Exxon Mobil Corp. (XOM) was awarded a $1.6 billion judgment by an international arbitration panel for assets seized by Venezuela’s government in 2007, a fraction of what the crude producer had sought.
The World Bank’s International Centre for Settlement of Investment Disputes, or ICSID, awarded the sum to Irving, Texas-based Exxon as compensation for investments in the Cerro Negro project and other losses, according to a ruling on the center’s website today. The world’s most valuable oil company had originally sought as much as $14.7 billion for assets nationalized after it refused to accept terms of a partnership with state-owned Petroleos de Venezuela SA.
“Our goal with the arbitration was to seek compensation for the fair market value of assets that were expropriated,” Exxon said in an e-mailed statement. “Exxon Mobil’s affiliate engaged in extensive discussions with PDVSA and government officials but was unable to reach agreement on fair compensation.”
President Hugo Chavez’s handpicked successor, Nicolas Maduro, is paying the price of his late mentor’s socialist revolution just as slumping oil prices and a dollar shortage fan investor concern the country may default on debt. The Exxon settlement may remove legal obstacles to his planned sale of PDVSA’s U.S. unit Citgo Petroleum Corp., according to Bloomberg Intelligence analysts Gurpal Dosanjh and Vincent G. Piazza.
“The potential for a higher award, more than Venezuela could afford to pay, may have deterred potential suitors for Citgo, which is ultimately owned by Venezuela, amid fears of lawsuits against the nation’s foreign assets,” Dosanjh and Piazza wrote today.
Award Reduction
The amount to be paid to Exxon under today’s ruling should be reduced after adjustments for payments Venezuela made in 2012 under a previous settlement at the International Chamber of Commerce, or ICC, Venezuela Foreign Minister Rafael Ramirez said on state television.
The payment will be reduced to about $1 billion and will not be a problem for PDVSA, according to a financial official at the company, who asked not to be named because of internal policy. Venezuela will pay its bonds due this month, he said.
“In the event of favorable award, the claimants are willing to make the required reimbursements to PDVSA,” ICSID said in the ruling. “Double recovery will thus be avoided.”
Chavez, who died last year after struggling with cancer, began to expropriate assets in Venezuela’s energy, mining and telecommunications industries in 2005, claiming their strategic role in the country’s development and sovereignty.
2007 Ultimatum
Energy companies were given until late-2007 to accept proposed contract and compensation terms from Chavez’s government or risk having their assets seized.
Exxon and ConocoPhillips, the third-most valuable U.S. crude producer after Exxon and Chevron Corp. (CVX), were the largest American energy companies to reject Venezuela’s terms.
In 2011, the ICC ordered PDVSA to pay Exxon $907.6 million, minus a $161 million counterclaim by PDVSA, for the seizure of a 41.67 percent stake in the Cerro Negro heavy-oil project in the Orinoco Belt, the same one that triggered the claim at the ICSID. The cases differ because the ICC handles contract disputes while the ICSID hears disputes based on investment treaties between countries.
PDVSA said in 2012 that it had settled the ICC ruling with a cash payment of $255 million.
Seized Projects
Exxon’s assets in Venezuela, which included 425 million barrels of proved reserves net to the company, had a remaining net book value of $750 million, according to the company’s filings to the U.S. Securities and Exchange Commission.
Shares of Exxon declined 3 percent to close at $91.82 in New York today.
The ICSID award includes $1.4 billion for expropriation of the Cerro Negro project, $179.3 million for expropriation of the smaller La Ceiba project and $9 million in compensation for production and export curtailments, ICSID said. It will incur compound interest of 3.25 percent dating back to June 2007.
In a similar complaint, the ICSID ruled Sept. 23 that Venezuela must pay $740 million to Spokane, Washington-based Gold Reserve Inc. (GRZ) for taking its Brisas gold and copper project in 2008. Gold Reserve said on July 23 that it was seeking $2.1 billion for the nationalization.
About 28 cases filed by mining and oil companies remain unresolved at the ICSID, including those filed by Phillips 66 and Highbury International AVV.
Not Over
The government will likely try to use legal challenges to delay compensation and to negotiate settlements with claimants, Risa Grais-Targow, an analyst in Washington at political consultancy Eurasia Group, said in an e-mailed research note to clients today. Should claimants refuse this offer, the government would likely struggle to pay significant cash awards, potentially resulting in asset seizures
“Venezuela will just want to subtract the $908 million from the $1.4 billion Cerro Negro portion, pay it and get out of there, and Exxon is unlikely to be satisfied with that math,” Russell Dallen, Miami-based managing partner at Caracas Capital Markets, said in an e-mail. “While I predict that Venezuela will move to annul the Gold Reserve case by February, it is possible that Exxon may move to annul this case and keep fighting.”
The South American country must honor ICSID rulings to avoid default of sovereign bonds, according to Joe Kogan, an analyst at the Bank of Nova Scotia.
Bond Decline
Venezuela’s benchmark dollar bonds due 2027 extended losses after the ruling, falling 0.8 cent on the dollar to close at 65.6 cents today in New York. The yield on the bonds rose 20 basis points to 15.5 percent.
Venezuela said yesterday that it paid bonds due in 2014 totaling $1.5 billion. PDVSA has $3 billion of dollar bonds that mature on October 28.
“While Venezuela has been willing to compensate claimants in the past, the government is clearly working with limited liquidity and already faces tough policy trade-offs between servicing its liabilities and importing basic goods to satisfy its base,” Grais-Targow said.
LNG producers facing competition from U.S. exports now have to contend with the biggest buyers in Asia banding together to beat down prices.
Tokyo Electric Power Co. (9501) and Chubu Electric Power Co. (9502) announced a partnership this week that may create the world’s biggest consumer of liquefied natural gas. The alliance follows a trend among Asian utilities to boost purchasing power through tie-ups with rivals, according to Wood Mackenzie Ltd. Tokyo Gas Co. and Korea Gas Corp. last month said they’ll start talks to cooperate in fuel purchasing to reduce prices.
Global supply of the power-station fuel is forecast to increase by almost 80 percent over the next decade as the shale boom prompts the U.S. to start exporting and producers including Chevron Corp. and BG Group Plc (BG/) begin projects in Australia. Asian companies are looking to take the opportunity to bargain for lower prices after they jumped to a record this year.
“The sheer volume of potential purchasing power must give them a huge negotiating advantage for price in new sales and purchase agreements, particularly as they are looking to new projects in Mozambique, Canada and now Alaska,” said Leigh Bolton, managing director of Holmwood Consulting Ltd., a Surrey, England-based energy consultant.
Tepco and Chubu Electric, Japan’s two biggest buyers, will form a joint venture by the end of March for thermal-power generation and fuel imports, they said in a statement on Oct. 7. This will improve their bargaining position with suppliers, according to Chubu Electric President Akihisa Mizuno.
Largest Importer
The venture may purchase 35 million to 40 million metric tons a year, according to the statement, rivaling Korea Gas as the largest importer of the fuel that’s the dominant energy source in Japan. That’s almost half the nation’s annual use.
“The announcement appears similar to one or two others we’ve seen recently and is representative of the way we are seeing major buyers looking to put more pressure on sellers on price and contract flexibility,” Gavin Thompson, Wood Mackenzie’s Tokyo-based head of Asia gas and power research, said in an e-mail.
New projects will boost global supply to 425 million metric tons by 2025 from the current level of 240 million, according to BG estimates as of Sept. 17. The Reading, England-based company plans to produce the first LNG at its Queensland Curtis plant in Australia by the end of 2014.
Delays, Cancellations
U.S. exports starting next year won’t be enough to meet rising demand for the fuel in Asia and Europe through 2025, requiring additional volumes from other locations such as Canada and East Africa, according to BG. Mark Todd, a spokesman for the company, confirmed the forecasts in an e-mail yesterday, without further commenting.
Projects in Africa, Canada and Australia face delays or even cancellation as global demand growth slows and U.S. output increases, Goldman Sachs Corp. said in a report e-mailed on Oct. 2. The bank cut its forecast for worldwide consumption to 5 percent on an annual compound basis by 2020, and 4 percent by 2025. It previously saw growth of 6 percent and 5 percent, respectively.
Asia accounted for three-quarters of global demand last year, according to the Paris-based International Group of LNG Importers. Japan imported a record 87.49 million tons in 2013 after the Fukushima disaster in 2011 prompted the shutdown of all its nuclear plants. It spent a record 7 trillion yen ($64.9 billion) on LNG imports, more than double the cost three years ago, according to the Ministry of Finance.
Peak Price
Spot LNG delivered to northeast Asia rose to a peak of $19.70 per million British thermal units in February as Japan entered its main demand season without any of its nuclear reactors operating, according to data from Energy Intelligence Group’s World Gas publication.
Prices may top $20 per million Btu this winter if there’s a cold spell in northeast Asia combines with disrupted flows of Russian gas to Europe, Energy Aspects, a London-based consultant, said in an e-mailed note Sept. 25. It forecast Northeast Asia prices at $16.50 for the last quarter this year and $15.10 for 2015.
The Japanese utilities will still need to compete with each other in the domestic power market, according to Thompson. “Power-market liberalization will only increase this, so it will be interesting to see how durable these partnerships prove to be,” he said.
The European Union rekindled a probe into possible rigging of fuel-price benchmarks, raiding ethanol companies in the bloc 17 months after officials inspected three oil producers and industry publisher Platts.
European Commission investigators on Oct. 7 made surprise inspections on companies involved in the production, distribution and trading of ethanol, the regulator said in a statement.
“The commission has concerns that price benchmarks may have been distorted through anti-competitive behavior, including through possible collusion when submitting price information to a price reporting agency,” the EU said.
The unannounced inspections revitalize a probe into benchmark energy prices produced daily by Platts that has seemingly been dormant for more than a year. EU investigators in May of last year raided Platts along with BP Plc (BP/), Statoil ASA (STL), Royal Dutch Shell Plc (RDSA), Argos Energies and Abengoa SA (ABG), owner of continental Europe’s biggest bioethanol plant.
Copycat probes followed on from last year’s EU raids. The U.S. Federal Trade Commission and the Japanese Fair Trade Commission started quizzing BP in June of 2013. The Korea Fair Trade Commission opened an investigation in December and the U.S. Commodity Futures Trading Commission requested price-reporting documents from BP the following month.
The EU didn’t identify the companies or countries involved in this week’s inspections.
Better Understanding
Statoil officials said they weren’t aware of the latest raids, while BP and Shell representatives declined to comment on the EU announcement. Platts wasn’t targeted in this week’s raids, Kathleen Tanzy, a spokeswoman for the company based in New York, said in an e-mailed statement.
Peter Zeylmaker, a spokesman for Argos Energies in Rotterdam, said in a phone interview that the company was not raided on Oct 7. Argos has heard nothing from EU investigators since they visited the company in May last year, he said.
Abengoa is “is cooperating with the authorities and will not comment on an ongoing investigation,” according to an e-mailed statement yesterday.
To get a better understanding of the $3.4 trillion-a-year fuels market, the commission sent questionnaires to major participants last year -- Vitol Group, Glencore Xstrata Plc, Mercuria Energy Group Ltd. and Gunvor Group Ltd.
Seth Pietras, spokesman for Gunvor, and Benoit Lioud, a spokesman for Mercuria, said the companies weren’t raided. Vitol and Glencore officials declined to comment.
“Since 2012, ethanol market prices in the EU have been trading 13 percent higher than supply costs,” said Salim Morsy, an analyst at Bloomberg New Energy Finance. “In 2011 that difference was just 5 percent.”
Libor Rigging
In the wake of an international probe of banks that rigged the London Interbank Offered Rate, the EU said last year that providers of market data for oil and biofuels may also have colluded when they reported prices used to establish benchmarks for global fuel sales.
Platts, which is a unit of New York-based McGraw Hill Financial Inc. (MHFI), has assessed prices for crude oil, petroleum products and related swaps using its market on close process since 2002 in Europe. To participate, traders voluntarily report some of their bids, offers and trades to Platts’s defined window period each day, which are then used to create end-of-day price assessments for various commodities.
Its oil-price reporting system “may leave scope for anti-competitive behavior leading to price distortions,” Joaquin Almunia, the EU’s antitrust chief said last year.
His successor, former Danish Economy Minister Margrethe Vestager, is scheduled to take over the EU antitrust brief at the start of November. She said last month that all cases should be “treated with fairness and transparency.”
Following last year’s announcement, Platts said its price assessment process was “robust and specifically designed to safeguard against distortion.”
Bloomberg LP, the parent of Bloomberg News, competes with Platts and other companies in providing energy markets news and information.
Indonesia, once the biggest oil producer in Southeast Asia, is giving up on its target of restoring output to 1 million barrels a day even as operations begin at the Cepu block in Central Java.
New projects will add little to Indonesia’s reserves, while output from aging fields will continue to decline, Deputy Energy and Mineral Resources Minister Susilo Siswoutomo said at this week’s inauguration of Cepu block, operated by a unit of ExxonMobil Corp.. Without more exploration, Indonesia’s oil production may fall to 600,000 barrels a day in 2020, he said.
Indonesia, a former member of the Organization of Petroleum Exporting Countries, set a target in 2012 of restoring output to 1 million barrels a day by 2014. The country’s crude production has dropped more than 50 percent since the mid-1990s as shifting regulations and complicated permits deter investments in new fields.
“Even if we held massive prayers to ask for help, God won’t increase production straight from 850,000 to 1 million,” Siswoutomo said. “If we don’t drill, we won’t get oil.”
The Banyu Urip field at the Cepu block on the Indonesia’s island of Java will have peak production of 165,000 barrels a day from 49 wells, according to data from Mobil Cepu. The Cepu oil and gas block is 45 percent owned by Mobil Cepu and Ampolex Cepu Pte Ltd., 45 percent by Pertamina EP Cepu Pt., and 10 percent by the Cepu Block Cooperation Body. The block’s production sharing contract will expire in 2035.
Ramping Up
The block may not be able to reach peak output by the initial target of April 2015, Zudaldi Rafdi, a spokesman at country’s oil and gas upstream regulator SKK Migas, said on Aug. 7. The block is the biggest among 23 oil and gas projects that will come online next year, according SKK Migas data.
Cepu will increase production to reach peak output in the third quarter of 2015, Interim Energy and Mineral Resources Minister Chairul Tanjung said yesterday. The field currently has production capacity of 40,000 barrels a day, according to SKK Migas.
The government is trying to make it easier for investors to get permits needed for exploration and production of oil and gas, said J. Widjonarko, acting head of SKK Migas said. Indonesia, which now has 289 permits for oil and gas, plans to reduce that to 69, Widjonarko said.
