Russia failed to rule on a planned purchase of the company by Schlumberger Ltd.

Russia’s foreign-investment commission met Thursday yet didn’t make a decision on Schlumberger’s bid, Natural Resources Minister Sergei Donskoi said by phone, without giving a reason. Investors had hoped a ruling would clear the way for the deal’s $1.7 billion first phase, which has already been delayed months.

Schlumberger, based in Houston and Paris, announced the planned purchase in January as the U.S. and Russia faced off over President Vladimir Putin’s support for a separatist insurgency in Ukraine. U.S. and European sanctions on Russia include curbs on exports of drilling technology.

The acquisition was pushed back as Russia’s antitrust authority sought additional information. That led Eurasia to miss a February deadline for completing the first phase, under which core investors would buy out the 45.65 percent held by minorities at $22 a share. At a later stage Schlumberger would gain an option to acquire the rest.

A discussion of the bid was originally on the commission’s agenda for Thursday, two officials said earlier this week. It was unexpectedly removed before the meeting, RBC reported, citing two unidentified people with knowledge of the matter.

“The government probably decided to be more cautious amid rising tensions in Ukraine and statements from U.S. and EU politicians on extending sanctions against Russia,” said Ildar Davletshin, an energy analyst at Renaissance Capital in Moscow.

- See more at: http://www.rigzone.com/news/oil_gas/a/139087/Eurasia_Drilling_Slumps_as_Russia_Fails_to_Rule_on_Schlumberger?rss=true#sthash.E7oboHf2.dpuf

Senators of Brazil’s largest party expect the upper house to approve a bill that relieves state-controlled Petrobras of its role as sole operator and compulsory stakeholder in so-called pre-salt oilfields.

“I don’t see any difficulty for this project to be approved in the Senate,” Eunicio Oliveira, leader of the PMDB, said in a telephone interview from Brasilia this week. “It’s an important project for the country and would aid Petrobras.”

Changes would help the most indebted oil company in the world by reducing necessary investments in future oil rounds, said PMDB Senator Ricardo Ferraco, the sponsor of the bill. Humberto Costa, Senate leader of President Dilma Rousseff’s Workers’ Party, said only a widespread social movement could stop the bill from being approved.

While Rousseff herself is resisting deregulation, her Energy Minister Eduardo Braga said in a recent interview in Houston that he supports allowing Petroleo Brasileiro SA, as the company is formally known, to opt out of the obligation to assume at least 30 percent ownership of all pre-salt projects and operate them. The company lacks the money to cover its share of development after racking up $125 billion in debt. The pre-salt is the jewel in Brazil’s vast offshore oil reserves.

The bill, authored by Senator Jose Serra of the opposition PSDB party, would still have to be approved by the lower house. Brazilian legislators often don’t vote along party lines, making the outcome unpredictable.

Ferraco said he has spoken to fellow congressmen and is certain of the majority of votes. He plans to place the bill on a fast-track that would put it to a vote on the floor without going through committees.

While most members of the Workers’ Party oppose the bill, some will vote for it, said Costa.

“We will have to rally our constituency against it because there are strong lobbies behind the push to change the rules,” Costa said.

http://www.bloomberg.com/news/articles/2015-06-11/brazil-senate-may-approve-bill-to-reduce-petrobras-pre-salt-role

Oil futures dipped on Friday after Saudi Arabia said it was ready to raise output further to meet strong demand.

But the rally was halted by a dimming global economic outlook as well as top crude exporter Saudi Arabia saying it was ready to increase its oil output in coming months to a record high to meet a rise in global demand.

In Japan, the world's third-biggest economy, May crude oil purchases by its big utilities fell 47.4 percent compared with the same month last year, and they also bought less natural gas and coal.

Thanks to relatively cheap crude oil, refiners have enjoyed high margins as demand for refined products has been strong, but there are early signs that overproduction will pull down margins as product oversupply emerges.

Independent stocks of oil products at Europe's Amsterdam-Rotterdam-Antwerp hub rose 5 percent in the week to Thursday to hit a record high of 5.845 million tonnes.

While gasoline refining margins remain near three-year highs and surprising diesel demand growth underpinned its margins, the profitability of European jet fuel has declined as thousands of tonnes in surplus cargoes land from new refineries in the Middle East. Some analysts and traders say jet fuel's fate could foretell margins for other oil products, particularly diesel.

Should demand for refined products fall due to emerging oversupply, analysts have said that would spill back into the crude market and pull down prices there as well, as refineries slash orders and reduce output.

http://www.reuters.com/article/2015/06/12/markets-oil-idUSL3N0YY17M20150612

Alexey Miller of Gazprom and Shell’s CEO Ben van Beurden met in Milan on Wednesday where they discussed the status of Sakhalin II and the future collaboration within the project.

They also addressed the prospects for cooperation in the oil and gas sector, as well as the current situation in the LNG markets, according to a statement by Gazprom’s press office.

As part of Sakhalin II, Russia’s first LNG plant with the annual capacity of 9.6 million tons of LNG was commissioned in 2009.

Sakhalin Energy is the Sakhalin II project operator with the ownership distributed among Gazprom (50 per cent plus one share), Shell (27.5 per cent minus one share), Mitsui & Co. (12.5 per cent) and Mitsubishi (10 per cent).

In 2014, Gazprom and Shell signed the memorandum-roadmap to prepare FEED documents for the third LNG production train within the Sakhalin II project.

http://www.lngworldnews.com/gazprom-and-shell-talk-lng/

Cheniere plans to expand its liquefied natural gas empire, adding two additional production units in Corpus Christi and partnering with a smaller Houston-based LNG company to build new projects in Louisiana.

The company on Wednesday announced that it has filed paperwork seeking federal approval to build two more liquefaction trains near its proposed LNG export terminal in Corpus Christi, where construction has started on two of the five proposed trains.

Cheniere also agreed to team up with Parallax Enterprises to complete two mid-scale projects already under development in places close to pipelines and deep water access. The company unveiled Live Oak LNG on the Calcasieu Ship Channel in southwestern Louisiana earlier this year and in April, acquired Louisiana LNG on the Mississippi River south of New Orleans.

The projects each have two trains with a capacity to produce 2.5 million metric tons of the supercooled gas per year.

Altogether, the expansions would boost Cheniere’s LNG production capacity to 60 million metric tons per year within a decade.

In a statement, CEO Charif Souki said Cheniere expects to fund the developments with internally generated cash flows, which allows the company to remain a low-cost supplier while giving Cheniere more flexibility in making deals to sell LNG to global buyers.

If the plans are approved by the federal government, Cheniere expects to start construction on the projects by 2017 and could begin producing the first batches of LNG as early as four years later, the company said in a statement.

http://fuelfix.com/blog/2015/06/11/cheniere-reveals-plans-for-additional-lng-projects/?utm_source=twitterfeed&utm_medium=twitter

Hess Corp., the most active oil driller in the Bakken last year, agreed to sell a 50 percent stake in its pipeline and processing unit in the area to private equity firm Global Infrastructure Partners for $2.675 billion in cash.

The companies are forming a midstream joint venture called Hess Infrastructure Partners, New York-based Hess said in a statement Thursday.

“The joint venture with its strategically located assets will be one of the largest midstream operators in the Bakken,” Chief Executive Officer John Hess said in the statement. “The joint venture will be in a strong position to fund future energy infrastructure investments and continue to grow its midstream business.”

Hess will get a total of $3 billion in cash from the transaction, including $300 million from a debt sale by the joint venture that will help it close a cash flow gap expected this year because of lower oil prices. Fracking and horizontal drilling in the Bakken formation have made North Dakota the nation’s largest oil-producing state behind Texas, according to the Energy Information Administration.

The company said it will continue with plans for an initial public offering of units in Hess Midstream Partners LP.

http://www.bloomberg.com/news/articles/2015-06-11/hess-sells-half-of-bakken-midstream-for-2-675-billion

China's natural gas output fell 2 percent in May from a year earlier, official data showed on Thursday, its second straight month of decline as the market expects Beijing to announce another price cut in the coming months to lift slowing demand.

Output recorded a 2.9-percent year-on-year drop in April, to 9.4 billion cubic metres (bcm), the lowest since July 2014 in outright volumes. Such drops in output have been rare.

Production was 9.9 bcm in May, slightly higher than April on a daily basis. Total output in the first five months of 2015 climbed 2.1 percent from the same period the year before to 53.2 bcm, the National Statistical Bureau (NSB) said.

China, the world's largest energy guzzler, is keen to boost the use of natural gas to cut emissions and fight air pollution.

But demand has been hit since last year as domestic prices, which are regulated by the government, were not cut until April, lagging the steep declines in global oil markets that Beijing uses as a benchmark for gas pricing.

In the first four months of 2015, China burned 62.9 bcm of gas, up a tepid 2.4 percent from the same period last year, according to the National Development & Reform Commission.

Industry sources said Beijing may move to cut city-gate, or wholesale gas prices again in the coming months to lift demand.

Factories that produce items such as ceramics and glass have curbed gas purchases, while the use of gas as a transport fuel has also eased as its price competitiveness relative to diesel narrows hugely.

http://www.reuters.com/article/2015/06/11/china-economy-output-gas-idUSL3N0YW3UX20150611

Cenovus Energy Inc said it had resumed normal operations at its Foster Creek oil sands site in Alberta after a forest fire led to a precautionary shutdown on May 23.

