected to have fallen 2 million barrels last week with a pull-back in imports offsetting the idle crude unit at Marathon Petroleum’s Garyville, Louisiana, refinery, a Platts poll of analysts showed Monday.
Still, NYMEX front-month crude stalled at the higher end of a recent trading range near $105/b as overriding fundamentals of the market remain the same. “[The US] has a massive amount of oil in storage, multi-decade high production and no significant change in the fundamentals,” said Gene McGillian, analyst at Tradition Energy.
The geopolitical landscape of the session was also sedate, leading to a near unchanged move in Brent futures. “There is no new news as far as Ukraine and Russia and no immediate disruption to supply so geopolitical risk is factored in at the moment and the market is just not pushing higher on that possibility,” he said.
In addition, the possible restarts of Libyan oil production has kept oil futures contained. Reports said Monday that Libyan production was at 156,000 b/d, up from 155,00 b/d a day earlier and that the Hariga oil export terminal could reopen within two days.
OPEC members are “doing their job” to keep oil markets adequately supplied this year, but need to increase investment to ensure that they will continue to do so in the future, the International Energy Agency’s chief economist, Fatih Birol, said Tuesday.
The IEA warned in a special report on world energy investment launched earlier Tuesday in London that world oil markets would be tighter and more volatile and that oil prices would be $15/barrel higher in 2025 if Middle Eastern producers failed to increase the level of investment needed to ensure sufficient supply.
In mid-May, the agency said the oil producer group would need to boost its output in the third quarter by some 900,000 b/d from an estimated April level of 29.9 million b/d to meet rising global demand.
Birol, speaking to Platts on the sidelines of the launch, stressed the importance of OPEC investing now to meet future needs. “For this year, they are doing their job, but they need to invest,” he said.
He expressed some concern about output growth in Iraq, where a key pipeline that moves Kirkuk crude from the northern fields to the Turkish Mediterranean coast has been closed since early March because of sabotage by insurgents, and where tension between the federal government in Baghdad and the Kurdish Regional Government has been growing over the KRG’s independent exports of crude from the semi-autonomous region.
“We see that the risks are growing, and even though the potential is there, further growth will depend on infrastructure and Erbil,” Birol said, without indicating whether the agency would downgrade its forecasts for Iraqi output in its latest annual medium-term energy report, which will be published on June 17.
In October 2012, the IEA forecast in a special study that Iraqi oil output would more than double over the rest of the current decade, rising to 6.1 million b/d by 2020 and reaching 8.3 million b/d in 2035. But a year later, in November 2013, the agency trimmed these forecasts to 5.8 million b/d in 2020 and 7.3 million b/d in 2030, citing slower than expected progress, persistent security concerns, infrastructure constrains and logistical difficulties.
Oil imports by China and India are expected to reach 19.5 million b/d by 2035 and will account for around 40% of inter-regional oil trade, the International Energy Agency said Tuesday.
In its World Energy Investment Outlook special report, the IEA said the two countries would also import some 270 billion cubic meters/year of gas by 2035. The cumulative upstream investment required to generate these future imports is some $2.35 trillion — $1.57 trillion for Chinese oil and gas imports and $770 billion for India, the IEA said.
“This dependence creates a need, as well as an attractive opportunity, for investment in the resource-rich countries,” it said. Many Chinese and Indian oil companies are already investing heavily outside of their home countries in a bid to secure more upstream resources, though the IEA points out that the resulting production — particularly in oil — is then sold on wholesale markets rather than transported back to the domestic market.
“We estimate that upstream capital expenditure by Chinese NOCs outside China was more than $18 billion in 2013, the largest share of this being spent in North America and the Middle East,” it said. “This is well ahead of the comparable figure for Indian companies, at $1.4 billion,” it said. However, the IEA said, large-scale upstream opportunities are increasingly difficult to secure. “China, in particular, is pursuing other avenues,” it said.
One example is China offering financing, through bank loans and advance payments, to Russia’s Rosneft in return for oil supplies.
By International Business Times | Commodities News | Jun 03, 2014 02:33PM GMT | Add a Comment
By Meagan Clark - Uganda plans to award new oil and gas exploration licenses next year, ending an eight-year halt in licensing, the Petroleum Exploration and Production Department said Tuesday.
Uganda To Award Oil Exploration Licenses in 2015Uganda To Award Oil Exploration Licenses in 2015
The Ugandan government plans to license more than a dozen oil blocks, including at least four big discoveries, in an open bidding process, the Wall Street Journal reported.
Seventy-six of 88 oil exploration and appraisal wells drilled in the country have hit oil, bringing estimated reserves to at least 3.5 billion barrels of crude from 500 million barrels in 2007 and attracting international oil companies to Uganda. The new licensing round planned in the second half of 2015, is expected to attract major international oil companies.
Uganda stopped issuing oil exploration licenses in 2007 in an effort to give the country time to develop regulations to ensure that Ugandans would benefit , according to government officials. Shortly after the licensing ban, oil exploration companies discovered commercial oil reserves.
Less than 40 percent of the country's oil region has been explored, analysts estimate, wih corruption and political interference hampering development. Despite receiving 10 applications in the past two years, Uganda has only issued one oil production license, for $2 billion, to China's state-owned China National Offshore Oil Corp.Uganda's lawmakers have passed two oil bills and are finishing a final bill to regulate their oil industry.
According to a report issued Tuesday by the International Energy Agency (IEA), meeting the world’s growing need for energy will require more than $48 trillion in investment from now through 2035, and this will require countries to maintain credible policy frameworks.
“Policy makers face increasingly complex choices as they try to achieve progress towards energy security, competitiveness and environmental goals,” IEA Chief Economist Fatih Birol said in a statement. “These goals won’t be achieved without mobilizing private investors and capital, but if governments change the rules of the game in unpredictable ways, it becomes very difficult for investors to play.”
Western donors and investors have redirected about $118 million from Uganda since the country's president Yoweri Museveni signed a law in February toughening rules against homosexuality. According to the Ugandan finance minister in May, the country's foreign direct investment in 2012-2013 totaled $1.5 billion, double that of 2008-2009.
Analysts forecast that current discoveries in Uganda can produce a peak of 200,000 barrels-a-day over a 30-year period, roughly the amount of oil stolen daily in Nigeria.
Photographer: Dado Galdieri/Bloomberg
Petrobras is the world’s most indebted crude producer as it spends $220.6 billion over... Read More
Petroleo Brasileiro SA (PETR4) is set to reverse two years of output declines as it starts tapping the biggest group of oil discoveries this century. Halting its five-year share slide probably will take longer.
Petrobras, as Brazil’s crude producer is known, had the worst returns on equity and assets of the 10 largest publicly traded oil companies in the past year, data compiled by Bloomberg show. Delays in developing the giant finds and delivering on output goals have erased more than half the Rio de Janeiro-based company’s market value in the past five years.
Losses of $31 billion in three years at its fuel unit and the cost of drilling some of the world’s deepest wells mean Petrobras probably will continue to be less lucrative than Russian state-run peers OAO Rosneft and OAO Lukoil, Citigroup Inc. said. Petrobras is the world’s most indebted crude producer as it spends $220.6 billion over five years to drill, refine and market oil trapped miles beneath the Atlantic Ocean’s floor.
“The sad thing is these results have not come more quickly, and that’s why investors have lost so much money,” said Russ Dallen, head trader at Miami-based Caracas Capital Markets. “It’s a cheap version of an Exxon Mobil or a ConocoPhillips. Sadly, it will remain a cheaper version.”
Exxon Mobil Corp. and ConocoPhillips have returned 14 percent and 36 percent to investors in the past year, compared with a 16 percent loss from Petrobras, the worst performance of any oil company worth more than than $50 billion, according to data compiled by Bloomberg. Petrobras trades at 8.3 times estimated earnings this year, compared with a ratio of 13 for Exxon and 13 for ConocoPhillips. Petrobras shares are down 2.6 percent so far this year, cutting its value to $93 billion.
Most Volatile
The gradual adjustment of fuel prices will improve Petrobras’s financial results and reduce its leverage, the company said in an e-mailed response to questions. The company also has 267.5 billion reais of assets under construction and the resulting increase in oil and fuel production will improve the company’s return on capital. Fuel imports will decline as it expands the refining network, it said.
