Venezuelan state oil company PDVSA has offered Russian counterpart Rosneft a stake in a joint venture in the country's Orinoco Belt extra-heavy crude area, five industry sources said, in a sign of the Latin American nation's dire economic situation and Moscow's growing muscle there.

Rosneft, Russia's top oil producer, has been offered a 10 percent stake in the Petropiar joint venture.

PDVSA, as Petróleos de Venezuela SA is known, has a 70 percent share, and U.S. oil company Chevron Corp (CVX.N) holds 30 percent of the venture, which includes an oil field and a 210,000 barrel-per-day oil upgrader.

Two sources said the offer was part of a larger package offered to Rosneft as PDVSA seeks to raise money to pay suppliers and bond holders.

It is unclear if Rosneft will accept the offer. Financial details of the potential transaction were not immediately available.

PDVSA and Venezuela's Oil Ministry did not respond to requests for comments. Chevron and Rosneft declined to comment.

A deal would see California-based Chevron working alongside state-owned Rosneft, which has been affected by U.S. sanctions against Russia.

But Chevron's main concern is that accounting and transparency laws are less strict in Russia than in the United States, a source close to the matter said.

The proposal highlights Venezuela's need for cash after the nation's oil output fell about 10 percent last year, according to the Organization of the Petroleum Exporting Countries. This has worsened a recession that has millions of Venezuelans skipping meals amid food shortages and spiraling inflation.

The opposition-controlled National Assembly says President Nicolas Maduro's unpopular government is resorting to surreptitiously selling strategic assets to weather the unprecedented crisis.

"Any deal of national interest must be approved by the National Assembly," tweeted lawmaker Jose Guerra, head of congress' finance commission, in reaction to Reuters' article. "If PDVSA sells 10 (percent) of Petropiar to Rosneft, that sale is null and void."

MOSCOW'S MUSCLE

Rosneft has already been gaining ground in Venezuela, an OPEC member.

Last year, the company paid $500 million to increase its stake in the Petromonagas joint venture from 16.7 percent to 40 percent, the maximum foreign partners are allowed to have under oil sector regulations created under late leader Hugo Chavez.

"The ballpark value of the two projects (Petromonagas and Petropiar) probably isn't that different," said Francisco Monaldi, fellow in Latin American energy policy at the Baker Institute in Houston.

The Petromonagas sale also raised the ire of the National Assembly, which said the purchase was illegal because Congress did not approve it. Critics have also said the stake was sold too cheaply.

In another controversial move, PDVSA last year used 49.9 percent of its shares in coveted U.S. subsidiary Citgo as collateral for loan financing from Rosneft.

PDVSA said this month it had received $1.985 billion from an unnamed client in return for future oil shipments, with Citgo shares used as a guarantee.

In total, Rosneft has lent PDVSA between $4 billion and $5 billion, but the details of those deals have not been disclosed.

"We must thank life that Russia and the world have a Vladimir Putin," Maduro said at a deal-signing event with Rosneft head Igor Sechin last year.

"I wanted to be here at this event because of how important relations with the new Russia are."

http://www.reuters.com/article/us-venezuela-pdvsa-rosneft-idUSKBN16N2E9

Halfway into an OPEC-led oil supply cut, Asia remains awash with fuel in a sign that the group's efforts to rein in a global glut have so far had little effect.

The Organization of the Petroleum Exporting Countries (OPEC) and other suppliers including Russia have pledged to cut production by almost 1.8 million barrels per day (bpd) during the first half of this year to rein in oversupply and prop up prices.

Yet almost three months into the announced cuts, oil flows to Asia, the world's biggest and fastest growing market, have risen to near record highs.

The Asian surplus will pressure global oil prices and weigh on the budgets of major oil producing nations but may also help spur growth in demand needed to soak up the excess.

Thomson Reuters Oil Research and Forecasts data shows around 714 million barrels of oil are being shipped to Asia this month, up 3 percent since December when the cuts were announced.

Responding to rising production, benchmark crude prices are down 10 percent since January, and analysts warn that more falls could follow.

