Canadian oil-sands producers who are restoring production after wildfires are finding U.S. refiners are doing just fine without as much crude from their northern neighbor.

The U.S. imported 2.6 million barrels a day from Canada last week, the smallest amount since May 13, preliminary data from the Energy Information Administration show. The decline came after producers including Suncor Energy Inc. and Syncrude Canada Ltd. brought back more than a million barrels a day that was shut in May amid the worst wildfire in Alberta’s history.

U.S. refiners made commitments to import crude by sea from alternative suppliers when the northern Alberta wildfire was out of control, and the duration of disruption to supplies was unclear, John Auers, executive vice president at Turner Mason & Co. in Dallas, said by phone Thursday. Those imports are arriving now, he said.

“As the supply comes back on, that will displace some of the imports brought in to replace that lost supply,” he said.

Imports from Mexico, which compete with Canada’s heavy crude, rose to 803,000 barrels a day last week, the highest since April 15, EIA data show. Shipments from Saudi Arabia also increased.

A wildfire that broke out at the beginning of May prompted the shutdown of as much as 1.4 million barrels a day of oil-sands production, about 40 percent of Canada’s supply. Since then, restarts have restored most of the lost output. Rising output combined with reduced U.S. demand has weakened Canadian heavy-crude prices, with Western Canadian Select trading at its biggest discount to U.S. futures since April.

Western Canadian Select’s discount to West Texas Intermediate futures grew 10 cents to $14.25 a barrel Thursday, the biggest discount since April 18, data compiled by Bloomberg show. Light synthetic crude, produced from oil sands upgraders, has also weakened, trading at a 30 cent a barrel discount to WTI, the biggest discount since April 22.

http://www.bloomberg.com/news/articles/2016-07-08/oil-sands-crude-returns-to-u-s-market-when-it-s-less-needed

A Nigerian trade union representing oil workers said it had begun a strike on Thursday, but added that the effect of its industrial action would not be felt for some time because it started on a public holiday.

The Petroleum and Natural Gas Senior Staff Association of Nigeria said 10,000 of its members, who include refinery workers and office staff, had begun a "gradual withdrawal" from "offices, sites and production facilities".

In a statement, the union said it was responding to issues that were "critical to the survival of the oil and gas industry in the country" including joint venture funding and cash call arrears, which it said had stalled the creation of new jobs.

Cash calls are the government's financial obligations to joint venture projects between state oil firm NNPC and international and local oil companies.

Nigeria, the north of which is predominantly Muslim with mostly Christian southerners, has been observing the Eid al-Fitr holiday. Thursday was the last day of the three day holiday.

"The strike has started but you know today is a public holiday that is why you may not readily see the immediate impact but I can assure you that the strike has commenced," said Lumumba Okugbawa, the union's acting general secretary.

Okugbawa said the union had been in touch with the government to hold talks. He said the government had proposed discussions take place on Friday but the PENGASSAN would prefer to meet on Monday instead.

"Shutting down the refineries, oil production and export would be the last option if all negotiations with government break down," he said, adding: "There are so many steps to that."

Crude production in Nigeria, an OPEC member, has been pushed to 30-year lows as a result of attacks on oil and gas facilities in the southern Niger Delta.

The militants behind the attacks have called for a greater share of Nigeria's oil wealth to go to the impoverished region, which is the source of most of the country's oil.

http://www.reuters.com/article/nigeria-oil-idUSL8N19T4VP

The U.S. Department of Interior on Thursday unveiled its final regulations on drilling in the U.S. Arctic Outer Continental Shelf to boost safety in the environmentally sensitive region.

The rules set safety standards for exploratory drilling on the U.S. Arctic Outer Continental Shelf for vessels on Alaska's Beaufort and Chukchi Seas.

"The rules help ensure that any exploratory drilling operations in this highly challenging environment will be conducted in a safe and environmentally responsible manner, while protecting the marine, coastal and human environments, and Alaska Natives’ cultural traditions and access to subsistence resources,” said Janice Schneider, the Interior Department's assistant secretary for land and minerals management.

The rules are a key part of the Obama administration's strategy for energy development in the Arctic region, Schneider said.

Oil and gas exploration in the U.S. Arctic has been limited. Last year, Royal Dutch Shell pulled the plug on its Arctic oil exploration plans after failing to find enough crude oil, despite getting permission from the United States to drill.

The company had spent $7 billion exploring in the waters off Alaska's coast. In 2012, Shell interrupted Arctic exploration after an enormous drilling rig broke free and ran aground.

The new rules require oil operators to submit a detailed operations plan before filing an exploration request. The operators must also demonstrate that they can quickly deploy containment equipment, such as capping stacks or domes, as well as a relief rig in the event of a well accident.

The Interior Department's environmental enforcement director, Brian Salerno, said the rules were developed to address issues identified after Shell's 2012 rig accident.

“This rulemaking seeks to ensure that operators prepare for and conduct these operations in a manner that drives down risks and protects both offshore personnel and the pristine Arctic environment,” Salerno said.

Kristen Miller, conservation director of the Alaska Wilderness League, said the Interior Department released "minimum regulations" - a first step that needs to be further strengthened.

National environmental groups went further and said the Interior Department should not allow any drilling in the Arctic.

Rachel Richardson of Environment America said: "The only 'safe' form of drilling for the Arctic and the climate is none at all."

But industry groups like the American Petroleum Institute quickly reacted to the announcement by saying the regulation is the latest attempt by the Obama administration to stifle offshore energy development.

http://www.reuters.com/article/us-usa-energy-arctic-idUSKCN0ZN27J

Brazil's state-led oil firm Petrobras may never collect some debts owed it by state-run power utility Eletrobras, the energy ministry said on Thursday, acknowledging the government has little cash to provide new capital to the debt-ridden electricity company.

The government will probably be unable to provide Centrais Eletricas Brasileiras SA, as Eletrobras is formally known, with the estimated 8 billion reais ($2.38 million) it wants to cut debt and revive investment, said Fabio Lopes Alves, electricity secretary at the Energy Ministry. The company's financial woes may force it to let licenses for some money-losing power-distribution units lapse,

http://www.reuters.com/article/petrobras-eletrobras-debts-idUSE5N16T00Y

U.S. crude oil refinery inputs averaged 16.7 million barrels per day during the week ending July 1, 2016, 8,000 barrels per day less than the previous week’s average. Refineries operated at 92.5% of their operable capacity last week. Gasoline production increased last week, averaging over 10.0 million barrels per day. Distillate fuel production decreased last week, averaging about 5.0 million barrels per day. U.S.

crude oil imports averaged about 8.4 million barrels per day last week, up by 808,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 8.0 million barrels per day, 11.6% above the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 765,000 barrels per day. Distillate fuel imports averaged 61,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 2.2 million barrels from the previous week. At 524.4 million barrels, U.S. crude oil inventories are at historically high levels for this time of year. Total motor gasoline inventories decreased by 0.1 million barrels last week, but are well above the upper limit of the average range. Finished gasoline inventories decreased while blending components inventories increased last week. Distillate fuel inventories decreased by 1.6 million barrels last week but are well above the upper limit of the average range for this time of year. Propane/propylene inventories rose 2.7 million barrels last week and are near the upper limit of the average range. Total commercial petroleum inventories increased by 3.4 million barrels last week.

Total products supplied over the last four-week period averaged over 20.5 million barrels per day, up by 3.0% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.8 million barrels per day, up by 2.5% from the same period last year. Distillate fuel product supplied averaged over 3.9 million barrels per day over the last four weeks, up by 1.5% from the same period last year. Jet fuel product supplied is up 11.7% compared to the same four-week period last year.

Cushing down 100,000

http://ir.eia.gov/wpsr/wpsrsummary.pdf

                                              Last Week      Week Before        Last Year

Domestic Production '000........ 8,428                 8,622                 9,604

Alaska '000                        ...........340                   496                    434

http://ir.eia.gov/wpsr/overview.pdf

Russia’s Novatek said Thursday it has supplied its first ever cargo of liquefied natural gas, marking the company’s first step into global LNG trading business.

The cargo was sourced from Trinidad & Tobago’s LNG plant in Point Fortin and delivered to the Quintero import terminal in Chile.

The shipment was made by Novatek Gas & Power, a trading subsidiary of Novatek involved in sales of gas and liquid hydrocarbons on the international markets.

“This first LNG cargo is an important milestone for Novatek to enter the global LNG market,” said Lev Feodosyev, Deputy Chairman of Management Board – Commercial Director of Novatek.

“After the launch of the first train of the Yamal LNG project we will enter the LNG market with our own volumes, and gaining spot trading experience is important for us,” Feodosyev added.

Novatek is the operator of the US$27 billion Yamal LNG project in the Arctic which is expected to produce 16.5 mtpa of LNG at full buildout. The first cargo from Yamal LNG’s first train is scheduled to be shipped during the second quarter of 2017.

Novatek’s first spot LNG cargo comes just weeks after Russia’s Rosneft delivered its first ever shipment of the chilled fuel to Egypt.

Gas giant Gazprom is currently the only Russian company that exports LNG from Russia from the country’s sole liquefaction facility in Sakhalin.

At the end of 2013, Russia approved legislative amendments liberalizing its export regulations for LNG, allowing Rosneft and Novatek to export the chilled fuel.

As a result, Gazprom and its unit Gazprom Export lost the exclusive right to ship LNG abroad.

http://www.lngworldnews.com/russias-novatek-says-ships-first-lng-cargo/

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Attached Files

Lynn Helms, director of the Oil and Gas Division of the North Dakota Department of Mineral Resources, testified before the House Committee on Energy and Commerce – Subcommittee on Energy and Power to discuss the effects EPA regulations have had on the state since 2009. Helms’ testimony, which can be read in full here, outlined the ways in which the EPA was creating duplicative and unproductive regulations in the state.

Helms presented a timeline of nine different topics – all of which have the ability to directly impact the way North Dakota regulates the oil and gas industry, starting with the 2010 EPA study of the relationship between hydraulic fracturing and drinking water, to the most recent 2016 request for emission information for existing oil and gas facilities.

Helms pointed to a number of issues, from studies which cannot be concluded due to the EPA Scientific Review Board dealing with concerns over the definitions of “widespread” and “systemic,” to rules that “potential conflict with (North Dakota’s Industrial Committee’s) mission to prevent waste, maximize recovery, and fully protect correlative rights (of mineral owners).”

“It is of great concern to North Dakota that the USEPA rule and guidance would potentially conflict with the Industrial Commission’s mission,” Helms stated in his testimony.

Helms also pointed out that many of the EPA’s regulation were disproportionately costly compared with the environmental threat. “Many states that run effective regulatory programs and have adopted hydraulic fracturing rules that include chemical disclosure, well construction, and well bore pressure testing should be explicitly exempted from the guidance,” Helms said to the sub-committee.

North Dakota’s Mineral Resources director encouraged the sub-committee to expand the use of the program FracFocus nationwide, saying it is “by far the best way for EPA to minimize reporting burdens and costs, avoid duplication of efforts, and maximize transparency and public understanding.

“EPA should consider funding of programs such as FracFocus and Interstate Oil and Gas Compact Commission and Ground Water Protection Council programs such as the State Oil and Gas Regulatory Exchange, UIC Peer Reviews, and National Field Inspector Certification Program,” said Helms. “All of these programs are overseen by governors and state regulators who can provide independent third-party certification, collection of information, and development of best practices about hydraulic fracturing operations in lieu of a new EPA mandatory reporting or voluntary disclosure program.”

He went on to add that some of the rules proposed by the EPA could have a direct impact on the planned expansion of North Dakota’s gas capture and infrastructure requirements, with changes to regulations like the transportation of drill cuttings potentially costing the state billions of dollars.

Other witnesses included, Travis Kavulla, Vice-Chairman of the Montana Public Service Commission and David Porter, Chairman of the Texas Railroad Commission.

http://www.oilandgas360.com/north-dakota-mineral-resource-director-calls-epa-regulations-into-question/

Libya will resume crude exports from two of its biggest oil ports within one week after clashes that forced Islamic State militants to pull out of the area, according to the commander of the petroleum guards in the region.

Crude exports will resume from Es Sider, the country’s biggest oil port, and Ras Lanuf, the third-largest, and which have been closed since 2014, Ibrahim al-Jedran, a regional commander of Libya’s Petroleum Facilities Guard, said in a phone interview. The exports will be under the authority of the Tripoli-based Government of National Accord, which is seeking to reunify the divided country, he said.

Some “minor technical problems” related to the transportation network between the oil storage tanks and the Es Sider and Ras Lanuf oil ports due to damage, inflicted during clashes since last year, will be fixed within a few days, al-Jedran said.

“The oil ports are now safe after Islamic State pulled back away from them toward Sirte,” he said. “The petroleum guards are now capable of guaranteeing the safety and security of oil tankers seeking to use the ports.”

News of the reopening of the ports that had been exporting more than two thirds of Libya’s oil comes after the Petroleum Facilities Guard captured towns from Islamic State militants last month. Rival leaders of Libya’s National Oil Corp., reached an agreement last week to unify the state company under a single management, a step meant to help end the conflict over who can control the divided country’s crude exports and revenue.

Libyan oil officials have made multiple predictions over the past few years that crude production or exports were poised to climb only for those increases to fail to materialize. The nation pumped an average of about 330,000 barrels a day this year, on course for the smallest annual supply in decades, data compiled by Bloomberg show.

http://www.bloomberg.com/news/articles/2016-07-07/libya-to-resume-oil-exports-to-from-biggest-ports-within-a-week

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Attached Files

Nigeria militant group, Niger Delta Avengers said  it has blown up more Chevron oil installations belonging to Chevron Nigeria Limited in the creeks of Delta State early Thursday morning.

In a statement by its spokesperson, Mudoch Agbinigbo, the group said it destroyed manifolds RMP 22, 23 and 24 operated by Chevron in Delta state at about 1:20 am (0020 GMT).

The group had earlier blown up the RMP 23 and 24 last Friday.

RMPs or remote manifold platforms are where smaller oil and gas pipelines converge before being sent

Avengers’ statement read, “Between the hours of 10:50pm to 11:10pm our (Niger Delta Avengers) strike team blew up Chevron Manifolds. The manifolds are RMP 22, 23 and 24.”

Reports indicated that the attacks which occurred in the Warri North area of Delta state may have been carried out using controlled explosive device.

Niger Delta Avengers repeated attacks on Nigeria’s oil installations has brought the country’s oil production to a historic low, worsening the financial crisis inflicted on the country by low crude prices.  

The group has since rebuffed any suggestions of dialogue with the Nigerian government towards stopping its spate of attacks on oil installations.

