Singapore (Platts)--12Jun2014/812 am EDT/1212 GMT
Oman's crude and condensate production in May edged up 1.3% to 935,898 b/d, from 924,270 b/d in April, the country's oil and gas ministry said in its monthly oil report.
Oman produced a total 29.013 million barrels of oil and condensate in May, compared with 27.728 million barrels in April. The volume was up from 28.513 million barrels in May 2013.
The country's oil and condensate exports averaged 846,405 b/d in May, up 12% from April.
China remained Oman's biggest customer, receiving 76% of total exports in May, up 8% from April, according to the data.
Oman's crude and condensate production over 2013 averaged 941,949 b/d.
The country's crude and condensate output has rebounded in recent years, with its relative stability and openness to international partnerships helping it to attract large investments in challenging hydrocarbon projects.
In 2007, Oman's output bottomed out at 713,000 b/d, according to a BP Statistical Review of World Energy.
--Daniel Colover, daniel.colover@platts.com
--Edited by Jonathan Fox, jonathan.fox@platts.com
Similar stories appear in Crude Oil Marketwire See more information at http://www.platts.com/Products/crudeoilmarketwire
Houston (Platts)--12Jun2014/800 pm EDT/000 GMT
US Gulf Coast 3% sulfur fuel oil jumped $2.25 on Thursday to an eight-month high of more than $94/barrel following a spike in crude oil and swaps prices.
Gulf Coast HSFO was assessed at $94.08/b following activity in the Platts Market on Close assessment process, during which Glencore bid for Gulf Coast HSFO up to $94.05/b and was sold to by Valero for 50,000 barrels delivering June 19-21.
Gulf Coast HSFO rose by the largest amount from the previous day since rising about $2.35/b in late August, Platts data show. Furthermore, the hi-lo -- or New York Harbor LSFO's premium to Gulf Coast HSFO -- narrowed to $2.79/b, the lowest since October 21, when it was $1.90/b.
Front-month Brent rose nearly $3/b while the Gulf Coast HSFO swap jumped more than $1.50/b.
--John-Laurent Tronche, john-laurent.tronche@platts.com --Edited by Jason Lindquist, jason.lindquist@platts.com
Offshore risks main driver for Shell selling stake in Canada's Shelburne field: CAPP
Calgary (Platts)--12Jun2014/147 pm EDT/1747 GMT
Sharing of risks associated with drilling and operating in offshore areas is a prime reason for Shell divesting its 50% interest in a hydrocarbons acreage in Canada's Nova Scotia, an industry official said.
Paul Barnes, manager for Atlantic Canada and Arctic with the Canadian Association of Petroleum Producers, said late Wednesday that offshore Nova Scotia "although prospective, is still classified as a risky play."
"The provincial government has done its bit to better understand the geology, but it is still unexplored," he said.
Shell Canada announced this week it will take onboard ConocoPhillips and Suncor Energy as joint venture partners for its Deepwater Shelburne Basin Venture Exploration Program. Under a deal, Shell has agreed to sell 30% and 20% interest to ConocoPhillips and Suncor, respectively, in its Shelburne exploration licenses, while retaining operatorship, the company said.
Shell has six licenses spread over 19,845 sq km that are located in water depths of 500 meters to 3,500 meters and where it plans to spend C$998 million ($980 million) in developing the resources, the company said.
Shell conducted last year the first 3-D wide "azimuth" seismic survey over 10,850 sq km and in the spring of 2015 it plans to carry out a seabed survey to assess potential drilling locations, the company said, noting the first two wells will likely be drilled in second-half next year.
It is too early to talk about probable resources at the Shelburne Basin, Barnes said, adding shallow waters in Nova Scotia is gas prospective while deepwater blocks are likely to be oil prone.
"That is thought until now and it will only be known when the drill bit hits the seabed. Shell is hoping it will be oil that will already have a market in refineries in both the US' and Canada's East Coast. Oil will also fetch higher margins, compared with natural gas," he said, without indicating any numbers.
In neighboring Newfoundland and Labrador, Barnes said, the geology is "different" with oil being produced at depths of less than 100 meters.
A ConocoPhillips Canada spokeswoman, Lauren Stewart, said her company will bring to the table global experience in offshore drilling, including the East Wolverine exploration project off Newfoundland's south.
"This transaction [with Shell and Suncor] expands ConocoPhillips' growing presence in our frontier deepwater exploration regions, adding to deepwater exploration acreages held offshore Senegal, Angola and Bangladesh, as well as in Malaysia and the Gulf of Mexico," she said late Wednesday in an email.
No comment was immediately available from Suncor.
Home to two of the largest gas facilities in Eastern Canada, at present Nova Scotia does not produce any crude oil. The gas fields are Deep Panuke and Sable Offshore that produce a total of some 500,000 Mcf/d.
However, the province is estimated to hold resources of 8 billion barrels of crude oil, its Natural Resources Minister Andrew Younger said in an February 17 interview.
"There has been exploration off the Nova Scotia coast and they have mostly been in the shelf area," he said then. "But, with a better understanding of the geology the industry interest is now getting into deep waters."
--Ashok Dutta, newsdesk@platts.com --Edited by Katharine Fraser, katharine.fraser@platts.com
London (Platts)--12Jun2014/813 am EDT/1213 GMT
The Urals crude market strengthened sharply Wednesday in both Northwest Europe and the Mediterranean as buying interest increased sharply to clear some remaining prompt June cargoes.
Differentials for CIF Augusta Urals Aframax cargoes climbed $0.445/barrel Wednesday to be assessed at a $2.335/b discount to the Mediterranean Dated Strip. The climb marked a sharp reversal in the market, where differentials have been falling steadily since early April.
In the Platts Market on Close assessment process, Vitol lifted an ENI offer for an 80,000 mt Urals cargo, ex-Novorossiisk, loading June 21-25 CIF basis Augusta at Dated Brent minus $2.50/b, subject vessel acceptance of Super Lady.
On Tuesday, an ENI offer of a similar cargo with a June 20-24 laycan was offered down to Dated Brent minus $2.90/b before being withdrawn ahead of the 16:30 London close.
Market sources said that while there is still June Urals volume available in the Mediterranean, most of the remaining cargoes are available on larger, Suezmax vessels, while the Aframax market has largely been sold.
A Litasco bid for an Aframax Urals cargo loading June 24-28 CIF basis Augusta was left outstanding at Dated Brent minus $2.40/b at the London close.
"It's bizarre, really," a crude trader said. "I think people were scared to buy because the market kept falling, and it bottled up the demand, and when people sensed that it had bottomed out they started buying."
Differentials for CIF Rotterdam Urals cargoes also climbed Wednesday, up $0.265/b from the 26-month low seen Tuesday to a discount of minus $3.225/b relative to the Mediterranean Dated Strip Wednesday.
In the Platts MOC, a Totsa bid for a 100,000 mt Urals cargo, ex-Primorsk/Ust-Luga, loading June 28 to July 2 CIF basis Rotterdam was left outstanding at Dated Brent minus $3.25/b at the close.
"Overall in terms of sentiment, [the market] is on the upside," a crude trader said, but added that nothing had so far traded at higher levels.