"Cuts are not enough to re-absorb the world's excess supply. So, unless oil demand growth rebounds to record levels in 2017, oil prices could head for another substantial fall," said Leonardo Maugeri, senior fellow at the Harvard Kennedy School's Belfer Center for Science and International Affairs.

Not only are supplies from the Middle East and Russia to Asia still high despite the pledge to cut, but record volumes are flooding into Asia from the Americas and Europe.

The result is a market awash with fuel. More than 30 supertankers are sitting off the coasts of Singapore and southern Malaysia filled with oil, despite a price structure that makes it unattractive to buy oil now and store it for sale at a later date. Crude for delivery in January 2018 is only 70 cents more expensive than that for delivery next May, making those floating storage vessels unprofitable.

OPEC'S DILEMMA

The ongoing glut poses a predicament for OPEC. Its members need higher oil prices to balance government budgets, but cutting back production to prop up prices means losing market share as other suppliers step in to fill the gap.

OPEC's cuts early in the year pushed up Middle East Dubai crude price against the international benchmark Brent, allowing oil from outside the Middle East to head to Asia.

Traders are shipping competitively priced crudes such as Russian Urals, Kazakhstan's CPC Blend, North Sea Forties and U.S. West Texas Intermediate to replace Middle East staples from Oman to Abu Dhabi.

A record 10.5 million barrels of Russian Urals will arrive in Asia between April and June, Eikon data shows.

Oil from Kazakhstan, the North Sea, Brazil, and the United States arriving in Asia in March is expected to reach 45 million barrels, double the volume in the same month a year ago.

"The uptick in arbitrage has not gone unnoticed by the large Middle Eastern (OPEC) producers," analysts from consultancy JBC Energy said in a note to clients this week.

In a move to beat off competition but which contradicts the announced cuts, OPEC's de-facto leader Saudi Arabia unexpectedly cut light crude prices last week.

State-owned Saudi Aramco has also given additional supplies to Asian customers in April, trade sources said.

Stiff competition and ample supplies have depressed prices for Middle East and Asia-Pacific grades, some of them to multi-month lows.

May-loading for Qatar Marine crude sold at discounts to its official selling price for the first time in four months while spot premiums for Russian and Malaysia's flagship Kimanis crude have also hit lows.

With few signs that producers will cut supplies deeply enough to end the glut, and indicators that output is rising in the United States, traders say only strong demand can eventually rein in the surplus.

"Demand growth in Asia is about 700,000 bpd, so the glut will eventually clear," said Oystein Berentsen, managing director for oil trading company Strong Petroleum in Singapore.

Not all are as confident.

"Enduring excess supply could be eased by a robust demand growth," said Maugeri of the Belfer Center. "But preliminary data and analyses do not portend such a development, especially because of a significant slowdown in demand growth in China and India - the two major engines of world oil consumption growth."

http://www.reuters.com/article/us-asia-oil-analysis-idUSKBN16O07Z

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Attached Files

The fire at Syncrude Canada's oil sands plant in northern Alberta was extinguished on Thursday morning, the company said in a statement, as parts of the mining and upgrading facility ran at reduced rates.

Syncrude said crews were still working to fully isolate the affected area of the Mildred Lake upgrader to allow safe entry to assess damage and development a repair strategy. The upgrader processes mined bitumen into refinery-ready synthetic crude

Other operations remained stable at the 350,000 barrel per day mining and upgrading facility, roughly 40 kilometres north of the oil sands hub of Fort McMurray.

Several upgrader units were shut down or running at reduced rates, while mining and extraction were being paced to balance lower bitumen demand, the company said.

Syncrude spokesman Will Gibson said he did not have details of the impact on production volumes.

The fire broke out on Tuesday afternoon after a line failure caused a treated naphtha leak, prompting an evacuation of the Syncrude site. One worker was injured and was at an Edmonton hospital, in stable condition.

Syncrude is majority-owned by Suncor Energy, while Imperial Oil provides operational, technical and business management support.

http://www.reuters.com/article/canada-syncrude-fire-idUSL2N1GT1B2

The Interior Department is weighing Eni SpA’s request to explore for oil in waters north of Alaska, giving the Trump administration a chance to reverse course from former President Barack Obama’s attempt to curtail Arctic drilling.