President Dilma Rousseff’s office didn’t respond to e-mails requesting comment on the company’s stock performance and fuel price policy. The finance ministry declined to comment in an e-mailed response.
Brazil’s policy to force Petrobras to sell imported fuel for less than it pays to stem inflation puts it at a further disadvantage relative to peers, according to Citigroup.
Petrobras fell the most in five years in December the day after dashing investors’ hopes it would set a market-based fuel pricing methodology, and continued slumping until it hit a nine-year low in March. Since then it has posted the biggest rally among peers in the past three months on speculation Rousseff, who has used Petrobras to subsidize fuel imports since 2011, may be voted out of office.
No Bounce Back
“Petrobras is probably one of the biggest challenges for money managers in the equity space,” said Guilherme Ache, a co-manager at Squadra Investimentos in Rio de Janeiro. In recent years “almost anyone who has tried to bounce back with Petrobras has lost money.”
While Citigroup estimates production gains and fuel prices may add as much as $10 billion a year, the bank says it will still take more than two years for the producer to generate total positive cash flow.
“Potential improvements are not large enough to bear the risk of its debt load and underlying continuous expansion in the medium term,” Citigroup analysts led by Graham Cunningham said in a May 22 research report. “In contrast to Petrobras, Rosneft and the rest of the Russian oil industry do not subsidize the Russian economy with low-priced oil products.”
The Brazilian company, the biggest producer in waters deeper than 1,000 feet, planned to increase output 9.4 percent annually from 2010 through 2014 when it started developing the so-called pre-salt reserves off Rio’s coast.
Instead output has remained flat amid equipment delays and faster-than-expected declines at older fields closer to shore.
Output Gains
Petrobras now expects to boost domestic output 7.5 percent this year and has already anchored two of the five offshore production units it plans to add. It has also dedicated staff and equipment to arrest declines at the Campos Basin where it extracts most of its crude, according to its business plan.
Still, with Brazilian engineering companies busy with unfinished projects related to the soccer World Cup this month and building those for summer Olympic Games in 2016, concerns that Petrobras’ plans will be derailed again loom large. Many of the companies that are building sports venues and urban upgrades are also Petrobras suppliers.
Business also probably will be bogged down in coming months as companies enter wait-and-see mode before the October presidential elections, said Ted Harper, who helps manage more than $10 billion for Frost Investment Advisors LLC in Houston.
More Delays
“With the multitude of things going on in Brazil over the next six to 12 months -- the elections, the World Cup, and eventually the Olympics -- it seems somewhat problematic,” Harper said by phone. It’s unlikely “you’re going to have a smooth-glide path toward continued recovery in production.”
Uncertainty over fuel-import costs and production growth has made Petrobras the most volatile major oil stock in the past year, according to data compiled by Bloomberg.
“It would have a double-digit rise at least if subsidies were eliminated,” Luana Helsinger, an oil and gas analyst at brokerage GBM Brasil, who has the equivalent of a buy rating on the stock and expects output growth of this year of about 6 percent, said by telephone from Rio. “Petrobras’s business plan isn’t viable the way it is, something has to change.”
To contact the reporter on this story: Peter Millard in Rio de Janeiro at pmillard1@bloomberg.net
To contact the editors responsible for this story: James Attwood at jattwood3@bloomberg.net; Jessica Brice at jbrice1@bloomberg.net Carlos Caminada
By Franz Wild Jun 3, 2014 9:30 PM GMT+0700
China’s gung-ho foray into Africa is waning. As trade with the continent surpasses an annual $160 billion, its companies are avoiding risk by taking smaller stakes in projects close to making money.
Cowed by capricious commodity prices, political instability and a string of lost investments, Chinese financiers aren’t as gutsy as when state-owned giants used their heaps of cash to propel the nation’s “Go Out” drive and whip up business abroad 15 years ago.
“There was a lot of enthusiasm and momentum,” said Clement Kwong, whose Beijing-based Long March Capital Ltd. clubbed together with other investors last year to take over a South African gold company. “That momentum is definitely reined in by a new level of risk aversion and caution.”
China surpassed the U.S. as Africa’s largest trading partner in 2009. Trade volumes soared 11-fold in the decade through 2013, according to data from the Geneva-based International Trade Centre. The quest for profit now trumps the wider aim of creating a Chinese footprint abroad.
Smaller private companies are taking the lead from the state-owned giants that prepared the ground. After many African leaders doubled back on the initial fervor for China, the new players are less conspicuous and score quicker returns.
China’s enthusiasm for the mega-deals of the past, such as the landmark $2 billion oil-for-infrastructure accord with Angola in 2004, is tempered by failures.
China’s Missteps
Gabon scrapped China Machinery Engineering Corp.’s $3.5 billion project to develop the Belinga iron-ore deposit in 2012, while a Chinese copper-cobalt mine in Democratic Republic of Congo has been delayed as the companies await legislation guaranteeing tax exemptions.
Jinchuan Group Co. Ltd.’s search for nickel and copper in Tanzania failed in 2011, when the world’s fourth-biggest nickel producer realized it wouldn’t get a license to dig up a nature reserve. Project leader Jianke Gao was sent to build a South African mine as Chief Executive Officer of Wesizwe Platinum Ltd. (WEZ) Jinchuan had bought a 45 percent stake.
“Before coming to buy a project here, Chinese companies will now do more research before making a decision,” Gao said in an interview. “When Chinese investors come to other countries to invest, there are lots of examples of failure.”
Libya gave China its biggest wakeup call, when the 2011 civil war forced Chinese construction companies to abandon billions of dollars worth of equipment and business, and 30,000 Chinese workers were evacuated.
Political Calculations
“We need to price in things like regime change and the cost of operating in a somewhat less than transparent environment,” Kwong, 47, said wearing a checked shirt, blue jeans and white sneakers and sipping iced coffee on the terrace of his Johannesburg hotel. South Africa’s business hub is Kwong’s base from which he looks for other African acquisitions.
Examples of the new pattern abound. China National Offshore Oil Corp. is partnering with Tullow Oil Plc and Total SA to develop Uganda’s oilfields, which they estimate hold 3.5 billion barrels of crude. Beijing Haohua Energy Resource Co. Ltd. last year bought a 24 percent stake in South Africa’s Coal of Africa Ltd. for $100 million.
China National Petroleum Corp. last year bought a fifth of an off-shore Mozambican gas field for $4.2 billion. China Petroleum & Chemical Corp. purchased a 10th of an Angolan oil and gas field for $1.5 billion. In Sierra Leone, China Railway Materials, Shandong Iron and Steel Group and Tianjin Materials and Equipment Corp. between them invested $1.8 billion in London-listed African Minerals Ltd. (AMI)’s Tonkili mine, Africa’s second-largest iron-ore producer, including in rail and port infrastructure.
Africa Appetite
With growth in developed economies sluggish, Chinese appetite for Africa is undiminished.
Chinese Premier Li Keqiang said on a visit to Africa last month that the government will boost its line of credit to African nations by half to $30 billion. He repeated a pledge to almost double capital in the China-Africa Development Fund, which gives financing to Chinese companies for private equity deals including Long March Capital’s, to $5 billion.
Chinese capital growth has been “frighteningly explosive” and has spread to private groups, or “nouveau capital,” which need to invest abroad to make greater returns, according to Kwong.
“The more de-risked a project, the easier it is to get funded today, so something without even a pre-feasibility report is a little difficult to swallow,” Kwong said, before flying to Zimbabwe to look at another possible project. “But if it is near production, but requires a substantial amount of capex to take it into production in order to unlock value, that is probably our favorite type of profile.”
Diversifying Investments
China Investment Corp., the country’s $575 billion sovereign wealth fund, has entered the fray, joining Huawei Technologies Co. (002502) to diversify from oil, minerals and infrastructure to include telecommunications and finance.
“Africa is by far and for sure the single most important and most welcoming destination,” Changhui Zhao, the chief country risk analyst at China Exim Bank, said in an interview from Beijing. “For many outsiders these countries may seem risky, because of the order disturbances, ethnic tensions or even foreign incursions. If you understand the place you are in, then you will see how much premium you will be awarded.”
