By Marek Strzelecki and Maciej Martewicz Aug 6, 2014 9:58 PM GMT+0700
July 31 (Bloomberg) -- Kevin Sara, Chief Executive Officer at Nur Energie, talks with Guy Johnson about the technology behind the challenge of supplying Europe with solar energy gathered in the African desert. He speaks on “The Pulse.”
Europe’s energy dilemma -- burning the dirtiest coal while meeting pollution targets -- is crystallizing in opposition to a plan that would uproot 700-year-old villages and dig two pits the size of Manhattan.
PGE SA and Vattenfall AB, the Warsaw- and Stockholm-based utilities, want to tap Europe’s richest lignite deposit, along the German-Polish border. They’re opposed by communities already suffering sporadic sand storms and crumbling roads, in an area where the 12 kilometer (7.5 miles) long Jaenschwalde mine has dominated the landscape for three decades. Locals will form an 8-kilometer cross-border human chain on Aug. 23 in protest.
The battle reflects the divide across Europe. Polish Prime Minister Donald Tusk sees coal, used to generate 90 percent of his nation’s power, as a way for Europe to depend less on Russian natural gas. German Chancellor Angela Merkel’s government calls lignite “the black gold” that will help smooth out fluctuations from wind and solar generation. The European Union, to which both belong, wants tighter pollution rules that make coal pricier to burn.
Confronting Coal
“We feel like Asterix and Obelix fighting the Roman Empire,” said Andreas Stahlberg, an engineer analyzing the impact of the expansion for the German municipality of Schenkendoebern, referring to the French comic strip characters resisting powerful invaders. “Since Poles are dealing with the same problem and the mines will be so close, we think this is an international issue,” he said in an interview in Gubin, Poland.
2010 Purchase
PGE bought the project in the Polish towns of Gubin and Brody from the state for an undisclosed amount in 2010, a year after it was blocked in a referendum. Poland’s largest utility has since tried to persuade the almost 11,000 locals in the area to change their minds and approve zoning plans that would include the mine.
Zbigniew Barski, mayor of the 7,300-strong Gubin rural community that surrounds the town of the same name, and Ryszard Kowalczuk, his counterpart in neighboring Brody, still oppose the project.
Including the mine in zoning plans means coal resources will be prioritized over other developments, Kowalczuk said May 28 in an interview at his office. “We are closing the community for new investments for many years,” he said.
‘Indispensable’ Fuel
Lignite is a soft, brown, sedimentary rock formed from compressed peat. Germany is embracing the fuel to back up intermittent solar and wind power and compensate for lost output as it shutters nuclear plants, Thoralf Schirmer, a Vattenfall spokesman in Cottbus, Germany, wrote in an e-mail June 6.
A palace stands in Luboszyce, between Gubin and Brody.
Lignite’s share of the nation’s power generation rose to 26 percent last year from 23 percent in 2010, according to data from AG Energiebilanzen e.V., an association of energy lobbies and economic research institutes.
Coal for delivery next year to Northwest Europe is up 2.6 percent from this year’s low at $79.25 a ton. The contract is down 8.5 percent in 2014.
Fossil fuels, including lignite, “are part of the national energy mix and are indispensable for the foreseeable future,” Merkel’s party said in a treaty with the Social Democrats, its coalition partner.
Poland’s use of the fuel has risen 15 percent since 2010, according to grid data, displacing generation from hard coal, which PGE says is as much as 50 percent more expensive.
Burning coal at power plants emits about twice as much carbon dioxide as natural gas. Lignite is about 16 percent dirtier than hard coal, according to the Polish government.
Suffering Communities
The European Commission seeks a deal by October to cut greenhouse-gas emissions across the 28-nation bloc by 40 percent by 2030 from 1990 levels. The current target is for a 20 percent reduction by 2020.
Gubin and Brody have suffered financially since plans for the mine were announced in 2008. Buying and selling of arable land slowed and as a result fewer farmers can take loans to expand, Barski said in a May 28 interview at his Gubin office, less than four kilometers from fields that would be swallowed up by the expansion.
After plans to build the mine were announced, the amount of farmland sold by Gubin’s Agricultural Property Agency fell by more than a third from prior years from 2009 to 2013, data provided by the agency’s branch in Zielona Gora show.
PGE may start work on the 10,000-hectare (24,700-acre) mine within four years if it gets the approvals, according to Jacek Kaczorowski, who heads PGE’s conventional generation unit. The project may be expanded with an adjacent power plant depending on Polish and EU climate and energy policies, he said in an e-mail June 9.
Russian Gas
Poland relies on Russia for 59 percent of its gas, according to Eurogas, a Brussels-based lobby group. The new mine is instrumental to promoting coal as an alternative, Prime Minister Tusk said during a May 22 visit to Gubin.
“I want to be as clear and definitive as possible that the Polish energy mix will be based on coal, both hard and brown,” Tusk said. “We need to prove to all Europeans that such investments are safe from the point of view of CO2 and other emissions. But the intention here is clear, this investment will happen.”
Vattenfall, which plans to cut its carbon-dioxide emissions by more than 26 percent by 2020, will decide whether to build a new power plant next to Jaenschwalde in the next five to 10 years, Schirmer said. The project includes expanding the mine to the north along the Polish border.
Local Woes
Schenkendoebern’s 3,800 residents, 16 kilometers away, are suffering even before any new coal has been mined.
Ground water levels are declining, while sand and smoke from the mine has cut electricity output from the solar panels that once made the community self-sufficient, Stahlberg said May 28 without providing specific data.
The towns are working together across the border. Schenkendoebern is supplying data on the environmental, economic and social impact of the pit to Gubin as they seek an energy mix based on renewable power instead, Barski said.
“A Polish mine will only make things worse, my village will be an island between two pits,” said Eugeniusz Swiderski, a Polish farmer about two kilometers away from Jaenschwalde who has lived in the area for more than 30 years.
This month’s demonstration is being organized by an association called “No to the Pit,” which includes people from Brody and Gubin.
Opposing the utility, which sponsors sports and cultural events, isn’t easy, says Marzena Prugar-Wasilewska, who heads the organization.
