India paid a second instalment of $550 million in oil dues to Iran, under an interim deal that has allowed Tehran access to $4.2 billion in blocked funds globally, two industry sources said.Asian buyers such as Japan and South Korea have already cleared some of the money they owe for imports of Iranian oil under a payment schedule approved by world powers in an interim nuclear deal with Iran last November.
Iran wanted the last three payments under the joint plan of action (JPA) totalling $1.65 billion from India, but New Delhi could not clear the May and the June instalments on time as the banking mechanism to remit the funds was not in place. The current mechanism involving the central bank of the United Arab Emirates allows Tehran access to funds in Dirahms as a reward for cooperating in talks with world powers over its nuclear programme.
"All refiners have made the payment," said one of the sources, who declined to be named because of the sensitivity of the issue. India also made the first payment to Iran under the interim deal. The settlement of the final instalment of $550 million to Iran due on July 20 depends on Iran fulfilling all of its commitments under the joint action plan.
Iran and six major powers resumed talks last week and negotiators continued meetings in Vienna on Tuesday, but there was no immediate sign of substantive progress. Supreme Leader Ayatollah Ali Khamenei has said his country would need to significantly increase its number of centrifuges, underlining a gap in positions between Tehran and world powers as they seek to clinch a nuclear accord.
The respective payments by the five refiners were the same as in the previous instalment, said a second source. Mangalore Refinery and Petrochemicals Ltd, Essar Oil, Indian Oil Corp., Hindustan Petroleum Corp and HPCL-Mittal Energy Ltd. together owed about $4.6 billion to National Iranian Oil Co as of May 31. India, which imports a total of 4 million barrels per day of oil, has been steadily reducing its dependence on Iran, whose share in its overall oil imports has fallen by two-thirds over the last five years to 5.7 per cent in 2013/14.
But the energy use in the world's second-largest economy rose a mere 4.7 percent, falling below the average annual growth rate of 8.6 percent observed over the past decade, despite the fact that Beijing officially reported a 7.7 percent rise in GDP last year, BP Chief Economist Christof Ruhl said.
"Normally, energy consumption growth traditionally reflects the rate of economic growth," Ruhl said. "Energy consumption in the United States benefited from the shale gas boom. There are lots of cheap fuels that feed into the industry which will eventually reflect in GDP growth, but in China's case, it's not that easy to reconcile to the slowdown in energy numbers."
He added that the moderate growth was mainly driven by lower consumption of coal, which can be partly attributed to the domestic economic restructuring. The share of China's service sector surpassed that of the industrial sector for the first time in 2013, he said, leading to a further decline in the use of energy.
"China's slowdown in coal usage cannot be attributed to the government's environmental policies, as the closure of coal plants and the push for clean energy started rather late in the year, and hence cannot be attributed in the full-year numbers," Ruhl said.
Last year, coal continued to be a dominant source of energy and accounted for 67 percent of the overall energy pie.
Total coal production in China slowed even further, with growth of just 1.2 percent - the weakest since 2000.
The demand for oil, the second-largest fuel in China, also hit its lowest point since 1991, accounting for 17.8 percent of the country's energy consumption, BP said.
Over the past decade, natural gas has doubled its share of total energy consumption to 5.1 percent, and the share of non-fossil fuels increased by more than 50 percent to 9.6 percent.
Wang Tao, a resident scholar with the Energy and Climate Program of the Carnegie-Tsinghua Center for Global Policy in Beijing, said that the fact that the growth of all the three major fossil fuels, including natural gas, fell below average in the past decades, is a reflection of a major trend that is evolving in the energy market.
"Apparently, this important shift in China is structural, and whatever is the reason, it is certainly happening," he said.
Du Juan contributed to this story.
Wed Jul 9, 2014 2:12am EDT
(Reuters) - Saudi Arabia produced 9.780 million barrels per day (bpd) of crude oil in June, up from 9.705 million bpd in May, an industry source familiar with the matter said on Wednesday.
The world's largest oil exporter and OPEC heavyweight supplied 9.745 million bpd to the market, the source said. Supply to the market may differ from production depending on the movement of barrels in and out of storage.
The source did not give a reason for the rise in output, but the kingdom typically increases production during the hot summer months to meet a surge in electricity demand.
Demand for power generation oil in Saudi Arabia is usually higher in June than in May, official data from recent years shows.
OPEC's oil output has fallen in June from May's three-month high, a Reuters survey found last month, as fighting in Iraq closed its largest oil refinery and technical problems slowed its southern exports.
Supply from the Organization of the Petroleum Exporting Countries has averaged 29.93 million bpd, down from 30.00 million bpd in May, according to the survey based on shipping data and information from sources at oil companies, OPEC and consultants. (Reporting by Rania El Gamal; Editing by Mark Potter)
The US Energy Information Administration on Tuesday raised its 2014 non-OPEC oil production forecast, while lowering its expectations for global demand.
In its July Short-Term Energy Outlook, the agency said global oil demand in 2014 is expected to be at 55.84 million b/d, up 180,000 b/d from its June estimate.
At the same time, the EIA lowered its 2014 global demand outlook to 91.62 million b/d, down 170,000 b/d from a month earlier. Production from the US and Canada is expected to grow by a combined annual average of 1.6 million b/d in 2014, and 1 million b/d in 2015.
EIA estimates that the Former Soviet Union’s production will rise by an annual average of 120,000 b/d in 2014, led by Russia. However, production in the region declines by 100,000 b/d in 2015.
Unplanned supply disruptions among non-OPEC producers averaged 600,000 b/d in June, down from an estimated 700,000 b/d in May. South Sudan, Syria, and Yemen accounted for 83% of total non-OPEC supply disruptions.
The agency said non-OECD countries account for nearly all of the expected consumption growth in 2014 and 2015. China is the leading contributor to projected global consumption growth, with consumption increasing by 400,000 b/d, or 3.7% in 2014 and 430,000 b/d in 2015.