Canada's No. 2 independent oil producer had evacuated about 1,800 workers and shut down production at the site, which it operates as part of a joint venture with ConocoPhillips.

The project averages production of about 135,000 barrels per day.

Cenovus said it expects production in the second quarter to be reduced by 10,500 bpd and in the full year by about 2,600 bpd due to the shutdown.

The company's total production in the first quarter ended March 31 averaged 218,020 bpd.

The company said its Athabasca natural gas operations, which were also shut down due to the forest fire, have resumed.

At least 233,000 barrels per day of oil sands production, 9 percent of Alberta's total oil sands output, had been suspended because of the fire risk.

http://www.reuters.com/article/2015/06/11/canada-oil-sands-fires-idUSL3N0YX3UE20150611

Apache Corp. CEO John Christmann didn’t just get a new job when he took charge of one of the world’s biggest shale producers in the dark days of the oil market crash in January, he signed on to a corporate makeover.

In the past six months Christmann has focused on transforming Apache from a high-flying global explorer into a ruthlessly efficient production machine rooted deeply in West Texas shale fields. Under his watch, Apache has set the pace for an industry intent on moving beyond basic cost-cutting to reset priorities on regions and projects that can thrive with $50-a-barrel oil.

Christmann has now accomplished what none of his other major peers have yet managed: he’s making more cash from operations than he’s spending. That compares to the two years preceding the 2014 oil market crash, when Apache was among a group of 18 producers on the Standard & Poors 500 Index spending a total of $36 billion more than the cash they generated.

Christmann and his peers have used the downturn as a catalyst to turn shale drilling from a money-losing technology into the future of global oil, said Les Csorba, partner at executive search firm Heidrick & Struggles.

“This new generation of leaders was really anticipating the downturn, even before prices began falling, focusing on standardization and driving efficiency,” said Csorba, who helped Apache select Christmann and placed other energy CEOs in the past two years. “They’re engineers who are very focused on returns, more than on production growth.”

Apache moved faster than anyone, reducing its operating drilling rigs initially by 70 percent and finally by 87 percent, to 12 from 91, a cut equivalent to some producers’ entire rig fleet.

By February, Christmann had cut spending so severely its planned 2014 production increase fell to zero from a previous 18 percent -- a daring move in an industry investors value mainly for growth prospects.

With his emphasis on profits, Christmann was returning Apache to its roots. The company was among the top-performing oil and natural gas producers from 2001 to 2010, nearly tripling in value as it focused on turning tired-out oilfields into cash engines.

As the shale boom was taking off in the U.S., Apache began pursuing developments from Argentina to Australia, sinking billions into projects that wouldn’t show returns for years. The company’s market value fell 21 percent from 2010 to mid-2014, while peers such as EOG more than doubled in value during the same period, according to data compiled by Bloomberg.

Under Christmann’s guidance, Apache’s service costs have fallen 40 percent in some regions, contributing to free cash flow that is expected to reach up to $1 billion in 2015, according to the average of analyst estimates compiled by Bloomberg. Apache sold off all but two of its major overseas operations, in Egypt and the North Sea, and Christmann is refocusing the company on North America.

The 3.3 million gross drilling acres the company controls in the Permian Basin of West Texas are now the “heart and soul” of Apache, he said.

EOG can now make the same profit with oil at $65 a barrel that it could with $95-a-barrel crude two years ago.

The overall decline in costs may outpace early industry hopes of realizing 25 percent reductions, according to analysis by Bloomberg Intelligence. After six months of oil prices hovering between $50 and $60, producers in the top three drilling regions of the Permian Basin have dropped the so-called breakeven price -- which includes a 10-percent profit -- to about $42 a barrel, a decline of 19 percent from last year, according to Bloomberg New Energy Finance.

http://www.bloomberg.com/news/articles/2015-06-10/why-this-shale-ceo-isn-t-afraid-of-opec-or-low-oil-prices

BP Plc released its yearly Statistical Review of World Energy on Wednesday. Used for decades as an industry benchmark, this year's edition laid bare the seismic shifts taking place in global energy markets.

1) The rise and rise of U.S. oil production

The rise in U.S. crude output has simply been explosive. America added 1.6 million barrels a day in 2014, taking production past its previous peak in 1970. It also made the U.S. the world's largest crude producer, knocking Saudi Arabia off its perch.

While there are signs shale production will fall back slightly this year because of the slump in oil prices it's marginal compared with the longer-term trend. Energy independence is getting closer: U.S. energy production met almost 90 percent of consumption last year, the most since the Reagan administration.



2) China's energy slowdown

China -- the motor of global energy demand since the turn of the century -- is trying to change course. A slowing economy and shift away from heavy industry meant 2014 saw energy consumption grow just 2.6 percent, less than half its recent average and the smallest increase since the Asian crisis of 1998. The country's energy intensity -- the amount of fuel it needs to consume to generate each dollar of GDP -- is getting closer to U.S. and European levels.

If, and BP says it's quite a big if, China keeps a lid on new steel mills and cement factories, it'll have a big impact on global demand in the years ahead.


3) The global solar boom

Renewable energy is now a force to be reckoned with. Last year non-fossil fuels, including nuclear, accounted for more of the increase in global energy consumption than oil, gas and coal combined. Particularly notable are record installations of solar panels.

The combination of slower energy demand growth and more renewable power meant global emissions expanded just 0.5 percent in 2014, the slowest pace since the financial crisis. increasing just 0.5 percent. 

http://www.bloomberg.com/news/articles/2015-06-10/the-three-seismic-shifts-that-are-shaking-up-the-world-of-energy

Mexican state oil company Pemex said on Wednesday it had made one of its biggest discoveries in years, unveiling new shallow water oil fields in the southern Gulf of Mexico that could produce 200,000 barrels per day (bpd) by mid-2018.

The total proven, probable and possible reserves of the fields could be as high as 350 million barrels of crude-oil equivalent, Pemex's Chief Executive Officer Emilio Lozoya told an oil conference in Guadalajara.

The new fields off the coast of Tabasco and Campeche states comprise three of light crude and one of heavy crude, and could start coming onstream in 16 months, Pemex said.

The fields would take around three years to reach their full 200,000 bpd capacity, Jose Antonio Escalera, director of exploration for Pemex, told Mexican radio.

Pemex described the finds as its biggest exploration success in the last five years after the discoveries in Tsimin-Xux and Ayatsil, also in the southern Gulf.

Located near the super giant Cantarell oil field found in the 1970s and Pemex's most productive current field Ku Maloob Zaap, the finds could boost revenue for the government, which relies on Pemex income to provide about a third of the federal budget.

CEO Lozoya said the discoveries could also make the company reconsider its production forecasts.

The new hydrocarbon finds were also expected to generate production of 170 million cubic feet of gas per day.

Output at Pemex has fallen from a peak of 3.4 million bpd in 2004 to less than 2.4 million bpd currently.

Mexico will auction 14 oil and gas exploration and production blocks not far from the new fields this summer, and Energy Minister Pedro Joaquin Coldwell said at the Guadalajara event that the finds would make the tenders more attractive.

http://www.reuters.com/article/2015/06/11/mexico-pemexdiscovery-idUSL1N0YX01Y20150611

China's crude througput grew 7.4 percent in May from the same month a year ago to 43.92 million tonnes, data from the National Statistical Bureau showed on Thursday.

Crude oil output rose 2 percent on year last month to 18.14 million tonnes.

http://www.reuters.com/article/2015/06/11/china-oil-output-idUSENNF680TA20150611

Gulfport Energy Corp., Oklahoma City, has agreed to acquire 35,326 net acres in the Utica shale in Ohio from American Energy-Utica LLC, a subsidiary of American Energy Partners LP.

The purchase price for 6,198 net undeveloped acres in Belmont and Jefferson counties is about $68.2 million, subject to adjustment. The acreage is near or adjacent to acreage in Gulfport’s pending acquisition of Paloma Partners III LLC (OGJ Online, Apr. 16, 2015).

In a second agreement with AEU for about $319 million, Gulfport will acquire 27,228 net acres in Monroe County, including 14.6 MMcfd of net production, 11.3 net drilled but uncompleted wells, a fully constructed four-well pad location, and an 11-mile gas gathering system.

Gulfport also has agreed to acquire from AEU an additional 1,900 net acres in Monroe County for $19.4 million if completed within 30 days of the closing of the other Monroe agreement.

The pending Paloma acquisition includes 24,000 net acres. Gulfport said its holdings of Utica shale leasehold are expected to total 243,000 net acres.

http://www.ogj.com/articles/2015/06/gulfport-energy-to-buy-more-utica-acreage-in-ohio.html

Islamic State strengthened its hold in central Libya, taking territory near Libya’s largest oil terminal and repelling efforts by militias to halt its advance.

The jihadist group had been tightening its grip on Sirte over recent months. It claimed on Tuesday to have finally succeeded in taking Muammar Qaddafi’s hometown, after overrunning a nearby power station.

Islamic State already controls the desert town of Naufaliya, about 30 miles from Libya’s largest export terminal of Es Sider and neighboring Ras Lanuf, the third-largest. Controlling Sirte helps cement those positions on the west side of the so-called Sirte Basin, which is home to about 70 percent of the country’s crude reserves.

“It’s becoming clear that they’re getting more structure and their control of this region is getting more serious,” said Riccardo Fabiani, senior North Africa analyst at the London-based Eurasia Group.

https://www.energyvoice.com/oilandgas/79844/islamic-state-expands-near-libyas-largest-oil-terminal/

Production rose once again (up 0.25%) to new record highs at 9.61mm bbl/day.

