By UPI
NEW YORK, Oct. 21 (UPI) -- Brent and West Texas Intermediate for November delivery both showed gains in trading Tuesday, with Brent showing sustained growth from an earlier session.
Brent for November delivery was up 0.23 cents to trade at $85.63 in early Tuesday trading. That follows a lackluster close, but follows growth for the week ending Oct. 17. WTI, the U.S. benchmark, continued its rally to trade at $83.04 early Tuesday, up from $82.71 in the previous session.
Long-term contracts show WTI falling to around $80 per barrel, with Brent moving closer to the $90 per barrel mark.
The U.S. Energy Department's Energy Information Administration shows a national average price for a gallon of regular unleaded gasoline for the week beginning Oct. 20 at $3.12, down 24 cents from the same period in 2013.
Crude oil prices account for about 60 percent of the price at the pump.
Motor club AAA said in a weekly report, published Monday, that gasoline prices should remain lower because of the general sentiment that oil markets are in decline.
"This tumble has sent the national average to a low not seen since early 2011 and increased the likelihood that the national price at the pump could test the $3.00 per gallon mark for the first time since 2010," spokesman Avery Ash said in a statement.
By UPI
WASHINGTON, Oct. 21 (UPI) -- Better fuel efficiencies and a change in fuels used for home heating means most people are spending less on energy than before, the U.S. Energy Department said.
"Because electricity and transportation spending accounts for more than two-thirds of consumer energy expenditures, increasing vehicle fuel efficiencies and changing fuels used for home heating have contributed to lower consumer energy expenditures relative to disposable income," the department's Energy Information Administration said Tuesday.
Edmunds.com said the average new vehicle sold in January got 24.9 miles per gallon of gasoline, an increase of nearly 5 mpg from October 2007. The number of consumers using natural gas has increased more than 3 percent from 2007.
EIA said consumer energy expenditures as a percent of disposable income was lower last year than the average in the 1960s despite the rate of inflation.
The report found, however, that energy prices have been more volatile than overall prices for consumer goods.
By UPI
TEHRAN, Oct. 21 (UPI) -- The Iranian government should work to take oil revenue out of its total budget to protect the economy from market dynamics, a commissioner said Tuesday.
Hamid Farnam, the energy commissioner in the Iranian Chamber of Commerce, told the Oil Ministry's news website Shana the government should work to slowly push oil revenue out of the national budget.
"As long as we look at oil as a commodity for collecting revenues, not as a capital good, fluctuations in the world oil market will influence our economy," he said.
An assessment from the World Bank finds the Iranian economy is contracting. Sanctions imposed by Western powers on Iran's energy sector resulted in a 5.8 percent decline in gross domestic product last year.
The bank said the dependence on oil revenue makes the Iranian economy "intrinsically volatile."
Farnam said the government should work to cut the share of oil revenue in the total budget to nothing within a three- or four-year period.
Iran is limited by sanctions to around 1 million barrels of oil per day in exports. A bear market for oil prices leaves an Iranian economy exposed to short-term risks.
By UPI
BRUSSELS, Oct. 21 (UPI) -- The Russian government said Tuesday its representatives met separately with the European energy commissioner before talks about the Ukrainian gas crisis.
Russian Energy Minister Alexander Novak met one-on-one with European Energy Commissioner Gunther Oettinger ahead of three-way talks that include Ukrainian delegates. Novak said earlier Tuesday he expected the meeting would result in a written agreement on the way to settle the long-standing issue.
An already-fragile Ukrainian economy was left in further turmoil following the political upheaval that followed Kiev's tilt toward the European Union in November.
Russia meets about a quarter of European gas needs, though the bulk of that gas runs through a Ukrainian pipeline network. Last week, Oettinger said EU member states could stave off winter gas shortages.
"No household in the EU has to be left out in the cold this winter," he said.
Gazprom said Monday it filled European underground gas storage facilities with about 80 percent of the expected winter need.
Under the terms of a draft agreement reached last week in Milan, Ukraine gets a temporary discount on gas from Russia in exchange for a pledge to settle the majority of its debt to Gazprom by the end of the year.
By UPI
STAVANGER, Norway, Oct. 21 (UPI) -- Norwegian energy company Statoil said Tuesday it found at least 30 million barrels of oil in the Grane area in the Norwegian waters of the North Sea.
Statoil said the discovery in the so-called D-structure near the Grane field in the North Sea holds between 30 million and 80 million barrels of recoverable oil. The company said discoveries in the immediate area were struck in 1992, with an estimated reserve potential of 6 million barrels of oil.
The company said discoveries like Tuesday's are part of an effort to extend the life of existing basins on the Norwegian continental shelf.
Norway is a European leader in terms of oil and natural gas production.
The Norwegian government said average oil production in September was 1.47 million barrels of oil per day, 2.5 percent higher than expected and 10 percent above the production level for September 2013.
By UPI
DUBLIN, Ireland, Oct. 21 (UPI) -- The increase in exploration activity of the Irish coast shows the sector is moving in the right direction, Irish Natural Resources Minister Joe McHugh said.
Though considered frontier territory, the Irish government is hedging its bets on the reserve potential. In 2012, the government said, offshore reserves produced 14 billion cubic feet of natural gas and no oil.
McHugh said interest has increased significantly in recent years, with more seismic surveys conducted to get a better understanding of offshore reserve potential conducted in the last year than in the previous 10 years combined.
"All of this demonstrates that exploration in the Irish offshore is moving in the right direction," he said in a statement Monday. "What we are witnessing in our offshore is positive and there is a clear forward momentum."
Ireland imports all of its oil and relies in foreign sources for 90 percent of its natural gas needs.
McHugh said the government is seeing industry interest for a 2015 auction for offshore acreage, "which has the potential to build on the existing positive momentum and bring exploration activity to the type of levels whereby the true petroleum potential of the Irish offshore can be realized."
President Energy rides on oil find in Paraguay
By UPI
LONDON, Oct. 21 (UPI) -- Shares in British company President Energy continued their rally Tuesday after announcing the first ever oil discovery in Paraguay.
President Energy, trading on the London stock exchange under ticker symbol PPC, were up nearly 10 percent to $53.04, one day after share prices soared 76 percent on word it made the first oil discovery ever in Paraguay.
The London-based company said the discovery in the Lapacho well has commercial potential, with an estimated reserve base of approximately 200 million barrels of oil equivalent.
Company Chairman Peter Levine said in a statement announcing the discovery President has shown "beyond doubt" that oil exists in Paraguay.
"This discovery represents a significant milestone," he said Monday.
The discovery was made before drilling reached its target depth, suggesting the find may hold more reserves than expected.
The company said the first phase of production from the Lapacho well is expected to begin next year.
IHS examines Islamic State's oil wealth
By UPI
WASHINGTON, Oct. 21 (UPI) -- Oil is fueling the war chest for the group calling itself the Islamic State by more than $2 million per day, a study from consultant group IHS said.
A report from IHS Energy found IS, known also as the Islamic State in the Levant, is able to finance itself through a black market for oil.
"Oil fuels ISIL's war machine, notably including the military vehicles vital to its movements and fighting capabilities," analysis e-mailed Monday to UPI found. "Oil directly finances ISIL's myriad activities and encourages the activities of middlemen who sell, transport and export the oil and thus have a vested interest in ISIL."
IHS estimates the oil production controlled by IS is worth an estimated $800 million per year.
A U.S.-led air offensive against IS has targeted oil installations in Syria in an effort to cut off the group's source of revenue and fuel.
A recent report from the International Energy Agency found airstrikes were diminishing the terrorist group's ability to function and finance itself.
IHS estimates IS sells oil on the black market for an average $40 per barrel, roughly half the price on the global market.
By UPI
WASHINGTON, Oct. 21 (UPI) -- A report on the impacts of crude oil exports reinforces the industry view that trade barriers are curbing U.S. influence, the American Petroleum Institute said.
A report from the Government Accountability Office found consumer fuel prices would decline if authorities ended the 1970s ban on crude oil exports.
John Felmy, API's chief economist, said allowing free trade in the U.S. oil sector would have a ripple
"U.S. energy production is already having a major impact on world markets, and if policymakers embrace free trade, that influence will continue to grow in a way that benefits our economy," he said in a statement Monday.
U.S. refiners have expressed concern that easing the ban on crude oil exports would mean higher costs per barrel in the U.S. market. The GAO study found exports would raise domestic crude oil prices by as much as $8 per barrel.
In terms of consumer benefits, the report found domestic fuel prices would fall because those prices follow international market conditions.
The GAO report relied in part on recommendations from a September study from NERA Economic Consulting, which found that lifting the ban on crude oil exports doesn't eliminate foreign dependency.
By UPI
MOSCOW, Oct. 21 (UPI) -- Russian President Vladimir Putin issued a statement to the French government to offer his condolences over the death of Total chief Christophe de Margerie.
De Margerie, the chief executive of French oil company Total, died when a Falcon 50 business jet crashed after it hit a snow removal vehicle while taking off from a Moscow airport. Three other crew members, all French citizens, also died.
Russian authorities said the driver of the vehicle was drunk.
Putin sent a letter Tuesday to French President Francois Hollande to offer his respects.
"Please convey my sincerest condolences and sympathy to the family and friends of Christophe de Margerie - a prominent French businessman who pioneered many of the major joint projects, which laid the foundation for many years of fruitful cooperation between France and Russia in the energy sector," the letter read.
Total is working alongside Russian gas producer Novatek at the Yamal liquefied natural gas project in Russia, among others.
Putin's spokesman, Dmitry Peskov, said the Russian president had a close working relationship with 63-year-old de Margerie.
The French supermajor confirmed de Margerie's death in a Tuesday statement.
By Bloomberg
Trinidad & Tobago is substituting crude from Gabon with Colombian and Russian shipments amid protests by refinery workers alarmed by the outbreak of Ebola in other African countries.
Energy Minister Kevin Ramnarine halted oil purchases from Gabon, the Caribbean country’s only African supplier in the past 20 months, he said in an e-mailed response to questions.
The decision follows the refusal of workers from Petrotrin, which operates Trinidad’s sole refinery, to assist with the berthing of a tanker that arrived in Trinidad waters on Oct. 18 from Gabon. The vessel, called Overseas Yellowstone, eventually docked late yesterday using outsourced tugs and labor, Ramnarine said.
“The situation is dynamic and we will review if need be,” the minister wrote. “It should, however, be noted that there is no Ebola outbreak in Gabon.”
Gabon, which has had Ebola outbreaks in 2001-2002, 1996-1997 and 1994, is not among countries currently citing cases of Ebola. The virus has killed more than 4,500 people, mostly in Liberia, Sierra Leone and Guinea.
By Bloomberg
Stockpiles of oil from Alaska’s North Slope have surged to a five-year seasonal high as tanker maintenance slows loadings, forcing the grade to trade at a discount to U.S. crude for the first time since 2010.
Inventories at the Valdez terminal, the northernmost ice-free port in North America and the loading point for Alaskan oil, have averaged 4.38 million barrels this month, the most for October since 2009, data posted on the Alaska Revenue Department’s website show. Tanker repairs have shrunk the pool of vessels available, terminal operator Alyeska Pipeline Service Co. said.
The trapped stocks threaten to further cut prices for oil from the North Slope, once the most prolific crude-producing region in the nation, as refiners on the U.S. West Coast turn elsewhere for supplies. California is bringing in a record volume of oil by rail from other states and the region has increased imports from countries including Iraq and Saudi Arabia.
Alaskan oil “is cheap and there’s a lot of it because it’s sitting in Valdez,” David Hackett, president of energy consulting company Stillwater Associates in Irvine, California, said by telephone.
ConocoPhillips (COP) last month exported a cargo of Alaskan oil to South Korea, the first shipment of crude from the state bound for foreign shores since 2004. A company spokesman said at the time that sending the oil abroad would “potentially realize a higher value.”
ANS Prices
Alaska North Slope crude for delivery to the U.S. West Coast weakened by 50 cents a barrel to a discount of 40 cents relative to domestic benchmark West Texas Intermediate, data compiled by Bloomberg show. It’s the first time the grade has been discounted against WTI since Dec. 9, 2010. The oil fell $1.53 a barrel versus the international benchmark North Sea Brent for prompt delivery to a $3.81 discount at 2:54 p.m. New York time.
Alyeska’s 800-mile (1,300 kilometer) Trans Alaska Pipeline System, known as TAPS, carries oil from the North Slope to Valdez. From there, it’s typically sent by vessel to refineries along the U.S. West Coast. Production of the oil has declined from a peak of 2.1 million barrels a day in 1988 to an average of 523,797 barrels a day this month, state data show.
Tanker Work
Tanker maintenance is affecting vessel-loading schedules at Valdez, Michelle Egan, a spokeswoman for Alyeska in Anchorage, Alaska, said by e-mail. “It will sort itself out over time,” she said.
All BP Plc (BP/), Conoco and Exxon Mobil Corp. (XOM) tankers that carry Alaska North Slope oil are operating, spokesmen for the companies said by e-mail. Conoco’s inventories at Valdez “are within normal levels,” said Natalie Lowman, a Conoco spokeswoman in Anchorage.
While the Houston-based company sent Alaska North Slope, or ANS, oil abroad last month, Lowman said by e-mail, “Our traditional and most important market for ANS crude oil is, and will likely remain, the U.S. West Coast.”