Eni’s exploration well would be in an area it previously leased from the federal government, and so it isn’t covered by the executive order Obama issued in December to block the sale of new drilling rights within huge swaths of the Chukchi and Beaufort seas. As the Trump administration considers ways it could reverse Obama’s directive, approving this plan could encourage more oil companies to consider Arctic exploration.

Although some oil companies have abandoned plans to launch expensive quests for crude off Alaska’s coast, recent discoveries have fanned interest in waters near the shoreline that can be drilled at a lower cost.

The Bureau of Ocean Energy Management is conducting an initial, 15-day review of the broad drilling blueprint filed by Italy’s Eni, which is aiming to sink a well in the federal waters of the Beaufort Sea before its leases expire at the end of the year.

If the bureau deems Eni’s broad exploration blueprint complete, it would publish the document online and subject it to public comment while scrutinizing the plan’s details in a 30-day review.

"By the end of the 30-day period BOEM will either approve the exploration plan, require modifications to the exploration plan or disapprove the exploration plan," bureau spokeswoman Connie Gillette said in an email. Before it could launch operations on its proposed Nikaitchuq North well, Eni also would have to win a drilling permit from the Bureau of Safety and Environmental Enforcement and secure other government approvals.

Eni already uses a man-made gravel island to extract oil from leases in state waters hugging Alaska’s coast. Under its plan, the company would would use that same site -- known as Spy Island -- as a launching pad for extended-reach drilling that would target a potential oil reservoir in nearby federal waters.

Eni, the lead operator on the project, owns 40 percent of the 13 leases set to be affected by the plan. Its partners are Royal Dutch Shell Plc, which also has a 40 percent share, and Spain’s Repsol SA, which claims the remaining 20 percent.

In an emailed statement, Eni said it was planning to begin drilling by the end of the year. Eni could cite its proposed oil exploration in trying to convince federal regulators to issue a "suspension of operations" that would effectively extend its leases there.

In February, the safety bureau approved Eni’s bid to consolidate 13 of its federal leases in a single unit -- a decision that could make it easier to prolong the life of all of them if drilling began in any one of those tracts.

Still, U.S. law is designed to push oil companies to diligently develop their holdings -- and it sets a relatively high bar for granting time-outs. Eni’s targeted leases have already been suspended before -- some for roughly four years. Federal law does not give the Interior Department authority to issue blanket extensions and requires companies to lay out a specific plan for developing leased acreage in order to get more time.

Environmental Opposition

"Eni and the federal government must be cautious and responsible," said Michael LeVine, Pacific senior counsel for the conservation group Oceana, which closely monitors Arctic development. "The leases Eni owns have sat dormant for more than a decade and have already had their expiration dates extended in the past. There is no compelling reason to extend the leases again or to rush to grant last minute approvals."

Under Obama, the Interior Department rejected bids by Shell and ConocoPhillips to extend the life of other Arctic leases. Shell initially appealed the decision but later dropped the effort after a challenge from environmentalists.

Environmentalists argue the risks of Arctic drilling are too high -- potentially imperiling the seals, whales and walruses that live in the region as well as the Alaska Natives who live off those resources. Government auditors have warned that icy conditions, dark days and sparse infrastructure could make it impossible to adequately sop up a spill in the region.

27 Billion Barrels

Obama cut Arctic tracts from a five-year leasing plan issued last year, and issued a sweeping order that withdrew almost all U.S. Arctic waters from future sales. Neither action affects existing leases, such as that held by Eni. Trump is weighing how to reverse both of Obama’s moves, according to Alaska Senator Lisa Murkowski.

The U.S. Arctic is estimated to hold 27 billion barrels of oil and 132 trillion cubic feet of natural gas, but energy companies have struggled to tap resources buried below the remote, icy waters at the top of the globe. Shell spent more than seven years and roughly $8 billion trying to find a large stash of crude in the Chukchi Sea, but it abandoned that quest in 2015 after a series of embarrassing mishaps and a test well yielded disappointing results.