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

U.S. crude oil refinery inputs averaged 16.6 million barrels per day during the week ending June 5, 2015, 169,000 barrels per day more than the previous week’s average. Refineries operated at 94.6% of their operable capacity last week. Gasoline production increased last week, averaging 10.0 million barrels per day. Distillate fuel production increased last week, averaging 5.1 million barrels per day.

U.S. crude oil imports averaged over 6.6 million barrels per day last week, down by 750,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged about 7.0 million barrels per day, 2.3% below the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 666,000 barrels per day. Distillate fuel imports averaged 181,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 6.8 million barrels from the previous week. At 470.6 million barrels, U.S. crude oil inventories remain near levels not seen for this time of year in at least the last 80 years. Total motor gasoline inventories decreased by 2.9 million barrels last week, but are in the upper half of the average range. Finished gasoline inventories increased while blending components inventories decreased last week. Distillate fuel inventories increased by 0.9 million barrels last week and are in the middle of the average range for this time of year. Propane/propylene inventories rose 1.7 million barrels last week and are well above the upper limit of the average range. Total commercial petroleum inventories decreased by 0.6 million barrels last week.

Total products supplied over the last four-week period averaged over 19.7 million barrels per day, up by 5.1% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged 9.4 million barrels per day, up by 3.8% from the same period last year. Distillate fuel product supplied averaged over 3.9 million barrels per day over the last four weeks, down by 1.7% from the same period last year. Jet fuel product supplied is up 8.7% compared to the same four-week period last year.

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

When forecasting how much oil will be available in future years, a standard approach seems to be the following:

Figure out how much GDP growth the researcher hopes to have in the future.
'Work backward' to see how much oil is needed, based on how much oil was used for a given level of GDP in the past. Adjust this amount for hoped-for efficiency gains and transfers to other fuel uses.
Verify that there is actually enough oil available to support this level of growth in oil consumption.

In fact, this seems to be the approach used by most forecasting agencies, including EIA, IEA and BP. It seems to me that this approach has a fundamental flaw. It doesn't consider the possibility of continued low oil prices and the impact that these low oil prices are likely to have on future oil production. Hoped-for future GDP growth may not be possible if oil prices, as well as other commodity prices, remain low.

It is easy to get the idea that we have a great deal of oil resources in the ground. For example, if we start with BP Statistical Review of World Energy, we see that reported oil reserves at the end of 2013 were 1,687.9 billion barrels. This corresponds to 53.3 years of oil production at 2013 production levels.

If we look at the United States Geological Services 2012 report for one big grouping-undiscovered conventional oil resources for the world excluding the United States, we get a 'mean' estimate of 565 billion barrels. This corresponds to another 17.8 years of production at the 2013 level of oil production. Combining these two estimates gets us to a total of 71.1 years of future production. Furthermore, we haven't even begun to consider oil that may be available by fracking that is not considered in current reserves. We also haven't considered oil that might be available from very heavy oil deposits that is not in current reserves. These would theoretically add additional large amounts.

Given these large amounts of theoretically available oil, it is not surprising that forecasters use the approach they do. There appears to be no need to cut back forecasts to reflect inadequate future oil supply, as long as we can really extract oil that seems to be available.

There is clearly a huge amount of oil available with current technology, if high cost is no problem. Without cost constraints, fracking can be used in many more areas of the world than it is used today. If more water is needed for fracking than is available, and price is no object, we can desalinate seawater, or pump water uphill for hundreds of miles.

If high cost is no problem, we can extract very heavy oil in many deposits around the world using energy intensive heating approaches similar to those used in the Canadian oil sands. We can also create gasoline using a coal-to-liquids approach. Here again, we may need to work around water shortages using very high cost methods.

The amount of available future oil is likely to be much lower if real-world price constraints are considered. There are at least two reasons why oil prices can't rise indefinitely:

Any time oil prices rise, economies that use a high proportion of oil in their energy mix experience financial problems. For example, countries that get a lot of their revenue from tourism seem to be vulnerable to high oil prices, because high oil prices raise the cost of airline travel. Also, if any oil is used for making electricity, its high cost makes it expensive to manufacture goods for export.
When oil prices rise, workers find that the cost of food tends to rise, as does the cost of commuting. To offset these rising expenses, workers cut back on discretionary spending, such as going to restaurants, going on long-distance vacations, and buying more expensive homes. These spending cutbacks adversely affect the economy.

The combination of these two effects tends to lead to recession, and recession tends to bring commodity prices in general down. The result is oil prices that cannot rise indefinitely. The oil extraction limit becomes a price limit related to recessionary impacts.

The cost of oil is currently in the $60 per barrel range. It is not even clear that oil prices can rise back to the $100 per barrel level without causing recession in many counties. In fact, the demand for many things is low, including labor and capital. Why should the price of oil rise, if the overall economy is not generating enough demand for goods of all kinds, including oil?

http://www.oilvoice.com/n/Why-EIA-IEA-and-BP-Oil-Forecasts-are-Too-High/30aeae396ac7.aspx?utm_source=dlvr.it&utm_medium=twitter

OAO Lukoil, Russia’s largest non-state oil producer, said first-quarter profit dropped 60 percent after crude prices slumped.

Net income fell to $690 million from $1.73 billion a year earlier, the Moscow-based company said Wednesday in a statement. That missed the $1.04 billion average estimate of seven analysts surveyed by Bloomberg.

Oil companies have been hurt by tumbling prices for output amid a global supply glut. Brent, the benchmark for more than half the world’s crude, has slumped 40 percent in the past year after the Organization of Petroleum Exporting Countries chose to maintain production to defend market share.

Oil’s partial recovery since January helped Lukoil post a profit after reporting a loss in the fourth quarter of 2014. Results were also buoyed by a weaker ruble, which reduced costs, and spending cuts. Russian peers OAO Gazprom Neft and OAO Novatek also returned to profit in the first quarter following losses in the fourth.

Lukoil signed an agreement on the sale of 50 percent of Caspian Investment Resources Ltd. to China Petrochemical Corp., or Sinopec, for $1.07 billion. The agreement will halt arbitration, which the Russian company began in London this February, Lukoil said in the statement.

Lukoil’s oil and natural-gas output rose 7 percent from a year earlier to 2.37 million barrels a day, it said. The company pumped 2.03 million barrels of oil and liquids a day as it ramped up an Iraqi project.

Refining throughput in Russia fell 12 percent due to a decrease in margins as a result of tax legislation.

First-quarter capital spending fell 25 percent to $2.43 billion from a year earlier, it said.

http://www.bloomberg.com/news/articles/2015-06-10/lukoil-first-quarter-profit-slides-60-following-crude-s-decline

Indonesia's plan to develop 30 days' worth of fuel and oil emergency reserves is expected to cost up to $24 billion, and would be in addition to plans to boost operational reserves, an energy ministry official said on Wednesday.

The government hopes funding for the emergency reserve facilities would come from the private sector, but it may also come from state-owned firms, Oil and Gas Director General Wiratmaja Puja also told reporters.

He estimated that 45 million barrels of crude and fuel would be needed for the emergency reserves, assuming demand of 1.5 million barrels per day.

"The function of this storage buffer is for emergencies, like when there was a tsunami in Aceh, or wars. This requires a lot of fuel, so when there's an emergency we're ready for at least a month," Wiratmaja said.

The government hopes to begin designing the facilities next year, he said. The estimated investment cost of $17 billion-$24 billion would cover construction costs as well as the fuel and crude to fill new oil storage tanks, he said.

Regulations for the emergency reserves plan are currently being drafted and are expected to be released this year.

Indonesia also plans to develop operational fuel reserves to cover 30 days, up from around 22 days at present, Wiratmaja said, and has asked state oil and gas firm Pertamina and other companies to assist.

Last month Pertamina announced plans to build a fuel depot in Jakarta as part of this programme.

The government is also considering hiring storage from other firms and utilising facilities that oil and gas contractors are no longer using, he said.

http://www.reuters.com/article/2015/06/10/indonesia-oil-reserves-idUSL3N0YW2YQ20150610

Weir Group Plc said it expects its full-year results to be more weighted towards the second half, as a drop in orders at its oil and gas division and weak trading at upstream businesses hurt second-quarter performance.

The Scottish company, which makes valves and pumps for the energy and mining industries, has been hit by a slowdown in North American oilfield activity as crude oil prices remain depressed and explorers and producers slash capital spending.

The company said its oil and gas order input was 34 percent lower in the first five months of 2015 than in the prior year period.

Weir, whose North American operations accounted for about a third of its 2014 revenue, said it had temporarily suspended operations for a week at its Fort Worth, Texas facility to cut costs.

"The overall tone of the update suggests a possibly tougher Q2 than management had thought... Some improvement is expected in H2, but the statement will likely create some small downside risk to consensus EPS," UBS analysts wrote in a note.

Weir Group told Reuters in April that it planned to cut another 125 jobs, mostly in its North American oil and gas business. The company first began taking cost-saving measures in November.

http://www.reuters.com/article/2015/06/10/weir-group-outlook-idUSL3N0YW2ZX20150610

Pioneer Natural Resources Co. says it wants to sell 640,000 acres of mineral rights it holds in eastern Colorado.