“We’re staying united even though sometimes dividing lines cross families,” she said.
To contact the reporters on this story: Marek Strzelecki in Warsaw at mstrzelecki1@bloomberg.net; Maciej Martewicz in Warsaw at mmartewicz@bloomberg.net
To contact the editors responsible for this story: Lars Paulsson at lpaulsson@bloomberg.net Philip Revzin
By Lynn Doan Aug 6, 2014 11:47 PM GMT+0700
California, home to two-thirds of refining capacity in the western U.S., brought in a record volume of waxy oil by rail from Utah in June as crude imports from Canada and North Dakota slid.
The state, the biggest gasoline market in the U.S., received 2,737 barrels a day of oil by rail from Utah in June, almost twice the volume of the previous month and up from nothing a year ago, data on the state Energy Commission’s website showed yesterday. Canadian oil-by-rail imports dropped 25 percent to 6,669 barrels a day. North Dakota shipments shrank by 34 percent to 4,035.
California’s oil-by-rail deliveries are at a seasonal record as refiners in the western U.S., lacking direct pipeline access, use trains to reach surging crude production from shale formations in the center of the country and in Canada. Utah is shipping record volumes of oil by rail as companies use a combination of hydraulic fracturing and horizontal drilling to draw the most waxy oil out of its Uinta Basin since 1987.
Ultra Petroleum Inc., a Houston-based independent oil and gas driller that bought $650 million worth of oil-producing assets in the Uinta Basin in northeast Utah last year, said July 31 that “rail capacity is the best option to place our barrels.”
“By 2016, we expect to market approximately 45 percent of our crude oil volumes via rail,” Garland Shaw, the company’s chief financial officer, said in a conference call with analysts. The company has agreements for at least 2,000 barrels a day of rail capacity that can expand to 7,500, he said.
Small Fraction
Rail shipments still account for a small fraction of oil supplies in the western U.S. In May, the region took 1.1 million barrels of crude a day from outside the U.S., according to data compiled by the Energy Information Administration, the Energy Department’s statistical arm.
Demand for Uinta Basin oil may be limited by California refiners’ ability to receive and process the black, waxy oil, David Hackett, president of energy consulting firm Stillwater Associates in Irvine, California, said by telephone yesterday.
“It’s hard to place because of its high pour point,” he said. “They don’t call it black wax for nothing. At room temperature, it’s a candle.”
Refiners in the western U.S. ran 2.51 million barrels a day of crude last week, the highest rate in 11 months, the EIA said today.
To contact the reporter on this story: Lynn Doan in San Francisco at ldoan6@bloomberg.net
To contact the editors responsible for this story: David Marino at dmarino4@bloomberg.net Richard Stubbe, Bill Banker
Calgary (Platts)--6Aug2014/429 pm EDT/2029 GMT
Canadian independent Canexus later this month will begin loading Cold Lake blend crude from its rail terminal in Alberta, destined for refineries in North America, CEO Doug Wonnacott said Wednesday.
"Shipping of Cold Lake blend will begin on unit trains with the completion of maintenance and expansion of our [North American Terminal Operations] facility in late August," he said on a webcast to discuss the company's second-quarter earnings.
The work, which started June 17, includes the installation of 12 new loading arms and a tie-in of the Cold Lake pipeline system operated by Inter Pipeline, Wonnacott said.
The system serves several leading oil sands producers in Alberta's Cold Lake region, including Cenovus Energy, Shell, Imperial Oil and Canadian Natural Resources.
Wonnacott did not indicate the volumes of Cold Lake blend Canexus plans to ship on rail cars, but Lavonne Zdunich, a company investor relations official, said Canexus will initially load on behalf of Cenovus.
She did not disclose either the volumes or the destination, citing confidentiality reasons. No comments were immediately available from Cenovus.
Last summer, Inter Pipeline said it had a binding 10-year agreement with Canexus to supply 100,000 b/d of firm capacity from the Cold Lake pipeline system to Canexus' rail loading terminal.
Canexus, which inaugurated the North American Terminal Operations rail loading facility at Bruderheim, Alberta, in December, currently has Cenovus and fellow oil sands producer MEG Energy as its anchor customers.
The company initially started with loading two unit trains a month, each with a 58,500 b/d capacity of primarily Access Western Blend, and in April operated a total of 12 unit trains, Zdunich said, without giving latest details on the number of unit trains that were loaded before maintenance work started.
"With the completion of our maintenance and expansion, we will be ramping up to six to seven units trains a week," Wonnacott said. "Sometime in 2015, we will also have an option of a minor debottlenecking of our loading facilities to increase the number of unit trains to 11 [a week]."
Besides unit trains, Canexus also loads crude oil on manifest trains.
A manifest train is a combination of rail cars that transport not only crude oil, but also hoppers for shipment of grain and other cars loaded with coal, chemicals and general freight.
In the second quarter, Canexus shipped 10,400 b/d on manifest trains, compared with 17,200 b/d during the first quarter 0f 2014, Wonnacott said, without giving a reason.
From July to September, the company's target is to load seven manifest trains, each with a capacity of 4,000-20,000 b/d, he said.
GROWTH PLANS, ASSET SALE
Meanwhile, Canexus' 480-acre site at Bruderheim also presents the company with multiple growth opportunities that could potentially include the construction of a diluent recovery unit to improve crude-by-rail economics and backhauling of condensates from either the Chicago or the US Gulf Coast areas to meet a growing demand from oil sands producers, Wonnacott said.
Separately, Canexus has also received interest from potential buyers for the sale of the North American Terminal Operations facility, Wonnacott said, noting: "It's early days, and our focus will be on stabilizing the company and getting the terminal up and running [to its new capacity]."
Canexus will look for buyers that bring in cash and operating experience, he said, without divulging the names of interested parties.
--Ashok Dutta, newsdesk@platts.com --Edited by Annie Siebert, ann.siebert@platts.com
Rio de Janeiro (Platts)--6Aug2014/325 pm EDT/1925 GMT
Brazil's National Petroleum Agency, or ANP, has opened data rooms for 10 onshore blocks holding marginal accumulations of oil in an attempt to generate interest from small and medium producers, the regulator said.
