Two 100,000 mt cargoes have been pulled from the June Urals crude loading program out of Primorsk, according to a copy of the final signed schedule seen by Platts Thursday, bringing total scheduled exports out of the terminal for the month to 3.4 million mt.
A Lukoil cargo that was in the provisional loading program released earlier this week for loading June 24-25 is not present in Thursday’s final version, and a Rosneft cargo scheduled for June 25-26 loading in the provisional schedule has been moved forward into the June 24-25 slot.
Additionally, a handwritten note at the bottom of the schedule indicated that a June 10-11 cargo, also of Rosneft equity, was no longer part of the export program in June. The removal of the two cargoes brings scheduled exports out of the port — which sees the greatest export volumes of the three main Urals crude loading terminals — to their lowest level in at least two years, according to Platts data.
The average daily loading rate at the terminal is scheduled to come in at 819,400 b/d in June, down 113,503 b/d from the rate seen in May. The Urals program typically comes out in several stages and is often subject to change between the publication of the provisional programs and the final, signed program. Changes to the loading schedule after the publication of the signed version are uncommon.
Some analysts and proponents of current restrictions on US crude exports on Thursday questioned a new claim made by energy consultancy IHS that domestic gasoline prices would fall if more US crude was exported.
The IHS study’s gasoline price impact forecast counters both the prevailing argument against a change in current US export policy and the key political hurdle to that change, but sources questioned the reliability of long-range gasoline price forecasts. They also pointed to numerous factors outside US export policy which could influence prices at the pump.
In a conference call, Kurt Barrow, a vice president with IHS, stood by the study’s results, and stressed that free trade of crude would cause domestic gasoline prices to fall by 8-12 cents/gallon, due to the close link between gasoline and world oil prices.
“It’s really based on the supply and demand fundamentals,” said Barrow, who said the study’s gasoline price estimates were inflation adjusted. “If we have additional crude production from the US, that increases the spare capacity in the world market, brings down Brent prices and world prices and translates back to that 8 cents/gal.”
The IHS study claims that an unrestricted crude export policy will cause domestic production to increase by 1.2 million b/d over the 2016-2030 period, adding new crude supply to the global market. This, in turn, will cause international crude prices to fall and put downward pressure on US gasoline prices, according to the study.
“This shows the dual benefit of free trade: producers receive greater price certainty and somewhat higher crude prices and consumers receive lower gasoline prices as a result of the direct effects of greater global supply,” the report states.
Jeff Peck, the head of Consumers and Refiners United for Domestic Energy (CRUDE), a refiners group against allowing crude exports, argued that the study’s claims of lower gasoline prices “defies common sense,” since a liberal export policy will likely lead to higher crude prices.
Peck pointed to US Energy Information Administration data which found that 68% of the cost of gasoline to consumers is directly attributable to the refiner’s cost of crude. Peck also dismissed the IHS study’s conclusions since the study was funded by the oil producers pushing for a change in current US export policy.
A number of oil and service companies, including ExxonMobil, Chevron, ConocoPhillips, Halliburton and Baker Hughes, sponsored the IHS study.
According to Barrow, the 8 cents/gal reduction was based on an estimate that dropping crude export restrictions would cause production to climb to 11.2 million b/d, from the current 8.2 million b/d level today, Barrow said.
A key Obama administration official on Thursday said the US has enough refining capacity to meet an increase in domestic light crude production, indicating that White House officials believe a change in current US crude export policy is not imminent.
During a conference call, White House adviser John Podesta said administration officials were monitoring the balance between domestic production and refining as it studies potential changes to long-standing restrictions on crude export policies.
“We’re keeping our eye on the fact that some of the oil being produced, particularly the light crudes that are coming from Eagle Ford in Texas, whether the refining capacity in the United States is able to manage it,” he said.
“It has been so far.” Podesta said the administration is continuing to review export policies, but declined to comment further. “We’re constantly reviewing the production, both where it’s coming from, how much is coming, what kinds of products are being produced, with an eye on what its overall effect on the economy is,” he said.
Earlier this month, Podesta said the Obama administration has ordered an interagency study on crude exports. Meanwhile, Energy Secretary Ernest Moniz said export policy changes were being considered because “the nature of crude oil we are producing may well not be matched to our current refining capacity.”
“North Dakota and Eagle Ford are producing very light oil that is not well connected by infrastructure to refiners,” Moniz said.
The ongoing shale boom has caused a production surge, but much of the oil being produced is light sweet crude and most of the refineries in the US are built for heavy sour crudes.
Nigerian light sweet crude Akpo has seen its values fall sharply amid weaker demand because of a drop in refining margins, trading sources said Thursday.
About a month ago at the start of the trading cycle of the Nigerian June loading program, demand for naphtha-rich Akpo from Asian, European and South American refiners was healthy. But in the last two weeks, demand for this grade has fallen amid a fall in naphtha cracks and declining refining margins.
June Akpo cargoes were being offered at Dated Brent plus $1.70/barrel in early May but by late May the last two Akpo June loading stems were heard traded well under Dated Brent plus $1/b. Akpo was assessed at Dated Brent plus $0.90/b Wednesday, a fall of $0.30/b since last Thursday. This is also the weakest value for Akpo since April 28, Platts data showed.
On Thursday afternoon, sources pegged Akpo closer to Dated Brent plus $0.80/b. Sources said the last end-June Akpo cargo was sold at levels close to Dated Brent plus $0.70/b though details of this trade could not confirmed by the participants involved at the time of writing.
But all traders acknowledged the market was looking much weaker than seen recently. “[It is] a terrible market, under a lot of pressure with margins so poor,” said a trader.
Sources said offer levels for the Nigerian July cargoes, however, were also on the high side, with Akpo being offered at Dated Brent plus $1.50/b, while Bonny Light was being offered at Dated Brent plus $3.20/b. “The market is pretty lethargic, with awful [refining margins],” said another trader.
NYMEX July crude settled 86 cents higher at $103.58/ barrel Thursday despite a 1.66 million-barrel rise in US commercial crude stocks, according to US Energy Information Administration oil data. ICE July Brent rose 16 cents to settle at $109.97/b.
NYMEX products were led by June RBOB, which rose 77 cents to settle at $3.0136/gal. Front-month ULSD futures settled down 1.16 cents at $2.9190/gal.
“I think that the numbers weren’t all that bearish,” Oil Outlooks President Carl Larry said. “It was make or break with imports today, and when we’re talking about imports then we get more in line with geopolitical risk.”
At 392.95 million barrels, US crude stocks are more than 4% above the EIA five-year average. “No one is having any trouble getting crude,” Larry said. “But all that we are getting hasn’t really helped us build supply for gasoline or distillates. We’re averaging about 15.8 million b/d in runs and supply just doesn’t reflect that.”
EIA product demand figures showed strength. Implied demand for gasoline rose 136,000 b/d to 9.31 million b/d last week, putting it nearly 4% above the five-year average. On a four-week moving average, demand is up 155,000 b/d to 9.1 million b/d, nearly 466,000 b/d higher than a year ago.
Distillate demand jumped as well, up 410,000 b/d to 4.2 million b/d. Larry also pointed toward stronger equities as a barometer for oil demand.
The Dow Jones Industrial Average was up more than 20 points at 16,656 around the NYMEX settle. The S&P 500 was up almost 6 points at 1,915.