--Paula VanLaningham, paula.vanlaningham@platts.com
--Edwin Yeo, edwin.yeo@platts.com
--Edited by Jeremy Lovell, jeremy.lovell@platts.com
Similar stories appear in Crude Oil Marketwire See more information at http://www.platts.com/Products/crudeoilmarketwire
By Indira A.R. Lakshmanan and Anthony DiPaola Jun 13, 2014 2:17 AM GMT+0700
Iran’s oil exports have risen this year, according to Bloomberg calculations, a trend that threatens to violate U.S. sanctions on the Islamic Republic’s main source of revenue.
Shipments of Iranian crude oil and condensate have increased about 28 percent on average this year, according to an analysis of customs data from importing nations and figures from the International Energy Agency in Paris. If crude sales are up by the end of July, that would break an international accord to hold Iran’s oil exports at the same level in the first half of this year that they were at in the previous six months.
Questioned in Congress yesterday about possible sanctions violations, an Obama administration official who monitors Iran’s oil exports said he’s confident Iranian crude shipments have remained within the limits set in a six-month agreement signed Jan. 20 that granted Iran limited sanctions relief in exchange for some nuclear concessions.
“Where we are today, we feel comfortable that the crude oil exports of Iran are remaining in the 1 million to 1.1 million barrels per day average,” Amos Hochstein, deputy assistant secretary of state for energy diplomacy, testified before the House Foreign Affairs Committee.
The U.S. Congress passed legislation in December 2011 to curtail Iran’s oil exports in an effort to deprive the Persian Gulf state of its leading foreign revenue earner, to pressure its leaders to accept constraints on a suspected nuclear weapons program. A month later, the European Union approved an embargo on Iranian oil purchases by its members.
Six Buyers
Only six buyers are still allowed to take crude from Iran - - China, India, Japan, South Korea, Turkey and Taiwan -- down from 21 before the restrictions went into effect in mid-2012.
Among the reasons that exports in the first few months of this year look higher are seasonal variations in oil purchases and the fact that reporting lags shipments and customs data are sometimes revised, according to two U.S. officials who weren’t authorized to be quoted.
Another reason is that while India’s crude imports from Iran were up significantly in the first few months of this year, its refiners have signed contracts for lower purchases in the coming months, which should bring down Iran’s average exports by July, the officials said.
The Obama administration says Iran’s oil exports have been reduced by more than half from 2.5 million barrels a day before sanctions. The U.S. also says Iran is losing as much as $5 billion a month in oil revenue.
Iranian Minister
Customs and other publicly available data, though, show that Iran’s exports of crude and condensates rose to an average of 1.33 million barrels a day in the first four months of this year from 1.04 million barrels a day on average in 2013, according to Bloomberg calculations.
Iranian Oil Minister Bijan Zanganeh, asked by a reporter at an OPEC meeting in Vienna yesterday, gave a higher figure, saying the Persian Gulf producer is exporting 1.2 million barrels of crude oil and 300,000 barrels of condensate a day.
U.S. officials say Iran consistently inflates trade figures to create an illusion that sanctions are crumbling.
Using customs and ship-tracking data to assess Iran’s oil export quantities is complicated by the fact that crude and condensates can be transported by the same type of tanker or blended together and that some countries combine the two in their import data.
Condensate, a light petroleum liquid often found with oil or gas, is not restricted by U.S. sanctions as long as the buyer nation was granted a waiver from the sanctions by reducing the amount of crude oil it buys from Iran.
Chinese Purchases
China has considerably increased its purchases of Iranian condensate this year, and that has inflated overall import figures, according to the two Obama administration officials who spoke on condition of anonymity. U.S. officials say Iran may be offering China and other customers significant discounts on condensate and crude in an attempt to keep sales flowing despite punishing sanctions.
Although Iran exports condensate in much smaller quantities than crude oil, the product fetches higher prices because it’s easier and less expensive to refine into gasoline or diesel fuel.
Richard Mallinson, an analyst at Energy Aspects Ltd., a London-based consultancy, said Iran is set to sell an average of more than 1.3 million barrels of crude oil and condensates a day in the first half of the year, up from last year’s combined average of 1.06 million barrels, he said.
Higher Exports
“However you choose to define it, exports are running higher than they did last year,” Mallinson said in a phone interview. “What’s become clear is that for the U.S., achieving a comprehensive deal” to curb Iran’s nuclear program “is too valuable to risk over the fact that Iran’s oil exports will be more than the desired levels.”
Mark Dubowitz, executive director of the Foundation for Defense of Democracies in Washington, who’s advised Congress on ways to tighten sanctions against Iran, said lenient enforcement of oil sanctions during the negotiations sends a bad message.
“If this is an example of how strictly they will enforce any final nuclear agreement with Iran, then Iran should feel more confident that they will be able to exploit any loopholes with impunity,” he said.
Crediting Sanctions
At a Senate Foreign Relations Committee hearing today, several members expressed concern that Iran may be circumventing sanctions, just as it may intend to bypass any negotiated restrains on its nuclear program if a final deal is reached. Committee chairman Bob Menendez, a New Jersey Democrat, credited international sanctions as the “single most influential” reason that Iran is still at the nuclear negotiating table.
Questioned at yesterday’s House hearing by Representative Ted Deutch, a Florida Democrat, the State Department’s Hochstein explained that while most publicly available figures count crude and condensate together, the U.S. government has more accurate measures for determining if countries buying crude from Iran are complying with U.S. sanctions.
U.S. Rebuttal
“We have a lot of concerns, we are actively engaging, but we believe that countries have kept tight,” Hochstein said.
Hochstein also said that due to sanctions, payments for Iran’s oil aren’t made in hard currency; they’re still going into local-currency escrow accounts that Iran’s government may use only to buy goods in the importing nation.
“They are not getting the money and the access to the cash,” Hochstein said. “That money is still going to accounts that are blocked in those countries and have to remain, under certain conditions, in those countries.”
China, which remains the biggest buyer of Iranian crude and showed the largest increase in purchases this year, is a U.S. partner in negotiations aimed at constraining Iran’s nuclear activities. Sanctioning oil buyers such as China by blocking their banks from the U.S. financial system could derail international unity in negotiations on a nuclear accord.
Price Pressure
“Having a little more Iranian oil than was expected at the beginning of the year has been helpful,” Mallinson said. “We haven’t seen the usual mid-year price slide, which shows we came into the year quite tight. Iran pumping more crude did help, but not enough to bring down oil prices.”
West Texas Intermediate rose to an eight-month high of $106.53 a barrel today and Brent crude surged to $113.02 a barrel as violence escalated across northern and central Iraq, increasing the prospect of a return to civil war in OPEC’s second-biggest oil producer. Iran, previously OPEC’s No. 2 producer, slipped to fourth place after sanctions took effect.
Deutch and Florida Republican Representative Ileana Ros-Lehtinen also challenged Hochstein over reports that Iran this year has begun exporting oil to longtime ally Syria.