However, China’s economic and oil consumption growth rates have moderated compared with rates before 2012, when annual GDP growth exceeded 9% and oil consumption growth averaged almost 800,000 b/d from 2009 through 2011. US liquids consumption, which increased by 400,000 b/d in 2013, is expected to be largely unchanged in 2014 and then increase by 70,000 b/d in 2015.
(Recasting to include Seplat Nigerian efforts)
Nigeria-focused Canadian independent Mart Resources will begin shipping oil through a new pipeline linked to the Forcados terminal by August, enabling it to more than double output from the Umusadege Field, the company’s chief financial officer said Tuesday. Separately, Nigerian independent Seplat Petroleum Development’s own alternative pipeline project is also progressing, a spokesman said.
The two companies are part of a boom in independents producing onshore Nigeria, particularly as the majors sell assets to concentrate on offshore fields less vulnerable to unrest and theft. Both are looking to decrease dependency on single pipelines and their vulnerability to sabotage and theft.
Helped by its new 50-km link to the Trans Forcados pipeline, Mart expects to increase output from Umusadege to 30,000 b/d at year-end from around 12,000-13,000 b/d currently, CFO Dmitri Tsvetkov told Platts.
The pipeline “is being commissioned this month and the first oil will flow at the end of July-beginning of August,” he said. Mart until now has been entirely dependent on the Eni Nigerian Agip Oil pipeline, which provides the company with about 12,000-13,000 b/d of capacity, but has been prone to sabotage.
Mart expects Umusadege output next year of 35,000-40,000 b/d. It expects 8-10% losses along the total length of its route to the Forcados terminal, including the new 50-km section, Tsvetkov said. Mart is drilling a horizontal well at Umusadege and has two more planned, along with deepening of an existing well and one or two exploration wells, Tsvetkov said.
“We have a lot of oil behind wells, which is waiting for additional capacity and with additional development drilling we can ramp up production very quickly to the level of 30,000 b/d by the end of the year, he said. “The second reason [for the new route] is to have two pipelines, to have an alternative route.”
First drilled in 1974, Umusadege was redeveloped starting in 2007 in a partnership between Canada-based Mart and two Nigerian companies, Midwestern Oil and Gas and Suntrust Oil, taking advantage of tax breaks for fields officially designated “marginal.” Seplat Petroleum’s new 10-km pipeline linking its OML 4, 38 and 41 blocks to the Warri refinery will be fully operational by year-end, spokesman David Boyd said Tuesday.
The pipeline to the refinery provides an alternative to Seplat’s link to the Trans Forcados pipeline. Crude on the new pipeline is to be provided under a swap deal in which Seplat receives oil at the Forcados terminal, he said.
Light, sweet North Sea grade Oseberg is at its lowest differential to Dated Brent since October 2010, Platts data showed Tuesday, after poor margins saw Europe’s refineries reduce run cuts recently and amid competition from West African suppliers. Oseberg was assessed at a $0.33/barrel premium to Dated Brent Monday.
On other parameters, the sweet grade broke recent records — the cracking margin hit $5.88/b Monday, its highest since Platts began assessing the metric on May 1, 2013. The cracking yield netback margin is the difference between the ARA delivered spot price and northwest European refinery crack yields.
Oseberg’s weakness was indicative of a wider trend among sweet crudes in the North Sea. Norway’s Troll was assessed at Dated Brent plus $1.62/b, its lowest premium since Platts began assessing the grade in March 2012.
The same was true of DUC, a Danish sweet, which fell to Dated Brent plus $0.45/b. Gullfaks, another Norwegian light, sweet crude, was at its weakest premium to Dated Brent, at $1.12/b, since first assessed on January 1, 2010 on a CIF Rotterdam basis.
“Sweets are [at these levels] because of poor margins in the recent past for European refineries,” a North Sea crude trader said. “These [margins] have recently improved, so I would not be surprised if [sweets] started to go up, because today’s margins allow for some spot demand.”
Libya’s slow return to the Mediterranean sweet crude market could cause hesitation among refinery buyers, the trader said. However, some Mediterranean sweet grades, such as Azeri Light, have started to pick up in recent days. In addition, the West Africa sweet crude glut has started to clear.
WAF sellers turned to Europe for offtake demand as China and other Far Eastern buyers failed to buy their regular volumes from Angola and Nigeria. The WAF glut pushed down sweet premiums in the North Sea as they competed directly for European trade. Sour grades in the North Sea have picked up in recent days: Flotta and Forties, for instance, have recovered from recent troughs seen last Thursday. This process has brought in the sweet-sour spread in the North Sea somewhat.
The major Sharara oil field in the southwest of Libya is due to restart production Wednesday after an agreement was reached Tuesday with protesters that were blockading the pipeline linking the field to export terminals, an official at Libya’s state-owned NOC said.
Sharara has a capacity of 340,000 b/d, so its return would give Libya’s crisis-hit oil sector a major boost. “It should restart tomorrow,” the NOC official said. The Sharara field is operated by a joint venture between NOC and Spain’s Repsol.
Earlier Tuesday, NOC said total Libyan crude oil production has risen further to an average of 326,000 b/d as hopes remain high of a recovery in both output and exports following the lifting of force majeure at the major eastern ports of Es Sider and Ras Lanuf.
Output is slowly ramping up from lows of just 150,000 b/d last month, though it remains well below the 1.5 million-1.6 million b/d Libya was producing before the current spate of unrest began in May 2013.
Despite US total crude production climbing by 1.1 million b/d in just a year and expectations that production will climb another 800,000 b/d to 9.3 million b/d in 2015, both WTI and Brent prices will average above $100/ barrel this year, the US Energy Information Administration said Tuesday.
In its July Short-Term Energy Outlook, EIA increased its forecast for 2014 average prices for WTI to $100.98/b, up $2.31 from last month’s 2014 estimate, while prices for Brent are expected to average $109.55/b, up $1.73 from the previous estimate.