President Muhammadu Buhari   had also in the past weeks appeal to the militants to stop their attacks on oil installations.

But the militant group had insisted that on more autonomy for the Niger Delta and more control of the oil resources as its key demands.

  http://thenewsnigeria.com.ng/2016/07/niger-delta-avengers-claim-fresh-attack-on-chevrons-oil-facilities/

Noble Energy, Inc. today announced second quarter 2016 expected sales volumes of approximately 425 thousand barrels of oil equivalent per day (MBoe/d).

The amount represents a record quarterly total for Noble Energy and is more than 3 percent beyond the midpoint of the Company's quarterly guidance range of 405 to 415 MBoe/d.

The out-performance was driven by continued strong operating performance and execution across the Company.

Significant contribution to the higher volumes resulted from new wells online in the Eagle Ford, including wells testing various lateral spacing and completion techniques. In addition, Israel gas sales volumes were higher than expected due to continued displacement of coal by natural gas in electricity generation and seasonally warmer weather than normal.

http://www.oilvoice.com/n/Noble-Energy-announces-second-quarter-2016-sales-volumes-of-425-MBoed/72ae425db2c3.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

Already contending with a global price slump, U.S. explorers are also grappling with the demographic hangover of the last great industry downturn in the 1980s, when scores of drillers went out of business. That rout drove a generation away from the business, leaving a shortage of workers in their late 30s to 50s today just as companies try to replace the Baby Boomers who make up much of senior management.

What the industry calls the Great Crew Change -- the looming retirement of thousands of older workers -- has companies trying to plug the gap by training younger employees, recruiting outside the industry and enticing veterans to hang on longer. It’s also forced drillers into a delicate balancing act amid the current downturn, as they lay off thousands but try to hold on to hard-to-replace scientists and engineers.

“Everybody that’s going through the process of downsizing their business right now is faced with this extra complication," said Robert Sullivan, a management consultant for New York-based AlixPartners. “Decisions that get made right now on how you right-size the company are going to have a huge impact when the market turns."

Employers have spent years trying to prepare. Baker Hughes Inc., the oilfield services company, runs a mentoring program for young engineers. Exxon Mobil Corp. has spent about $2.6 million on workforce training initiatives in the Gulf Coast over the last decade, Bill Holbrook, a company spokesman, said. It’s also sponsored ad campaigns to entice more Americans into engineering careers.

Houston-based Apache Corp. has been bracing for the Great Crew Change for 15 years, Chief Executive Officer John Christmann said by phone. The driller has asked some senior staff to extend their careers past retirement age. It also runs a three-year professional development program for new hires designed to cement their ties to the business. About half the company’s technical staff are 36 or younger; another third are over 50.

“There’s a big gap from 1985 to 2000 when not very many people entered this business," said Christmann, 50. While Apache is prepared for the transition, the industry as a whole is “reeling a little bit because we don’t have a lot of those managers," he said.

The wave of retirements comes as the oil sector is already bleeding talent. Worldwide, oil and natural gas companies have cut more than 350,000 jobs since crude prices started to fall in 2014, according to a May report by Houston-based consultant Graves & Co.

http://www.bloomberg.com/news/articles/2016-07-07/lost-generation-of-oil-workers-leaves-few-options-for-next-boom

Royal Dutch Shell's Nigerian division lifted a force majeure on exports of Bonny Light crude oil on Thursday, the latest sign that Nigeria's oil production is recovering after being hit by militant attacks in its oil-rich delta region.

The force majeure was lifted from 09:00 a.m. Nigerian time (0800 GMT) on Thursday, the company said in a statement, following restoration of production into Bonny Terminal.

Two other Nigerian crude oil grades - Forcados and Brass River - remain under force majeure. But the country's oil production has remained resilient despite some of the worst militant attacts in decades on delta region oil facilities.

Oil prices rose during the attacks, which briefly pushed Nigeria's production to 30-year lows. The country was Africa's largest oil exporter, but dropped into second place behind Angola earlier this year due to the disruptions.

Still, some fields recovered more quickly than expected so that Nigeria's exports were largely steady from April into May.

Exports are on track to rise in August, although the Niger Delta Avengers, the group that has claimed responsibility for the worst of the damage, have continued to attack oil installations.

Bonny Light exports had continued during the force majeure, a legal declaration made on May 11 following the closure of the Nembe Creek Trunk line. But cargo loadings are expected to run more smoothly now it has been formally lifted as these had been subject to repeated delays.

http://www.reuters.com/article/nigeria-crude-forcemajeure-idUSL8N19T2JK

Libya's oil guards back NOC, preparing to reopen fields - spokesman

Libya's oil guard brigades, who control Ras Lanuf and Es Sider, two major export terminals closed since 2014, are working with the unity government's state oil company and preparing to reopen shuttered fields to pump crude again, a spokesman said on Thursday.

The spokesman for Ibrahim Jathran's PFG forces did not give any details of whether that would include reopening the two ports soon; starting shipments there would restore a potential 600,000 barrels per day of crude export capacity.

Militant attacks, fighting between rival factions and strikes have kept Libya's oil production at around 350,000 bpd, or less than a quarter of its output before the 2011 revolution that ousted Muammar Gaddafi and began years of instability.

The National Oil Corporation (NOC) is working with the U.N.-backed government of national accord, led by Prime Minister Fayaz Seraj, who is trying to bring together rival factions whose armed backers have fought for control and oil resources since 2014.

"The commander of Petroleum Facilities Guards (PFG), Ibrahim Jathran, has announced that oil will be pumped soon and oilfields of the oil crescent (region) will be also prepared to resume work," PFG spokesman Ali Hassi said.

"Jathran said that we, the PFG of central region, will work with the NOC that belongs to the presidential council of the government of national accord."

The NOC announced this week that it would merge with a rival energy company set up in the east by Libya's eastern government, a move seen by analysts as a step towards restoring order to the industry.

The NOC in Tripoli, recognised by the international community, and the eastern NOC had operated in parallel as the rival governments struggled for control. The U.N.-backed government now in Tripoli is meant to supersede those administrations, but hardliners on both sides are holding out.

The NOC has an ambitious plan to bring Libya's oil production back to pre-revolution levels. But damage to oil pipelines left closed for months, and to ports that have seen fighting, may take years to fully repair.

Islamic State militants who are fighting in the western city of Sirte have also targeted the oil infrastructure in the past, and Seraj's unity government has yet to fully establish its influence.

http://www.reuters.com/article/libya-security-energy-idUSL8N19T0X7

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Attached Files

Investments in additional oil sands production capacity in Alberta will be boosted with a WTI price hovering between $55/b and $60/b even as producers spare no effort to reduce their capital costs, executives said Wednesday.

"It is still tough out there, but in the past year we have dropped operating and capital costs by 17% and 30%, respectively, with our focus still being on consolidation and optimization," Lyle Stevens, Canadian Natural Resources executive vice president, told the 2016 TD Securities Energy Calgary Conference.

CNR is adding 23,000 b/d of oil equivalent of heavy and light oil output in Western Canada over the coming six months at a cost of C$17,000 ($13,120)/flowing barrel and is also three months away from adding 45,000 b/d of bitumen output at its Horizon facility in northern Alberta, he said.

Flowing barrel costs include construction costs and sustaining capital and operating expenditure.

"We're feeling a lot better this year than last year and have also been successful in cutting costs by 40% primarily due to the application of new technologies and deflation in the service sector," Harbir Chhina, executive vice president of oil sands development with Cenovus Energy, told attendees of the same event.

Cenovus will restart three projects that were put on the backburner last year due to low oil prices. But the company would seek "price sustainability" before taking a final investment decision, Chhina said.

"We are going to design this [oil sands] business at WTI $55/b," Chhina said, without naming the three projects that would likely be sanctioned for development.

No decision has been made yet about the restart of deferred projects as oil prices move higher, Cenovus spokesman Brett Harris said separately in an email, adding that the earliest an update on capital allocations would likely be available was in the company's second-quarter earnings later in July.

MEG PLANS BITE-SIZED PROJECTS

Fellow producer, MEG Energy, which is producing at less than C$10/b, could "very quickly turn on" a few bite-sized oil sands projects typically of 10,000 b/d to 15,000 b/d if prices were to rise to $60/b, company spokesman John Rogers said at the same event.

But Suncor Energy, which is on track to produce first oil in late 2017 from its 180,000 b/d Fort Hills development, will be less proactive in loosening its purse strings, the company's executive vice president for refining and marketing, Kristopher Smith, said.

"We need some very strong signals on prices before we sanction new projects beyond Fort Hills and Hebron," Smith said.

Hebron is a heavy oil development in offshore Newfoundland and Labrador that is due to start up in late 2017 and is being developed by operator ExxonMobil Canada along with Suncor, Chevron, Statoil Canada and Nalcor Energy.

In 2015, Suncor reduced its costs by $1 billion, with a target of doing so again by C$500 million in 2016, Smith said.

"This is not a crash diet, but a life-cycle change. With cash operating costs of just north of C$24/b, managing costs will be a focus and a challenge and there is a need for a structural change," Smith said.

While the oil sands sector will likely receive the bulk of the planned investments, availability of financing will decide the future growth of tight oil production in Alberta and Saskatchewan, MEG Energy's Rogers said.

"For an oil sands project, we spend 20% of our cash on maintaining the facility while the remaining 80% is available for growth. But for tight oil, it is just the reverse," Rogers said.

Tight oil output in Western Canada is forecast to decrease 13% by 2019, the Alberta government said in a report in April.

Compared with production of some 560,000 b/d in 2015, output will decline to 529,000 b/d this year and 524,000 b/d in 2017. In 2018 and the following year, production is forecast to be 506,000 b/d and 486,000 b/d respectively, it said.

http://www.platts.com/latest-news/oil/calgary/alberta-oil-sands-producers-will-eye-new-projects-21904248

The oil industry is losing the burn of Asian demand

After half a year of strong oil price rises, Asian crude demand is slowing and by some measures falling, and many market participants suspect it is not just a cyclical phenomenon, but also a product of more permanent structural changes.

But an industry that has come to rely on Asia's booming thirst for oil could soon be scratching around for growth.

Thomson Reuters Eikon data shows that Asian crude oil tanker imports have fallen, albeit from record levels, for four straight months and by 12 percent since March to around 82 million tonnes (20 million barrels per day), slightly below last year's levels.

Much of the surprise decline is explained by conditions in China, the region's biggest consumer, accounting for 27 percent of Asia-Pacific demand and 13 percent of global demand.

With its long-term growth outlook now camped perhaps permanently below 7 percent, most analysts expect vehicle sales in China will slow accordingly.

They have already slipped to 2.1 million at the end of May, down from a peak of almost 2.8 million in December 2015.

Refiners across Asia said that was starting to hit their business.

"Asian oil demand growth is slowing down. China, Asia's largest market, is experiencing sluggish demand," said a South Korean refiner.

As domestic refiners sell off surplus fuel, China's exports of diesel and gasoline, the main refined fuels for industrial and passenger vehicles, have both soared.

"Asia refiners have already started to pull back ... and there are reports of (oil) cargoes struggling to sell," said Adam Longson of Morgan Stanley this week in a note to clients, adding that demand in the third quarter could fall further.

Ship brokers say traders have started chartering supertankers to store supplies that consumers can't absorb.

One key pillar of recent demand is never coming back. Analysts think China has nearly finished building its strategic petroleum reserves (SPR).

Oil analysts at JPMorgan estimated in a note to clients last week that the SPR was now at 400 million barrels, which they believed was close to capacity.

"Our model suggests a 15 percent month-on-month decline in China's crude oil net imports in September, or a loss of 1.2 million barrels versus August and 0.8 million barrels less from the 12-month average," they said.

http://www.reuters.com/article/us-asia-oil-demand-idUSKCN0ZN019

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Attached Files

The American Petroleum Institute (API) trade group said its data showed U.S. crude stockpiles fell by 6.7 million barrels last week, declining for a seventh week in a row.

The profit from turning U.S. crude into gasoline, known as the gasoline "crack," remained at a four and a half month low despite expectations that a record number of motorists would hit the road during the July 4 holiday weekend.

Gasoline stocks in the U.S. East Coast, home to the New York Harbor delivery point for the fuel, reached a record high of 72.5 million barrels in the week ended June 24. Vessels carrying gasoline-making components could not unload at the harbor this week because of lack of space.

http://www.reuters.com/article/us-global-oil-idUSKCN0ZM01H

Summer driving season is in full swing and American motorists are filling their tanks at a healthy clip, but that is not swelling the profit margins as much as usual at U.S. independent oil refiners such as PBF Energy Inc and Valero Energy Corp.

In April, executives shrugged off the industry’s lousy first quarter as an aberration that would be remedied this summer.

“We still are bullish gasoline and bullish octane," PBF CEO Tom Nimbley told investors in an earnings call back then. “The driving season really hasn't hit that hard yet.”

Nimbley was right about the surging summer demand. But refiner margins are still being squeezed as gasoline and diesel inventories stubbornly sit well above five-year averages.

Summer gasoline demand usually fattens margins for refiners with seasonally high levels for the crack spread, the premium of a barrel of gasoline over a barrel of crude oil.

That will not happen this year, said analysts who expect the situation to remain bleak in the weeks ahead unless there are large drawdowns in inventories.

Late on Wednesday, the American Petroleum Institute, an industry group, assuaged some of those concerns, reporting a 3.6-million-barrel drawdown in gasoline stocks. Yet inventories remain much higher than they were last year at this time, and analysts have slashed earnings estimates for big U.S. refiners who report second-quarter results in coming weeks.

The situation is so dire that U.S. East Coast refineries have been cutting production. Refiners on the East Coast, known as "PADD 1" by the U.S. Energy Department, are typically the first to feel a profit pinch, because their margins tend to be thinner than those of other regions.

“PADD 1 is a holy mess,” said Andrew Lebow, senior partner at Commodity Research Group in Darien, Connecticut. “It is very unusual. If a market becomes extremely oversupplied, like PADD 1, they are going to have to cut runs.”

The U.S. gasoline crack spread 1RBc1-CLc1, a proxy for refiner margins, has dropped 34 percent in two weeks. On Wednesday, it hit a five-year low for this time of year of $13.10 a barrel. That is less than half the crack spread of $28 a barrel at this time last year.

"An RBOB crack trading 13 bucks in the middle of driving season is unheard of," said one trader.

East Coast gasoline stocks hit a record 72.4 million barrels, about 17 percent higher than the same time last year, data from the U.S. Energy Department showed last week. Overall, U.S. gasoline stocks were at 239 million barrels in the week to June 24, nearly 10 percent higher than last year and 15 million barrels more than the five-year average.