“Over the last few months, Iran has begun to direct shipments of crude oil to Syria for the first time” because Syria’s regime can no longer buy crude on the open market, Hochstein said. “But that is a very different kind of delivery,” he added, because Iran is giving the oil to its embattled ally for free. “This doesn’t contribute to the overall economic benefit to Iran.”
Free Oil
China remained the biggest buyer of Iranian oil, importing an average of 620,710 barrels a day of crude and condensate in the first four months of the year, according to customs data from the world’s largest energy importer. The country, which imported an average of 430,585 barrels of crude and condensate a day last year, also accounted for the biggest increase in imports of Iranian fuel.
The next round of talks between Iran and the five permanent members of the United Nations Security Council -- China, France, Russia, the U.K. and the U.S. -- plus Germany is scheduled to start June 16 in Vienna.
This week, senior U.S. officials held bilateral discussions with Iranian officials in Geneva in an effort to press Iran to be more realistic in its demands for a civilian nuclear program and assess whether it’s feasible to reach a final deal before the interim agreement expires July 20. Both sides have said an extension of the current deal is possible.
Civilian Purposes
Iran says its nuclear program is only for civilian energy and medical research. The U.S. and other world powers accuse Iran of seeking a nuclear weapons capability.
Bloomberg’s calculations for Iranian exports use data from the International Energy Agency for India because that country’s customs figures were not available for this year. Turkey’s averages purchases are based on data for the first three months of the year provided by Turkey’s government. Taiwan said it hasn’t imported any Iranian crude yet this year.
The following is a table of purchases of Iranian crude and condensate calculated from customs and import data provided by national authorities in each of the buyers listed:
----------------------------------------------------
Average purchases of Iranian crude in bbl/day
Buyer Jan.-April 2014 2013 China 620,710 430,585 India 316,250* 178,182** Japan 151,252 180,106 South Korea 134,383 132,093 Turkey 107,726*** 105,545 Taiwan 0 15,373 Total 1,330,321 1,041,884
----------------------------------------------------
* data from IEA ** April-Dec. 2013 *** Jan-March 2014
To contact the reporters on this story: Indira A.R. Lakshmanan in Washington at ilakshmanan@bloomberg.net; Anthony DiPaola in Dubai at adipaola@bloomberg.net
To contact the editors responsible for this story: John Walcott at jwalcott9@bloomberg.net; Alaric Nightingale at anightingal1@bloomberg.net
By Nicole Gaouette Jun 12, 2014 10:45 PM GMT+0700
Islamic militants’ sweep through northern Iraq and the collapse of the Iraqi army threaten to undo whatever was accomplished after the U.S. invaded the country and ousted dictator Saddam Hussein 11 years ago.
America and Europe now face the creation of a de facto militant Sunni Islamic state along the Syrian-Iraqi border that can serve as a safe haven and training zone for the Islamic State in Iraq and the Levant, a group with a declared interest in attacking the West that no country in the region can control.
For U.S. President Barack Obama, who’s built his foreign policy legacy on ending the wars in Iraq and Afghanistan, the militants’ swift victories raise questions about his 2011 decision to withdraw all U.S. troops from Iraq and his reluctance to help arm moderate Syrian rebels fighting Sunni extremists in that country.
“Now, in the middle of the Middle East, we have a big, gaping hole where the Iraqi-Syrian border has broken down,” said Andrew Tabler of the Washington Institute for Near East Policy. “It’s a threat to the regional security architecture, the boundaries of the region we’re invested in, and a threat to a lot of the assets we’ve built up inside Iraq.”
The Obama administration hasn’t responded so far to a request last month from Iraqi Prime Minister Nouri al-Maliki to mount air attacks against militant training camps in western Iraq, according to two U.S. officials who asked not to be identified discussing internal deliberations. One of the officials said Obama is reluctant to revisit a war that he opposed and repeatedly has declared over.
U.S. Options
The administration is weighing options including expedited equipment and training for the Iraqi military, according to a White House official who also asked not to be identified. Some money may eventually come from a $5 billion fund that Obama has asked Congress to approve to help U.S. allies fight terrorism.
The U.S. Senate Armed Services Committee held a closed-door briefing from Pentagon officials today on the situation in Iraq.
“Our failure to leave forces behind in Iraq was the reason” that country now is at risk of collapse, Republican Senator John McCain of Arizona, who has long denounced Obama for withdrawing U.S. troops from Iraq and now Afghanistan, told reporters after the briefing.
McCain said Obama should fire “his entire national security team, which has been a total failure.” He called for a review of all options in Iraq, short of U.S. troops on the ground. “Air strikes may be part of it,” he said.
American Lives
The Iraq war cost 4,490 Americans their lives, according to Defense Department data, and could cost U.S. taxpayers more than $2 trillion, according to the Costs of War Project by the Watson Institute for International Studies at Brown University in Providence, Rhode Island. The best estimates of Iraqi civilian casualties exceed 125,000.
The Islamic State in Iraq and the Levant, or ISIL, a group with regional ambitions and significant numbers of Western recruits, has long held areas in Anbar province to Baghdad’s west. It now has seized oil-rich areas north of the capital, including Tikrit and parts of Kirkuk province, after taking Mosul, Iraq’s second-largest city.
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Those changes are probably “semi-permanent,” said Michael Knights, a fellow with the Washington Institute. ISIL can be expected to “consolidate their hold on huge swaths of Iraq, cutting the country into three pieces” along ethnic and geographic lines, he said, an outcome the U.S. had sought to avoid during its occupation of the country from 2003 to 2011.
‘Warning Signs’
“This is not an out-of-the-blue development,” said Knights, echoing other analysts who pointed to U.S. and Iraqi policy choices that have fueled events. “It’s the culmination of many trends, warning signs ignored, enlightened paths not taken by the Iraqi government. This is a game-changing moment in the country’s security.”
Knights and other analysts, two U.S. intelligence officials, and a former Bush administration official who helped set Iraq policy said the return of Sunni extremism and the collapse of the Iraqi military are traceable in part to a series of American and Iraqi policy blunders over the years. The current and former officials asked not to be identified discussing internal policy debates.
After the decision to invade Iraq, the first mistake, said the former Bush administration official, was the May 16, 2003, U.S. edict purging all members of the Saddam’s Baath Party from the military and security services -- a move that to the puzzlement of some officials exceeded President George W. Bush’s order to de-Baathify the military only down to the rank of battalion commander.
Shiite Rule
The second blunder cited is Maliki’s use of his government and the military as a tool to enforce Shiite Muslim rule after years of Saddam’s minority Sunni oppression.
The result now, said one of the U.S. intelligence officials, is that it’s hardly surprising to find Sunni soldiers unwilling to fight others of their religion, no matter how extreme, on behalf of a Shiite government.
Given the way that Maliki “provoked, marginalized, and mistreated” Sunni Muslims, “it’s a surprise it’s taken so long for Sunnis to react,” said Wayne White, a former State Department official who worked on Iraq, off and on, beginning in the 1970s.
Maliki’s Role
The Obama administration rejects any linkage between the fall of northern Iraq and Maliki’s approach. When asked yesterday if the U.S. saw Maliki’s failure to govern inclusively as an element in the insurgency, State Department spokeswoman Jen Psaki said, “absolutely not.” The U.S. does call for Iraqi national unity in the face of the ISIL attack, she said.