The price increase was largely because of unrest in Iraq, which put upward pressure on world oil prices, EIA said. Prices for WTI are expected to average $95.17/b in 2015, while Brent prices are expected to average $104.92/b next year, EIA said. These estimates are $4.25 and $3 higher, respectively, than estimates EIA released last month.
Total US crude production, which averaged 7.4 million b/d in 2013, will average nearly 8.5 million b/d in 2014 and 9.3 million b/d in 2015, EIA said. “The 2015 forecast represents the highest annual average level of oil production since 1972,” EIA said.
Total US consumption of motor gasoline, distillate fuel oil and jet fuel will be 18.88 million b/d this year, EIA said. That estimate is 500,000 b/d less than EIA’s June estimate. Total consumption is expected to climb to 18.95 million b/d in 2015, about 300,000 b/d less than what EIA estimated last month.
EIA said consumption of motor gasoline will climb to 8.81 million b/d in 2014, up from 8.77 million b/d in 2013, but will fall slightly to 8.80 million b/d in 2015 “as improving fuel economy in new vehicles increasingly offsets highway travel growth.”
By Stephen Treloar and Eduard Gismatullin Jul 8, 2014 11:14 PM GMT+0700
A.P. Moeller-Maersk A/S (MAERSKB) said its oil and gas business will take a $1.7 billion writedown on its assets in Brazil, becoming the latest explorer to draw a blank in the country’s energy boom.
Maersk in 2011 purchased stakes in three oil blocks in Brazil for $2.4 billion, which it has now written down to $600 million, it said in a statement. The Copenhagen-based company, which said it will ax plans to acquire the operatorship of the three fields, maintained 2014 guidance for an “underlying profit” of about $4 billion.
After state oil company Petroleo Brasileiro SA (PETR3) made several massive offshore discoveries, explorers rushed to acquire Brazil assets. Results have been mixed. BP axed staff after poor exploration results and OGX Petroleo & Gas Participacoes SA (OGXP3) went bankrupt when fields failed to perform as expected. While others including Repsol SA (REP) and BG Group Plc (BG/) have had more success increasing production, Petrobras has become the world’s most indebted oil explorer through a $220 billion plan to develop fields.
The investment “was made at a time when the outlook for the oil industry and oil prices were more positive than today and we had growth ambitions for our Brazilian oil business,” Chief Executive Officer Nils S. Andersen said in the statement. “It’s of course clearly unsatisfactory that the oil volumes in the acquired fields Itaipu and Wahoo after appraisal drilling has proved to be in the low end of our original expectations.”
http://www.bloomberg.com/image/i_7m91lY4vE4.jpg
Shares of Maersk, which runs the world’s biggest container line, fell 1.4 percent to 13,420 kroner in Copenhagen.
Wahoo Field
The Danish company sold a stake in the producing field Polvo to the operator, HRT O&G Exploracao e Producao de Petroleo Ltda., and is writing down the value in the other two fields, Wahoo and Itaipu, which are being planned for development. Wahoo is operated by Anadarko Petroleum Corp. (APC) and BP manages Itaipu.
“Maersk Oil now expects that these plans will result in a lower value than originally anticipated as the appraisal drilling performed have come out at the low end of the original expectations and additional adverse impacts from increased development costs and lower oil price also must be expected,” Maersk said.To contact the reporter on this story: Stephen Treloar in Oslo at streloar1@bloomberg.net
To contact the editors responsible for this story: Jonas Bergman at jbergman@bloomberg.net Ana Monteiro, Alex Devine
By Lananh Nguyen Jul 8, 2014 10:44 PM GMT+0700
European gasoil, used to heat homes, had the longest slump since in at least 25 years as rising fuel imports from Russia and the U.S. added to a supply glut.
Futures for delivery this month dropped by $7.50 a metric ton, or 0.8 percent, to $888.75 a ton on the ICE Futures Europe exchange in London at 4:20 p.m. That’s the 10th daily decline, the longest retreat in ICE data going back to July 1989 on Bloomberg.
Gasoil supplies in Europe’s oil trading hub rose to a 16-month high last week, according to PJK International BV, a researcher in the Netherlands. Imports of fuel from Russia and the U.S. have surged this year. Crude oil prices fell below $110 a barrel today, reversing a rally that started when Islamist militants seized a swathe of northern Iraq a month ago.
“Weak demand and a high supply of gasoil from Russia and the U.S. is putting pressure on gasoil prices,” Abhishek Deshpande, an analyst at Natixis SA in London, said by e-mail today.
Europe’s gasoil inventories are at their highest for this time of year since 2011. Supplies held in independent stockpiles in the Amsterdam-Rotterdam-Antwerp oil hub rose 4.9 percent to 2.5 million metric tons in the week to July 3, PJK data showed.
ICE gasoil prices fell this month after rising in July for the last five years. The contract is a benchmark for middle distillates, a category of fuels that includes diesel, heating oil and jet fuel. Demand for diesel typically rises in the summer.
High Stockpiles
“Consumers just haven’t been buying,” Michael Barry, a director at FGE, an energy consultancy, said by phone from London. “We’re still really suffering from the very warm winter. We came out of that winter with very high consumer stocks of heating oil.”
Increased imports are also pressuring gasoil prices, Barry said. Russian diesel destined for export rose to 3.7 million tons in May, 23 percent higher than a year earlier, according to data from the Energy Ministry’s CDU-TEK unit. Russian refiners including OAO Rosneft reduced maintenance in the first half of the year, enabling them to export more fuel, according to KBC Energy Economics and UralSib Financial Corp., an investment bank.
Diesel shipments to Europe from the U.S. rose to 321,000 barrels a day from January to May, an increase of 5.6 percent from 304,000 in the same period last year, according to an estimate from FGE. North America is becoming a fuel export “titan” as the shale revolution makes U.S. refineries more competitive, the International Energy Agency said June 17.