That word comes a month after Irving, Texas-based Pioneer announced plans toshut its Denver office and halve its workforce in Trinidad in southern Colorado.

Pioneer, like many oil and natural gas companies, has been cutting staff, closing offices, and selling “non-core” assets in order to focus on what executives consider to be their best operations as crude oil and natural gas prices continue to be stubbornly low.

The eastern Colorado oil and gas leases Pioneer has put on the market are in what has been considered an exploration area in recent years, a place where companies sought to replicate the success found in northern Colorado.

There, mostly in Weld County, companies using horizontal drilling and hydraulic fracturing techniques have produced oil previously trapped in the Niobrara and Codell shale rock formations some 7,000 feet underground, contributing to record-setting oil production in recent years.

The leases Pioneer wants to sell are in several eastern counties — Bent, Cheyenne, Crowley, Elbert, Kiowa, Kit Carson, Lincoln, Prowers and Washington —and include rights to drill for oil and gas in the Niobrara, Cherokee, Atoka, Mississippean and Morrow rock formations.

http://www.bizjournals.com/denver/blog/earth_to_power/2015/06/texas-company-to-sell-640-000-acres-of-colorado.html?ana=yahoo

Wood Mckenzie reported Wednesday that Chinese national oil companies (NOCs) are assessing how best to optimize their diverse supply portfolios as gas demand disappoints, leading to an oversupplied market with weaker prices. Wood Mackenzie says there are three major levers China can focus on to adjust with market movements and how these levers are used to manage oversupply will impact liquefied natural gas (LNG) prices and suppliers to China.

Gas demand growth in China has been reduced significantly with demand now expected to reach around 12.71 trillion cubic feet (Tcf) or 360 billion cubic meters (Bcm) and 19.77 Tcf (560 Bcm) in 2020 and 2030 respectively compared to 14.83 Tcf (420 Bcm) and 22.59 Tcf (640 Bcm) previously. This is due to short-term and structural drivers. Gavin Thompson, Wood Mackenzie’s principal gas consultant explains, “Short-term drivers include low oil prices and high domestic gas prices, reversal of environmental policies, competition from coal and hydro and warmer winter weather. Structural factors include the switch from industrial production to the service sector as a driver of economic growth.”

Chinese companies have signed around 2.33 Tcf (66 Bcm) per annum of term LNG contracts. Of this total, new contracts will ramp up through 2015, ultimately supplying an addition of approximately 812.1 billion cubic feet (Bcf) or 23 Bcm per annum of gas into the domestic market by 2018. Given the significant downward revision in demand, China’s NOCs are now pursuing numerous channels to reduce volumes. This includes efforts to renegotiate ramp up schedules and pricing terms and reselling volumes into the Pacific market where agreement can be reached with suppliers. Despite weakening demand growth, Central Asian volumes into China also continue to rise. Thompson says. “As a result, there is an oversupply of contracted LNG into the market, particularly during periods of low seasonal demand. We expect China will be over-contracted by about 635.6 Bcf (18 Bcm) from 2015 till 2017.”

- See more at: http://www.rigzone.com/news/oil_gas/a/139048/Wood_Mackenzie_China_Faces_Weaker_Gas_Demand_and_Oversupply_Till_2017#sthash.wKcDwyeX.dpuf

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Attached Files

A top Republican senator on Tuesday provided a blueprint for foreign countries to acquire U.S. crude, as oil companies push for an end to the nation’s longstanding ban on exporting it and the Senate nears votes on the issue.

The document, prepared by Republican staff on the Senate Energy and Natural Works Committee and released by the panel chairwoman, Sen. Lisa Murkowski of Alaska, notes that the Obama administration can allow greater oil exports to U.S. allies already — without any changes by Congress.

“Exempting certain countries on a case-by-case basis, as the statutes and regulations currently allow, would be a partial and helpful step toward the modernization of U.S. energy policy,” the white paper says.

Under a change made by former President Ronald Reagan, oil shipments to Canada are exempted from the broader crude export ban. And the Obama administration is under increasing pressure to make a similar change for Mexico.

But the paper suggests there are many other potential beneficiaries around the globe with deep ties with the United States.

“Many U.S. allies and trading partners are interested in purchasing American oil to diversify away from Russia, Iran and other problematic sources,” the paper says. “Allowing such shipments would send a powerful signal of support and reliability at a time of heightened geopolitical tensions in much of the world. The mere option to purchase U.S. oil would enhance the energy security of (these countries) even if physical shipments did not occur.”

The document also offers case studies for six countries — including Poland, Japan and India — that are seen as particularly well-positioned candidates to seek U.S. crude, given their dependence on foreign sources of oil.

http://fuelfix.com/blog/2015/06/09/murkowski-releases-paper-offering-road-map-for-countries-to-seek-u-s-crude-exports/

Brazil's oil exports to China increased threefold in the first five months of this year, making Beijing the largest consumer of Brazilian oil in the world, said daily Folha de Sao Paulo on Tuesday.

According to Folha, Brazil exported 5.4 million tons of oil to China from January to May, accounting for 35 percent of Brazil's total oil exports in the same period. The amount of oil shipped to China is twice as much as that to the United States.

The rise in China's purchase of Brazilian oil came at a time when Brazil's state-controlled oil giant Petrobras tried to boost its relations with China. Petrobras signed some financing agreements with China during a recent visit to Brazil by Chinese Premier Li Keqiang.

China's higher demand for oil also helped Brazil achieve record oil exports of 15 million tons from January to May, up 80 percent from the same period last year.

However, as oil prices have fallen significantly over the past months, the record sales did not generate corresponding high revenues.

With increased oil purchases, China has become the largest buyer of four major Brazilian products. The other three are soybeans, iron ore and cellulose.

    China replaced the United States to become Brazil's largest trade partner in 2009. The Sino-Brazilian trade value amounted to 86.67 billion U.S. dollars in 2014.

http://en.chinamining.com.cn/News/2015-06-10/1433918141d72520.html

Glencore Plc has bought more than 1 million metric tons of fuel oil in Singapore this month as prices tumble from a record premium in the world’s biggest bunker market.

The company has purchased at least 925,000 tons of 380-centistoke fuel oil and 140,000 tons of the 180-centistoke grade so far in June on the so-called window run by pricing service Platts, a unit of McGraw Hill Financial Inc. Glencore’s cargoes, loading this month and in July, account for about 36 percent of the total transacted volume of 2.95 million tons, data provided by Platts show.

Francis de Rosa, a Sydney-based spokesman for Glencore, said on Tuesday the company declined to comment.

Under the Platts process, traders report bids, offers and deals through e-mails, instant messages and phone conversations in a defined period each day, which are then used to create end-of-day price assessments for various commodities and used as benchmarks for transactions around the world.

“It’s the high volume of cargoes traded recently that has caught the market’s attention,” Harry Tchilinguirian, the London-based head of commodity markets strategy at BNP Paribas SA, said by phone. “The fuel oil inventory data in Singapore indicates very ample supplies.”

Singapore’s onshore stockpiles of residual fuels, including fuel oil, rose to a record in the week to June 3, according to International Enterprise, a unit of Trade and Industry Ministry. The city-state is the world’s largest port for bunker, or ship fuel, with sales of about 42 million tons in 2014, data from the Maritime and Port Authority show.

http://www.bloomberg.com/news/articles/2015-06-10/glencore-in-1-million-ton-singapore-fuel-spree-as-premiums-slump

According to the latest analysis from PIRA Energy Group, the LNG supply side seems focused on challenging coal for a lead in the race to join forces with renewable energy to meet incremental power generation demand.

LNG scorecard

The supply side, led by LNG players with portfolio volumes looking for end-user markets, seems focused on challenging coal for supremacy in the race to join forces with renewable energy to meet incremental power generation demand. In summary, key figures attending the World Gas Conference in Paris, France, are offering a policy-driven solution to solve a commercial problem.

European gas prices

PIRA’s analysis noted: “Sometimes it's difficult to think of European gas markets as a proving ground for the next phase in the evolution of the global gas industry. After all, this market was dragged kicking and screaming into the spot market era, and even today large portions of the market remain relatively uncompetitive by oil market standards.”

The European gas market has shown that being resistant to change in one area does not prevent change from occurring elsewhere. This has been witnessed in the gas market for power generation over the past five years, and the next phase of testing will occur in the form of integrating more LNG into the supply mix.

http://www.lngindustry.com/liquid-natural-gas/09062015/LNG-vs-coal-in-race-for-energy-mix-918/?utm_source=feedburner&utm_medium=feed&utm_campaign=Feed%3A+LNGindustry+%28LNG+industry%29

Iraq made a $430 million budget payment to the Kurdistan region for May, the finance minister said on Tuesday, potentially putting further strain on a deal over oil exports.

The December deal was hailed as a breakthrough in a long-running dispute over exports between the federal government in Baghdad and Kurdish regional authorities, but both sides accuse each other of violating it.

Finance Minister Hoshiyar Zebari said Baghdad had paid 508 billion dinars ($430 million) to the region in May as expenditure had been lowered across the board, and sought to play down any impact on the oil deal.

"All the amounts for all ministries and state departments have been lowered," Zebari said. "There are no negative effects on the deal: it is standing and still ongoing."

Under the deal, the Kurds committed to export 550,000 barrels per day (bpd) of oil in return for the reinstatement of budget payments to the region, which Baghdad slashed in early 2014.