Lee Tillman, chief executive officer of Marathon Oil Corp., told investors last month that the company was potentially sitting on the equivalent of 4.3 billion barrels in its U.S. shale acreage.
That number was 5.5 times higher than the proved reserves Marathon reported to federal regulators.
Such discrepancies are rife in the U.S. shale industry. Drillers use bigger forecasts to sell the hydraulic fracturing boom to investors and to persuade lawmakers to lift the 39-year-old ban on crude exports. Sixty-two of 73 U.S. shale drillers reported one estimate in mandatory filings with the Securities and Exchange Commission while citing higher potential figures to the public, according to data compiled by Bloomberg. Pioneer Natural Resources (PXD) Co.’s estimate was 13 times higher. Goodrich Petroleum Corp.’s was 19 times. For Rice Energy Inc., it was almost 27-fold.
“They’re running a great risk of litigation when they don’t end up producing anything like that,” said John Lee, a University of Houston petroleum engineering professor who helped write the SEC rules and has taught reserves evaluation to a generation of engineers. “If I were an ambulance-chasing lawyer, I’d get into this.”
Experienced investors know the difference between the two numbers, Scott Sheffield, chairman and CEO of Irving, Texas-based Pioneer, said in an interview.
“Shareholders understand,” Sheffield said. “We’re owned 95 percent by institutions. Now the American public is going into the mutual funds, so they’re trusting what those institutions are doing in their homework.”
Mutual Funds
Investors poured $16.3 billion in the first seven months of the year into mutual funds and exchange-traded funds focused on energy companies, including drillers that create fractures in rocks by injecting fluid into cracks to enable more oil and gas to flow out of the formation. That’s almost twice as much as in the same period last year, bringing total assets to $128.2 billion, according to New York-based Strategic Insight.
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U.S. oil production surged to a 28-year high in 2014, bolstering the companies’ sales pitch and contributing to a 20 percent drop in American oil prices since the end of June. U.S. output is expected to grow 12 percent next year, to the highest level since 1970, according to the Energy Information Administration of the U.S. Department of Energy. At the same time, U.S. consumption will shrink 0.2 percent this year, the EIA said.
Annual Accounting
Marathon’s Tillman, who was speaking at the Barclays Plc CEO Energy-Power Conference in New York on Sept. 3, said there are “risk and uncertainties that could cause actual results to differ materially from those expressed or implied by” his comments. Many company presentations remind investors that publicly announced estimates are more speculative than the numbers the drillers file with the SEC.
Figures the company executives cite during presentations “are used in the capital allocation process, and are a standard tool the investment community understands and relies on in assessing a company’s performance and value,” said Lisa Singhania, a Marathon spokeswoman. The Houston-based company’s shares have risen 1.6 percent in the last year.
The SEC requires drillers to provide an annual accounting of how much oil and gas their properties will produce, a measurement called proved reserves, and company executives must certify that the reports are accurate.
Resource Potential
No such rules apply to appraisals that drillers pitch to the public, sometimes called resource potential. In public presentations, unregulated estimates included wells that would lose money, prospects that have never been drilled, acreage that won’t be tapped for decades and projects whose likelihood of success is less than 10 percent, according to data compiled by Bloomberg. The result is a case for U.S. energy self-sufficiency that’s based more on hope than fact.
Judy Burns, a spokeswoman for the SEC, declined to comment on what drillers say during investor presentations.
A Rice Energy spokeswoman declined to comment on the difference between the numbers. A spokesman for Houston-based Goodrich Petroleum didn’t return calls and e-mails seeking a comment on the subject.
Predicting how much oil can be pumped out of shale has been controversial since the boom began about a decade ago. Companies combined horizontal drilling with fracking, or hydraulic fracturing. Fracking involves blasting water, sand and chemicals into deep underground layers of shale rock to free hydrocarbons.
Reasonable Certainty
Innovators such as Oklahoma City-based Chesapeake Energy Corp. (CHK) said that drilling vast expanses of oil-soaked rock formations is more predictable than the traditional, straight-down method of exploration. Regulators agreed and requirements were loosened starting in 2010.
A spokesman for Chesapeake Energy declined to comment on the rules for proved reserves.
To count as proved reserves to the SEC, companies must have “reasonable certainty” that the oil and gas will be extracted from existing wells and those scheduled to be drilled within five years. The forecasts are based on fuel prices, geology, engineering and the performance of nearby wells. Planned wells must be economically and technically viable.
For Harold Hamm, the billionaire founder, chairman and CEO of Oklahoma City-based Continental Resources Inc., the five-year rule is too constraining. It will take longer than that to extract a lot of his company’s petroleum, and he should be able to cite those resources in regulatory filings, he told the Senate Energy and Natural Resources Committee on Jan. 30.
“Those numbers are totally pessimistic,” Hamm said about proved reserves. Continental shares have risen 8.3 percent in the last year.
Lobbied SEC
Energy companies also lobbied the SEC to let them file more speculative estimates, known as probable reserves and possible reserves. Only three companies take that option, according to data compiled by Bloomberg. The rest report only proved reserves to the SEC and save their other estimates for public presentations, which the SEC doesn’t supervise.
The data include year-end 2013 SEC filings, the latest available, compared with 2014 marketing materials, press releases, company websites and executives’ speeches for the 73 shale drillers. The presentations rarely explain how the drillers calculated the figures. The numbers sometimes change from one presentation to the next.
Total Estimate
Many of the companies use their own variation of resource potential, often with little explanation of what the number includes, how long it will take to drill or how much it will cost. The average estimate of resource potential was 6.6 times higher than the proved reserves reported to the SEC, the data compiled by Bloomberg News show.
Several companies, including Sanchez Energy Corp. (SN), don’t provide a total estimate. Instead, they publish variables such as the number of well locations and the estimated output from each one. Analysts often use these figures to independently compute the total.
Even though Sanchez Energy provides the variables for analysts to calculate its resource potential, the Houston-based company doesn’t publish a total estimate. Executives debated whether to include one and decided against it, said Gleeson Van Riet, senior vice president for capital markets and investor relations.
‘Garbage Out’
“We don’t think that a lot of the guesstimates that go behind those sorts of things will ultimately be constructive to investors,” Van Riet said. “Put another way, garbage in, garbage out.”
Denver-based Cimarex Energy Co. is one company that doesn’t report a different number to investors than it does to the SEC. “We want to have things on the books that are part of our near-term drilling plans,” Karen Acierno, a Cimarex spokeswoman, said in an interview. “A lot of people appreciate our conservative nature, a lot of investors.” Cimarex shares are up 19 percent in the past year.
The investor presentation by Canonsburg, Pennsylvania-based Rice Energy shows 2.7 billion barrels. Rice, which went public in January, reported 100 million barrels to the SEC in March, records show.
At Pioneer Natural Resources, the number they cite to potential investors has increased by 2 billion barrels a year in each of the last five years -- even as the proved reserves it files with the SEC have declined.
The rising number is “a game changer for this company,” said Sheffield, the CEO. “It’s a game changer for this country.”
‘Great Resource’
Pioneer’s numbers aren’t misleading; they’re conservative, Sheffield said. He said he’s shared them with Senators Mary Landrieu of Louisiana and Lisa Murkowski of Alaska, the Democratic chair and Republican ranking member, respectively, of the Senate energy committee.
“Obviously it’s helped us in regard to making headway on convincing people to lift the export ban,” Sheffield said. “We want to convince them that we have this great resource. We don’t want it trapped here in the U.S. That’s for the public, the administration and Congress. So if we’ve got this great resource, why don’t you allow us to export it?”
The message is getting through. While Landrieu said she favors more study, Murkowski said she supports ending the ban.
A loosening of trade restrictions imposed after the 1973 Arab oil embargo would be worth billions to drillers such as Pioneer, Marathon and Continental because the price of oil on the international market in the past year has averaged 8.5 percent more than in the U.S.
Bakken Shale
“If you don’t allow the exports of this oil, they’re going to reinvest someplace else where they can market this oil,” Senator Heidi Heitkamp, a North Dakota Democrat, told CNBC Sept. 15. “And so it’s going to reduce the development and the dollars coming in.”
Joining her that morning was John Hess, the billionaire CEO of New York-based Hess Corp., who said, “We’re in a period of supply strength.”
Hess’s company told the SEC it had the equivalent of 659 million barrels of proved reserves in the U.S. The latest investor presentation said the company had 1.2 billion barrels just in the Bakken shale, in Heitkamp’s home state. Hess shares have increased 7.9 percent in the last year. A Hess spokesman didn’t return calls seeking comment.
Lee, the University of Houston professor, said in an interview that he’s alarmed by the inconsistent and overly optimistic estimates published by shale companies.
Shale Engineers
In August, Lee led a workshop in Houston on the best practices of reserves estimation. The audience in the ballroom of the Hotel Derek included engineers for shale drillers such as Marathon, Continental and Rice.
Pamela Allen, a senior reserves coordinator for Marathon, raised her hand and told Lee that she was worried that using outsized forecasts in public presentations would run afoul of the SEC and “come back to haunt us.”
Singhania, the Marathon spokeswoman, said she was unable to comment on Allen’s remarks without seeing a transcript.
“If a lot of people get burned -- and I think a lot of people can and will be burned -- by these numbers in the investor presentations, there may be a push by investors to get the SEC to do something about it,” Lee said during the workshop.
Crude imports to the U.S. Midwest increased to a record last week in anticipation of a new pipeline linking the region to Cushing, Oklahoma, the nation’s supply hub.
Shipments to the region, known as PADD 2, climbed 26 percent to 2.53 million barrels a day in the week ended Oct. 3, the most in Energy Information Administration weekly data that began in 1990. Deliveries to the U.S. from Canada, more than two-thirds of which enter through the Midwest, topped 3 million barrels a day for the first time, preliminary EIA data show.
Demand to ship on Enbridge Inc.’s Lakehead system, the largest conduit for Canadian crude into the U.S., increased in October. Enbridge plans to start filling the 600,000-barrel-a-day Flanagan South pipeline with oil next month, opening an additional connection between the Chicago area and Cushing, the delivery point for New York futures.
“When that pipeline opens, you don’t want to all of a sudden be rushing around to buy barrels then,” Dave Nielsen, research associate at National Bank of Canada, said by telephone from Calgary yesterday. “You definitely want to have the barrels on hand to fill, so there’s some ramp-up to that.”
October shipments on lines 4 and 67, which combined can carry about 1.25 million barrels a day of heavy crude, were oversubscribed from Manitoba to Superior, Wisconsin, according to Enbridge. Lines 61 and 6A/62, which can carry about 1.1 million barrels from Superior to Flanagan, Illinois, also had shipment requests exceed capacity. Lines 61 and 6A/62 weren’t overfilled in September.
Rising Output
Oil output in Canada is projected to increase 6.8 percent to an average of 4.38 million barrels a day this year, the EIA said in its monthly Short-Term Energy Outlook on Oct. 7. Production will climb to 4.47 million barrels a day in 2015, according to the report.
“Canadian production continues to creep up while U.S. output is climbing, and that’s not going to change anytime soon,” Kyle Cooper, director of research with IAF Advisors and Cypress Energy Capital Management in Houston, said by phone yesterday. “The infrastructure is getting better and now we can move those barrels to where they’re needed.”
Crude stockpiles in the Midwest rose 3.51 million barrels to 91.6 million, the most in five months, according to the EIA. Not including Cushing, inventories climbed to a record 72.7 million barrels.
Increasing Shipments
Canada’s oil producers are also gaining increasing access to rail and barge operations that have allowed for exports to the U.S. in the absence of pipeline space, Mike Tran, an analyst at CIBC World Markets Inc. in New York, said by phone yesterday.
The growing take-away capacity helped narrow the discount for Western Canada Select, a heavy sour crude blend, to the smallest versus West Texas Intermediate, the U.S. benchmark, in more than a year on Oct. 7.
“Imports will continue to climb as rail ramps up and the Flanagan fill approaches,” Tran said. “As these formerly stranded barrels move, WCS will strengthen.”
WTI crude for November delivery fell $1.54, or 1.8 percent, to close at $85.77 a barrel on the New York Mercantile Exchange today, the lowest settlement since Dec. 10, 2012. WCS crude was valued at a $12.70-a-barrel discount to WTI, from as much as $24.50 in July.
“You’re seeing guys less concerned with the differential for WCS blowing out to $40 again,” Nielsen said. “We’re seeing more confidence in more sustained, consistent pricing, and that’s all takeaway capacity. They’ve diversified their strategy.”
Ukraine reported intensified shelling in its war-ravaged east as German Chancellor Angela Merkel said the terms of a month-old truce aren’t being met.
The government reported one death among its forces the past day, saying pro-Russian insurgents fired artillery rounds at the military on 33 occasions. While the cease-fire “isn’t flawless,” the tendency in Ukraine is “unambiguously positive,” Russian Foreign Minister Sergei Lavrov said. The rebels yesterday described the truce as all but dead.
“It’s obvious that the Minsk agreement isn’t implemented yet,” Merkel said today after talks with Polish Prime Minister Ewa Kopacz in Berlin. Drones could be used to monitor the truce, “but the condition for everything is that the cease-fire really holds. You can see how fragile the situation is right now.”
While the truce, sealed Sept. 5, has reduced the bloodshed in Ukraine’s easternmost regions, it’s been marred by daily violence. There have been at least 331 deaths since the deal was agreed, the United Nations estimates. The rebels say they’re ready to resume peace talks once Russia and the Organization for Security and Cooperation in Europe agree on the terms.
International Support
Christine Lagarde, the managing director of the International Monetary Fund, said today in Washington that more international financing will be needed to prop up Ukraine’s war-battered economy, but that not all of the funding should come from the IMF. Lagarde, speaking at an event during the IMF’s fall meetings, said other lenders will need to participate, without providing details.
The Washington-based IMF has already approved a $17 billion bailout loan to help Ukraine stay afloat.
Ukrainian central bank chief Valeriya Gontareva said last month the official support program from the IMF envisages a 6.5 percent shrinkage in the country’s gross domestic product this year. She said the “really drastic deterioration of economic conditions” will cause a revision showing an even larger economic contraction.
“I suppose that it will be minus 9 percent, or even 10 percent,” she told reporters in Kiev on Sept. 13.
3,000 Troops
Olexander Motsyk, the Ukrainian ambassador to the U.S., told reporters in Washington that 3,000 Russian troops remain on the Ukrainian side of the border between the two countries. He said the cease-fire has been violated more than 1,000 times though “it’s difficult to say” if the violations have been committed by Russian forces or pro-Russian separatists. ►
One civilian was killed in Donetsk in fighting today, the city council said on its website, while artillery rounds were heard all day in the city.