The glut is so extreme that several tankers full of products were forced to sit idle in New York Harbor recently, waiting to unload.

Inventories have grown despite evidence that U.S. motor travel continues to surge. Analysts noted that U.S. refiners switched to maximum gasoline mode earlier than usual during a fleeting moment of high margins in the early part of 2016. Imports also have been higher than normal in recent weeks, adding to the glut.

John Auers, executive vice president at Turner, Mason & Co, a Dallas-based consultancy, said he remains bullish on gasoline demand and refining margins this summer, noting that gasoline and diesel inventories can draw down just as fast they fill up.

“I think we will see some significant drawdowns in July and August, and that will help margins,” Auers said. “I think $50 a barrel for crude oil will be the high water mark, so gas prices will remain low and we will have a record driving season this summer."

He warned that if inventories remain historically high at the end of the summer, refiners could be forced to cut production significantly to account for weaker seasonal demand.

The 10 largest independent U.S. refiners booked a combined net income of $944 million in the first quarter, down 74 percent from a year earlier, a Reuters analysis showed. That put profits on track to be much less than the annual level of more than $10.6 billion in the past five years.

Auers estimated that second-quarter margins would come in as the lowest for this normally profitable quarter in at least five years. Over the last 30 days, estimates for second-quarter earnings have fallen 17 to 20 percent for four of the major U.S. refiners, Phillips 66, Valero Energy, Marathon Petroleum and Tesoro, according to Thomson Reuters StarMine.

http://www.reuters.com/article/us-usa-refineries-cuts-east-coast-idUSKCN0ZN0BD

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Qatar’s exports of liquefied natural gas (LNG) to India and Pakistan grew by 50 percent annually over the first half of the year. LNG deliveries to South Asia reached 7,138,785 metric tons from January to June, which is an increase of 46 percent compared to the same period in 2015. Of this, Qatar delivered 6,045,886 metric tons to India.

The India shipments resulted from a revised contract between India’s Petronet and Rasgas of Qatar. In December of last year, the two companies re-worked a long-term agreement that had stipulated the delivery of 7.5 million metric tons of LNG per year to India. The revision followed Petronet delivering some 30 percent less than the amount it had agreed to deliver up to September 2015.

According to the new revisions, the volumes not taken in 2015 would be purchased during the term of the contract with 1 million metric tons added to the total contract volume.

In Pakistan, Petronet delivered some 1,092,899 metric tons of LNG during the first half of 2016. The increase in deliveries was attributed to a new 15-year agreement with Qatargas for the delivery of 3.75 million metric tons per year. That deal was inked in February. Deliveries began in March. During that time, deliveries of LNG from Qatar rose to around three cargoes per month, which was up from one per month for the same period in 2015.

Qatar gas shipments to parts of the Middle East also saw a spike in the first half of this year. The amount was an increase of approximately 20 percent in the shipments to Dubai, Kuwait, Jordan, and Egypt. Egypt had the lion’s share of deliveries. The country has meanwhile purchased two floating storage and regasification units, which will give Egypt the ability to increase its imports. The units were delivered last year.

http://oilprice.com/Latest-Energy-News/World-News/Qatar-Sees-Spike-in-LNG-Exports-to-South-Asia-Middle-East.html

Rex Energy, now a pure play driller focused on the Marcellus/Utica, announced yesterday that its bankers have reaffirmed (or continued) the company’s $190 million borrowing base.

A company’s borrowing base is the value of its assets–in this case the value of the leases and oil/gas wells Rex owns. Those assets are used as collateral to back up loans and IOUs.

Rex has plenty of both. Rex announcement that its bankers will continue to value Rex’s assets at $190 million…

http://marcellusdrilling.com/2016/07/rex-energys-190m-borrowing-base-reaffirmed-by-bankers/

Last week MDN reported that Southwestern Energy, a major Marcellus/Utica driller, was floating up to 86 million shares of new stock looking to raise $1.1 billion

If you do the math, it worked out to ~$12.75 per share. The stock offering is done and dusted.

Southwestern ended up selling 98.9 million shares for $1.247 billion, or $12.60 per share. Not too shabby in a down market where investors have been reluctant to continue funding oil and gas companies…

http://marcellusdrilling.com/2016/07/southwestern-exceeds-goal-in-new-stock-offering-raises-1-2b/

U.S. crude oil exports rose to a record 662,000 barrels per day in May from 591,000 bpd in April, foreign trade data from the U.S. Census Bureau showed on Wednesday.

Canada accounted for the most U.S. crude exports at 308,000 bpd, followed by the Netherlands at 110,000 bpd and Curacao at 67,000 bpd. Other prominent destinations were the United Kingdom at 36,000 bpd, Japan at 29,000 bpd and Italy at 23,000 bpd.

The total export figure was the highest on record since at least 1920, according to U.S. government data.

U.S. oil exports have risen since a decades-long ban on them was lifted in January. During that time, a number of merchants, traders, producers and even refiners have moved crude to Latin America, Europe, Asia and other locations.

The Census Bureau publishes its oil export data weeks before the closely watched U.S. Energy Information Administration trade figures. The EIA, which bases its numbers on the Census data, will release its monthly crude figures at the end of July.

http://www.reuters.com/article/us-usa-oil-exports-idUSKCN0ZM1E5

Exxon Mobil Corp. and Qatar Petroleum have teamed up to look at energy assets in Mozambique, home to some of the biggest natural-gas discoveries in a generation, according to four people with knowledge of their plans.

The companies are considering buying stakes in gas fields owned by Anadarko Petroleum Corp. and Eni SpA, the people said, asking not to be identified because the matter is confidential. They have a strong relationship and often discuss potential investments, though no final agreement has been reached, the people said.

Mozambique’s discoveries in the Rovuma Basin off its northern coast have attracted oil companies from Europe, the U.S. and China as the southern African country plans one of the world’s largest liquefied natural gas projects. Investment from Exxon and state-owned Qatar Petroleum, which have partnered in joint ventures for at least 15 years, would bring much needed funds for development, not to mention a tax windfall to a nation grappling with a deepening debt crisis.

Exxon, Eni and Anadarko declined to comment. Qatar Petroleum didn’t respond to a call or e-mail.

Exxon Presence

Anadarko operates in Area 1 of the Rovuma Basin, while Eni is in Area 4. Both have plans to export the gas as LNG, though neither has reached a final investment decision.

Exxon has already established a presence in Mozambique after winning three offshore exploration licenses in October for blocks to the south of the Anadarko and Eni finds. The U.S. company also has a working interest in Statoil ASA’s Block 2 in Tanzania, north of the Rovuma Basin.

Exxon’s ties with Qatar, the world’s largest exporter of LNG, include the RasGas partnership, which produces and liquefies gas from Qatar’s North field, and the Golden Pass LNG terminal in Texas.

Acquiring a share of Anadarko’s Area 1 could generate capital gains tax of about $1.3 billion for the Mozambique government, one person said last month, adding that Exxon is also interested in Eni’s Area 4. Rome-based Eni said in May that it’s in talks to sell a stake in its discovery and expects to decide on its LNG project this year.

Should Exxon and Qatar decide to invest, they would potentially accelerate the realization of Mozambique’s LNG export ambitions amid a looming credit crunch. The country is struggling to balance its books after $1.4 billion of hidden debt was disclosed in April, prompting the World Bank and other donors to suspend aid.

http://www.bloomberg.com/news/articles/2016-07-06/exxon-said-to-join-forces-with-qatar-for-mozambique-gas-assets

A militant group has reportedly bombed an Ecopetrol pipeline in Colombia.

The incident has halted output and caused an oil spill into a nearby river.

The Cano Limon pipeline is the second largest in Colombia and trasnfers oil from Occidental Petroleum’s oilfields near the Venezuelan border to the Caribbean port of Covenas.

According to local reports, the pipeline was hit late on Monday in Boyaca department’s Cubuara municipality.

https://www.energyvoice.com/oilandgas/113937/pipeline-reportedly-bombed-colombia/

Africa-focused oil explorerTullow Oil has issued convertible bonds worth $300-million, a move it said was designed to diversify its investor base, sending its shares to the lowest in nearly three months.

The bonds, due in 2021 and offered at a conversion price set at a 30% to 35% premium to the average Tullow share price on July 6, will be offered to institutional investors at a coupon between 5.88% and 6.63%, Tullow said on Wednesday.

"The proposed convertible bond issue will further diversifyTullow Oil's sources of funding and give the company access to a new investor base," said CFO Ian Springett.

Tullow shares were down 12% at 211.5 pence at 07:55 GMT, the lowest since April 18.

An initial negative share price reaction had been expected due to bond investors typically hedging their purchases by taking a short position on the share price, a source close to the company said.

Tullow said it would use the money raised to pay for investments in west and east Africa, where it is developing new oil fields, and general corporate purposes.

In April, the oil producer announced its lenders had agreed to extend a revolving loan facility by a year and to increase flexibility on another, helping Tullow keep its finances in order amid weak crude prices.

"The fact that the company needs $300-million after the recent reassessment of its borrowing facilities is a bit of a surprise to us," said analysts at Stifel, who recommend selling Tullow shares.

Other analysts judged the bond issuance more positively.

"The dilution should be limited and this is a useful diversification of funding for Tullow," said analysts at RBC Capital Markets, who rate Tullow's stock as 'outperform'.

http://www.miningweekly.com/article/tullow-issues-convertible-bonds-to-attract-new-investors-shares-dive-2016-07-06

U.S. gasoline stocks remain stubbornly high despite record demand from motorists, a situation that will probably force refiners to cut crude processing over the next few months and prioritise production of diesel.

The prospect of reduced refinery processing rates has intensified the downward pressure on crude oil prices in recent days.

U.S. gasoline stockpiles have been running above last year's level since January but the year-on-year build-up has increased rather than lessened as the summer driving season arrived (tmsnrt.rs/29jUrGi).

Gasoline stockpiles hit a seasonal record 239 million barrels on June 24, an increase of 22 million barrels (10 percent) compared with the previous year, according to data from the U.S. Energy Information Administration.

The year-on-year stock build has grown from 14 million barrels (6 percent) at the end of April and 10 million barrels (4 percent) in late January (tmsnrt.rs/29hzorF).

The gain in stockpiles has been most pronounced along the U.S. East Coast, where stocks were 13 million barrels (21 percent) higher than prior-year levels and still increasing as recently as June 24 (tmsnrt.rs/29hzdg6).

The degree of oversupply is less in other parts of the eastern United States.

Gasoline stocks in the Midwest are up by 4 million barrels (8 percent), while stocks on the Gulf Coast are up by 6 million barrels (8 percent) (tmsnrt.rs/29hzqA9 andtmsnrt.rs/29jUQbP).

But the East Coast is the pricing point for U.S. gasoline futures which call for delivery to New York Harbor.

Tankers have been forced to anchor off the harbour, unable to discharge their cargo, because local tanks are full ("Gasoline tankers drop anchor off New York as stocks brim", Reuters, July 4).

Unsurprisingly, gasoline futures prices and crack spreads have come under pressure as stocks build in the region.

The crack for gasoline delivered in October has fallen from a peak of almost 30 cents per gallon on May 23 to less than 22 cents on July 5 (tmsnrt.rs/29hA8wU).

Futures prices are anticipating even worse oversupply once the peak demand season for gasoline finishes in September.

In contrast to gasoline futures, crack spreads for middle distillates such as heating oil and diesel, have continued to climb.

Refiners have only limited flexibility to shift from producing gasoline to distillates in the short term ("Increasing distillate production at U.S. refineries", EIA, 2010).

So the main response to falling gasoline cracks is likely to come through reduced refinery crude processing, which will cut the output of heating oil as well as gasoline.

Delta's refinery at Philadelphia has already cut production by 16 percent, according to sources familiar with the plant's operations .

Run cuts should eventually rebalance the gasoline market but will tighten the distillate market even further, supporting heating oil cracks.

http://www.reuters.com/article/usa-gasoline-kemp-idUSL8N19S243

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Brazil on Tuesday said it will sell four areas in its prolific subsalt region by mid-2017 to speed up development of offshore oil and gas discoveries blocked by nationalist energy policies and state-run Petrobras' debt and financial woes.

One of the areas will abut the giant Carcará prospect in the BM-S-8 block in Brazil's offshore Santos Basin south of Rio de Janeiro, Marcio Felix, the energy ministry's oil and gas secretary designate, told reporters in Rio de Janeiro.

"Without this sale, Carcará can't be developed," said a senior official with a company that owns Carcará resources.

While there is no official estimate for the size of Carcará, partners in the group, including state-led Petroleo Brasileiro SA, or Petrobras, Portugal's Galp Energia SPGS SA, and Brazil's Barra Energia and QGEP Participações SA, have said it rivals Brazil's 8-billion-barrel Lula field.

With enough oil to supply all the world's needs for nearly three months, Lula is one of the world's largest discoveries in four decades. The subsalt is a region near Rio where about 100 billion barrels of oil are trapped deep beneath the seabed by a layer of mineral salts.

Petrobras owns 66 percent of BM-S-8 where Carcará was discovered, and is lead partner or "operator". Galp owns 14 percent and Barra and QGEP each own 10 percent.

In addition to areas abutting BM-S-8, Felix said the auction will sell blocks adjacent to Petrobras' Tartaruga field; the Sapinhoa field owned by Petrobras, Royal Dutch Shell Plc, Spain's Repsol SA and China's Sinopec; and the Gato do Mato prospect owned by Shell and France's Total SA.

Changes made in 2010 by a previous government to Brazil's oil law were designed to increase government control of the giant subsalt discoveries and channel an expected bonanza to health care, education and economic development.

Instead they stalled investment and put development into regulatory limbo. They've since combined with a Petrobras corruption scandal, the company's $126 billion of debt, the world oil industry's largest, and a plunge in oil prices, to hobble a once-booming oil industry.

Carcará partners have invested more than $2 billion to date but will have to wait until at least 2020 for a return, two decades after rights to the area were first sold.

Brazilian law also requires fields to be developed as a single unit, meaning parts of Carcará extending into unleased areas must be sold to another company and "unitized" with Carcará resources in BM-S-8.

About 55 percent of Carcará is outside BM-S-8, the Carcará partner and a governmentsource said.

The 2010 law, though, required all unleased areas in Brazil's subsalt to be operated and at least 30 percent owned by Petrobras. New subsalt areas must also be sold under production sharing contracts, where the government earns both oil and royalties. Older areas such as BM-S-8 are concessions that pay only royalties.

Short of cash, though, Petrobras can no longer afford new subsalt areas it is legally obligated to lead.