The bank agreed last month to finance 90 percent of a $3.8 billion railway connecting five East African countries.
Platinum mine chief Gao’s experiences during his four foreign postings tell of the difficulties many Chinese have in bridging the cultural gap with Africans. Speaking through an interpreter, he said he failed to understand the resistance by South African engineers to Chinese technology, which has proven to make the construction of new mine shafts more efficient.
Catholic School
Kwong went to a Catholic high school in Singapore and studied at the University of British Columbia, and is just as fluent in English as in Mandarin and his native Cantonese. He is part of a new generation of Chinese entrepreneurs who’ve overcome some of the cultural differences impeding their African adventure.
“The fact that they have a lot more exposure in Africa now, a lot more experience, a lot more knowledge, they are a lot pickier,” said Standard Chartered Plc Director for Corporate Finance in Africa George Lo, who moved to South Africa at the age of 10 when his father, a property developer, wanted to escape the Hong Kong rat race. “They know where the stuff is. They’re very knowledgeable now.
Lo advised the China Investment Corp. on its first investment in Africa in 2011, when it bought a 16 percent stake in Shanduka Group, the diversified investment group started by South African Deputy President Cyril Ramaphosa.
African Opposition
As well as political risks, Chinese companies know they need to overcome opposition from Africans who sometimes feel they exploit the continent. Zambian workers in 2012 killed the Chinese manager of a coal mine over a wage dispute. Two years earlier, two Chinese managers at the same mine wounded 11 protesting workers when they opened fire on them.
“The Chinese go there with a mentality to conquer,” Elias Masilela, the outgoing chief executive officer of the Public Investment Corp., which manages $153 billion of mainly South African state worker pensions, said in an April interview. Chinese companies demand regulatory breaks because of the amount of investment they bring, he said.
“I cannot blame the Chinese entirely for that,” Masilela said. “I also blame the receiving governments.”
Even though many Chinese companies have the highest operating standards, that attitude is something Kwong says Chinese companies need to address.
“In Africa, many enterprises have learnt lessons along the way,” he said. “We may do things a little differently the next time round.”
To contact the reporter on this story: Franz Wild in Johannesburg at fwild@bloomberg.net
To contact the editors responsible for this story: Antony Sguazzin at asguazzin@bloomberg.net Karl Maier
By Adam Williams Jun 4, 2014 5:24 AM GMT+0700
June 4 (Bloomberg) -- Petroleos Mexicanos is looking to strengthen its balance sheet with the sale of a stake in Repsol SA for about $3 billion as Mexico’s state-owned producer prepares to form partnerships with foreign oil companies.
Pemex, as the Mexico City-based company is known, is selling a 7.9 percent stake in Repsol, according to a Citigroup Inc. filing to the Spanish stock exchange yesterday. Citigroup and Deutsche Bank AG (DBK) are conducting the sale.
The Mexican company is raising cash from the sale as lawmakers prepare regulations to open the oil industry to foreign investment for the first time since 1938. Pemex was “very disappointed” in Repsol’s performance, Chief Executive Officer Emilio Lozoya said in an Oct. 31 interview.
“If Pemex is going to be restructured as a new company, it needs a nest egg of capital in its balance sheet,” George Baker, an energy consultant in Houston, said in a telephone interview. “This money is headed towards Pemex’s balance sheet to give it market credibility.”
The Repsol shares are being offered at 20.1 euros to 20.865 euros each, valuing the stake at about 2.2 billion euros ($3 billion).
Pemex is pledging not to sell more stock for 60 days, according to terms obtained by Bloomberg. The state company owns 9.2 percent of Repsol, according to data compiled by Bloomberg.
Repsol spokesman Kristian Rix in Madrid declined to comment. Pemex’s press office in Mexico City didn’t have an immediate comment on the sale when contacted by Bloomberg.
‘Not Bad Idea’
Reducing the stake would be “not a bad idea,” Mexican Finance Minister Luis Videgaray said May 4 in an interview with Radio Formula. Pemex could “bring that capital and invest it in the opportunities that Pemex is going to have in Mexico,” he said at the time.
An end to Mexico’s state oil monopoly would bring in an additional $20 billion of foreign investment a year, according to Bank of America Corp. Chevron Corp., the third most valuable oil producer, said last month that it has been in talks with Pemex about potential partnerships in onshore, shallow and deep water fields, according to Ali Moshiri, Chevron’s president of Latin America and Africa.
“If Pemex is going to go out and look for a joint venture with Chevron in deep water Gulf of Mexico, they are going to want to know that Pemex has the resources to back up the commitments involved in that type of project,” Baker said.
Shale Interest
Pemex may not have the financial, technical or operational capabilities required to maintain all the fields it wants to keep, Lourdes Melgar, Mexico’s deputy energy minister, said in March. Pemex’s limitations will be considered by the ministry when awarding fields with potentially large amounts of oil reserves, Melgar said. The country’s oil regulator will decide by September which fields Pemex can keep.
Repsol’s growth plans were distracted by its feud with YPF SA after Argentina seized control of YPF from the Madrid-based company in 2012, Pemex’s CEO said in October. The stake “has returned zero” under the current administration, he told a congressional energy committee on Nov. 20.
Pemex, which has expressed interest in working with YPF to develop shale deposits in Argentina, helped broker a preliminary compensation accord between Repsol and YPF that led to a binding deal earlier this year. Repsol received and then sold about $5 billion in bonds from Argentina in May from the compensation.
Repsol’s stock has returned investors 100 percent in dollar terms since CEO Antonio Brufau took the helm in 2004, compared with a 150 percent average gain among peers tracked by Bloomberg in the same span.
The stock is up 14 percent this year.
To contact the reporter on this story: Adam Williams in Mexico City at awilliams111@bloomberg.net
To contact the editors responsible for this story: James Attwood at jattwood3@bloomberg.net Carlos Manuel Rodriguez
By Isis Almeida and Rachel Morison Jun 3, 2014 5:22 PM GMT+0700
Europe is in jeopardy of running short of power because wholesale electricity prices are too low to encourage spending on new thermal plants, according to the International Energy Agency.
The region needs more than $2 trillion in power-industry investment by 2035 and about 100 gigawatts of new thermal capacity in the decade to 2025, the Paris-based IEA said today in its World Energy Investment Outlook. Electricity prices are more than 20 percent below the level necessary to spur investment, according to the adviser to 29 nations. One gigawatt is enough to power about 2 million European homes.
“The investment required to maintain the reliability of Europe’s electricity system is unlikely to materialize with the current design of power markets,” said the IEA. “If this situation persists, the reliability of European electricity supply will be put at risk.”
German power for delivery next year, a European benchmark, rose 0.2 percent to 34.30 euros ($46.67) a megawatt-hour at 12:07 p.m. Berlin time, according to broker data compiled by Bloomberg. The contract dropped 5.8 percent in 2014, heading for a fourth straight annual decline.
Gas Capacity
Natural gas-fired power plants accounting for 14 percent of installed capacity in the European Union were idled, shut or at risk of closing at the end of 2013 as utilities burn coal instead, the International Center for Natural Gas Information, or Cedigaz, said yesterday. Europe is at risk of losing a third of its gas- and coal-fired capacity, the center said.
“Part of the solution involves higher revenues to thermal generators, but this potentially means higher prices to consumers,” the IEA said. That highlights “the difficulties facing European policymakers as they seek to make simultaneous progress toward ensuring energy security, environment sustainability and economic competitiveness.”
Europe must compete in the “near term” with Asian consumers for supplies of liquefied natural gas, according to the IEA. The organization also pointed to the expense of infrastructure for handling the super-chilled fuel.
“The expectation that a surge in new LNG supplies will totally transform gas markets needs to be tempered by recognition of the high capital cost of LNG infrastructure, with transportation typically accounting for at least half of the cost of gas delivered over long distances,” the IEA said.
Investment in LNG will exceed $700 billion over the period to 2035, according to the IEA.
Global energy investment is set to fall short of climate-stabilization goals, with $53 trillion in cumulative investment in energy supply and efficiency required by 2035 “to get the world onto a 2-degrees-Celsius emissions path,” the IEA said, referring to the generally agreed level to avoid irreversible climate change. Current policies and market signals are failing to drive investment in low-carbon sources and energy efficiency at the necessary scale and pace, the report showed.