The ANP will make seismic surveys and well-performance data available to interested companies at the regulator's offices in Rio de Janeiro and Salvador until October 3, the ANP said Tuesday. Data will cover 10 so-called marginal onshore areas in the Reconcavo, Espirito Santo, Tucano Sul, Parana and Barreirinhas sedimentary basins, according to the ANP.
The 10 areas previously produced oil, but were returned to the regulator because output had fallen to levels that were not economically feasible for larger companies.
The areas that generate interest from companies could be put up for bid at auctions focused on marginal accumulations or be included with other exploration blocks in a more traditional concession auction, the ANP said.
When the ANP restarted auctions of exploration and production concessions in 2013, the regulator had planned to sell rights to such marginal areas in an effort to increase participation of small and medium businesses in the country's oil industry. The auction, however, was never held.
Inclusion of any areas that generate interest from oil companies in a future auction will need approval from Brazil's National Energy Policy Council, or CNPE, the ANP said.
--Jeff Fick, newsdesk@platts.com --Edited by Derek Sands, derek.sands@platts.com
Lagos (Platts)--6Aug2014/710 am EDT/1110 GMT
The cost of refining domestic oil in Nigeria has increased by $7.52/barrel after the government's decision to transport crude to three state-run refineries by ship in a bid to bypass damaged pipelines, oil minister Diezani Alison-Madueke said.
"Due to theft-related vandalism, crude oil supply to our refineries remains constrained, thus affecting uptime and volume. In order to mitigate this anomaly, the option of crude transportation by marine vessel has been deployed thereby increasing the operating cost of refining by an additional sum of $7.52 per barrel," Alison-Madueke said in a speech to an industry conference seen by Platts Wednesday.
She did not give the current cost of refining crude at the refineries.
State oil company Nigerian National Petroleum Corp, which manages the refineries, announced last week that it had resorted to shipping crude oil to its three refineries -- the 125,000 b/d Warri refinery and two in Port Harcourt with a combined nameplate capacity of 210,000 b/d -- because of frequent hacking into pipelines that transport crude from Chevron, Shell and Eni operated fields. The refineries have been operating intermittently because of the resulting disruption to crude supply.
Alison-Madueke said that pipeline vandalism not only affected the refineries but also crude production and exports.
"In 2013, we sustained an average crude oil and condensate production of 2.3 million b/d and gas production of 7.6 Bcf/d despite crude oil theft and pipeline vandalism. Average crude oil theft and deferment during the same period were 215,000 b/d," the minister said.
--Staff, newsdesk@platts.com
--Edited by Jonathan Dart, jonathan.dart@platts.com
London (Platts)--6Aug2014/712 am EDT/1112 GMT
The physical Med/NWE gasoline spread -- the difference between the FOB Mediterranean gasoline cargo market and the Northwest European Eurobob gasoline barges -- has turned negative as fundamentals in the Mediterranean market turned bearish, traders said.
The spread was assessed at a minus $0.25/mt Tuesday, moving into negative territory from $3.50/mt Monday. The spread was last negative on July 14.
Market fundamentals have turned bearish in recent days on the back of more ample availability, reversing the tightness around prompt-loading barrels that had characterised recent weeks.
"The general sensation is that the Med is not tight anymore," a refiner in the region said.
Another Mediterranean gasoline market source said there were "many cargoes now without a home".
The swaps market reflected the bearishness in the physical, with the August Med/NWE spread swap assessed at minus $9/mt, down from minus $6/mt.
--Francesco Di Salvo, francesco.disalvo@platts.com
--Edited by Dan Lalor, daniel.lalor@platts.com
James Bambino, Platts Oil Futures & Options Editor
New York - August 06, 2014
U.S. gasoline supply fell sharply the week ended August 1 amid higher domestic demand, weak imports and likely steady exports, U.S. Energy Information Administration oil data showed Wednesday.
Total U.S. gasoline stocks fell 4.39 million barrels to 213.85 million barrels during the reporting week ended August 1, putting inventory nearly 1% below the EIA five-year average.
The decline far surpassed analysts' expectations of a 700,000-barrel draw.
The draw comes despite a surge in production -- which jumped 422,000 barrels per day (b/d) to 9.76 million b/d, the second-highest weekly production figure on record.
In June, weekly U.S. gasoline production reached a record-high 9.84 million b/d.
Implied demand* for gasoline jumped to 9.36 million b/d the week ended August 1, up from just over 9 million b/d the week ended July 25. This marks the first two-week stretch of plus-9 million b/d gasoline demand this summer. Demand was above 9 million b/d for the last four reporting weeks of May.
Stocks on the U.S. Atlantic Coast (USAC) -- home to the New York Harbor-delivered New York Mercantile Exchange (NYMEX) RBOB contract -- fell 1.59 million barrels to 58.42 million barrels. USAC stocks now sit just 1.93% above the five-year average. This is the tightest USAC gasoline supply has been since mid-May.
The USAC is a net importer of gasoline; however, imports the week ended August 1 fell to 412,000 b/d, which is 172,000 b/d below year-ago levels.
Coming into Wednesday, the market had considered U.S. gasoline well-supplied. Front-month RBOB futures settled at $2.7155 per gallon (/gal) Tuesday, the lowest settle for an RBOB contract since February 6. But a sharp draw reported in American Petroleum Institute (API) data late Tuesday rallied RBOB overnight and into Wednesday trading.
At 1515 GMT, September RBOB had climbed back to $2.7620/gal, up 4.65 cents.
But gasoline stocks also have tightened in the rest of the country. U.S. Midwest stocks fell 1.34 million barrels to 47.5 million barrels the week ended August 1, putting them nearly 5% below the five-year average.
U.S. Gulf Coast (USGC) stocks fell 657,000 barrels to 74.81 million barrels, which is 0.32% above the five-year average.
While the USGC is a large supplier to both the U.S. Midwest and USAC, it is also the source of much of the U.S. export market. EIA data estimates U.S. gasoline exports held steady at 487,000 b/d the week ended August 1 -- in line with the more accurate figure for May, according to the latest EIA monthly data.