"Petrobras is broke, the rules a mess. Without change we're stuck," the Carcará partner said.

A bill ending Petrobras' obligation to lead all new subsalt development should pass Congress within weeks, opening the 2017 subsalt auction to new bidders, Felix said.

Rules clarifying unitization of concessions and production-sharing contracts will be complete by year end, he added.

http://www.reuters.com/article/us-brazil-oil-auction-idUSKCN0ZM0BU

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Indonesia's state-owned oil and gas company Pertamina will seek partners to build a strategic petroleum reserve of about 25 million barrels to ensure energy security, a senior official said Tuesday.

"The third party will provide the crude. We plan to select partners after Eid al-Fitr," Pertamina's processing director Rahmad Hardadi said.

About 60% of the crude for the SPR storage was expected to come from domestic production and the rest from other sources, he added.

The SPR storage facility was expected to be built in 1 1/2 to two years, Hardadi said.

The company also plans to build storage capacity for 7.3 million kiloliters of oil products by 2020 from 4.8 million kl currently, S&P Global Platts reported earlier.

President Joko Widodo has committed to build upstream and downstream infrastructure, such as new refineries, pumping stations and storage tanks in a bid to cut Indonesia's dependency on imported fuels.

The government also plans to provide incentives to private companies to participate in building the infrastructure.

Indonesia is already in talks with Oman, Kuwait, Iran and Saudi Arabia to lease storage tanks to hold buffer stocks of crude and oil products equivalent to 30 days of consumption.

http://www.platts.com/latest-news/oil/jakarta/indonesias-pertamina-eyes-spr-storage-facility-27619711

Shale producers are tapping their crown jewel assets in response to the latest oil price rally, according to Morgan Stanley.

The recovery in crude to close to $50 per barrel has encouraged shale producers to double down on their most profitable fields — a process known in oil country as high grading.

This new trend threatens to force analysts to revisit calls for declining U.S. production, warned Morgan Stanley Commodity Strategist Adam Longson, and thereby constitutes a downside risk for prompt prices.

"The rig count in the highest initial production counties of the Permian Midland continues to march higher and is not far from its 2015 peak," writes a Morgan Stanley team led by Longson. "Since May 6, the Midland has added 13 horizontal rigs in top tier counties versus only eight for the entire play."

In other words, capital is returning to the oil patch, and it's being invested in new projects that will allow firms to boost production in an expeditious manner once the taps are turned on.

The collapse in headline oil rig count, as such, continues to provide only a partial picture of the outlook for U.S. production.

If this trend towards new fertile plays continues, it could alter the downwards trajectory for U.S. production in about four to six months, said Longson.

"It’s also important to consider that the rigs are going into the most prolific areas, the decline curve for shale wells is flattening, and completing drilled-but-uncompleted wells could slow declines in as short as one to two months," he added.

http://www.bloomberg.com/news/articles/2016-07-05/grade-grubbing-oil-producers-are-threatening-to-boost-u-s-output-yet-again

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Genscape reported an unexpected 230k barrel build at Cushing

@Zerohedge

Is a peace dividend in the form of more investment-and ultimately more production and jobs-coming to Colombia's beleaguered oil and gas sector?

That's been the hope of executives and analysts since the government signed a permanent cease fire on June 23 with the Revolutionary Armed Forces of Colombia, or FARC, the country's largest rebel group. If a comprehensive peace deal is signed later this summer as expected, the warring sides could end 52 years of armed aggression.

An end to hostilities, assuming one takes hold in the mostly rural areas where oil is pumped, would be welcome news for E&P and oil field services firms. Their employees have been regular victims over the decades of FARC kidnappings, bombings, extortion and murders.

From 2001 through 2015, Colombian national police reported 219 oil company employees were kidnapped for ransom by FARC guerrillas and other groups, according to figures compiled by Agora Consultorias, a risk analysis firm in Bogota. Oil firms have paid untold millions in extortion payments to armed groups as well.

Over that same 15-year period, there were 1,814 reported bombings of Colombian pipelines, the vast majority by suspected FARC rebels. According to El Tiempo newspaper, as many as 4.1 million barrels of oil have been lost to the bombings since the mid-1980s, or more than twice the oil spilled by the Exxon Valdez after it ran aground in Alaska in 1989.

Naturally, those statistics have had a chilling effect on Colombia's oil patch, especially in recent years as lower global prices have made the Andean country a tougher sell to oil companies' investment committees. Added to the country's challenging logistics and higher lifting costs associated with heavy oil, security issues have driven many companies to more inviting conditions in Mexico, Peru and Argentina.

Three years of investment declines are coming home to roost, contributing to a precipitous decline in Colombia's crude output this year. After averaging 1,005,000 b/d in 2015, Colombia pumped only 904,000 b/d in May, down a shocking 11.8% from what was pumped in the year-ago month.

Adding to the gloom is that Colombia's proven oil reserves took a major hit last year, falling to 2 billion barrels as of December 31, down from 2.308 billion barrels at the end of 2014, a 13% decline.

The drop follows a 5.6% decline reported at the end of 2014.

Others step in where FAR C left

President Juan Manuel Santos insists the improved security resulting from a peace deal, which if signed would go before Colombian voters later this year, could be a turning point, making Colombia more appealing to investors in energy and other sectors.

But analysts caution that benefits from a peace accord will take time to materialize. Moreover, investors are weighing factors other than security in their Colombian investment decisions, including a looming tax reform package that goes before Congress later this year that could place a higher fiscal burden on oil companies.

Orlando Hernandez, president of Agora Consultorias, notes that Colombian armed forces are still at war with other rebel and criminal groups that dominate some areas of rural Colombia, making the Colombian oil patch still a risky environment.

Hernandez notes that as the FARC has wound down its violent activities since declaring a provisional cease-fire a year ago, the National Liberation Army, another rebel group known by its Spanish initials ELN, had moved in. The ELN has carried out 15 pipeline attacks so far this year, up from its year-ago total of five, he said.

The Colombian government and the ELN are not currently in peace talks.

Another problem that oil companies face that won't be helped by a FARC peace deal is the rising occurrence of blockades by peasants and indigenous groups of oil and gas installations. Executives complain that the blockades have been more damaging to production in recent years than the rebels. Some groups have environmental complaints against E&P projects, others do it to extract labor or royalty concessions from the government.

Currently, a month-long blockade by indigenous groups of a natural gas processing plant in the town of Gibraltar in northeast Colombia has caused a 30% increase in gas prices for residents of nearby Bucaramanga. Last year, groups blocked repair crews from fixing the 220,000-b/d Cano Limon pipeline for two months, costing the country millions in oil revenue, Hernandez said.

http://www.oilvoice.com/n/Colombias-peace-deal-could-spur-oil-sector-turnaround-Fuel-for-Thought/6097671f8ea7.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

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Oil well pads are getting bigger in western North Dakota as companies figure out how to get the most oil out of the Bakken.

Hess Corp. has the Bakken’s largest well pad with 18 wells on a single location, but the state’s top oil regulator says he expects to see mega-pads get even larger.

“At any time in the not too distant future, their record is going to be eclipsed,” said Lynn Helms, director of the Department of Mineral Resources.

Regulators already have permitted a few larger multi-well pads, including one from Continental Resources that will have 25 wells on one location.

Many landowners prefer consolidating more wells onto one location rather than having several smaller pads, said Troy Coons, chairman of the Northwest Landowners Association.

“For the most part, people want things to be the most efficient so they can farm around them with the least amount of impact on the land,” Coons said.

On average, a single-well pad takes up 3.35 acres, Helms said.

But consolidating 18 or more wells on on pad can shrink that impact to less than 1 acre per well, Helms said.

“That’s an enormous reduction in use of the landscape,” Helms said. “I think we’re going to see a lot of 16-plus well pads.”

In addition to reducing the footprint of oil production, companies are finding other benefits.

Hess recently increased the amount of oil the company expects to recover from its Bakken and Three Forks wells from 1.4 billion barrels to 1.6 billion barrels. The increase in production is in large part due to spacing the wells closer together, as well as optimizing hydraulic fracturing techniques, said Gerbert Schoonman, a Hess vice president who oversees the company’s Bakken assets.

“All of a sudden, essentially you add another 200 million barrels of recoverable reserves to your business,” Schoonman said. “There aren’t many fields in the world that have got 200 million barrels. This is big.”

Oil companies are experimenting with different well densities to optimize how much oil they can recover from the Bakken and Three Forks formations.

For Hess, drilling nine middle Bakken wells and eight Three Forks wells in a single location is showing good results, Schoonman said, though the company is doing other field studies.

These multi-well pads are unique to the Bakken, Helms said.

“In my experience, our multi-well pads are larger and have a lot more wells on them,” he said.

The largest locations will be concentrated in the core of the Bakken in McKenzie, Dunn and Mountrail counties. In those areas, Helms estimates it will take 32 wells in a single 1,280-acre spacing unit to fully develop the Bakken.

The areas on the fringe of the Bakken, such as parts of Stark and Divide counties, will likely have four to six wells in a single area, Helms said.

At the Hess 18-well pad in Mountrail County, the location has nine pump jacks lined up on one side and nine on the other, with horizontal wells extending two miles in opposite directions. Pipelines transport the oil, natural gas and produced water - a waste byproduct of oil production - to nearby facilities for further processing. The 20-acre pad, which looks like a gravel parking lot, is surrounded by a containment berm in case of a spill.

Steve McNally, general manager for Hess in North Dakota, said multi-well pads make the entire process of developing a well more efficient, from acquiring the land to drilling and fracking the well to monitoring wells once they’re complete.

“It reduces the amount of time through every single step,” McNally said.

Consolidating wells also allows pipelines to be installed to one location, rather than several smaller ones, eliminating truck traffic and reducing natural gas flaring.

One potential downside to multi-well pads is that by consolidating the drilling, it could also concentrate the waste, Helms said.

State regulations allow companies to bury drill cuttings – a waste byproduct of oil development – on the drilling site after mixing them with a stabilizing material. Cuttings pits at multi-well pads will be larger with the waste more concentrated in one place, Helms said.

But companies can also choose to dispose of the cuttings by hauling them to a special waste landfill, which is how Hess handles the waste.

Another downside of the larger locations is they can have a major impact on a single landowner, Coons said.

http://bismarcktribune.com/news/state-and-regional/bakken-multi-well-pads-getting-bigger/article_6b164795-1643-5ef9-8960-e74689d6c8d6.html

Cabot Oil & Gas Corp. reported Tuesday that it has executed a 10-year sales agreement to be the exclusive provider of natural gas supplies to Invenergy LLC's Lackawanna Energy Center power plant.

Additionally, South Jersey Industries (SJI) , the energy holding company for South Jersey Resources Group, LLC, will become a counterparty to both entities through an exclusive supply fuel management service agreement.

The company noted that confidential pricing terms under the deal guarantee Cabot attractive rates of return while providing fuel costs directly linked to power prices, eliminating risks for each of the parties involved in the transaction.

The proposed facility is a natural-gas fueled 1,500 megawatt combined-cycle generating station located in Lackawanna County, Pennsylvania and is expected to be one of the most efficient power plants in the United States.

Commercial operations are expected to begin in mid-2018 and to reach full-scale operations by year-end 2018. The facility, at maximum capacity, will burn up to 240,000 dekatherms of natural gas per day.

Dan O. Dinges, Chairman, President and Chief Executive Officer, said, "Together with our previously announced agreement with SJI to supply natural gas to the Caithness Moxie Freedom project, Cabot will be providing more than 400,000 dekatherms of natural gas per day for power generation directly in our backyard."

http://world.einnews.com/article/334087728/5LQ2Lzc23n5p58YS

Noble Energy, Inc. today announced that it signed a definitive agreement to divest a 3 percent working interest in the Tamar field, offshore Israel, to the Harel Group, a leading insurance provider and pension manager in Israel, in partnership with Israel Infrastructure Fund ('IIF'), Israel's largest infrastructure private equity fund. The transaction value of $369 million is based upon a gross pre-tax Tamar valuation of approximately $12 billion and is subject to purchase price adjustments between January 1, 2016 and the closing date. Closing for the transaction is anticipated in the third quarter of 2016, subject to customary terms and conditions, with after-tax proceeds received expected to be approximately $275 million. Under terms of the agreement, Harel and IIF have the option to elect, before closing, to purchase an additional 1 percent working interest from Noble Energy at the same valuation.

Gary W. Willingham, the Company's Executive Vice President of Operations, commented, 'This transaction reflects the inherent value of our producing Tamar asset, which reliably fuels more than half of Israel's electricity generation today. It also highlights the potential of our other undeveloped Levant Basin discoveries, which share similar reservoir and well deliverability characteristics and are poised to bring needed energy to a region which is fundamentally short natural gas. We are excited about partnering with Harel and IIF, which bring additional leading Israeli investors into the project. These proceeds further bolster our balance sheet in the near-term and will contribute to our upcoming capital investments in Israel, including our initial investment in the Leviathan project.'

Noble Energy and partners are planning to drill and complete an additional development well at the Tamar field in response to the continued increasing demand and outlook for natural gas usage within Israel, as Israel displaces coal for clean-burning natural gas. Drilling is anticipated to commence in the fourth quarter of 2016. The additional producing well will further enhance redundancy while meeting maximum deliverability for extended peak demand periods. There is no material change to the Company's overall 2016 capital program.

Prior to the announced working interest sale, Noble Energy operated the Tamar field with a 36 percent working interest. The Company is carrying out an 11 percent sell-down of its interest in the Tamar field in accordance with Israel's approved Natural Gas Regulatory Framework. Noble Energy anticipates the sale of the remaining 7 to 8 percent working interest over the next 36 months. Following completion of this sell-down process, Noble Energy will retain a 25 percent working interest and operatorship in the Tamar field, which has recoverable gross mean natural gas resources of 10 trillion cubic feet (Tcf).

The Tamar field sold 252 million cubic feet per day, net, of natural gas and generated net pre-tax income of $318 million for Noble Energy in 2015.

Noble Energy also operates the Leviathan field, offshore Israel, with a 39.66 percent working interest and the Aphrodite field, offshore Cyprus, with a 35 percent working interest. The Leviathan field has an estimated 22 Tcf of recoverable gross natural gas resources, while Aphrodite holds an estimated 4 Tcf of recoverable gross natural gas resources.

http://www.oilvoice.com/n/Noble-Energy-sells-3-interest-in-Tamar-field-for-369-million/9dd5b2f258e4.aspx?utm_source=twitterfeed&utm_medium=twitter&utm_campaign=Feed%3A+OilvoiceHeadlines+%28OilVoice+Headlines%29

As oil prices began recovering from 13-year lows early this year, U.S. shale producers ramped up their hedges against another slump on a scale unseen for at least a year, a Reuters analysis of company disclosures shows.