Ukraine, the U.S. and the European Union blame Russia for providing weapons, financing and troops to the separatists, an allegation Moscow denies. The two sides imposed tit-for-tat sanctions that have depressed economic growth in both the EU and Russia, causing the latter to flirt with a recession.
The ruble weakened 0.1 percent to 40.05 against the dollar by 6 p.m. in Moscow. The Micex Index rose 0.3 percent, while the yield on local-currency bonds due February 2027 was unchanged at 9.69 percent.
Putin, Minsk
Lavrov, at a meeting of Commonwealth of Independent States foreign ministers in Belarus, said resolving the six-month conflict in Ukraine hinges on constitutional changes involving all the nation’s regions and political forces. Ukraine, which was represented by its ambassador to
Belarus, was only discussed on the sidelines of the meeting, he said. President Vladimir Putin will join regional leaders tomorrow in Minsk.
While the cease-fire may not be fully observed, Russia deems the move constructive and a positive process, Yuri Ushakov, Putin’s foreign-policy aide, told reporters today in Moscow. Putin may meet Ukrainian President Petro Poroshenko, Merkel and French leader Francois Hollande at a summit in Milan next week. He isn’t asking for sanctions to be lifted, Ushakov said.
Lavrov will meet U.S. Secretary of State John Kerry in Paris Oct. 14, the State Department said today in a statement.
Russian optimism on the truce contrasts with remarks yesterday by Andrei Purgin, deputy premier of the self-proclaimed Donetsk People’s Republic. He criticized the pact and a plan to create a no-fire zone between the rebels and the army, as well as reiterating the separatists’ goal of independence.
“There is no truce, buffer zones are non-existent,” he said via Russian state-run news service RIA Novosti. “Such casualties make any political union with Ukraine impossible.”
Poroshenko said last week that shelling must stop for 24 hours for the government to pull its troops back and create a 30-kilometer (19-mile) buffer zone. The government in Kiev said yesterday marked the second occasion since Oct. 5 that a halt in shelling by the military went unreciprocated.
Ignore the talk of an OPEC price war, say crude market bulls. Oil’s next move was spelled out in Saudi Arabia’s own words.
Price cuts announced by the Saudis, including the biggest discounts for Asia since 2008, sparked speculation that the world’s biggest crude exporter would let oil tumble rather than cede market share to rivals in OPEC. This is misguided, said UBS AG and BNP Paribas SA. Brent is below the $95-to-$110 range endorsed by Saudi Oil Minister Ali Al-Naimi, ensuring the country will curb output, they said.
Brent, the European benchmark, fell into a bear market amid a surplus of U.S. shale oil and weaker economic growth. The discounts prompted predictions that Saudi Arabia would tolerate lower prices to deter investment in higher-cost U.S. shale. The advance of Islamist militants across a swathe of Iraq and Syria means the kingdom will shore up oil prices to support neighbors instead, BNP Paribas said.
“We do not buy into the argument that there’s a price war in the making,” Harry Tchilinguirian, head of commodity markets strategy at BNP Paribas in London, said by e-mail on Oct. 6. “Saudi Arabia has always done the heavy lifting when it comes to OPEC supply management. What is key in our view is that it is not in the best interest of OPEC to witness a prolonged period of low prices.”
Battle Commences
Front-month Brent futures slid to $91.38 a barrel yesterday on the ICE Futures Europe exchange, the lowest since June 28, 2012, after the International Monetary Fund cut global economic growth forecasts on Oct 7. The contract settled 21 percent below its June 19 peak of $115.06. A 20 percent drop is a common definition of a bear market. Brent was at $90.93 today.
Saudi Arabia lowered the November official selling price, or OSP, last week for its Arab Light grade to Asia by $1 a barrel to a discount of $1.05 to the average of Oman and Dubai crude, the lowest level since December 2008. The move followed reductions by Iran and Iraq for October, signaling the start of a potential battle for customers in Asia, according to Commerzbank AG and Citigroup Inc.
Rather than stoke competition with other nations in the Organization of Petroleum Exporting Countries, the lower prices were intended to revive profit margins for Asian refiners, a person familiar with Saudi policy said yesterday.
Preferred Range
A range of $95 to $110 a barrel is suitable for consumers and producers, Saudi Arabia’s Al-Naimi said at OPEC’s last meeting on June 11 in Vienna. The average price of benchmark OPEC crudes dropped below $90 for the first time in more two years, the group said yesterday. OPEC will discuss prices and production at a meeting on Nov. 27 in Vienna, Al-Naimi said on Sept. 11.
History shows that Saudi OSP cuts precede decreases in production, not increases, Giovanni Staunovo, an analyst at UBS in Zurich, said by e-mail on Oct. 6. Prices will rebound by the end of year, Staunovo said.
BNP Paribas forecasts that Brent will average $108 a barrel during the fourth quarter. Barclays Plc estimates an average of $93 during the same period, reduced from $106 previously, according to an e-mailed report today.
“I don’t think there’s any rush on the Saudis’ side to bring the market lower” when disappointing demand could do that anyway, Francisco Blanch, head of commodities research at Bank of America Corp., said by phone from New York on Oct. 7. “I don’t think a price war is going on. Saudi Arabia will cut if needed.”
Europe is set to boost natural gas storage capacity in the coming years as markets liberalize and nations seek to reduce reliance on Russian fuel, according to the International Center for Natural Gas Information.
There are currently 44 billion cubic meters (1.6 trillion cubic feet) of storage sites being built or expanded globally, 50 percent of which are in Europe, Cedigaz, as the Paris-based center is known, said by e-mail. The region plans 55 billion cubic meters more, or 59 percent of proposed global capacity.
Trading of European gas is increasing as markets liberalize, boosting competition. The European Union is looking to diversify supplies as a conflict between Russia and Ukraine threatens to disrupt supplies to the region like it did in 2006 and 2009. Russian fuel meets about 30 percent of the region’s needs, half of which travels through pipes across Ukraine.
“There are a lot of countries in Europe so a lot of them want probably their projects for different reasons, some for security of supply,” Geoffroy Hureau, secretary general of Cedigaz, said by telephone, adding that other reasons include liberalization and competition.
Europe will need more storage facilities as its reliance on imported gas is set to rise to 70 percent by 2030 from 50 percent last year, according to Cedigaz. Demand will gain 15 percent to 595 billion cubic meters in the period.
Storage sites in the European Union’s 28 members contained 77.2 billion cubic meters of gas as of Oct. 8, the most since at least 2009, making them 93 percent full, according to Gas Infrastructure Europe, a Paris-based lobby group.
Planned Inventories
The U.K. has the most gas storage capacity under construction or planned, followed by Germany and Italy, Cedigaz data showed. Germany currently has the most operational capacity in the EU, five times more than the U.K., according to data from Eurogas. Salt caverns account for 33 percent of potential new capacities, highlighting the growing need for short-term flexibility as markets liberalize, according to the center.
Some of the projects currently planned in Europe may not be built as they were proposed before demand started to fall, Hureau said. EU consumption of the fuel declined over the past three years, according to Cedigaz. Another drop is forecast for 2014, according to Eurogas, which estimates 9 percent less usage this year.
Global gas storage capacity in operation rose 5 percent to 399 billion cubic meters in the year to Jan. 1, with European space expanding 3 percent to 101 billion, according to Cedigaz. In North America, capacity also expanded by 3 percent to 157 billion cubic meters, the data showed.
In the Middle East, capacity more than quadrupled to 6 billion cubic meters due to the commissioning of the Shourijeh facility in Iran, the only country in the region with underground gas storage, Cedigaz said. In Asia and Oceania, inventory space expanded 15 percent to 17 billion cubic meters.
BRUSSELS, Oct. 9 (UPI) -- The European Union said Serbia needs to get in line with regional energy regulations, notably as they relate to the planned South Stream gas pipeline.
Serbia and the EU begin formal discussion on accession in January. In a status report, the EU said the Serbian government has made progress in aligning itself with European governance, but it's lacking in key foreign policy and economic areas.
"Serbia needs to step up its efforts towards alignment with the EU acquis in particular in the fields of energy -- including on the South Stream gas pipeline," it said Wednesday.
Serbian Foreign Minister Ivica Dacic met with Russian officials in Moscow this week to discuss the natural gas pipeline Russia views as a means to diversify a gas transit network vulnerable to geopolitical concerns over Ukraine.
Ukraine hosts more than half of all Russian natural gas bound for European markets. With Europe concerned over not only the crisis in Ukraine, but also the role of state-controlled companies like Russia's Gazprom, Dacic said lingering questions over South Stream should "be settled between Russia and Brussels."
Gazprom in 2013 supplied Serbia with about 70 billion cubic feet of gas and said Wednesday the country should have adequate winter supplies. The company said it was waiting for the necessary permits to begin South Stream construction in Serbia.
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BOSTON, Oct. 9 (UPI) -- Embracing a greener future is about charting a course of economic prosperity on both sides of the Atlantic, U.S. and British government officials said Thursday.
U.S. Secretary of State John Kerry met with British Foreign Secretary Phillip Hammond in Boston, where they toured a wind technology center.
Both leaders in a joint editorial published Thursday in the Boston Globe said economic advances would come from the development of renewable energy resources like wind energy.
"It's time to embrace the energy of the future -- not to endanger good jobs, but to create them," they write.
Britain is a world leader in terms of installed offshore wind energy. In the United States, there are more than 900 utility-scale wind projects in service on land and the government is preparing to advance the technology offshore.
Both leaders said their countries are increasing investments in clean energy. For the United States, the clean energy sector has created more than 70,000 jobs, while the British economy is on track to cut emissions by 80 percent by 2050 through the use of renewables.
"It is clear governments around the world need to do more," Kerry and Hammond said. "When they do, it will create even greater opportunities in a sector that's already thriving."
BEIJING, Oct. 9 (UPI) -- China National Petroleum Co. said Thursday it received consent from the government to start work on the Power of Siberia natural gas pipeline from Russia.
Russian President Vladimir Putin was on hand for the launch ceremony for construction of the Power of Siberia natural gas pipeline last month. CNPC said it received permission to start engineering work for its part of the pipeline and construction was slated for early 2015.
Putin said the new 2,500-mile gas pipeline to China will tie the Russian energy sector to both poles of the economic world.
A contract between Russian natural gas company Gazprom and CNPC is for 30 years and calls for 1.3 trillion cubic feet of natural gas per year.
Members of Putin's administration met Thursday in Moscow to discuss the terms of the bilateral gas deal.
"The parties are to support a successful implementation of this contract and provide comprehensive assistance to authorized companies in matters of designing, constructing and maintaining of the gas transport infrastructure needed to deliver Russian gas to China," the government said.
Moscow says the project should be completed in time for first gas deliveries in 2018.
LONDON, Oct. 9 (UPI) -- Environmental campaign group Greenpeace claimed victory Thursday after toy company LEGO announced it wouldn't renew a contract with Shell.
Greenpeace said Shell is building brand loyalty with the next generation of consumers, business leaders and politicians through its relationship with LEGO, which distributed toys through Shell's retail centers.
The advocacy group said its three-month campaign against the toy company paid off after LEGO announced it wouldn't renew a contract "with arctic destroyer Shell."
"It's a huge blow to Shell's strategy of partnering with beloved brands to clean up its dirty image as an arctic oil driller," the campaign group said in a statement.
In July, LEGO said it was being used as a scapegoat for Shell's operations in the arctic.
LEGO said Tuesday it wouldn't renew its contract with Shell, but expressed frustration with the Greenpeace campaign nonetheless.
"We firmly believe Greenpeace ought to have a direct conversation with Shell," Chief Executive Officer Jorgen Vig Knudstorp said in a statement. "The LEGO brand, and everyone who enjoys creative play, should never have become part of Greenpeace's dispute with Shell."
Shell aims to conduct an exploration campaign in the arctic waters off the coast of Alaska. Environmental groups like Greenpeace have expressed concern over drilling in arctic waters, saying an oil spill there would harm the pristine environment.
LONDON, Oct. 9 (UPI) -- British shale drilling pioneer IGas said Thursday it plans to drill its third well in the country's northwest next month to survey the reserve potential.
The company said it's completed some of the infrastructure necessary for exploration work at its Ellesmere Port site and expects to start drilling in November.
"This well, which is a vertical exploration well, will be the third drilled in a sequence designed to give IGas a suite of results distributed across its licensed areas in the northwest [of the country]," the company said in a statement.
The company in May completed drilling operations at the Irlam-1 exploration well, where data will be used to help provide information for any future program involving hydraulic fracturing of the Bowland shale.
The British Geological Survey in June estimated the Bowland shale formation in the north of the country contains 1.3 quadrillion cubic feet of natural gas.
At Ellesmere Port, the company said exploration work carried out so far has given it the confidence necessary to plan a preliminary hydraulic fracturing campaign.
"This will prove invaluable for future planning applications for potential shale wells and the ability to demonstrate the commerciality of gas extraction from these deep formations," it said.
Shale exploitation is in its infancy in the country. The government said shale gas could eventually offset imports, though operations so far have been met with widespread opposition.
WASHINGTON, Oct. 9 (UPI) -- Disrupting the ability of the group calling itself the Islamic State to raise funds through oil revenue is a key U.S. military objective, an official said.
U.S. Central Command said this week a series of airstrikes were carried out against the group variably known as the Islamic State of Iraqi and the Levant. Strikes inside Iraq and Syria were carried out with the support of Middle East and European allies.
Jen Psaki, a spokeswoman for the U.S. State Department, said there are targets outside the strategic border town of Kobani that require military attention.
"The transfer of oil or the ability of ISIL to gain funding and increased strength from oil revenues is of great concern," she said during a Wednesday press briefing. "That's one of the reasons why we've gone after the refineries, and that's one of the objectives of our efforts."
Peace advocates last month said disrupting oil financing may be a better strategy to contain the militant group than military strikes. The Islamic State at its peak was said to be generating about $2 million per day on pilfered oil.
The militant group claimed a brief hold over the Baiji oil refinery north of Baghdad in mid-June.
OSLO, Norway, Oct. 9 (UPI) -- The Norwegian government said its fight to reduce greenhouse gas emissions includes plans for a carbon capture and storage project by 2020.
Norwegian Energy Minister Tord Lien said carbon capture and storage technology is a necessary component of an effort to cut greenhouse emissions.
A report last year from the International Energy Agency said more investments are needed in carbon sequestration programs like CCS, describing them as essential to reducing greenhouse gases in a world still "hooked on fossil fuels."
"A comprehensive commitment to CCS is necessary to reduce greenhouse gas emissions," Lien said in a statement Wednesday. "The government's ambition is to realize at least one full-scale demonstration facility by 2020."
The government said the CCS effort would be challenging, however, because of a lack of land-based facilities suitable for CCS.