Tina Barbee, a spokeswoman at Tesoro Corp. (TSO)’s headquarters in San Antonio, declined by e-mail to comment.
In Transit
The volume of Alaskan oil being carried in tankers slid in the week ended Sept. 19 to 1.85 million barrels, the lowest since January 2011, data compiled by the Energy Information Administration show.
“There are only a handful of companies involved in moving that oil, and there were some ships in dry dock, having maintenance,” Robert Merriam, who oversees the EIA’s weekly petroleum report, said by telephone Oct. 8.
The tanker work is another blow for Alaskan oil producers as the West Coast replaces their output with less-expensive barrels from other states including Utah and North Dakota. California took 16,373 barrels of oil a day by rail in July, a record for the month, according to the state Energy Commission.
Saudi Arabia supplied 17 percent of California’s oil in the first six months of 2014, up from 14 percent in the two previous years, state data show. Iraq’s share has risen to 11 percent from 9 percent.
By Bloomberg
Libya’s warring factions have pledged to keep the North African country’s crude flowing, putting pressure on other OPEC nations to curb output when the group supplying 40 percent of the world’s oil meets next month.
Libya’s production has risen even as violence and political disputes have left the country under the rule of two competing administrations: the internationally recognized government of Abdulla al-Theni and the Islamist-led cabinet of Omar al-Hassi. Both authorities are seeking to keep oil output stable as various militias battle for influence.
“It is almost beyond me that the Libyans managed to maintain production, considering that there is no government, and with all these militias,” Ole Hansen, head of commodity strategy at Saxo Bank A/S, said in an interview Oct. 20 in Dubai. “It is almost a miracle that they managed to get back production to where they have managed to get it back to.”
Libya, holder of Africa’s largest crude reserves, is producing 800,000 barrels a day, compared with 215,000 barrels a day in April when oil ports were shut by rebels seeking self-rule in the eastern region, according to state-run National Oil Corp. An agreement with the rebels allowed output to increase while the fighting between Islamist and pro-government militias has been contained to non-oil-producing areas in and around the capital Tripoli and Benghazi, the country’s second-biggest city.
OPEC Signals
Brent crude, a benchmark for more than half of the world’s oil, has tumbled 25 percent since June and settled at $86.22 a barrel yesterday on the London-based ICE Futures Europe exchange. Banks including BNP Paribas SA and Bank of America Corp. predict the rout may be over. They’re counting in part on the Organization of Petroleum Exporting Countries to reduce supply as the U.S. pumps the most oil in almost three decades and Russia’s output approaches a post-Soviet record.
Libya called for OPEC to reduce its collective output as rising global production pushed down crude prices, Mohamed Elharari, spokesman for National Oil, said Oct. 17. Saudi Arabia, the world’s biggest exporter, and other large producers in the group haven’t signaled that they will push for a cut at a planned meeting Nov. 27 in Vienna.
“Every incremental barrel from Libya expands the supplies of already surplus levels of light sweet crude in the market,” Miswin Mahesh, a commodities analyst at Barclays Plc, said in an e-mail yesterday. “The call on OPEC crude and stocks for the fourth quarter this year is at 29.8 million barrels a day while their latest production numbers are 30.66 million barrels a day so, yes, the surplus is already quite a lot, and warrants an adjustment.”
Keep Working
The Islamist government published a statement on National Oil’s website on Oct. 20 calling on workers to maintain oil output at the maximum level and not to hold protests at oil sites to preserve the country’s income amid declining prices.
“We are keen to provide security to all citizens and all companies operating in Libya,” said Mashallah al-Zawi, the oil minister in Hassi’s Islamist-led National Salvation Government, at a conference last week in Istanbul, according to comments published by local websites including Akhbar Libya. Theni’s government moved to the eastern region as Islamist militias expanded their control in the capital Tripoli.
Disruption Concerns
Most of Libya’s oil fields and export terminals for crude are hundreds of miles away from the conflict. The so-called Executive Office for the Barqa region, which seeks self-rule for eastern Libya, pledged to work with Theni’s government to defend oil facilities and keep crude flowing to international markets, a Barqa spokesman, Ali Al-Hasy, said Sept. 3.
Concerns about future disruptions persist as violence seems to be spreading, Riccardo Fabiani, a North Africa analyst based in London at Eurasia Group, a political risk research and consulting firm, said in an e-mail Oct. 20. “Inevitably at some point an incident will affect some oil facility,” he said.
Libya’s security situation “is getting increasingly out of control,” Saxo Bank’s Hansen said. “If Libya suddenly falls off the cliff, that’s another 400,000 or 500,000 barrels a day” of crude lost for global markets, he said.
Qaddafi Toppled
The OPEC member’s current output is half what it was before the 2011 rebellion that ended Muammar Qaddafi’s 42-year rule. Political schisms and violence have intensified amid a lack of central authority since his ouster and the chaos has undercut efforts to restore production to pre-2011 levels.
The two national institutions running the country’s oil industry, National Oil and the central bank, have avoided taking sides. “We are doing our work in a professional manner,” National Oil spokesman Mohamed Elharari said Oct. 20 by phone in Tripoli. “We don’t want any political interference.”
Libya’s House of Representatives was to discuss transferring the Central Bank of Libya’s work to a safe location amid the nation’s hazardous security, Issa Al-Oraibi, a House member, said by phone on Oct. 11.
“Apparently all the oil revenues in Libya are deposited at the central bank’s offshore branch, so the only money that comes into the country is strictly to pay salaries and keep the country going,” Hansen said. “So no one is being able to get their fat claws on the billions there.”
By Bloomberg
TransCanada Corp. (TRP) will have to spend $1 billion more than planned on an oil pipeline to Canada’s Atlantic Coast if natural gas customers get their way, a move it says would threaten the viability of the project.
TransCanada has delayed seeking regulatory approval of the C$12 billion ($10.7 billion) Energy East line as it negotiates with Quebec’s Gaz Metro Inc. and Ontario units of Spectra Energy Corp. (SE) and Enbridge Inc. (ENB), said two people familiar with the talks who asked not to be identified discussing a private matter.
The spat centers on TransCanada’s plan to convert a 3,000-kilometer (1,865-mile) stretch of its mainline gas conduit to carry oil. The nation’s largest pipeline operator after Enbridge is pursuing Energy East as environmental opposition imperils other planned lines from Canada’s oil sands to tidewater, including its Keystone XL.
Gas distributors claim that converting the mainline in eastern Ontario would lead to fuel shortages and higher prices. While TransCanada intends to build a new 250-kilometer gas line to meet demand, the distributors say it won’t be big enough. They want the company to build a standalone oil conduit or a gas line the same size as the existing one at no cost to customers.
Building an oil line from North Bay, Ontario, to Ottawa instead of altering the existing one would cost at least $1 billion more and put Energy East in jeopardy, the company says.
“It would be prohibitively expensive,” Karl Johannson, president of natural gas pipelines at TransCanada, said in an Oct. 16 phone interview, adding Energy East’s economics are tied to re-purposing the 1950s-era mainline. “What makes this project work is we have underutilized infrastructure.”
Longest Line
Energy East would be North America’s largest and longest crude line, crossing six Canadian provinces and carrying 1.1 million barrels a day. TransCanada, based in Calgary, latched onto the concept as a means to transport rising supplies of oil-sands crude and also reverse declining business on its mainline.
Mainline gas flows have fallen as the U.S., supplied with volumes from the Marcellus and Utica shale formations, requires less Canadian gas. TransCanada plans to convert a leg of its mainline that can carry 1.2 billion cubic feet a day of gas in Ontario and replace it with one that can transport 600 million cubic feet a day.
Gaz Metro says TransCanada’s plan would reduce gas capacity in Central Canada by 20 percent and lead to shortages at peak times, such as on the coldest days when demand for the heating fuel is highest.
Enough Supply
TransCanada’s proposal will more than cover demand for gas in Ontario and Quebec, the country’s two most populous provinces, Johannson said.
A compromise is unlikely before TransCanada submits its application to the National Energy Board in a few weeks, Johannson said. The filings are taking longer because of their complexity, not the feud with gas distributors, he said. TransCanada planned a mid-year application for Energy East as of May and has revised its schedule multiple times since then.
TransCanada rose 1.5 percent to C$54.33 at the close in Toronto and has gained 12 percent this year, compared with a 2.9 percent gain for the 69-member Standard & Poor’s/TSX Energy Index this year.
The regulator needs to weigh what’s in the national interest before making a recommendation to Prime Minister Stephen Harper.
The gas dispute risks becoming political as the emerging public discourse pits Central Canada’s gas needs against Alberta’s aspiration for new markets for its crude.
‘Tremendous Impact’
Gaz Metro is seeking to rally the business community, including through a speech Chief Executive Officer Sophie Brochu is scheduled to give today in Montreal that’s entitled, ‘The Energy East Project or Canada’s Energy Incoherence.’
“This will have a tremendous impact on natural gas users,” Marie-Christine Demers, a Gaz Metro spokeswoman, said in a phone interview.
Elizabeth Blair, a spokeswoman for Enbridge Gas Distribution Inc. and Andrea Stass, a spokeswoman for Spectra’s Union Gas Ltd., said their companies are aligned with Gaz Metro.
The Ontario and Quebec governments aren’t taking a final position on Energy East as they hold consultations on the project’s impacts.
Jennifer Beaudry, press secretary to Ontario Energy Minister Bob Chiarelli, said it’s premature to comment while Ontario’s energy regulator conducts a review, which includes considering the reliability of the province’s gas supply.
The Quebec government will examine TransCanada’s filing to determine how it affects gas volumes in the province, which will need to remain well supplied, Finance Minister Carlos Leitao told reporters in Quebec City on Oct. 15.
Producer Costs
“We continue to be optimistic that Energy East, which we see as vital for TransCanada, will be found to be in the national public interest, though the regulatory process is becoming ever more daunting, and approval can’t be taken for granted,” Stephen Dafoe and Francesco Sorbara, corporate bond analysts at Bank of Nova Scotia in Toronto, said in an Oct. 17 note to clients.
If TransCanada bows to gas distributors’ demands, Energy East’s higher costs would be passed on to oil producers and refiners that have booked capacity on the line, Johannson said.
As Energy East is currently envisioned, shippers will probably incur costs of $7.40 to $10.20 a barrel to move oil across Canada on the pipeline and then by tanker to the U.S. Gulf Coast, the most likely market, said David McColl, an analyst at Morningstar Investment Services in Chicago. Currently, the costs are less than rail alternatives, he said.
“That’s a key piece of the economic equation -- will Energy East be competitive in shipping to the Gulf Coast?” McColl said. “There are probably solutions for all these issues and concerns, none of which would kill the TransCanada Energy East project.”
By Bloomberg
http://www.bloomberg.com/image/iycPVk9uVsWw.jpg
Photographer: Aaron McKenzie Fraser/Bloomberg
Storage tanks an oil refinery in New Brunswick, Canada.
Investors are putting money into funds that track oil prices at the fastest rate in two years, betting that crude will rebound from a bear market.
The four biggest oil exchange-traded products listed in the U.S. have received a combined $334 million so far this month, the most since October 2012, according to data compiled by Bloomberg. Shares outstanding of the funds, including the United States Oil Fund (DBO) and ProShares Ultra Bloomberg Crude Oil, rose to 55 million yesterday, a nine-month high.
“There are investors who love to catch a falling knife,” said Dave Nadig, chief investment officer of San Francisco-based ETF.com, an ETF analysis firm. “It’s pretty easy to look at what’s been going on in oil and say ‘well, it has to bottom out somewhere.’ There are plenty of investors out there who still believe that the long-term trend of oil has to be $100.”
Money has flowed into the funds as West Texas Intermediate and Brent crudes, the benchmarks for U.S. and global oil trading, each plunged more than 20 percent from their June highs, meeting a common definition of a bear market.
WTI futures gained 10 cents to end at $82.81 a barrel today on the New York Mercantile Exchange. Prices are down 9.2 percent this month. Brent was up 82 cents to $86.22 a barrel.
The US Oil Fund (USO), the biggest oil ETP, received $101.9 million. The fund, which tracks WTI prices, gained 0.6 percent to $31.33 today and is down 11 percent this year. The ProShares fund, which follows the Bloomberg WTI Crude Oil Subindex (BCOMCL), saw $192.7 million flow in. Shares gained 1.5 percent to $24.99 today and fell 22 percent this year.
The PowerShares DB Oil Fund and the iPath S&P GSCI Crude Oil (UCO) Total Return Index ETN (OIL) also had inflows this month.
Short Funds
The ProShares UltraShort (SCO) Bloomberg Crude Oil, a so-called inverse ETP which gains when the underlying index falls, had an outflow of $93.2 million this month.
WTI for December delivery is about 50 cents more expensive than the January contract. This structure, known as backwardation, allows ETPs like the U.S. Oil Fund to own more barrels of crude each month as it sells the expiring futures and buys the less expensive next-month contract. The value of the fund increases more if futures then rise.
“The structure of the curve in oil has really been the driver of returns for a lot of investors,” Nadig said.
The recent slump in crude oil prices came as production in OPEC and the U.S. increased. U.S. oil output will rise next year to the highest since 1970, according to the Energy Information Administration.
OPEC Output
The Organization of Petroleum Exporting Countries, which supplies about 40 percent of the world’s oil, pumped 30.47 million barrels a day in September, the most since August 2013, its monthly report on Oct. 10 showed. The group is scheduled to meet next month in Vienna.