A review of disclosures by the largest 30 U.S. shale firms showed 17 of them increased their hedge books in the first quarter, the most at least since early 2015.

Several, including EOG Resources Inc and Devon Energy Corp, two of the biggest shale companies, secured significant protection of future earnings for the first time in at least six months.

A greater volume of hedged production typically indicates more drilling activity ahead as producers that locked in prices for a sizeable part of their output ensure enough cash flow to sustain or increase production.

What makes the outlook more complicated this time is the fact that oil companies, fearing the rally could fizzle, locked in sales at levels around $10 a barrel below both current prices and break even levels for some producers.

For those producers the concern is that their margins will suffer if service costs rise as activity picks up.

It is less clear how it will affect production, though most analysts expect more supply.

Michael Cohen, head of energy commodities research at Barclays in New York, believes hedges allow producers to plan better even if they secured prices below present levels just below $50 a barrel.

"I think (the hedging) gives producers more security to lock in a capex plan," Cohen said, predicting shale production will edge up in the second half of the year.

The 17 companies locked in prices for nearly 55 million barrels of future production, the highest volume in at least a year and some 45 percent more than hedges added by eight companies in the fourth quarter.

The spike in hedging came as crude recovered from February's 13-year lows around $26 a barrel CLc1 later in the first quarter, a rally that continued into the second quarter.

That recovery stalled, however, in the final weeks of last month amid heightened uncertainty about the impact of Britain's vote to leave the European Union and crude prices slipped back below $50 a barrel. (Graphic: tmsnrt.rs/1MiNzFx)

FIRST QUARTER BORROWING

Sometime in the first quarter, Marathon Oil Corp (MRO.N), for example, hedged at an average price of $39.25 for the second quarter, when prices averaged just below $46 a barrel. Denbury Resources Inc (DNR.N) locked in first-quarter 2017 U.S. crude production at just over $42 a barrel; those futures CLF7 this week were trading at about $52 a barrel.

While those deals may look problematic now, analysts point out that they did make more sense three or four months ago.

Michael Tran, director of commodity strategy at RBC Capital Markets in New York, said that at the time market players had expected oil prices to average at or below $40 this year.

"You have to remember that sentiment in this market is still so fragile," he said. "Producers ended up locking in something in case we did a double dip."

For those that have enough money, the hedges may now act as an incentive to crank up production for the spot market to average up how much they fetch per barrel, said John Saucer, vice president of research and analysis at Mobius Risk Group in Houston.

For a number of oil producers hedges were more of a necessity than a strategic choice as they needed them to get bank loans, said Thomas McNulty, a director at consultancy Navigant, who advises producers on valuation, transactions and risk management such a hedging.

"Banks have been working very hard with their clients to continue or extend financing, and that requires producers to hedge more," McNulty said, adding that he saw limited appetite for hedging that went beyond what banks required.

http://www.reuters.com/article/us-usa-oil-hedging-idUSKCN0ZL0OA

Saudi petrochemicals producers are looking for mergers and acquisitions to secure scale and raw materials as part of an efficiency drive to adjust their businesses to lower oil prices.

The industry has developed substantially since the 1970s, fuelled by cheap gas feedstock provided by the Saudi government. Saudi Basic Industries Corp (SABIC), the kingdom's biggest petchems firm, is the world's fourth-largest by sales behind German BASF and Bayer and U.S. Dow Chemical.

But a government decision in December to raise feedstock prices, has forced petchem firms to reconsider their business models, already hit by lower product prices due to cheap crude.

Saudi companies have already invested abroad with SABIC signing a coal to chemicals project in China. Another reaction has been consideration of potential mergers and acquisitions.

"We made a commitment at SABIC to improve our efficiency to absorb the additional cost for the feedstock and we will do that, but we still look for any other options that can position SABIC competitively for investment through acquisitions," the company's acting CEO Yousef al-Benyan, told Reuters.

The acquisitions route could create a number of benefits, including increased scale for businesses to drive efficiencies, sourcing raw materials, and expanding into new product ranges.

Petrochemicals are the second-largest contributor to Saudi's economy at 7-10 percent of GDP and has the potential to be a significant part of the kingdom's Vision 2030 economic plan.

"The way forward is to crack naphtha or to grow outside, and me and everybody are looking outside. By increasing gas prices, the opposite will happen, it is definitely not going to encourage investors to go further downstream," Mutlaq al-Morished, chief executive of National Industrialization Co (Tasnee) said.

INEFFICIENCIES

It is the increase in feedstock prices that has jolted the Saudi petchems industry into action, as previously they could enjoy much improved margins thanks to subsidies.

Remove the subsidies -- the Saudi government has pledged to phase out "support" over the next five years -- and high-priced oil and Saudi is competing on a level playing field.

"What is alarming in the Saudi petrochemical industry is its obsolete fixed assets and inefficiency, where large numbers of plants today are more than 20-30 years old and do not match parameters of fuel consumption and need to be replaced," said Mohammed Alomran, a member of the Saudi Economic Association.

Most Saudi petchem firms are now undertaking restructuring programmes to slash costs -- Tasnee said it has cut 2,000 jobs, while SABIC is reviewing some of its investments.

It could help to switch to a more effective feedstock, but this is being inhibited by Saudi's shortage of gas.

"I think the Saudi petchem industry is more constrained by new gas allocations than by price," said Sanjay Sharma vice President - Middle East and India at IHS Chemical Consulting.

Aramco plans to double gas output in a decade but it is unclear just how much will go to petrochemicals.

One alternative is deriving petrochemicals directly from crude oil, with Aramco and SABIC announcing this week they were study building an oil-to-chemicals (OTC) venture.

OTC will open up a number of new downstream product lines to Saudi producers, which fits with the kingdom's strategic goals of creating more higher-value products.

But the technology is still developmental and there are question marks over how it would work commercially, Sadad al-Husseini, a former top executive of Aramco, says.

Therefore, perhaps the most promising short-term solution would be to go down the M&A route for more feedstock supply.

Aramco has indicated it would seek opportunities in global upstream gas, while SABIC has said in May it would look to North America for gas to fuel growth.

However, it is unlikely to result in M&A within the Saudi sector due to cumbersome rules on combining listed companies.

http://www.reuters.com/article/saudi-petchems-idUSL5N18M2V6

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Attached Files

Chevron Corp., Exxon Mobil Corp. and their partners on Tuesday committed to a $36.8 billion oil expansion project in Kazakhstan—the biggest investment in new barrels since oil prices collapsed two years ago.

The investment in the expansion of the field known as Tengiz—one of the world’s largest—comes on top of around $37 billion already spent by Chevron, the operator, and its partners: state-owned energy firm KazMunaiGas, Exxon and Russia’s Lukoil.

“This project builds on the successes of prior expansions at Tengiz and is ready to move forward,” said Jay Johnson, Chevron’s executive vice president in charge of upstream.

“It has undergone extensive engineering and construction planning reviews and is well-timed to take advantage of lower costs of oil industry goods and services,” he said in a statement.

The $36.8 billion includes $27.1 billion for facilities, $3.5 billion for wells and $6.2 billion for contingencies. It will take Tengiz production up to 1 million barrels of oil equivalent a day from around 800,000 barrels of oil equivalent a day currently. First production from the expansion is due in 2022.

Tengiz is one of the most profitable fields in the history of the modern oil era. Some analysts estimate that it has brought Chevron more than $70 billion in revenue, and $40 billion in profits, since 1993, when the U.S. company became the first foreign oil company to strike a deal with the former Soviet republic.

The decision, which has been on hold since last year, is a signal of the industry’s growing confidence that oil prices have stabilized and are set to move higher. Oil prices collapsed from around $115 a barrel in mid-2014 to a low of $27 in January, but have hovered near $50 a barrel in recent weeks.

http://www.wsj.com/articles/chevron-exxon-commit-to-36-8-billion-expansion-project-in-tengiz-1467709203

Oil prices won’t rise much further over the next year and a half as demand growth slows and refiners comfortably meet gasoline consumption, according to the world’s largest independent oil-trading house.

"I cannot see the market really roaring ahead," Vitol Group of Cos. Chief Executive Officer Ian Taylor told Bloomberg Television in an interview. "We have a lot of oil in the system and it will take us considerable time to work that off."

Since rallying from a 12-year low of $27.10 a barrel in January, Brent crude has been hovering around $50 a barrel for the last month. The international benchmark will probably end the year “not too far away from where we are today" and rise to about $60 by the end of 2017, Taylor said.

The forecast, which coincides with a similar view from Goldman Sachs Group Inc., would mean oil-rich countries and the energy industry face a prolonged period of low prices, more akin to the 1986 to 1999 downturn than the swift recovery after the 2008 financial crisis. Vitol trades more than 6 million barrels a day of crude and refined products -- enough to cover the needs of Germany, France, Italy and Spain together -- and its views are closely followed in the energy market.

Taylor, who has traded oil for nearly four decades, said one-off factors, including supply disruptions and stronger-than-expected demand growth, helped to tighten the market in the first half, lifting prices.

Demand Growth

"We probably expect demand growth to be slightly less in the second half of the year," he said. "There is a little less pull from the Far East” and basic Chinese refineries, known as teapots, seem well satisfied after having “overbought” crude in the first months of the year, he said.

The summer driving in the U.S. may not be so bullish for oil because "the refinery system of the world has clearly been able to make enough gasoline, and the gasoline stocks are healthy,” Taylor said.

U.S. wholesale gasoline futures for August delivery -- traditionally the peak of the driving season -- traded at $1.50 a gallon in New York at 12:01 p.m. Monday, below the price for futures to delivery in September, suggesting current supplies are plentiful. "We don’t see any shortages of gasoline," Taylor said.

Supply Disruptions

At the same time, "most of the disruptions are beginning to correct themselves," such as wildfires that halted Canadian output, Taylor said.

The oil price outlook is unlikely to change significantly in 2017 as supply from new oilfields, including the super-giant Kashagan in Kazakhstan and others in the U.S. Gulf of Mexico, offset production drops elsewhere, Taylor said. The wild card for next year is U.S. shale supply, which appears to have reached a bottom, but it’s too early to say whether growth will resume.

U.S. oil production was hit hard by the plunge in oil prices after the Organization of Petroleum Exporting Countries diverged from its traditional policy of adjusting supply to manage prices, announcing in late 2014 that it would maintain output to defend its position in the market. The nation pumped 8.6 million barrels a day last month, down from a peak of 9.6 million in June 2015.

Vitol, which celebrates its 50th anniversary this year and is owned by its employees, didn’t made as much money in the first half of the year as in the same period in 2015, Taylor said. It earned $1.6 billion last year, the most since 2011, as it profited from price swings in the energy market.

http://www.bloomberg.com/news/articles/2016-07-05/world-s-top-oil-trader-says-prices-won-t-rise-much-further

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Petrobras' plans to sell 'junk' oil fields off the coast of Brazil's Sergipe and Ceara states will do little to boost the economic prospects of the regions, hampered by company cutbacks and delays at larger discoveries nearby, sources said on Monday.

Brazil's state-owned oil company on Monday said it plans to sell nine shallow-water oil fields that produce a total of 13,000 barrels of oil and equivalent natural gas a day from multiple wells.

Furthermore, the sale of the fields, among Brazil's oldest, will not significantly cut the debt of Petroleo Brasileiro SA as the company is formally known, the sources said. Petrobras' $126 billion of debt is the largest in the world oil industry.

Not only do the fields produce very little oil or natural gas compared to other Petrobras assets, the sources said, their age will require substantial investment to maintain commercially viable output, a situation made more difficult by oil prices near decade lows.

Additionally, the ageing wells come with large future costs for safe closure under environmental and other laws.

"The fields are junk," one of the sources said. "Unless Petrobras shoulders the labor-related costs of selling the fields and laying off workers and some of the shut-in costs that will come sooner rather than later, the fields offer little upside even though almost anybody can run them cheaper than Petrobras."

The sources, who asked for anonymity because their dealings with Petrobras are confidential, have either direct knowledge of the fields up for sale or were briefed on the proposed sale on Monday by Petrobras chief executive Pedro Parente.

Petrobras announced the sale hours after Parente met with Sergipe officials to explain the company's cutbacks at low-output onshore fields in the state.

He also addressed repeated delays in developing giant offshore discoveries it owns with Indian companies Oil and Natural Gas Corp and IBV Brasil Ltda, a 50-50 joint venture between Bharat Petroleum Corp and Videocon Industries Ltd, a source at the briefing said.

Earlier on Monday, Reuters reported that Petrobras told IBV in April that oil output at the Sergipe offshore areas would be delayed until 2022, four year later than promised. The Indian partners have invested $2.1 billion in the giant deepwater fields near the state.

The prospects owned by Petrobras and the Indians dwarf the rapidly declining Sergipe onshore and shallow water fields and are among the world's largest discoveries in decades. Sergipe gets about a quarter of its industrial output from Petrobras.

"We're stuck," one of the sources said. "Petrobras is cutting crucial investment and thousands of jobs in Sergipe and can't or won't invest in new discoveries that could transform people's lives here. The shallow water sales, even if they happen, won't help much."

Parente has promised to sell or slash investment and sell assets in underproducing areas to focus the company's limited cash on the so-called "subsalt" region near Rio de Janeiro. Some single wells in the subsalt produce 40,000 barrels a day, among the highest levels ever seen in offshore development.

http://www.reuters.com/article/us-petrobras-assets-idUSKCN0ZL0HG

Calgary,Alberta-based oil and gas major Gran Tierra Energy has launched a $525-million bid to acquire independent exploration and production company PetroLatina Energy, marking the company’s third multi-million dollar push this year into Colombia.

Under terms of the acquisition agreement,Gran Tierra would make an initial $500-million cash payment at closing, and a deferred payment of $25-million before December 31.

"The acquisition represents a unique material opportunity inColombia in terms of scale and upside potential, and will add a new core area for Gran Tierra in the prolific MiddleMagdalena Basin. The combination of Gran Tierra's strong, positive cash-flowing asset base and PetroLatina's attractive portfolio of development opportunities will create a premierColombia-focused exploration and production company,”Gran Tierra president and CEO Gary Guidry stated.

Gran Tierra advised that the acquisition was expected to be funded through a combination of the comany’s current cash balance, available borrowings under existing credit facilities, a new $130-million debt facility, and a private placement of up to $173.5-million of subscription receipts priced at $3 each. Each receipt would entitle the holder thereof to one share of common stock in the capital of the corporation. The pricing reflected a 7.9% discount from the five-day volume weighted average price of $3.26 a share.