The Norwegian economy relies on renewable resources for energy production, but is the regional leader in oil and natural gas production.
The government said it was ready to join European efforts to develop full-scale CCS projects apart from the pilot ambitions in Norway.
MOSCOW, Oct. 9 (UPI) -- The start of operations at an oil field in West Siberia is a sign the Russian energy sector remains competitive, Russia's deputy prime minister said.
Deputy Prime Minister Arkady Dvorkovich joined Lukoil President Vagit Alekperov for the commissioning of the Imilorskoye in West Siberia.
Dvorkovich said tapping into the field is a testament to the technological know-how of the oil company's employees.
"I am sure that this is an important indicator of the competitiveness of the Russian fuel-and-energy complex," he said in a statement.
Lukoil was among the companies sanctioned by Western governments in response to Russia's role in the eastern Ukrainian conflict.
The company estimates the complex of fields in the West Siberian region holds around 1.4 billion barrels of oil. Alekperov said commissioning came six months ahead of schedule.
"[Imilorskoye] is strategically important for the development of LUKOIL," he said.
The development plan calls for the restart of more than a dozen legacy wells.
Lukoil is Russia's largest non-state operated oil company.
WASHINGTON, Oct. 9 (UPI) -- While the Ukrainian gas issue may have short-term consequences, regional economies need to address simmering issues of their own, the World Bank said.
A report from the U.N. High Commissioner for Human Rights finds residents across Ukraine are growing concerned about energy issues, as they fear there could be a natural gas shortage this winter.
"The tensions in Ukraine have clearly had an impact on the country's growth and have disrupted economic activity," Laura Tuck, vice president for the World Bank's emerging Europe and Central Asia region, said in a statement. "But many of the structural problems that confront countries in the region existed before the crisis and still need to be urgently addressed."
Political upheaval in Ukraine in November left an economy already damaged by recession in shambles. Russian energy company Gazprom cut gas supplies to Ukraine earlier this year because of mounting debt.
Tuck said the bank was monitoring the potential short-term impact the Ukrainian crisis for the region, though there are longer-term issues that need to be addressed.
From Central Europe to the Balkans, economies need to rekindle their economies as the recession ends.
"In Russia and many neighboring countries, key are reforms to enhance competitiveness and create sources of growth beyond oil and gas," she said.
TEHRAN, Oct. 9 (UPI) -- Iran will be ready to unveil a new oil contract regime by early 2015 should sanctions pressure ease, top energy officials said.
Iranian Oil Minister Bijan Zangeneh said the "final touches" are being put on a new oil contract system and then will be put before government officials for approval.
Economic sanctions imposed on Iran in response to its controversial nuclear program have constrained oil production. The Organization of Petroleum Exporting Countries said in its latest monthly market report output from member state Iran was around 2.7 million barrels per day, about 7 percent less than it was in 2012.
"In case the sanctions are annulled, a new model of oil contracts will be unveiled [at a February oil conference] in London" Mehdi Hosseini, head of the ministry's contract committee, said Wednesday.
The new contract proposal would do away with buy-back contracts, where Tehran agrees to pre-set price, and replace them with a joint venture system, where international companies would be paid with a share of the output.
Iran under the terms of an agreement with six world powers working to resolve the nuclear impasse can export around 1 million bpd. That limited relief from sanctions could be cancelled should diplomatic efforts fail by the end of the year.
New York (Platts)--9Oct2014/422 pm EDT/2022 GMT
Crude futures closed lower Thursday after the dollar rose and a closely watched report slashed Germany's economic growth forecast.
ICE November Brent crossed below $90/barrel for the first time since June 2012, falling as low as $89.90/b before settling $1.33/b lower than Wednesday's close at $90.05/b.
NYMEX November crude finished the day $1.54 lower at $85.77/b.
In refined products, front-month NYMEX ULSD settled down 3.93 cents at $2.5366/gal, while NYMEX November RBOB closed 4.35 cents lower at $2.2749/gal.
The dollar gained ground Thursday, putting downward pressure on oil prices, after retreating Wednesday when minutes from the latest Federal Reserve meeting delayed expectations of an interest rate hike.
In Europe, a semi-annual report by leading German think tanks pegged the country's economic growth at 1.3% this year and 1.2% in 2015, a downward revision compared with their earlier forecast of 1.9% and 2%.
IMF chief Christine Lagarde said the eurozone could fall into recession unless actions are taken, AFP reported.
"I thought the risks of an economic slowdown, ample supply and strong dollar had been priced in, but the market can't seem to find any traction," Gene McGillian, analyst at Tradition Energy, said.
"The primary factors that have been pushing down prices continue to be present as the market hunts for a bottom," he said.
Another bearish sign has been the change in term structures for front month/12th month spreads, especially over the last week.
Over that time, the NYMEX crude future curve has become less backwardated, while the ICE Brent future curve has become more in contango.
The shift toward contango is evidence of a well-supplied crude market, Dennis Gartman, publisher of the Gartman Letter, said.
"Crude, in other words, is now bidding for storage across an entire year; supplies are large; demand is lessening and competition amongst the leading exporters is becoming more and more and ever more intense. The term structures don't lie," he said.
Contango is when prices are less expensive for front-month delivery, while backwardation is the opposite situation -- a front-month contract is more expensive than later delivery.
One consequence of the contango market has been stockpiling by Chinese buyers, Barclays analysts said in a note Thursday.
Stockpiling has mitigated the impacts of global production cuts, while also creating a crude overhang, they said.
"The rapid demand contraction, dollar strengthening and unexpected Libyan output return has lowered prices, and in combination with the contango, shields the market from a disruption in supplies from Libya, Iraq or other OPEC countries," the bank analysts said.
Barclays revised downward their crude forecasts for the fourth quarter by $13/b, predicting prices will average $93/b for ICE Brent and $85/b for NYMEX crude.
As prompt Brent flirts with $90/b, a move lower could trigger fresh selling, amid growing open interest in bearish put options at strike prices between $85-$90/b.
Energy Aspects analysts in their weekly note warned that a move toward $85/b would do just that, especially considering the record short position that has been built up by money managers.
ICE Commitment of Traders data released Tuesday showed speculative shorts rose to a record high 163,923 contracts for the week ended September 30.
"[V]arious producer hedges between $75 and $85 expose many banks (who are short these put options) to falling prices and could risk creating significant downside and volatility in the market as banks may be forced to sell flat price in order to cover their options books," the analysts said.
"It is not a given that prices are necessarily falling below $85, but if they do, the amount of short put options held by banks can lead to a downward spiral."
Swap dealers -- many of which are market makers at investment banks -- saw long positions grow to 349,032 contracts over the same period, their highest so far this year.
Open interest in Brent November $90 puts was around 4,499 lots Wednesday, with around 625 lots traded. Open interest at this strike has been growing since the beginning of summer, as prompt Brent prices have sunk from more than $114/b in mid-June. Open interest in the $90 put was just 300 lots on July 1, ICE data showed.
Open interest in the November $85 put has also risen, up to 2,273 lots on Wednesday from around 300 lots on July 1. But 132 lots have traded so far Thursday, up from nothing over the past three trading days. Volume for the $90 put shows 285 lots traded Thursday.
Open interest data is delayed one day.
Argentina unloaded its first October LNG cargo on Tuesday at the port of Escobar as seven vessels remained in queue offshore, the longest wait since September 14, data from Platts' ship tracking software cFlow showed Thursday. The Polar Spirit discharged a partial cargo of 89,880 cubic meters, the first LNG vessel to unload at an Argentine port since September 25 as mild spring temperatures reduced domestic demand for natural gas and dwindling foreign currency reserves have slowed LNG imports to the country.
"Beyond the problem with US dollars, they've also made a very poor consumption estimate" said one South American based market observer. "A large portion of these [LNG] volumes won't be necessary and accordingly, they should reduce domestic production to make space for the LNG."
Argentina's Planning Ministry, which overseas energy affairs, late Wednesday said high tides and strong winds from unusual spring temperatures made it impossible for vessels to enter the ports of Bahia Blanca and Escobar from October 2 to October 6.
The ministry added that this was not the first time such conditions delayed the off-loading of vessels.
While weather may have impacted Argentina's recent ability to discharge LNG cargoes, two vessels have been in queue for three weeks or longer with a total of seven ships still waiting to discharge volumes, four outside the port of Escobar and three outside the port of Bahia Blanca.
The Lobito has been idling offshore for the last 26 days, while the Iberica Knutsen has been in a holding pattern for the last 21 days.
More recent arrivals include the Sestao Knutsen on September 22, the Arctic Spirit on September 30, the Lena River on October 4 and most recently the Cadiz Knutsen and the Methane Princess. The British Ruby was recently redirected toward Cape Town, South Africa, likely for bunkering, after spending seven days offshore the Port of Bahia Blanca.
"[LNG cargoes] will be unloaded as the vessels are authorized to enter port to inject the gas [to the pipelines system]" Argentina's Planning Ministry said in a statement without providing any timeline.
Argentina typically buys LNG under take-or-pay tender contracts and often pays a risk premium for cargoes. The country is the largest importer of LNG in South America, having imported a total of 11.78 million cu m of LNG in 2013, according to data from Platts unit, Bentek Energy.
London (Platts)--9Oct2014/852 am EDT/1252 GMT
The contango between front and second-month CIF Northwest Europe naphtha swaps is at its widest in 26 months as the force majeure at Shell's Moerdijk cracker exacerbates the oversupply in Europe and amid a weak Asian market, trading sources said.
The contango was assessed $5/mt higher Wednesday at $6.50/mt, the widest since May 31, 2012, when it was $7/mt.
The front-month CIF NWE crack swap fell $1.35/barrel Wednesday to an eight-week low of minus $6.75/barrel, and the CIF Northwest Europe naphtha cargo value was $18.75/mt lower at $742.50/mt, its lowest level in 27 months.
"There is a lot of product available for prompt delivery and demand is not there," a trader said, adding nobody in Europe seemed interested in open specification naphtha, and adding that the sharp weakening of the naphtha paper structure was due both to the Moerdijk cracker being offline and falling premiums in Asia.
Shell declared force majeure on ethylene and propylene production at its 900,000 mt/year steam cracker at Moerdijk in the Netherlands at the end of last week, following a steam leak at the unit last Thursday.
The cracker, which usually uses 100,000-200,000 mt of naphtha per month as feedstock, could stay offline until the end of the year, market participants said.
"I think the paper market is reacting to Shell's force majeure requiring them to sell an estimated 200,0000 mt of material that would have otherwise been cracked in Moerdijk," a trader said.
One European end-user said the weakening of naphtha paper structure had more to do with the increasingly softer Asian market.
"It is due to the fact that Asia stopped buying," he said.
The front-month east/west spread -- the premium of CFR Japan naphtha cargo swaps over the CIF NWE naphtha cargo swap -- narrowed to $28.50/mt Thursday from $29/mt Wednesday and $30/mt Tuesday as naphtha was offered lower in Asia, leading to the deepest physical discounts in over two years.
At noon London time, the contango between the front and second-month CIF NWE Europe naphtha swaps was heard at $7.25/mt and the front-month CIF NWE naphtha crack was at minus $7.80/barrel.
Libyan crude differentials to Dated Brent have pushed up above the October official selling prices over the last week, trading sources said, as strong Mediterranean sweet crude demand and growing confidence in the country's reliability prompted an increase in demand.
On Wednesday, Platts assessed FOB Es Sider Aframax cargoes at a $1/barrel discount to the Mediterranean Dated Strip, its highest level relative to the 13-28 day forward Dated Brent curve since the grade resumed loading in August after more than a year of near-constant disruption.
Wednesday's assessment was a full $0.10/b above the October OSP of $1.10/b set by state-owned National Oil Company.
Traders said the upswing in differentials has not been limited to distillate-rich Es Sider, but has carried across the country's slate of sweet crude exports.
"El Sharara, Mellitah, Brega and Abu Attifel...these grades have all [seen] an increase in premiums," a trading source said.
The majority of Libya's land-based crude exports are sweet, ranging from naphtha-rich grades like Mellitah and Sharara, which are direct competitors to Algeria's Saharan, to more distillate-rich crudes like Es Sider, which is seen as a frequent substitute for Azerbaijan's Azeri Light, Russia's Siberian Light, or even, for some end-users, Russia's Urals.
Earlier this week, Turkey's Tupras reportedly tendered for either an Aframax cargo of Urals or of Es Sider, ultimately settling on the cargo of Es Sider.
"Some refiners could prefer Es Sider over Urals -- it's pushing out Azeri [demand] for some and Urals for others," another trader said. "It's not the same grade, but it is filling some gaps."
Market sources said market confidence in the reliability of Libyan grades has been improving, despite the ongoing political unrest in the country, as disruptions to the country's petroleum sector has proved minimal since production restarted in earnest this summer.
Production in the country is currently hovering around 900,000 b/d.
However, market sources said part of the increase in demand has been driven by the surge in sweet crude differentials across the Mediterranean, as strong refinery margins at the prompt have led to a surge in buying interest, pushing differentials for Azeri Light, Saharan and CPC Blend up to multi-month highs.
"People are now diversifying into Libyan," a crude trader said. "CPC and Azeri got too strong for people and they are now willing to take that Libyan risk because Libyan is so cheap versus Saharan...Saharan is now around plus $0.70/b, so why wouldn't you buy Mellitah if it's so much cheaper."
Singapore (Platts)--9Oct2014/544 am EDT/944 GMT
Bangladesh will import gasoil with 0.05% sulfur content, instead of 0.2-0.25%, from January 2015, in line with instructions from the Ministry of Environment and Forest, Bangladesh Petroleum Corporation Chairman Eunusur Rahman said Thursday.
State-owned BPC had already sent letters to gasoil suppliers on the lower sulfur specifications, he said, adding that no responses had been received from the suppliers as yet.
BPC is Bangladesh's sole importer of gasoil and has term deals with Kuwait Petroleum Corporation; Petco, the trading arm of Malaysia's Petronas; Emirates National Oil Company, or ENOC; PetroChina; Vietnam's Petrolimex; and Unipec Singapore.
It currently imports around one-third of its total gasoil requirement from KPC, according a BPC official.
Importing the lower sulfur gasoil might lead to higher import costs, Rahman said.
Apart from gasoil, BPC imports 180 CST high sulfur fuel oil, A-1 jet fuel, 95 RON gasoline and superior kerosene.
Bangladesh is the latest country to join a slew of Asia Pacific and Middle Eastern countries in adopting cleaner fuels as part of a global push.
In Asia, Sri Lanka, which was previously importing 0.25% sulfur gasoil, has progressively switched to 500 ppm sulfur gasoil earlier this year, with the majority of its import volumes now of that grade.