The former Bush administration official flagged another issue: Obama had little choice but to withdraw the last American forces from Iraq by the end of 2011, when an agreement couldn’t be reached granting them immunity from prosecution in Iraqi courts, the former official said. Their departure, however, undid both the gains made rebuilding Iraqi security and the progress that the “surge” of U.S. forces in Anbar and other Sunni provinces made toward marginalizing Sunni extremists.
“We shouldn’t have walked away from Iraq,” said Ken Pollack, a senior fellow at the Brookings Institution, a Washington policy group, pointing to the Obama administration’s decision to withdraw all troops. Pollack says that a troop presence would have dealt with the fear and mistrust that characterizes inter-communal conflicts and curbed Maliki’s ability to make sectarian power grabs.
Syrian Opposition
“This is nothing 10,000 or 20,000 troops couldn’t have fixed,” Pollack said.
Tabler pointed to the administration’s decision not to arm the moderate Syrian opposition, which has been fighting ISIL in Syria, even as it also combats Syrian President Bashar al-Assad’s troops.
The administration’s “approach to Syria has been to say that it’s containable, that we don’t need to get more involved,” Tabler said. “Well, it’s not containable. It’s spilling over into Lebanon and Iraq, and only becoming more extremist in nature.”
Compounding the problem, said one of the U.S. intelligence officials, is that training of Iraqi special forces has focused almost exclusively on combating limited local insurgencies, not the type of offensive that ISIL has mounted this week.‘Real Army’
ISIL is highly organized, disciplined, and battle-hardened, “a real army” equipped with anti-aircraft guns, .50 caliber sniper rifles and heavy machine guns, according to Douglas Ollivant, a senior vice president at Mantid International, a global consulting firm with offices in Washington and Baghdad. The group also has at least hundreds of members with European Union passports, according to Ollivant.
The speed and extent of the ISIL offensive and the disintegration of Iraqi forces, who left almost all their weaponry and equipment for ISIL to collect, has caught the Obama administration off-guard, said the two intelligence officials.
The more than $14 billion in foreign military assistance that the U.S. has provided to Iraq since 2005 includes F-16 fighter jets, Apache attack helicopters and M-16 and M-4 rifles, and the U.S. has been training Iraqi forces in Jordan and elsewhere. At least two F-16s are scheduled for delivery to Iraq this fall, and the country will lease six Apaches for training later this year, two U.S. defense officials said yesterday.
Captured Weapons
So far, the officials, who spoke on the condition of anonymity to discuss intelligence matters, said they’ve seen no evidence that the Sunni militants have picked up Hellfire anti-armor missiles or other weapons that could threaten American, Israeli or other forces in the region.
There is some evidence, they said, that ISIL is delivering some captured weapons, including machine guns, rifles and vehicles, to its fellow militants in Syria.
Asked about reports that ISIL has captured tanks and ammunition, Psaki said the U.S. is “trying to obtain confirmation on what assets ISIL may have obtained on the ground.” The situation on the ground, she said, “is very murky.”
To contact the reporter on this story: Nicole Gaouette in Washington at ngaouette@bloomberg.net
To contact the editors responsible for this story: John Walcott at jwalcott9@bloomberg.net Larry Liebert
By Glen Carey and Mahmoud Habboush Jun 12, 2014 9:21 PM GMT+0700
The jacket from an Iraqi Army uniform in front of the remains of a burnt out Iraqi army vehicle close to the Kukjali... Read More
This image made from video posted by Iraqi0Revolution, a group supporting the al-Qaida breakaway Islamic State of... Read More
Iraqi forces sought to check the rapid advance of Islamist militants who had seized major cities, as Prime Minister Nouri al-Maliki responded to the greatest threat to his government since taking power.
The military attacked fighters of the Islamic State in Iraq and the Levant in Saddam Hussein’s former hometown of Tikrit, about 80 miles (130 kilometers) north of Baghdad, state-sponsored Iraqiya television reported. In Mosul, the air force struck ISIL positions after they seized the largest city in Iraq’s north earlier this week, Iraqiya said. Al-Sumaria television reported heavy clashes as the army fought for Tikrit backed by air support.
The surge in violence across northern and central Iraq, three years after U.S. troops withdrew, has raised the prospect of a return to sectarian civil war in OPEC’s second-biggest oil producer. Al-Maliki’s Shiite-led government is struggling to retain control of Sunni-majority regions, and his army units in northern Iraq collapsed in the face of the Islamist advance.
“This can’t be looked at as anything other than a comprehensive failure by the Iraqi army,” Crispin Hawes, managing director of the research firm Teneo Intelligence in London, said in a phone interview. “If the army can’t protect Mosul, how are they going to protect other cities?” he said. “Moving southward would be the logical thing to do for ISIL.”
Oil Prices
The advance of ISIL fighters has rattled oil futures and markets in both Iraq and Turkey. Brent crude oil rose to the highest since the start of March and West Texas Intermediate to an eight-month high amid the violence.
Kurdish authorities, who control the territory to the east of Mosul, have fortified defenses around their borders and also dispatched their armed forces to take control of Kirkuk, home to the biggest northern oilfield, the semi-autonomous Kurdish government said on its website.
There were conflicting reports from Baiji, a town north of Baghdad that’s home to the nation’s largest refinery. Output at the 310,000 barrel a day plant stopped after militants seized the facility overnight, according to a police statement today.
Oil Minister Abdul Kareem al-Luaibi said in an interview in Vienna that the government was still in control of the refinery, speculating that U.S. jets may play a role in the government-led offensive.
State of Emergency
The U.S. has yet to respond to a request from Iraq made last month to mount air attacks against militant training camps in western Iraq, according to two American officials who asked not to be identified discussing internal deliberations. One of the officials said President Barack Obama is reluctant to revisit a war that he opposed and has repeatedly declared over.
Iraq’s parliament delayed a session to debate the imposition of a state of emergency as it lacked the number of members needed to vote on the decision, Iraqi state-sponsored Al-Baghdadia TV reported. Al-Maliki had asked parliament for emergency powers to battle ISIL.
The premier’s office also said that in response to popular demand, volunteers will be enrolled at national security offices to help in the fight against ISIL.
Brent rose as much as 2.2 percent to $112.34 a barrel. WTI, the U.S. benchmark, advanced 2 percent as the al-Maliki government fails to end the fighting.
Spare Capacity
“While there are concerns over the impact of the crisis on the oil market, any disruption should be contained,” Jason Tuvey, assistant economist at London-based Capital Economics Ltd., said in a report today. “Most of Iraq’s major oilfields are located in the south of the country, far from where the current turmoil is taking place.”
Saudi Arabia, the world’s largest oil supplier, has the spare capacity to offset a decline in Iraqi oil production, Tuvey said.
Iraqi stocks fell 1.7 percent, the sixth day of declines. The yield on $2.7 billion of government securities due January 2028 fell 11 basis points to 6.79 percent, according to data compiled by Bloomberg. In Turkey, stocks and bonds pared losses after a report that Turkish hostages captured during a raid on the country’s consulate in Mosul would be freed.