“Everyone is trying to pick a bottom here,” said Tariq Zahir, a New York-based commodity fund manager at Tyche Capital Advisors. “ETF is the easiest way to get involved in oil. That’s why you are seeing the big inflows. Oil has gone down a little bit too far, too quickly.”
By Bloomberg
The bear market in oil has analysts reassessing the U.S. shale boom after five years of historic growth.
The U.S. benchmark price dropped to $79.78 a barrel on Oct. 16, the lowest since June 2012. At that level, one-third of U.S. shale oil production would be uneconomic, analysts for New York-based Sanford C. Bernstein & Co. led by Bob Brackett said in a report yesterday. Drillers would add fewer barrels to domestic output than the previous year for the first time since 2010, according to Macquarie Group Ltd., ITG Investment Research and PKVerleger LLC.
Horizontal drilling through shale accounts for as much as 55 percent of U.S. production and just about all the growth, according to Bloomberg Intelligence. The Paris-based International Energy Agency predicted in November that the U.S. would pass Russia and Saudi Arabia to become the biggest producer in the world by 2015. Though some forecasts show oil rebounding or stabilizing, any slower increase in U.S. output would shake perceptions for the global market, said Vikas Dwivedi, an oil and gas economist in Houston for Sydney-based Macquarie.
Oil Prices
“It would reshape the way everybody would think about oil,” Dwivedi said.
Daily domestic production added a record 944,000 barrels last year and reached a 29-year high of 8.95 million barrels this month, according to the Energy Information Administration, the U.S. Department of Energy’s statistical arm.
Well Depletion
Output, much less growth, is difficult to maintain because shale wells deplete faster than conventional production. Oil production from shale drilling, which bores horizontally through hard rock, declines more than 80 percent in four years, more than three times faster than conventional, vertical wells, according to the IEA. New wells have to generate about 1.8 million barrels a day each year to keep production steady, Dwivedi said.
At $80 a barrel, output would grow by 5 percent, down from a previous forecast of 12 percent, according to New York-based ITG.
At $75 a barrel, growth would fall 56 percent to about 500,000 barrels a day, Dwivedi said. Closer to $70 a barrel, the growth rate would drop to zero, he said.
Decline Rates
In North Dakota’s Bakken shale, oil at $70 a barrel could cut production 28 percent to 800,000 barrels a day by February from the 1.1 million barrels a day that was pumped in July, according to Philip Verleger, who was an economic adviser to President Gerald Ford and the director of the Office of Energy Policy for President Jimmy Carter.
“The cash flow will go down as the prices go down, the amount of money advanced to these people to continue the drilling will dry up entirely, so you’ll see a marked slowdown in drilling,” said Verleger, who runs PKVerleger in Carbondale, Colorado, referring to the industry as a whole.
West Texas Intermediate crude, the U.S. benchmark price, has fallen 22 percent since June 20.
The price will rise to a level where more output is economic, the Sanford C. Bernstein analysts said. The flood of oil from shale is powerful enough to put a ceiling of $90 a barrel on prices through the latter half of this decade, and at times the price will dip to as low as $70, Eric Lee, an oil market strategist at New York-based Citigroup Inc., said yesterday in a phone interview.
More Bearish
There’s a risk the price will “briefly” fall to $75 a barrel before global demand recovers in 2015, Bank of America Corp. analysts said last week. They predicted an average price of $85 a barrel in the fourth quarter.
Investors are more bearish. They’re holding the highest number of short positions on WTI in 22 months, U.S. Commodity Futures Trading Commission data show.
The impact of the bear market on supply could be muted depending on how many companies locked in higher prices with derivatives contracts, Verleger said.
Shale drillers managed to keep expanding production of natural gas even after prices collapsed, said Amy Myers Jaffe, executive director of energy and sustainability at the University of California-Davis. U.S. output rose 3.8 percent to 2.6 trillion cubic feet a month in the year to July, EIA data show, even as the rig count fell in April to a 21-year low, according to data from Baker Hughes Inc., a Houston-based oilfield-services company.
Improve Efficiency
Drillers could also maintain output by improving efficiency. Each rig in the Permian Basin of West Texas will add a record 176 barrels of new oil a day in November, up 20 percent from a year previous, according to an EIA estimate. In the Eagle Ford, each rig is getting 540 new barrels a day, also up 20 percent.
The cost of completing a well in the Leonard shale of the Permian’s Delaware Basin fell to $5 million this year, compared with $6.9 million in 2011, according to Houston-based EOG Resources Inc. (EOG)
Companies could also drill wells closer together, called downspacing. The practice is relatively new in horizontal drilling, and there’s a risk neighboring wells will interfere with one another. So far, production results have been mixed.
“The companies that got in early and have low costs and already built the infrastructure are going to continue to execute on their strategies,” said Bill Kroger, Houston-based co-chair of the energy litigation practice at Baker Botts LLP. “If prices stay down for the long term it’s possible we’ll see production fall off but I don’t think we’re there yet.”
Returns Shrink
While analysts have focused on the price at which shale drilling remains economic, companies that can profit at $80 a barrel may still curb their budgets as returns shrink, said Shane Fildes, the Calgary-based head of global energy at BMO Capital Markets.
“You’ll see a supply response more quickly than some people expect,” Paul Sankey, an analyst with New York-based Wolfe Research LLC, said Oct. 17 in a note to clients. “While it could take several months to see a clear supply impact, we do expect to see a drop in completed wells in the major basins within a couple of months.”
Oil is so much more than a fuel. It’s a force even bigger than its $3.4 trillion market. It’s a weapon, a strategic asset, a curse. It’s a maker and spoiler of fortunes, a leading indicator and an echo chamber. All these roles have a part in setting its price. The result is a peculiar market that says as much about global economics and politics as it does about supply and demand.
The Situation
After four years when the highest average oil prices in history often seemed to defy economic gravity, petroleum fell in mid-2014. It had risen to $107.73 a barrel in June, even as Americans and Europeans drove fewer miles in more fuel-efficient cars, curbing consumption of gasoline, the biggest source of oil demand. Meanwhile, supply expanded as the sustained higher prices made techniques such as deepwater drilling and fracking pay off. Those fundamentals started to register in the summer, as Chinese imports sagged, Europe teetered on the brink of recession, and the stronger U.S. economy made barrels priced in dollars relatively more expensive. Instead of stanching the glut by pumping less oil, Middle East exporters engaged in a price war to defend their market share. New sources of supply such as Canadian oil sands and U.S. shale have loosened the OPEC cartel’s grip on the market. Saudi Arabia stands to gain as lower prices hurt political and economic rivals such as Russia and Iran, already facing strain from sanctions. Cheap oil also helps Saudi producers compete better against the U.S., where production costs more. In mid-October, the price dipped below $80 a barrel, testing the level at which U.S. drillers in North Dakota and Texas can still turn a profit.
http://www.bloomberg.com/quicktake/content/uploads/sites/2/2014/10/OilGraphicPeakFixed.png
The Background
Through the mid-20th century, a group of multinational oil giants known as the Seven Sisters (including the companies that became Exxon Mobil, Chevron and BP) dominated the market. Controlling the barrels from the wellhead to the gasoline tank, they traded mainly with each other on confidential terms; there was no open market. Countries with oil fields wrested more control with the formation in 1960 of the Organization of Petroleum Exporting Countries. The cartel’s Arab members used their power for political and economic ends, shocking the global economy with embargoes in 1973 and 1979. In the 1980s, OPEC infighting, the emergence of new suppliers and the development of futures exchanges gave rise to new market-based prices. Today the international benchmark is Brent crude from the North Sea, which has the advantage of political stability but lately is contending with declining output that makes trading sparse. The U.S. benchmark, West Texas Intermediate crude, started trading at less than the Brent price in 2010 as supplies of shale oil became plentiful. Last year, the European Union raided offices of Shell, BP and others to investigate possible manipulation of reference prices produced by the publisher Platts.
The Argument
As the world industrializes and consumes more energy, each new barrel of oil costs more than it used to, because the cheapest and easiest oil has already been pumped. This observation gave rise to a theory called “peak oil,” which holds that world production will eventually max out and decline as oil fields deplete. Skeptics of this notion point to the technological innovations that let U.S. producers extract oil and gas from previously impermeable shale, unlocking vast new resources, albeit at greater expense; the issue isn’t quantity but cost. The other variable, of course, is demand, and the stunning weakness this year raises long-term questions about oil’s future as consumers grow more efficient and switch to alternative fuels such as natural gas and renewable power. Oil supplied 31 percent of the world’s energy in 2012, down from 46 percent in 1973. There may come a day when oil gets cheap because it’s unwanted. That’s the argument often advanced by advocates of divestment. They warn of a financial crisis caused by a bursting “carbon bubble” of inflated energy-company valuations after fossil-fuel prices rise to account for the costs of contributing to global warming.
New York (Platts)
The oil complex settled higher Tuesday as fresh Chinese economic data provided bullish fodder, despite the statistics having an overall mixed message.
Front-month NYMEX crude closed 10 cents higher at $82.81/b. The November contract expired Tuesday. December delivery becomes the front-month contract starting Wednesday. NYMEX December crude settled at $82.49/b, up 58 cents.
ICE December Brent settled up 82 cents at $86.22/b.
In refined products, NYMEX November ULSD ended 2.76 cents higher at $2.5132/gal, while front-month NYMEX RBOB closed up 1.32 cents at $2.2134/gal.
China's gross domestic product grew 7.3% year-on-year from July through September, official data showed. The growth rate was just above analysts' expectations, but was the slowest since the first quarter of 2009.
Chinese oil demand rose in September as refineries processed the second-highest monthly amount of crude on record. China's refinery throughput averaged 10.27 million b/d, a 9.1% year-on-year increase, according to data from the National Bureau of Statistics.
As the world's largest energy consumer, the Chinese economy is closely scrutinized. Forecasts have generally been bearish, a view underscored last week when the International Energy Agency trimmed its 2014 and 2015 outlook for Chinese oil demand.
The data released Tuesday would seem to point in the opposite direction, indicating that a relatively strong appetite exists and appears consistent with reports of active Chinese buying in recent weeks.
Chinese demand has helped absorb an excess of crude in the market, leading Mediterranean and West African grades to strengthen and Dubai to flip into backwardation, Energy Aspects said in a research note Tuesday.
In the Mediterranean, Azeri Light was assessed at a $3.85/b premium to Dated Brent Tuesday, compared with a $1.50/b premium at the end of September.
The rise in West African price differentials has been less dramatic. Bonny Light was assessed at a $1.45/b premium to Dated Brent Tuesday, compared with a 50 cents/b premium at the beginning of August.
The question now becomes whether China's crude buying and high refinery run-rate reveal strong underlying demand for end-use products.
According to Energy Aspects, the rise in refinery runs suggests a "moderate pick-up in demand," but the consultancy says other factors are likely at play.
The bulk of buying is probably still earmarked for China's new strategic petroleum reserve and commercial stockpiles, as refineries begin building forward cover inventories, the consultancy said.
"It will be key to wait for product inventory numbers to see if increased runs are being underpinned by demand, or a product glut forms that is transferred back to crude," Energy Aspects analyst Amrita Sen said.
Chinese economic data helped pivot attention away from the Middle East as analysts continue trying to figure out whether Saudi Arabia is willing to live with lower oil prices or will move to cut production.
"I think the Saudis will jawbone the market into stability by assuring the market they could do something in a minute if they wanted to, and then hope the winter is cold," Bill O'Grady, chief market strategist at Confluence Investment Management, said.
Supply disruptions could also emerge in the Middle East, leading prices higher, another reason why the Saudis may be content to delay any production cuts, he said.
Rio de Janeiro (Platts)
Financially troubled Brazilian oil producer Oleo e Gas Participacoes, or OGPar, expects output from its flagship Tubarao Martelo field to peak at about 30,000 b/d in 2016, the company said Tuesday.
OGPar, formerly known as OGX, will invest $200 million-$500 million at the field over the next few years to drill two additional production wells and three injection wells at Tubarao Martelo,
OGPar said. The new wells are expected to increase production at Tubarao Martelo to an average of about 25,000 b/d in 2016, up from output of 17,508 b/d in September.
OGPar currently pumps oil from four wells at Tubarao Martelo, with the fourth well starting output on September 4.
Tubarao Martelo holds proved and probable reserves of 78.5 million barrels, according to a recent report by certification firm DeGolyer and MacNaugton. Proved reserves have a 90% chance of being produced, while probable reserves have a 50% chance of recovery.
The challenging Tubarao Azul field, meanwhile, is expected to continue producing about 3,000 b/d until March 2015, OGPar said. OGPar recently reached a deal with OSX Brasil, the services company that owns the OSX-1 floating production, storage and offloading vessel at the field, to continue testing at Tubarao Azul until mid-December.
OGPar expects production at Tubarao Azul to trend steadily lower through the end of 2014 as the company recovers the last of the estimated 6 million barrels of 21 API rated oil from the field. The field's output is expected to fall to 2,900 b/d in October, 2,700 b/d in November and 2,500 b/d in December, OGPar said earlier this year.
Operational troubles at Tubarao Azul caused the financial woes that eventually led the company to file for protection from creditors in late 2013. The field was originally expected to peak at output of about 40,000 b/d, but fell well short of expectations amid a series of technical problems and low flow rates from production wells.