In North Asia, China is planning to move from the current National Phase 3 standard, which limits sulfur to a maximum of 350 ppm, to National Phase 5 standard, which is comparable to Euro V standard, that caps sulfur at 10 ppm, by 2017.
In the Middle East, the United Arab Emirates in July, switched its motor fuel specifications from 500 ppm sulfur gasoil to 10 ppm sulfur.
Saudi Arabia is expected to make a similar switch around 2016-2017.
Jordan Petroleum Refinery which was previously importing 0.5% sulfur gasoil, recently switched to importing 500 ppm sulfur.
While in East Africa, five countries -- Uganda, Tanzania, Kenya, Rwanda and Burundi -- have agreed to lower their sulfur content in motor fuels to 50 ppm for diesel and 150 ppm for gasoline by January 1, as the region plays its part in reducing emissions.
Buenos Aires (Platts)--9Oct2014/951 am EDT/1351 GMT
Russia's Gazprom plans to partner with Argentina's state-run energy company YPF on a $1 billion project for developing natural gas in the South American country, while Germany's Wintershall is also looking at opportunities, Argentine Industry Minister Debora Giorgi said Wednesday.
Gazprom "is closing an agreement of confidentiality with YPF," Giorgi said in a statement from the 4th St. Petersburg International Gas Forum.
"The agreement will be for the exploration and production of gas in Argentina, for which $1 billion in investments is estimated," she said.
Giorgi made the comments after meeting at the conference with Alexey Miller, chairman of Gazprom's management committee.
Miller said he will send a team of specialists to Argentina in November, according to the Industry Ministry statement.
In a separate statement, Gazprom said the meeting between Giorgi and Miller involved "the development prospects for the bilateral cooperation in the gas sector, with an emphasis on exploration and production of gas from Argentine gas fields."
Gazprom said it also will look at the possibility increasing liquefied natural gas sales to Argentina, which started importing the supplies off the global market in 2008.
Gazprom said it won a tender in 2013 to supply 15 LNG cargoes with a total volume of one million tons to Argentina between 2014 and 2015.
Giorgi added that Wintershall also expressed interest at the conference of increasing its business in Argentina, possibly in partnership with Gazprom and YPF.
Wintershall has been producing oil and gas in Argentina for years, and has acreage in shale plays, including through a partnership signed in January with the state oil company of Neuquen province, Gas y Petroleo del Neuquen.
They plan to invest an initial $110 million in exploratory drilling before moving into the production phase.
Argentina is seeking investment, expertise, equipment and technology to develop shale resources estimated at among the world's largest.
The country wants to regain energy self-sufficiency after oil and gas production fell by 20% over the past decade to widen the energy trade deficit to $10 billion this year.
Houston (Platts)--8Oct2014/359 pm EDT/1959 GMT
A rare cargo of Colombian crude is set to be loaded in the second half of October for delivery to South Korea, said Latin American crude market sources Wednesday.
A 1 million-barrel cargo of an undisclosed crude will load from the port of Covenas on October 25 on the vessel Delta Ocean, according to Platts cFlow vessel tracking software.
The cargo was heard sold by Colombia's state oil company Ecopetrol to South Korean refiner Hyundai, but a source close to Ecopetrol did not comment. Hyundai operates a 310,000 b/d refinery at Daesan, South Korea.
Colombian exports to Asia have in the past included China and India.
The Delta Ocean is currently in the Mediterranean with an estimated time of arrival in Gibraltar of October 10, according to Platts cFlow.
Ecopetrol typically loads 1 million-barrel cargoes of Castilla Blend from Covenas and Suezmax-sized vessels (500,000 barrels) of Vasconia from Covenas.
Castilla Blend has a gravity of 18.8 API and 1.96% sulfur, while Vasconia has a gravity of 24 API and 0.90% sulfur.
Meanwhile, the Polar Discovery is currently on its way to South Korea with Alaska North Slope crude, according to Platts cFlow.
The US-flagged Suezmax departed from Valdez on September 26 and is just west of Japan en route to the Yeosu, South Korea, according to Platts cFlow. The vessel's estimated time of arrival is October 11.
The last time US West Coast or PADD 5 crude exports were more than 9,000 b/d was in April 2004, when exports averaged 27,000 b/d or a total for the month of around 810,000 barrels, according to US Energy Information Administration data.
ANS is typically exported to refiners in California, Washington and occasionally to Hawaii.
An increase in the volumes of Bakken crude being railed to Pacific Northwest and California refiners has depressed demand for ANS in those regions.
Houston (Platts)--8Oct2014/320 pm EDT/1920 GMT
US propane and propylene stocks reached 80.65 million barrels for the reporting week ending October 3, beating record stocks of 79.56 million barrels during the previous week, Energy Information Administration data showed Wednesday.
US stocks showed a boost of 1.085 million barrels for the reporting week.
These stocks declined by 548,000 barrels during the comparable week last year. US stocks are now 21.3% higher compared to the beginning on October 2013.
Market sources indicated last week that stocks may show a downward trend as the winter demand season approaches.
But some market sources suggested the stocks would rather increase in the range of 600,000-900,000 barrels with lower demand.
Midwest stocks rose 3,000 barrels to 27.96 million barrels. They declined by 22,000 in the previous week.
Gulf Coast stocks rose 768,000 barrels to 43.22 million barrels, beating last week's historic high for that region.
These inventories were down 538,000 barrels in the comparable week last year.
Atlantic Coast stocks rose 74,000 barrels to 5.94 million barrels.
US stocks of propylene for nonfuel use decreased once again by 175,000 barrels week on week to 2.65 million barrels.
These stocks have declined since the week ending June 6, when the nonfuel use was 4.23 million barrels.
Imports in the reporting week were up 58,000 b/d to 115,000 b/d.
Implied demand decreased 2.7% week on week to 1.12 million b/d.
Gulf Coast propane at the Enterprise terminal in the Mont Belvieu, Texas, hub was trading at $1.06125/gal on IntercontinentalExchange Wednesday morning, some 2.3 cents higher than at 3:15 pm EDT (1915 GMT) Tuesday.
Singapore (Platts)--9Oct2014/848 am EDT/1248 GMT
Shanghai bunker fuel prices fell to a 45-month low Wednesday as weak crude oil market sentiment and a week-long holiday in China increased selling activity, but traders said Thursday they hoped the lower values would now attract buyers.
Shanghai 380 CST bunker fuel fell $14.50/mt to $549.50/mt Wednesday, the lowest level since $545.50/mt on January 10, 2011.
The marker was assessed at $548.50/mt Thursday.
This is the largest single day drop in Shanghai's 380 CST delivered bunker fuel market since April 8, 2013, when the price fell $18/mt.
Shanghai bunker fuel traders said sales volumes rose prior to the Chinese holiday October 1-7.
"We hope to sell more this week, to make up for the loss of sales during the holiday," a Shanghai trader said.
Traders said prices should improve in the medium term, as buying interest has already increased.
"Some shipowners are already buying fuel for dates as far as 10 days forward, in expectation that bunker fuel flat prices will moves up if crude futures rebound," another trader said.
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The decision of the United States to stop the importation of Nigeria’s light blend of crude oil due to the shale oil boom has exposed the US refineries to the dangers associated with the processing of lighter shale oil.
As a result of the increased domestic production of shale oil, the US has slashed crude oil imports from a peak of almost 14 million barrels per day in 2006, to slightly above 7 million barrels per day.
Crude oil import from Nigeria, one of the principal sources of light crude, was also slashed from more than 1 million barrels per day in 2010 to zero in July 2014.
But the US refineries, Reuters has reported, are designed to handle medium blend crude as against the much lighter shale oil being produced in the country to replace imports from Nigeria and others.
US refiners are said to have shown a strong preference for a medium blend, but almost all the oil being produced as a result of the shale boom is much lighter than the refineries can handle.
Reuters reported that while imports of medium-heavy and heavy grades of crude oil (with specific gravity of less than 30 degrees) have remained roughly constant at 4.5 to 5 million barrels per day since 2007, imports of medium-light and light oils have dropped from 6 million barrels per day to just over 2 million.
Imports of the lightest grades of oil, the closest substitutes for domestic shale production, have been reduced from 2.5 million barrels in 2007 per day to just 500,000 in the first seven months of 2014, according to US Energy Information Administration (EIA).
The sudden change in the grades of crude oil processed by the refineries were said to have threatened the capacity of the plants to blend the different grades to derive the required quality of refined products.
The refineries are said to be conscious of the quality and density of crude oil as “crude varies considerably in terms of density, acidity, type of hydrocarbon molecules they contain, and presence of impurities such as sulphur and heavy metals such as nickel and vanadium.”
For instance, if the crude oil contains too much acid or salt, the refinery’s equipment will be damaged by corrosion, while with too many heavy metals, the catalysts that aid refining will be poisoned.
On the other hand, too much sulphur will make the crude too hard to meet specifications for petroleum products.
Also, if the crude oil is of the wrong density, it will be impossible to maximise the efficiency of the refinery’s distillation tower and other units.
The average density of crude oil processed in the US refineries since 1985 has been fairly steady and in statistical terms, the weighted average specific gravity has been 31.1 degrees with a standard deviation of just 0.7 degrees.
But according to EIA’s US crude oil production forecast, analysis of crude oil types released in May 2014, “roughly 96 percent of the 1.8 million barrels per day growth in (domestic) production between 2011 and 2013 consisted of grades with American Petroleum Institute (API) gravity of 40 or above.”
To handle the lighter shale oil, the US refiners need to reconfigure their plants to handle a lighter average blend, but that would take time and involves costly investment.
The simpler option, it was learnt, would be to lift the ban on crude oil exports and allow US refiners to continue to import and refine more of the heavier oil they prefer.
Russia’s economy will be impacted more from falling oil prices than from sanctions, according CEIC.
The Russian economy often pays a price for being more or less a one trick pony. Oil and gas revenues are imperative to a balanced budget. And oil prices are in decline. The iPath S&P GSCI Crude Oil Total Return (OIL) fund is down 15.85% over the last three months. Russian equities are following their leader.
“Recent political risk has taken 2% from our GDP forecast, but falling oil prices are going to hurt our balance of payments,” said Russia’s Finance Minister Anton Siluanov at the Russia Calling investor conference, which concluded in Moscow last Thursday. “Thanks to a fairly cautious economic policy, we’ve been able to live through this without creating big deficits.”
The Russian government’s recent draft federal budget for 2015 and projections for 2016 and 2017 give an overview of just how much falling commodity prices will impact government accounts. So far, despite sanctions and oil prices in decline since June, Russia will end the year with a surplus of 196.8 billion rubles ($5.04 billion). This amount has been in decline since the first quarter, however. A deficit is being budgeted for the next three years.
The key element of Russia’s budget planning is oil.
http://blogs-images.forbes.com/kenrapoza/files/2014/10/Russia-CHART.jpgWith oil prices estimated by the government to average $100/barrel for 2015-2017, Russia may be over-estimating. Brent crude settled at $88.97 per barrel for the November 2014 futures contract on Thursday.
Since the largest share of government revenue comes from oil and gas revenues, the ruble’s devaluation will play a significant role in meeting the budget targets for the current year, while posing risks for inflation down the road. This situation is exacerbated by falling oil prices since July.
“You have rising inflation, falling oil revenues and a weaker economy,” says Mike Reynal, an emerging markets fund manager for RS Investments in Des Moines. ”Ukraine’s political crisis and the sanctions against Russia also hurts investor sentiment. The impact sanctions and oil have on growth are all very negative. The 0.5% growth rate is marginally at risk now. Inflation is over 8%. So you have high inflation and no growth and a Central Bank that doesn’t want to protect the ruble but will have to protect it regardless, which means you are likely to see interest rate hikes in a moribund economy. It’s an investor nightmare.”
Investors do not believe that Russia will use oil and gas as a weapon in its sanctions war against the West. In such a scenario, Russia would limit exports of natural gas to a dependent European Union. In theory, this would drive up prices as Russia tightens supplies.
“I think the energy markets have come to the conclusion that the conflict will not be allowed to get really bad because there is a deep, and broad energy integration between Russia and the E.U.,” says Jan Dehn, an economist with the Ashmore Group in London. “I believe energy markets have that priced in.”
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Just how big a deal is oil to the Russian government?
The federal budget ran a surplus from 2000 until 2008 because of it. Oil, coupled with conservative economics, saved Russia from numerous liquidity crunches. The draft federal budget for 2015 figures a slight deficit from then until 2017. The revenue plan for 2014 is set at 14.2 trillion rubles, and current revenues reached 9.4 trillion rubles as of August 2014. Budget expenditure planned for 2014 is set at 14.0 trillion rubles and current expenditure amounts to 8.5 trillion rubles, thus creating a budget surplus of 905.5 billion rubles as of August 2014.
“We have a surplus despite a very difficult economic situation,” Vladimir Putin told a gathering of roughly 1,500 at Russia Calling last week. “We’re not going to raise taxes to compensate for revenue declines,” he said.
In order to keep that promise, Russia won’t increase expenditures, including reductions in infrastructure spending and agricultural subsidies over the next three years. To grow, Russia will have to rely on the private sector. Yet, Russia remains a monopolistic economy, dominated by commodities, namely oil and gas.
CEIC analyst Alexander Dembitski said in a recent report that Russia will struggle to control its deficit.
“Maintaining high rates of growth is unlikely without boosting spending on the national economy items in the budget,” he wrote.
Meanwhile, the economic outlook for Russia will be determined by the global price of oil, domestic inflation, the depreciation of the ruble and the Ukrainian crisis, which has sanctioned Russia’s access to foreign credit.
“The government is not investing. Corporations are investing less. And interest rates are going to rise,” said Reynal. “This is not a good scenario.”
Russian equities have been declining in line with falling oil prices. The Market Vectors Russia (RSX) exchange traded fund is down 8.55% since April while the OIL ETF is down 14.96%.
There is, to those of a somewhat romantic bent, an inherent beauty in financial markets.
Even just simple supply and demand has an appealing logic. As demand for a product increases, the price goes up, prompting an increase in supply, which in turn brings the price back down. When you look at the flow of money between countries and asset classes in a global sense, that tendency towards equilibrium becomes much more complex, but it is still the driving force of markets, with the same inherent self-correcting tendencies. Foreign exchange rates, interest rates in different countries, and stock prices around the world are all part of this complex dance, but in the modern, energy dependent world, the price of oil is arguably the most influential variable.