Kurdistan's minister of natural resources Ashti Hawrami said in a conference in London on Tuesday that the region had met its target and remained committed to the deal despite receiving only 35 percent of the funds it should have to date.

Baghdad says the region has failed to hand over the volumes they agreed upon to state-run oil marketing firm SOMO.

The Kurds say they have not received the monthly 1.2 trillion dinars to which they are entitled in the 2015 budget and have threatened to sell more oil independently to make up for the shortfall.

Iraqi Prime Minister Haider al-Abadi said in an interview on May 30 that even if the Kurds exported their full share of oil, they could not expect to receive the 1.2 trillion Iraqi dinars to which they say the budget entitles them because it was drawn up when the price of oil was higher.

The Kurds said they exported an average of 577,621 bpd via pipeline to Turkey in May, of which 448,889 bpd was handed over to SOMO.

http://www.reuters.com/article/2015/06/09/iraq-budget-kurds-idUSL5N0YV12F20150609

Production from Iraq's West Qurna Two oilfield is at around 402,000 barrels per day and is expected to rise to 420,000 bpd by the end of the year, senior vice president of Lukoil Overseas Gati Al-Jebouri said at a conference in London.

"There is no more curtailment and we were at 402,000 bpd yesterday so we are very happy and we hopefully will go up to 420,000 bpd by end of the year," he said at a conference in London, adding that was due to the split in exports of Basrah crude grades to heavy and light.

- See more at: http://www.rigzone.com/news/oil_gas/a/139032/Production_from_Iraqs_West_Qurna_Two_Now_at_Around_402000_Barrels_per_Day?rss=true#sthash.t45CyhKF.dpuf

Gazprom has been granted six extra weeks to respond to charges launched by European Union (EU) antitrust regulators that it had abused its dominant market position, the Russian gas giant said on Tuesday.

http://www.upstreamonline.com/incoming/1402568/gazprom-gets-eu-trial-extension?utm_source=twitterfeed&utm_medium=twitter

When OPEC left production unchanged in November last year many understood it to be US or Canadian tight oil producers who would suffer, but thanks to technological advances — to paraphrase Mark Twain — the reports of the death of the tight boom have been greatly exaggerated.

In October 2014, the average new-well oil production per rig in the Bakken was 486 b/d, in the Eagle Ford it was 599 b/d, and in the Permian 207 b/d. In the ensuing seven months to June, the same basins saw new well output per rig increase to 631 b/d in the Bakken, 720 b/d in the Eagle Ford, and 296 b/d in the Permian, according to the EIA’s Drilling Productivity Report.

How did the companies do it? The answers differ from company to company and basin to basin, but there were some common themes.

Several companies reported a reduction in spud to well drilling days, allowing the potential for drilling more wells at the same cost, in turn yielding more production. Oxy has seen a 40% decrease in spud to rig release time in the Wolfcamp area of its Permian holdings from 43 days in 2014 to 26 days in March this year with a target of eventually reaching 16 days, according to the company’s Q1 earnings presentation.

To that end, the company is using a process called “mechanical specific energy” which looks at the formations to be drilled and designs “exactly how much we should do,” said soon-to-be Oxy CEO Vicki Hollub in its earnings call, including “how fast we should rotate the bit and how much weight we should put on it by interval.”

Pioneer Natural Resources is experimenting with efficiencies on several fronts in the Permian. For example, it is modifying the casing design in drilling its core Spraberry/Wolfcamp formation operation. Now in test phase, the technique offers $500,000-$1 million savings per well and shaves off 10-15 days per well, Pioneer officials have said.

Another savings comes from expanded use of dissolvable plugs in the Eagle Ford Shale, the company said. The plugs isolate fracture intervals along horizontal wells, and using them avoids having to drill them out after a well is fractured. The savings is about $300,000 per well and completion time is reduced by three days per well.

The efficiency gains, big and small, are why internal rates of return for basins across the shale-scape are over 10% even with WTI at $50/b, according to Platts’ Bentek Energy calculations. WTI settled at $59.13/b Friday.

Those returns are ultimately what matters and keeps tight oil pumping. OPEC’s actions were a wake-up call, but now the tables have turned and, as ConocoPhillips CEO Ryan Lance warned last week, OPEC needs to prepare for even more competition on the “real possibility” the US crude export ban gets lifted.

http://blogs.platts.com/2015/06/08/north-american-oil-productionincreasing-efficiencies/?hootPostID=3d4990fae9bf42b7b925ef2efa163eda

Business Insider reported that Iraq is committing 27,000 security personnel to protecting its oil and energy industry from the advance of Islamic State.

The Telegraph reports that Iraq's oil minister Adel Abdel Mahdi outlined plans for the new oil army at the Organisation of the Petroleum Exporting Countries meeting in Vienna over the weekend.

Iraq is now the second largest oil producing nation in OPEC after Saudi Arabia and there are fears that ISIS, which operates in parts of Iraq, Syria and Iran, could disrupt supply through terrorist attacks.

The terrorist state could also look to annex more oil resources to help fund its campaigns. It already controls several oil assets in northern Iraq and industry officials estimate ISIS could be making at least USD 1 million a day from oil exports.

Armed forced have been trying to take back key oil fields and refineries from ISIS in Iraq in recent weeks. Iranian and US forces have been working together to try and retake the Beiji refinery in Iraq.

Abdel Mahdi said the final structure of the new oil security forces will be finalised over the next few weeks.

http://steelguru.com/gas-oil/iraq-is-raising-a-new-army-to-defend-its-oil-from-islamic-state/426449#tag

The former boss of British energy company Centrica Sam Laidlaw will head a new $5 billion fund backed by private equity firms Carlyle Group and CVC Capital Partners to buy oil and gas assets worldwide.

The London-based platform, Neptune Oil and Gas, will focus on investing in large-scale fields and companies in the North Sea, North Africa and Southeast Asia struggling in the wake of the sharp drop in oil prices over the past year.

Laidlaw, who stepped down as Centrica's chief executive late last year, said the fund aimed to complete one or two large deal totalling around $5 billion within the next two years to build a new exploration and production (E&P) company of 75,000-100,000 barrels per day, similar to the output of London-based Tullow Oil.

"Very few people have actually invested in scale because there haven't been any large-scale private equity funds really devoted to international E&P," Laidlaw told Reuters on Tuesday.

A raft of oil and gas assets have been put up for sale in recent months as energy firms ranging from majors Royal Dutch Shell and Total to small exploration companies seek to boost balance sheets.

"The timing is good, a lot of the super majors are going through portfolio restructuring and national oil companies might be pulling back because of the lower oil price," Laidlaw said.

Global private equity firms in recent years have formed a number of partnerships led by high-profile industry executives in a bid to turn around assets by introducing efficiencies and cost cutting.

Siccar Point is headed by former Conoco and Centrica executive Jonathan Rogers, while Scotland-based Verus Petroleum is led by Alan Curren, a North Sea veteran with Wood Group and Lundin Petroleum.

"We're expecting to deliver value through improving efficiencies, adding reserves, improving operating uptime and bringing in new technologies to ensure we can deliver a sensitive risk return on that basis," Laidlaw said.

"This isn't a bet on the oil price, because it could be with us for a while," he added, referring to recent lower prices.

http://www.reuters.com/article/2015/06/09/privateequity-energy-centrica-idUSL5N0YV0Q520150609

Bechtel is on track to complete the construction of an additional three liquefied natural gas (LNG) production trains on Curtis Island by the end of 2015, quadrupling Queensland's LNG production.

Bechtel is constructing the state's first three LNG plants, the first in the world to convert commercial quantities of coal seam gas into liquid form ready for export. When complete, the operators of the plants - Queensland Curtis LNG (BG Group), GLNG Plant Project (Santos, PETRONAS, Total & KOGAS) and Australia Pacific LNG (ConocoPhillips) - will produce the commodity for export to their global customers.

"The projects will begin producing LNG in rapid succession over the second half of 2015," said Alasdair Cathcart, Bechtel's global LNG general manager. "It's certainly a time of significant milestones on Curtis Island, as we move though final commissioning and eventually into handover of these projects to the operating teams.  It's all part of a carefully planned program to deliver unprecedented capacity to our customers, further building on our extensive global LNG experience."

Six production trains will be operational when Bechtel hands over the LNG plants to the owner teams for long-term operation. Queensland Curtis LNG Train 1 has been producing LNG since December 2014, filling more than 16 ships with cargo to date. Bechtel is now working on delivering the second train for that project. Concurrently, Bechtel teams on the GLNG and Australia Pacific LNG plants recently introduced gas into their systems and began producing their own power as part of commissioning the first of two production trains on each site. The second production trains on each of these projects are expected to be operational in early 2016.

http://www.prnewswire.com/news-releases/bechtel-ready-to-quadruple-queensland-lng-production-this-year-300095638.html

Argentine state-controlled oil company YPF said Monday it found unconventional gas in the Vaca Muerta shale play in the southern province of Neuquen.

The La Ribera x-1 well is located about 25 kilometers (15 miles) from the town of Añelo and some 90 kilometers (56 miles) from the capital of the province, YPF said in a statement.

"This discovery raises the expectations about the wealth and productivity of the Vaca Muerta formation in areas near those currently undergoing massive development," YPF said.

Initial tests indicate high potential for gas production, the oil company said.

This is the second unconventional resource discovery made in less than a month in Argentina.

YPF said on May 25 that it discovered unconventional oil in Rio Negro, another province in southern Argentina.