OGPar said it expects to emerge from protection from creditors in April 2015, but will remain under court supervision until about September 2015. The company's new OGX American depositary receipts are expected to start trading in New York in about 15 days, OGPar said.
OGX will be the holding company controlling oil producer OGPar, with creditors who participated in the debtor-in-possession financing round as part of bankruptcy proceedings retaining about 65% of the new firm and pre-bankruptcy creditors owning 25%, OGPar said.
Original OGX shareholders will retain 10%, with Brazilian entrepreneur Eike Batista -- once Brazil's richest man before the financial meltdown at his EBX Group of firms -- holding about half of those shares.
London (Platts)
Christophe de Margerie, who was killed Monday in a plane crash in Moscow, was very much the face of French oil major Total and wanted to transform the company into a 3 million boe/d oil and gas producer.
He was passionate about the pursuit of oil and gas and was not afraid of expressing opinions from which other oil bosses might shy away.
Always courteous and friendly, never aloof, de Margerie was popular among journalists, who reported his comments with relish.
De Margerie, nicknamed "Big Moustache" because of his trademark facial hair, was, at times, a controversial figure.
He was accused of violating a United Nations oil-for-food program in Iraq and stood trial in a Paris court in July 2013 before being acquitted of all charges.
He was also placed under formal investigation by French judges in 2007 in an inquiry into alleged bribes related to a gas deal in Iran. Under his leadership, Total retained a business in Iran until international sanctions forced it out.
In July 2010, he called US sanctions against Iran that banned gasoline sales to the Islamic Republic "an error."
In recent months, too, he criticized the imposition of western economic sanctions against Russia, where Total plans significant expansion in coming years.
"We don't think sanctions are improving anything. We consider that business, economy, developing links between countries [and] companies are the best way to improve stability, understanding and peace," he said in May.
Total has said it expects Russia to contribute the biggest share of its production by 2020, and Russia's Prime Minister Dmitry Medvedev, with whom de Margerie met earlier Monday, said Tuesday he had discussed further cooperation and expansion of Total's activities in Russia at the meeting. PRODUCTION GROWTH
Appointed chief executive in 2007, de Margerie led Total to significant finds across the globe and to new developments in countries as diverse as Uganda, Angola and Azerbaijan.
He was proud of Total's ability to successfully operate major new projects and was critical of failures at developments where Total was a non-operating partner.
Most recently he slammed delays at the giant Kashagan oil field in Kazakhstan and at the Angola LNG project. Indeed, the problems at both projects prompted Total's downward revision in August of its 2017 production target to 2.8 million boe/d from 3 million boe/d.
How de Margerie's death will affect Total's plans to reach output targets remains to be seen.
He was a key figure in the company's negotiations with the UAE's state oil company ADNOC over future participation in the Adco oil production license.
Last month, he said Total's proposal to rejoin the license -- which until January this year provided the company with some 140,000 b/d of production -- would remain valid until October 22 -- two days after de Margerie's death.
De Margerie has also been a strong defender of Total's strategy regarding the refining sector in France, repeatedly saying the company would have to "adjust" its French refining capacity to the needs of the market.
Unions have been critical of his approach, calling on him to respect the demands of Total's refining workers.
As recently as August, de Margerie said there would be changes to its exposure to refining in France in 2015 -- the deadline the company gave in 2010 for not shutting any more plants following the closure of the Dunkirk refinery.
Total, which operates five refineries in France, has said it expects to lose Eur500 million ($645 million) in 2014 in the sector due to weak demand and overcapacity.
Last month, Total said it could announce changes in its French refining strategy next spring.
Under de Margerie, Total looked outside of Europe to expand its refining business, developing the 400,000 b/d Jubail refinery in Saudi Arabia together with Saudi Aramco.
He argued that Total was responding to the needs of the global market and the company made investments that were economic. BLUECHIP
In recent years, Total's role as Europe's leading blue chip company was reinforced, with the company heading the Dow Jones Euro STOXX 50 index by weight.
And ironically analysts at Raymond James in a Tuesday note selected Total as its "top pick" among European energy companies.
De Margerie's death sent Total's shares down by 2% in early European trading, but the price recovered by midday London time to be up by 2%.
As of early Tuesday, no announcement was due about either an interim replacement for de Margerie or a permanent successor.
De Margerie's peers expressed their sadness at his death, a reflection of how well the Frenchman was regarded in the industry.
"This is a great loss to our industry, for which Christophe exemplified true leadership, courage, humility, and his resilience was inspiring during times of adversity," Saudi Aramco CEO Khalid al-Falih said.
Shell CEO Ben van Beurden said: "Christophe was a larger-than-life character, a leader respected across the energy industry and a friend."
BP chief Bob Dudley said the oil and gas industry had lost "one of its giant international champions - an outstanding leader, a distinguished colleague and I have lost a personal friend."
And as Olivier Appert, head of France's national petroleum and renewable energy institute, summed up on Tuesday: "He was a man liked by his colleagues, his business partners, and he was respected by his competitors and journalists for the honesty of his remarks which were rarely politically correct. Big Moustache, we will miss you."
London (Platts)
FOB Rotterdam low sulfur fuel oil barges hit a $13/mt premium to FOB NWE cargoes Monday, Platts data shows, with FOB Rotterdam barges and FOB NWE cargoes assessed at $470/mt and $457/mt respectively.
Traders said this was due to a lack of spot supply triggering tightness in the barge market. The two main producers of LSFO in the Amsterdam-Rotterdam-Antwerp triangle were said to have limited prompt volumes to offer.
The premium of LSFO barges to FOB NWE cargoes was last higher on May 5, when it was $16.75/mt.
"The market is tight, the only two producers of LSFO, BP in Rotterdam and Totsa in Antwerp are blending," a bunker player said. "It will only get worse, because they are the only two producers, Shell is not producing LSFO anymore."
He said Shell had stopped producing 1% sulfur fuel oil in anticipation of tighter sulfur emission caps in 2015. Shell was not immediately available for comment.
Meanwhile, the Rotterdam 1% sulfur delivered bunker premium reached a $20.25/mt premium over ex-wharf barges on October 6, the highest in about seven months, as some refiners began to move away from LSFO production ahead of new emission control area rules next year, while others were heard to be in maintenance.
"Not really seeing much LSFO around," a bunker trader said.
Northwest European refineries are preparing for the changes by testing new specifications similar to 0.1% sulfur marine diesel grade, traders said.
One major oil company and two big Amsterdam-Rotterdam-Antwerp fuel oil suppliers are already offering the new product, priced at a $10-20/mt discount to gasoil, one European trader said.
Paris (Platts)
OPEC could in the future take action to respond to the recent fall in oil prices, Algerian energy ministry official Ali Hached said in Paris Tuesday.
"Collectively OPEC can respond to the excess supply that we have on the market," he said.
Answering questions at the 19th Gas and Electricity Summit organized by Petrostrategies, Hached said "this situation is not new" and added that "we've already faced major fluctuations in oil prices" in the past.
He noted comments earlier in the meeting from Olivier Appert, head of the IFP Energies Nouvelles research institute. Appert had recalled the oil price falls of 1985/86, as well as the way that OPEC had reacted to the dramatic fall in prices in the immediate aftermath of the global financial crisis in 2008.
Brent crude prices fell back to around $40/barrel in 2008, but were back to $100 by early 2011.
Hached said for "most countries" the fall in prices "challenges their ability to receive the revenues they need for their own development."
He said producers should wait to see how the market responds and then OPEC could also respond.
Knoxville, Tennessee (Platts)
The NYMEX November natural gas futures contract tumbled 9.6 cents to a $3.67/MMBtu settlement Monday -- the lowest close in 11 months -- as the market considered forecasts calling for mild weather into November as well as new US gas production records set over the weekend.
The last time the prompt month settled below $3.70/MMBtu was exactly 11 months ago, when the December contract closed at $3.674/MMBtu on November 20, 2013.
"We're at 11-month lows and the market can't seem to pick its head up," said Gene McGillian, analyst at Tradition Energy.
Updated forecasts released Monday now are calling for mild weather to extend into the first week of November. The US National Weather Service's forecast map is predicting above-normal temperatures for all of the US in its eight- to 14-day outlook.
Such weather could dampen demand and allow the industry to continue chipping away at historic storage deficits on likely strong injections, analysts noted.
On the supply side, Platts unit Bentek Energy reported that US dry gas production hit a new record over the weekend, topping out Sunday at 70.5 Bcf/d.
McGillian said light trading volumes may have sustained the price drop as well. "We've fallen past $3.70[/MMBtu] support and next we may test $3.50[/MMBtu]" on our way to the bottom, he said.
"The bears are in control" until the weather changes, he added.
"The levels that held up since the end of July" were finally breached as mild weather continues, noted Elaine Levin, president of brokerage PowerHouse. "We also continue to watch other markets, like crude and distillates, and see weakness across all the energies," she added.
November traded Monday in a range of $3.663-3.745/MMBtu.
The NYMEX settlement is considered preliminary and subject to change until a final settlement price is posted at 7 pm EDT (2300 GMT).
London (Platts)--20Oct2014/947 am EDT/1347 GMT
International sanctions and the recent sharp fall in crude oil prices may have prompted Russia to seek a compromise in talks with Ukraine about natural gas supplies, Prime Minister Arseniy Yatseniuk said Sunday.
The EU and US should continue to pressure Russia in order to achieve even greater results, Yatseniuk said in an interview aired late Sunday by TSN-Tyzhden, a television news show.
"What does Russia have? They have two pedals: one is gas and the other one is oil. That is all. Therefore, the decline in oil price by more than 20% is an incredible blow to the Russian economy," Yatseniuk said.
"If we continue to keep the unity with our European and American partners, only then we will achieve the results."
Russia suspended gas supplies to Ukraine on June 16, citing disagreements on prices. The countries made progress in talks between their presidents -- Russia's Vladimir Putin and Ukraine's Petro Poroshenko -- on Friday.
The talks, now involving energy ministry officials, were supposed to continue on Tuesday in Brussels.
Poroshenko, in a sign of a breakthrough, indicated Ukraine has been willing to pay $385 per 1,000 cubic meters for Russian gas during the winter --until March 31 -- and $325/1,000 cu m during the summer, reflecting different levels of demand.
WARM HOMES
"Following the talks we can say that Ukraine will have gas and it will be warm in the homes of Ukrainians," Poroshenko said Saturday.
"This is the result of yesterday's agreement, provided that Ukrainian national interests are protected."
The progress came with Ukraine facing a shortage of at least 5 billion cu m of gas during the upcoming winter, according to Yatseniuk.
Ukraine had 16.76 Bcm of natural gas in underground storage facilities on October 18, or about 52.5% of capacity, according to Gas Storage Europe, a non-profit Brussels-based organization that provides energy statistics to the EU.
The figures showed Ukraine failed to meet its original target of 17.2 Bcm by October 15, the date when the six-month heating season usually begins.
Facing gas shortages, the government recently decided to postpone the start of the heating season to November 1.
Yatseniuk said the government was ready to start heating. "We have the resources needed to turn on the radiators," Yatseniuk said, adding weakening oil prices will probably further reduce the price of natural gas.
Dhaka (Platts)
Bangladesh has for the first time decided to set the domestic gas tariffs in line with the costs of production following requests from international oil companies for an increase, a former senior Petrobangla official told Platts Monday, October 20.
The Energy and Mineral Resources Division of the Ministry of Power, Energy and Mineral Resources, or MPEMR, asked Petrobangla earlier this month to propose an increase in the gas tariff by calculating upstream costs, former Petrobangla chairman Hussain Monsur said.
"We have started calculating the upstream costs of natural gas production," he said.
Natural gas will be treated as a commodity for the first time in the country and a tariff hike will be proposed accordingly, Monsur said.
Monsur served as Petrobangla chairman until October 18.
Once prepared, the tariff hike proposal will be submitted to the Bangladesh Energy Regulatory Commission to scrutinize and subsequently announce a gas tariff increase for all types of consumers in the country.
Bangladesh has never set gas tariffs by taking into account upstream costs, Monsur said.
Until now gas tariffs in Bangladesh have been fixed mainly by taking into consideration the profitability of gas marketing and distribution companies, a senior official of the country's sole oil and gas exploration company, Bangladesh Petroleum Exploration and Production Company Ltd, or BAPEX, told Platts Monday.
The market and political impacts had also been considered in previous tariff increases, he said.
But IOCs urged the government to revisit the price structures of domestic gas to encourage oil and gas exploration in the country's potential onshore and offshore structures.
Inadequate offshore fiscal terms in production sharing contracts and restrictive onshore access have resulted in limited exploration investment in the country, IOCs said during a meeting in May with MPEMR state minister Nasrul Hamid.
Bangladesh last raised gas tariffs for all types of domestic consumers, except CNG, by 11% on August 1, 2009.
The country's energy regulator increased the price of CNG by 20% on September 20, 2011.
Domestic natural gas prices in Bangladesh currently range from Taka 72.92/Mcf (93 cents/Mcf) to Taka 268.09/Mcf across industrial, commercial and power generation sectors, according to Petrobangla.
The country buys gas from international oil companies operating in the country in the much higher range of around $2-4.50/Mcf, a Petrobangla official said.