A different scenario is playing out closer to the coast, where recent discoveries -- and the prospect of far lower development costs -- may be luring oil companies. Caelus Energy Corp. claimed to have found at least 2 billion barrels of recoverable oil far beneath northwestern Alaska’s Smith Bay in 2016. And Repsol just announced a 1.2 billion-barrel discovery on Alaska’s North Slope.

https://www.bloomberg.com/news/articles/2017-03-16/trump-weighing-eni-bid-to-drill-in-arctic-waters-after-obama-ban

India has permitted coal bed methane (CBM) producers to sell gas at the market rate, a government statement said on Wednesday, a move that could help companies such as Oil and Natural Gas Corp and Reliance Industries.

The producers can also now sell CBM gas to their affiliates if they are unable to find any other buyer, the government statement said.

The government will announced a price for CBM gas, which will be used as a floor for calculating its royalty and other charges.

But CBM producers will pay royalties and other dues to the government on the basis of sale or market prices, if it is higher than the official rate, the statement added.

http://www.reuters.com/article/india-coalbedmethane-idUSL3N1GS4QX

The regional government of semi-autonomous Iraqi Kurdistan appears to be struggling to maintain the quality of its oil exports, just as it has signed a landmark supply agreement with Rosneft aimed at opening up new markets for Kurdish crude.

The problem surfaced last month in a regulatory filing by Gulf Keystone Petroleum, which produces heavy crude from Kurdistan's giant Shaikan field, disclosing a Kurdistan Regional Government decision to stop accepting Shaikan crude for blending into pipeline exports of Kurdish crude for delivery to the Turkish Mediterranean oil terminal at Ceyhan.

Instead, the KRG has agreed to shoulder the cost of transporting Shaikan crude by truck for onward export as a stand-alone product and to continue paying Gulf Keystone a flat $15 million/month for current and past exports, the company said.

Kurdish officials said the action was taken to preserve the quality of the crude exported by pipeline.

The main problem for the KRG, however, is unlikely to be solely the low API and relatively high sulfur content of Shaikan crude, which so far has been pumped in limited quantities -- recently at a rate reported by Gulf Keystone of about 37,000 b/d.

More likely, the KRG's unexpected decision to exclude Shaikan crude from the export pipeline reflects much bigger problems for the regional government in coping with a large drop in output from one of Kurdistan's major producing fields, compounded by delays in bringing new fields onstream.

Taq Taq, a field operated by a joint venture between Genel Energy and Sinopec, is one of two major fields that for the past several years have been the mainstays of Kurdish light crude oil production. The other is DNO-operated Tawke.

Until last year, the two fields had similar prospects, with reserves in each case estimated at over half a billion barrels and long-term prospects of expanding production to 200,0000 b/d.

But their fortunes diverged sharply in late February 2016, when Genel stunned investors by slashing its estimate of Taq Taq's initial proven and probable reserves by nearly half, to 356 million barrels from 683 million, with gross remaining 2P reserves as at December 2015 of only 172 million barrels.

The company also indicated output from the field could shrink to as little as 50,000 b/d by 2018 from the then-expected average for 2016 of 80,000 b/d.

Last year, Tawke's output averaging 107,000 b/d easily outstripped Taq Taq's actual average output of only 60,000 b/d. As at December 31, 2016, Tawke still had 504 million b of proven and probable reserves.

Tawke production continues to trend upwards but only gradually, and certainly not by enough to offset the big decline from Taq Taq. It averaged 110,000 b/d in December 2016, DNO reported.

The other main source of crude contributions to the KRG's piped export stream is northern Iraq's major Kirkuk field, which lies in territory disputed between Eribil and Baghdad.

In practice, the administration of the huge field's three oil domes has long been partitioned between the KRG and Iraq's federal government, with the KRG opportunistically strengthening its position following the major Islamic State group insurgency in mid-2014.

But the Kirkuk field, which gave its name to northern Iraq's Kirkuk export crude grade long before the underdeveloped Kurdistan region started its own oil exports, is a source of medium-heavy crude.