To contact the reporters on this story: Isis Almeida in London at ialmeida3@bloomberg.net; Rachel Morison in London at rmorison@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net Dan Weeks, Claudia Carpenter
By Nayla Razzouk and Khalid Al-Ansary Jun 3, 2014 7:03 PM GMT+0700
An oil tanker shipping crude from Iraq’s semi-autonomous Kurdish region turned back after getting almost 200 miles across the Atlantic Ocean, amid a challenge over the shipment’s legality.
The United Leadership, able to haul 1 million barrels, signaled that it was about 5 miles off Mohammedia in Morocco at about 6 p.m. local time yesterday, according to information entered by the ship’s crew and captured by Coulsdon, England-based IHS Maritime. It turned back onMay 30 after getting about 190 miles west of Gibraltar, at which point it was sailing to the U.S. Gulf. The shipment is illegal, SOMO, Iraq’s oil marketing company, said yesterday.
The tanker “has arrived at its destination,” Kurdish news website Rudaw reported late yesterday, citing Safeen Dizayee, a spokesman for the Kurdistan Regional Government. The tanker is close to the port of Mohammedia in Morocco, tracking data show. Representatives from the facility are meeting their counterparts at the local refinery, port officer Afifa Loughzail said by phone. At least seven calls to Mohammedia refinery officials weren’t returned.
“There will be a lot of attention focused on where that tanker heads because it is potentially a milestone, the first cargo,” Richard Mallinson, an analyst at Energy Aspects Ltd. in London, said by phone. “That would discourage any potential buyers. It may also limit the Kurds’ options, it may force them to accept discounts on the price that they can sell for.”
Escalating Dispute
Three calls to the Kurdish Regional Government’s natural resources ministry weren’t answered and an e-mail wasn’t returned. United Leadership is owned by Marine Management Services MC, according to a database IHS maintains for the United Nations’ shipping agency. Four calls to the company’s offices in Piraeus, Greece yesterday weren’t returned and the line went dead when Bloomberg News asked for an e-mail address for Marine Management’s directors. A message to the company’s generic e-mail address wasn’t immediately returned.
The KRG estimates its region has about 45 billion barrels of crude reserves. Iraq itself has about 150 billion barrels. A dispute between the two sides escalated last month when the Kurds began pumping oil through their own pipeline to Ceyhan, the Turkish port in the Mediterranean sea from where ship tracking data show United Leadership loaded its cargo.
Arbitration
Iraq said May 23 it sought arbitration over Kurdish oil sales at the International Chamber of Commerce. SOMO said June 1 that buyers should not purchase the cargo. The KRG says it’s abiding by the Iraqi constitution, according to its website. Shipping signals can be wrong because much of the information is entered manually and because not all data are captured.
“Nowadays, due to technology, it has become easy to track any shipped oil and anyone who will deal with this oil may face problems,” Asim Jihad, a spokesman for Iraq’s oil ministry, said by phone yesterday.
Disputes about cargoes sometimes delay merchant ships. A tanker called the ETC Isis spent months marooned off Singapore in 2012 as part of a dispute between northern and southern Sudan. Earlier this year, U.S. special forces boarded a tanker shipping crude from eastern Libya that the nation’s government said was illegally shipped.
To contact the reporters on this story: Nayla Razzouk in Dubai at nrazzouk2@bloomberg.net; Khalid Al-Ansary in Baghdad at kalansary@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net Rachel Graham
By Natasha Doff Jun 3, 2014 10:08 AM GMT+0700
Russian energy stocks rallied in U.S. trading amid speculation that OAO Gazprom’s deadline extension for natural-gas payments from Ukraine is a signal that tension is easing between the two countries.
The Bloomberg Russia-US Equity Index of the most-traded Russian companies in the U.S. rose 1 percent to 88.55 from a one-week low. OAO Surgutneftegas, the oil producer known as Surgut, was the best performer on the gauge. OAO Lukoil rallied the most in three weeks. Gazprom added 0.9 percent following a 1.7 percent rise in Moscow.
Energy stocks gained as state-controlled Gazprom extended the deadline for Ukraine to pay an estimated $1.7 billion bill after the country made its first gas payment in months. The company had demanded that the former Soviet republic pay bills up front or risk being cut off from supplies. Russia and the European Union resumed talks with Ukraine to resolve a dispute over prices.
The Russian government “seemed to be willing before to sacrifice the economy for geopolitical positioning,” Gary Greenberg, an emerging-markets money manager at London-based Hermes Fund Managers, which oversees 26 billion pounds ($43.5 billion), said by phone yesterday. “Now the past few weeks of news flow seems to be indicating that the economy does matter.”
Russia’s dollar-denominated RTS Index has dropped 8.3 percent this year, the fourth-worst performance among 93 equity gauges tracked by Bloomberg. Stocks tumbled to a four-year low in March after President Vladimir Putin annexed Ukraine’s southern Crimea region, prompting sanctions from the U.S. and European Union.
Gas Debt
Ukraine gets about half its gas from Gazprom, and about 15 percent of Europe’s annual demand passes through its pipelines. Putin had threatened to cut the country off over unpaid debt. The state-controlled gas producer’s Chief Executive Officer Alexey Miller said in e-mailed statements that Ukraine may avoid a move to advance payments and get a lower price by settling its gas debt by June 9. The company said it received $786 million for February and March and is still owed $1.45 billion for the last two months of 2013.
While the dispute on price will continue, yesterday’s agreement sparked a “relief rally” as it signaled that the Ukraine crisis is easing, Slava Smolyaninov, the chief strategist at UralSib Financial in Moscow, said by e-mail.
“Not many people expected the beginning of the summer in Moscow to result in such a powerful move higher” in Russian stocks, Smolyaninov said.
Micex Rally
The Micex Index (INDEXCF) added 2.3 percent in Moscow yesterday, continuing a rebound to levels seen before Russia’s incursion into Crimea. RTS stock-index futures expiring this month slid 1.1 percent in U.S. hours.
The gain in the Micex pushed its relative strength index to 66.3, data compiled by Bloomberg show, approaching the level of 70 that some technical analysts see as an indication that a security is poised to fall. The Bloomberg Russia-US Equity Index’s RSI is 64.
Gazprom rose to $8.24 in New York. Surgut advanced 4.7 percent to $7.50, the most in two weeks. Lukoil jumped 2.3 percent to $57.85.
Yandex NV, Russia’s largest search-engine operator, added 1.7 percent to $31.67. The company’s stock is set to start trading in Moscow today, according to two people with knowledge of the matter who asked not to be identified before the announcement. The move coincides with the government urging companies to cut dependence on foreign exchanges.
The Market Vectors Russia ETF (RSX), the biggest U.S. exchange-traded fund that holds Russian shares, gained 0.9 percent to $25.32. The RTS Volatility Index, which measures expected swings in futures, increased 3.5 percent to 26.89.
Moscow-based United Co. Rusal, the world’s biggest aluminum producer, advanced 3 percent to HK$3.40 at 11:06 a.m. in Hong Kong trading, heading for the biggest gain in a month.
To contact the reporter on this story: Natasha Doff in London at ndoff@bloomberg.net
To contact the editors responsible for this story: Nikolaj Gammeltoft at ngammeltoft@bloomberg.net Richard Richtmyer, Matthew Oakley
By Grant Smith Jun 3, 2014 7:00 AM GMT+0700
Meeting the world’s energy supply needs by 2035 will require $40 trillion of investment, as demand grows and production and processing facilities have to be replaced, the International Energy Agency said.
More than half of that amount will be needed to compensate for declining output at mature oil and gas fields, and the remainder on finding new supplies to meet rising demand, the Paris-based agency said in a report today. The world will increasingly rely on countries that restrict foreign companies’ access to their oil reserves, as North American shale output tails off from the middle of next decade, it predicted.
“Declines and retirements set a major reinvestment challenge for policy makers and the industry,” said the IEA, which advises 29 of the most industrialized nations on energy policy. “In the case of oil, the focus for meeting incremental demand shifts towards the main conventional resource-holders in the Middle East as the rise in non-OPEC supply starts to run out of steam in the 2020s.”