Guidry pointed out that Gran Tierra was acquiring significant proved, probable and possible reserves in a new core area in the Middle Magdalena basin, which he expected to enhance the company’s long-term growth strategy and to be a fit withGran Tierra's current reserves and resources base in the Putumayo basin.

The transaction was expected to provide Gran Tierra with a significant growth platform in the Middle Magdalena basinwith significant proved plus probable (2P) reserves additions of 53-million barrels (100% oil), increasing Gran Tierra's pro forma December 31, 2015 2P reserves by 70% to 129-million barrels of oil equivalent.

The PetroLatina deal was expected to close by October 31.

Earlier this year, Gran Tierra completed the acquisitions ofPetroamerica Oil Corp and PetroGrenada as part of its corporate strategy to expand and diversify Gran Tierra's oil and gas growth portfolio in Colombia.

In May, the company increased its 2016 capital budget by between $33-million and $43-million to a range of $140-million to $150-million, from the previously budgeted $107-million.

Despite the TSX-listed stock being down as much as 5.5% on Monday at C$4.12 apiece, the stock had gained more than 41% since the start of the year, buoyed by more optimistic crude oil prices.

http://www.miningweekly.com/article/gran-terra-launches-525m-bid-for-third-colombian-acquisition-this-year-2016-07-04

Nigerian President Muhammadu Buhari has replaced Oil Minister Emmanuel Ibe Kachikwu as group managing director of state oil company NNPC as part of a wider board overhaul.

Oil accounts for about 70 percent of Nigeria' revenue, but the OPEC member has been hit hard by a prolonged drop in crude prices that has caused the deepest crisis in Africa's biggest economy for more than a decade.

Dr Maikanti Kacalla Baru, previously group executive director for exploration and production, will take the reins from Kachikwu, who will remain on the board as chairman, the president's spokesman said on Monday.

Buhari, elected last year, has accused the previous administration of failing to save when crude oil cost more than $100 a barrel. In 2013 the central bank governor said that tens of billions of dollars in oil revenue had failed to make it into state coffers, which the company denied.

Kachikwu was appointed minister of state for oil last year, making him a junior minister, while Buhari kept the petroleum minister portfolio for himself in order to oversee energy sector reforms.

Baru's previous roles at the state oil company included a six year stint, from 1993 to 1999, as an executive at the National Petroleum Investment Management Services (NAPIMS), an NNPC subsidiary, where he worked on gas-related projects.

"President Buhari urges the new board to ensure the successful delivery of the mandate of NNPC and serve the nation by upholding the public trust placed on them in managing this critical national asset," said Buhari's spokesman Femi Adesina.

The president's chief of staff, Abba Kyari, joins the new board, which replaces the one dissolved by Buhari in June last year.

"Reconstituting the board appears to be an attempt to adopt a different approach with a sense of proper oversight and accountability," said Antony Goldman, head of Nigeria-focused PM Consulting.

"The issue in the past has been that NNPC has been involved in deals that benefited certain individuals but not Nigeria as a whole," he added.

Kachikwu, a former Exxon Mobil executive, was brought in by Buhari as head of NNPC last August and was named as minister of state for oil when his cabinet was appointed a few months later.

Rolake Akinkugbe, head of energy and natural resources at FBN Capital, said there was "always a question around how you could have the head of the national oil company who was also the oil minister".

"Being moved to chairman, where he will not be involved in day-to-day operations but retains strategic input, helps to resolve that issue," she said.

http://www.reuters.com/article/nigeria-oil-idUSL8N19Q3QS

French oil major Total has moved the head of its refining and chemicals arm to run its newly created gas, renewables and power division as the group strives to become a leading renewables and electricity player within 20 years.

The appointment of Philippe Sauquet to oversee Total's expansion in renewables makes room for Bernard Pinatel to return to the company as president of the refining and chemicals arm.

Pinatel returns from Bostik, a former Total subsidiary that was sold to Arkema. He was a member of Total's refining and chemicals management committee from 2012 to 2014.

Pinatel will join Total's executive committee, as will Namita Shah, who was appointed executive vice president and will take charge of Total's human resources division and oversee the newly created Total Global Service.

The new appointments will take effect from Sept. 1.

http://www.reuters.com/article/france-total-organisation-idUSL8N19Q3Y3

Colombian state-oil player Ecopetrol has taken over operations at the large light oil and gas condensate field Cusiana after ending a long-term contract with partners Equion Energy and Emerald.

http://www.upstreamonline.com/live/1437727/ecopetrol-takes-over-cusiana-operation?utm_source=twitterfeed&utm_medium=twitter

Gulf Keystone, struggling oil explorer told the market it had defaulted on its $26m April debt payment, but remains in crunch talks with its lenders.

After Gulf Keystone failed to pay its April debt coupon its bondholders granted repeated extensions to its stay of execution. The oil producer has technically been in default since May but it has used a ‘stand-still’ period to shield itself from insolvency proceedings while it negotiates a rescue deal with its lenders.

The freeze agreement expired on Friday evening and the company said it would not extend the stand-still period, or make the outstanding debt coupon payment, raising speculation that a deal with its lenders may be imminent.

Gulf Keystone said its “restructuring discussions remain ongoing” with the bondholders and a further announcement would be made in due course, but a company spokesman declined to comment further.

A deal to restructure its debt is expected to deliver a heavy blow to existing Gulf Keystone shareholders, who have already seen the stock plummet from 410p in early 2012. The company has been hit hard by the oil market crash and geopolitical tensions in the Iraqi region, which have crimped oil payments from the local government.

In addition to April’s $26m debt coupon Gulf Keystone is due to make another $26m payment in October before repayments rocket to $250m in April 2017 and $325m in October next year.

http://www.telegraph.co.uk/business/2016/07/04/gulf-keystone-shares-rocked-by-debt-default/

Two oil workers working for Italian major Eni were killed after their boat came under fire in the Niger Delta last week, it has emerged.

The men were travelling in what is believed to have been a workboat in Bayelsa State when they came under fire some time on Wednesday.

A spokesman for Eni told Upstream that the team from local subsidiary Agip was on its way to a well location to carry out a routine operation in the Nembe area when it was attacked.

“Three members of the team managed to escape, reaching the near flow station, while another two were missing.

“Two days later their bodies were found. Investigations with security agencies were immediately undertaken and are still ongoing.”

One source said the workers were on their way to the Obiama flow station when they were attacked around Okoroma waterway. The source added that the boat may have had no escort, which is not advisable in the locality.

Some local reports have linked the Niger Delta Avengers (NDA) with the attack, although this would be a significant departure from their current modus operandi of attacking oil infrastructure such as wells and pipelines, while refraining from killings.

The NDA has routinely claimed attacks through posts on its internet page or Twitter. However, the militant group’s Twitter account was disabled on Monday morning, but not before it used it to claim five attacks on infrastructure belonging to Chevron, Nigerian National Petroleum Corporation (NNPC) and Nigerian Production Development Company (NPDC) between Friday and Sunday.

Attacks on oil companies this year has spiked in Nigeria’s oil-producing region due in some measure to political tensions and the continued low oil price. Information from Norwegian risk analysis firm Bergen Risk Solutions shows that there have been 65 incidents in the Niger Delta so far this year involving international oil players, compared with 42 for the whole of 2015.

http://www.upstreamonline.com/live/1437695/two-eni-workers-killed-in-niger-delta-attack

Lebanon may soon approve measures to push ahead with a stalled first auction of offshore oil and natural gas rights, ending years of political wrangling as it tries to catch up in a regional race to tap energy wealth in the eastern Mediterranean.

The auction first scheduled for November 2013 was frozen by the government’s failure to pass decrees to demarcate energy blocks, establish production-sharing contracts and specify tender protocols. Mohammad Kabbani, head of the parliamentary energy committee, said Monday that he expected the decrees to be approved “a short period” after the Muslim holidays of Eid al-Fitr this week.

“This would be the first serious step in three years,” Kabbani said in a phone interview in Beirut, without elaborating on the possible timing of an approval. “We should hurry up to be present in the market before it is too late.”

Lebanon has lagged behind neighboring Israel, Cyprus and Egypt in developing oil and gas deposits that may lie beneath its share of the Mediterranean Sea. Seismic surveys show the country could hold at least 96 trillion cubic feet of gas and 850 million barrels of oil, then-Energy Minister Gebran Bassil said in a December 2013 interview. Exxon Mobil Corp. and Total SA are among 46 companies pre-qualified to bid to explore off the country’s coast.

Lebanon has had no president for more than two years, and government institutions have been paralyzed by political divisions and sporadic violence that have deepened since the war in Syria erupted in 2011. Lebanon needs revenue to trim its public debt, the highest as a share of annual economic output among 22 Arab nations.

A breakthrough to enable the energy auction looks close, partly because a dispute has been settled over which of 10 blocks should be awarded, Kabbani said. Companies will be allowed to bid for the blocks they want, and the government will then approve two or three, he said.

The possibility that Lebanon shares offshore gas reserves with Israel adds urgency to the effort, Kabbani said. Turkey and Israel ended years of diplomatic estrangement in June, opening the way for Israel to export fuel to the Turks from its offshore Leviathan field. “We have to prove we are here and we are serious,” Kabbani said.

http://www.bloomberg.com/news/articles/2016-07-04/new-rival-seen-in-mediterranean-gas-race-before-it-s-too-late

India’s burgeoning demand for liquefied natural gas is dictating how many tankers make it to Europe, the world’s dumping ground for the fuel.

LNG imports to India jumped 43 percent in May from a year earlier, a contrast to western Europe where shipments have stagnated over the past three months. The world’s second-most populous nation is expected to double its LNG intake over the next four years, according to energy consultants Wood Mackenzie Ltd.

India overtook South Korea as the second-biggest buyer of spot and short-term LNG cargoes after prices crashed about 65 percent in almost two years, spurring demand for the cleaner fuel from fertilizer producers to power plants. For a supplier, having a closer market helps. It takes three days to ship LNG to western India from Qatar, the biggest producer of the fuel, compared with two weeks to get it to the U.K. where prices are lower.

“India needs to be full before you start getting LNG imports in Europe going up,” Noel Tomnay, vice president of global gas and LNG research at Wood Mackenzie, said in an interview in London. “We haven’t seen a significant uptick in European LNG imports yet. What we have seen is a significant uptick in India.”

The nation gets the fuel from Qatar at about $5 per million British thermal units, according to Petronet LNG Ltd., India’s biggest importer. That compares with $4.37 on average at Britain’s National Balancing Point trading hub in the second quarter, data from the ICE Futures Europe exchange in London show.

“The NBP is below the western Indian market price, and that should gravitate the spot cargoes toward India,” Prabhat Singh, the chief executive officer of Petronet, said in an interview in New Delhi on June 30. “India is the place for world LNG to come if we handle the market well.”

Import Surge

India’s imports of cargoes under contracts with duration of four years or less rose 45 percent to 9.7 million tons in 2015, according to the International Group of LNG Importers. The country imported 14.6 million tons of LNG last year, little changed from a year earlier, according to the group.

In May, the nation purchased a total of 2.08 billion cubic meters of LNG, or 1.57 million tons, according to provisional data from the Oil Ministry’s Petroleum Planning & Analysis Cell. That compares with 3 billion cubic meters imported into western Europe, a figure that’s slated to fall to 1.25 billion cubic meters in June, according to consultants Energy Aspects Ltd.

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Western Europe is poised to take a bigger share of LNG imports “over the coming quarters” thanks to the region’s liquid trading hubs capable of absorbing excess LNG from the global markets, according to Fitch Ratings Ltd.’s BMI Research unit. Global supply is set to soar from the second half of this year as plants from the U.S. to Australia and Angola increase production, pressuring prices, BMI said in a June 30 research note.

Stretched Infrastructure

Increased deliveries have stretched India’s existing infrastructure. The Dahej terminal this year is running at an estimated 111 percent of its designed nameplate capacity and will be operating at 120 percent over the next six months, according to Petronet, which operates the facility. The company plans to complete an expansion of the terminal by September.

India’s LNG price is forecast to fall to $4.8 per million Btu on average this year and $4.6 in 2017, down from $7.5 last year, according to Energy Aspects.

“We have seen demand elasticity in India and it’s starting to stretch regas capacity,” said WoodMac’s Tomnay. “It is interesting to see how tested India will be as Asia’s natural sink.”

http://www.bloomberg.com/news/articles/2016-07-04/india-demand-surge-sucks-up-lng-otherwise-destined-for-europe

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Indian Oil Corp. will spend about 400 billion rupees ($6 billion) to boost capacity by almost 30 percent in the next six years to feed the booming fuel demand in the world’s second-most populous nation.

“Fuel demand is rising and India’s excess capacity is very small,” Sanjiv Singh, director of refineries at India’s biggest processor, said in an interview Friday. “We all need to expand if demand sustains.”

The expansion comes as Indian refiners are racing to add capacity amid rising fuel consumption. India is poised to surpass Japan as the world’s third-largest oil user this year and will be the fastest-growing crude consumer in the world through 2040, Paris-based International Energy Agency estimates.

The state-run company aims to increase its capacity to about 104 million metric tons a year, or about 2 million barrels per day, over the next six years by expanding the existing refineries across the country, said Singh.

Indian Oil currently can process 80.7 million tons of crude a year from its nine plants and two owned by its unit Chennai Petroleum Corp., accounting for 35 percent of the nation’s total, according to its website.

India’s oil demand is forecast to reach 329 million tons by 2030, according to IEA. The country’s 23 refineries have a total capacity of 230 million tons a year, while total fuel demand was 183.5 million tons during the financial year that ended March 31, according to the oil ministry.

Adding Capacity

“In another 15 years, India should be adding another 100 million ton refining capacity,” Singh said. “By 2030, India would easily cross as much as 340 million-ton capacity.”

Separately, Indian Oil is working with the government as well as other refiners to build a 60-million-ton-a-year refinery on the west coast. The proposed project, which would include petrochemical units, may cost about 2 trillion rupees, Singh said.

They will build the refinery in two phases, with two crude units totaling 40 million tons in the first phase and a third one in the second phase, he said. “After getting possession of the land, it will take five to six years to complete the first phase,” he said.

http://www.bloomberg.com/news/articles/2016-07-04/top-indian-refiner-plans-6-billion-expansion-as-demand-climbs

Hedge funds and other money managers are betting diesel and heating oil will take over from gasoline as the main driver of U.S. refinery profitability in the second half of the year.

For the past 18 months, refiners have been rewarded for maximising output of gasoline and minimising production of diesel, but that could all be about to change.