YPF announced the discovery of non-conventional oil and natural gas reserves in Vaca Muerta in 2011 after successful results in the exploration phase.

http://latino.foxnews.com/latino/news/2015/06/08/ypf-finds-unconventional-gas-in-southern-argentina/

The federal forecast of U.S. shale production is sinking again for the third month in a row, but the decline is still just a thin layer off the top.

Daily oil production at the nation’s six biggest shale plays is set to slip by 91,000 barrels from June to July, the Energy Information Administration says. That’s roughly 2 percent of the 5.48 million U.S. barrels anticipated next month, hardly the kind of decline oil-industry stakeholders had expected for after drillers sidelined nearly 1,000 oil-drilling rigs in the last six and a half months.

“It’s a pretty resilient industry,” said Bill Herbert, an analyst at Simmons & Co. International in Houston. And given the billions that oil producers have raised this year — they still have generous equity investors waiting in the wings — it’s not inconceivable that crude production could start to rise again early next year, especially with oil prices flirting with the $60-to-$65 a barrel range, Herbert said.

“If you send the right price signals, the oil producers are going to start reinvesting, and production will respond,” he said.

Oil traders are watching the shale industry and Baker Hughes’ U.S. rig count closely to see whether the nation’s production, which helped feed a glut of crude and send oil prices plummeting in the last 12 months, will ease up enough to lift prices again. Despite the falling rig count, not much has changed on the production side of the business, largely because oil companies are moving rigs to the sweetest shale acreage and because their rigs are more efficient, analysts say.

So far, falling production from older, deteriorating wells is outpacing the output from newly drilled wells, especially in the Eagle Ford Shale in South Texas, which is expected to see daily production decline by 49,000 barrels by July. Daily output at the Bakken Shale in North Dakota and the Niobrara formation in Colorado, Nebraska and surrounding states is supposed to fall by 29,000 and 17,000 barrels a day, respectively.

The Permian Basin in West Texas, so far the nation’s stalwart oil patch, still pumping out adding crude, is slipping close the point at which its net production will be in the red. Its month-over-month production is expected to be 3,000 barrels a day by July, the EIA estimates.

West Texas Intermediate, the U.S. benchmark crude, fell 99 cents to $58.14 a barrel on the New York Mercantile Exchange. The international standard, Brent, dipped 62 cents to $62.69 on the ICE Futures Europe.

Meanwhile, the nation’s natural gas production is shrinking in all but the Utica Shale in Ohio. From Texas to Pennsylvania, old wells are expected to bring down gas production by 221 million cubic feet a day, or 0.5 percent of the nation’s gas output.

http://fuelfix.com/blog/2015/06/08/u-s-shale-production-could-fall-again-in-july-eia-says/#31744101=0

Big Star Oil & Gas, LLC  today announced that its first Howard County horizontal well, the Ryder Unit A2H, has been successfully drilled and completed in the Wolfcamp A shale.  The well has a productive lateral length of 7500', and was completed using a 30-stage hybrid hydraulic fracture stimulation.  The well achieved a peak 24-hour IP rate of 1725 boepd (2-phase) and had a 30 day IP rate of 1469 boepd, consisting of average rates of 1358 bopd and 670 mcfd (92% oil).

Based upon production data as reported to the Texas Railroad Commission, the Ryder Unit A2H has achieved the highest reported 30-day average rate of any Howard County Wolfcamp horizontal well to date.  According to Railroad Commission data, Big Star's Ryder Unit A2H well produced 23% more oil and gas in its first month than the previous top horizontal Wolfcamp well, Athlon Energy's Tubb 39 #5H.  The Ryder Unit A2H is also performing significantly above the company's 752 MBOE Wolfcamp type curve.

Bradley Cross, President and Partner, Big Star Oil & Gas, said, "We are pleased with the record results that we have been able to achieve to date.  The successful drilling and completion of our Ryder Unit A2H horizontal shale well strategically positions Big Star among a small population of private, independent oil companies with the technological capabilities and resources to be a top-tier shale player in the Midland Basin."

Big Star is currently completing two additional Howard County horizontal wells, one in the Wolfcamp A shale and one in the Lower Spraberry shale.  The company has identified 207 gross development locations within the Wolfcamp A, Wolfcamp B, and Lower Spraberry shale horizons across its approximately 11,000 net acres of Midland Basin leasehold, and is seeking additional horizontal well development opportunities in the Middle Spraberry and Cline formations.

http://www.newson6.com/story/29267575/big-star-oil-gas-announces-record-results-with-first-horizontal-well

Tuesday skipped publishing monthly data on the average spot prices paid by
buyers in the country for liquefied natural gas (LNG) due to a lack of trades in May, the latest sign of tepid global demand for the fuel.

The LNG market has been struggling with oversupply as Australian projects ramp up output, ahead of more new developments coming online in the United States over the next year.

Japan's Ministry of Economy, Trade and Industry (METI) publishes the price average only when there is a total of at least two spot LNG trades from two companies. A ministry official declined to say whether there had been any trades at all in May.

This marks the first time that no prices have been published since Tokyo started surveying spot LNG prices in March 2014, looking to add transparency to the market amid concerns about rising fuel costs in the wake of the shutdown of nuclear plants after the Fukushima crisis.

Earlier METI data had shown that spot LNG contracted in April for delivery to Japan averaged $7.60 per million British thermal units (mmBtu), down from $8 the month before, less thanhalf the level a year ago.

Asian spot liquefied natural gas (LNG) prices for July were broadly stable late last week as lower production from some export plants still left plenty of supply to meet weak global demand.

The trade ministry survey looks at samples of fixed prices for LNG sold to power companies and utilities among others, and excludes spot deals linked to benchmark prices such as the U.S. natural gas Henry Hub index.

The following table lists monthly prices for LNG per million British thermal units for spot cargoes contracted during the month and those that arrived during the month.
   
  Year   Month   Contract price   Arrival price
  2015     May              n/a             n/a
  2015   April            $7.60           $7.90
  2015     Mar            $8.00           $7.60
  2015     Feb            $7.60          $10.70
  2015     Jan           $10.20          $13.90
  2014     Dec           $11.60          $15.10
  2014     Nov           $14.40          $14.30
  2014     Oct           $15.30          $12.40
  2014    Sept           $13.20          $11.30
  2014     Aug           $11.40          $12.50
  2014    July           $11.80          $13.80
  2014    June           $13.80          $15.00
  2014     May           $14.80          $16.30
  2014   April           $16.00          $18.30
  2014   March           $18.30             n/a

http://www.reuters.com/article/2015/06/09/lng-japan-spot-idUSL3N0YV1OY20150609

The proportion of distillate cargoes making their way to the Mediterranean from the US has more than doubled this month from the January-May average, according to data on vessels tracked by Platts, drawn by premiums at a 28-week high over Northwest Europe.

Over the first five months of this year about 25% of USGC-originated cargoes bound for Europe discharged into the Mediterranean. So far this month, 54% have done so.

Meanwhile, Mediterranean ultra low sulfur diesel cargoes climbed to a $9/mt premium above Northwest European cargoes Friday, the widest spread between the two regions since November 24 on the back of supportive buying interest in the south against an oversupplied cargo market in the north.

CIF Mediterranean cargoes were assessed at $14.25/mt over front-month low sulfur gasoil futures Friday while CIF NWE cargoes were at a $5.25/mt premium.

"The Med [diesel] market is balanced and north is oversupplied," a source said Monday.

In the Mediterranean, demand remained strong in eastern destinations and the buying interest displayed in the Platts MOC failed to attract sellers.

Refinery turnarounds in Greece and Israel were contributing to tilt the balance to the short side, with firm seasonal demand emphasizing the tightness, notably in Turkey where Tupras was said to have issued a buy tender for 40,000 mt of diesel Friday.

Gasoil 0.1% demand in the Mediterranean has been a significant contributor to the market strength and the pull for distillate cargoes from the US, sources said.

http://www.platts.com/latest-news/oil/london/us-distillate-cargoes-arrive-in-mediterranean-26116567?hootpostid=1cabc6bf69addc47c6e153967a681147

The Aphrodite natural gas field off Cyprus is commercially viable and plans call for producing 8 billion cubic metres (bcm) a year and construction of a pipeline to Egypt.

Cyprus, which required an international bailout in 2013, is hoping for an economic turnaround based partly on offshore reserves.

Texas-based Noble Energy and Israel's Delek Group discovered the deposit, estimated to hold 128 bcm of gas, in Cyprus's offshore Block 12 in 2011. It also contains 9 million barrels of condensate.

Plans call for a floating production storage and offloading vessel (FPSO) to process 8 bcm of gas a year and the construction of underwater pipelines connecting the well to Cyprus and Egypt, Delek said in a statement.

The planned Egyptian exports were made possible by a cooperation agreement the countries signed in February, Delek said, adding that the partners would submit their plans to the Cypriot government in the near future.

Noble is the project operator with a 70 percent stake. Delek, through two subsidiaries, holds the remaining 30 percent, but is in early-stage talks to buy an additional 19.9 percent for about $155 million.

Cyprus is seeking to develop its energy sector to bolster an economy that relies mostly on tourism, business services and shipping. The island has, for now, shelved plans to create its own liquefied natural gas terminal.

http://in.reuters.com/article/2015/06/07/delek-noble-cyprus-idINL5N0YT03C20150607

In a new two-part study, Wood Mackenzie explores the implications of the current low oil price for upstream fiscal terms. Governments dependent on oil taxation income are wrestling with lower oil revenues for public spending and pressure from oil and gas companies for more lenient terms.