While a boom in shale oil is pushing U.S. production to its highest level in almost 30 years, diminishing the biggest crude consumer’s reliance on imports, this output surge is forecast to fade, restoring the importance of supplies from the Middle East and the Organization of Petroleum Exporting Countries.
Upstream Spending
Spending on extracting oil and gas worldwide will climb by 25 percent to $850 billion a year by 2035, with most of this concentrated in natural gas, according to the report. Global markets will tighten if investments in the resource-rich Middle East are too slow, pushing oil prices $15 a barrel higher on average in 2025, it warned. Brent futures averaged $108.70 a barrel last year.
“The prospects for a timely increase in oil investment in the Middle East are uncertain,” according to the agency, which estimates that more than 70 percent of global oil and gas reserves are under the ownership of state-controlled entities. OPEC, whose largest producer is Saudi Arabia, currently accounts for 40 percent of global oil supplies.
“Decisions to commit capital to the energy sector are increasingly shaped by government policy measures and incentives, rather than by signals coming from competitive markets,” according to the IEA.
About half of the $40 trillion spent on energy through to 2035 will be on extraction, refining and transporting fossil fuels, the report indicated. Two-thirds of the total will be spent in emerging economies, according to the agency. Investment needed in renewable energy will total $6 trillion, with another $1 trillion in nuclear power.
Annual spending on satisfying global energy requirements will increase to $2 trillion by 2035, up from $1.6 trillion last year, the agency projected.
Spending on energy efficiency through 2035 pushes the total required investment to $48 trillion, according to the IEA.
To contact the reporter on this story: Grant Smith in London at gsmith52@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net Rachel Graham, Sharon Lindores
By Tsuyoshi Inajima, Chou Hui Hong and Emi Urabe Jun 3, 2014 3:35 PM GMT+0700
Tokyo Electric Power Co. (9501), Japan’s biggest buyer of LNG, is considering purchases of the fuel from natural gas export projects being developed on the West Coast of North America, said three people with knowledge of the matter.
The utility, known as Tepco, is looking at West Coast projects because liquefied natural gas supplies wouldn’t need to pass through the Panama Canal en route to Asia, two of the people said. That would reduce toll fees and shipping times, according to the people, who asked not to be identified because they aren’t authorized to speak to the media.
Hiroshi Itagaki, a Tokyo-based spokesman for Tepco, declined to comment on the company’s potential LNG purchases.
“There is no doubt LNG from West Coast projects would be highly competitive,” Junzo Tamamizu, the managing partner of Clavis Energy Partners LLC, a Tokyo-based consulting and advisory firm, said in a phone interview today. “That’s why Asian players would be naturally interested in the projects.”
Oregon LNG estimates shipments from its facility to Tokyo will be $2 per million British thermal unit cheaper than cargoes from the U.S. Gulf Coast, CEO Peter Hansen said in October. Spot cargoes sold into Northeast Asia last week were priced about $13.30 per million Btu, according to data published by Energy Intelligence Group.
Lean LNG
Japan imported a record 87.49 million metric tons of liquefied natural gas last year to supply the world’s third-biggest economy after the Fukushima disaster in 2011 prompted the shutdown of all the nation’s nuclear plants. Tepco intends to buy as much as 10 million tons a year of lean, or low-energy LNG from projects such as those fed by North American shale gas.
The utility agreed to buy a total of 1.2 million tons a year from Sempra Energy’s Cameron LNG facility in Louisiana on the U.S. Gulf Coast through Mitsubishi Corp. and Mitsui & Co., Itagaki said. Tepco is in talks with Mitsui to buy more gas from the project, he said.
Cameron LNG is scheduled to begin liquefying gas in late 2017 and will be fully operational by 2018, according to San Diego-based Sempra, which owns 50.2 percent of the facility
To contact the reporters on this story: Tsuyoshi Inajima in Tokyo at tinajima@bloomberg.net; Chou Hui Hong in Singapore at chong43@bloomberg.net; Emi Urabe in Tokyo at eurabe@bloomberg.net
To contact the editors responsible for this story: Pratish Narayanan at pnarayanan9@bloomberg.net Ramsey Al-Rikabi, Mike Anderson
By ER/Associated Press
The European Union is telling Bulgaria to suspend preparatory work on Russian energy company Gazprom's South Stream gas pipeline, which will bypass Ukraine to bring supplies into the heart of Europe.
EU Commission spokeswoman Sabine Berger said Tuesday that work on the line should not proceed until the Bulgarian government gives clear answers on antitrust concerns over ownership. She added that "the project should be reevaluated in the light of the EU's energy security priorities."
The standoff over Ukraine has forced the 28-nation EU into a sudden rethink of its energy policies to make it less reliant on Russia and state-owned Gazprom.
The start of the construction works in Bulgaria was initially scheduled for June, but now is likely to be delayed.
CNBC.com
Iranian oil exports are on course to run well above the levels the Obama administration said they would when the U.S. agreed to allow some crude shipments in exchange for limits on Iran's domestic nuclear program.
Iran's exports are running at an average of 1.3 million barrels per day since December, about the time sanctions were eased. In comparison, its exports averaged only 1 million barrels a day in 2013 overall, with some months averaging as low as 850,000 barrels daily last year.
In November, the U.S. and five other countries agreed to a "Joint Plan of Action" for Tehran, and the administration has said repeatedly that Iran's oil exports would average only 1 million barrels per day for the first six months of that agreement.
For its part, the U.S. Treasury Department, which enforces sanctions against Iran, points out that those six months aren't yet over, and suggests that the averages will come down.
"I think it's important not to look at month-to-month fluctuations," said David Cohen, the Treasury's undersecretary for terrorism and financial intelligence. "Obviously we have figures that we're looking at very carefully as well. But the term under the Joint Plan of Action looks at oil sales over the course of the six months ... and calls upon Iran not to export over the course of six months more oil than they were exporting essentially last November."
But so far, at least, Iran appears to be doing just that. According to Nat Kern, analyst with Washington-based consulting firm Foreign Reports, Iranian exports to countries given purchase waivers by the U.S. government averaged 1.3 million barrels per day from December to April.
The Joint Plan of Action, announced in November, was signed Jan. 20, meaning that starting from that date, the U.S. officially began to monitor Iranian exports. Monitoring will continue through July. Given the exports from the first three months of the period, that means that May, June and July will have to show a sharp drop in oil exports in order for the total for the period to average out to the 1-million-barrel level.
Rob Wile
Jun. 3, 2014, 2:10 PM
Bahraini Foreign Minister Sheikh Khaled bin Ahmed al-Khalifa (C) arrives to attend the Gulf Cooperation Council (GCC) meeting in Riyadh June 2, 2014.
The American shale boom will begin to taper sometime in the mid-2020s, after which point the world will fall back to depending on the Middle East more than ever to meet energy needs, according to the International Energy Agency.
But this time, the traditional Gulf players may not be ready to shoulder the burden.
In its latest outlook, the IEA projects that while total spending on oil drilling will remain fairly constant (at $500 billion a year) through 2035, "there will be a noticeable shift in the location of this investment over the coming decades."
That shift will be away from North America — where the most accessible plays will dry up and the expense required to extract unconventional oil will rise — and back toward traditional petro states, where the cost of extraction will remain relatively cheaper and the resource base more extensive.
"Gradual depletion of the most accessible reserves forces companies to move to develop more challenging fields," the agency says. "...Although offset in part by technology learning, this puts pressure on upstream costs and underpins an oil price that rises to reach $128/barrel in real terms by 2035."
Here's the chart, showing 13% of the total upstream oil investment in OPEC countries of the Middle East accounts for a third of the new resources developed to 2035, whereas tight oil in North America accounts for 13% of investment but for just 6% of new resources.
"Meeting long-term oil demand growth depends increasingly on the Middle East, once the current rise in non-OPEC supply starts to run out of steam in the 2020s," the agency says.
But the Middle East, in the form of OPEC, may miss its cue to jump in to the breach, the agency says, because the American boom has slowed oil price growth and diverted OPEC resources to non-traditional projects. As a result, spending on oil development among OPEC players will be constrained.
"The result would be tighter and more volatile oil markets, with an average price $15/barrel higher in 2025," the agency says.