The swift seizure of Mosul suggests that ISIL probably colluded with “disenfranchised” army units in the city, Hawes said. The advance was made easier by an “extremely antagonistic” relationship between the government armed forces and the population of Mosul, a Sunni majority town, he said.
The New York Times reported that army commanders from the Saddam era joined forces with the Islamists to rout the government. Many senior ex-officers, including General Sultan Hashim who was defense minister during the U.S. invasion in 2003, were from Mosul, and The U.S. also faced stiff resistance in the city during its occupation.
ISIL rose to prominence as one of the mostly Sunni groups fighting to topple Syria’s President Bashar al-Assad, and has used the desert areas of western Iraq as secure bases for its fighters.
To contact the reporters on this story: Donna Abu-Nasr in Beirut at dabunasr@bloomberg.net; Glen Carey in Riyadh at gcarey8@bloomberg.net; Mahmoud Habboush in Abu Dhabi at mhabboush@bloomberg.net
To contact the editors responsible for this story: Andrew J. Barden at barden@bloomberg.net; Alaa Shahine at asalha@bloomberg.net Alaa Shahine, Ben Holland
Norway Oil Spending Seen Plunging on Costs, Political Meddling
By Mikael Holter Jun 12, 2014 8:26 PM GMT+0700
Oil and gas companies operating in Norway, western Europe’s biggest producer, predict investments will plunge 21 percent next year amid rising costs and increased political interference over offshore developments.
Spending is forecast to drop to 182.4 billion kroner ($30.4 billion) from a record 231.7 billion kroner in 2014, Statistics Norway said today, citing a quarterly survey of producers. That would be the first drop since 2010.
“The need to cut costs and increased uncertainty about framework conditions is contributing to a weaker development of investments in 2015,” Bjoern Harald Martinsen, manager for economics at the Norwegian Oil and Gas Association, said in a statement today. The group represents companies including Statoil ASA (STL), Exxon Mobil Corp. (XOM), and ConocoPhillips. (COP)
Norway’s government last year unexpectedly increased taxes on the industry while last month parliament intervened to change the terms of the Johan Sverdrup development, the country’s largest offshore development in decades.
“Investments will reach a peak in 2014 and fall again in 2015,” Statistics Norway said in a statement. “The decrease is mainly due to significantly lower estimates of field development and fields on stream.”
Oil companies in Norway have more than tripled investments during the past decade as costs and activity climbed, driven by new finds. Companies including Statoil, which operates more than 70 percent of the nation’s oil and gas output, have cut spending plans for the coming years to boost returns amid rising costs and stagnating energy prices.
Rate Delay
The “dramatic decline” in oil spending will result in Norges Bank postponing an interest rate increase “at least until the autumn” of next year, Marius Gonsholt Hov, an analyst at Svenska Handelsbanken AB (SHBA), said in a note. Norges Bank had earlier signaled it may raise rates during the summer of 2015.
The oil and gas industry accounts for more than a fifth of the Norway’s gross domestic product, and its petroleum revenue has helped it build a $880 billion sovereign wealth fund, the world’s biggest.
Spending on field developments is expected to fall by 33 percent to 56.3 billion kroner, Statistics Norway said. That decline could be moderated when spending estimates are included for the development of Johan Sverdrup, the agency said.
The plan for Sverdrup, due to start production at the end of 2019, is expected early next year, acting operator Statoil has said. Investments could reach 120 billion kroner for the project’s first phase alone.
Cancellation Concerns
Spending on already producing fields are forecast to drop by almost 20 percent to 75.4 billion kroner in 2015, according to Statistics Norway. Oil companies also cut their estimates for this year’s investments on producing fields by 5 percent from a previous forecast in March.
Norway’s government, including state-owned oil firm Petoro AS, has voiced concern about delays and cancellations of time-critical projects designed to increase recovery at producing fields. Statoil plans to deepen investment and cost cuts beyond 2016 targets announced earlier this year, according to internal documents seen by Bloomberg News last week.
While Statistics Norway’s estimate for total investments in 2014 was increased 3.6 percent from its previous forecast, that rise is largely due to the addition of shutdown-and-removal spending in the forecast. The latest survey is the first time companies have been asked to give forecasts for next year. The estimate for 2015 is 12 percent lower than the first forecast companies made for 2014.
The Norwegian Petroleum Directorate said in January it expects investments by oil companies to reach a record 214 billion kroner in 2015, before falling to 204 billion kroner a year in the period from 2016 through 2018. Rising costs and uncertainty about oil prices are a “significant challenge” to the development of Norway’s oil and gas production, which has fallen 20 percent during the past decade, the authority said.
To contact the reporter on this story: Mikael Holter in Oslo at mholter2@bloomberg.net
To contact the editors responsible for this story: Jonas Bergman at jbergman@bloomberg.net Alastair Reed
WTI Oil Trades Near Three-Month High Amid Shrinking Crude Supply
By Ben Sharples Jun 12, 2014 6:23 AM GMT+0700
West Texas Intermediate traded near the highest price in three months as crude inventories dropped for a second week in the U.S., the world’s biggest oil user.
Futures were little changed in New York after gaining 0.1 percent yesterday. Crude stockpiles fell by 2.6 million barrels last week to 386.9 million, according to the Energy Information Administration. They were forecast to decline by 2 million in a Bloomberg News survey. The Organization of Petroleum Exporting Countries decided at its meeting in Vienna to keep its production target unchanged at 30 million barrels a day, a decision that was widely anticipated.
WTI for July delivery was at $104.47 a barrel, up 7 cents, in electronic trading on the New York Mercantile Exchange at 9:20 a.m. Sydney time. The contract settled at $104.41 on June 9, the highest close since March 3. The volume of all futures traded was about 74 percent below the 100-day average. Prices have advanced 6.2 percent this year.
Brent for July settlement gained 43 cents, or 0.4 percent, to $109.95 a barrel on the London-based ICE Futures Europe exchange yesterday. The European benchmark crude ended the session at a premium of $5.55 to WTI.
U.S. gasoline supplies expanded by 1.7 million barrels to 213.5 million during the week ended June 6, the EIA said yesterday. They were projected to gain by 1 million, according to the median estimate of 11 analysts surveyed by Bloomberg.
To contact the reporter on this story: Ben Sharples in Melbourne at bsharples@bloomberg.net
To contact the editors responsible for this story: Pratish Narayanan at pnarayanan9@bloomberg.net Alexander Kwiatkowski, Ramsey Al-Rikabi
TPPI Shuts Petrochemical Plant as Agreement Ends With Pertamina
By Fitri Wulandari Jun 12, 2014 11:37 AM GMT+0700
PT Trans Pacific Petrochemical Indotama has stopped production at its Tuban plant in East Java after an agreement with Indonesia’s state oil company ended.
The subsidiary of Tuban Petrochemical Industries is negotiating with PT Pertamina, overseas suppliers and the country’s upstream oil and gas regulator for condensate feedstock to restart the plant in July or August, Basya Himawan, the company’s vice president, said in a phone interview yesterday. The company known as TPPI can process 100,000 barrels a day at its Tuban unit in East Java, which turns condensate into products including naphtha.