Meanwhile, US crude imports rebounded last week, up 1.34 million b/d to 7.81 million b/d, EIA data showed. Imports to the US’ major refining centers on the US Gulf Coast alone rose 1.08 million b/d to 3.92 million b/d last week from lows not seen since the hurricane-heavy September 2008.
This boosted stocks in the region by 3.14 million barrels to 213.13 million barrels. Analysts expect volatility in USGC inventories to persist, making it tough to gauge fundamentals. “Beyond normal noise created by the timing and level of imports, a number of growing factors have added to the volatility,” Morgan Stanley analysts said in a note.
James Bambino, Platts Oil Futures & Options Editor
New York - May 29, 2014
U.S. gasoline stocks fell 1.8 million barrels to 211.58 million barrels during the reporting week ended May 23, U.S. Energy Information Administration (EIA) data showed Thursday.
The larger-than-expected draw comes in the wake of Memorial Day demand in the U.S. and sent New York Mercantile Exchange (NYMEX) June RBOB more than 2 cents higher to around $3.026 per gallon shortly after the data was released.
Analysts surveyed Tuesday had been expecting a draw closer to 200,000 barrels.
EIA data showed implied demand* for gasoline rose 136,000 barrels per day (b/d) to 9.31 million b/d the week ended May 23, putting it nearly 4% above the five-year average.
On a four-week moving average, demand is up 155,000 b/d to 9.1 million b/d, nearly 466,000 b/d higher than a year ago.
"A lot of gas went on the rack to meet strong Memorial Day weekend demand," Price Futures Group analyst Phil Flynn said.
Sharp draws in the U.S. Midwest and U.S. Gulf Coast (USGC) seemed to trump a bearish 2.47 million-barrel build in U.S. Atlantic Coast (USAC) gasoline stocks, which rose to 59.24 million barrels. The USAC is home to the New York Harbor-delivered NYMEX RBOB contract.
U.S. Midwest stocks fell 2.05 million barrels to 47.18 million barrels, and USGC stocks dropped 1.43 million barrels to 72.92 million barrels.
RBOB futures have rallied since mid-day Wednesday after a tornado damaged a crude oil unit at Marathon's 490,000 b/d Garyville, Louisiana, refinery and an unspecified mechanical breakdown occurred late Tuesday at ExxonMobil's 238,000 b/d Joliet, Illinois, refinery.
The outages come amid seasonal turnarounds at both the 600,000 b/d Saudi Aramco/Shell joint venture Motiva refinery in Port Arthur, Texas, and ExxonMobil's 502,500 b/d Baton Rouge, Louisiana, refinery. Despite the obvious bullish effect on futures, these outages will only be reflected in next week's data release.
EIA data showed U.S. gasoline production surged 229,000 b/d to 10.55 million b/d the week ended May 23. While USAC production edged 19,000 b/d lower to 3.23 million b/d, USGC gasoline production jumped 200,000 b/d to 2.34 million b/d.
USAC gasoline imports were down 293,000 b/d to 686,000 b/d. But a four-week moving average showed imports around 766,000 b/d, the highest since the week ended August 31, 2012.
This time last year, USAC imports on a four-week moving average were around 630,000 b/d.
U.S. distillate stocks were down 196,000 barrels to 116.08 million barrels, counter to analysts' estimates of a 290,000 barrel build. The draw was likely aided by sharply higher demand.
Implied demand for distillates soared 410,000 b/d to 4.2 million b/d the week ended May 23, EIA data showed.
Ultra-low sulfur diesel stocks on the USGC fell 1.62 million barrels to 30.15 million barrels.
U.S. CRUDE OIL STOCKS UP 1.66 MILLION BARRELS
U.S. commercial crude oil stocks rose 1.66 million barrels to 392.95 million barrels the week ended May 23, largely in line with analysts' expectations.
USGC stocks rose 3.14 million barrels to 213.13 million barrels as crude oil runs in the region dropped 138,000 b/d to 8.13 million b/d, and imports rebounded 1.08 million b/d to 3.92 million b/d.
This helped to drive total U.S. crude oil imports 1.34 million b/d higher to 7.81 million b/d.
Imports from Saudi Arabia were up 419,000 b/d to 1.59 million b/d, while those from Venezuela rose 255,000 b/d to 853,000 b/d. Colombian imports rose 211,000 b/d to 402,000 b/d.
Imports from Nigeria rose 192,000 b/d to 210,000 b/d, but imports from Angola fell 81,000 b/d to 151,000 b/d.
And while crude oil runs in the USGC were sharply lower, gross inputs, which include feedstocks other than crude oil, actually rose 146,000 b/d to 8.23 million b/d.
This boosted run rates in the region by 1.6 percentage points to 89.9% of capacity.
Total U.S. refinery utilization rates rose 1.2 percentage points to 89.9% of capacity, about double analysts' expectations.
Stocks at Cushing, Oklahoma -- delivery point for the NYMEX crude oil futures contract -- fell 1.53 million barrels to 21.69 million barrels the week ended May 23
* Implied demand is the amount of product that moves through the U.S. distribution system, not actual end consumption.
# # #
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 180 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.
By Mark Shenk May 30, 2014 3:55 AM GMT+0700
OPEC crude production climbed in May for the first time in three months, led by gains in Angola and Saudi Arabia, a Bloomberg survey showed.
Output from the 12-member Organization of Petroleum Exporting Countries rose by 75,000 barrels a day to an average 29.988 million, according to the survey of oil companies, producers and analysts. Last month’s total was revised 50,000 barrels a day higher to 29.913 million because of changes to the Saudi Arabian and United Arab Emirates estimates.
Members increased production as the International Energy Agency projected further increases will be needed to meet demand during the second half of the year. The IEA said in a May 15 report that OPEC will need to provide an average of 30.7 million barrels a day in the last six months of 2014.
“There’s still room for OPEC production to increase further,” said Sarah Emerson, managing principal of ESAI Energy Inc. in Wakefield, Massachusetts. “Both the IEA and OPEC said this month that there’s a need for additional barrels.”
Brent crude for July settlement advanced 16 cents to close at $109.97 a barrel today on the London-based ICE Futures Europe exchange. Brent is the benchmark grade for more than half the world’s oil.
West Texas Intermediate crude for July delivery increased 86 cents, or 0.8 percent, to settle at $103.58 a barrel on the New York Mercantile Exchange.
Angolan output increased by 140,000 barrels a day to 1.68 million, the biggest gain for any member in May. Production climbed because of the end of maintenance at the Greater Plutonio offshore field operated by BP Plc.
Saudi Gain
Saudi Arabia, the group’s biggest producer, bolstered output by 70,000 barrels a day to 9.67 million, the first gain this year. The country pumped 10 million barrels a day in September, the most in monthly data going back to 1989. Local crude burning is ramped up as temperatures rose in the desert kingdom this month.
Iranian production declined 90,000 barrels a day to 2.75 million this month, the biggest decline in the survey. The nation pumped more than 3.1 million barrels a day from 1991 until July 2012, when additional sanctions were imposed on the Islamic republic. Iran, the group’s second-biggest producer in June 2012, is now in fourth place.