U.S. West Coast gasoline stocks fell 834,000 barrels to 27.17 million barrels the week ended August 1, putting regional supply more than 4.5% below the five-year average.
U.S. CRUDE OIL STOCKS DOWN
U.S. commercial crude oil stocks, meanwhile, fell 1.76 million barrels to 365.62 million barrels the week ended August 1 as U.S. crude oil runs were steady above 16 million b/d for the sixth straight reporting week.
Despite U.S. crude oil runs at 16.39 million b/d, U.S. refinery utilization -- which includes alternative feedstocks -- fell 1.1 percentage points to 92.4% of capacity.
Analysts had been expecting a 0.8 percentage-point decline.
The draw in crude oil stocks was also aided by lower imports, which fell 181,000 b/d to 7.56 million b/d. The bulk of this came on the USGC, where imports dropped 372,000 b/d to 3.44 million b/d. This helped to knock USGC stocks down 2.65 million barrels to 194.74 million barrels, as robust runs in the region largely held steady at just under 8.6 million b/d.
Imports from Saudi Arabia rebounded 337,000 b/d to 1.23 million b/d, but imports from Mexico nearly halved, falling 410,000 b/d to 582,000 b/d -- a 14-week low.
U.S. Midwest crude oil stocks rebounded the week ended August 1, up 1.39 million barrels to 85.27 million barrels, as imports of Canadian crude oil rose 252,000 b/d to 2.78 million b/d the week ended August 1.
Also likely aiding the build was a 137,000 b/d decline in crude oil runs, which fell to 3.57 million b/d.
Crude oil stocks in Cushing, Oklahoma -- delivery point for the NYMEX crude oil futures contract -- steadied, up 83,000 barrels to 17.98 million barrels.
DISTILLATES DRAW
U.S. distillate stocks fell 1.8 million barrels to 124.92 million barrels, counter to analysts' expectations of a 1.1 million-barrel build.
Implied demand for distillates rose 201,000 b/d to 4.03 million b/d as production fell 182,000 b/d to 4.83 million b/d.
Combined low- and ultra-low-sulfur diesel stocks on the USGC fell 2.18 million barrels to 32.96 million barrels the week ended August 1, putting them more than 13% below the five-year average.
However, tightness on the USGC -- where the bulk of U.S. supply comes from -- often is reflective of strong U.S. diesel exports. EIA weekly data estimates U.S. distillate exports held steady around 1.2 million b/d the week ended August 1.
The more accurate and most recent monthly data shows U.S. distillate exports were 1.17 million b/d in May.
* Implied demand is the amount of product that moves through the U.S. distribution system, not actual end consumption.
Putin Befriends Iran with Oil Deal to Take on the West
By Kalyan Kumar | August 7, 2014 10:51 AM EST
Russian President Vladimir Putin has roped in sanctions-hit Iran as a friend in need with a huge oil deal to side step the pressure of Western sanctions. The Telegraph reported that Russia signed a 5 year oil deal with Iran.
REUTERS
Russia's President Vladimir Putin chairs a meeting at the Novo-Ogaryovo state residence outside Moscow July 17, 2014.
The deal will give Putin the relief of $20 billion to beat the stress of Western sanctions on the energy sector. Iran was also looking for a supporter as it is facing sanctions for the controversial nuclear programme. Iran set an ambitious target of 5.7m barrels per day of crude by 2018.
Russia also denied allegations that the deal violated international obligations. Alexander Novak, Russia's energy minister said the agreement with Iran does not violate any international obligations.
Under the accord, Russia would help Iran to organise oil sales and expand cooperation in the oil-gas industry, power plants, grids, machinery, consumer goods and agriculture products. This was stated in the statement issued by the Energy Ministry in Moscow.
EU Sanctions
The US and EU are jointly targeting Russia for its support to Ukraine rebels. The issue reached a flashpoint in July with the downing of the Malaysia Airlines Flight MH17 killing all 298 people on board.
The White House spokeswoman Caitlin Hayden had taken exception to the reports of the talks between Russia and Iran for an oil deal and warned that such a deal would be inconsistent with the terms set for Iran.
Deal implications
The deal will see Russia buying 500,000 barrels of Iranian oil a day, reported the Kommersant newspaper in Moscow. This will constitute about one fifth of Iran's monthly output and half of its exports. Richard Mallinson, analyst in the energy sector, expressed skepticism that the functioning of the deal can be strained considering the current production capacity of Iran and problems like geography, shipping logistics and ongoing US sanctions.
RT. Com reports that Russia-Iran trade is around $5 billion a year. Iran's oil reserves are one of the largest in the world after Venezuela, Saudi Arabia, and Canada. The country is also home to 18 per cent of the total natural gas reserves in the world.
To contact the editor, e-mail: editor@ibtimes.com
A rig contracted by Apache Corp drills a horizontal well in a search for oil and natural gas in the Wolfcamp shale located in the Permian Basin in West Texas in this file photo from October 29, 2013. (Stringer/Reuters)
By Editorial Board August 6 at 8:30 PM
THE UNITED States is a rising oil exporter. That sentence is amazing when you consider that federal law technically bans crude oil exports.
Last week, the BW Zambesi oil tanker left Texas City, Tex., with $40 million worth of minimally processed condensate, a form of oil, and headed to South Korea. This was the first shipment following a Commerce Department determination that decades-old federal restrictions on crude oil exports do not apply to condensate from which drillers have removed various natural compounds. That stuff, regulators said, falls under an exception to the export ban that allows the shipping of oil that has been processed. This policy change may clear the way for more U.S. crude exports. While polls show Americans are worried about that prospect, it actually is an unambiguous win for the country. If anything, the rules should get less restrictive.
The case against U.S. oil exports seems simple and obvious: Why allow them when the country still imports some crude? The answer is slightly more complicated. The U.S. has become an energy powerhouse, with crude oil production leaping some 48 percent in the last few years. New technology is tapping oil-bearing shale formations in states such as North Dakota and Texas. Most of this product is light oil, which does not require heavy refining. Some of the most advanced refineries in the world are along the Gulf Coast , but that’s actually a problem: Their owners invested in expensive facilities suited to refining heavier crude, so there is a mismatch between the refining infrastructure and the type of crude flowing from U.S. wells. In the deeply interconnected global oil market, in which borders matter less than many people think, the obvious solution is to allow oil companies to ship the light crude to refineries suited for processing it, supporting U.S. profits and U.S. jobs in the process, and to tolerate imports of crude oil that U.S. refineries can handle.