Beginning in the era of late Iraqi dictator Saddam Hussein, Kirkuk's crude has been made heavier by the injection of large volumes of excess heavy fuel oil into the reservoir -- an unwanted by-product from ageing Iraqi refineries.

TON OF TROUBLE

All this adds up to a ton of trouble for the KRG, which has struggled to pay its oil contractors and staff following Baghdad's suspension of federal budget transfers to the region in early 2014, and the crash in oil prices and major IS group insurgency later that year.

The big question now is whether sufficient new sources of Kurdish light crude can be developed fast enough to offset Taq Taq's decline, allowing the KRG to shore up its reputation as a reliable exporter of a crude blend with Kirkuk grade specs.

Only that, paired with better relations with Baghdad, could help the KRG substantially reduce the hefty discount to other regionally traded crudes at which it currently sells its oil to international buyers.

Certainly there are other Kurdish fields with light crude waiting in the wings. One is Atrush, operated by Abu Dhabi National Energy Co., or Taqa. Another is Gazprom-operated Sarqala, and a third is Kurdamir, on a block operated by Repsol adjacent to Gazprom's license.

Early-stage production has already begun at Atrush and Sarqala, while the partners in Kurdamir plan to file a revised development plan for their field by the end of this year.

With a state-controlled or large international producer leading each development, production from all three fields could in theory be ramped up quickly.

But even major producers and government-backed companies such as Taqa and Gazprom are currently balking at investing heavily in drilling campaigns while they remain deeply uncertain of the KRG's ability to pay for future crude exports.

Even DNO, long entrenched in Kurdistan as an oil producer and currently the biggest producer of the region's crude, has said its investment in further drilling to bring Tawke's output capacity to 135,000 b/d is "contingent on regular and predictable export payments" from the KRG.

After pledging early last year to make prompt and regular monthly payments for contractual volumes of oil delivered for export, the KRG is still running behind on such payments.

DNO and Genel last week reported the receipt from the KRG of $36.73 million for gross December 2016 exports from Tawke and $17.46 million for gross exports from Taq Taq that month. They also received about $10 million in aggregate toward recovery of amounts owed for earlier exports.

The one sliver of good news to emerge recently on the KRG's situation is that the regional government has not hung Gulf Keystone out to dry.

The company last week reported receiving its standard $15 million payment for December exports, indicating the KRG has not yet been squeezed into giving up on prospects for Shaikan's vast store of heavy crude to become a future money-spinner.

But for that to happen in anything sooner than the distant future, the KRG would probably have to build a new pipeline dedicated to heavy crude exports.

Gulf Keystone's previous disclosures on the high cost of transporting Shaikan crude by truck to the Turkish Mediterranean port of Dortyol, as happened until May 2016, mean that any near-term profits from trucked exports of Kurdish heavy crude to the Turkish coast are likely to be marginal.

Still, with Gulf Keystone's cash position standing at just $121.6 million as of last week, the KRG continues to treat the revenue-poor oil developer as a special case, ensuring it just about stays afloat.

Kurdistan's known petroleum resources also include meaningful volumes of condensate in the Khor Mor and Chemchemal fields, for which the Pearl Petroleum consortium, led by UAE affiliates Crescent Petroleum and Dana Gas, hold development contracts.

Much to the partners' disappointment, as indicated in Dana's regulatory filings related to an international arbitration case against the KRG, negotiations with the regional government to start development of Chemchemal, which holds major condensate reserves, have not yet reached fruition.

Pearl currently produces gas from Khor Mor, used as feedstock for two Kurdish power plants, along with LNG and condensate. But those operations, too, are included in the arbitration case, in which Pearl partners also including OMV and MOL have already won a partial settlement award of about $2 billion.

CONDENSATE ADDED TO MIX

Nonetheless, officials at Iraq's federally-controlled North Oil Co. last week told S&P Global Platts gas condensate had been added to the Kirkuk export mix. One official said Khor Mor condensate was being added.