This outcome is not a total certainty. The IEA notes that the "learning" effect in North American drilling — whereby the longer a play is developed, the more efficient drilling in that play becomes — could extend beyond their original taper date.
And the fact that the price of oil will increase, on average, less than 1% a year to 2035 further shows the shale boom has created a huge cushion for the rest of the world.
But it looks like, one way or another, we'll be returning to the way things once were.
Baku. Anakhanum Hidayatova - APA. "Azerbaijan's role as an energy producer has changed markedly. With the construction of Baku Tbilisi Ceyhan pipeline Azerbaijan became major supplier of oil to world markets".
US Ambassador to Azerbaijan Richard Morningstar said while speaking at the reception on the occasion of Caspian Oil & Gas Exhebition 2014 opened in Baku this morning, APA reports.
"The construction began for the Southern Gas Corridor which will make Azerbaijan a major suppplier of gas to Europe. Objectives of the US energy policy in the region have remained consistent over the last twenty years. First we want to help Azerbaijan to develop its energy resources to help it become a strong and independent nation. Strong and stable Azerbaijan contributes to regional stability and benefits the region, as well as Europe and whole world with respect to the global energy markets. Second we value is Azerbaijan energy resources to contribute to European and world energy supplies. Diversifying global energy supply benefits everyone" - Ambassador said
Mexico's state-owned oil giant Pemex has sold the majority of its stake in Spanish energy firm Repsol for approximately 2.2bn euros ($3bn; £1.8bn).
Pemex has been a shareholder in Repsol for more than 25 years.
But the relationship has been under pressure since 2011 when Pemex backed a failed bid by Spanish construction group Sacyr to take control of Repsol.
And recently Repsol appointed a chief executive not supported by Pemex.
Pemex, which is Repsol's third-biggest shareholder, sold 104 million shares, or 7.9% of Repsol's total market share.
The sale was revealed in a regulatory filing by Repsol.
Mexican President Enrique Pena Nieto is due to make his first official visit to Spain next week.
Producers Stepped Up Production, Pushing it to a New Record
DENVER, June 3, 2014 /PRNewswire/ -- U.S. exploration and production companies were at full throttle in May, producing 67.7 billion cubic feet per day (Bcf/d) of natural gas in the lower 48 States, according to the latest estimates from Bentek Energy, an oil and natural gas analytics and forecasting unit of Platts. This was up 0.6% from the previous monthly high set in April.
May 2014 saw nine days of production in excess of 68.0 Bcf/d and ten days of the highest production levels in the history of U.S. gas production, the Bentek analysis showed. Production peaked on May 26 at 68.2 Bcf/d. Average May 2014 gas production was up 3.0 Bcf/d or 4.6% from May 2013 levels.
The U.S. Energy Information Administration (EIA) will publish its domestic production estimates for May on or around July 31.
"With summer heat and air-conditioning season upon us and elevated natural gas demand from the power generation sector, despite higher prices, this record production is a shot in the arm for what is turning into a more and more robust market," said Jack Weixel, Bentek Energy director of energy analysis. "With power utilities clearly anxious about relying on coal as a fuel source now that the Environmental Protection Agency has released its latest carbon emissions reduction program, natural gas producers have stepped up and see a clear signal to deliver as much as the market can bear."
Bentek data analysis suggests 2014 production will average approximately 67.5 Bcf/d due to a higher price environment for producers and continued production growth from liquids-rich shale basins such as the Eagle Ford, Bakken, Permian and Greater Anadarko, in addition to continued increases in dry production in the Marcellus.
The Bentek data analysis is based on an extensive sample of near real-time production receipt data from the U.S. lower 48 interstate pipeline system. Platts' Bentek production models are highly correlated with and provide an advance glimpse of federal government statistics from the U.S. EIA.
This Bentek Energy U.S. natural gas production data estimate will be published on the first Tuesday of every month, covering the previous month's output activity. Bentek's dry gas production estimates are not observed data and are based on pipeline receipt nominations and certain state production data.
Bentek Energy, which specializes in energy market analytics and is recognized as an industry leader in natural gas market fundamental analysis, was acquired by Platts in 2011. For more information about natural gas supply and demand fundamentals and Bentek Energy, visit www.bentekenergy.com.
For more information about natural gas spot price trends and Platts, a leading global energy, petrochemical and metals information provider, visit the website at www.platts.com.
Note: As with any modeled number, Bentek makes no warranty, express or implied, regarding the use of any information in connection with trading of commodities, equities, futures, options or any other use.
About Platts: Founded in 1909, Platts is a leading global provider of energy, petrochemicals, metals and agriculture information and a premier source of benchmark prices for the physical and futures markets. Platts' news, pricing, analytics, commentary and conferences help customers make better-informed trading and business decisions and help the markets operate with greater transparency and efficiency. Customers in more than 150 countries benefit from Platts' coverage of the biofuels, carbon emissions, coal, electricity, oil, natural gas, metals, nuclear power, petrochemical, shipping and sugar markets. A division of McGraw Hill Financial (NYSE: MHFI), Platts is based in London with approximately 900 employees in more than 15 offices worldwide. Additional information is available at http://www.platts.com.
About McGraw Hill Financial: McGraw Hill Financial (NYSE: MHFI), a financial intelligence company, is a leader in credit ratings, benchmarks and analytics for the global capital and commodity markets. Iconic brands include: Standard & Poor's Ratings Services, S&P Capital IQ, S&P Dow Jones Indices, Platts, CRISIL, J.D. Power and McGraw Hill Construction. The Company has approximately 17,000 employees in 29 countries. Additional information is available at www.mhfi.com.
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SOURCE Platts
Global Security Newswire
By Diane Barnes
A senior U.S. lawmaker wants the Obama administration to explain how it would respond if Iran and Russia finalize a "sanctions-busting" oil deal.
U.S. House Foreign Affairs Committee Chairman Ed Royce (R-Calif.) said the potential "oil-for-goods" plan would circumvent international efforts to squeeze concessions from Iran on its bomb-usable nuclear activities. In a Monday letter, he asked Secretary of State John Kerry to identify what "designation and enforcement steps" the administration would pursue if the potential $20 billion arrangement takes effect.
Negotiators for Russia, the United States and four other countries are offering Iran relief from economic pressure if the Middle Eastern nation significantly dials back its contested atomic efforts. Tehran denies it is seeking a nuclear-bomb capacity, and so far has not offered curbs sufficient to satisfy Washington and its allies.
A senior U.S. lawmaker wants the Obama administration to explain how it would respond if Iran and Russia finalize a "sanctions-busting" oil deal.
U.S. House Foreign Affairs Committee Chairman Ed Royce (R-Calif.) said the potential "oil-for-goods" plan would circumvent international efforts to squeeze concessions from Iran on its bomb-usable nuclear activities. In a Monday letter, he asked Secretary of State John Kerry to identify what "designation and enforcement steps" the administration would pursue if the potential $20 billion arrangement takes effect.
Negotiators for Russia, the United States and four other countries are offering Iran relief from economic pressure if the Middle Eastern nation significantly dials back its contested atomic efforts. Tehran denies it is seeking a nuclear-bomb capacity, and so far has not offered curbs sufficient to satisfy Washington and its allies.
Royce said the proposal for Iran to trade oil for nonmonetary goods from Russia "would present a clear violation of Iran's obligations and would undermine the rationale behind the current negotiations." Treasury Secretary Jack Lew in April said Washington could penalize groups or individuals that engage in trade under the possible pact, but he did not specify what legal authorities would permit such action.
The lawmaker also asked for a rundown of steps by Washington or its partners "to deter a potential deal."
The United States contends that a six-month interim accord obligates Iran to cap its average daily oil exports to six key oil-importing nations at about a million barrels. Royce said the list does not include Russia, potentially enabling a barter deal to boost Tehran's daily oil sales by up to half a million additional barrels.
Royce also aired concern over indications that Moscow may supply Iran with arms or nuclear systems under the proposed arrangement.
This article was published in Global Security Newswire, which is produced independently by National Journal Group under contract with the Nuclear Threat Initiative. NTI is a nonprofit, nonpartisan group working to reduce global threats from nuclear, biological, and chemical weapons.