To contact the reporter on this story: Lananh Nguyen in London at lnguyen35@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net James Herron
By Lananh Nguyen and Yuji Okada Jul 9, 2014 6:07 AM GMT+0700
Energy trading on futures exchanges is slumping as increased oversight from regulators hinders transactions, according to Platts, a company publishing prices for physical commodities including oil.
The amount of light, sweet crude futures handled by CME Group Inc. (CME), the world’s largest derivatives exchange, slumped 22 percent to an average of 489,658 contracts a day in May from a year earlier, the bourse’s data show. Natural gas trades fell the same amount. Brent crude transactions on Intercontinental Exchange Inc. (ICE) were 9 percent fewer in the first six months than the same period in 2013.
Banks including Barclays Plc, JPMorgan Chase & Co. and Morgan Stanley reduced their commodity businesses over the past several years as returns declined and regulatory scrutiny intensified. The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010 restricted banks from trading for their own account, under the Volcker Rule, and expanded oversight of commodities derivatives.
“Regulators of course, with the best intentions, were trying to protect interests of the people that are involved with production and consumers that are hedging,” Jorge Montepeque, global director of market pricing at Platts, said at a conference in Tokyo today. “But the end result is that there are fewer people now to hedge with.”
Montepeque didn’t say which regulations reduced trading. Total energy trading slumped 18 percent in May on CME and by 19 percent on ICE, according to his presentation.
Volatility Slump
Cross-border regulatory uncertainty is a growing concern for traders, Chris Grams, spokesman for CME Group, which operates the New York Mercantile Exchange, said by e-mail. For example, global commodity firms are less willing to hedge risks outside of Europe because the European Union treats cleared futures traded on non-EU exchanges as over-the-counter derivatives, which then count toward the clearing threshold for non-financial customers.
“We continue to work with regulators on equivalence standards that would resolve the issue,” Grams said.
Trading volume fell in May because of reduced price volatility in oil markets, ICE spokeswoman Claire Miller said in an e-mailed response to questions, adding that they rebounded in June as price movements increased again. Brent crude jumped last month because of escalating violence in Iraq.
“ICE is investing substantial time and resources to ensure that new regulatory reforms maximize and enhance market efficiencies, while minimizing unintended consequences such as a reduction in market liquidity,” Miller said.
Traders who use futures to hedge “complained that their access to markets has actually suffered since regulators came in to protect them,” Montepeque said. Platts, a unit of New York-based McGraw Hill Financial Inc. (MHFI), competes with Bloomberg LP and other companies in providing energy markets news and information.
To contact the reporters on this story: Lananh Nguyen in London at lnguyen35@bloomberg.net; Yuji Okada in Tokyo at yokada6@bloomberg.net
To contact the editors responsible for this story: Alaric Nightingale at anightingal1@bloomberg.net Richard Stubbe, David Marino
By Mark Shenk Jul 9, 2014 12:10 AM GMT+0700
The U.S. Energy Information Administration increased its 2014 and 2015 price forecasts for West Texas Intermediate and Brent crudes because of the upsurge of violence in Iraq.
WTI will average $100.98 a barrel this year versus the June projection of $98.67, the EIA, the Energy Department’s statistical unit, said today in its monthly Short-Term Energy Outlook. The U.S. benchmark grade will average $95.17 in 2015, up from the previous month’s estimate of $90.92.
The EIA boosted the forecast for Brent to $109.55 for this year from $107.82. Next year’s forecast was raised to $104.92 from $101.92.
“Price forecasts were raised primarily because the problems in Iraq caused us to scale back our production projections,” Tancred Lidderdale, an economist with the EIA in Washington who helped write the report, said in a telephone interview.
U.S. crude output is projected to rise to 8.46 million barrels a day this year and 9.28 million in 2015, up from 7.44 million last year. That’s up from last month’s forecast of 8.42 million barrels a day this year and 9.27 million in 2015. U.S. crude production peaked at 9.6 million in 1970.
Liquid Fuels
Total production of liquid fuels, including those associated with natural gas output, will average 13.63 million barrels a day in 2014 and 14.6 million next year, the report showed. That’s up from last month’s projections of 13.52 million this year and 14.51 million.
“Our projections for natural gas liquids have been rising steadily this year because plants are getting better at separating them and demand has grown,” Lidderdale said.
Horizontal drilling and hydraulic fracturing, or fracking, have unlocked supplies in shale formations in North Dakota, Texas and other states.
The department lowered its forecast for global oil consumption this year to 91.62 million barrels a day from 91.79 million estimated last month. The forecast for 2015 production was reduced to 93.08 million from 93.12 million.
U.S. oil consumption will average 18.88 million barrels a day in 2014, down from last month’s forecast of 18.93 million. Next year demand is projected to climb to 18.95 million. The previous 2015 estimate was 18.98 million.
Regular gasoline will average $3.54 a gallon at the pump this year, up from an estimate of $3.50 in June, the EIA said.
To contact the reporter on this story: Mark Shenk in New York at mshenk1@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Richard Stubbe, Stephen Cunningham
By Zaid Sabah and Caroline Alexander Jul 8, 2014 9:39 PM GMT+0700
Sunni tribes battling the Shiite-led government of Iraq won’t stop until Prime Minister Nouri al-Maliki steps down, a clan chief said. Then they want to set up their own autonomous region within a united Iraq.
“There is no way back,” Najih al-Mizan, a leader from the Albu-Rahman tribe in the northern city of Samarra in Salahuddin province, said by phone. “We’re going to form our own federal territory based on the Iraqi constitution.”
The al-Qaeda breakaway group that last month escalated its offensive against the state has been joined by some clans who accuse Maliki of excluding Sunnis from government. The premier, whose party won the most parliamentary seats in April’s election, has defied calls from across the sectarian divide for him to step down, while rivals have been unable to garner enough support to force him from office. Parliament, which had been due to sit today, is now set to meet on July 13.