As at October 14, Bangladesh was producing 2.390 Bcf/day against demand of around 3.0 Bcf/day, Petrobangla data showed.
Of the total natural production, IOCs produce 54.56%, or 1.304 Bcf/d, while state-owned gas firms produce the remainder, the data shows.
Gas shortages in Bangladesh have prompted Petrobangla to ration new connections to industries, fertilizer factories and power plants, hindering economic growth since June 2009.
Moscow (Platts)
Russian gas giant Gazprom said Tuesday it is considering listing on the Hong Kong Stock Exchange as part of the company's strategy to increase the role of Asian investors in its financial policy amid worsening relations with the West over the ongoing crisis in Ukraine.
"Now we are looking at the possibility of listing on the Hong Kong Stock Exchange and increasing the level of our listing in Singapore," Gazprom said in a statement following a board of directors' meeting.
In June, Gazprom listed global depository receipts on the Singapore Exchange.
"Listing in Asia offers access to new types of investor, including pension funds, insurance companies, Asian corporations, family funds and management companies of Asian banks," Gazprom said.
Gazprom said previously it wants to increase the role of Asian investment in its financial profile and is looking into possible Eurobond placements in Asian currencies.
Its oil subsidiary Gazprom Neft has also taken steps recently to diversify its supply contracts away from the dollar and into alternative currencies, such as the Yuan and Ruble.
During the meeting Gazprom executives discussed other aspects of financial policy in the context of geopolitical factors, including Western sanctions and the ongoing crisis in Ukraine, which have "impacted most Russian companies," the statement said.
"In these conditions Gazprom considers it necessary to maintain the course of the current financial strategy, which will guarantee the company's financial sustainability and allow it to react in good time to a possible worsening of the situation," Gazprom said.
This strategy includes a conservative budget policy, which takes into account the risk that supply volumes could fall or the company will not be paid for some deliveries, it said. The company is aiming to ensure this by focusing on priority projects as well as adopting a conservative debt management policy.
Gazprom officials said last week that financial markets are still open to the company, despite Western sanctions which have directly targeted access to Western financing for other energy companies such as Rosneft and Novatek as well as Gazprom's oil arm Gazprom Neft.
Gazprom has been hit by sanctions targeting access to technology for use in Arctic, deepwater and shale oil projects, but has not been included in the lists of companies blocked from accessing Western financing.
Gazprom directors also approved an amended company investment program for 2014 at Rb1.026 trillion (around $25 billion), the company said in a separate statement following the board of directors meeting.
Louisville, Kentucky (Platts)
Kentucky's two largest electric utilities, Louisville Gas & Electric and Kentucky Utilities, say they expect to need up to 737 MW of additional long-term capacity in 2020, when they also assume they will retire two units totaling 272 MW at the E.W. Brown baseload coal plant near Harrodsburg.
Any new generation brought online at the end of this decade most likely would be fired with natural gas. However, whether the PPL Corp. subsidiaries construct a new combined-cycle or simple-cycle combustion turbine plant probably will be dictated by gas prices, the utilities told the Kentucky Public Service Commission in newly filed update to their latest integrated resource plan first submitted in May.
Depending on gas prices several years from now, LG&E and KU could add anywhere from 368 MW to 737 MW of gas-fired generation in 2020.
"In the baseload scenarios, the companies have a long-term need for capacity beginning in 2020," they said. "With low gas prices, NGCC [natural gas combined cycle] capacity is added in 2020, but with mid and high gas prices, simple-cycle combustion turbine capacity is added."
The scenario also changes if the federal government does not impose a price on carbon dioxide emissions, as has been proposed.
With both mid and high gas prices and no CO2 price, the utilities' energy needs primarily would be met with their existing coal units, the new 640-MW Cane Run 7 gas plant, under construction near Louisville, and new simple-cycle gas units, they said.
"With low gas prices, the production cost savings associated with NGCC capacity more than offset the NGCC unit's higher capital costs," they added.
LG&E and KU abandoned plans earlier this year to build a 700-MW gas plant at the site of their 242-MW Green River baseload coal plant in Muhlenberg County, which is targeted for retirement in April 2015.
That decision came after nine municipals told the utilities they intend to sever their wholesale power contracts in 2019. Federal law requires a five-year notice of such action.
After adjusting for the impending loss, the utilities said they expect energy requirements ranging from 34,053 MWh to 37,379 MW in 2014 to be essentially flat in 2020, when they are forecasted to range from 33,497 MWh to 37,716 MWh.
Peak load, however, is seen rising from a high of 7,294 MW in 2014 to 7,396 MW in 2020.
The updated IRP, often referred to as a snapshot in time, also assumes that Brown Units 1 and 2, representing a total of 272 MW, will be shuttered in 2020 to comply with new Environmental Protection Agency rules. Each unit is more than 50 years old.
There are no current plans to retire Brown Unit 3, rated at 446 MW.
LG&E and KU already have announced plans to retire about 800 MW of coal-fired generation over the next year or so. Altogether, they own about 8,000 MW of generation capacity, mostly coal-fired.
Liz Pratt, a LG&E/KU spokeswoman, said the 2014 IRP examined multiple scenarios and potential resource plans, but cautioned, "it is not a commitment or prediction as to what will come."
The two utilities, she said, will continue to explore all available options "for providing reliable energy to our customers while complying with all regulations in a least-cost manner."
She did not indicate if the companies intend to revive plans for the new Green River gas plant later this decade to meet the expected 2020 requirement for additional generation.
By Bloomberg
Somalia plans to begin producing oil and gas offshore for the first time within six years and is in talks with state governments about how revenue will be shared, Petroleum Minister Daud Mohamed Omar said.
The Horn of Africa country, which has been immersed in conflict for more than two decades, is proceeding tentatively on exploration to avoid creating new tensions, Omar said at the Somalia Oil & Gas Summit yesterday in London. Somali President Hassan Sheikh Mohamoud said in August the government expects to complete an assessment of its oil and gas potential this year.
“The Somali government, even though it wishes to move forward quickly in these areas, will also move forward cautiously,” an interpreter for Omar said at the conference. “We do not intend to have the quest for oil and gas to re-ignite divisions and violence.”
Somalia is considering its first bidding round for oil blocks since 2009 as increasing stability begins to attract more foreign investors. African Union-backed government forces have regained control of about 70 percent of the country that had fallen under the control of al-Shabaab, the al-Qaeda-linked militant group seeking to create an Islamic state in Somalia.
The government is in talks with companies including Royal Dutch Shell Plc, Exxon Mobil Corp., BP Plc and Chevron Corp. about reactivating dormant contracts in the country, said J. Jay Park, managing director of Petroleum Regimes Advisory, who provides legal advice to the government. Oil companies haven’t operated in the country since civil war erupted in 1991 and they were forced to declare force majeure.
Yemen Geology
“It is in Somalia’s interest that these companies are given every opportunity to return,” Omar said.
While Somalia has no proven oil reserves, drillers are betting the country has a geology similar to that of Yemen, which lies across the Gulf of Aden and has 2.7 billion barrels of proven oil reserves.
Somalia’s oil deposits may amount to as much as 110 billion barrels, according to a June report published by the Mogadishu-based Heritage Institute for Policy Studies. Saudi Arabia, the world’s biggest oil exporter, has 266 billion barrels of proven reserves, BP data shows.
The results of seismic surveys carried out by Soma Oil & Gas Holdings Ltd., a London-based exploration company funded by Russian billionaire Alexander Djaparidze, are expected to be submitted to the government by the beginning of next year, Chief Executive Officer Robert Sheppard said in an interview at the conference. The survey, completed at a cost of $37 million, was finished without any security issues, he said.
$100 Million
“This Soma activity has demonstrated that seismic can be done in offshore Somalia,” Shell Vice President for Exploration in Sub-Saharan Africa Alastair Milne said at the conference. “But it will take more detailed technical work before we can pinpoint that place to drill, and that will likely require investment well in excess of $100 million.”
An oil and gas revenue-sharing bill has been drafted and is moving through consultations with the emerging federal member states, Omar said. Somali officials at the summit were unable to provide a timeframe for when the law might be passed.
For now, the provisional federal constitution allows the federal government to award blocks and make deals with international oil companies after consultations with the states, Omar said.
A UN monitoring group report on Somalia published last week flagged increased onshore commercial activity as a risk that may trigger conflict, recommending that no contracts with oil and gas companies be signed until “appropriate constitutional, legislative, fiscal and regulatory provisions had been clarified and agreed to by the federal government and its regional authorities.”
(An earlier version of this story corrected the title of the conference in the second paragraph.)
By Miami Herald
Forty—one years ago this month, the Arab oil embargo began. The countries that were part of it belonged, of course, to the Organization of Petroleum Exporting Countries — OPEC — which hadbanded together 13 years earlier to strengthen their ability to negotiate with international oilcompanies. The embargo led to widespread shortages in the United States, higher prices at thegas pump and long lines at gas stations. By the time it ended, the price of oil had risen to $12 abarrel from $3.
Perhaps more important than the price increases themselves was the new world order theembargo signaled. The embargo “set in motion geopolitical circumstances that eventually allowed (OPEC) to wrest control over global oil production and pricing from the giant international oilcompanies — ushering in an era of significantly higher oil prices,” as Amy Myers Jaffe and Ed Morse noted in an article in Foreign Policy magazine that was published last year at the 40thanniversary.
Twice a year, OPEC’s oil ministers would meet in Vienna, where they would set oilpolicy — deciding to either hold back or increase oil production. There was always cheatingamong members, but there was usually enough discipline in the ranks to keep prices more or lesswhere OPEC wanted them.
As it happens, the title of that Foreign Policy article was, “The End of OPEC.” Jaffe and Morse areboth global energy experts — she is the executive director of Energy and Sustainability at theUniversity of California, Davis, and he is the global head of commodities research at Citigroup —who say that if America plays its cards right, OPEC’s dominance over the oil market could be over.
I think that day may have already arrived.
“OPEC is not going to survive another 50 years,” Morse told me. “It probably won’t even surviv another 10. It has become extremely difficult for them to forge an agreement.”
When Morse and Jaffe wrote their article last year, the price of oil was more than $100 a barrel.
Today, the per-barrel price is in the low- to mid-$80s. It has dropped more than 25 percent sinceJune. There was a time when $80 a barrel would have been more than satisfactory for OPECmembers, but those days are long gone. Venezuela’s budgetary needs requires that it sell its oil at well above $100 a barrel. The Arab Spring prompted a number of important OPEC members —including Saudi Arabia and the United Arab Emirates — to increase budgetary spending to keeptheir own populations quiescent. According to the International Monetary Fund, the United Arab
Emirates needs a price of more than $80 to meet its budgetary obligations. That’s up from lessthan $25 a barrel in 2008.
Not long ago, Venezuela asked for an emergency OPEC meeting to discuss decreasing production.
Iran has said that such a meeting is unnecessary. Meanwhile, Saudi Arabia has made it clear thatit is primarily concerned with not losing market share, so it will continue to pump out oil regardlessof the needs of other OPEC members. This is not exactly cartel-like behavior. The next OPECmeeting is scheduled for late November, but there is little likelihood of an agreement.
And why does OPEC suddenly find itself in such disarray? Simply put, the supply of oil is greaterthan the demand, and OPEC has lost its ability to control the supply. Part of the reason is aslowdown in global demand. China’s economy has slowed, and so has its voracious appetite foroil. Japan, meanwhile, is increasingly turning to natural gas and nuclear power.
But an even bigger part of the reason is that the shale revolution in North America is utterlychanging the supply-demand dynamic. Since 2008, says Bernard Weinstein, an energy expert at
Southern Methodist University, oil production in the United States is up 60 percent. That’s anadditional 3 million barrels a day. Within a few years, predicts Morse, America will overtake Russiaand Saudi Arabia and become the world’s largest oil producer.
What’s more, according to another article Morse wrote, this one for Foreign Affairs magazine, “thecosts of finding and producing oil and gas in shale and tight rock formations are steadily goingdown and will drop even more in the years to come.” In other words, the American energy industrymight well be able to withstand further price drops easier than OPEC members.
When I got Jaffe on the phone, I asked her if she thought OPEC was a spent force. “You can neversay never,” she replied, and then laid out a few dire scenarios — mostly revolving around oil fieldsbeing bombed or attacked — that might make supply scarce again. But barring that, this is amoment we’ve long been waiting for. Thanks to the shale revolution, OPEC has become a papertiger.
By Andy Tully | Tue, 21 October 2014 21:52 | 0
When the Norwegian energy company Norsk Hydro explored a prospective oil well in the North Sea in 1992, it found only an estimated 6 million barrels of crude, then abandoned it. Now Norway’s energy giant Statoil says it’s found more than 10 times that amount in the well.
Statoil announced Oct. 21 that it has found between 30 million and 80 million barrels of recoverable oil at the site, named Well 25/8-18 S, off the southwestern coast of Norway. What makes the discovery more attractive is that it’s close enough to the Grane oil field – just four miles away – that the two can share some drilling resources, making extraction less expensive for Statoil.
“These [newly discovered] barrels are very profitable,” Trond Omdal, an analyst with Pareto Securities, told Reuters. “You can use the existing installation [at Grane] and extend the life of it.” In its announcement, Statoil said it is considering doing just that.
May-Liss Hauknes, Statoil’s vice president for exploration in the North Sea, said in a statement that the discovery “is a result of a recent re-evaluation of the area” by means of “new seismic and improved subsurface mapping.”