Nigeria’s production fell 70,000 barrels a day to 1.95 million in May, the second-biggest decrease in the survey. Royal Dutch Shell Plc lifted a force majeure on Forcados crude exports on May 15 after removal of theft points, according to e-mailed statement. Force majeure is a legal step that protects a company from liability when it can’t fulfill a contract for reasons beyond its control.
Libyan Slump
Libyan output fell by 35,000 barrels a day to 180,000, the lowest level since September 2011. Production this month was down 87 percent from a year earlier. The North African country’s pumped 1.59 million in January 2011 before the uprising that led to former leader Muammar Qaddafi’s ouster and subsequent killing that year.
“If there is an improvement in Libya or Iran, everything changes for OPEC,” Emerson said. “Members will be looking to cut output, not increasing it, in the second half of the year.”
OPEC ministers kept their output target unchanged at 30 million barrels a day on Dec. 4. The group will next meet on June 11 in Vienna.
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 Bill Banker
By Christine Harvey May 30, 2014 2:55 AM GMT+0700
Gasoline futures climbed in New York after a tornado-damaged Louisiana refinery shut a crude unit and a government report showed U.S. inventories tumbled.
Prices rose 0.3 percent. Marathon Petroleum Corp. (MPC)’s Garyville, Louisiana, plant, the nation’s third-largest, suffered damage to a cooling tower and shut a crude unit following yesterday’s tornado. Motor fuel stockpiles fell 1.8 million barrels to 211.6 million in the week ended May 23, Energy Information Administration data showed today.
“The Garyville issue is significant because it’s one of the largest refineries in the country and there’s still no indication of how long it’s going to be down,” said Jim Ritterbusch, president of Ritterbusch & Associates LLC in Galena, Illinois. “The market tends to price in a worst-case scenario.”
Gasoline for June delivery gained 0.77 cent to settle at $3.0136 a gallon on the New York Mercantile Exchange. Volume was 22 percent above the 100-day average at 3:15 p.m. The more actively traded July contract advanced 0.77 cent to $2.9958. June contracts expire tomorrow.
Production of the motor fuel at U.S. refineries dropped 66,000 barrels a day to 9.5 million last week, a second consecutive weekly decline, according to the EIA, the Energy Department’s statistical unit. Gasoline demand as measured by finished product supplied climbed 155,000 barrels a day to 9.1 million in the four weeks ended May 23, the highest level since Aug. 30.
Refinery Work
Marathon expects to keep the crude unit at the Garyville refinery shut while it carries out repairs to the damaged cooling tower, the company said yesterday in an e-mail.
That adds to a list of maintenance projects under way at U.S. Gulf Coast and East Coast plants. PBF Energy Inc.’s Delaware City, Delaware, refinery began work on several units May 27, while Exxon Mobil Corp. conducts crude unit repairs in Chalmette, Louisiana, and Beaumont, Texas.
Alon USA Energy Inc.’s Big Spring, Texas, site this month shut a crude unit and fluid catalytic cracker for a turnaround. The work is expected to be completed in mid-June.
The average U.S. pump price gained 0.1 cent to $3.651 a gallon yesterday, according to Heathrow, Florida-based AAA. That’s 3 cents higher than a year ago.
Ultra low sulfur diesel for June delivery dropped 1.16 cents to $2.919 a gallon. Volume was 19 percent below the 100-day average. Distillate stockpiles slid 196,000 barrels to 116.1 million, the EIA said.
To contact the reporter on this story: Christine Harvey in New York at charvey32@bloomberg.net
To contact the editors responsible for this story: Dan Stets at dstets@bloomberg.net Charlotte Porter, Richard Stubbe
By Rakteem Katakey and Debjit Chakraborty May 30, 2014 1:30 AM GMT+0700
Oil & Natural Gas Corp. (ONGC), India’s biggest energy explorer, reported its steepest increase in profit in seven quarters after writedowns from dry wells fell and a lower rupee countered discounts on crude oil sales.
Net income in the fiscal fourth quarter ended March 31 rose 44 percent to 48.9 billion rupees ($829 million), or 5.71 rupees a share, compared with 33.9 billion rupees, or 3.96 rupees, a year earlier, the New Delhi-based company said in a stock exchange filing yesterday. That missed the 54.8 billion-rupee median profit estimate of 27 analysts surveyed by Bloomberg. Sales fell 2.3 percent to 209 billion rupees.
The discounts ONGC gives to state-run refiners are eroding its cash pile and risking cuts in its 11 trillion-rupee spending plan on oil fields and overseas acquisitions by 2030. The explorer is mandated by India’s federal government to partly compensate Indian Oil Corp. (IOCL) and other state-run refiners, which sell fuel below cost to help curb inflation in a nation where more than 800 million people earn less than $2 a day.
The rupee’s depreciation and lower writedowns from the drilling of unsuccessful exploration wells helped boost profit, A.K. Banerjee, ONGC’s director finance said at a press conference in New Delhi yesterday. The company wrote off 19.06 billion rupees during the quarter for dry wells, compared with 41.27 billion rupees a year earlier, he said.
ONGC fell 2.6 percent to 374.15 rupees in Mumbai yesterday. The stock has increased 30 percent this year compared with a 14 percent gain in the benchmark S&P BSE Sensex (SENSEX) index. The results were released after the close of trading.
Dollar Billing
The rupee averaged 61.79 in the quarter compared with 54.17 against the dollar a year earlier. ONGC bills its customers in dollars and its selling price increases when the money is converted into rupees. The currency has increased 1.5 percent since the beginning of this quarter.
“It’s the rupee supporting earnings,” said Dhaval Joshi, a Mumbai-based analyst at Emkay Global Financial Services Ltd. “The fall helped ONGC make up for the higher subsidy it had to bear.”
The explorer’s discounts on crude oil sales to state refiners increased 32 percent to 162 billion rupees in the quarter compared with 123.1 billion a year earlier, according to the statement. This reduced net income by 91.2 billion rupees, ONGC said.
Brent oil in London trading, a benchmark price for more than half the world’s oil, averaged $107.87 a barrel in the three months ended Dec. 31, 4.2 percent lower than a year earlier.
To contact the reporters on this story: Rakteem Katakey in New Delhi at rkatakey@bloomberg.net; Debjit Chakraborty in New Delhi at dchakrabor10@bloomberg.net
To contact the editors responsible for this story: Jason Rogers at jrogers73@bloomberg.net; Pratish Narayanan at pnarayanan9@bloomberg.net Abhay Singh, Dick Schumacher
By Derek Wallbank and Nathan Crooks May 29, 2014 9:08 PM GMT+0700
U.S. House lawmakers voted to require sanctions against Venezuelan officials involved in a crackdown against protesters and opposition leaders in that country.
The measure passed by voice vote yesterday in Washington.
The legislation is intended to “hold these human rights violators accountable,” said bill sponsor Representative Ileana Ros-Lehtinen, a Florida Republican. “The first step in doing so is hitting them in their pocketbooks and denying them entry into the United States.”
Venezuela has cracked down on protests that started in February over the world’s fastest inflation, crime and shortages of staples such as food and toilet paper. At least 42 people have been killed in the demonstrations.
Amnesty International said April 1 it had received dozens of accounts of torture allegedly carried out by security forces since the protests began.
The U.S. State Department has so far resisted calls from Congress for sanctions against Venezuelan President Nicolas Maduro’s government.