The tribesmen aren’t fighting for the caliphate that the Islamic State fighters have proclaimed in territory they control, and will deal with the militant threat once their demands are met, al-Mizan said. In addition to removing Maliki, they’re seeking an emergency government of technocrats, the disbanding of Shiite militias, and the restoration of an independent judiciary, he said.
The partial Sunni uprising -- other tribes have remained loyal to the government -- and an emboldened push for independence by ethnic Kurds have raised concerns Iraq may fracture along historic fault-lines.
Protest Camps
This is a “defining crisis for the modern Iraqi state,” said Ali Allawi, a minister in governments following the dismantling of Saddam Hussein’s regime. “It’s the first time in modern history that the state itself is seriously questioned,” he said in a July 2 conference call organized by Arabia Monitor. “The way the Iraqi political class is responding may exacerbate a de facto split.”
Maliki has vowed to defeat the “terrorists” threatening the nation’s integrity. He has offered an amnesty to Sunni tribesmen who “return to their senses” and haven’t shed blood, according to the BBC.
While it was the storming of Mosul by the Islamic State, known then as the Islamic State in Iraq and the Levant, or ISIL, that provided the spark, anger over Maliki’s government had been building.
Refuge Claim
Sunnis set up protest camps in the western city of Ramadi last year, saying Maliki was using anti-terrorism legislation to target them. Unrest escalated after guards protecting popular Sunni Finance Minister Rafih al-Issawi were arrested on terrorism charges and the minister resigned in protest.
Demonstrations spread to eight Sunni-dominated regions, including Samarra, which also houses the al-Askari mosque, one of the holiest for Shiites. The camps, which Maliki said were providing a refuge for terrorists, were forcibly closed with about 50 people killed in one raid in Hawija in April 2013, according to Al-Jazeera television.
“We realized peaceful protests won’t work so Sunni tribes decided to turn to weapons to get their rights,” al-Mizan said from Erbil, capital of the semi-autonomous Kurdish region, carved from Iraq during the 1991 Gulf War.
Last month, al-Mizan appeared at a news conference in Erbil with Sheikh Ali Hatem al-Suleiman, head of the Dulemi tribal confederation. With more than 3 million members, it’s one of the largest of dozens of Sunni tribes in western Iraq.
‘Uprising of Oppressed’
Suleiman said Iraq was witnessing “a popular revolution and it won’t stop until Maliki is removed.”
Organized and funded by the U.S. into so-called Awakening Councils, the Sunni clans played a key role in ending the war that ravaged Iraq following the toppling of Saddam.
After control of the councils passed to Maliki’s government in 2008, he reneged on vows to integrate fighters into the security forces and stopped salaries.
Former Prime Minister Ayad Allawi, a secular Shiite lawmaker, said the Islamic State is taking advantage of “the favorable political landscape of sectarianism” and described the insurgency as “an uprising of the oppressed.”
“Ex-Baathists, ex-army, tribal leaders, academics, ordinary citizens and the old resistance” to the U.S. military are fighting the government, he said in an e-mailed response to questions. “I don’t know who’s leading them but they, with their families, reach millions.”
Al-Mizan won a seat in the April election, only to lose it following a judicial review. After the Islamic State seized Mosul, he fled to the safety of Erbil along with other tribal leaders.
Sunnis look to the Kurdish region as an inspiration for the self-governing region they want to establish in the provinces of Anbar, Salahuddin and Nineveh, al-Mizan said.
“About 90 percent of Sunnis in these provinces would go for a semi-autonomous region,” he said. “We’d form our own government, parliament and army -- the same way the Kurds did.”
To contact the reporters on this story: Caroline Alexander in London at calexander1@bloomberg.net; Zaid Sabah in Washington at zalhamid@bloomberg.net
To contact the editors responsible for this story: Alaa Shahine at asalha@bloomberg.net Mark Williams, Ben Holland
By Zain Shauk and Narayanan Somasundaram Jul 8, 2014 2:59 PM GMT+0700
A fund managed by Macquarie Group Ltd. (MQG) agreed to take full control of a U.S. bulk liquid terminals operation for $1.03 billion in cash and stock as Australia’s largest investment bank expands its North American businesses.
Macquarie Infrastructure Co. (MIC), which owns storage terminals for oil products and chemicals in the U.S., will buy the 50 percent of International-Matex Tank Terminals it doesn’t already own, it said in a statement yesterday. The deal also will boost quarterly dividends, it said.
The acquisition is the latest transaction in the terminals business for Macquarie. The bank agreed in August to buy 45 percent of Singapore’s Helios Terminal Corp. from Oiltanking Gmbh for an undisclosed sum. It also bought ANZ Terminals for A$525 million ($492 million), the Australian Financial review reported June 30.
“There has been an emphasis on the commodities business as Macquarie sees it as a stable business in the long run,” David Ellis a Sydney-based analyst at Morningstar Inc. said by phone. “It plays into their strategy to boost steady revenue streams to offset the cyclical nature of their advisory and equity trading businesses.”
Macquarie Infrastructure has gained 12 percent in New York trading this year. Macquarie Group closed 0.8 percent lower at A$59.73 in Sydney. The benchmark S&P/ASX200 index fell 0.1 percent.
The accord comes after years of disagreement and arbitration between Macquarie and other investors, including members of International-Matex’s founding Coleman family, according to U.S. regulatory filings. Macquarie Infrastructure bought its initial 50 percent stake in the company in May 2006.
Founding Family
Macquarie Infrastructure will purchase the stake from the Colemans, the New York-based company said in a statement. Members of the family will step down from roles as chairman, chief executive officer and head of government relations.
International-Matex owns and operates 12 bulk liquid storage terminals in North America, with a capacity of 42 million barrels, including marine terminals on the U.S. east, west and Gulf coasts, according to a company website.