“We are pleased with having proved new oil resources in the Grane area,” Hauknes’ statement said. “It provides high-value barrels that are important for extending the production life of existing installations.”
The Norwegian Petroleum Directorate says the Grane field, which has been in operation since 2003, was the country’s third most productive oil field in 2013 at about 95,000 barrels per day.
Grane is in the Utsira High area of the North Sea, the site of Norway’s biggest oil find in decades, the Johan Sverdrup oil field. Statoil is in charge of operations at Grane.
Statoil owns 57 percent of Grane, while the Norwegian energy licensing company owns 30 percent and Exxon Mobil Corp. has a 13 percent share. The Norwegian state-controlled company found as much as 33 million barrels of oil in the same formation in a neighboring license in 2013.
The discovery of plentiful oil in Well 25/8-18 S could help shore up Statoil financially. Like other energy companies, stock in Statoil has been taking a beating recently.
Part of the reason for this decline has been a weakening global economy, a rise in the value of the U.S. dollar and a glut of oil and natural gas, thanks in large part to burgeoning American production due to new extraction techniques, including horizontal drilling and hydraulic fracturing, or fracking.
Of particular concern are weakening economies in countries including Germany and China, whose industrial bases have lagged recently, putting further downward pressure on the prices of crude and gas.
The announcement of the contents of Well 25/8-18 S, though, immediately pushed Statoil’s shares up by 0.2 percent in early trading.
By Andy Tully of Oilprice.com
Slumping oil prices are putting pressure on U.S. drillers.
The number of active rigs drilling for oil and gas fell by their most in two months, according to the latest data from oil services firm Baker Hughes. There were 19 oil rigs that were removed from operation as of Oct. 17, compared to the prior week. There are now 1,590 active oil rigs, the lowest level in six weeks.
“Unless there’s a significant reversal in oil prices, we’re going to see continued declines in the rig count, especially those drilling for oil,” James Williams, president of WTRG Economics, told Fuel Fix in an interview. “We could easily see the oil rig count down 100 by the end of the year, or more.”
Baker Hughes CEO Martin Craighead predicted that U.S. drilling companies could begin to seriously start removing rigs from operation if prices drop to around $75 per barrel. Some of the more expensive shale regions will not be profitable at current prices. For example, the pricey Tuscaloosa shale in Louisiana breaks even at about $92 per barrel.
But that also reflects the high costs of starting up a nascent shale region.
Much of the shale basins that are principally responsible for America’s oil production will not feel the effects of low prices as quickly as many are predicting.
Better-known shale formations, such as the Eagle Ford in South Texas, can break even at much lower prices. That’s because exploration companies have become familiar with the geology and fine-tuned drilling techniques to specific areas.
Productivity gains have allowed drillers to extract more oil for each rig it has in operation. For example, in North Dakota’s prolific Bakken formation, an average rig is producing over 530 barrels per day from a new well in October. Less than two years ago, that figure sat at around 300 barrels per day. Extracting more barrels from the same operation improves the economics of drilling, which means shale producers are not as vulnerable to lower prices as they used to be.
Another factor that could insulate U.S. oil production is that companies also factor in sunk costs. That is, if they have already poured in millions of dollars into purchasing land leases and securing permits, throwing in a little extra money to drill the prospect is probably the rational thing to do even at current prices. It is only projects in their infancy that may not be economically feasible.
This should delay the drop in rig count, and delay the drop in overall U.S. oil production. As the Wall Street Journal notes, given these assumptions, U.S. oil production in the Eagle Ford, Bakken, and Permian could actually break even at just $60 per barrel.
Much rides on the decision making of officials in Saudi Arabia. Although exact calculations vary, the world’s only swing producer needs oil prices between $83 and $93 per barrel for its budget to break even. But that may not be as important of a metric as it appears. Saudi Arabia has an enormous stash of foreign exchange, and could run deficits for quite a while without too many problems. With average costs of oil production from wells in the Middle East sitting at only $25 per barrel, the Saudis can clearly wait out U.S. shale if they really want to.
But it may actually be Canada’s oil sands that end up being the first victim, the Wall Street Journal reports. Mining, processing, and pumping heavy oil sands from remote positions in Canada are much more costly than conventional oil and even shale oil in the U.S. While short-term operating costs are only around $40 per barrel, new projects need prices well above $90 per barrel to be in the money.
Rig counts are starting to drop, but due to the long lead time for most oil projects, it could be a while before production begins to decline in a significant way. What happens next will be largely determined by the outcome of the next OPEC meeting in Vienna on Nov. 27, where all eyes will be on Saudi Arabia.
By Nick Cunningham of Oilprice.com
By Yale Global
CHICAGO: Lee Raymond, the famously pugnacious oilman who led ExxonMobil between 1999 and 2005, liked to tell Wall Street analysts that covering the company would be boring. “You’ll just have to live with outstanding, consistent financial and operating performance,” he once boasted. For generations, Exxon and its Big Oil brethren, including Chevron, ConocoPhilipps, BP, Royal Dutch Shell and Total, dominated the global energy landscape, raking in enormous profits and delivering fat dividends to shareholders. Big Oil has long been an investor darling.
Those days are over. Once reliable market beaters, Big Oil shares are lagging: Over the last five years, when the S&P 500 rose more than 80 percent, shares of Exxon and Shell rose just over 30 percent. The underperformance reflects oil majors’ inability to maintain steady cash flows and increase production in a world where much of the easy oil has already been found and project costs are rapidly escalating. Last year, Exxon, Chevron and Shell failed to increase oil and gas production despite having spent US$500 billion over the previous five years, $120 billion in 2013 alone. Under pressure from investors, the world’s largest oil companies are now forced to cut capital expenditure and sell assets to boost cash flows.
Big Oil is, in short, heading towards liquidation. And this process has set in motion a tectonic shift in the global energy balance of power away from western international oil companies, or IOCs, and towards state-owned national oil companies, NOCs, in emerging markets. Not only do the NOCs – companies like Saudi Aramco; Russia’s Gazprom and Rosneft; China’s CNOOC, CNPC and Sinopec; India’s ONGC; Venezuela’s PDVSA; and Brazil’s Petrobras – control approximately 90 percent of the world’s known petroleum reserves, they are also immune to the market pressures constraining Big Oil.
Ironically, the rise of emerging-market NOCs and the decline of Big Oil come in the middle of the US-led fossil fuel renaissance. Thanks to higher prices that have made it cost-effective to deploy horizontal drilling technologies to unlock shale oil and gas deposits, the US is set to overtake Saudi Arabia this year as the world’s largest producer of petroleum liquids. The sudden turnaround in America’s energy-supply picture prompted President Barack Obama to shift from calling for a reduction in the country's reliance on petroleum to boasting about higher US oil production and supporting industry efforts to further increase output.
However, the euphoria surrounding new US status as a big-time energy player masks the real existential crisis facing Big Oil. With the vast majority of petroleum reserves controlled by NOCs, the majors are forced to explore in risky, inhospitable, politically unstable and remote regions such as the Arctic or deep under the ocean floor. That means high costs and an uncertain payoff. Exxon, for example, has invested US$40 billion in the Russian Arctic and elsewhere so far this year in a bid to increase output. Exxon’s joint venture with Rosneft in the Kara Sea reportedly discovered what could be a large crude deposit, but was forced to stop drilling due to US sanctions on Russia.
Oil production by the majors has been falling steadily despite a sharp rise in spending. Output peaked at 16.1million barrels per day, mbpd, in 2006 before declining to 14 mbpd in 2012, while capital expenditure increased from US$109 billon to US$262 billion over the same period. Overall, the productivity of capital expenditure by the majors has fallen by a factor of five since 2000 and is declining at 5 percent annually. At the same time costs outpace revenues by 2 to 3 percent per year, while profitability is down 10 to 20 percent.
The majors are on the horns of a dilemma. They urgently need to augment their reserves to avoid becoming a business with no future, simply running down inventory until there’s nothing left to sell. They must simultaneously keep generating strong cash flows to placate shareholders. But reserve replacement means spending more money on exploration and development of new prospects, which leaves precious little cash left over for shareholders. The majors cannot do both.
Faced with the choice of ensuring the viability of their business or placating Wall Street, Big Oil has chosen the latter. Under pressure from investment banks and investors to maintain healthy dividends and high market capitalizations, the majors have opted to prioritize cash flows over reserve replacement. In January, for example, Shell CEO Peter Voser declared that the company would discontinue production guidance – it would stop giving investors projections on future output growth – and instead focus on quarterly cash flow growth. In other words, Big Oil is committing slow-motion suicide to satisfy shareholders.
As part of their attempt to boost cash flow and profits, the majors have embarked on an aggressive program of selling assets. BP is planning to sell US$10 billion in oil producing and refining assets by the end of 2015; it will use the proceeds to buy back shares and increase shareholder dividends. Shell has begun a program to sell US$15 billion in assets to pay down debt incurred to fund capital expenditure. Total is selling a Nigerian offshore oil field among other assets to meet a US$10 billion cash-flow target for 2015.
NOCs are already outspending the majors in exploration and production and have been driving global energy mergers and acquisitions as they seek access to resources, technology and skilled labor. Big Oil’s divestment program is an attractive opportunity for them to further increase their energy footprint and control resources at fire-sale prices. So far Nigerian and Gulf NOCs and sovereign-wealth funds have been most active buyers of IOC assets. Several Nigerian companies such as Seplat and Oando have purchased upstream operations previously owned by ConocoPhilipps and Shell Nigeria, respectively. In February, the Abu Dhabi Investment Council was among the buyers for Shell’s refining operations in Australia. Kuwait Petroleum International purchased Shell’s Italian retail operations earlier this year.
NOCs in net oil-importing countries, such as China, India and South Korea, are set to drive the next wave of IOC asset acquisitions. For Chinese companies especially the majors’ divestment program provides an invaluable opportunity to lock up resources and project power overseas. Led by CNPC, Chinese state-owned energy companies have expanded aggressively in projects from Canada to Kazakhstan to Australia. By next year, Chinese NOCs international operations are expected to produce the equivalent of Kuwait’s oil production, according to the International Energy Agency.
The relative power of NOCs in the global energy market is set to increase further if oil prices remain subdued. According to Goldman Sachs, the vast majority of listed IOCs require oil prices in excess of US$100 per barrel to maintain current levels of capital expenditures and dividends. With oil now falling below US$95, the financial and operational pressure on Big Oil will only intensify.
As the US and Europe's leverage over the global energy landscape dissipates, it will fall to the NOCs to provide leadership on climate change. If they continue to expand production, lower oil prices will continue to lock us into fossil-fuelled growth. According to BP, the world has more than 53 years of oil reserves remaining. That's much more than what we can afford to burn and still preserve life as we know it. This is the next big test.
By Deepak Gopinath
(Source: YaleGlobal, 16 October 2014)
By Claude Salhani | Tue, 21 October 2014 22:02 | 0
While still a predominant factor in the war being waged by the Islamic State, oil is taking a back seat as the full brunt of Middle East-style politics is unleashed on and around the small Syrian border town of Kobani.
The oil extracted from this region in a large part helps the Sunni terror group finance its war.
The battle for control of Kobani has indeed seen some of the heaviest fighting to date as fighters loyal to the Islamic State, or IS, have launched renewed attacks on Kurdish Peshmerga defenders, hitting them with mortars and car bombs, according to wire agencies quoting sources in the besieged town.
The Kurds, who are indigenous to the region where the heavy fighting is unfolding, in a way represent the West’s last line of defense in the region. If the Kurds fail to hold Kobani, they have nowhere to fall back. The next line of conflict between IS and the U.S.-led coalition will be fought inside Turkey, a NATO country.
Already, Turkish border towns and villages have suffered badly from the ongoing violence. One report said 44 mortars had been fired at Kurdish positions over the weekend, with some of the shells falling inside Turkey.
The London-based Syrian Observatory for Human Rights reported that four more mortars were fired on Oct. 19.
The town has become strategic as both sides now see it as a point of significant psychological importance and a symbol for their cause.
For the fighters of the Islamic State, winning Kobani would mean it had successfully stood up to a far superior military onslaught -- the aerial bombardment being waged by the United States and its European and Arab allies.
For the Western-led alliance, the fall of Kobani would give the enemy a public relations victory. It would create favorable conditions for IS to recruit more volunteers and be a terrible blow for the Kurds and other groups engaged in fighting the radical Islamists.
Since U.S. President Barack Obama launched the campaign aimed at defeating IS, bombing raids against the terrorists have been carried out with renewed vigor. But will it be enough? Or will the United States be forced to eventually put reluctant boots on the ground? The fate of the beleaguered town will say a lot about the level of the Obama administration’s resolve for dealing with the threat posed by the Islamists.
Amidst the confusion of war, there is further opaqueness over the role of Turkey, a NATO member country who seems to be playing both sides of the fence. Turkey has its armed forces – the most powerful military in the Middle East -- deployed along its border with Syria, yet Turkish authorities have been reluctant to intervene.
The moderate Islamist party known as the Justice and Development Party rules Turkey, but Ankara also must comply with certain directives issued from NATO HQ in Brussels.
But Turkey, who has long had its own share of problems with the Kurds is reluctant to offer too much help to the Kurdish fighters in Kobani, lest it encourages its own Kurds to demand an independent Kurdish state.