By the middle of June, hedge funds had accumulated the largest net long position in heating oil futures and options since oil prices began to slump in July 2014.

At the same time, hedge funds were running one of the smallest net long positions in gasoline contracts in the past decade.

The most recent data published by the U.S. Commodity Futures Trading Commission shows some profit-taking on these positions in the week to June 28.

But the strongly bullish position on heating oil and bearish position on gasoline remains fundamentally intact for the time being.

At the start of the year, hedge funds were bearish towards heating oil and bullish on gasoline, but the position began to switch from March onwards.

The switch in hedge fund positions has coincided with a marked strengthening in the refining margins for diesel and weakening of those for gasoline.

The gross refining margin for diesel for October is now 35 cents per gallon compared with just 23 cents per gallon for gasoline (tmsnrt.rs/29dQLpE).

Despite record consumption of gasoline, refiners have struggled to work down the excess stockpiles that built up in January and February.

Gasoline stocks remain close to the highest level for a decade even after adjusting for current record rate of demand(tmsnrt.rs/29hyyLk).

Gasoline stocks are currently equal to 24.6 days worth of consumption, down from 29.2 days at the end of January, but still well above the 22.7 days at this point last year and the 10-year average of 22.9 days.

By contrast, the enormous overhang of diesel stocks that built up at the start of the year has been steadily reduced over the last two months (tmsnrt.rs/29hzejA).

Diesel stocks have dropped from almost 50 days worth of consumption at the turn of the year to 39.3 days although they are still well above the 34.5 days this time last year and the 10-year average of 31.9 days.

During the summer driving season, gasoline stocks normally fall while diesel stocks rise, as refiners run hard to produce motor fuel and find themselves with too much distillate as a by-product.

But this year gasoline stocks show little signs of reducing while diesel stocks are exhibiting an unusual seasonal decline.

Counter-seasonal stock movements suggest the U.S. market is on course to have surplus gasoline and not enough distillate once the summer driving season is over. Margins are adjusting accordingly.

Hedge funds and futures prices are also anticipating stronger demand for diesel during the winter of 2016/17 after unusually weak demand over the winter of 2015/16.

El Nino, which contributed to an unusually warm winter in parts of North America during 2015/16, is now giving way to La Nina.

The unusually warm winter temperatures experienced last winter are unlikely to be repeated in the coming winter which should increase consumption of heating oil.

Diesel demand should also get a boost from an eventual recovery in the freight market, provided the U.S. and global economies manage to avoid recession.

Freight remains sluggish, but U.S. manufacturers, distributors and retailers do at last seem to be starting to get a grip on excess inventories, which could herald an eventual improvement.

The realignment of gasoline and diesel margins seems to have a solid grounding in supply-demand-stocks fundamentals.

The big problem is the large concentration of hedge fund positions, which makes the market vulnerable if they all attempt to unwind at the same time.

With hedge funds already so bearish on gasoline and bullish on heating oil, and margins already having moved significantly, the risk now is that margins will recoil as the funds try to take some profits.

Profit-taking already seems to have started in the final week of June but could still have some way to run.

http://www.reuters.com/article/usa-gasoline-kemp-idUSL8N19Q1IQ

World’s largest liquefied natural gas producer, Qatargas has expanded its European client portfolio by signing a seven-year sales and purchase agreement with German utility RWE Supply & Trading.

According to Qatargas’ statement, it has agreed o deliver 1.1 million tons of LNG per year, supplied from the Qatargas 3, the joint venture between Qatar Petroleum, ConocoPhillips and Mitsui & Co.

Khalid Bin Khalifa Al-Thani, chief executive officer of Qatargas noted that the company is working to expand its European client portfolio.

With the emerging export volumes from the United States and Australia, Qatar is looking to reinforce its position as the leading supplier of liquefied natural gas.

It was reported in March that Qatargas is looking to expand LNG supply deals with Uk and Dutch terminals.

However, it is not only the European market that Qatargas is adding new supply deals in. On June 30, the company signed a 20-year contract with Global Energy Infrastructure (GEIL) of Pakistan for the supply of 1.3 mtpa of LNG per year.

Andree Stracke, chief commercial officer at RWEST noted that the deal with Qatargas adds to the diversity of the company’s European gas portfolio.

http://www.lngworldnews.com/qatargas-rwe-in-lng-supply-deal/

Shale drillers brought back the most oil rigs of any week this year as confidence in a stabilized market is prompting talk of expansion throughout 2016.

Rigs targeting crude in the U.S. rose by 11 to 341, after 7 were dropped last week, Baker Hughes Inc. said on its website Friday. It’s the fourth time in the past five weeks that producers have added oil rigs. Explorers in the Permian Basin of West Texas, the nation’s busiest oil patch, again led the activity climb by adding 4 for a total of 154 oil rigs working in the region.

"You’re seeing rig counts added in the right places, like the Permian," Luke Lemoine, an analyst at Capital One Southcoast in New Orleans, said in a phone interview. "There have been a lot of cuts in the industry, so a lot of wounds to heal. It’s understandable that the first steps would be small."

Supply disruptions and falling U.S. output have helped cut a global surplus, with both the International Energy Agency and theOrganization of Petroleum Exporting Countries forecasting that the market is heading toward balance as demand growth outpaces supply.

"With oil prices approaching $50 per barrel for WTI as supply and demand move into balance, operational visibility is beginning to improve," Patrick Schorn, president of operations at Schlumberger Ltd., told investors last week at the Wells Fargo West Coast Energy Conference in San Francisco. "The rig count is now expected to increase on land during the next two quarters."

http://www.bloomberg.com/news/articles/2016-07-01/u-s-drillers-boost-activity-as-oil-market-seen-stabilizing

---

Attached Files

Once-rival leaders of Libya’s National Oil Corporation (NOC) have agreed on a structure for the group that aims to put to rest squabbles over who has the right to export the country’s oil, according to a statement.

Oil industry leaders in OPEC-member Libya have said they could quickly double production to over 700,000 bpd if conditions stabilized. Before a 2011 revolution, Libya was producing 1.6 million bpd.

The rival oil officials agreed in principle to unify the oil sector in May, but the agreement on the structure and leadership of a joint group took weeks of meetings to iron out. (here)

Mustafa Sanalla, who led the Tripoli-based NOC, will remain chairman of the group, while the head of the eastern-backed NOC, Naji al-Maghrabi, will serve as a board member, according to a statement seen by Reuters.

A UN-backed unity government that arrived in Tripoli in March is seeking to replace two rival governments that were set up in Tripoli and the east, and to unite Libya's many political and armed factions.

A united oil sector would be a key support for the unity government. Libya relies heavily on oil exports as a source of income and hard currency.

“This agreement will send a very strong signal to the Libyan people and to the international community that the Presidency Council is able to deliver consensus and reconciliation,” Sanalla said in the statement.

Al-Maghrabi said both men “made a strategic choice to put our divisions behind us” as there is “no other way forward”.

Oil production sank to around 200,000 bpd in May after a political dispute between the eastern and western factions blocked loadings at Marsa al Hariga for more than three weeks.

A unified NOC structure could also smooth negotiations to reopen the El Sharara and El Feel fields, which are closed due to disagreements with local groups.

The two sides also agreed a budget for the remainder of the year, taking steps to “address any imbalances resulting from the period of division”, they said.

They also identified infrastructure rehabilitation as a big goal, particularly in the eastern city of Benghazi, "in preparation for the relocation of NOC's headquarters".

NOC aims to hold meetings of its board of directors meetings in Benghazi "if security conditions permit”.

The joint NOC will also submit periodic reports to committees established by both the Presidential Council and the House of Representatives, which it recognized as the highest executive and legislative authorities within Libya.

http://www.reuters.com/article/us-libya-energy-idUSKCN0ZI0UB

The Niger Delta Avengers, a militant group that has been carrying out attacks on Nigerian oil facilities in the past few months, claimed responsibility on Sunday for five new attacks in the southern energy hub since Friday.

The group had previously not laid claim to any attacks in the Niger Delta - the source of most of the OPEC member's oil - since June 16.

Petroleum Ministry sources said in late June that a month-long truce had been agreed with militants. But the Avengers said they did not "remember" agreeing to a ceasefire.

Attacks in the Niger Delta have pushed Nigerian crude production to 30-year lows, although the Nigerian National Petroleum Corporation (NNPC) said last week that output was rising because of repairs and a fall-off in attacks.

In messages posted on Twitter in the early hours of Sunday, the Avengers said they had attacked a pipeline connected to the Warri refinery operated by NNPC on Friday night.

They added that they blew up two lines on Saturday night close to Batan flow station in Delta state run by NPDC, a subsidiary of NNPC.

The militants also said two Chevron facilities close to Abiteye flow station, in Delta state, came under attack early on Sunday.

Residents in some of those areas reported hearing blasts.

"All five operations" were carried out by an Avengers "strike team", the group said.

Garba Deen Muhammad, a spokesman for state oil company NNPC, whose managing director is the oil minister, confirmed that the crude facilities identified by the Avengers had been attacked.

"Government will not be deterred in its efforts to find a lasting solution to these attacks," he said.

Chevron spokeswoman Isabel Ordonez said that "as a matter of long-standing policy," the company did not comment on "the safety and security" of its personnel and operations.

The militants say they want a greater share of Nigeria's oil wealth, which accounts for around 70 percent of national income, to be passed on to communities in the impoverished region and for areas blighted by oil spills to be cleaned up.

On Thursday, President Muhammadu Buhari hosted a group of community leaders from the Delta and urged them to pacify people in the restive region where anger is widespread.

Eric Omare, of the Ijaw Youth Council (IYC), which represents the Delta's biggest ethnic group, said the "resumption" of attacks was "worrisome", adding that the government had failed to build on goodwill generated by the oil minister's visit to the region in June.

"The federal government has not taken any practical step toward resolving the issues," said Omare, adding that the IYC urged the Avengers not to carry out further attacks in order to "give room for constructive dialogue".

http://www.reuters.com/article/us-nigeria-delta-idUSKCN0ZJ01L

Petrobras has warned its Indian partners in a huge offshore project to not expect oil from the site until 2022, according to sources, a fresh sign of how low oil prices and the state-owned company's corruption scandal and mountain of debt are dragging on Brazil's energy industry.

The previously unreported, four-year delay in the "super-giant" discovery off the northeastern coast of the Brazilian state of Sergipe is forcing India's Oil and Natural Gas Corp and IBV Brasil Petroleo Ltd to seek ways to speed up the Petrobras-led project which has cost them $2.1 billion with no return in sight.

The delay and pressure from the Indian partners is just one of many challenges for new Petrobras Chief Executive Pedro Parente, named by Brazil's interim-President Michel Temer in late May amid an ongoing financial crisis.

In the face of a massive bribery and kickback scandal and Petrobras' $126 billion of debt, Parente has pledged to run the company in a more market-friendly way but has declined to comment on individual projects. He has also promised a revamped investment plan by the end of October - though it is unclear whether it will address the Sergipe offshore standoff.

In April, Petrobras told IBV, a 50-50 joint venture between state-owned Bharat Petroleum Corp and privately held Videocon Industries Inc, that there will be no oil output from Sergipe "until at least 2022," an IBV executive told Reuters. A year ago, Petrobras' promised first oil by 2018.

Hoping to speed up development, IBV told Reuters it has offered to arrange up to $10 billion in loans from Indian and other international development banks to finance the Sergipe development - Brazil's biggest oil prospect outside the prolific subsalt region near Rio de Janeiro where Brazil is pinning hopes of energy independence.

"It's a common and simple loan structure, if Petrobras is willing to provide future output as collateral, it won't have to pay a penny until oil starts flowing, something we could can probably do by 2020," the IBV executive said.

"But we get the feeling that Petrobras has yet to accept its new, more restricted circumstances," the executive added.

Petrobras told Reuters it has yet to receive a formal proposal from its Indian partners to finance the project. Asked about the delays, Petrobras said in a statement it has invested about $3.5 billion on exploration in the Sergipe blocks it owns with ONGC and IBV. It expects to complete a development plan for the areas by 2020 but has no date for the first production of oil.

All development decisions have been made in conjunction with its partners, Petrobras said, and delays have been the result of "considerable" deepwater technical challenges, efforts to reduce costs and a lack of infrastructure to transport the area's natural gas.

After investing $2.1 billion in the offshore finds since 2007, the Indian partners are getting impatient.

"We can't put off a return forever," the IBV executive, whose company has spent $1.6 billion in Sergipe, told Reuters. "We've been investing for nearly a decade. They now say we'll have to wait at least four years more. In our experience with Petrobras, it will probably be longer."

An ONGC executive, who also declined to be named, said the partners hope the new Parente regime will speed up development plans "so that we can monetize and unlock the potential at the earliest."

The company did recently relinquish its stake in one of two proposed production areas in the Sergipe block that it owns a quarter of to partner Petrobras.

SHARED BLAME FOR DELAYS

In nine years, ONGC has invested $500 million exploring with Petrobras off the coast of Sergipe. It has spent another $2 billion elsewhere in Brazil and produces about 12,000 barrels a day in the country, a small amount considering the outlay so far.

The expected prize, though, is Sergipe. The BM-SEAL-11 block, 40 percent controlled by IBV, holds more than 3 billion barrels of oil and equivalent natural gas, enough to supply all the world's petroleum needs for more than a month. There are no public estimates for the two adjacent blocks, one fully owned by Petrobras and the other owned 25 percent by ONGC, but people involved with them say the volumes of oil and gas are very large.

The Sergipe project's problems have also been compounded by IBV and ONGC's own failures. Two sources involved with the Indians in Sergipe exploration said IBV and ONGC often missed deadlines to pay their share of costs, only paying after Petrobras threatened legal action.

The Indians confirmed the delays, which they blamed on partner Videocon, which has cash flow problems and may sell its IBV stake. Videocon executives were not available for comment.

Venugopal Dhoot, chairman of Videocon told the Business Standard Newspaper in June that his company was considering the sale of its oil and gas assets to pay debt.

Both IBV and ONGC also declined to invoke clauses in the blocks' contracts allowing them to move ahead with development on their own if Petrobras demurred.

"Unfortunately, everybody in Brazil is afraid to challenge Petrobras, even if they have a case. They know Petrobras, and perhaps the government, will retaliate," said John Forman, a geologist and former director of Brazil oil regulator ANP. "Court fights can drag on for years, so you lose even if you win."

Whatever the reason for delay, Brazil may be the biggest loser. While ONGC and IBV bought their Sergipe stakes in 2007 from existing leaseholders Petrobras and Encana, Brazil's oil regulator ANP has allowed partner Petrobras to delay a start to production by extending exploration rights in the areas repeatedly.