Macquarie’s funds management business is the group’s largest revenue contributor. Its operating income climbed to A$1.93 billion in the year ended March 31, up 27 percent on the previous year, filings show. Macquarie’s infrastructure business is a part of the funds management unit.
Income from its business in the Americas, largely in the U.S., overtook its home market of Australia for the first time and contributed 35 percent of total income, according to the filings.
Dividend Growth
“The acquisition will deliver dividend growth for shareholders of MIC and further enhance our ability to drive operational improvement and growth investments,” James Hooke, CEO of Macquarie Infrastructure, said in the statement.
With the signing of the deal, Macquarie Infrastructure will increase its quarterly cash dividend. The dividend payable for the second quarter will be 95 cents a share, up 1.3 percent from the prior quarter. The dividend will be payable on Aug. 14 to shareholders on record on Aug. 11.
Macquarie Infrastructure said it will buy the remaining stake for $910 million in cash and $115 million in stock.
After the deal, International-Matex will become the largest business division within Macquarie Infrastructure, which has a market value of $3.5 billion. The company said it doesn’t expect the transaction to close before late July.
Macquarie Infrastructure’s earnings before interest, taxes, depreciation and amortization, or Ebitda, from International-Matex has more than tripled to $279.6 million for the 12 months through March 31, the company said in its statement. Macquarie’s 50 percent stake in the business contributed $39.7 million to Macquarie’s first quarter Ebitda, according to the company’s earnings report April 30.
To contact the reporter on this story: Narayanan Somasundaram in Sydney at nsomasundara@bloomberg.net
To contact the editors responsible for this story: Chitra Somayaji at csomayaji@bloomberg.net Keith Gosman, Jason Rogers
By Zain Shauk Jul 8, 2014 6:00 AM GMT+0700
Squinting into a laptop perched on the back of his pickup, Austin Holland searches for a signal from a coffee-can-sized sensor buried under the grassy prairie.
Holland, Oklahoma’s seismology chief, is determined to find the cause of an unprecedented earthquake epidemic in the state. And he suspects pumping wastewater from oil and gas drilling back into the Earth has a lot to do with it.
“If my research takes me to the point where we determine the safest thing to do is to shut down injection -- and consequently production -- in large portions of the state, then that’s what we have to do,” Holland said. “That’s for the politicians and the regulators to work out.”
So far this year, Oklahoma has had more than twice the number of earthquakes as California, making it the most seismically active state in the continental U.S. As recently as 2003, Oklahoma was ranked 17th for earthquakes. That shift has given rise to concern among communities and environmentalists that injecting vast amounts of wastewater back into the ground is contributing to the rise in Oklahoma’s quakes. The state pumps about 350,000 barrels of oil a day, making it the fifth largest producer in the U.S.
The rise in earthquakes isn’t just happening in Oklahoma, challenging scientists and regulators across the country. The growth of seismic activity alongside oil production in fracking states from Colorado to Ohio has sparked a series of studies tying the temblors to drilling activity. Most seismologists around the country are convinced that wastewater injected back into the ground is jolting fault lines and triggering earthquakes. Between 2006 and 2012, the amount of wastewater disposed in Oklahoma wells jumped 24 percent, to more than 1 billion barrels annually, according to the Oklahoma Corporation Commission, which regulates the industry.
‘Strong Correlation’
“There’s a couple of good examples where I think it’s pretty clear that if you turn off the well the earthquakes stop,” said Justin Rubinstein, deputy chief of the U.S. Geological Survey’s induced seismicity project “It’s a pretty strong correlation.”
Oil companies say the science isn’t far enough along and that correlation in activity does not amount to proof that their wastewater wells are causing the earthquakes.
“We’ve been doing injection in the state for a long time,” said Chad Warmington, president of the Mid-Continent Oil and Gas Association of Oklahoma. “It deserves a lot more investigation before making a determination.”
Waiting on Science
Duane Grubert, executive vice president of investor relations for SandRidge Energy Inc., based in Oklahoma City, said his company is “waiting on the science” to become more conclusive. More than a half a dozen other oil companies contacted for this story declined to comment.
Warmington said the industry is concerned that oil and gas laws may be hastily rewritten, requiring costly changes in the way companies handle the billions of gallons of waste fluids they inject underground each year.
“We don’t want anyone to rush to judgment based on faulty or inaccurate data and that’s all we’re asking for,” he said.
Some studies done so far suggest that wastewater wells may be the culprit in what scientists say is an otherwise unexplained and unprecedented surge in temblors. One study published July 3 in the journal Science used data to show that the sharp rise in earthquakes near Oklahoma City starting in 2009 was caused by high levels of wastewater injection at four disposal wells.
Statistical Analysis
A statistical analysis by the U.S. Geological Survey showed that recent jumps in Oklahoma’s earthquake rate do not seem to be a result of natural seismic changes and that wastewater disposal has likely played a role in the increase. The survey warned that the rise in activity has significantly raised the chance of a damaging earthquake of magnitude 5.5 or greater in the state.
One mystery is why some wastewater disposal wells pose problems while others don’t, said Rubinstein, of the Geological Survey’s induced seismicity project. If researchers could untangle that riddle, “it seems probable that the industry would be able to avoid the problem,” he said.
While the debate continues in Oklahoma, other states are already moving forward. Arkansas has banned wastewater disposal in a 1,200-square-mile area after four wells there were blamed for causing a series of temblors. Ohio has prohibited waste-fluid injection into some underground rock layers and requires companies to monitor for earthquakes before and after drilling new disposal wells. Colorado regulators shut down a disposal well last month on suspicion that it had caused two earthquakes there.
More local governments may also institute bans following a New York court ruling, not related to earthquake fears, that allows cities and towns to block hydraulic fracturing if deemed adverse to communities.