But what about energy security? The Council on Foreign Relations’s Blake Clayton points out that expanded exports would encourage the development of oil fields and transport infrastructure, which would help the country weather some disruption in the global oil trade. Then there is the question of what lifting the ban would mean for domestic gasoline prices. This embarrassing debate discredits the Obama administration as it lectures other nations about irrational government barriers and supports in the fossil fuels business, which skew consumption habits and reduce the resilience of the world oil market on which everyone depends.
The export ban was a desperate ploy in the 1970s to control commodities markets amid spikes in oil prices induced by the Organization of the Petroleum Exporting Countries. Keeping it in place now is an economically incoherent policy, particularly when removing it would encourage an industry that is transforming the fortunes of large swaths of the nation. Congress should lift the ban entirely. Until then, Commerce should allow as much oil as it can to flow through the ban’s exceptions.
By Catherine Ngai
NEW YORK, Aug 6 (Reuters) - Exports of crude oil from U.S.shores jumped in June to the highest since the 1950s, accordingto U.S. data, topping OPEC member Ecuador in supplying globalmarkets and underscoring the dramatic shift in global flows.
Exports jumped 35 percent from May to 389,000 barrels perday in June, almost all of that sent to Canada, according todata from the U.S. Census Bureau released on Wednesday. That'smore than Ecuador, the smallest producer in the Organization ofthe Petroleum Exporting Countries with overseas sales of some354,000 bpd in 2012, according to government data.
The June surge of more than 100,000 bpd is the biggestmonthly rise since the onset of the U.S. shale oil revolution,which has unlocked billions of barrels of reserves and fueled aproduction boom that has the potential to exceed domesticdemand.
The rise shows that U.S. crude from places such as NorthDakota and Texas is finding more buyers in Canada, particularlyon the Atlantic Coast where refiners are still dependent oncostlier Brent-linked crude from the North Sea or West Africa.
Although a decades-old U.S. law generally bars exports ofdomestically produced crude, shipments to Canada are broadlyallowed, as are re-exports of foreign oil.
But a growing excess of particularly light crude isprompting companies to find ways around the ban, including bylightly processing a super-light form of oil known as condensatein order to get around restrictions on raw crude. The first suchcargo sailed from Texas bound for east Asia in late July
The rise in exports may level out soon due to congestion onU.S. railway lines that now handle a tenth of U.S. oilproduction, according to Dr. Philip K. Verleger, Jr., presidentof consultancy PKVerleger LLC. Some of North Dakota's Bakken oilis sent by rail thousands of miles to the Canadian east coast.
"Export figures will probably slow down in the fall becausethe railroads are going to run into a capacity problem," hesaid. "When the fall comes, agriculture (shipments) will getpriority and the pressure is on for the railroads to move ag andsidetrack oil. Suddenly, exports will plateau."
SINGAPORE AND SWITZERLAND TOO
The Customs data showed 6,000 bpd went to Singapore and5,000 bpd to Switzerland. These cargoes were likely re-exports,probably of Canadian oil, market sources say. Small-scaleexports to Switzerland first emerged in April. The shipments toSingapore, classified as under 25 degrees API, also known asheavy crude, appeared to be the first on record.
June is the first month that exports have leapfrogged abovetheir previous recent peak in the 1970s. They hit their highestsince April 1957, in the aftermath of the Suez Crisis when thenationalization of the canal caused the United States toincrease crude shipments to Europe.
Despite the June increase, the United States remains a largenet importer of crude, buying some 7.5 million bpd over the pastweek. Many refiners are geared to run heavier, sour crudes fromabroad, while others lack easy access to shale oil.
Exports under the exemptions need to be approved by theCommerce Department's Bureau of Industry and Security.
The Census data is published weeks earlier than closelywatched Energy Information Administration (EIA) trade figures,which are based in large part on the Census. Since 2012, themonthly Customs figures are identical to the EIA's data with theexception of four months, according to a Reuters analysis. TheEIA could not immediately comment on the discrepancies.
Export data from the Census Bureau is gatheredelectronically where exporters are required to fill outdeclaration forms when cargo worth more than $2,500 in valueleaves U.S. shores, a spokeswoman said. It combines bothdomestically-produced and re-exported crude oil.
The EIA's export data also includes re-exported oil.However, it was not immediately clear how the EIA defines crudeoil in its monthly export data, which could be a reason for theslight variation.
barrels per day June 2014* May 2014**
Canada 378,000 263,000
Singapore 6,000 0
Switzerland 5,000 8,000
Spain 0 17,000
TOTAL 389,000 288,000
* Indicates Census Bureau data
** Indicates U.S. Energy Information Administration
(Reporting By Catherine Ngai; Editing by David Gregorio)
MEXICO CITY Wed Aug 6, 2014 11:37pm BST
Aug 6 (Reuters) - Mexican President Enrique Peña Nieto said on Wednesday he would likely sign a series of bills next week to implement the historic opening of the state-run oil, gas and electricity sectors to more private investment.
Mexican Senators are voting this week on laws aimed at attracting companies such as Royal Dutch Shell Plc and Exxon Mobil Corp, and help stem declining crude production in Latin America's No. 2 economy.
When asked by reporters if the laws would be published next week, Peña Nieto said: "It is very likely to happen that way."
A constitutional overhaul approved last year ended the 75-year monopoly of state-owned oil company Pemex, which has struggled with falling output for a decade. Lawmakers took months longer than expected to pass the bills needed to flesh out the reform.
The government had hoped to have the first auctions of oil and gas fields later this year, but it is now likely to take until the third quarter of next year.
Pemex could move quickly in the coming weeks to announce joint ventures with international oil majors as soon as the Energy Ministry determines which fields the company will keep and which will be open to private companies.
The energy ministry has until mid-September to makes it decision on the so-called Round Zero allocation for Pemex, but it could happen sooner.