Wood Mackenzie's analysis of fiscal changes from 2014 to date concludes that while there has been much talk of fiscal change in response to low oil prices, only a few governments have followed through, most notably the UK, which has made the most extensive changes, encompassing all assets.

"Governments which are less dependent on oil tax for income can afford to play the long game and will be more likely to reduce tax rates or introduce incentives to try to maintain investment while companies cut back on new projects elsewhere. However, their ability to do this may be restricted by contracts with oil and gas operators, which insist that the fiscal terms remain as they are," Kellas added.

Regressive fiscal terms—such as royalty, export duty, cost recovery ceilings and indirect taxes—have the most negative impact on future investment decisions. These are the most obvious targets for fiscal changes, especially in systems where the minimum government share of revenue is particularly high. Equally, high marginal tax rates reduce companies' interest in incremental opportunities and may need to be lowered, or other allowances introduced.

"It's important to note that governments facing declines in oil production would be considering how they can stimulate investment in any circumstances, and depressed oil prices makes this task more difficult and more necessary. Indonesia, in particular, may need to offer more attractive terms to try and stem its expected decline in oil production. Fiscal incentives for new investment—particularly challenging projects such as unconventional resources—are likely to become common," Kellas said.

In fact as Wood Mackenzie's study shows, several countries were already in the process of reviewing their fiscal terms before the oil price plunge, but this is an added complexity.

"Governments now launching exploration licensing rounds face stiff competition in what is a buyers' market. The fiscal terms on offer will play a critical role in determining how attractive the opportunities are perceived," Kellas concluded.

OPEC must live with the reality of oil prices remaining well below $100/barrel, a level the market no longer recognizes, OPEC secretary general Abdalla el-Badri said as the oil producer group maintained official output at 30 million b/d for the next six months.

Badri stopped short of saying how this new reality might translate to actual price levels. Brent crude appears to have found a trading range -- for the time being, at least -- of $60-$65/b, although this falls considerably short of the $75-$80 suggestions from ministers polled over the past few days in Vienna.

Indeed, current Brent prices are closer to the $65/b plus-or-minus $2-$3/b preferred by key consumer India.

"Now the cycle is down, we have to live with it," Badri told a press conference. "We have to adjust to the new reality. The market does not recognize $100 anymore."

In a communique, OPEC said the sharp decline in oil prices caused by oversupply and speculation had now abated, with prices moving higher in recent months.

But it also noted that stock levels "lie well above the five-year average in terms of absolute volumes, indicating that the market is comfortably supplied."

Member countries, OPEC said, had "confirmed their commitment to a stable and balanced oil market, with prices at levels that are suitable for both producers and consumers," but did not define a suitable price.

Iranian oil minister Bijan Zanganeh, however, said most members believed that $75/barrel was reasonable.

But still smoldering away below the surface are the tensions that run along the fault lines of OPEC's geographical and geopolitical map.

These tensions continue to separate the richer members from those without the financial wherewithal or production capacity to help them ride the tide of what could turn out to be years of below-breakeven prices as world oil markets re-balance alongside changing supply patterns.

OPEC may be congratulating itself for having, through its November decision not to cut output despite the oil price plunge, dealt a blow to US shale oil production, which is now growing more slowly.

Over the longer term, though, shale is likely to continue to challenge OPEC, especially if the United States government decides to allow the export of light crude.

http://www.platts.com/news-feature/2015/oil/opec-guide/index?hootpostid=9780c4aab55e759c885c895317bfc24d

The US New Orleans jury has acquitted BP exploration former vice-president David Rainey of lying about the quantity of oil that spilled into the Gulf of Mexico following the explosion of the Deepwater Horizon rig in April 2010.

The US Government filed the case based on David Rainey's statement given to FBI and US Environmental Protection Agency (EPA).

Justice Department lawyer Robert Zink told Reuters that the text messages and testimony from witnesses proved that Rainey understated the flow rate intentionally.

According to Zink, Rainey termed a 5,000-barrel-a-day estimate as BP's 'best scientific guess' at the flow rate and sent it to Congress on 24 May 2010.

The Department of Justice said that a group of government and independent scientists assessed the situation and concluded that a total of over 60,000 barrels per day of oil leaked.

Following the rig explosion, BP said that approximately 1,000 barrels of oil per day were flowing into the Gulf of Mexico.

Rainey's lawyer Reid Weingarten was cited by Reuters as saying that the prosecutors could not prove Rainey will lie to investigators.

"Under the Clean Water Act, BP is facing up to $13.7bn in penalties."

In 2012, the company paid a $4bn settlement to the US and has also put aside $43.8bn to pay for the disaster.

In a regulatory filing in April, BP said it already paid more than $28bn in response, cleanup and compensation. Under the Clean Water Act, BP is facing up to $13.7bn in penalties.

http://www.offshore-technology.com/news/newsus-jury-acquits-bps-executive-of-lying-about-2010-deepwater-horizon-oil-spill-quantity-4595468

Nigeria can boost its oil and gas production by changing the way capital investments are funded in its joint ventures with energy companies, according to Seplat Petroleum Development Co.

State-owned Nigerian National Petroleum Corp., or NNPC, holds an average 55 percent stake in five joint ventures with Royal Dutch Shell Plc, Exxon Mobil Corp., Chevron Corp., Total SA and Eni

SpA that pump more than 80 percent of the country’s crude. It pays the same share of capital contributions for the operation of the oil ventures.

Seplat, a Nigerian producer now running a joint venture with NNPC after buying assets sold by Shell, wants the current funding arrangement in Africa’s biggest oil producer scrapped in favor of a method less dependent on the government.

The “cash call” requirements are a “constraint” affecting production, Ambroise Orjiako, the company’s chairman, said in a June 5 interview at the World Economic Forum Africa in Cape Town.

“We need to find a situation where the joint-venture partners sit down and agree on what percentage of production should be dedicated on operation and capital expenditures,” Orjiako said.

“That way you ensure that growth in the industry is guaranteed, that the production will increase, that the reserves will be increased and that there will be room for exploration activities as well,” he said.

The Nigerian government struggles to meet its share of funding to the operation of the joint ventures with energy companies, thereby limiting the scope for increasing production. It is currently indebted to companies including Shell, Exxon Mobil, Total and Eni, which had provided loans in the past to fill the funding gap.

“We would like to see government also thinking about divesting some of its joint-venture assets such that the private sector will drive the industry,” Orjiako said.

https://www.energyvoice.com/oilandgas/79709/nigeria-could-boost-oil-output-with-changed-funding-seplat-says/

Cyprus government has welcomed Noble Energy’s declaration of commerciality of the “Aphrodite” natural gas offshore field.

Noble Energy operates a license for the exploration of hydrocarbons in Block 12 of Cyprus’ Exclusive Economic Zone (EEZ). Other partners are Delek Drilling Limited Partnership and Avner Oil Exploration Limited Partnership.

The declaration of commerciality confirms the existence of substantial recoverable natural gas reserves in exploration Block 12 of Cyprus’ EEZ.

According to the government, the declaration constitutes a significant milestone to Cyprus’ transition from the hydrocarbons exploration phase to that of exploitation.

The submission to the Cypriot Government of a Development and Production Plan for the “Aphrodite” field will follow.

The Development and Production Plan is expected to include the Licensees’ proposal with regard to the method and the timeline for development and production, as well as the planning for the sales and marketing of the hydrocarbons produced. The Plan is subject to final approval by the Government of Cyprus.

If and when an agreement is reached and the Plan is approved, the Council of Ministers will be called upon to grant the Licensees the relevant Exploitation License.

http://www.offshoreenergytoday.com/aphrodite-gas-discovery-declared-commercial-cyprus/

Thousands of activists filled along the state capitol lawn to rally against pipeline and fossil fuel infrastructure projects that would accelerate development of the tar sands oil fields in Canada.

Regulators approved a certificate of need Friday for the Sandpiper from North Dakota's Bakken Oil fields to Superior, Wisc.

The hot topic was what else flows south, in this case, out of North Dakota andCanada.

Activists came to St. Paul from across the Midwest for one giant mega rally to oppose oil drilling and the tar sand fields of Canada, which they all say are doing a lot of damage.

Calgary, Alberta-based Enbridge argued that Sandpiper is necessary to move the growing supply of North Dakota crude safely and efficiently market.

There's so much oil being found to the north, which is going to keep this as a hot topic for a while.

“Bringing in really toxic oil is a little bit suicidal it's kind of scary.” Susu Jeffrey said.

The Sandpiper Pipeline being approved was only step one, the commission voted that the 610 mile pipeline is needed and in the public interest, the next step is to figure out where it should run, which could take a while.

http://www.myfoxtwincities.com/story/29257011/thousands-fill-downtown-st-paul-to-rally-against-proposed-sandpiper-pipeline

The US drilling rig count dropped 7 units during the week ended June 5 to settle at 868 rigs working, according to data from Baker Hughes Inc.

For the second straight week, the decline represents the second-smallest of the now 26-week slump, during which time the count has lost 1,052 units. Compared with this week a year ago, the count is down 992 units.

During the week, oil-directed rigs dropped 4 units to 642, down 967 from a recent peak on Oct. 10, 2014, and 894 year-over-year. Gas-directed rigs dropped 3 units to 57.