Magnitude 3.0
Among the most alarming statistics in Oklahoma is the rise in stronger earthquakes. Between 1990 and 2008, there were never more than three quakes registering a magnitude 3.0 or greater in a single year, according to data from the Oklahoma Geological Survey. In 2013 there were 109, and through June of this year there were 238.
The largest earthquake tied to injection wells was a magnitude 5.7 temblor centered about 50 miles west of Oklahoma City in 2011 that destroyed 14 homes, injured two people and buckled pavement, according to research led by Katie Keranen, an assistant professor of geophysics at Cornell University.
“I think it’s pretty critical to assess the hazard,” Keranen said.
Holland’s work may provide the additional evidence the state needs to underpin new safety regulations. The focus of his latest investigation lies about five miles east of where Holland has buried his sensor: Injection Well No. 8520296, just across the Texas border due north from Fort Worth, Texas.
Tumbling Chimneys
The well sits on a site that was rattled nine months ago by a series of earthquakes that knocked over TVs, tumbling chimneys from rooftops and shattering the nerves of local residents. The temblors began two weeks after the wastewater company, Love County Disposal, began pumping millions of gallons of oilfield fluids down the well. When the pumping stopped weeks later, the shaking stopped.
Plans to begin using the Love County disposal well again later this year have given Holland a rare chance to study the link between wastewater disposal and earthquakes in real time.
“We’ve temporarily shut down to coordinate with the regulators and the geological survey,” said Thomas Dunlap, an owner of Love County Disposal. “Now let’s get the emotion out of it and get to the science of it to tell us what’s going on.”
To contact the reporter on this story: Zain Shauk in Houston at zshauk@bloomberg.net
To contact the editors responsible for this story: Susan Warren at susanwarren@bloomberg.net Rick Schine, Will Wade
Gas Bulls Cut Bets by Most Since November as Supply Gains
By Christine Buurma Jul 8, 2014 2:27 AM GMT+0700
Hedge fund managers’ retreat from bullish natural gas bets is becoming an exodus as mild weather and rising production erode a record supply shortfall.
Money managers cut net-long positions, or wagers on rising prices, by 15 percent in the seven days ended July 1, according to the Commodity Futures Trading Commission data. Net-long bets fell by the most since November. Long positions slumped 9.2 percent while bearish bets dropped by 2.7 percent.
A deficit to five-year average gas stockpiles has narrowed to 29 percent from an all-time high of 55 percent in April at the end of a frigid U.S. winter. Gross gas output in the lower 48 states rose to a record in April as new wells came online in Texas, Energy Information Administration data show. Commodity Weather Group LLC predicted mostly normal July weather that would limit demand from power plants.
“The pace of storage injections has gotten the market’s attention,” said John Kilduff, a partner at Again Capital LLC, a New York-based hedge fund that focuses on energy. “Rising production and a lack of early-season power demand have bullish traders back on their heels.”
Natural gas fell 8 cents to $4.455 per million British thermal units on the New York Mercantile Exchange in the week covered by the report. The fuel then slid 1.1 percent over the next two days to settle at $4.406 per million Btu on July 3. Prices sank to $4.225 today, the lowest settlement since Jan. 10.
Prices Drop
Gas futures dropped 1.8 percent in June and have tumbled 35 percent from a 10-month high reached in February. Government reports have shown eight consecutive triple-digit injections into storage since May 9, the longest streak in 20 years of data. Inventories totaled 1.929 trillion cubic feet as of June 27.
“The injection season has gotten off to a fantastic start, considering where we were at the end of the winter,” Stephen Schork, president of Schork Group Inc., a consulting firm in Villanova, Pennsylvania, said in a phone interview today. “We’re doing everything we potentially can to mitigate the deficit.”
Natural gas production in the lower 48 states rose 1.3 percent in April to a record 77.52 billion cubic feet a day from the previous month, the EIA, the Energy Department’s statistical arm, said in a June 30 report.
Record Output
Output from the Marcellus shale deposit in the Northeast will climb 1.9 percent in July to 15 billion cubic feet a day from 14.7 billion a month earlier, the agency said June 9 in its monthly Drilling Productivity Report.
The high in Chicago on July 12 may be 82 degrees Fahrenheit (28 Celsius), 3 less than usual, according to AccuWeather Inc. in State College, Pennsylvania. Atlanta temperatures may reach 88 degrees, matching the normal reading for the day.
Power plants account for 31 percent of gas consumption, according to the EIA, the Energy Department’s statistical arm.
In other markets, hedge funds reduced wagers on rising crude-oil prices for a second week as the conflict in Iraq has so far spared the country’s main oil-producing region.
WTI Crude
Net-long bets on West Texas Intermediate dropped 15,135 contracts futures and options combined, or 4.4 percent, in the week ended July 1 to 330,148, according to the CFTC. Wagers reached a record high of 356,336 on June 17.
WTI crude slipped 0.7 percent to $105.34 a barrel on the Nymex in the week covered by the report and settled at $103.53 today.
Net-long positions in gasoline held by money managers, including hedge funds, commodity pools and commodity-trading advisers, rose by 394 futures and options combined, or 0.6 percent, to 66,982, the CFTC report showed. Futures slipped 2.9 percent to $3.0366 a gallon in the week covered by the report. Gasoline closed at $2.989 today.
Gasoline at U.S. pumps, averaged nationwide, dropped 0.1 cent to $3.655 a gallon yesterday, according to Heathrow, Florida-based AAA, the nation’s largest motoring company.
Money managers’ bets on ultra-low sulfur diesel fell by 1,893, or 4.7 percent, to 38,488 futures and options combined, the CFTC report showed. Futures slid 2.1 percent to $2.9782 a gallon in the week covered by the report and settled at $2.9145 today.
Natural Gas
Net-long wagers on four U.S. natural gas contracts held by money managers dropped by 45,362 futures equivalents to 254,831 in the week ended July 1, the lowest level since December 3, according to the CFTC. Bearish bets slipped by 7,158 while long positions declined by 52,520.