“Any law approved by U.S. Congress to sanction Venezuela is illegitimate and we won’t recognize it,” Maduro said May 27 on his weekly radio show broadcast on state television. “We reject it, and we’ll fight it around the world.”
U.S. Secretary of State John Kerry said May 21 that all options for Venezuela “remain on the table at this time” though “our hope is that sanctions won’t be necessary.”
Freezing Assets
That resistance hasn’t stopped U.S. lawmakers.
The House bill would direct the U.S. to identify Venezuelan human-rights abusers and impose sanctions on them. In addition to denying them entry to the county, sanctions would include freezing their assets held in the U.S. or held by American entities.
The measure also would sanction those who provide Venezuela with firearms, ammunition and less-lethal munitions like rubber bullets, pepper spray and tear gas, as well as surveillance technology.
New York Democrat Gregory Meeks was the only representative to speak against the bill during debate on the House floor.
“I believe unilateral action by the U.S. is not the answer,” Meeks said. The measure is an “unfortunate reminder of U.S. arrogance in the Western Hemisphere,” he said, and approving sanctions without support and similar actions from regional allies would be a “costly mistake.”
Opposition Talks
Caracas mayor and Venezuelan ruling party leader Jorge Rodriguez, speaking on state television, accused U.S. Ambassador to Colombia Kevin Whitaker of working with opposition politicians to support the protests. A State Department official said in an e-mail that the allegation was false. The official responded on condition of anonymity.
Venezuela’s opposition coalition on May 13 said that it suspended talks with the government and said Maduro was not seriously considering its proposals. Two sessions of talks were held last month and mediated by the Roman Catholic Church and the foreign ministers of Brazil, Colombia and Ecuador.
Among other demands, the opposition is pushing for the release of political prisoners and jailed protesters including opposition leader Leopoldo Lopez, who was arrested in February after the government accused him of inciting protests.
Annual Inflation
Annual inflation in Venezuela, which has the world’s largest oil reserves, hit 59 percent in March, with prices rising the most in four months, after the government carried out the biggest devaluation since currency controls were instituted in 2003.
The central bank hasn’t provided data on product scarcity since January, when it said 28 percent of basic goods were out of stock at any given time. Venezuela’s economy grew 1.3 percent in 2013, down from 5.6 percent in 2012.
The House vote followed last week’s approval by the U.S. Senate Foreign Relations Committee of a separate sanctions measure. It would apply to Venezuelan government officials involved with violence and human-rights abuses, including anyone who ordered arrests of opposition protesters for their beliefs.
The vote was 13-2, and the bill is unlikely to advance to the Senate floor, Eurasia Group said in an e-mailed note to clients May 27.
“The debate will likely only pick up steam if massive protests do erupt and levels of violence lead to hundreds or even thousands of deaths and Venezuela becomes a permanent fixture in the domestic news media,” Eurasia Group analyst Risa Grais-Targow said.
The House bill is H.R. 4587. The Senate measure is S. 2142.
To contact the reporters on this story: Derek Wallbank in Washington at dwallbank@bloomberg.net; Nathan Crooks in Caracas at ncrooks@bloomberg.net
To contact the editors responsible for this story: Jodi Schneider at jschneider50@bloomberg.net
By Juan Pablo Spinetto May 30, 2014 6:01 AM GMT+0700
Oleo e Gas Participacoes SA, the oil startup that triggered Eike Batista’s financial collapse, will emerge as a viable producer once creditors approve a recovery plan at a meeting scheduled for next week, Chief Executive Officer Paulo Narcelio said.
OGpar, as the Rio de Janeiro-based company is know, will eliminate most of its debt and recover financing capacity as it generates about $500 million in sales this year, enough to sustain operations, Narcelio said in an interview at the company’s headquarters today. OGpar expects to produce an average 16,000 barrels a day for 12 months after connecting two extra wells to its Tubarao Martelo deposit by July, he said.
“We have a combination of resources that leave us comfortable in the coming months,” Narcelio, 51, said. “Operationally, the company’s going very well.”
OGpar is attempting to reinvent itself as a much smaller version of the vision Batista marketed to investors in a 2008 stock listing. The former speed-boat racer planned to create Brazil’s second-biggest oil producer and rise to the top of global wealth rankings by tapping deposits state-run Petroleo Brasileiro SA had overlooked for decades.
Instead, the company abandoned most of its offshore fields and failed to generate enough income to service debt, including $3.6 billion in international bonds, culminating in a bankruptcy protection filing in October. Creditors including Pacific Investment Management Co. will discuss a revised plan to guide the company out of the bankruptcy process at a June 3 meeting in Rio.
Weighing Pre-Sales
OGpar is considering options to generate new income, including selling oil production in advance or finding partners for its blocks, Narcelio said during the interview. It also has the proceeds from the sale of assets including natural gas operations and Colombian exploration blocks.
Creditors probably will approve OGpar’s proposal to exit the bankruptcy protection process after next week’s meeting, Narcelio said.
“The alternative of not approving the plan would be to liquidate the company,” he said. “That’s not a good alternative to anyone. It would be an irrational decision.”
Shares of OGpar rose 5.3 percent to 20 centavos in Sao Paulo today, reducing its decline in the past year to 87 percent. It’s market value is 647 million reais ($291 million).
OGpar’s management, Batista and creditors still need to resolve a so-called put option the entrepreneur pledged in 2012 when output at the company’s first oil project was fading.
Unresolved Put
In September the company requested payment of the $1 billion option. Batista refused, arguing it was set up for expansions not debt payments. Brazil’s securities regulator CVM is investigating the original agreement, and minority investors have complained about it at shareholders meetings.
“The put is still to be resolved,” Narcelio said. “The board will review this and eventually send a decision, whatever that is, to a shareholders assembly.”
He declined to comment on the likelihood of Batista paying part or all of the option.
To contact the reporter on this story: Juan Pablo Spinetto in Rio de Janeiro at jspinetto@bloomberg.net
To contact the editors responsible for this story: James Attwood at jattwood3@bloomberg.net Peter Millard
By Ann Koh and Fitri Wulandari May 30, 2014 7:40 AM GMT+0700
The ripples from Indonesia’s ban on mineral-ore exports are reaching energy markets, as shuttered mines and idle trucks crimp demand for diesel.
Profit from making the fuel in Singapore this year will be the lowest since 2011, Wood Mackenzie Ltd. says. Indonesia, Asia’s biggest importer of the fuel, will buy 20 percent less amid the contraction in mining following the ban in January, according to the Edinburgh-based consultant.
The forecasts show how Indonesia’s ban, designed to stimulate the domestic ore-processing industry, is having unintended consequences across the region. Weakening demand for diesel is coming at a time when China is exporting more fuel as its economy expands at the slowest pace in a quarter century.
“Less miners, less work going on, less trucks, so the diesel consumption would also be less,” Gavin Wendt, the founding director of MineLife Pty, a commodities researcher in Sydney, said by phone on May 23. “Mining accounts for a considerable portion of diesel consumption.”
Diesel in Singapore, the benchmark for Asian refiners, will average $17.40 a barrel more than Dubai crude this year, compared with $17.90 last year, said Suresh Sivanandam, a Singapore-based senior downstream analyst at Wood Mackenzie. The difference, known as the crack spread, was at $14.97 yesterday, the lowest level in more than a year, according to PVM Oil Associates Ltd. That’s a 23 percent drop from the four-month high of $19.36 reached in November.