Another official, who did not comment on the source of the condensate, said 10,000 b/d of condensate was being injected into gathering stations, swelling the 168,000 b/d flow of crude being sent for export from northern Iraqi oil fields under NOC control to 178,000 b/d.

Since repeated IS group attacks on Iraq's federal export pipeline put the line permanently out of action three years ago, NOC has been sending limited volumes of crude from Kirkuk and smaller northern Iraqi fields for export through the KRG's pipeline under successive makeshift agreements between Baghdad and Erbil.

While the use of Khor Mor condensate to thin Kirkuk and even Shaikan crude might seem an obvious way for the KRG to control the quality of the crude passing through its export pipeline, the regional government previously suspended that practice over a dispute with Pearl over payments for condensate.

Given the continuing bad blood between the KRG and Pearl over the subsequent arbitration case, the reintroduction of Khor Mor condensate into the export stream points to growing KRG desperation.

Adding to KRG woes is growing anti-government activism by supporters of the opposition Patriotic Union of Kurdistan party, which earlier this month briefly interrupted crude flows from NOC fields when a security force loyal to the PUK took over and temporarily halted operations at a pumping station.

The activists' main complaint was that not enough Kirkuk crude was reaching a refinery near Kurdistan's Sulimaniyah province, where a large majority of voters support the PUK.

Yet another potential problem is a recently signed energy cooperation agreement between Iraq's federal government and Iran, which includes a plan to build a 150 km crude oil pipeline from Kirkuk to Kaneqin, on the the Iranian border, to feed refineries in northwestern Iran.

That pipeline, if built, would bypass the KRG export system and reduce exports from Ceyhan by Iraq's federal State Oil Marketing Organization, thereby lessening KRG political leverage in negotiations with Baghdad.

Unless the KRG could compensate with higher output from the Kirkuk domes under its control, it might suddenly need to accelerate Shaikan's development to avoid deviating too far in the lighter direction from Kirkuk blend specs.

How this will all pan out is far from obvious. The biggest hope on the near horizon for the KRG may be Atrush, which could be developed quickly with the help of Abu Dhabi government resources.

Last week, in an operating and financial statement, junior Atrush partner Shamaran reported that construction of the 30,000 b/d Atrush phase 1 production facility was complete, with final commissioning in progress.

Four production wells had been completed and connected to the production facility, ready for start-up, and work on pipelines to connect the field to the KRG export pipeline was well underway, with completion expected in Q2, the company added.

http://www.platts.com/latest-news/oil/dubai/analysis-iraqi-krg-faces-obstacles-to-maintain-26686863

India’s ministry of the road, transport and highways has given the green light for the use of liquefied natural gas (LNG) as fuel for road vehicles.

Minister Nitin Gadkari told reporters that the LNG has been approved as fuel for vehicles with fueling stations expected to be made available across the country, Press Trust of India reports.

Speaking after an agreement with India’s largest importer of liquefied natural gas, Petronet LNG, Gadkari said the standard for the use of LNG as fuel will be defined by a number of ministries including the ministry of Petroleum.

He added that the wider use of LNG as fuel will reduce the cost of road transport.

Prior to the agreement with the ministry, Petronet LNG signed an agreement with the Inland Waterway Authority of India to set up LNG stations along the inland waterways that will provide fuel for LNG-fueled barges.

Petronet is in the process of preparing a detailed feasibility report for setting up LNG facilities at Haldia, Sahibganj, Patna and Ghazipur on NW-I (river Ganges).

http://www.lngworldnews.com/india-approves-use-of-lng-as-fuel-for-transport/

Brazil’s Petrobras saw its oil and natural gas production in February totaling 2.82 million barrels of oil equivalent per day (boed), with 2.703 million boed produced in Brazil and 113,000 boed abroad.

Average domestic oil output stood at 2.20 million barrels per day (bpd), 1% down on the January figure. This was mainly due to a scheduled stoppage on FPSO Cidade de Paraty in the Santos Basin’s Lula Nordeste pre-salt field, and termination of the Anticipated Production System (SPA) test phase in the Búzios field under the Rights Transfer Agreement.

The SPA was designed to gather information about the behavior of the reservoirs in the oilfield.