At the same time, the country’s leader, Recep Tayyip Erdogan, has a personal vendetta against Syrian President Bashar Assad, and has been trying to connect any cooperation by Turkey in the fight against IS to stepping up efforts to oust Assad. Given the geography of the region, Turkey’s participation on the fight against IS remains vital to the success of the campaign.
By Claude Salhani of Oilprice.com
By Voice Of America
Russia and Ukraine failed to strike an interim gas deal in Brussels on Tuesday, with both sides holding out for guarantees on payment and price.
European Union negotiators, however, are hoping for an agreement next week.
After hours of talks, efforts to resolve a natural gas pricing dispute between the neighboring countries proved fruitless, but there was at least a draft accord.
Speaking through an interpreter, European Union Energy Commissioner Guenther Oettinger told reporters he hoped an interim agreement would be sealed in Brussels next week.
"We have made some important progress, and thanks to goodwill [by] all of the partners, we hope we will reach an agreement on an interim package for Ukraine," he said. "We're looking for a solution to provide gas supply security in the European Union, the Western Balkans and, of course, for Ukraine."
Russia's state-run company Gazprom stopped gas deliveries to Ukraine earlier this year over a pricing and debt disagreement, amid an ongoing insurgency by pro-Russian separatists in eastern Ukraine.
The fighting has also sunk European and Russian relations to lows not seen in years. Moscow denies any role in the insurgency.
Roughly one-third of Europe's gas supplies is piped from Russia through Ukraine, and the EU fears the ongoing dispute could lead to supply cuts during the winter months.
In Milan last week, the presidents of Ukraine and Russia sketched the broad outlines of a deal, but their energy ministers failed to lock in the details Tuesday.
Russian Energy Minister Alexander Novak said Ukraine and the EU failed to offer guarantees that Ukraine can pay its November and December gas bills — and its past debts.
"Ukraine should pay, before gas deliveries, $1.45 billion," he said. "This is for the arrears. So this amount is the debt. The minimal amount. And then the current supplies should be in advance — payments for November."
Ukraine has asked the EU for an additional $2.5 billion loan, on top of a $14 billion aid package the 28-member bloc has already agreed on.
That would help Kyiv meet Gazprom's demands that it pay all its past debts — totaling more than $3 billion dollars — by year's end.
By Diplomat
Since the disaster at its Fukushima Daiichi Nuclear Power Plant in March 2011, Japan has faced a highly uncertain energy future. Despite the government’s best attempts to begin restarting the country’s 48 nuclear reactors, popular sentiment has remained opposed to any such generalized restart. As a result, and despite the fact that some of its reactors may indeed come back online over the next few years, Japan is planning for a future where nuclear energy no longer plays a significant role in its energy mix.
The country’s own geology is a large part of this new direction in energy policy. While the government’s Nuclear Regulation Authority (NRA) has set much more stringent guidelines regarding safety measures at nuclear plants, and Japan has one of the most sophisticated systems in place for detecting geological activity like earthquakes and volcano eruptions, the inability to predict the eruption of Mount Ontake on September 27 highlighted the limited utility of these safety measures. Indeed, Toshitsugu Fujii, a volcanologist and professor emeritus at the University of Tokyo told Reuters last Friday that the Tohoku Earthquake of 2011 may end up causing larger and more frequent volcanic eruptions. He said that “The 2011 quake convulsed all of underground Japan quite sharply, and due to that influence Japan’s volcanoes may also become much more active.” He added that, “It has been much too quiet here over the last century, so we can reasonably expect that there will be a number of large eruptions in the near future.”
As a result of recent reports like this, Japan appears to be heading toward a two pronged approach: a diversification of its LNG sourcing over the short to medium term while planning for greater and more efficient use of renewable energy. While LNG is already a large part of Japan’s energy mix, it plans to reduce its dependence on the Middle East and focus more on cheaper supplies from North America and Australia. By 2020, Japan plans to import 70 percent of its LNG needs from these sources, with 40 percent coming from fields in Australia that Japan is currently helping to develop, and the rest from the U.S. and Canada. Japan hopes to reduce costs by importing from these closer and more stable sources, with the additional benefit of U.S. imports costing about 20 percent less than its current LNG.
Japan’s plans for a greater percentage of renewable energy will be more difficult to implement, yet it has already made significant progress. After instituting a Feed In Tariff system for renewable resources in 2012 to increase the percentage of this energy source by obligating utilities to buy the energy at set prices (which were transferred to consumers), the government hoped that renewables would contribute 30 percent of Japan’s energy usage by 2030. However, the plan has hit a significant snag as utilities claim this increase in renewables is unstable given the current energy grid, and could cause blackouts.
A sub-committee for the economy, trade and industry ministry is attempting to work out a solution. The would entail making solar energy prices under the FIT more competitive for the utilities, which would slow the rate that new solar sources come online. The government is also considering putting a cap on the cost that could be passed on to the consumer, as at current rates of new solar development that could reach 10,000 yen ($93) per household. These two policies would slow the rapid development that has occurred in solar energy at the expense of other sources like wind and hydroelectric, which may lead to a more balanced renewable energy base in the future.
The economy, trade and industry ministry on Tuesday is also proposing another idea to reduce overall energy usage. The “negawatt” exchange system would allow utilities to contract with businesses and households to agree to ways to conserve energy usage. Through methods such as lowering air-conditioning usage and installing more energy efficient lighting, users will effectively be “selling” utilities back their energy at roughly 10 to 100 yen per kilowatt hour. The government expects the system could begin as early as 2017, with businesses being brought in first and later households with the use of smart meters. A similar system is already in place in the U.S., where “power equal up to 10% of demand is said to be traded.”
DUBAI: Saudi Arabia’s closure of an offshore oilfield it shares with Kuwait has revived speculation of renewed tensions between the two, and put Chevron’s role in the shared Neutral Zone in focus. Crude output from their jointly-run offshore Khafji oilfield has been halted temporarily to comply with environmental rules. “Little things lead to big things, it’s an accumulation of the past. Each party says a different story,” said Kamel Al-Harami, an independent Kuwaiti analyst.
The loss of Khafji’s 280,000 barrels per day of Arabian Heavy crude will be felt more in Kuwait, which has far less spare output than its neighbor, the world’s top oil exporter. Oil prices rose briefly to over $86 a barrel on Monday on the news. Any differences between the two OPEC allies are watched closely by oil majors getting ready to return to Kuwait after years of fruitless talks and fierce political opposition to foreign firms taking a role in production in the past.
Diplomatic and industry sources said that Kuwait has been placing restrictions on the Saudi unit of US oil major Chevron which operates another jointly run Neutral Zone field, Wafra, as a result of various disputes. The curbs have affected oil output from the Neutral Zone, which dates back to 1920s treaties to establish regional borders.
Output capacity from the Zone has been around 600,000 bpd until last year, according to the US Department of Energy. But industry sources say it has been in decline in recent months even before the Khafji shutdown. A Chevron spokesman said the company complies with the laws and regulations of the countries where it operates, and does not comment on discussions it has with governments about its business operations. The Saudi’s 60-year concession with Chevron was first granted to the US Getty Oil Company in 1949. Texaco acquired Getty Oil in 1984, and Chevron took over Texaco in 2001.
A senior Kuwaiti official dismissed any political implications and said the Kuwaiti side was informed of the Khafji shutdown. Recently, Kuwait’s oil marketers have been challenging their Saudi counterparts in an increasingly competitive battle for market share, selling oil to buyers in Asia at the widest discount to a comparable Saudi grade in 10 years.
Kuwait’s objections
The sources say Kuwait was angry because it was not consulted when the Chevron concession to operate Wafra was renewed by Riyadh in 2009 until 2039. But the row goes back even further, to 2007, when a land dispute between Kuwait and Saudi led to a delay in Kuwait’s plans to build an oil refinery. Chevron has had a lease on some of the land on Kuwait’s side which was earmarked for the new refinery.
In recent months, Kuwait has been making it more difficult for Chevron to acquire work permits to operate in the Zone, because of legal misinterpretation of the agreement, the sources said. “Kuwait has been giving Chevron a hard time,” one diplomatic source said. Chevron is leading a full-field steam injection project in the onshore Wafra field to boost output of heavy oil there by more than 80,000 bpd. Last year, Saudi Arabia and Kuwait shelved a project to develop another venture in the Neutral Zone, the Dorra offshore gas field, after disagreeing over how to share the gas back on land.
Kuwait blames Riyadh for ending that project despite its desperate need for gas for power generation. “These issues between the two countries have started several years ago. Relations soured when Saudi stopped the Dorra project from proceeding,” said another Kuwaiti official. He added there have been also disagreements over the distribution of investments costs with the Saudi side. Dorra has long been a bone of contention between Kuwait and Iran, which also lays claim to part of the field.
Kuwait agreed with Riyadh in 2000 to jointly develop the field they desperately need to satisfy their growing gas need. More than a decade on, little progress has been made and it has now been shelved indefinitely. The Neutral Zone is the only place in Saudi Arabia and Kuwait where foreign oil firms have equity in fields, which are otherwise owned and operated by state oil companies. Crude output is divided equally between the two countries. It survived the nationalization of the Saudi oil industry in the 1970s. Since then, Saudi reserves of 264 billion barrels – around a fifth of the world’s proven oil reserves – have been off limits to international oil companies.- Reuters
DUBAI/KHOBAR, Saudi Arabia, Oct 21, (Agencies): Saudi Arabia’s closure of an offshore oilfield it shares with Kuwait has revived speculation of renewed tensions between the two, and put Chevron’s role in the shared Neutral Zone in focus. Crude output from their jointly-run offshore Khafji oilfield has been halted temporarily to comply with environmental rules. “Little things lead to big things, it’s an accumulation of the past. Each party says a different story,” said Kamel Al-Harami, an independent Kuwaiti analyst. The loss of Khafji’s 280,000 barrels per day of Arabian Heavy crude will be felt more in Kuwait, which has far less spare output than its neighbour, the world’s top oil exporter.
Oil prices rose briefly to over $86 a barrel on Monday on the news. Any differences between the two OPEC allies are watched closely by oil majors getting ready to return to Kuwait after years of fruitless talks and fierce political opposition to foreign firms taking a role in production in the past.
Diplomatic and industry sources have told Reuters that Kuwait has been placing restrictions on the Saudi unit of US oil major Chevron which operates another jointly run Neutral Zone field, Wafra, as a result of various disputes. The curbs have affected oil output from the Neutral Zone, which dates back to 1920s treaties to establish regional borders. Output capacity from the Zone has been around 600,000 bpd until last year, according to the US Department of Energy. But industry sources say it has been in decline in recent months even before the Khafji shutdown. A Chevron spokesman said the company complies with the laws and regulations of the countries where it operates, and does not comment on discussions it has with governments about its business operations. The Saudi’s 60-year concession with Chevron was first granted to the US Getty Oil Company in 1949.
Texaco acquired Getty Oil in 1984, and Chevron took over Texaco in 2001. A senior Kuwaiti official dismissed any political implications and said the Kuwaiti side was informed of the Khafji shutdown. Recently, Kuwait’s oil marketers have been challenging their Saudi counterparts in an increasingly competitive battle for market share, selling oil to buyers in Asia at the widest discount to a comparable Saudi grade in 10 years. The Saudi-Kuwaiti conflict about the Khafji Oil Field is caused by the company working in that area due to commercial, economic and administrative reasons, reports Al-Shahed daily. It started with the recruitment of Saudis in leading positions without consulting the Kuwaiti side and also because of refusing to hire a Kuwaiti in one of the senior positions.
However, the Saudi side says the issue is of a technical nature only and has nothing to do with politics. The entire file is in the hands of the Saudi Minister of Oil and Mineral Resources Abdul Aziz Bin Salman. Meanwhile, some eyebrows were raised why the Kuwaiti officials failed to come to an agreement with the Saudi authorities. And why these officials took to the media thus making the issue more complicated without taking into account the interests of both parties. The Al-Jarida daily reported a high-level Kuwaiti delegation will soon meet the Saudi authorities to look for a solution to the Khafji oil field production which has been unilaterally stopped by Saudi Arabia citing environmental pollution.
Consumption of oil products in the month at 12.3 million tonnes was 2.9% higher than 11.95 million tonnes a year ago
By Press Trust Of India
India's oil consumption rose nearly three per cent in September, while diesel sales fell for the second time this financial year.
Consumption of oil products in the month at 12.3 million tonnes was 2.9 per cent higher than 11.95 million tonnes a year ago, petroleum ministry data said.
Total sale of diesel, the most consumed fuel in the country, fell to 4.89 million tonnes during the month from 4.90 million tonnes in September 2013.
In April, too, sales had dipped to 5.92 million tonnes as compared to with 6.15 million tonnes in the corresponding month last year.In 2013-14, diesel demand dipped for the first time in more than a decade as monthly price raises and increased power generation clipped consumption.
Diesel, India's most consumed fuel, accounting for 43 per cent of the total petroleum product demand, has seen sales growth of six to eight per cent annually since 2003-04.
By Bloomberg
Petroleo Brasileiro SA (PETR4), the most indebted publicly-traded oil company, had its rating lowered by Moody’s Investors Service as lower prices and local currency weakness inhibit its capacity to rein in leverage levels.