Indonesia Halt
Diesel swaps are trading at about $121 a barrel in Singapore, Asia’s biggest oil-trading center, compared with last year’s average of $122.54, according to PVM data. Refiners in the region typically use Dubai crude as a benchmark for measuring profits from making fuels.
Indonesia banned exports of all mineral ores including nickel, iron and bauxite from Jan. 12 as part of a policy to boost revenue by turning the country into a manufacturer of higher-value products. The economy last quarter expanded at the slowest pace since 2009 as mining and quarrying contracted about 3.6 percent from the previous three months.
The curb halted shipments from companies such as Freeport-McMoRan Copper & Gold Inc. and Newmont Mining Corp. Nickel futures advanced 37 percent this year on the London Metal Exchange, compared with a 3.5 percent gain in the Standard & Poor’s GSCI Spot Index of 24 commodities.
Indonesia will cut overseas purchases of diesel to 92,000 barrels a day this year from 115,000 in 2013, according to Wood Mackenzie. The 23,000-barrel decline is equal to about 5 percent of the country’s consumption last year.
Oil Processing
Diesel producers such as Mumbai-based Reliance Industries Ltd., China Petroleum & Chemical Corp. and South Korea’s SK Innovation Co. may find more demand in Australia, where the shuttering of domestic oil processing is boosting imports.
“All of a sudden, all the diesel that would otherwise have gone into Indonesia would be looking for a home,” said MineLife’s Wendt. “We’ve refineries in Sydney and Melbourne that are in the process of closing because they can’t turn crude into fuel as cheaply as they can buy it.”
BP Plc will halt its Bulwer Island refinery in Queensland by mid-2015 and may convert it into a fuel-import terminal amid “insurmountable” competition, the company said April 2. Caltex plans to halt its Kurnell plant in the second half of this year while Royal Dutch Shell Plc has ceased processing at its Clyde facility in Sydney.
Diesel Importer
Australia, the Asia-Pacific region’s largest diesel importer, “could be a winner” if prices for the fuel decline, according to Wendt. The nation bought about 220,000 barrels a day last year, data from the Australian Bureau of Resources and Energy Economics show.
China is shipping more fuel overseas as it builds new refineries and industrial expansion cools. Exports of gasoil, or diesel, rose to 371,350 metric tons in January, the highest level in 10 months, according to government trade data.
The world’s second-biggest economy will increase refining capacity by about 6.5 percent this year to reach a total of 668 million tons, China National Petroleum Corp. estimated in January. That’s about 13.4 million barrels a day. The government is targeting 7.5 percent economic growth this year, which would be the lowest rate since 1990.
“In the last few months we’ve seen a huge amount of diesel coming from China and that’s kind of keeping the market jittery,” Wood Mackenzie’s Sivanandam said.
To contact the reporters on this story: Ann Koh in Singapore at akoh15@bloomberg.net; Fitri Wulandari in Jakarta at fwulandari@bloomberg.net
To contact the editors responsible for this story: Pratish Narayanan at pnarayanan9@bloomberg.net Yee Kai Pin
By Benjamin Haas May 30, 2014 12:44 AM GMT+0700
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China’s effort to catch up with the U.S. in developing shale gas and become more energy independent is coming at a big cost: It’s spending four times as much developing some fields, according to a new report.
Holding the world’s biggest potential reserves of natural gas in shale rock, China will spend billions of dollars in trying to close a gap with the shale leader, which is about a decade ahead in developing the energy resource, according to a study by Bloomberg New Energy Finance released yesterday.
The emergence of shale projects in Asia and Europe affects global gas and oil prices and is changing the energy agendas of governments from London to Beijing. In China, leaders mandated national targets for their producers such as state-owned China Petroleum & Chemical Corp. (386), known as Sinopec.
“For the government, shale is one of the highest priorities, and Sinopec is looking to distinguish itself by making gains in shale,” Xiaolei Cao, an analyst at Bloomberg New Energy Finance, said in an interview.
Sinopec’s estimate that it will spend an average of $10 million per well at its Fuling site compares with costs as low as $2.6 million a well in parts of the U.S., BNEF said.
The chasm will narrow going forward. Sinopec’s drilling costs will fall as it ramps up production to meet the government’s target of 6.5 billion cubic meters a year by 2015. Analysts say that goal is increasingly within reach after massive investments by China and overcoming technological hurdles.
Cost Reductions
“By reducing costs, Sinopec will be able to produce more gas and those economies of scale will further bring down its expenditure,” Cao said.
In contrast to China’s target of 6.5 billion cubic meters, the U.S. produced almost 300 billion in 2012, the last year data is available, according to the Energy Information Administration.
Two calls to Lv Dapeng, Sinopec’s Beijing-based spokesman, were unanswered.
Sinopec has made progress reducing its costs at Fuling in the past two years, BNEF said. It could even be cheaper than a landmark $400 billion deal China signed with Russia earlier this month, depending on the amount a well produces, according to the report.
PetroChina Co. in 2012 produced 74 percent of the nation’s natural gas, while Sinopec’s share was about 16 percent, according to the two companies’ annual reports of gas production, which was almost entirely conventional and tight gas.
Air Quality
In keeping with its goals to improve air quality, China plans to increase gas consumption to 9 percent of its total energy demand by 2017, up from 5.2 percent in 2013, and hold coal consumption to below 65 percent, according to a statement from China’s National Development and Reform Commission on May 16.
Beyond its 2015 target, China aims to produce between 60 billion to 100 billion cubic meters of shale gas by 2020. While next year’s goal now seems within reach, analysts say they are still skeptical about such a rapid development in shale.
The 2020 target “still looks quite ambitious,” Charles Blanchard, head of gas research for BNEF, said in a statement. “Costs must continue to fall and greater competition, at least in the upstream, will be required.”
China holds the world’s largest reserves at 25.08 trillion cubic meters of exploitable onshore shale gas, the country’s Land and Resources Ministry said in March 2012. The U.S. has 13.65 trillion cubic meters of technically recoverable gas from shale formations, its Energy Information Administration said in January that year.
To contact the reporter on this story: Benjamin Haas in Hong Kong at bhaas7@bloomberg.net
To contact the editors responsible for this story: Jason Rogers at jrogers73@bloomberg.net Alex Devine, Joshua Fellman
By Jeremy van Loon May 30, 2014 6:00 AM GMT+0700
Total SA (FP) will cut 150 jobs at its Joslyn oil-sands mine in Canada and delay a final investment decision as costs escalate and the company and partner Suncor Energy Inc. (SU) look for ways to make the project more profitable.
“We just need to find ways to go further in cost effectiveness,” Andre Goffart, the president of Total’s Canadian business, said on a conference call yesterday. Oil-sands mining projects including the C$11 billion ($10.1 billion) Joslyn venture are “very capital intensive projects.”
Oil-sands miners have struggled with rising costs in northern Alberta because of labor shortages and distance from equipment suppliers. Imperial Oil Ltd. (IMO), the Calgary-based producer majority owned by Exxon Mobil Corp., last year boosted the cost of its Kearl project by 18 percent.