Peña Nieto has sought the reforms to help boost Mexico's economy, which has lagged more dynamic emerging markets. The economy grew 1.l percent during his first year in office and Mexico is expected to post a 2.6 percent rate this year. (Reporting by Noe Torres. Editing by Andre Grenon)
By Dave Forest | Wed, 06 August 2014 19:02 | 0
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Very interesting research released last week by the U.S. Energy Information Administration. Showing that the domestic E&P sector may be headed for some difficult times.
The Administration calculated the spending habits of oil and gas firms operating within the U.S. Tallying both incoming operational cash flow and outgoing capital expenditures for these companies.
The results are surprising. Revealing that today’s oil and gas sector is spending well beyond its means.
Just look at the chart below. Showing that 2013 operational cash flow for the industry ran approximately $575 billion—while spending ("uses of cash") averaged just under $700 billion. Meaning that firms spent over $100 billion more than they made from operations.
Of course, these metrics don’t tell the complete story when it comes to company financials.
E&P firms could, for example, make up the spending shortfall by selling assets and using the profits to shore up their bank accounts.
But the EIA research reveals that’s not the way many companies have been doing things. With numerous firms instead making up the difference in spending through increased bank borrowing.
That means debt loads are growing across the industry. Which sets up some interesting dynamics for the sector going forward.
A lot is now riding on the future performance of U.S. fields. With today’s E&P spenders basically betting that increased capital outlays will pay for themselves through rising production and profits down the road.
But the EIA numbers make this proposition look somewhat dubious. As the chart clearly shows, operational cash flows have been largely flat-lined for the last two years. With increased spending no longer giving the financials a lift.
That’s a very worrisome trend. Which could see today’s big spenders left with high and perhaps even unserviceable debt loads as oil and gas fields “run on the treadmill”.
This may be where the quality managers in the shale patch start to separate themselves from the pack.
Here’s to living within your means,
Dave Forest
Aug 6 (Reuters) - Tallgrass Energy Partners LP expects the Pony Express crude pipeline to start up next month with linefill and final testing under way, Chief Executive David Dehaemers told analysts on Wednesday.
The 690-mile, 230,000 barrels-per-day (bpd) to 320,000 bpd pipeline runs from Guernsey, Wyoming, to the U.S. crude futures hub in Cushing, Oklahoma. Dehaemers said another pipeline that will feed 38,000 bpd into Pony Express has been delayed, but executives expect other producers to bring in uncontracted volumes.
Dehaemers did not identify the delayed pipeline.
(Reporting By Kristen Hays; Editing by Chris Reese)
A boom in domestic oil and gas production is keeping the US trade deficit down. Some politicians and analysts think increased production means it's time the US allow for crude oil exports, while others say exporting oil would harm American energy security.
By Jared Gilmour, Staff writer August 6, 2014
The U.S. trade deficit narrowed more than expected in June as petroleum imports dropped to a 3-1/2-year low, suggesting that trade was less of a drag on...
Washington — An oil and gas boom helped drive the US trade deficit to a five-month low in June, according to federal data released Wednesday.
Increased domestic energy production means Americans are buying less foreign oil and gas, and selling more of it overseas. That has tamped down the trade deficit in recent years, helping along an economy that continues to recover from the Great Recession.
Some say the deficit could be slashed further if the US were to ease energy export restrictions put in place to protect US consumers from global energy shocks. But such a move would have impacts that go beyond country’s balance of trade. Critics of oil and gas exports say they will raise energy prices at home, and increase the environmental impacts of extracting and burning fossil fuels.
Either way, a renaissance in oil and gas production is already changing the way officials, analysts, and economists look at the future of the US economy.
“Everybody targeted the US to be importing 10 billion cubic feet [of natural gas] per day by now,” says Pete Stark, an energy analyst at IHS, in a telephone interview Wednesday. “Instead, we’re targeted to have the capability to export 10 billion cubic feet of gas per day by the end of this decade. That’s a huge reversal.”
Oil and gas product exports accounted for $12.7 billion of US exports in June, according to the Commerce Department. That’s a $1.2 billion leap from June of 2013. The rise in exports helped lower the overall US trade deficit to $41.5 billion in June, from May’s $44.7 billion.
Innovations in hydraulic fracturing and horizontal drilling have spurred a domestic energy revival in the US, unlocking significant stores of oil and gas. The boom has unexpectedly positioned the US as a top producer alongside Russia and Saudi Arabia.
For the oil and gas industry, Wednesday’s Commerce report signals that it’s time for the US to loosen restrictions on oil exports. Relaxing the US’s 70s-era restrictions would help the US economically and would increase energy security, according to the American Petroleum Institute, a Washington-based oil and gas industry group.
“America’s potential as an energy superpower remains limited by outdated trade restrictions that prevent more U.S. oil and natural gas from reaching global markets,” said API chief economist John Felmy in a statement Tuesday.
The US is converting some import terminals to export terminals to ship natural gas abroad, and there are signs the US is mulling policy changes that would loosen the crude oil exports ban.
The US could conceivably export half a million to a million barrels of oil per day if crude exports were allowed, according to Stark. If the export ban isn’t lifted, the US could see bottleneck since US refiners aren’t fit to process the light crude the US is producing, Stark says. US refiners are better equipped to handle heavy Canadian crude.
“No one predicted such a surge of the light crude. It’s out of sync with the way the current refinery basis is set up,” Stark adds.
Despite the US limits on crude exports, increased domestic production means its imports have dropped substantially. Between 2012 and 2013, US crude imports fell 10.2 percent, according to the US Energy Information Administration.
But a change in the crude export policy may be on the horizon. In June, Commerce ruled that two companies could export condensates. Some interpreted Commerce’s action as an incremental step towards an even more lenient export policy.
Last week, a tanker of US condensates – an ultralight, unrefined form of oil – set sail from Texas to South Korea.
“Condensate exports are an easy first step on the road towards a wider lifting of the oil export ban,” Sen. Lisa Murkowski (R) of Alaska said in a statement e-mailed to the Monitor in July. “Simply put, we are producing more condensate than we know what to do with, but customers overseas would be happy to take it off our hands."