“We want to start operating independently,” Himawan said. “We are looking for financing and feedstock suppliers as well as to sell output by ourselves.”
TPPI restarted the plant in November after a nearly two-year suspension under the deal with Pertamina that ended May 21. TPPI bought all of its condensate from Pertamina in exchange for selling its output to the state-owned company.
TPPI is looking to buy at least 1 million barrels a month of condensate to restart the plant, Himawan said. The company has processed both domestic and imported supplies, including from the Middle East and Australia, he said.
The plant can produce 500,000 metric tons of paraxylene, 120,000 tons of orthoxylene and 200,000 tons of benzene annually, according to Himawan. Paraxylene is used to make synthetic fibers and plastics. Benzene and orthoxylene are found in car additives, solvents and dyes.
To contact the reporter on this story: Fitri Wulandari in Jakarta at fwulandari@bloomberg.net
To contact the editors responsible for this story: Pratish Narayanan at pnarayanan9@bloomberg.net Mike Anderson, Ramsey Al-Rikabi
By Naureen S. Malik Jun 13, 2014 2:35 AM GMT+0700
Natural gas futures climbed the most in almost four months, reaching a five-week high, after a government report showed that a U.S. stockpile expansion was smaller than forecast.
Gas rose 5.6 percent, the biggest one-day gain since Feb. 19. The Energy Information Administration said stockpiles grew 107 billion cubic feet in the seven days ended June 6. Analyst estimates compiled by Bloomberg showed an expected increase of 111 billion. Inventories reached 1.606 trillion cubic feet, the lowest level for the time of the year since 2003.
“Natural gas traders are prone to stampede; this is a very one-directional trade so there were not a lot of people selling into this rally to slow it down,” said Tim Evans, an energy analyst at Citi Futures in New York. “We’ve had eight consecutive weeks with storage injections above the five-year average and the only bullish argument over this eight-week span is that it’s still not enough.”
Natural gas for July delivery advanced 25.4 cents to $4.762 per million British thermal units on the New York Mercantile Exchange, the highest settlement since May 6. Volume for all futures traded was 85 percent above the 100-day average at 2:35 p.m. Prices are up 13 percent this year.
September $5.50 calls, the most actively traded options, rose 2.3 cents to 4.7 cents at 2:38 p.m. on volume of 1,558 contracts.
The storage injection was bigger than the five-year average gain for the week of 88 billion cubic feet and the year-earlier increase of 97 billion, according to the EIA, the Energy Department’s statistical arm. A deficit to the average narrowed to 35.3 percent from 37.4 percent the previous week. Supplies were 31.2 percent below year-earlier levels, compared with 33 percent in last week’s report.
Below Expectations
“Demand has been solid, supply is solid, but with the deficit that we have, we need to have 110s and 115s,” said Kyle Cooper, director of research with IAF Advisors in Houston.
Commodity Weather Group LLC in Bethesda, Maryland, predicted seasonal temperatures across most of the lower 48 states in the next five days will give way to above-normal readings on the East and West coasts for June 17-21.
The high in Washington on June 20 may be 94 degrees Fahrenheit (34 Celsius), 8 above normal, said AccuWeather Inc. in State College, Pennsylvania. Atlanta’s reading is forecast to be 5 higher than average at 92.
Electricity generators account for 31 percent of gas consumption, according to the EIA.
’Catch-Up Game’
“The heat is not really on yet so injections should continue to be strong for the coming weeks, but the catch-up game is not looking that strong,” Drew Wozniak, vice president of market research at United-ICAP, a brokerage in Jersey City, New Jersey, said in a note to clients today.
Gas production rising to a record for the fourth consecutive year will help boost stockpiles to 3.424 trillion cubic feet by the end of the October, which would be the lowest level at the start of the peak heating-demand season since 2008, according to the EIA’s June 10 Short-Term Energy Outlook.
To get there, stockpiles increases will have to average about 87 billion cubic feet a week over the next 21 EIA inventory reports. Weekly storage injections have averaged 78 billion so far this year. The five-year average gain for the six-month refill season is 65 billion.
Marketed gas output in the lower 48 states will increase 4 percent to 73 billion cubic feet a day this year, expanding for the ninth straight year as new wells come online at shale deposits such as the Marcellus in the Northeast, according to the June 10 outlook.
“Market sentiment can swing dramatically without warning, just as it did today,” Evans said. The reaction to the inventory report was “extreme” given the new production coming online, he said. “We are going to continue to see above-average storage injections.”
To contact the reporter on this story: Naureen S. Malik in New York at nmalik28@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Bill Banker, Charlotte Porter
By Nick Cunningham | Thu, 12 June 2014 22:32 | 0
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Along with 3 billion other viewers around the world, I plan to tune in for the month-long World Cup to see whether the 22-year old Neymar can withstand the colossal pressure that has been put upon his shoulders to deliver a win for team Brazil.
Every time I turn on my television set, I’m using World Cup-related energy. And that’s just the start. Flying in teams, trainers, equipment, World Cup personnel and the estimated 500,000-plus fans will use enormous volumes of jet fuel.
Add to that powering the stadiums on game days, moving millions of spectators around host-country Brazil, and transmitting the event to billions of viewers worldwide, and you end up with millions of tons of carbon dioxide added to the atmosphere.
So while the 2014 World Cup is going to be bigger than ever -- it’s shaping up to be the most watched, most lucrative and expensive tournament in soccer history -- it’s also going to be one of the biggest energy-consuming, greenhouse gas-spewing World Cups in history.
Think about this as the music blasts through the stadium and the fans cheer and scream and the players race up and down the field chasing the ball: The 2014 World Cup tournament will burn through enough energy before it’s over to fuel almost every one of the 260 million cars and trucks in the United States for an entire day, or the equivalent of what 560,000 cars use in a year.
Estimating the total energy required to mount such a massive operation with any precision is a fool’s errand, but let’s take a look at some numbers to get a sense of scale.
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FIFA did its own fascinating study of the carbon footprint that will be created by setting up and running its broadcast television operation. It found that the biggest contributor – 60 percent – is international flights for staff members. The other 40 percent comes from all the trucks needed to transport cables, cameras and furniture, and the energy required to operate all of the electronics.
All told, FIFA’s TV operations will contribute 24,670 tons of CO2 to the atmosphere – the same impact of burning 2.8 million gallons of gas, or 13,250 tons of coal.
FIFA also tried to estimate its carbon footprint for staging the tournament’s matches, which wraps in the electricity needed for stadiums, fan festivals, banquets, concession stands, training sites, travel for ticket holders, and team hotels. That number came to 2.72 million tons of CO2 equivalent. That’s like using up 306 million gallons of gasoline or burning 1.46 million tons of coal.
What’s the point of the study? FIFA says to figure out where it can do better next time. Just a 10 percent decline in international staff, for example, reduces the carbon footprint by 6 percent.
TVs and Tea Kettles
None of these numbers include other sources of Cup-related energy use, like building new transportation infrastructure and stadiums.
And speaking of stadiums, while everyone would probably love to attend the final match in Rio de Janeiro’s famous Maracana stadium, the vast majority of us will be watching at home. Which means we’re contributing to the Cup’s carbon footprint, too.