Total, France’s largest oil producer, and Suncor last year canceled their Voyageur upgrader because of rising costs. The partners in October announced they would go ahead with a C$13.5 billion Fort Hills venture that will produce 180,000 barrels a day within 12 months of startup in 2017.
Goffart declined to provide a timeline for a final decision on the project, where cost-reduction efforts will continue, he said on the call. The company will try to find positions for the employees affected by the decision, he said.
Total has no plans to sell its stake in the project, Goffart said. Work at the company’s other oil-sands sites, including the Surmont assets, will continue as planned, he added.
Total, based in Paris, purchased its oil-sands stakes in 2010. The shares declined 0.2 percent yesterday to 51.72 euros in Paris. Calgary-based Suncor fell 0.4 percent to C$41.71 in Toronto.
To contact the reporter on this story: Jeremy van Loon in Calgary at jvanloon@bloomberg.net
To contact the editors responsible for this story: Tina Davis at tinadavis@bloomberg.net Carlos Caminada, Steven Frank
By Brian Baskin
NEW YORK--Natural-gas futures sank after government data showed the biggest increase in supplies this year.
Producers added 114 billion cubic feet of gas to storage for the week ended May 23, according to the U.S. Energy Information Administration. The average forecast was for an addition of 110 bcf in a Wall Street Journal survey.
Even so, gas inventories remain 40% below the five-year average for this time of year, the EIA said. Total stockpiles stood at 1.38 trillion cubic feet.
Natural gas for July delivery recently traded down 1.1% at $4.565 a million British thermal units on the New York Mercantile Exchange. Before the data, gas traded at $4.653.
Write to Brian Baskin at brian.baskin@wsj.com
U.S. natural gas production in 2013 hit 24.2 trillion cubic feet, which would be a new record if preliminary data are correct.
By Daniel J. Graeber | May 29, 2014 at 10:45 AM | 0 Comments (Leave a comment)
http://cdn.ph.upi.com/sv/b/upi/UPI-8311401374113/2014/1/882673f4cdefc984d6203bff7834aca3/US-gas-imports-declining-steadily.jpg
WASHINGTON, May 29 (UPI) --The amount of natural gas imported into the U.S. market dropped 14 percent last year in part because of abundant domestic resources, the Energy Department said.
The Energy Information Administration, the statistical arm of the Energy Department, said natural gas production in 2013 hit 24.2 trillion cubic feet, which would be a new record if preliminary data are correct.
EIA said in its report net imports declined in part as a response to increases in domestic production. The level of natural gas imports have declined every year since 2007, the report said, and is at its lowest level since 1989.
In a separate monthly report, EIA said the United States imported 542 billion cubic feet of natural gas for the first two months of 2014, which is actually 5 percent more than the same period last year. Total natural gas exports for the two-month period were down nearly 7 percent year-on-year.
The annual report, published Wednesday, said 97 percent of all U.S. natural gas imports come through pipelines from Canada. Last year, Canadian natural gas imports declined overall by 6 percent.
The U.S. gets a minimal amount of gas sent through pipelines from Mexico.
© 2014 United Press International, Inc. All Rights Reserved. Any reproduction, republication, redistribution and/or modification of any UPI content is expressly prohibited without UPI's prior written consent.
PIRA Energy Group analysis of oil market fundamentals for the week ending 25 May revealed the following:
USA
Tighter global oil markets will send third quarter crude oil prices into a new, higher trading range for Brent.
Low inventories and increased and increased global supply disruptions have supported prices despite a larger than expected second quarter stock build.
Ethanol
Ethanol prices increased near the end of the week as the market in the Midwest tightened.
Manufacture of ethanol-blended gasoline reached an all time high, while PADD II stocks fell to the lowest level of the year.
Ethanol production rose in the week ending 16 May, reaching 925 million bpd for only the second time this year. However, total US inventories drew 312 000 bbls to a four week low of 16.99 million bbls.
Q1 results
Four themes emerged in the first quarter results:
Operators indicated that 2014 production would be weighted to the second half of the year as harsh winter weather continued well into Q1 2014.
In the Permian, drilling activity increased rapidly despite the weather, resulting in some service cost inflation.
In Bakken and Eagle Ford, operators are still focused on increasing acreage productivity, with emphasis on downspacing and completion designs.
A number of operators divided their attention between the three bug plays and emerging plays.
Bullish for US prices
June Saudi loading delays and reduced operational tolerances should continue to be bullish for US prices. Lower freight rates have opened the arb to Europe and Asia encouraging increased exports. Continuing stock build should erode the year on year deficit in US LPG stocks.
Adapted from a press release by Emma McAleavey.
By Nick Cunningham | Thu, 29 May 2014 22:14 | 0
Although serious obstacles remain, China is finally making progress on tapping its vast shale gas reserves, which hold the promise of a new source of clean energy for the coal smoke-choked country.
According to the U.S. Energy Information Administration, China holds the world’s largest reserves of technically recoverable shale gas in the world, 1,115 trillion cubic feet. That’s about 68 percent more than what the U.S. holds.
But it has thus far been unable to unlock those reserves for a couple of reasons. First, it has taken time for Chinese oil and gas companies to acquire shale drilling expertise. And second, China’s shale is geologically different than what’s found in the U.S., which means China can’t easily use existing technology.
Despite this, a new report from Bloomberg New Energy Finance finds that China may actually hit its 2015 shale gas production target, which the central government has mandated. Researchers analyzed the results of well data from the Fuling block in the Sichuan Basin, state-owned firm Sinopec is making substantial progress, and the national target of 6.5 billion cubic meters per year (480 million cubic feet per day) by 2015 could be within reach.
Hitting that goal would be a boon for a country that is desperate to find sources of energy other than coal, which is causing crisis-level air pollution. Earlier this year, China declared a “war on pollution” in an effort to cut back on the suffocating smog in many of its major cities. By 2017, China is aiming to lift natural gas consumption to 9 percent of total energy demand, up from 5.2 percent in 2013. China has already made some progress on that front, as natural gas only made up 4 percent of energy demand just two years ago (see chart).
https://oilprice.com/images/tinymce/James%209/AE3252.jpg
To be sure, China’s shale gas industry is still in its infancy. Although Sinopec has been able to boost production, it has come at a high cost. The average cost to drill a Chinese shale well this year is around $11 to $13 million. That far exceeds U.S. figures: $9.3 million per well in the Haynesville, $6 million in the Marcellus, $3.3 million in the Barnett, and $2.6 million in the Fayetteville shale.
On the brighter side, China has brought down costs as it gains experience. So while the current cost of drilling each well is still high, it’s down from the $16 million average in 2012. Drillers are aiming to further slash costs to $10 million per well for 2014. And as the industry scales up and gains more experience, costs should decline further.
Coming on the heels of a massive $400 billion natural gas deal with Russia, news that China may be making serious progress in shale development suggests that China could be at a turning point. China has long been a voracious consumer of all commodities – except, notably, natural gas – so it could be on the verge of charting a future path that relies very heavily on natural gas.
And developing shale gas into a serious source of supply would give it greater leverage over LNG pricing. The deal with Russia will secure natural gas at a price of around $10 per million
Btu (MMBtu) – although exact figures have been kept a secret. That alone could make LNG pricing more competitive in Asia, bringing prices down from the highs of $16 to $18/MMBtu seen in the last few years. But if China can also develop shale gas in a meaningful way, it will have much greater influence at the bargaining table over LNG supplies.