But Doug Norlen, chief economist at Friends of the Earth, an international environmental group, points out that natural gas and oil both have significant greenhouse impacts – impacts that could worsen if the US keeps pursuing carbon-intensive energy.
Mr. Norlen says in a telephone interview Wednesday that lifting the export ban would "worsen climate change and continue us down an economically unsustainable path."
It might also undermine the very reasons for imposing the ban in the first place.
The Commerce Department’s reported ruling on condensates “puts America on a slippery slope to send more of our oil abroad, even at a time when the Middle East is in disarray and tensions are running high with Russia,” Sen. Ed Markey (D) of Massachusetts said in a statement in June. “We should keep our resources here at home for American families and businesses, not send this oil abroad even as we import oil from dangerous regions of the world.”
By OGJ editors
Nigerian National Petroleum Corp. (NNPC), through a service provider, has let a contract to General Electric Co. to provide gas turbines to be used to generate a reliable, uninterrupted supply of power to NNPC’s refining complex in Port Harcourt, Nigeria, that would enable the complex to return to its full production capacity.
GE will deliver three, 25-Mw, trailer-mounted TM2500+ aeroderivative gas turbines to GEL Utility Ltd., a subsidiary of independent power producer Genesis Electricity Ltd., with whom NNPC signed a 20-year power purchase agreement in November 2013 for the Port Harcourt refinery, GE said in an Aug. 4 news release.
In addition to delivery of the gas turbines, whichwill provide both the baseload and backup power to support refining operations at Port Harcourt, the recent agreement also includes the future modernization of Nigeria’s other two existing refineries, GE said.
The installation of the mobile gas turbines at the Port Harcourt refinery, Nigeria’s largest, is intended to guarantee the plant has the power it needs to overcome chronic grid outages in the region that have presently reduced production at the Port Harcourt complex to 30% of its total maximum nameplate capacity of 210,000 b/d, according to GE.
The three gas turbine units are scheduled to enter commercial operation in August, at which time the Port Harcourt refinery will have the necessary power to return to its full operational capacity, GE said.
In addition to the Port Harcourt complex—which is comprised of two refineries that, together, have a combined installed capacity of 210,000 b/d—NNPC also owns two additional Nigerian refineries, including its 110,000-b/d refinery in Kaduna and a 125,000-b/d refinery in Warri.
All three refineries recently have operated below their installed nameplate capacities, according to the latest data available from NNPC.
During the month of March, crude oil throughputs at the Kaduna refinery averaged about 38,700 b/d, while the Warri refinery processed about 28,000 b/d of crude.
No crude throughputs were reported at the Port Harcourt refinery during March, according to NNPC’s latest data.
There's been another Middle Eastern crisis brewing amidst the worst violence of Syria's civil war, ISIS's attempted genocide against Iraq's Yazidi community, and the month-long war in Gaza.
Libya has disintegrated rapidly in recent weeks, with the destruction of Tripoli's airport, a raging fuel tanker fire in the capital, and some the worst fighting since the country's rebels overthrew dictator Muammar Gaddafi in 2011.
Libya's chaos creates as gaping safe-haven for militant groups on the southern coast of the Mediterranean. And an analyst's report from Morgan Stanley suggests that the country's major industry is in an indefinite state of decline as well.
Libya's oil production has cratered in recent years. And this past month of violence is threatening the country's energy infrastructure, triggering a projected dip in already-low production levels and throwing the future of Libya's oil industry into doubt.
The report notes that Libya's oil economy was remarkably resilient in the year after Gaddafi's ouster. In 2012, Libya still accounted for 10% of oil imports to Europe's Organization for Economic Cooperation and Development member countries.
This was a slight decrease from pre-conflict years, when European governments began to re-establish commercial ties with a Gaddafi government that was supposedly moving towards greater openness and reform. But it's far greater than Libya's numbers now: OECD Europe "imported just 3% of its total import needs from Libya from Jan-April 2014." And this was long before the increased violence of the past month.
According to Morgan Stanley, Libyan production will likely average 500,000 barrels of oil per day in 2014 — a decline of over 400,000 barrels in daily production compared to the year before. While the country's oil infrastructure is still relatively intact, the report cites potential threats to Libya's seven oil export terminals, and security risks for oil fields deep in Libya's ungoverned desert frontier.
The violence in Libya is unlikely to have an impact on global oil prices, and the report stresses that increased exports from places like Saudi Arabia should easily cushion the blow of disrupted production in Libya.
At the same time, a slowdown in oil exports in 2013 led to a 10% drop in the country's GDP in 2013, according to the World Bank. Instability is sure to ward off any future investment in the oil sector, while the three multinationals most deeply invested in the Libyan oil sector all stand to lose in production levels and earnings per share as a partial result of the crisis, according to Morgan Stanley.
In sum, Libya's primary means of economic viability is slipping away at a time when the country is already chaotic. In a country that's spiraling into state collapse and militarism, things looks primed to get even worse.
By OGJ editors
Ending the US ban on exports of crude oil would hurt refiners now profiting from low feedstock costs but help producers and consumers, says an analyst at the Federal Reserve Bank of Dallas.
In a July report, Michael D. Plante, senior research economist in the bank’s Research Department, describes how transport constraints have created localized oversupply, lowering regional crude prices in relation to global prices of similar crudes.
With the transportation system adjusting to new production from unconventional resources in the US interior, oversupply is developing rapidly on the US Gulf Coast.
“If the export ban were not in place, this would not be a problem,” Plante writes. “The extra oil would be shipped to other countries with the appropriate refining capacity for light crude. Crude oil prices in the US then would reflect global prices.”
Complicating the problem is a quality mismatch. Many refineries on the Gulf Coast, location of more than of US refining capacity, are designed to process heavy crude. Most of the new US production is light.
“Refiners [on the Gulf Coast] lack the ability to process all the newly discovered oil, raising the specter of an oversupply that could persistently depress US oil prices,” Plante writes, noting that oil on the Gulf Coast has begun selling at small discounts to comparable grades traded globally.
While the discounts boost profit margins for refiners with access to the depressed crude, they don’t help consumers. US prices of oil products, Plante explains, “are determined in the global market, whereas crude oil prices reflect distorted local market conditions in the US.”