Land rigs declined 7 units to 837, down 960 year-over-year. Representing its smallest decline of the year, rigs engaged inhorizontal drilling edged down a unit to 673, down 699 from a recent peak on Nov. 21, 2014, and 577 year-over-year. Rigs drilling directionally jumped 6 units to 96.

Offshore rigs dropped 2 units to 27, down by more than half since the beginning of the year and year-over-year. Rigs drilling in inland waters doubled to 4.

After jumping 26 units last week, Canada’s rig count added 18 more to reach a total of 116, down 98 year-over-year. The rise was again boosted by a 15-unit jump in oil-directed rigs to 59. Gas-directed rigs gained 3 units to 57.

The average Canadian rig count for May was 80, down 10 from April and 82 from May 2014. All units laid down were on land.

A 5-unit loss to 364 in Texas represented the largest of the major oil- and gas-producing states. That downward movement was carried by a 7-unit drop in the Eagle Ford to 103. The state is now down 542 units since a recent peak on Nov. 21, 2014 and 532 units year-over-year. The Permian, however, edged up a unit to 233.

New Mexico and Colorado each lost 2 units to 46 and 39, respectively. North Dakota, Pennsylvania, Ohio, and Arkansas each edged down a unit to respective totals of 76, 46, 22, and 5. Arkansas’ total is its lowest in a decade.

Unchanged from a week ago were Oklahoma at 106, Wyoming at 22, Alaska at 10, and Utah at 7.

http://www.ogj.com/articles/2015/06/bhi-us-rig-count-continues-steady-but-shrinking-decline.html

Russia will begin importing Iranian oil under a long-heralded oil-for-goods barter arrangement in the coming week, Iran's oil minister was quoted as saying, more than a year after negotiations began.

The Kremlin announced in April it had begun to implement the deal, in which Iran would export up to 500,000 barrels per day (bpd) of crude oil to Russia in exchange for goods of an equivalent value, but traders said they saw no signs of it.

"We agreed with (Russian Energy Minister) Alexander Novak in Vienna that Russia will buy less than 500,000 bpd from Iran in exchange for cash, and Iran will use this cash to buy Russian goods such as steel, wheat and oil products from Russia."

Iran's oil exports have fallen by more than half to around 1.1 million bpd since 2012, when Western powers imposed sanctions aimed at curbing the Islamic Republic's disputed nuclear programme.

Iran and six countries, including Russia, reached an interim agreement in early April and are working towards a final deal by the end of this month that could see sanctions lifted.

But the two sides still disagree on several issues, and Tehran has been working in parallel to develop what its leaders call a 'resistance economy' that can survive under sanctions.

Sources told Reuters more than a year ago that Iran was working on the barter deal with Russia, which they said could be worth up to $20 billion.

Russia also lifted a self-imposed ban on selling the advanced S-300 surface-to-air missile system to Iran shortly after the interim nuclear agreement, a move criticised by Western powers.

http://www.reuters.com/article/2015/06/07/russia-iran-oil-idUSL5N0YT03D20150607

ConocoPhillips, the U.S. energy company, is withdrawing from shale gas exploration in Poland as it has not encountered commercial volumes of the gas, the company said on Friday.

ConocoPhillips said its subsidiary Lane Energy Poland has invested around $220 million in Poland since 2009. It drilled seven wells over its three Western Baltic concessions.

"Unfortunately, commercial volumes of natural gas were not encountered," Tim Wallace, ConocoPhillips country manager in Poland, was quoted as saing in a statement.

ConocoPhillips was the last major oil company looking for shale gas in Poland, after Chevron withdrawal at the start of this year.

http://www.reuters.com/article/2015/06/05/conoco-poland-shalegas-idUSL5N0YR2MY20150605

No new LNG projects will come online in Africa before 2020 due to falling commodity prices and competition from Australia and the US, where construction has already begun on facilities that will add significant volumes of gas to the market, according to researchers with the International Energy Agency (IEA).

http://www.upstreamonline.com/live/1402310/iea-doubts-near-term-africa-lng-hopes?utm_source=twitterfeed&utm_medium=twitter

Iraq hopes to boost its crude exports to 3.3 million b/d by the end of this year, oil minister Adel Abdul-Mahdi said Friday, though Baghdad has revised down its 2020 crude production target from a previous 9 million b/d to around 6 million b/d.

Speaking ahead of a meeting of OPEC ministers in Vienna, Abdul-Mahdi also said the Kurdistan region had yet to boost northern exports to the agreed level of 550,000 b/d in 2015.

Last month, Iraq's crude exports averaged 3.145 million b/d, up 68,000 b/d from April, marking a record high for the second consecutive month.

"I think we are approaching 3.2 [million b/d] and maybe by the end of the year we will hit 3.3 [million b/d]," Abdul-Mahdi said.

Current Iraqi production is around 3.6 million b/d, according to the latest Platts' estimates.

Asked if Iraq was still hoping to boost production to an ambitious 9 million b/d by 2020, Abdul-Mahdi said he thought that target was "exaggerated."

"I think Iraq is capable of producing at least 6 [million b/d] by 2020. This is our scheduled planned target," he said.

While the majority of the country's production comes from fields in Basra province in the far south, the largest increase in exports has come from northern Iraq.

This followed a January budget agreement that brought some of the independent Kurdistan exports under federal control and allowed for export of previously stranded Kirkuk oil to reach Ceyhan as well.

Under a temporary agreement from December, the KRG is expected to export 250,000 b/d of crude from its own fields in Kurdistan on behalf of Iraq's state-owned SOMO and 300,000 b/d from fields in the Iraq-controlled Kirkuk region via the Turkish port of Ceyhan.

In return, the agreement confirmed that Baghdad would provide the KRG with 17% of the Iraqi national budget.

http://www.platts.com/latest-news/oil/vienna/iraq-capable-of-crude-production-of-at-least-27482474?hootpostid=b1a2b537b2aad30ef84999183c17e015

Russia's Gazprom Neft, the oil arm of gas producer Gazprom, plans to ship 2.7 million tonnes of oil (54,000 barrels per day) to Asia this year, with around a third to China, company executives said on Friday.

Anatoly Cherner, deputy chief executive, also said shipments to China would be settled in the yuan currency, a practice that began last year.

Russian companies and banks, especially those under Western sanctions imposed over Moscow's role in Ukraine such as Gazprom Neft, are trying to limit transactions in U.S. dollars.

Alexander Dyukov, Gazprom Neft's chief executive officer, said the company used most of its yuan revenue for settlements with Chinese contractors.

"We are paying in yuan for machinery which we are getting from Chinese equipment producers. There may be some conversion (of yuan to other currencies) but in general yuan is being used to pay our contractors," Dyukov said.

The company, Russia's fourth biggest oil producer, started to use the yuan as a settlement currency for exports of crude oil and oil products with China last year.

Gazprom Neft's spokeswoman said pricing was still U.S. dollar-based. Gazprom Neft shipped around 1 million tonnes of oil to Asia last year, including China.

http://www.reuters.com/article/2015/06/05/russia-china-gazprom-neft-settlement-idUSL5N0YR1Y220150605

Oil group OPEC agreed to stick by its policy of unconstrained output for another six months on Friday, setting aside warnings of a second lurch lower in prices as some members such as Iran look to ramp up exports.

Concluding a meeting with no apparent dissent, Saudi Arabian Oil Minister Ali al-Naimi said the Organization of the Petroleum Exporting Countries had rolled over its current output ceiling, renewing support for the shock market treatment it doled out late last year when Saudi Arabia, the world's top supplier, said it would no longer cut output to keep prices high. The group will meet again on Dec. 4, Naimi said.

With oil prices having rebounded by more than a third after hitting a six-year low of $45 a barrel in January, officials meeting in Vienna saw little reason to tinker with a strategy that seems to have resurrected moribund growth in world oil consumption and put a damper on the U.S. shale boom.

Naimi, emerging from the talks, said he was happy with the decision. He told reporters ahead of the meeting that he was confident production from marginal fields would fall even at current prices.

"The decision taken in November was the right one," United Arab Emirates energy minister Suhail bin Mohammed al-Mazroui said earlier, referring to OPEC's previous meeting. "It will take time for the markets to rebalance."

Friday's decision defers discussion of several tricky questions set to arise in the coming months as members such as Iran and Libya prepare to reopen the taps after years of diminished production.

Iranian oil minister Bijan Zanganeh had promised to press the group for assurances that other members will give Tehran room to add as much as 1 million barrels per day (bpd) of supply once Western sanctions are eased. But most delegates had seen little reason for Tehran to pick a fight now.

"When the production comes, this matter will settle itself," one OPEC delegate told Reuters. That may not occur until 2016, according to many analysts who question how quickly Tehran will win relief from sanctions and be allowed to sell more crude.

Libya, still afflicted by a crippling civil war, hopes to double production to some 1 million bpd by September if key ports resume working, but past efforts have failed to deliver a sustained recovery in shipments.

"The markets are moving in OPEC's favour," said Dr. Gary Ross, executive chairman of PIRA Energy Group. "Prices are stimulating robust demand growth and slowing capex. This was the objective of the Saudi strategy and it's working."

The U.S. tight oil industry has been more resilient than many had expected, with falling costs helping sustain the revolution and possibly setting up another downward spiral.

http://www.reuters.com/article/2015/06/05/opec-meeting-idUSL5N0YR0BN20150605