The measure includes an index of four contracts adjusted to futures equivalents: Nymex natural gas futures, Nymex Henry Hub Swap Futures, Nymex ClearPort Henry Hub Penultimate Swaps and the ICE Futures U.S. Henry Hub contract. Henry Hub, in Erath, Louisiana, is the delivery point for Nymex futures, a benchmark price for the fuel.
“The two-week weather outlook is pretty normal, which isn’t helpful for gas demand,” Again Capital’s Kilduff said. “There isn’t a compelling case for a bull market at this point.”
To contact the reporter on this story: Christine Buurma in New York at cbuurma1@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Richard Stubbe
By Ladka Bauerova Jul 8, 2014 3:36 PM GMT+0700
A pipeline allowing Ukraine to import gas from Europe will start running at full capacity in September, providing vital fuel supplies as winter approaches with the prospect of no shipments from Russia.
The Vojany pipeline from Slovakia has been booked to ship 10 billion cubic meters a year until 2019, or about 20 percent of Ukraine’s demand, said Tomas Marecek, chairman of the link’s operator, Eustream AS. Ukrainian utility NAK Naftogaz booked the majority of the pipeline’s capacity for the five-year period, while the rest was reserved by European utilities, he said.
Vojany, unused for about 15 years, will be crucial this winter after Russia stopped exporting gas to Ukraine last month in a dispute over unpaid bills. Together with smaller pipelines from Hungary and Poland, Ukraine can import about 16.5 billion cubic meters a year from the European Union, Marecek said. That replaces about two-thirds of the fuel coming from Russia, and by reducing consumption and using underground storage, Ukraine stands a chance of lasting through the winter, he said.
“However things are not fully under the control of Ukraine,” Marecek said in an interview in Prague yesterday. “The weather will play a major role as well.”
Reverse Mode
While Ukraine would like even more gas from Europe, Slovakia, where the majority of Russian gas enters the EU, can’t increase reverse flows into Ukraine further without violating the existing contract with OAO Gazprom, the Moscow-based export monopoly, Marecek said. Under agreements between Eustream and Gazprom, no changes in gas use can be made before the commodity reaches the main import station in Slovakia about 7 kilometers (5 miles) past the Slovak-Ukraine border.
Eustream will spend as much as 20 million euros ($27 million) to prepare Vojany for reverse flow mode. The pipeline was built in the 1990s to supply a gas-fired power station that never started production.
“The European Commission pressured us, so we found a compromise solution,” Marecek said. “Using the Vojany pipeline is compatible with the EU energy laws and at the same time doesn’t violate any of Eustream’s existing contracts. We had it confirmed by both the EU and Russian Foreign Minister Lavrov.”
Ukraine hasn’t received any Russian gas since June 16, when Gazprom cut off deliveries after the two sides failed to reach an agreement on future prices and debt repayment. Gazprom raised the price for Ukraine to $485 per 1,000 cubic meters in April following the ouster of pro-Russian President Viktor Yanukovych and Russia’s annexation of Crimea.
Reduce Use
Ukraine, which consumes more than 50 billion cubic meters of gas a year, will need to reduce its use by 20 percent if Russia doesn’t start supplying again, Naftogaz Chief Executive officer Andriy Kobolyev said on July 4.
During the first few months of operation, there’s a risk that Vojany won’t be able to run at full capacity should the flow of transit gas from Russia to Europe through Ukraine get interrupted, Marecek said.
During September, Vojany’s flow will be “interruptible,” which means no gas will flow if Russia interrupts supplies to the EU. Starting Oct. 1, the pipeline will offer a firm capacity of 6.5 billion cubic meters a year, while the remaining 3.5 billion will remain interruptible until March 1. Vojany’s full capacity will become available at all times only at the end of next winter, he said.
Ukraine transports about 176 million cubic meters of gas to EU countries through its pipeline network connected with Slovakia, Romania, Hungary, Poland and Moldova. The Slovak pipeline carries around 95 million cubic meters a day.
Russia decreased gas transit via Ukraine in June by 17 percent from a year earlier to 5.9 billion cubic meters, UkrTransGas, the national pipeline operator, said today.
To contact the reporter on this story: Ladka Bauerova in Prague at lbauerova@bloomberg.net
To contact the editors responsible for this story: Will Kennedy at wkennedy3@bloomberg.net Alex Devine, Ana Monteiro
By Rakteem Katakey Jul 8, 2014 10:44 AM GMT+0700
China National Petroleum Corp., the nation’s biggest oil and gas producer, won its second order from Reliance Industries Ltd. (RIL) to build a natural gas pipeline in India.
China National Petroleum, or CNPC, will build 200 kilometers (124 miles) of the 302-kilometer pipeline from central India to the north of the country, according to CNPC’s newspaper China Petroleum Daily. The report didn’t give a value for the contract.
Reliance, which operates the world’s biggest refining complex, has coal-bed methane fields in Madhya Pradesh state in central India, according to the company’s website. The company, controlled by billionaire Mukesh Ambani, needs a pipeline to carry gas from its fields to customers in Uttar Pradesh state when production starts next year, according to the company’s annual report.
In 2006, CNPC won the contract to build Reliance’s pipeline that carries gas from its biggest field, KG-D6, off India’s east coast, to Gujarat state in western India.
Tushar Pania, a spokesman for Reliance, didn’t immediately comment on the pipeline contract.
Reliance dropped 0.5 percent to 1,027.20 rupees in Mumbai trading yesterday. The shares have increased 15 percent this year, compared with a 23 percent gain in the benchmark S&P BSE Sensex. (SENSEX)
To contact the reporter on this story: Rakteem Katakey in New Delhi at rkatakey@bloomberg.net
To contact the editors responsible for this story: Jason Rogers at jrogers73@bloomberg.net Indranil Ghosh, Abhay Singh