That is what China is hoping for anyway, but very large obstacles stand in the way. Lack of infrastructure, distorted pricing, and water scarcity are just a few of the enormous challenges holding back the Chinese shale industry. But the Chinese government and its state-owned exploration companies are determined to turn it into a reality.
By Nick Cunningham of Oilprice.com
By James Stafford | Thu, 29 May 2014 21:46 | 0
As the Canadian government pushes a new law rendering pipeline companies liable for all damages from leaks and spills, the only friend to both sides in this polarized world of dirty oil sands is leak prevention technology.
On May 14, amid heightened opposition to two planned pipelines, Canada’s Natural Resources Ministry unveiled a new law making pipeline operators liable for all the costs and damages related to oil spills, regardless of whether the operators were at fault or demonstrated negligence.
Under the new law, pipeline operators will be required to set up advance clean-up funds for future spills, while the Canadian National Energy board will be given the authority to order operators to reimburse those affected by spills.
Canada desperately needs more pipeline infrastructure to handle its increasing oil sands production capacity, but opposition has been growing exponentially to Enbridge’s Northern Gateway project and Kinder Morgan’s Trans Mountain pipeline expansion.
The Northern Gateway pipeline would mean an additional 525,000 barrels per day of crude piped from Alberta to the coast of British Columbia, while the Trans Mountain expansion would mean a tripling to 900,000 barrels per day of oil sands crude from Alberta to Vancouver.
According to the Tar Sands Solution Network, “tar sands oil is more corrosive and transported at higher pressures,” while “spills of tar sands crude are significantly more toxic and harder to clean up.”
In fact, according to the organization, “Alberta has seen 28,666 crude oil spills since 1975, an average of two per day.”
What oil sands opponents fear most is the rapid expansion of production capacity that is necessitating the creation of more pipeline networks and oil tankers threatening spills across North America.
In addition to this, new research by the Canadian government alleges that toxic chemicals from Alberta’s oil sands tailing ponds are leaking into groundwater and making their way into the Athabasca River.
The latest study used million-dollar technology that allows scientists to fingerprint chemicals and trace their origins. This has been a sticking point until now because the soil around these Alberta tailing ponds contained chemicals from naturally occurring bitumen deposits, and earlier technology was not capable of separating them from the industry chemicals.
The industry in Canada is reportedly addressing the issue of toxic seepage from its tailing ponds by footing the bill for more than $1 billion in new technology.
At the same time, investments in the latest leak detection technology may also be hastened by mounting opposition to pipeline development and new Canadian legislation that makes prevention much cheaper than clean-up.
Earlier this month, Synodon Inc., the creator of realSens leak detection technology, successfully demonstrated its oil sands applications by detecting hydrocarbon vapor plumes released from a synthetic crude oil product.
In doing so, the new technology also demonstrated its ability to detect very small oil sands leaks, long before they become catastrophic.
“We are very pleased to have had the opportunity to demonstrate to a third-party oil sands operator our ability to detect very small release rates from a low volatility crude oil product,” Adrian Banica, CEO of Synodon Inc, said in a press release. “As far as we are aware, Synodon has the only commercially available airborne liquid hydrocarbon leak detection system in the world that has been proven to be capable of detecting both gaseous hydrocarbons as well as a wide variety of liquid products from pentane to gasoline, condensates and crude oil."
RealSens technology was developed under the Canadian Space Program and by Synodon scientists.
Canada’s new pipeline infrastructure is about to become much more expensive as legislative changes focus on prevention, liability and preparedness.
Without this legislation, new technology, such as that used in the latest study on tailing pond seepage into water supplies, and pipeline leak detection advances, may have seemed prohibitively expensive to operators. However, with the specter of footing to bill for any and all spills, regardless of operator negligence, preventative technology suddenly seems rather cheap.
By James Stafford of Oilprice.com
By Daniel J. Graeber | Thu, 29 May 2014 21:29 | 0
Depending on whose talking, lifting the longstanding limits on U.S. crude exports would be a boon to the economy and a benefit to U.S. drivers, or it would increase U.S. reliance on imported oil and weaken America’s foreign policy strategy.
The U.S. government restricted crude oil exports in 1973 in response to an embargo from Arab members of OPEC. Now, with U.S. crude oil production increasing, the case is being made both for and against lifting the ban.
For the week ending May 23, the U.S. Energy Information Administration (EIA) said crude oil production averaged 8.4 million barrels per day (bpd), a 16 percent increase year-on-year.
A new report from consulting group IHS says that lifting the ban would push that output to 11.2 million bpd. That, in turn, would save the United States about $67 billion per year on oil imports and lead to lower prices for retail gasoline, it says.
"At present, the current policy is discouraging additional crude oil supplies from being brought to market, which actually makes gasoline prices higher than they otherwise would be," IHS said.
Their argument is that more oil on the global market would push the price of oil down. That, in turn, would push gasoline prices lower because a good deal of what consumers pay at the pump is linked directly to the price of oil.
The IHS findings are similar to a March report from the American Petroleum Institute (API), an energy-industry lobbying group. API's report found that lifting the ban could spur the U.S. economy to grow by as much as $38 billion in 2020.
Both groups, however, may be looking at only a narrow slice of the pie.
Those in the downstream sector, the part of the industry that deals with refining and distributing products like motor gasoline, argue that U.S. oil is already cheap and say it’s a better idea to export refined products in the current market rather than increasing crude exports.
For those looking at the U.S. energy sector from a foreign policy perspective, meanwhile, there is no separation of domestic issues from international affairs. A report from the Brookings Institution says energy is more of a strategic commodity than a pure market asset and points out that oil prices impact the Chinese economy as much as the U.S. economy, so it's not a zero-sum game.
In January, U.S. Senators Ed Markey (D-MA) and Robert Menendez (D-NJ) argued that there's a strong case for keeping the ban in place. "New crude exports would be inconsistent with current law and would increase reliance on imports," they said.
They said the U.S. economy is linked as strongly to foreign oil now as it was before the ban was enacted, in the 1970s. And indeed, the EIA’s report for the week ending May 23 showed that the United States imported 1.3 million bpd more oil than it did the previous week.
In early May, White House advisor John Podesta said the issue of crude oil exports was "under consideration."
So which side is right? As with every issue decided by Washington, the question of whether to lift or leave the export limit will likely be influenced more by politics than by pragmatism.
By Daniel J. Graeber of Oilprice.com
By Andy Tully | Thu, 29 May 2014 21:21 | 0
U.S. President Barack Obama is expected to announce a program that would cut emissions from his country’s coal-fired power plants by 20 percent nationwide and would lead to a cap-and-trade program in every state to pay for the right to pollute.
The plan was written by the U.S. Environmental Protection Agency and will be announced June 2 at the White House.
The new rules will be imposed by the president’s executive authority alone, not in legislation that would have to be passed by Congress, because it is sure to face fierce opposition from Republicans who control the House and have a strong presence in the Senate. The GOP has already accusing Obama of resorting to executive authority as a subterfuge merely to avoid democratic debate.
Coal plants are the nation’s largest source of the greenhouse gases that scientists say are the chief cause of global climate change. Cutting carbon emissions by 20 percent would be the toughest action ever taken by an American president to combat pollution, and Obama is said to view the program as a chief accomplishment of his two terms in office.