A spike in energy use is likely to occur in places when millions of people turn on their TVs at the same time to watch a match. For example, in the United Kingdom, the record for an energy surge during a TV program occurred during the 1990 World Cup, when England went to a shootout against West Germany in the semi-final. (Incidentally, West Germany prevailed and went on to win the trophy. West Germany’s title run was led by Jurgen Klinsmann, who is now coaching the U.S. national team.)
During that match, the UK National Grid experienced a spike of 2,800 megawatts of demand, as people across England tuned in to watch the game’s climax. Other significant power surges in the UK occurred during England’s 2002 quarter-final match against Brazil (2,570 MW surge), and the 2011 royal wedding of Prince William and Kate Middleton (2,400 MW surge).
In fact, it’s relatively common for the UK to experience a spike in power demand during big soccer matches. National Grid operators have become accustomed to forecasting higher electricity demand during games, according to its operations manager, Jon Fenn. Not only does electricity consumption spike from millions of TV sets, a surge is felt most acutely during halftime or just after the final whistle, when everyone heads to the kitchen to turn on electric tea kettles or grab a snack from the fridge.
“It must be one of the few jobs where watching World Cup matches is essential to your work rather than a distraction, because we need to know to the second when half time and full time occur to be ready for the surges in demand,” Fenn told The Telegraph in an interview before the 2010 World Cup.
The 2014 World Cup will be transmitted to every country in the world and could potentially be the most watched sporting event in history.
Now we know it could set new records in terms of greenhouse gas emissions, too.
By Nick Cunningham and James Stafford of Oilprice.com
06/11/2014
Offshore staff
WASHINGTON, DC – The US Energy Information Administration (EIA) says that the surge in the country's crude oil and natural gas production in recent years means there should be less interruptions to supply if hurricanes disrupt offshore production this summer.
The EIA has published an estimate for hurricane and tropical storm-related oil and natural gas production disruption for the Gulf of Mexico, based on the latest forecast from the National Oceanic and Atmospheric Administration (NOAA), which predicts 8–13 named storms, 3–6 hurricanes, and 1–2 major hurricanes. Based on this NOAA prediction, the EIA estimates that as much as 11.6 MMboe and 29.7 Bcf of natural gas production could be disrupted by the 2014 hurricane season.
EIA analysis shows a 69% probability that production shut-in volumes will be equal to, or greater than, the production that was shut in during the 2013 hurricane season. The 2013 season saw 3.1 MMboe and 6.7 Bcf of natural gas production shut down due to storms.
The EIA notes that the actual volume of production that gets shut in during the 2014 hurricane season could differ dramatically from these estimates, depending on the number, intensity, and track of storms that form. However, its estimate provides a rough guide for the hurricane season’s potential impact to US oil and gas production.
Recent storms have affected oil and gas production in the Gulf of Mexico. The impact of a major hurricane, such as Ike or Gustav, is clear, with the majority of production shut down across the Gulf and the resulting decline in Gulf gas production in recent years.
While the effect on US supply of a major hurricane could now be lower than in previous years, due to the declining production in the Gulf of Mexico, the EIA says that this won’t change the potential impact to insurers and reinsurers, particularly with the removal and decommissioning of rigs also being insured.
06/11/2014
By Gail Tverberg | Thu, 12 June 2014 21:45 | 0
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Recently, the IEA published a “Special Report” called World Energy Investment Outlook. Lets’s start with things I agree with:
1. World needs $48 trillion in investment to meet its energy needs to 2035. This is certainly true, if we assume, as the IEA assumes, that world economic growth will actually improve a bit, from 3.3% per year in the 1990 to 2011 period to 3.6% per year in the 2011 to 2035 period. It is likely that the growth in investment needs will be even higher than the IEA indicates.
In my view, this is a CYA report. The IEA sees trouble ahead. There is no way that investment of the needed amount (which is likely far more than $48 trillion) can be met. With the publication of this report, the IEA can say, “We told you so. You didn’t invest enough. That is why energy supply ran into huge problems.”
2. Without reform to power markets, the reliability of Europe’s electricity supply is under threat. The current pricing model, in which wind and solar PV get feed in tariffs and electricity prices for other fuels is set using merit order pricing, produces huge market distortions.
In my view, the problem is even worse than the writers of the report understand. The value of wind and solar PV are inherently difficult to determine, because they produce intermittent supply, and this is not comparable to other types of electricity. Furthermore, a big chunk of costs relate to transmission and distribution–42% of electricity investment costs in the New Policies Scenario. Many well-meaning researchers looked at wind and solar PV and thought they were a solution, but they tended to look at the situation too narrowly.
To look at the situation properly, one really needs to look at the total system cost of generating electricity with intermittent renewables (of a given amount) compared to the total system cost of generating electricity without intermittent renewables. Proper pricing needs to include all of the additional costs involved, including the additional cost for storage, the additional cost for long distance transmission, and the additional costs encountered by fossil fuel providers in ramping up and down their transmission to match changing output from intermittent renewables.
A study by Weissbach et al.(here or here) suggested that wind and solar PV were “an order of magnitude” less effective than fossil fuels, hydroelectric or nuclear, when full costs were considered. Broader analysis also raises questions as to whether there is any real carbon savings from wind and solar PV–did the belief they were helpful just come from underestimating true system costs?
I would raise the question as to whether competitive markets for electricity even make sense. Regulated markets allow the various players to make an adequate return, and allow utilities to collect adequate fees for infrastructure. The overseer can increase or reduce investment of a particular kind, based on the needs of the particular system. I notice a recent Bloomberg article says, Europe Faces Green Power Curbs to Stop Grids Overloading. The current system is clearly working badly.
3. Tight oil from shale deposits will need significant supplementation from other sources, if it is to be sufficient to meet our needs to 2035. This is the chart I made from data provided by the IEA in its November 2012 World Energy Outlook, with respect to its New Policies Scenario.
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he current report is not intended to be a report regarding future oil production, but one highlight is, “Meeting long-term oil demand growth depends increasingly on the Middle East, once the current rise in non-OPEC supply starts to run out of steam in the 2020s.” This implies that not only is US tight oil not going to solve our problems, neither will tight oil elsewhere. Instead IEA is back to its old plan of “calling on OPEC”–hoping that the Middle East is there to help, if no one else is around. This is wishful thinking–something I will discuss later.
4. IEA’s investment report is one documenting diminishing returns, even though it never uses that term. Diminishing returns take place if society is becoming less and less efficient at producing energy products. For oil, the issue is that the easy to extract resources were pulled out first; we must now move on to more difficult to extract resources. For electricity, the issue is that the old resources produced too much carbon; we must now move on to higher-priced approaches that (hopefully) produce less carbon.
We can see diminishing returns many places in the report. The major point of the report is that investment costs are expected to rise faster than either the amount of oil or the amount of electricity produced. There are other more specific statements, too. In US tight oil, “High production rates mean that resources are rapidly depleted, with a corresponding rise in costs per barrel as operators move out of the sweetspots to areas where the recovery per well is lower”(page 65). EU will need prices higher than today’s prices for LNG transported from America (page 76). In refineries, the drive is toward more complex and expensive technologies (page 77). There is a steady upward trajectory of the oil prices in the New Policies Scenario (page 81). Offshore wind is expected to move farther offshore, with higher expected costs (page 104).