* Bulgaria has a month to reply to formal notice from EU
* EU heads of government to debate energy security this month
* Sofia says South Stream must not be held hostage to Russia-Ukraine row
* Ukraine urges EU to block South Stream (Adds Bulgarian reaction, Ukraine comment)
By Barbara Lewis and Tsvetelia Tsolova
BRUSSELS/SOFIA, June 3 (Reuters) - European Union authorities have asked Bulgaria to suspend work on Gazprom's South Stream gas pipeline on the grounds that the project breaks EU law, a step that threatens to inflame tensions between Russia and the 28-country bloc.
The latest move against Moscow, announced by the European Commission on Tuesday, follows progress late on Monday towards resolving a pricing row that has threatened to disrupt Russian gas shipments via Ukraine.
As conflict rages following Russia's annexation of Ukraine's Crimea region in March, Russia has forged ahead with its giant South Stream conduit that would pump gas to the EU, bypassing Ukraine.
But the European Commission, the EU's executive arm, says South Stream breaks EU rules that prohibit gas suppliers from also controlling pipeline access and it has put on hold the approval process for the project.
Bulgaria, historically close to Russia and heavily dependent on its gas, has decided to start construction as a national priority.
"Whilst discussions with the Bulgarian authorities are taking place and until there is full compliance with EU law, we have asked the Bulgarian authorities to suspend the project," Commission spokeswoman Chantal Hughes told Reuters.
She also said the Commission had sent the Bulgarian authorities a letter of formal notice asking for information, a preliminary measure that could eventually lead to full infringement proceedings and possible fines.
Bulgaria's energy minister, a staunch supporter of the project as a means of bolstering energy security and creating jobs, said he did not believe Bulgaria would be sanctioned and called for dialogue to continue with Brussels.
"I do not see grounds for drama ... it is just a matter of time and a dialogue with the European Commission to find the best solution," Dragomir Stoynev told reporters.
Stoynev said the project, aimed at transporting 63 billion cubic metres of gas per year under the Black Sea through Bulgaria to central and southern Europe by 2018, should not be held hostage to the standoff between Russia and Ukraine.
"I appeal for solidarity from the European Commission. Bulgaria, and other member states through which South Stream passes, they cannot be hostages of this conflict between Russia and Ukraine," he said.
Commission spokesman Antoine Colombani described the matter as urgent and said the EU executive would also act against any other member states that work with Russia on South Stream if they break EU law.
The Commission was also concerned that downstream contracts between South Stream Bulgaria and subcontractors were allowing preferential treatment for Bulgarian and Russian bidders, Colombani said.
Last month, Sofia picked a consortium led by Russia's Stroitransgaz, owned by sanctions-hit businessman Gennady Timchenko, to build the Bulgarian section.
While Russia seeks alternative routes for its gas exports, which provide roughly one third of EU gas needs, the European Union is looking for other ways to improve its security of supply.
In Kiev, Ukrainian Prime Minister Arseny Yatseniuk called on the EU to block South Stream.
"We consider the South Stream project as one that aims to increase Europe's dependence on energy (from Russia), remove Ukraine as a transit country and increase Gazprom's influence in Europe. So we call on the EU to block South Stream," he said.
The Commission published a strategy paper last week that member states will debate later this month.
The paper underlined that any new infrastructure must comply with EU rules on a single energy market, including the so-called Third Energy Package, which prevents companies that supply gas from owning the infrastructure through which it is distributed. (Additional reporting by Pavel Polityuk in Kiev; Editing by Dale Hudson, Jane Baird and Matthias Williams)
* TAP plans to bring Azeri Shah Deniz II gas to Italy and Turkey
* Italian gas demand has fallen 15 pct since 2005
* Total has already withdrawn from Shah Deniz II project
* Gazprom ditched Italy as destination for its South Stream pipeline (Adds detail throughout)
By Nailia Bagirova and Margarita Antidze
BAKU, June 3 (Reuters) - France's Total and Germany's E.ON plan to withdraw from a pipeline scheme to bring Azerbaijan's gas to Italy, an Azeri official said, as falling Italian demand puts energy projects there into doubt.
The move comes less than a month after Russia's Gazprom said that it would re-route its massive South Stream pipeline, which plans to bring Russian gas to Europe later this decade, to Austria instead of Italy.
Total and E.ON plan to to withdraw from the Trans Adriatic Gas Pipeline (TAP), Vagif Aliyev, SOCAR's investment department head at Azeri SOCAR told reporters at an industry conference.
Total is already selling its stake in Azerbaijan's major gas field, while sources say E.ON is pulling out of the ailing Italian market.
Both are lesser partners in TAP, in which BP, SOCAR and Norwegian Statoil all hold 20 percent stakes.
Europe sees Azeri gas as an alternative to its reliance on Russia, but analysts say commercial issues cloud the picture.
"At the end of the day its all about the commercial viability," said Peter Kiernan, lead energy analyst at the Economist Intelligence Unit (EIU). "Gas in Europe seems pretty sluggish at the moment in terms of demand, so these factors combined would have an impact on the economics of it."
Azerbaijan aims to transport 16 billion cubic metres (bcm) of gas a year from its Shah Deniz II field in the Caspian Sea by the end of the decade to Turkey and on to Italy.
While Turkey is keen to find new supplies after its gas demand doubled in the last decade, Italian use of the fuel has dropped by over 15 percent since peaking around 80 bcm in 2005, casting into doubt projects that aim to bring more gas to an oversupplied market.
"We continuously review the strategic options with regards to our portfolio, including our pipeline business. Such review may or may not result in us deciding from time to time to evaluate a disposal of certain assets in the portfolio," E.ON spokesman Adrian Schaffranietz said.
"E.ON was expected as it is pulling out of Italy in general," a source with knowledge of the matter said.
TAP and Total said they would not comment on the matter, but Total said less than a week ago that it would sell its stake in the Azeri Shah Deniz II gas project to Turkey's state oil company TPAO.
"It would not be logical if Total stayed in TAP after selling its stake in Shah Deniz II project," said a senior official at SOCAR who did not want to be named.
Of its supplies, 10 bcm of Shah Deniz II's gas has been committed to come to the EU while 6 bcm a year have been earmarked for Turkey.
"Shah Deniz II has signed buyer commitments which were announced last year, and the changes in TAP won't change those commitments," said Toby Odone, spokesman at BP, which leads Shah Deniz II's development.
"There are still a host of companies in partnership for TAP (Socar/Statoil/BP/Fluxys/Axpo), but it would be interesting if the 6 bcm for Turkey, 10 bcm for Italy/Europe break down changes," the EIU's Kiernan said.
TAP's other shareholders are currently Fluxys (16 percent), Total (10 percent), E.ON (9 percent) and Axpo (5 percent).
CHEAPER GAS
Total's pullout from Shah Deniz II and its retreat from TAP together with E.ON comes a month after Statoil said it had sold a 10 percent stake in Shah Deniz II to the project's other main partners BP and SOCAR.
"This makes sense given the lower margins in this project compared to others because of the low gas prices in Europe," said Trond Omdal, analyst at Arctic Securities about Statoil's move.
European forward gas prices, which are used to make investment decisions for big pipeline and gas field projects, have dropped over 15 percent since the beginning of the year.
They are now close to 3-year lows, and most analysts say they will drop further as new producers flood markets with gas.
Analysts have said that many new gas projects will struggle to make a return on investment necessary to receive the required financing.
The pullout of two TAP partners could also be a blow for Italy's aim of finding new gas over fears that instability in North Africa could disrupt imports and after Gazprom's South Stream project was re-routed to end in Austria instead of Italy.
Italy's role as the destination for TAP has run into local protests against the pipeline and sources said Croatia had been applying pressure to redirect the project there. (Writing by Henning Gloystein, additional reporting by Stephen Jewkes in Milan, Barbara Lewis in Brussels and Matthias Inverardi in Frankfurt, editing by William Hardy.)
Tue Jun 3, 2014 11:19am EDT
* European refineries to cut runs by nearly 25 pct in summer
* Refiners seek alternative sources of crude to help profits
* More Latin American crude moves to Europe
By Ron Bousso
LONDON, June 3 (Reuters) - Caught between soaring crude prices and collapsing diesel profits, European oil refiners are slashing operating rates by nearly one quarter ahead of the peak summer period.