Oil, despite several different benchmarks such as Brent and WTI, is a commodity traded on a global market. While the value of a country’s currency, or the interest rate its government must pay to borrow, can affect economic conditions in that country, fluctuations in the oil price affect us all. Whether we like it or not, oil is still the principal source of the world’s energy, and pricing of the two next largest sources, coal and natural gas, are heavily influenced by the price of the black stuff. According to The International Energy Agency (IEA), those three accounted for over 80 percent of the world’s energy supply in 2012. Lower oil prices, therefore, give a boost to the global economy, while a rapid rise can strangle growth.
The wide variations in the production cost of oil make it very sensitive to price swings. When costs vary as much as they do, from an average cost per barrel in the Middle East of $16.68 per barrel to offshore American oil that costs $51.60 per barrel to extract (again using IEA numbers), many wells can quickly become uneconomical when prices are volatile, leading to supply dropping. If demand and supply were the only thing that influenced the price, that would be manageable, but they are not.
Oil is priced in U.S. dollars, so the relative strength of the dollar also impacts the price. If the dollar gains in strength, it gains against everything, including commodities.
To simplify, if, as a starting point, one barrel of oil could be exchanged for $100 and then the dollar doubles in overall value, it would take two barrels to buy the same number of dollars. Dollars would have doubled in value and therefore the price of oil, as expressed in dollars, would halve.
The dollar’s strength or weakness is influenced by many things, but one of the biggest is its status as a “safe haven” currency. When the economic outlook looks to be worsening, money around the world is used to buy the relative safety of U.S. dollars, and this is where the self-correcting beauty of markets comes in.
As the dollar strengthens, oil prices fall. Lower oil prices push down the cost of manufacturing and transporting goods, which in turn improves economic prospects around the globe. The reaction to worry has, at least in part, helped to alleviate that worry.
Increasing supply as the shale boom continues apace, combined with worries about global growth and the resultant strong dollar, can explain why, even with global tensions increasing, the price of oil has been falling. This is bad news for oil companies and their stockholders, but in the long run it will give a boost to the global economy.
When that happens, the whole process will reverse and the “invisible hand” that guides financial market will once again have done its job.
By Martin Tillier of Oilprice.com
Washington Takes on ISIS, Iran, and Russia.
It was heinous. It was underhanded. It was beyond the bounds of international morality. It was an attack on the American way of life. It was what you might expect from unscrupulous Arabs. It was “the oil weapon” -- and back in 1973, it was directed at the United States. Skip ahead four decades and it’s smart, it’s effective, and it’s the American way. The Obama administration has appropriated it as a major tool of foreign policy, a new way to go to war with nations it considers hostile without relying on planes, missiles, and troops. It is, of course, that very same oil weapon.
Until recently, the use of the term “the oil weapon” has largely been identified with the efforts of Arab producers to dissuade the United States from supporting Israel by cutting off the flow of petroleum. The most memorable example of its use was the embargo imposed by Arab members of the Organization of the Petroleum Exporting Countries (OPEC) on oil exports to the United States during the Arab-Israeli war of 1973, causing scarcity in the U.S., long lines at American filling stations, and a global economic recession.
After suffering enormously from that embargo, Washington took a number of steps to disarm the oil weapon and prevent its reuse. These included an increased emphasis on domestic oil production and the establishment of a mutual aid arrangement overseen by the International Energy Agency (IEA) that obliged participating nations to share their oil with any member state subjected to an embargo.
So consider it a surprising reversal that, having tested out the oil weapon against Saddam Hussein’s Iraq with devastating effect back in the 1990s, Washington is now the key country brandishing that same weapon, using trade sanctions and other means to curb the exports of energy-producing states it categorizes as hostile. The Obama administration has taken this aggressive path even at the risk of curtailing global energy supplies.
When first employed, the oil weapon was intended to exploit the industrial world’s heavy dependence on petroleum imports from the Middle East. Over time, however, those producing countries became ever more dependent on oil revenues to finance their governments and enrich their citizens. Washington now seeks to exploit this by selectively denying access to world oil markets, whether through sanctions or the use of force, and so depriving hostile producing powers of operating revenues.
The most dramatic instance of this came on September 23rd, when American aircraft bombed refineries and other oil installations in areas of Syria controlled by the Islamic State of Iraq and Syria (ISIS, also known as ISIL or IS). An extremist insurgent movement that has declared a new “caliphate,” ISIS is not, of course, a major oil producer, but it has taken control of oil fields and refineries that once were operated by the regime of Bashar al-Assad in eastern Syria. The revenue generated by these fields, reportedly $1 to $2 million daily, is being used by ISIS to generate a significant share of its operating expenses. This has given that movement the wherewithal to finance the further recruitment and support of thousands of foreign fighters, even as it sustains a high tempo of combat operations.
Black-market dealers in Iran, Iraq, Syria, and Turkey have evidently been assisting ISIS in this effort, purchasing the crude at a discount and selling at global market rates, now hovering at about $90 per barrel. Ironically, this clandestine export network was initially established in the 1990s by Saddam Hussein’s regime to evade U.S. sanctions on Iraq.
The Islamic State has proven adept indeed at exploiting the fields under its control, even selling the oil to agents of opposing forces, including the Assad regime. To stop this flow, Washington launched what is planned to be a long-term air campaign against those fields and their associated infrastructure. By bombing them, President Obama evidently hopes to curtail the movement’s export earnings and thereby diminish its combat capabilities. These strikes, he declared in announcing the bombing campaign, are intended to “take out terrorist targets” and “cut off ISIL’s financing.”
It is too early to assess the impact of the air strikes on ISIS’s capacity to pump and sell oil. However, since the movement has been producing only about 80,000 barrels per day (roughly 1/1,000th of worldwide oil consumption), the attacks, if successful, are not expected to have any significant impact on a global market already increasingly glutted, in part because of an explosion of drilling in that “new Saudi Arabia,” the United States.
As it happens, though, the Obama administration is also wielding the oil weapon against two of the world’s leading producers, Iran and Russia. These efforts, which include embargoes and trade sanctions, are likely to have a far greater impact on world output, reflecting White House confidence that, in the pursuit of U.S. strategic interests, anything goes.
Fighting the Iranians
In the case of Iran, Washington has moved aggressively to curtail Tehran’s ability to finance its extensive nuclear program both by blocking its access to Western oil-drilling technology and by curbing its export sales. Under the Iran Sanctions Act, foreign firms that invest in the Iranian oil industry are barred from access to U.S. financial markets and subject to other penalties. In addition, the Obama administration has put immense pressure on major oil-importing countries, including China, India, South Korea, and the European powers, to reduce or eliminate their purchases from Iran.
These measures, which involve tough restrictions on financial transactions related to Iranian oil exports, have had a significant impact on that country’s oil output. By some estimates, those exports have fallen by one million barrels per day, which also represents a significant contraction in global supplies. As a result, Iran’s income from oil exports is estimated to have fallen from $118 billion in 2011-2012 to $56 billion in 2013-2014, while pinching ordinary Iranians in a multitude of ways.
In earlier times, when global oil supplies were tight, a daily loss of one million barrels would have meant widespread scarcity and a possible global recession. The Obama administration, however, assumes that only Iran is likely to suffer in the present situation. Credit this mainly to the recent upsurge in North American energy production (largely achieved through the use of hydro-fracking to extract oil and natural gas from buried shale deposits) and the increased availability of crude from other non-OPEC sources. According to the most recent data from the Department of Energy (DoE), U.S. crude output rose from 5.7 million barrels per day in 2011 to 8.4 million barrels in the second quarter of 2014, a remarkable 47% gain. And this is to be no flash in the pan. The DoE predicts that domestic output will rise to some 9.6 million barrels per day in 2020, putting the U.S. back in the top league of global producers.
For the Obama administration, the results of this are clear. Not only will American reliance on imported oil be significantly reduced, but with the U.S. absorbing ever less of the non-domestic supply, import-dependent countries like India, Japan, China, and South Korea should be able to satisfy their needs even if Iranian energy production keeps falling. As a result, Washington has been able to secure greater cooperation from such countries in observing the Iranian sanctions -- something they would no doubt have been reluctant to do if global supplies were less abundant.
There is another factor, no less crucial, in the aggressive use of the oil weapon as an essential element of foreign policy. The increase in domestic crude output has imbued American leaders with a new sense of energy omnipotence, allowing them to contemplate the decline in Iranian exports without trepidation. In an April 2013 speech at Columbia University, Tom Donilon, then
Obama’s national security adviser, publicly expressed this outlook with particular force. “America’s new energy posture allows us to engage from a position of greater strength,” he avowed. “Increasing U.S. energy supplies acts as a cushion that helps reduce our vulnerability to global supply disruptions and price shocks. It also affords us a stronger hand in pursuing and implementing our international security goals.”
This “stronger hand,” he made clear, was reflected in U.S. dealings with Iran. To put pressure on Tehran, he noted, “The United States engaged in tireless diplomacy to persuade consuming nations to end or significantly reduce their consumption of Iranian oil.” At the same time, “the substantial increase in oil production in the United States and elsewhere meant that international sanctions and U.S. and allied efforts could remove over 1 million barrels per day of Iranian oil while minimizing the burdens on the rest of the world.” It was this happy circumstance, he suggested, that had forced Iran to the negotiating table.
Fighting Vladimir Putin
The same outlook apparently governs U.S. policy toward Russia.
Prior to Russia’s seizure of Crimea and its covert intervention in eastern Ukraine, major Western oil companies, including BP, Chevron, ExxonMobil, and Total of France, were pursuing elaborate plans to begin production in Russian-controlled sectors of the Black Sea and the Arctic Ocean, mainly in collaboration with state-owned or state-controlled firms like Gazprom and Rosneft. There were, for instance, a number of expansive joint ventures between Exxon and Rosneft to drill in those energy-rich waters.
“These agreements,” Rex Tillerson, the CEO of Exxon, said proudly in 2012 on inking the deal, “are important milestones in this strategic relationship... Our focus now will move to technical planning and execution of safe and environmentally responsible exploration activities with the goal of developing significant new energy supplies to meet growing global demand.” Seen as a boon for American energy corporations and the oil-dependent global economy, these and similar endeavors were largely welcomed by U.S. officials.
Such collaborations between U.S. companies and Russian state enterprises were then viewed as conferring significant benefits on both sides. Exxon and other Western companies were being given access to vast new reserves -- a powerful lure at a time when many of their existing fields in other parts of the world were in decline. For the Russians, who were also facing significant declines in their existing fields, access to advanced Western drilling technology offered the promise of exploiting otherwise difficult-to-reach areas in the Arctic and “tough” drilling environments elsewhere.
Not surprisingly, key figures on both sides have sought to insulate these arrangements from the new sanctions being imposed on Russia in response to its incursions in Ukraine. Tillerson, in particular, has sought to persuade U.S. leaders to exempt its deals with Rosneft from any such measures. “Our views are being heard at the highest levels,” he indicated in June.
As a result of such pressures, Russian energy companies were not covered in the first round of U.S. sanctions imposed on various firms and individuals. After Russia intervened in eastern Ukraine, however, the White House moved on to tougher sanctions, including measures aimed at the energy sector. On September 12th, the Treasury Department announced that it was imposing strict constraints on the transfer of U.S. technology to Rosneft, Gazprom, and other Russian firms for the purpose of drilling in the Arctic. These measures, the department noted, “will impede Russia’s ability to develop so-called frontier or unconventional oil resources, areas in which Russian firms are heavily dependent on U.S. and western technology.”
The impact of these new measures cannot yet be assessed. Russian officials scoffed at them, insisting that their companies will proceed in the Arctic anyway. Nevertheless, Obama’s decision to target their drilling efforts represents a dramatic turn in U.S. policy, risking a future contraction in global oil supplies if Russian companies prove unable to offset declines at their existing fields.
The New Weapon of Choice
As these recent developments indicate, the Obama administration has come to view the oil weapon as a valuable tool of power and influence. It appears, in fact, that Washington may be in the process of replacing the threat of invasion or, as with the Soviet Union in the Cold War era, nuclear attack, as its favored response to what it views as overseas provocation. (Not surprisingly, the Russians look on the Ukrainian crisis, which is taking place on their border, in quite a different light.) Whereas full-scale U.S. military action -- that is, anything beyond air strikes, drone attacks, and the sending in of special ops forces -- seems unlikely in the current political environment, top officials in the Obama administration clearly believe that oil combat is an effective and acceptable means of coercion -- so long, of course, as it remains in American hands.
That Washington is prepared to move in this direction reflects not only the recent surge in U.S. crude oil output, but also a sense that energy, in this time of globalization, constitutes a strategic asset of unparalleled importance. To control oil flows across the planet and deny market access to recalcitrant producers is increasingly a major objective of American foreign policy.
Yet, given Washington’s lack of success when using direct military force in these last years, it remains an open question whether the oil weapon will, in the end, prove any more satisfactory in offering strategic advantage to the United States. The Iranians, for instance, have indeed come to the negotiating table, but a favorable outcome on the nuclear talks there appears increasingly remote; with or without oil, ISIS continues to score battlefield victories; and Moscow displays no inclination to end its involvement in Ukraine. Nonetheless, in the absence of other credible options, President Obama and his key officials seem determined to wield the oil weapon.
As with any application of force, however, use of the oil weapon entails substantial risk. For one thing, despite the rise in domestic crude production, the U.S. will remain dependent on oil imports for the foreseeable future and so could still suffer if other countries were to deny it exports. More significant is the possibility that this new version of the oil wars Washington has been fighting since the 1990s could someday result in a genuine contraction in global supplies, driving prices skyward and so threatening the health of the U.S. economy. And who’s to say that, seeing Washington’s growing reliance on aggressive oil tactics to impose its sway, other countries won’t find their own innovative ways to wield the oil weapon to their advantage and to Washington’s ultimate detriment?
As with the introduction of drones, the United States now enjoys a temporary advantage in energy warfare. By unleashing such weapons on the world, however, it only ensures that others will seek to match our advantage and turn it against us.
By Michael T. Klare
Should the West worry about Russia’s growing oil and gas exports to the Asia-Pacific region? Michael Bradshaw doesn’t think so. While Vladimir Putin may want to shift his energy business from Europe to China, Gazprom needs Western revenues to build the desired pipeline infrastructure.
The 30-year gas deal between Russia’s Gazprom and China’s National Petroleum Corporation (CNCP), signed last May, for the supply of 38 billion cubic meters (bcm) of pipeline gas from 2018 onwards, marks the culmination of a decade of negotiations. Last year it was announced that everything was agreed but the price. No doubt the West’s reaction to events in Ukraine focused minds in Moscow to make sure the deal was done. Although the financial details of the agreement are unknown, the price is thought to be in the range of $350-$380 per thousand cubic metres -- about the average price that Gazprom charges to its European customers. At the time, Gazprom stated that the contract contains a “price formula linked to oil prices” and a “’take-or-pay' clause,'" which suggests an agreement akin to those that dominate Gazprom’s exports to Europe. An investment of $55 billion is required in Russia to develop the fields at Chayanda (in Sakha-Yakutia) and Kovytka (in Irkutsk) and to build the ‘Power of Siberia’ pipeline tothe border at Blagoveshchensk. To assist in the development phase, China will provide a loan of $25 billion. To prevent Russia from being reliant on a single buyer, the pipeline will also continue to Vladivostok where it will feed Gazprom’s planned Vladivostok LNG (Liquefied Natural Gas) plant.