The point that the IEA does not seem to understand is that diminishing returns affects buyers’ ability to pay higher prices for products. The IEA assumes that buyers will be able to pay higher prices (than the general rise in inflation) for energy products, without it adversely affecting the economy. This clearly isn’t true because salaries do not rise to match the higher cost of energy products. Buyers will cut back on discretionary goods, when energy prices rise. This leads to layoffs in discretionary sectors and quite possibly recession. It also leads to higher default risk.
In fact, wages tend to drop from diminishing returns, because workers are becoming, in some sense, less efficient and thus producing less goods per hour of work. Joseph Tainter in The Collapse of Complex Societies says that diminishing returns were what led to the collapse of ancient civilizations.
Points of Disagreement
1. Many OPEC countries which hold the largest, lowest-cost reserves are deliberately limiting their production rates so as to keep reserves for the longer term. This is common misbelief, repeated by the IEA, but it not true.
The true cost of production in the Middle East is not just the cost of pulling the oil out of the ground. Instead, one has to look at the full cost of the entire system needed for the extraction, including whatever costs are needed to pacify the people in the area, plus whatever costs are needed for additional infrastructure. Even if Iraq can in theory ramp up oil production, this does not automatically happen. Even if Libya can in theory ramp up production, we shouldn’t expect fighting to stop tomorrow. With these costs, the cost per barrel is up close to, or above, today’s oil cost.
Saudi Arabia publishes high reserve numbers, but there is no indication that Saudi could, if they wanted to, greatly ramp up production. Saudi’s big recent addition was 500,000 barrels a day of refinery capacity in 2013, so that it could make use of heavy, polluted oil from Manifa field, that was supposedly part of its “spare capacity.” An additional 400,000 barrels a day at the same facility is supposed to come on line in 2014. There are declines going on elsewhere, so it is not clear that even these additions will actually add to its total oil production. Saudi Arabia’s total output was slightly lower in 2013 than in 2012, according to the EIA.
The Saudi “proven oil reserves” are unaudited numbers. Its big oil field is Ghawar, producing something like 5 million barrels a day. We don’t know how long it can continue producing. We know that horizontal wells can keep production from declining for a while, but that if a drop-off comes, it is likely to be more severe than with vertical wells. If Ghawar production starts declining significantly, world oil production is likely to drop.
We know that Saudi Arabia has some heavy oil it can in theory develop, not that different from Canadian oil sands or Venezuelan Oronoco belt heavy oil. Such oil would require large front-end investment and flow very slowly. According to the Wall Street Journal, “That the Saudis are even considering such a project shows how difficult and costly it is becoming to slake the world’s thirst for oil. It also suggests that even the Saudis may not be able to boost production quickly in the future if demand rises unexpectedly.”
2. It makes sense to find new sources of investment that will provide funds at lower rates for energy project finance. The report talks trying to find new sources of investment for energy projects other than the traditional source. In particular, it mentions the possibility of tapping funds held by institutional investors (pension funds, insurers, sovereign wealth funds and so on). Pensions and insurance companies are of course currently involved by holding stocks and bonds of oil and other energy companies.
The reason why new sources of lending are needed (besides the problem with high costs) is that the fact that prior sources are getting burned out at the same time huge amounts of new lending are needed. Governments used to be sources of funds, but can no longer be taken for granted (page 38). Changes in Basel III rules make it harder for banks to make long-term energy loans, without charging higher rates (page 39). Quite a bit of the lending in the future will be need to be to developing countries (see Figure 2 below). Many who have lent to developing countries in the past have suffered losses (page 39). With respect to oil projects, there are many examples where oil companies have made big investments, with virtually no return, such as Kazakhstan oil (page 81).
Perhaps sovereign wealth funds, if they feel that the risk is appropriate, can lend in situations where past experience suggests prudence is needed. But with a background in the insurance industry, I am not sure that makes sense for insurance companies and pension funds to get into financing ports in Iraq, refineries in India, or long distance transmission lines to offshore wind turbines. If they do, it needs to be as part of program where adequate risk premiums are included in the interest rates, and the risk is distributed over a large number of participants using bonds or securitization of some form. It seems like an intermediary such as a bank would need to be involved.
The big interest in those writing the report is getting costs down for the borrowers. If risk is going up, it is not at all clear that interest rates should be going down. Furthermore, developing an undeveloped country using $100 barrel oil is far more difficult than developing an undeveloped country using $20 barrel oil. This is a big reason that financing debt in undeveloped countries doesn’t work well.
What the IEA has inadvertently stumbled upon is the reason why oil limits are a problem, and in fact, the reason why energy limits in general are a problem. It looks like there are plenty of resources available and plenty of ways to reduce energy use through mitigation. In fact, it becomes too impossible to finance everything that needs to be done.
An energy-providing device, or an energy-saving mitigation, requires upfront payment. This payment reflects the fact that oil and other scarce resources (high priced metals, for example) need to be used in creating these devices. Oil and other scarce resources need to be used in developing new oil, gas and coal fields and power plants as well. This puts pressure on both debt markets and on scarce resources. At some point, the use of scarce resources becomes too great, and debt needs become too high. The projects with high up-front costs are among the worst contributors.
The plan to keep adding more and more debt doesn’t work. The economy is growing too slowly. People’s salaries are not rising to match the higher costs involved. The locations where the debt is needed are not in the part of the world with adequate banking services. It is the inability to finance all of the investment that is needed that will bring the system down. Resource scarcity will be behind the scenes, playing a role as well, but its problems will be hidden behind the problems of financing the needed energy investments.
By Gail Tverberg
Jun 13, 2014 Priyanka Shrestha Coal, Gas & Oil 0
Copyright: Thinkstock
Europe’s imports of natural gas will surge 50% by 2030 as domestic production falls, according to a new report.
It claims Europe’s gas imports could increase to 320 million tonnes of oil equivalent (Mtoe) a year by 2030 from the current 215 Mtoe. Reliance on Russian gas will continue despite EU efforts to become less dependent on Moscow in light of the Ukraine crisis.
Massimo Di-Odoardo, Principal Analyst- European Gas and Power for Wood Mackenzie, which published the report said: “The ongoing crisis in the Ukraine has focused attention on Europe’s reliance on Russian natural gas. Russian gas remains competitive against other alternatives and will continue to be the cornerstone of European gas supply.
“It also represents a major market for Russian gas, even in light of the recent signing of a gas pipeline deal to export Russian gas to China. Therefore, our long term view is that the Europe-Russia gas relationship will continue out of necessity.”
The report also suggests India and China will be the destinations for exporters of coal, oil and gas and energy demand growth within Asia-Pacific will outpace that of North America by five times by 2020.
By 2018, North America is expected to overtake the gas output of Russia and the Caspian and by 2030 grow to become the world’s largest gas producing region, with production doubling to 1,000Mtoe.