A key element of the president’s plan reportedly is to let every state develop its own plan to cut coal emissions. A state would have several options for achieving the reductions, including adopting efficient energy technology and adding alternatives, including wind and solar power.
One option also would be initiating a cap-and-trade program, which allows companies with high greenhouse gas emissions to buy emission allowances from companies with fewer emissions in an effort to reduce their combined impact on the environment.
Obama tried to win congressional approval of a cap-and-trade plan in 2010, but it never even came to a vote in the Senate. Democrats who supported such a program came under fierce attacks from mainstream Republicans and the party’s more conservative wing, the Tea Party.
Despite opposition in Congress, some states already are looking at ways to adopt their own cap-and-trade programs. Two successful state level cap-and-trade programs already exist. Both are associated not with liberal Democrats but with senior figures in the Republican Party: Mitt Romney, who challenged Obama for the presidency in 2012, and Arnold Schwarzenegger, the former governor of California.
Romney disowned his program during his presidential campaign. But when he was governor of Massachusetts, he was closely aligned with a leading state environmental official, Gina McCarthy, who is now head of the Environmental Protection Agency. McCarthy said the state-level rules will give each state “flexibility to develop plans on how to achieve those reductions in a way that’s economically beneficial to them.”
Some industries that rely on coal and are most likely to be affected by the plan don’t seem as opposed as Republicans.
“Carbon regulation creates challenges for us,” says John Brekke, the vice president of Great River Energy, an electricity cooperative based in Maple Grove, MN. But he says Great River Energy has decided to comply with the program, not oppose it. It plans to increase the cost of the power it generates to offset the pollution it generates. He added, “... [G]iven that it’s coming, we wanted to be involved in offering an idea in managing that regulation.”
By Andy Tully of Oilprice.com
By James Paton May 30, 2014 7:41 AM GMT+0700
Billionaire Li Ka-shing’s Cheung Kong Group agreed to acquire Envestra Ltd. (ENV) in a cash deal that values the Australian natural gas distributor at A$2.4 billion ($2.2 billion), beating a rival share offer from APA Group.
Envestra’s independent directors recommended the A$1.32 a share offer from a group including Cheung Kong Infrastructure Holdings Ltd. (1038), the Adelaide-based company said today in a statement. The bid, announced earlier this month, is in line with APA’s worth A$1.32 a share at yesterday’s close. Cheung Kong is the second-largest holder in Envestra and APA is the biggest holder, according to data compiled by Bloomberg.
At stake is Envestra’s 23,000 kilometers (14,000 miles) of pipelines that supply gas to customers, mostly in the states of Victoria and South Australia. It comes after Li almost doubled the size of his U.K. gas transmission business in 2012 with the 645 million pound ($1.1 billion) purchase of Wales & West Utilities Ltd. APA added to its networks in Australia with the purchase of Hastings Diversified Utilities Fund in 2012.
CKI’s representatives on the Envestra board, Dominic Chan and Ivan Chan, had recommended in March that holders vote against APA’s offer because it isn’t in their interests. CKI holds 17.5 percent of Envestra. APA Group’s pipelines deliver more than half of Australia’s natural gas.
Photographer: Lam Yik Fei/Bloomberg
Billionaire Li Ka-shing, chairman of Cheung Kong Holdings Ltd. and Hutchison Whampoa Ltd.
Under the APA deal that was scheduled to go to a vote this month, shareholders had the option of receiving either 0.1919 APA shares for each Envestra share, or a combination of stock and cash, APA said in December.
To contact the reporter on this story: James Paton in Sydney at jpaton4@bloomberg.net
To contact the editors responsible for this story: Jason Rogers at jrogers73@bloomberg.net Keith Gosman, Madelene Pearson
By Nick Cunningham, Guest blogger / May 29, 2014
Kurdish Regional Government President Masoud Barzani speaks during an interview with Reuters in Arbil, in Iraq's Kurdistan region, May 12, 2014. Kurdistan made its first shipment of oil to the international market, much to Baghdad's dismay.
In what could prove to be an historic turning point for Iraq, the government of Kurdistan – the semi-autonomous region in the country’s north – has delivered its first shipment of oil to the international market, in defiance of the central government in Baghdad.
The move could mark the beginning of greater geopolitical and economic power for Kurdistan and presage a move towards eventual independence.
It comes after years of political deadlock between Kurdistan and the government of Iraqi Prime Minister Nouri al-Maliki over how to manage and share the nation’s oil wealth. The Kurdish Regional Government (KRG) has always objected to political meddling from Baghdad, and has been charting its own path towards developing oil within its borders, an area estimated to hold 45 billion barrels.
The stage for a showdown was set in 2011, when the KRG signed a deal with ExxonMobil that offered much more generous terms than Baghdad offered in its own deals. The KRG went to sign deals with Chevron, Gazprom and Total.
Baghdad maintains that the deals are illegal. It wants any oil exported from Iraq to do so under the banner of the government-owned State Oil Marketing Organization (SOMO), which is charged with distributing all revenues to regional governments. Maliki’s government also wants oil exported from Kurdistan to travel through pipelines owned by the central government.
Kurdistan began doing this in 2009, sending oil to Ceyhan, a Turkish port on the Mediterranean. However, shipments were inconsistent and often interrupted, which the KRG says was caused by inadequate payment from Maliki’s government.
Fed up, Kurdistan built its own pipeline to Turkey in 2013 and began exporting oil in January of this year. But deliveries have been piling up in storage tanks in Ceyhan while the Turkish government delayed its export, awaiting negotiations between the KRG and Baghdad.
Ankara finally relented after months of little progress, and on May 23, the first oil tanker left Ceyhan carrying more than 1 million barrels of Kurdish crude to Europe. “This is the first of many such sales of oil exported through the newly constructed pipeline in the Kurdistan Region,” the Kurdish Ministry of Natural Resources said in a statement.
After the announcement, according to the AP, Iraq’s Oil Ministry filed an arbitration request with the Paris-based International Chamber of Commerce, accusing the Turkish government of assisting Kurdistan in carrying out the illegal sales.
The Iraqi government has long threatened to cut off Kurdistan’s share of national revenues if it began exporting on its own. Earlier this year, budget allocations to Kurdistan dried up; the KRG received just $1.3 billion out of the $4.25 billion it was expecting. Workers have gone unpaid as a result.
To make up the shortfall, Kurdish officials have set up a bank account in Turkey into which oil export revenues will be deposited. Those funds “will be treated as part of the KRG’s budgetary entitlement under Iraq’s revenue sharing and distribution, as defined under the 2005 Constitution of Iraq.” It’s another way Kurdistan is loosening the ties that bind it to Baghdad and moving toward self-sufficiency.
The situation is further complicated by the recent Iraqi election, which Maliki won but without the number of votes needed to form a government. He will have to haggle with other political factions to build a coalition government. If he puts together a Shia-dominated government and takes a hard line against the Kurds, it could push the KRG into taking a more aggressive approach to independence.
Alternatively, Maliki could offer concessions to gain Kurdish support for a coalition government, which could stave off a Kurdish push for independence, but would likely result in greater autonomy for Kurdistan to export its own oil.
Either way, Kurdistan is headed for greater independence from Baghdad.