Had the ANP enforced tighter deadlines, designed to prevent companies from hoarding assets without developing them, Sergipe might be producing, or near first production, today and providing revenue for Brazil's cash-strapped Treasury, Forman said.

The tendency to give Petrobras such wide latitude underlines Brazil's conflicted priorities as it tries to revive both its economy and largest company, he noted.

"In Brazil we say 'the oil is ours', that it belongs to the people. In reality we act like it belongs to Petrobras," he said.

http://www.reuters.com/article/petrobras-offshore-partners-idUSL1N1911RJ

Norwegian offshore oil workers and employers signed a new wage deal on Saturday, avoiding a strike that would have cut the output from western Europe's top oil and gas producer by about six percent, employers and unions said.

Some 755 workers at fields operated by Statoil, ExxonMobil and Engie had threatened to strike if the talks had failed. A conflict would initially have capped Norway's daily oil and natural gas output by 229,000 barrels of oil equivalents.

"We've beaten back all attempts at weakening our terms," Safe union leader Hilde-Marit Rysst told Reuters. "On pay, we got a deal we can live with for this year," she added.

Unions were seeking pay increases in line with other industries while producers wanted workers to refrain from seeking such increases and to accept more flexible work practices, citing still weak oil prices.

In 2012 a 16-day strike among some of Norway's oil workers cut the country's output of crude by about 13 percent and its natural gas production by about 4 percent.

http://www.reuters.com/article/us-norway-oil-strike-agreement-idUSKCN0ZI027

Floating Storage Update

The amount of Iranian oil on floating storage has increased by

1.9 M Barrels

as the Diamond joins the fleet

The Current Amount Of Oil Stored

48.6 M Barrels 

From Windward
 

U.S. gasoline consumption was significantly lower in April than reported at the time, new data published by the Energy Information Administration on Thursday show.

Gasoline supplied to the domestic market averaged 9.213 million barrels per day (bpd) during April according to an estimate included in “Petroleum Supply Monthly” published on June 30 (tmsnrt.rs/297g3p8).

Gasoline supplied was significantly lower than the four-week average of 9.474 million bpd contained in the final “Weekly Petroleum Status Report” for April published on May 4 (tmsnrt.rs/297q5L8).

The downward revision in estimated consumption has encouraged analysts to reassess the strength of gasoline demand in the world’s largest driving market.

Strong demand for gasoline in the United States, as well as emerging markets including India and China, has been cited as the main reason for strong growth in oil consumption in 2016.

Strong gasoline demand underpins the argument for oil market rebalancing so anything that triggers a re-evaluation has important implications for the wider oil market.

But the most reasonable interpretation of the data suggests that gasoline consumption was slightly understated in April after being overstated in March, while the underlying growth trend is little changed.

DATA REVISIONS

Most analysts regard the monthly gasoline supplied data as more reliable than their weekly counterparts.

Both are estimates and calculated as residuals from reported domestic gasoline production plus imports minus exports minus stock changes.

Data on production, imports and stock changes are reported to the EIA in weekly and monthly surveys of the industry. Export data however is not reported to the EIA but to the U.S. customs service.

EIA has to estimate exports at the time of producing the weekly data; by the time it has to produce the monthly numbers it has hard figures on exports from U.S. customs.

Largely because of the problems associated with estimating exports in real time, most analysts regard the monthly data as more accurate.

CAVEAT LECTOR

Despite the differences, the gap between the daily consumption reported in the weekly surveys and the monthly survey for April amounts to just 260,000 bpd or 2.75 percent (tmsnrt.rs/297qsVG).

The gap is not especially large and actually represents a high level of accuracy given the enormous flows of physical oil which both the weekly and monthly surveys have to capture (tmsnrt.rs/297hAM0).

The lower level of gasoline consumption reported in the monthly survey is consistent with other data showing slower refinery run rates and an unusually high level of gasoline stocks in April.

Even at the lower level reported in the monthly survey, gasoline consumption was still up by 74,000 bpd compared with 2015 and only 2,000 bpd below the record rate set in 2007.

Moreover, there are some reasons to be cautious in relying on the monthly survey for April which comes after the previous monthly survey showed an exceptionally high level of consumption in March.

Monthly data put gasoline supplied at 9.4 million bpd in March, an increase of more than 340,000 bpd compared with the same month in 2015.

According to the monthly surveys, gasoline consumption then declined by 186,000 bpd between March and April, which if true, would be highly unusual.

Gasoline supplied normally increases significantly between March and April: the average increase over the last 70 years has been more than 160,000 bpd.

Gasoline supplied has only dropped between March and April in 10 years between 1945 and 2015. The last significant decline was back in 1995 (tmsnrt.rs/297qehl).

A reasonable conclusion is there is some noisiness in the data and that gasoline supplied was overstated in March and understated April.

The unusual decline in estimated consumption, and discrepancy between the weekly and monthly surveys for April, are a reminder about the dangers of over-interpreting noisy time series.

The broad picture, however, remains basically unchanged. U.S. gasoline consumption continues to grow significantly compared with 2015 and is on course to exceed the previous peak set in 2007.

http://www.reuters.com/article/us-usa-gasoline-kemp-idUSKCN0ZH5C2

Asian prices for liquefied natural gas (LNG) rose to their highest since February this week on rising Asian imports and a gas leak at Australia's Gorgon export site, as well as higher prices in Britain.

Asian spot LNG prices LNG-AS were valued around $5.50 per million British thermal units (mmBtu) by traders, about one-third higher than their 2016 lows from April.

Traders said that prices were supported by strong demand and also by Chevron's huge but troubled Gorgon LNG plant in Australia, with the latest technical incident a gas leak reported on Friday, although Chevron said the facility "remains on track to load the second cargo of Gorgon LNG in the coming days."

Prices were also supported by firm Asian demand. Driven by upticks in Japanese, Taiwanese and also Chinese imports, LNG shipments into North Asia have risen from weekly levels of around 3 billion cubic metres (bcm) to 4 bcm between mid-May and mid-June, according to Eikon data.

Volatile financial markets this week after Britain's vote to leave the European Union also pushed up gas prices.

With the British pound falling against other currencies, UK gas prices were pushed higher across the curve .

That lifted Asian spot LNG prices since international gas traders look towards Britain's gas market for guidance as it can take in supplies from multiple sources, including continental European pipelines and overseas LNG imports.

Also, Qatar's RasGas this week signed an agreement with France's EDF to deliver up to 2 million tonnes per year of LNG to EDF's new terminal in Dunkerque starting in 2017, pulling supply away from Asian markets.

With the opening of the extended Panama Canal last week, traders said LNG markets would become better connected, improving trade flows between the Atlantic and Pacific basins.

"The expanded Panama Canal increases LNG's reach and flexibility," Singapore's exchange SGX said.

The British Merchant LNG tanker, loaded with gas from Trinidad & Tobago, is scheduled to be the first LNG tanker to travel through the expanded Panama Canal.

But traders said that recent gas price rises might not last, with downward pressure building in both Europe and Asia.

With the start of the monsoon season, likely lasting through September, traders expect lower LNG orders from India.

In Europe, analysts said that recent price rallies might also fizzle out.

"The rally in European... gas prices is unlikely to be sustained and we expect global gas prices to remain low in an oversupplied market over the second half of 2016," analysts at BMI Research said.

"Markets have tightened in recent months but global supply is still robust at a time when there is limited demand-side pressure on prices," they added.

http://in.reuters.com/article/global-lng-idINL4N19N1YD

Chile this week gave Cheniere Energy Inc. a good reason to build another plant to export U.S. natural gas by clearing the final environmental hurdle for a proposed floating import terminal.

Approval was granted for the Penco Lirquen LNG project, which comprises a floating storage and regasification unit, Juan Jose Gana, executive director of Biobiogenera SA, the developer behind the project, said in an e-mail Thursday. The 1,200-megawatt Central El Campesino power plant, which will be supplied by the gas import vessel, “should be approved” in July or August, he said.

This approval marks a milestone for Cheniere, which has a 20-year agreement to supply gas to the power plant. Cheniere is also a co-owner of the LNG import project with Biobiogenera, according to Hoegh LNG Holdings Ltd., which is building the terminal.

Success in Chile may help Cheniere find other new buyers needed to sign long-term contracts before it makes a decision on an additional liquefaction plant at its Corpus Christi facility in Texas, according to Energy Aspects Ltd. and Hennessy Funds.

“This a positive development for U.S. exports,” Alex Tertzakian, an analyst with Energy Aspects in London, said by e-mail Thursday. Although the contract to supply the terminal and the connected power plant “is relatively small volume-wise,” the latest developments will “undoubtedly increase the chances” of Cheniere moving ahead with building the third liquefaction plant at Corpus Christi, he said.

Local Protests

Although it got the environmental nod, the project has stirred up controversy in the local community. Police used a water cannon to break up protests in the Chilean city of Concepcion on Tuesday after the regional environmental commission unanimously approved the LNG project, Radio BioBio reported on its website. Two local towns plan to team up to seek a court injunction to block the project, La Tercera reported, citing Valentina Escalona, the mayoress of Penco, 262 miles south of Santiago.

Cheniere’s marketing unit has an agreement to supply to the El Campesino power plant with 32.3 million British thermal units a year, the equivalent of nine cargoes, the company said in a June 27 presentation. Shipments are slated to start in 2019 from Corpus Christi. This contract would represent about 17 percent of the marketing arm’s projected LNG available from seven liquefaction plants over two decades.

Cheniere has two liquefaction plants under construction at Corpus Christi. While a third one is fully permitted, the company said on its website it is seeking additional contracts before making a final investment decision. Cheniere is building four plants in Louisiana.

“The more contracts that they can sign up to service their growth for the Texas project, the better because they don’t have it fully subscribed,” said Skip Aylesworth, who manages $1.5 billion in holdings at Hennessy Funds in Boston. “They are trying to develop markets that are closer to Texas and Louisiana than Europe and Asia because the smaller they can make that transportation cost the more it helps them.”

http://www.bloomberg.com/news/articles/2016-06-30/chile-just-gave-cheniere-a-big-reason-to-build-another-lng-plant

Iraq's oil exports from the southern ports fell slightly in June as power generators burning more fuel to keep up with demand for air conditioning increased domestic demand, an official at the state-run South Oil Company said on Friday.

Loadings from Iraq's southern oil terminals, on the Gulf, ran at an average daily rate of 3.175 million barrels, compared with 3.2 million barrels per day (bpd) in May, he said.

Crude supply to local oil refineries rose due to the increase in demand for electricity for cooling during summer in OPEC's second-largest producer, he said.

The southern region produces most of the OPEC nation's crude oil. The northern Kurdish regional government exports about 500,000 bpd through a pipeline to the Turkish port of Ceyhan, on the Mediterranean, but independently from the central government in Baghdad which oversees crude sales from the south.

Iraq, which relies on oil for nearly all its revenue, made$3.845 billion in revenue from oil exports in June, selling at an average price of $40.37 a barrel, an oil ministry spokesman said. June's revenue was higher than April as prices increased.

Iraqi officials and oil analysts expect further growth in the country's exports this year, but at a slower rate than 2015 when it was the fastest source of supply growth in OPEC.

http://www.reuters.com/article/us-iraq-oil-idUSKCN0ZH4G5

Russian oil company Russneft plans to hold an IPO on the Moscow Exchange in November, aiming to raise $500 million for 10 percent of its shares, a source close to the deal told Reuters.

"A request for proposal has been sent to banks, and most likely organizers of the deal will be chosen next week," the source said.

Western banks are not taking part in the IPO. Invitations to take part were received by Russian lenders Gazprombank, VTB and FC Otkritie.

http://www.reuters.com/article/us-russia-russneft-ipo-idUSKCN0ZH4BV

Chevron said it had suspended production at Australia's Gorgon liquefied natural gas (LNG) export terminal after a leak but remained on track to make a second shipment in coming days.

"Chevron Australia plans to undertake some minor repair work on the low pressure flare system at the acid gas removal unit before recommencing production in the coming week," it said in a statement. "Plans remain on track to load the second cargo of Gorgon LNG in the coming days."

http://www.reuters.com/article/idUSL4N19N2Y1

Project will create 10,000 new jobs and support economic growth in Papua Barat Province

BP, on behalf of Tangguh Production Sharing Contract Partners, today announced that the Final Investment Decision (FID) has been approved for the development of the Tangguh Expansion Project in the Papua Barat Province of Indonesia.

'The Tangguh Expansion Project demonstrates BP and its partners' continued confidence in Indonesia and our commitment to work closely with the government to meet the country's energy needs, while creating thousands of jobs,' said Bob Dudley, BP Group Chief Executive.

The Tangguh Expansion Project will add a third LNG process train (Train 3) and 3.8 million tons per annum (mtpa) of production capacity to the existing facility, bringing total plant capacity to 11.4 mtpa. The project also includes two offshore platforms, 13 new production wells, an expanded LNG loading facility, and supporting infrastructure.

The Tangguh Expansion Project will play an important role in supporting Indonesia's growing energy demand, with 75% of the Train 3 annual LNG production sold to the Indonesian state electricity company PT. PLN (Persero). The remaining volumes are under contract to Kansai Electric Power Company in Japan, the other foundation buyer for Train 3.

The Tangguh Expansion Project will also bring a positive contribution to Indonesia and the Papua Barat Province starting in 2016, supporting economic growth and providing 10,000 valuable jobs spread over the project period.

Tangguh is currently making positive local social and economic impacts through its comprehensive community development programs and providing much needed electricity for the Teluk Bintuni Regency. Train 3 will enhance this with a portion of the gas committed for the electrification of Papua Barat, and further development of Tangguh's Papuan workforce to meet the 85% Papuan skilled workforce commitment by 2029.

Commenting on the decision, Christina Verchere, BP Regional President Asia Pacific said, 'This final investment decision marks the culmination of many years of hard work by BP, our partners, and the Indonesian Government. We are pleased to reach this major milestone and look forward to continued cooperation as we progress the largest upstream project in the eastern part of Indonesia.'

This FID decision follows the Government of Indonesia's approval of the Plan of Development II in late 2012. Awards for the project's key engineering, procurement and construction (EPC) contracts are expected in the third quarter of 2016 with construction to begin thereafter. Operation is expected in 2020.

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In a first, U.S. oil-and-gas companies are on track this year to export more propane than the next four largest exporting countries combined—OPEC members Qatar, Saudi Arabia, Algeria and Nigeria, which have long dominated the trade—according to analytics provider IHS Inc. U.S. exports already account for more than a third of the overall market for waterborne shipments, IHS said.