Not surprisingly, this agreement has been dubbed Gazprom’s ‘Deal of the Century.’ Nevertheless, there may be much more to come.
More on the way
There are indications that an agreement for the additional 30 bcm may be signed by the end of the year. The original inter-governmental agreement signed in 2006 envisaged a total of 68 bcm of gas being exported via two corridors: the eastern corridor that is the basis of the initial agreement and a western corridor that would bring gas from West Siberia to China via the so-called Altai route. The gas from West Siberia would feed into an expanded ‘West-East Gas Pipeline’ that would bring additional gas from Central Asia. To help address the country’s chronic air pollution problems, the Chinese Government has demanded a substantial increase in the domestic use of natural gas. Securing such a substantial amount of pipeline gas to supplement domestic production and the import of LNG into coastal regions will go some way towards doubling the amount of gas used – from 5 percent today to 10 percent by the end of this decade, and again to 20 percent by 2030.
The Chinese Government also hopes that domestic shale gas production can make a significant contribution, but so far progress has been slow and production estimates have recently been downgraded. Dr Keun-Wook Paik, from the Oxford Institute for Energy Studies, estimates that between 2020-25 the total volume of pipeline gas imported into China could be as high as 160-165 bcm, with 68 bcm coming from Russia (in 2013 Russia exported 130 bcm to Europe). As
China also has ambitious plans to expand domestic production and can always build additional LNG import capacity, it can easily hedge against Russia, using its gas supplies for geopolitical gain. China has clearly seized on Russia’s current problems with the West to strike a good deal on gas.
Siberia for sale
Russia’s desire to expand its economic ties with the Asia-Pacific region is a long-standing theme. In fact, it goes back to the Soviet period when a series of inter-governmental agreements between the USSR and Japan opened up trade in forestry and coal and financed the initial oil and gas exploration offshore of Sakhalin. Expanding energy ties with the Asia-Pacific is enshrined in Russia’s Energy Strategy and the targets were recently revised ahead of publication of a new strategy next year. The aim now is to increase the share of total Russian oil and gas products going to Asia from 12% to 23% by 2035 (including 32% of crude oil exports), and to increase gas exports from 6% (which is the Sakhalin-2 LNG project) to 31.5% by 2035, with the volume of LNG exports rising to 30 mtpa (41 bcm) by 2020 and to 100 mtpa (138 bcm) by 2035.
Expansion of oil exports to the Asia-Pacific predates the current gas deals. In the aftermath of the 2008 crisis the completion of the East Siberia Pacific Oil pipeline (ESPO) was financed by deals with Rosneft and Transneft that saw Chinese finance provided in return for deliveries of oil. Rosneft has since expanded this agreement and most recently offered 10 percent of its Vankor oilfield to CNCP. This latest deal, worth $1 billion, has likely been prompted by Rosneft’s need to raise finance in the light of Western sanctions. Again, an example of how Western sanctions are promoting the expansion of Russia’s energy relations with Asia. Rosneft is also reported to have offered India’s ONGC a share in its Yurubcheno-Tokhomskoye oilfield in East Siberia. It almost seems as if the current situation has prompted a garage sale of Siberia’s oil and gas resources.
The race for LNG exports is on
In late 2013 the Russian Government approved a limited liberalization of LNG exports. Previously Gazprom had a monopoly on all of Russia’s gas exports. The legislation permits LNG exports from Novatek’s Yamal LNG plant, which is currently under construction, and from Rosneft’s planned Far Eastern LNG plant on Sakhalin Island, where Gazprom has already made a final investment decision on the Vladivostok LNG plant and is also considering the expansion of Russia’s only operational LNG plant at Prigorodnoye on Aniva Bay in the south of Sakhalin, which is part of the Sakhalin-2 project. By 2020 there could be 15 mtpa of new LNG capacity in the Russian Far East, to add to the 10.8 mtpa currently in operation. The Yamal LNG plant in West Siberia is also targeting Asian markets during the summer months via the Northern Sea route and could add at least another 5 mtpa. However, it remains to be seen if they will all be built on time. Gazprom and Rosneft are involved in a very public argument over the best way to bring
Sakhalin’s additional gas to market. For various reasons, there may not be enough gas available in time for all the projects to be completed by 2020. If we were to assume that the 30 mtpa target is met and that a second pipeline deal is done, then in the early 2020s Russia could be exporting over 100bcm of gas to the Asia-Pacific region.
Does the eastward expansion of Russian oil and gas exports present a challenge to Europe? In the case of oil, the real issue is whether or not Russia can satisfy the contracts it has with China, plus exports to the Pacific, in addition to domestic demand and exports to Europe. The current sanctions may hamper Russia’s ability to develop new fields, and the existing old fields are rapidly declining. The result may well be a fall in Russian exports to world markets. The situation with gas is rather different as there is currently a gas glut in Russia, and Gazprom has slowed the pace of new field development in the face of competition from Novatek and the oil companies. Gazprom has more than enough reserves to meet its obligations to Europe—where the market is unlikely to grow and may yet decline—and its new supply commitments in Asia. The question is whether it has the capacity to finance and complete all of these projects in a timely and cost-competitive fashion.
Putin may wish to link the pipeline networks so that he can threaten to send Europe’s gas to Asia. The reality, however, is that Gazprom cannot afford to lose revenue from its exports to Europe, as that is needed to finance its new projects including the South Stream pipeline to bypass Ukraine. When it comes to LNG, there are likely to be delays in completing the projects and there is stiff competition from established suppliers as well as new projects in Australia, North America and East Africa. When it comes to pipeline gas, this means that Europe has little to worry about in relation to Russia’s plans in the east. Furthermore, if the expansion of gas exports to the Asia-Pacific helps to slow the rate of coal consumption, then everyone wins as it will help to reduce global carbon emissions.
By Michael Bradshaw
Total US crude oil pipeline mileage increased 6% and deliveries rose 11.3% during 2013, data compiled by the Association of Oil Pipe Lines and the American Petroleum Institute showed.
US crude pipelines stretched 60,911 miles, 3,448 miles farther than in 2012, while deliveries climbed by 845 million bbl year-to-year to nearly 8.31 billion bbl, the latest US Liquids Pipeline Usage & Mileage Report said.
“Pipeline usage and mileage are growing to bring the benefits of America’s energy production renaissance to the nation’s workers and consumers,” said AOPL Pres. Andrew J. Black as the two associations jointly released the report on Oct. 7.
US crude pipeline mileage has increased 8,174 miles or 15.5% in the last 5 years, and 11,647 miles or 23.6% in the last 10 years, Black said. Deliveries climbed 1.35 billion bbl, or 19.4%, over 5 years, he said.
The report noted that in 2013, US pipelines carrying crude, refined products, and natural gas liquids totaled 192,396 miles, which was 16,431 miles or 9.3% farther than 5 years earlier.
US transmission pipelines delivered 14.948 billion bbl of crude oil and petroleum products in 2013, up 869 million bbl or 6.2% from 2012 and 1.43 billion bbl or 10.6% from 5 years earlier, it indicated.
Tesoro Corp. Chief Executive Officer Gregory J. Goff called for a review of the Jones Act, a federal law dating from the 1920s that requires US-produced goods moving between US ports to do so aboard US-flagged vessels.
“To move crude oil from the Gulf Coast to Northeast refineries costs 2-3 times as much as to bring it from Saudi Arabia,” he said in remarks to the US Energy Association’s 7th Annual Energy Supply Forum on Oct. 2. “The Jones Act makes it economically impossible for us to buy North Dakota crude for our West Coast refineries and displace imports.”
Goff, who leads one of the nation’s largest independent refiner-marketers, said provisions in the federal Renewable Fuels Standard and proposed ozone regulations also could pose problems for domestic downstream operations.
But he added that Congress and other federal policymakers should at least discuss and debate ways the Jones Act makes US oil product markets less economic and efficient. “It’s possible repealing it will be the best solution, although that wouldn’t be easy,” Goff said.
His observations after Graeme Burnett, senior vice-president for fuel optimization at Delta Air Lines Inc., which owns a Northeastern US refinery, said on Sept. 23 that the Jones Act and RFS need to be reconsidered before more US crude oil exports are authorized.
Transportation needs
On the question of allowing more US crude exports, Goff said, “We believe the market should determine this. You can’t have impediments like the Jones Act, which hurts refiners’ ability to get products to consumers.”
He said that while independents have acquired a bigger share of US refining since 2008, transportation needs have become critical since gasoline and diesel fuel exports are expected to grow by 750,000 b/d by 2020.
“The industry is incredibly efficient getting crude to refineries or export terminals by pipeline and, more recently, rail which has been critical and highly efficient the past few years,” Goff said.
Tesoro would be half-owner of a proposed Vancouver, Wash., rail-to-marine terminal with an up to 360,000 b/d capacity that it hopes to have operating in 2015, subject to regulatory approval, he noted. “A project like this enhances US energy security, and would help get US crude to West Coast refineries,” he said.
The company also has proposed building a crude oil pipeline in Utah to transport Uinta Basin waxy crude to refineries north of Salt Lake City, reducing tanker truck traffic over mountain highways there. Stakeholder engagement is essential, Goff said.
“It’s an ongoing process,” he explained. “We’ve been working for some time to help people understand how we’re handling issues that arise. Like our Vancouver, Wash., project, we have to deal with diverse stakeholders, some of whom oppose fossil fuels.”
Goff said he expects the US Pipeline and Hazardous Materials Safety Administration to issue new crude-by-rail regulations by yearend. “As it moves forward, we expect some recommended changes to be adopted,” he said.
Bahrain Petroleum Co. (Bapco) has let a contract to Chevron Lummus Global (CLG), a joint venture of CB&I and Chevron Corp., for technology and engineering as part of the planned expansion and upgrade of the 267,000-b/d refinery at Sitra, on Bahrain’s eastern coast.
CLG will provide licensing for its proprietary LC-Fining and isocracking technologies as well as engineering design packages for the new residue hydrocracking and vacuum gas oil hydrocracking units included in the refinery’s modernization program, CB&I said.
The contract is valued at more than $100 million, CB&I said.
The current contract builds on CLG’s history of providing the Bapco refinery with hydroprocessing technologies and catalysts to produce clean transportation fuels and lubricant base oils from heavy oil for past projects, said Daniel McCarthy, president of CB&I’s technology operating group.
In June, Bapco let an $82.8 million contract to CLG to prepare an engineering design package for the new residue hydrocracking unit at the refinery, according to a public notice from Bahrain’s government (OGJ Online, Sept. 16, 2014).
A major modernization, the project aims to enhance the refinery’s configuration and profitability by increasing its crude processing capacity to 360,000 b/d and improving its yield of products.
In its 2012 annual report, Bahrain’s National Oil & Gas Authority (NOGA) said the refinery modernization program—which will take close to 6 years to complete in a series of phases—is one of the main structural projects of government’s plan to develop the country’s oil and gas sector and generate increased financial returns for the national economy.
The modernization will include the staged implementation of at least five units, including a residue hydrocracker, vacuum gas oil hydrocracker, diesel hydrotreater, sulfur recovery unit, and delayed coker.
Relatively low prices of natural gas have contributed to steady increases in US industrial gas consumption since 2009, especially as a feedstock for chemical production.
According to the US Energy Information Administration’s most recent Short-Term Energy Outlook, growth in US industrial demand will continue through 2015, with consumption averaging 21.3 bcfd in 2014 and 22.1 bcfd in 2015, a 4% increase, boosted by newly proposed chemical plants.
Two methanol plants are set to begin service this year—a small facility in Pampa, Tex., and another in Geismar, La. A handful of fertilizer plants have begun service, and an expansion is planned at a plant near Beaumont, Tex., later this year.
Continued growth in industrial demand is also supported by two large facilities coming online in 2015, a methanol plant in Clear Lake, Tex., and a fertilizer-urea plant in Wever.
“Many plants are on the Gulf Coast, but proximity to shale development in the Marcellus, Bakken, and Niobrara areas have led to proposals for facilities outside of Texas and Louisiana,” EIA said.
Abundant gas in the Bakken shale falls in the spectrum of developments. Two ammonia-based fertilizer plants are proposed for North Dakota for 2018. Farm-owned cooperative CHS Inc.’s proposed plant in Spiritwood and Northern Plains Nitrogen’s proposed plant for Grand Forks are both in permitting stages. Both have expected production of 2,400 tons/day of ammonia and would use close to 100 MMcfd of gas each, according to Bentek Energy estimates.
While most of the proposed methanol plants are on the Gulf Coast, two are proposed for 2018 in the Pacific Northwest. Northwest Innovation Works, a Chinese company, is planning two methanol facilities on the Columbia River in Washington and Oregon. The company hopes to export methanol produced in the US to Asian markets.
US refiners will have the capacity by 2020 to process 3.1-4.3 million b/d more of light, tight crude oil (LTC) than in fourth-quarter 2013, according to a Baker & O’Brien Inc. study commissioned by Consumers & Refiners United for Domestic Energy (CRUDE).
This is well beyond the US Energy Information Administration’s high reference case forecast for incremental US LTC production through 2020 in its 2014 Annual Energy Outlook, CRUDE said on Oct. 2 as it released the study’s findings.
“This insightful expert analysis refutes the argument advanced by many domestic oil producers, as well as some analysts, that the domestic refining industry will soon be unable to absorb all the oil that, thanks to new drilling techniques, is now flowing from North Dakota, Texas, and other regions of the US,” said Jeffrey Peck, a principal at Peck Madigan Jones and a spokesman for CRUDE.
The argument is being made to convince the Obama administration and Congress to remove restrictions from US crude exports, Peck said. “In fact, the US refining system is the largest, most complex, and flexible in the world,” he said, adding, “With displacement of existing imports, increased utilization, and investment in modest capacity expansions, US refiners should be able to process all the [LTC] that will be produced in the US for the remainder of this decade and likely for years beyond.”
US refiners have announced projects that would add 800,000 to 1.1 million b/d of LTC processing capacity by 2019, the study said. Refiners could implement projects beyond those which have been announced because several are still evaluating their options, it added.