Europe's refining sector has battled for years with weakening demand and over-capacity which forced a string of plant shutdowns. Further closures may be looming.
This year alone, Hungary's MOL Group shut down its Mantua refinery in northern Italy and the Milford Haven refinery in Wales stopped processing crude as its owner Murphy Oil seeks buyers for its British assets.
A convergence of rising crude oil prices to around $110 a barrel with extremely low diesel refining margins, usually the bulwark of profits, are wreaking fresh havoc.
"We have had weak refining margin environment particularly in the last couple of months and it is driven by weak diesel in particular," Matti Lehmus, executive vice president for oil products at Finnish refiner Neste Oil, told Reuters.
Refining capacity in the Mediterranean region is set to drop by up to 25 percent this summer, whether by lowering operating rates or extending maintenance at plants, according to refiners and analysts. In coastal areas in northwest Europe, refineries are set to cut runs by around 15 percent.
European refining crude processing rates in June are set to reach 10.76 million barrels-per-day (bpd) or 76.3 percent of capacity, little unchanged from the peak maintenance months of March-May, according to data from Wood Mackenzie consultancy.
By comparison, operating rates in June 2013 reached 11.99 million bpd.
Runs are expected to rise to 11.12 million bpd or 78.8 percent of capacity in July but remain significantly lower than the previous year's 12.14 million bpd or 85.7 percent of capacity. Similarly, runs in August will rise to 11.35 million bpd or 80.4 percent of capacity compared with 11.83 million bpd in August 2013, according to the data.
"When margins are like this you try to do as much of your shutdowns and turnarounds in a time like this," said Marcel Van Poecke, managing director at Carlyle International Energy Partners, which specialises on European downstream investments.
"How long can you keep doing this? At a certain moment you've done all the maintenance you could do ... the only thing left to do are run cuts."
ALTERNATIVE CRUDE
Persistently high crude prices in the region have weighed heavily on refining margins.
Refineries in northwest Europe made $2 in profit for each barrel of Brent crude processed in May. In the Mediterranean, refineries processing Russian Urals made 12 cents a barrel on average in May, according to Reuters data,
That has led several refiners to seek alternative, cheaper crude sources.
Cargoes of Vasconia crude from Columbia, Maya from Mexico and Oriente from Ecuador have sailed in recent weeks to Europe, mostly to the Mediterranean, according to traders.
The flow of Latin American crude to Europe has steadily risen over the last year as booming domestic output has cut demand for imports in the United States.
Repsol will this month test the first batches of Western Canada Select (WCS) heavy blend at its Spanish refineries as it takes advantage of a provision that allows Canadian crude to be re-exported through U.S. ports.
"European refiners have to look to alternatives. Canadian supplies are slowly becoming more available to the market and the Latin American players have to reroute some of their exports away from the U.S.," said David Wech, managing director at Vienna-based consultancy JBC Energy.
"Perhaps you can make a cheap buy at the beginning of such an inflow but in a few months the costs would increase," he said.
THINGS CAN GET WORSE
In Europe diesel refining margins have hovered near a two-year low at around $10 a barrel in recent weeks.
Huge flows of diesel from highly competitive refineries in the U.S. Gulf Coast, Russia and Asia, that benefit from cheap crude feedstock, have kept supplies in Europe up and pushed prices down.
Imports from the U.S. are expected to reach above 2 million tonnes in May for the first time this year, according to shipping data and traders.
The flow is set to increase this summer as U.S. Gulf Coast refineries ramp up runs following the maintenance period.
"Diesel looks long and the situation will probably get worse before it gets better... I would anticipate U.S. arbitrage supplies to remain high until autumn maintenance," said Robert Campbell, analyst at London-based Energy Aspects consultancy.
And with more refining capacity coming on line in Asia and the Middle East over the next year, diesel margins are set to remain under pressure.
Around 2 million bpd of additional refining capacity, the equivalent of 10 medium-sized plants or nearly 15 percent of Europe's current capacity, will need to shut in the next four years to balance the market, analysts say. (Additional reporing by Claire Milhench and Lin Noueihed, editing by William Hardy)
* Ukraine has started to pay off gas debts
* Gazprom delayed switching Kiev to prepayment
* Tension eases after talks, more planned (Adds talks continued on Tuesday, Gazprom says exports to Europe up)
By Vladimir Soldatkin and Denis Pinchuk
MOSCOW, June 3 (Reuters) - Russian and Ukrainian energy companies tried again on Tuesday to settle a dispute over unpaid gas bills that is threatening supplies to Europe and stoking a political conflict setting Moscow against Kiev and the West.
Russian state-owned exporter Gazprom gave Kiev some respite on Monday by allowing it six more days to pay its debts, averting the risk of an immediate cut in supplies under an advance payment system that had been due to come into force.
Although the two sides disagree over the price Ukraine should pay, signs of compromise are growing after the latest talks brokered by the European Union in Brussels on Monday.
"Talks went for a long time yesterday ... There is an understanding on how to move forward - this is very important," Gazprom spokesman Sergei Kupriyanov told reporters in Moscow.
Talks between Gazprom and Ukrainian energy company Naftogaz continued on Tuesday in Berlin, a source at Gazprom said.
Ukraine owes billions of dollars and Prime Minister Arseny Yatseniuk hinted that his cash-strapped country would be now be more flexible over its price demands, although he made clear the price sought by Russia remained far too high.
"We look forward to the completion of negotiations with Russia's Gazprom this week," Yatseniuk told parliament in Kiev. "We understand it will be hard to reach $268 but we will never accept $500."
Ukraine wants to return to a discounted gas price of $268.5 per 1,000 cubic metres, granted by Moscow as a concession after Ukraine's then president Viktor Yanukovich dropped plans to sign agreements on closer political and trade ties with the EU.
After Yanukovich was ousted in February following months of protests provoked by his policy U-turn, Russia reinstated the earlier price of $485 - the highest in Europe.
Russian President Vladimir Putin does not want tensions over the gas dispute to overshadow a visit to France this week where he is likely to come face to face with U.S. President Barack Obama and is planning to meet European leaders who have imposed sanctions on Russia over its annexation of Crimea from Ukraine.
Ukraine's newly elected president, Petro Poroshenko, is attending the same event marking the 70th anniversary of the D-Day landings that opened the Western front against Nazi Germany in World War Two. His inauguration is set for Saturday.
SIGNS OF COMPROMISE
Despite the signs of compromise, Yatseniuk reiterated the threat of a legal challenge in the Stockholm arbitration court if no agreement is reached.
European Energy Commission Guenther Oettinger is brokering attempts to compromise on the price, with the average gas price paid by Europe to Gazprom at around $370 in 2013.
Late on Monday, after some six hours of talks, Oettinger said the chief executives of Gazprom and Ukraine's Naftogaz had agreed to consider a plan that could avoid price disputes recurring over the European winter when demand peaks.
Gazprom accounts for around a third of Europe's gas needs and supplies to Europe carried via pipelines across Ukraine were disrupted during two previous "gas wars".
Gazprom CEO Alexei Miller sought to emphasise the importance of Russian gas to Europe, saying supplies to Europe and Turkey in May had risen by more than 10 percent in May and by more than 5 percent in the first five months of 2014, year-on-year.
"At the same time, as we predicted, domestic gas production in Europe and supplies from other sources continue to decrease," Gazprom quoted Miller as saying.
Separately, however, Gazprom said it planned to export 158.4 billion cubic metres (bcm) of gas this year to Europe and Turkey, down from 161.5 bcm in 2013. But a senior official said this was a "conservative" forecast which could be revised later.
Russia said on Monday that Kiev, facing the prospect of its gas debt to Moscow rising above $5 billion by June 7, had paid $786 million of its bill.
The moves helped reduce tensions in the gas row, despite continuing political recriminations over fighting between pro-Russian separatists and the Ukrainian armed forces that are trying to regain control of territory in east Ukraine.
"Our view is that Gazprom and Naftogaz will reach a compromise on the price at around $350; however, it is unclear how long the discussions will continue and what the possible consequences will be," Russia's VTB Capital said in a research note. (Additional reporting by Pavel Polityuk in Kiev and Steve Gutterman in Moscow, Writing by Katya Golubkova, Editing by Timothy Heritage/Ruth Pitchford)