The classification was reduced one step to Baa2, the second-lowest investment grade and in line with the rating for Brazil’s government debt. The outlook is negative, Moody’s said today in a statement.
The Rio de Janeiro-based producer’s debt increased $25 billion in the first half of this year to $170 billion, pushing the ratio of total debt to adjusted earnings to 5.3 times, Moody’s said. The company’s earnings are hampered by its inability to raise local prices for oil products, Moody’s said.
“In this case the company was caught in a lower price environment with very high leverage,” Moody’s analyst Nymia Almeida said in a telephone interview from Mexico City. “It’s going to take more time, in a nutshell, to reduce leverage.”
Leverage is only likely to decline after 2016, longer than Moody’s original estimates, because of lower international oil prices and high capex commitments, Moody’s said in a statement.
Weaker Real
“It’s a reflexion of the company’s balance sheet,” Paula Kovarsky, an analyst at Itau BBA, said in a phone interview from Sao Paulo. “We are seeing an increase in leverage levels each quarter.”
A weaker real “is a very high risk” for Petrobras because about 70 percent of its debt is in U.S. dollars, Almeida said. Brazil’s real in the last three months has lost 11 percent against the U.S. dollar, more than all other major currencies tracked by Bloomberg.
“There is a real chance the oil price stays at a $85 level for a long time,” Auro Rozenbaum, equity analyst at Bradesco BBI said in a phone interview from Sao Paulo. “It affects Petrobras and the whole industry.”
Petrobras has had success increasing output from the so-called pre-salt region in deep waters that holds Brazil’s biggest discoveries, Almeida said.
“We’re giving them the benefit of the doubt on production because of good performance in the pre-salt,” Almeida said. The company is still “far from” losing its investment grade, she said.
* Nigeria sees higher growth despite oil price risk
* To tap non-oil sector for growth, as oil revenues fall
* Naira, bond yields impacted as oil price declines (Adds comments, details)
By Camillus Eboh
ABUJA, Oct 21 (Reuters) - Nigeria expects economic growth for 2015 to reach 6.75 percent, an improvement on this year's forecast of 6.2 percent, despite the risks posed by falling global oil prices to government revenues, its finance minister said on Tuesday.
Ngozi Okonjo-Iweala said the volatility in the oil price over the past two months, coupled with production shortages in Nigeria, may force the country cut its spending while it taps its non-oil sector for revenues.
But giving the first forecast for 2015 in a year, she said the economy was growing at 6.54 percent in the second quarter of 2014 and was estimated to grow at 6.75 percent by next year.
Brent crude oil, which Nigeria produces, has lost more than 25 percent since June. Losses accelerated in October on signs the Organization of the Petroleum Exporting Countries had no plan to cut output.
"Right now we have fluctuations in prices and quality of product that we sell. We may have to cut down on expenditures, ... to mobilise more money, look more in the direction of non-oil sector," Okonjo-Iweala told a news conference. "But Nigeria is not broke."
She said Africa's biggest economy had delayed a monthly meeting where it was meant to distribute September revenues to the three tiers of government by a week.
Nigeria government revenue had been declining partly due to production outages from crude oil theft and pipeline shutdowns. Government revenue fell 4.6 percent in August to 601.6 billion naira ($3.7 billion).
The sharp fall in the oil price has also hurt the local currency and forced the government to issue bonds at higher yields to draw investors.
OIL SAVINGS
On Tuesday, the naira eased to an 8-month low of 165.55 against the dollar, as importers and companies cut their exposure to the local currency while the government priced its 3-year bond to yield 12.14 percent at its latest auction, up 102 basis points from a previous sale.
Okonjo-Iweala said "U.S. demand (for Nigerian oil) has fallen to zero but has been substituted by China and India", so sales remained strong.
Nigeria faces a hotly contested poll in February, and its fiscal position always slips around election time, when spending on patronage to secure seats surges. This one is expected to be the most closely fought since the end of military rule in 1999.
Okonjo-Iweala said Nigeria's oil savings account, the Excess Crude Account, was broadly flat since August at $4.11 billion and that its fledgling sovereign wealth fund had $1.55 billion in it.
The oil savings in the Excess Crude Account (ECA) have recovered this year, though remains way below where it was two years ago.
The ECA declined as low as $2.5 billion at the start of 2014, from around $11.5 billion at the start of January 2013, according to the central bank. (Writing by Chijioke Ohuocha; Editing by Tim Cocks and Alison Williams)
By FOXBusiness
It is time to lift the oil export ban. The boom in U.S. oil production has to change the mindset about our energy policy to better reflect the realities of today instead of the fears of the past. After the Arab oil embargo in the 1970's America was faced with tough choices and there was need for drastic action. We had to hoard our oil and cut consumption because the reality of our dependency on oil imports put or national and economic security at risk. Of course that was then and this is now. This is a new era in the U.S. of oil production, one of abundance and security, not one of desperation and fear.
The pressure is rising by our trading partners to share our oil wealth. U.S. refiners and some politicians have shown some reluctance. The refiners like to try to keep what they perceive to be a home field advantage of cheap abundant oil. Politicians fear that if they agree to lift the ban, gas prices will increase and their support will be a sound bite in their next political attack ad. You know like so and so voted for lifting the U.S. oil ban so he could raise oil prices to help his friends in big oil.
Of course these are just myths and I am not the only one that it saying this and we have a new study to back that up. The United States Government Accountability Office yesterday released a report that showed that not only would lifting the oil ban not raise gasoline prices but they would actually lower them. As for the refiners the study suggests that a growing economy in the U.S. would improve the demand outlook not only here but abroad for their varied products.
The report did say that while the cost of U.S. crude oil prices would increase by about $2 to $8 per barrel--bringing them closer to international prices, the fee flow oil would reduce international prices and, subsequently, lower consumer fuel prices.
In fact so far because of the high quality of U.S. shale oil, at this point U.S. refiners have not been able to take full advantage of its high yielding qualities. By exporting this oil to refiners in Europe that are better equipped would add to the amount of global supply.
Not only would it give legs to the U.S. oil production boom providing jobs and tax revenue. The GAO says that lifting the ban would add up to 130,000 to 3.3 million barrels per day from 2015 through 2035. It would add the GDP to create jobs and open up investment and reduce the U.S. trade deficit.
The Report also says that the shale revolution will allow us to reduce the size of our Strategic Petroleum Reserve. Let's face it our new Strategic Reserve is North Dakota. Already there is a movement by the Obama administration to lower the SPR to about to 500 million barrels down from around its 691 million barrels. That means that that U.S. government may be soon adding a lot of extra oil on the market. One reason that oil seemed to take the latest GAO report as more bearish than anything else is the market is factoring in the possibility of another source of oil in an already oversupplied market.
Yet overnight with China's slowdown not as bad as feared and refining problems causing big spikes in Midwest diesel and gas price wholesale markets. Farmers and their late harvest are driving diesel demand off the map. Gas prices are following as Midwest refinery glitches are taking their toll
While China's 3Q GDP came in 7.3 at a 5 year low it was better than expected. Gold and bonds moved higher as a shaky China will make it harder for the Fed to raise rates and money just wants to find a safe haven. Gold sellers now have the fear of QE in the U.S. back on the table making them less bold on the bearish side! China is not going to help Iron ore or copper either.
Tuesday, 21 October 2014 - 11:31pm IST | Place: Dubai | Agency: Reuters
Iran has accused fellow Muslim countries in the Middle East of plotting with the West to bring down oil prices as a tactic to further undermine its sanctions-hit economy. With oil losing a quarter of its value since June, President Hassan Rouhani's administration has been scrambling for alternative sources of income to meet its forecast for revenue in the current budget based on an oil price of $100/barrel.
Speaking to conservative Shi'ite Muslim clerics in their stronghold of Qom late on Monday, government spokesman Mohammad Baqer Nobakht said "some so-called Islamic countries in the region are serving the interests of America and (other) arrogant powers in trying to squeeze the Islamic Republic." "They (the West) have forced our oil production from 4 million bpd to 1 million bpd, and this recent fall of oil prices is their latest gimmick," he was quoted as saying by the semi-official Mehr News.
The oil price slide has been attributed to oversupply, signs of weak demand growth and the apparent reluctance of Saudi Arabia and other key producers of the Organization of the Petroleum Exporting Countries (OPEC) to cut output to lift prices. Brent crude oil held near $86 a barrel on Tuesday, having tumbled from over $110 in June. While Islamic hardliners in Iran have been quick to blame Riyadh for the price falls, Rouhani and his moderate government have been careful not to antagonise their fellow OPEC member and regional rival in the interest of better future ties.
Under growing criticism for his "passive response" to the bearish oil market, the president ordered Oil Minister Bijan Zangeneh late last week to come up with "more effective use of diplomacy" to stop a further slide in crude prices. Rouhani was elected by a landslide 14 months ago on a moderate platform but progress has been slow on both the economy and nuclear negotiations with the West, the outcome of which is closely linked to the economic outlook and reform as a political alternative in the Islamic republic.
The president himself has hedged his bets on resolving the 12-year nuclear dispute in tough talks with six world powers -- the United States, Britain, France, Germany, China and Russia, a prospect promising the lifting of sanctions and Iran's strong come back as a major oil exporter. "We should not pin our hopes on high oil prices, but seek to compensate for falling revenues with bigger volumes of exports," Abbas Ali Noura, an ex parliamentarian, was quoted as saying by Qods Online.
Iran, OPEC's second-largest producer, is normally among the first members of the Organization of the Petroleum Exporting Countries to call for supply cuts to support prices. Iran needs relatively high oil prices to balance its budget, analysts say. But in a change of tack, Iran has said this month that it can live with lower oil prices and that there was no plan for an emergency OPEC meeting to stop the slide in prices.
Some OPEC members, including Saudi Arabia and Kuwait, have indicated that the group is unlikely to cut output to support prices when it meet on Nov. 27. Some analysts suggested Saudi Arabia was willing to absorb the impact of lower oil prices to help the West and weaken Moscow and Tehran position when negotiating over Ukrainian sovereignty or the Iranian nuclear deal.
Gulf oil sources dismissed the idea as pure fiction. Riyadh had always said that it adjusts oil supply to accommodate its customers and not to drive the price.
©2014 Diligent Media Corporation Ltd.
For months, the word “oil” in Mexico has gone hand-in-hand with “reform”, with the government giddily looking ahead to a rosy future filled with billions of dollars pouring into the sector.
Then oil prices tanked and people started whispering that maybe Mexico’s energy reform was not looking so attractive after all, and maybe Mexico’s fragile economic recovery might be given another knock.
There may be an ironic silver lining, though: Given state oil company Pemex’s declining production, Mexico just might have to import oil for the first time – and falling oil prices would handily make that cheaper. (There was no immediate official word from the finance ministry or Pemex when beyondbrics asked if imports were on the cards).
Still, El Universal newspaper quotes sources at Pemex’s trading wing, PMI, as saying that the company is analysing the purchase of up to 100m barrels per day to cover domestic needs and maintain current export levels, taking advantage of the low prices in the market.
The PMI officials who declined to be named told the paper this could:
… just be temporary … until the energy reform starts to yield constant increases in oil and gas production
That is still rather a long way off, mind you. The government is targeting 3m barrels of oil per day by 2018 (about half a million more than current levels). And if it is true that lower oil prices make investors a little more wary about the reform, that goal could be further off still.
So far, no panic in the government. Fernando Aportela, finance undersecretary, says Mexico is cushioned, including by futures sales that mean that there are only about 40 days in which the actual market price impacts sales. The FT exposed Mexico’s usually secretive annual oil hedge, the biggest of its kind in commodities markets, which appeared last week to have been disrupted by oil price falls.
So is Mexico just putting a brave face on things? No, says Benito Berber, at Nomura. He reckons we should be cautious but not overly worried.
While it is true that the Finance Ministry didn’t complete the hedging program (at $80 per barrel for the Mexican mix) when the FT note was published on September 19, we think a reasonable estimate is that about half of the 180mn barrels of net oil exports were hedged. If we assume that the government resumed the program and is in the process of hedging the remaining half at $70 per barrel then the average hedge would be around $75 per barrel. Therefore, if oil prices fall below $75 pb, below the $81 oil price set for the 2015 budget, and stay below that level throughout 2015, the impact on the fiscal accounts would be roughly 0.3% of GDP assuming the USDMXN remains unchanged. If the average hedging price were $70 pb, the impact could increase to 0.5% of GDP, which seems manageable. However, if MXN [Mexican peso] depreciates then the impact on the fiscal accounts would be even smaller as oil exports in peso terms would naturally increase with a weaker MXN.
He also noted that lower oil prices are partly offset by higher petrol prices (Mexico imports half its gasoline). While petrol prices are already about 13 per cent higher than in the US, the government sets the price and is on course to increase it by some 3.5 per cent year-on-year n 2015. He adds:
In short, the wedge between gasoline prices in Mexico and the US serves as an implicit hedge against falling oil prices in terms of the fiscal accounts.
What worries him more is falling production. But he is not over concerned about investor appetite evaporating for what is seen as the big prize in Mexico: deep water, where production costs are $10-$20 per barrel and it will take a good decade to get to production anyway. He believes that unless the oil price falls further, or is permanent, then sentiment should not be too dented.
The government has said that fiscal terms for the so-called Round One – the first round of tenders – will be announced next month. Given everything, it certainly looks like Mexico is under pressure to make the terms extra friendly…
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