Underutilized capacity
US refiners apparently underutilized their naphtha and lighter processing capacity during 2013’s final 3 months because of low crude throughput due to maintenance, economics, and other factors; and a crude slate oriented toward medium and/or heavy grades, the study said.
It said refiners could process another 432,000 b/d of LTC using existing capacity (with 320,000 b/d of incremental refinery crude runs, and 112,000 b/d through direct displacement of medium grades).
“For relatively moderate capital, it is expected that many refiners could debottleneck their facilities to process 10-20% more naphtha and lighter material,” the study said. “By 2020, it is estimated that refiners will implement additional projects that will absorb 108,000-503,000 b/d of [LTC], at an average industry cost of $50-$240 million/year (over 5 years).”
In its executive summary, the study said there is no limit from a conceptual standpoint to the amount of LTC that US refiners could process given proper economic incentives and enough lead time to modify and expand capacity.
It said LTC processing is relatively simpler and much less capital-intensive compared to the heavier, sour grades many refineries handle. “Similar to [LTC] production, [LTC] processing capacity is dynamic and is likely to respond to changes in [LTC] production,” it said. “If LTC production increases beyond projections, then additional LTC processing capacity is likely to be added.”
Stone Energy Corp., Lafayette, La., has agreed to lease the Ensco 8503 dynamically positioned deepwater drilling rig for Stone’s multiyear deepwater drilling program in the Gulf of Mexico.
The rig, which will be modified to include mooring capabilities prior to the commencement of the contract, can reach a maximum depth of 35,000 ft in as much as 8,500 ft of water.
The primary contract term is for 30 months and is expected to commence during second-quarter 2015 at a rate of $350,000/day. The contract permits Stone to exercise options to extend the term up to an additional 12 months, or reduce the 30 month primary term contract by up to 6 months.
“We are excited to execute our first Stone-operated multiyear deepwater drilling contract,” said David Welch, Stone chairman, president, and chief executive officer. “This contract will allow
Stone to better control the pace of execution of our deepwater drilling plans, which includes both development and exploration projects.”
The company in April discovered oil in the deepwater Cardona South well on the gulf’s Mississippi Canyon Block 29 (OGJ Online, Apr. 28, 2014).
The US drilling rig count lost 9 units to settle at 1,922 rigs working during the week ended Oct. 3, Baker Hughes Inc. reported.
Land rigs represented a majority of the loss, dropping 8 units to 1,850 overall. Offshore rigs edged down 1 unit to 61. Rigs drilling in inland waters were unchanged from a week ago at 11.
Gas rigs also lost 8 units, settling at 330. Oil rigs edged down a unit to 1,591.
Horizontal drilling rigs dropped 6 units to 1,341 while directional drilling rigs dropped 2 units to 209.
Canada’s rig count moved in the opposite direction compared with its southern neighbor, nudging its overall count up 1 unit to 430. A 3-unit gain in oil rigs to 249 was reduced by a 2-unit decline in gas rigs to 181. Canada currently has 69 more rigs working compared with this week a year ago.
Major states, basins
Modest movement for the third consecutive week in the major oil-and has-producing states resulted in gains in just two states. West Virginia was up 3 units to 30, and California edged up 1 unit to 46.
Unchanged from a week ago were North Dakota at 189, Louisiana at 113, Wyoming at 60, Pennsylvania at 57, Utah at 23, and Arkansas at 12.
Oklahoma, Colorado, and Kansas each edged down 1 unit to respective counts of 212, 76, and 24. Texas, New Mexico, Ohio, and Alaska each dropped 2 units to 895, 99, 40, and 9, respectively.
There were, however, some noteworthy gains in the major US basins. The Cana Woodford rose 4 units to 42 while the Eagle Ford rose 3 units to 210.
BP Oman has let two long-term drilling contracts totaling $730 million for the Khazzan gas project in the southern portion of Block 61.
The first agreement calls for KCA Deutag to construct and operate five newbuild land rigs to be assembled in Nizwa, Oman. The contracts total more than $400 million.
The second agreement calls for Oman’s Abraj Energy Service to supply three drilling rigs for the full field development. The contracts total more than $330 million.
Construction work for Khazzan is under way and production is expected to launch in late 2017.
Oman’s government and BP in December 2013 signed a gas sales agreement and an amended production-sharing agreement for development of the project. The agreements were ratified in February.
BP in February let a $1.2-billion engineering, procurement, and construction contract to UK-based Petrofac for a central processing plant (OGJ Online, Feb. 20, 2014).
The following month, BP let an engineering, procurement, and construction management services contract to Jacobs Engineering Group Inc. for $2 billion of gas gathering and water pipelines, wellhead production facilities, and export pipelines (OGJ Online, Mar. 4, 2014).
The project’s full field development involves a 300-well drilling program over 15 years to deliver plateau production of 1 bcfd of gas, equivalent to a one-third increase in Oman’s total daily domestic gas supply, BP says.
BP describes the Khazzan project as the first phase in the development of one of the Middle East’s largest unconventional tight gas plays, representing potential to serve as a major source of gas supply for Oman for many decades. The company in 2011 reported plans to invest $15 billion over a 10-year period for the full-field development of its Block 61 tight gas fields (OGJ Online, June 20, 2011).
BP operates Block 61 with 60% interest, and Oman Oil Co. for Exploration & Production holds the remaining 40%. BP’s upstream presence in Oman dates back to 2007.
For a second consecutive week the US drilling rig count was unchanged at 1,931 rigs working during the week ended Sept. 26, Baker Hughes Inc. reported.
This time, a 2-unit rise in land rigs to 1,858 was offset by a 2-unit decline in rigs drilling in inland waters to 11. Offshore rigs were unchanged at 62.
A 9-unit jump in gas rigs to 338 was nullified in the overall count by a 9-unit drop in oil rigs to 1,592. One rig considered unclassified remains from last week.
Horizontal drilling rigs gained 6 units 1,347 while directional drilling rigs edged down 1 unit to 2011.
In Canada, meanwhile, its rig count shot up 52 units to 429, 39 more than reported this week a year ago. A majority of the rise came from a 44-unit leap in oil rigs to 246. Gas rigs increased 8 units to 183.
Major states, basins
It was another week of light activity in the major oil- and gas-producing states. Wyoming’s 3-unit rise to a total of 60 led them all, with New Mexico’s 2-unit rise to 101 representing just the second multi-rig gain. Up a unit each were Colorado at 77, West Virginia at 27, and Alaska, which collected 3 units last week, at 11.
Unchanged from a week ago were North Dakota at 189, Louisiana at 113, Ohio at 42, Kansas at 25, Utah at 23, and Arkansas at 12.
Pennsylvania and California were each down a unit, now reporting respective totals of 57 and 45. Oklahoma lost 2 units to 213. Texas relinquished 3 units to 897, reflected in the Permian’s 4-unit drop to 556 and Barnett’s 3-unit drop to 22.
Wintershall Holding GMBH has let a $280 million subsea contract to FMC Technologies for the Maria development in the Norwegian Sea (OGJ Online, May 23, 2012).
Maria will be linked via subsea tie-back with the Kristin, Asgard, and Heidrun platforms.
The Maria Subsea Production System consists of two integrated template manifolds with respective trees and auxiliary equipment. It also includes the dynamic and the static umbilicals, the production riser base, the subsea umbilical termination unit, and the subsea control system.
Maria, 20 km east of Kristin and 45 km south of Heidrun, is expected to produce 130 million bbl of oil and 2 billion cu m of gas. Operator Wintershall has 50%; partners include Petoro 30% and Centrica 20%.
Wintershall said FMC Kongsberg Subsea AS was let the contract “after a thorough selection process and in alignment with the other license partners.”
Similar subsea systems are under consideration for Wintershall’s Skarfjell development and an extension north of Brage field.
Weakening global demand and higher Libyan oil exports have driven down North Sea Brent crude oil spot prices to an average of $97/bbl in September, a decrease of $5/bbl from August and the first month Brent crude oil prices have fallen below $100/bbl since June 2012.
In its most recent Short-Term Energy Outlook (STEO), the US Energy Information Administration forecasts Brent crude oil prices to average $104/bbl in 2014 and $102/bbl in 2015, $2/bbl and $1/bbl lower, respectively, than forecast in last month’s STEO.
WTI crude oil spot prices fell from a monthly average of $97/bbl in August to $93/bbl in September. The discount of WTI crude oil to Brent crude oil fell from an average of $8/bbl during this year’s first half to an average of $4/bbl in the third quarter, reflecting high refinery runs.
EIA now forecasts WTI crude oil prices to average $91/bbl in this year’s fourth quarter—$2/bbl lower than last month’s STEO—and average $95/bbl in 2015. The discount of WTI to Brent crude oil is forecast to widen from current levels, averaging $7/bbl in this year’s fourth quarter and in 2015.
Driven in large part by falling crude oil prices, US regular gasoline retail prices fell to an average of $3.41/gal in September, 29¢ below the June average, and are projected to continue to decline to an average $3.14/gal in December. EIA expects US regular gasoline retail prices, which averaged $3.51/gal in 2013, to average $3.45/gal in 2014 and $3.38/gal in 2015, both lower than last month’s STEO.
Global oil market
Global disruptions to near-term supply have abated since June, when Libya’s production and exports were at a minimal level, and violence in northern Iraq escalated. In September, unplanned crude oil supply disruptions among OPEC producers averaged 2.2 million b/d, 200,000 b/d lower than the previous month because of decreased outages in Libya.
“Iraq’s southern crude oil exports still remain unaffected by the unrest in northern Iraq. In Libya, production averaged 0.8 million b/d in September, its highest level in more than 1 year,” EIA said, adding that the security situation in Libya is however still precarious.
EIA expects OPEC crude oil production to fall 200,000 b/d in 2014 to 29.68 million b/d and by more than 400,000 b/d in 2015 to 29.24 million b/d, in accommodating the increase of non-OPEC supply.
Non-OPEC liquid fuels production is forecast to increase 1.9 million b/d in 2014 and 1.2 million b/d in 2015, averaging 55.98 million b/d and 57.15 million b/d, respectively, with the largest production growth from North America. This forecast assumes the current economic sanctions on Russian do not affect Russian oil production in the short term.
EIA expects worldwide liquid fuels consumption to rise by 1 million b/d in 2014 and by 1.2 million b/d in 2015, respectively, averaging 91.47 million b/d and 92.71 million b/d. EIA also expects a 200,000 b/d decline in consumption from countries in the Organization for Economic Cooeration and Development to 45.84 million b/d in 2014.
US oil, liquid fuels
With declines in the consumption of motor gasoline, hydrocarbon gas liquids, residual fuel oil, and other oils offsetting increases in distillate fuel and unfinished oils consumption, total US consumption of liquid fuels in 2014 is projected to average 18.92 million b/d, down 0.2% from 2013. Total consumption is expected to rise 170,000 b/d in 2015, with HGL consumption accounting for three fourths of the increase, according to EIA.
US crude oil production will average 8.5 million b/d this year, up from 7.4 million b/d last year, and 9.5 million b/d in 2015. Oil production from the Gulf of Mexico is expected to increase from 1.3 million b/d in 2013 to 1.6 million b/d in 2015, with 11 projects starting this year.
9 Oct 2014, 8.17 pm GMT
Caracas, 9 October (Argus) — An international arbitration panel has awarded ExxonMobil $1.6bn for the Venezuelan government´s 2007 expropriation of its local assets.
The award issued today by a three-judge panel of the International Centre for Settlement of Investment Disputes (Icsid) "confirms that the Venezuelan government failed to provide fair compensation for expropriated assets," ExxonMobil said today.
There was no immediate reaction from the Venezuelan government.
The Icsid award fell far short of the $20bn that the US major initially sought for the seizure of its Cerro Negro and La Ceiba assets, even though the company later reduced its goal to $6bn. The final amount paid to ExxonMobil could be cut back further if Caracas succeeds in subtracting an earlier compensation award.
The panel awarded $1.412bn for the 120,000 b/d Cerro Negro extra-heavy crude upgrader, located at the Jose complex in Anzoategui state. After the takeover, the facility was renamed PetroMonagas. Venezuela´s state-owned PdV now operates the facility with an 83.3pc stake. The balance is owned by Russia´s state-controlled Rosneft.
The Icsid award includes $179.3mn for La Ceiba, an oil field on the southeastern shore of Lake Maracaibo.
The ruling includes compound annual interest of 3.25pc from 27 June 2007--the date of the expropriation--until compensation is "paid in full".
Venezuelan government officials quietly hailed the compensation ruling as representing a fraction of ExxonMobil´s initial target.
The award nonetheless compounds pressure on the cash-strapped government at a time of falling international oil prices. Venezuela relies on oil exports for more than 95pc of its revenue. The government´s international hard currency reserves are shrinking and annual inflation is spiraling over 60pc. Recent violent clashes between police and armed gangs backed by the government are reviving a climate of instability that began with student-led protests in February.
Maduro succeeded late President Hugo Chavez who spearheaded a series of high-profile expropriations over his 14 years in power, including the ExxonMobil assets.
Still pending at Icsid is a separate compensation ruling concerning ConocoPhillips, whose Venezuelan upgraders, PetroZuata and Hamaca, and the Corocoro oil field, were also expropriated.
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Eni: World oil, gas reserves continue to rise
Italy’s Eni SPA has published its thirteenth edition of the World Oil & Gas Review, the annual statistics review of world oil and gas production, reserves, and consumption, with a particular focus on refining industry and crude quality.
According to the recently released review, 2013 world oil and gas reserves increased respectively of 0.4% and 1.7% mainly thanks to the US’s tight oil new plays and to the gas discoveries in East Africa.
The US holds its leadership in the crude oil production growth, with an increase of 12.2% compared with year 2012 by virtue of the contribution of tight oil. US production counterbalances the drop of Iran and Libya (–9.8% and –35.5%, respectively).
Eni’s data show that world’s oil and gas consumption increased 1.4% and 1%, respectively, in 2013, with US’s demand prominent.
Although there remains consumption weakness in Europe, countries in the Organization for Economic Cooperation & Development recorded an upswing in oil demand in 2013—the first since the economic crisis. As for non-OECD countries, China retained its top spot, reaching second in terms of worldwide oil consumption.
The European refining sector is facing a deep rationalization process, with about 2 million b/d of capacity reductions in the last years. But European refining overcapacity endures, amplified even more by a general decrease of demand.
The availability of low-cost crude is boosting refinery competitiveness in the US. Asia-Pacific and the Middle East are the areas with lately largest investments in new refining capacity to support a growing demand, confirming an ongoing trend.
In 2013, worldwide growth in gas consumption was modest, about 1% compared with an annual average of 2.5% recorded during 2000-13. The large availability of US gas production sustained the growth in consumption, confirming the US’s position as the world’s top gas consumer.