If the ban on crude exports ceased, gross margins would shrink for refiners running relatively low-cost crude.
But crude prices now depressed in the US would realign with competitive global grades and stimulate drilling, which would raise oil supplies overall.
“Over the longer term, US crude oil producers would receive higher prices,” Plante writes. “In response, they would produce more oil than they would have if the ban were in place.
“With greater amounts of oil available globally, more gasoline and diesel would be produced, reducing their prices and benefiting consumers.”
Royal Dutch Shell PLC reported the start of oil production from the first well at its Bonga North West deepwater development, drilled in 1,000 m of water offshore Nigeria. Operated by Shell subsidiary Shell Nigeria Exploration & Production Co. Ltd. (SNEPCo), the development is expected at peak production to contribute 40,000 boe/d to the Bonga development.
The $3.6 billion Bonga development project, which began producing oil and gas in late 2005, was Nigeria’s first deepwater development in water deeper than 1,000 m (OGJ Online, Dec. 1, 2005). The 60-sq-km Bonga field lies on OPL 212.
Oil from Bonga North West is transported by a subsea pipeline to an existing Bonga floating production, storage, and offloading vessel that has been upgraded to handle the additional flow. Shell expects four oil-producing wells and two water-injection wells to be connected to the FPSO, from which oil will be loaded on tankers.
SNEPCo holds a 55% stake in the Bonga project. Partners include Esso Exploration & Production Nigeria (Deepwater) Ltd., Total E&P Nigeria Ltd., and Nigerian Agip Exploration Ltd. under a production-sharing contract with the Nigerian National Petroleum Corp.
Natural gas production from the Marcellus shale has surpassed 15 bcfd through July and now represents 40% of US shale gas production, making it the largest producing shale gas basin in the country, according to the US Energy Information Administration’s Drilling Productivity Report.
While the region’s rig count has leveled off at around 100 rigs over the past 10 months, improvements in drilling productivity have enabled operators to more efficiently support new wells.
EIA expects wells coming online in August to add more than 600 MMcfd to existing production, more than offsetting a drop in production due to existing well decline rates, thus increasing the production rate by 247 MMcfd.
Marcellus production in recent years has shot up to record levels after accounting for just 2 bcfd in 2010, resulting in record gas storage injections, multiple pipeline expansion projects to remedy bottlenecks, and stabilized or decreased prices (OGJ Online, Apr. 25, 2014).
EIA points out that gas prices in the US Northeast, such as the Dominion South trading point in southwestern Pennsylvania, have increasingly been below the Henry Hub price, in part because of more access to Marcellus gas.
According to a report released by Moody’s in April, however, Marcellus producers are expected to benefit more than producers elsewhere in the US, even if prices were to decline to 2012 levels, because of rapid technological advancements, large producing wells in the northeast section conveniently located near major markets, and increased capital poured into the NGL-rich southwestern section (OGJ Online, Apr. 1, 2014).
Production in the region is now on pace to be enough to meet the combined winter demand of Pennsylvania, West Virginia, New York, New Jersey, Delaware, Maryland, and Virginia, EIA says.
* Iran and world powers agreed to extend nuclear talks
* China and India still top buyers of Iran's oil
By Jonathan Saul and Alex Lawler
LONDON, Aug 6 (Reuters) - Iran's oil exports slipped for a second month in July, yet sales remained above the limit set by the West under an interim deal aimed at curbing Iran's nuclear programme, according to sources who track tanker shipments.
Iran and six world powers, known as the P5+1, agreed to extend nuclear talks by four months after they failed to reach a July 20 deadline for a permanent resolution. Under the interim agreement, Iran's crude exports were supposed to be held just above 1 million barrels per day (bpd).
Shipments higher than that have not drawn serious criticism from Washington, partly because U.S. officials say the increased volumes are made up of condensate, a light oil which they say is allowed under the sanctions, as well as Iranian gifts of oil to Syria which they do not view as "sales".
One source who tracks tanker movements said Iran's crude oil exports reached 1.14 million bpd in July, slightly lower than 1.18 million bpd in June.
"Japan took less crude. At the same time, China and India took more oil in July to make up for lower amounts in the previous month," the source said.
July's shipments also included a cargo that appeared to have gone into Egypt's Sumed pipeline, the source said.
A second source said exports slipped by 100,000 bpd in July month-on-month.
"We're seeing Iranian exports down from June. It would not surprise me if some of the buyers are looking to move back into line with U.S. sanctions requirements," the second source said.
A third source said: "July is down a bit on exports."
Iran's biggest clients, including China and India, took more oil in the first six months of 2014 than in the same period of last year, and may keep rising.
Iranian officials have reiterated that they seek to ramp up exports. Nevertheless, continued restrictions on shipping and insurance have meant that a return to Tehran's pre-sanction rate of over 2 million bpd is still some way off.
"What we are seeing in Iranian exports today is Iran trying to show the P5+1 that it can sell more crude to Asia in an effort to recapture market share in spite of efforts of U.S. regulators to force Asian consumers to cut Iranian crude purchases," said Amir Handjani, a director at United Arab Emirates-based oil exploration and production firm RAK Petroleum PCL.
"Exports from Iran have steadily risen. However, the problem of Iran being able to access the proceeds of its sale of crude unfettered from existing U.S. and EU sanctions remains in place." (Editing by William Hardy)
TEHRAN (FNA)- The massive offshore South Pars gas field's production is expected to increase by 200 million cubic meters per day (mcm/d) by March 2016, a deputy oil minister said.
“Petroleum Ministry is making efforts to boost gas production from South Pars by 200 mcm/d by the end of Iranian calendar year of 1394 (March 20, 2016),” Emad Hosseini said, the oil ministry's website reported.
South Pars covers an area of 9,700 square kilometers, 3,700 square kilometers of which are in Iran’s territorial waters in the Persian Gulf. The remaining 6,000 square kilometers are situated in Qatar’s territorial waters.
The gas field is estimated to contain a significant amount of natural gas, accounting for about eight percent of the world’s reserves, and approximately 18 billion barrels of condensate.