In February, production of natural gas in Brazil (excluding liquefied gas) stood at 80.2 million m³/d, 1% down on the previous month, mainly because of a scheduled stoppage on the FPSO Cidade de Paraty.

Pre-salt Production

In February, oil and natural gas production managed by Petrobras (own and third party output) in the pre-salt layer was 1.53 million boed, showing growth of 41% against the February 2016 figure. However, compared to January this year, this figure is represents a 3% drop, which was due to a scheduled stoppage on FPSO Cidade de Paraty in the Santos Basin’s Lula Nordeste pre-salt field, and termination of the SPA test phase in the Búzios field.

Gas and oil production abroad

In February, oil output from oilfields abroad stood at 63.5 million bpd, 8% down on the previous month. Natural gas production amounted to 8.4 million m³/d, 3% down on the January 2017 figure. This was mainly due to operational stoppages in the Lucius and Hadrian South fields in the U.S. because of limitations in the distribution capacity of third-party facilities.

http://www.offshoreenergytoday.com/petrobras-domestic-output-down-of-fpso-stoppage/

Indian Oil Corp (IOC.NS) became India's first refiner to buy light sweet Hibernia crude from Canada's largest oil company, doing the deal after the opening of the arbitrage for Canadian oil to flow to Asia.

A decision by the Organization of the Petroleum Exporting Countries (OPEC) to cut output strengthened Middle East benchmark Dubai against other regional markers, allowing oil from the Americas and Europe to be shipped to Asia at competitive prices.

Production in North America, led by U.S. shale output, is increasing after supply cuts by OPEC and non-OPEC countries pushed oil prices to above $50 a barrel.

This was also the first time that Suncor Energy (SU.TO) has sold a cargo of offshore Canadian crude to IOC, a Suncor spokeswoman Sneh Seetal said on Wednesday.

Seetal declined to say how big the cargo was or when it would load, but confirmed Canada's biggest oil company had won an Indian Oil Corp tender.

"We do market our offshore crude production globally on an opportunistic basis," she said.

Trade sources said Suncor sold the 1 million barrel cargo of Hibernia crude to IOC on a free on board basis. Separately, IOC has also bought its first Russian Urals crude cargo in about a year in another tender.

IOC previously bought a cargo of Canadian White Rose oil in November 2013. State-refiners like IOC were last year given the freedom to draw up the crude import strategies that would allow them to make swift gains from changing market dynamics.

News of the Suncor cargo comes after market sources this week said two other vessels carrying Atlantic Canadian crude are on their way to China.

The Stena Suede and the Jag Lalit, both Suezmaxes, loaded at Whiffen Head terminal, Newfoundland, according to Reuters ship tracking data. At least one of them was sold by Husky Energy (HSE.TO) to buyer PetroChina (601857.SS), two sources said.

Husky had said in February it sold its first one-million-barrel cargo of offshore Atlantic Canada crude bound for China from its White Rose field.

At the time a Husky spokesman said low shipping rates helped make the transaction worthwhile.

http://www.reuters.com/article/us-canada-suncor-energy-cargo-idUSKBN16N0Y8

The chief of the production, exploration and development unit or upstream division, Bernard Looney, has appointed several executives including a new head of production and a new head of drilling, BP told Reuters.

Gordon Birrell, who previously headed BP in Azerbaijan, will become chief operating officer for production, transformation and carbon in the BP upstream segment, reporting to Looney.

Based in London, he will be responsible for global operations, global wells, global procurement, supply chain management and upstream engineering.

He will also be accountable for upstream modernization and lead the development of the upstream approach to a low-carbon future, BP said.

Andy Krieger will become the new head of drilling. Krieger, previously vice-president for drilling in the Gulf of Mexico, will report to Birrell.

The previous head of drilling, Gary Jones, will lead operations in Azerbaijan. The country is a key global growth area where the company wants to expand the giant ACG oilfields and the Shah Deniz gas development.

Jones will report to Andy Hopwood, chief operating officer for strategy and regions in BP's upstream segment.

"Project execution followed by an underlying cashflow inflection will be the key steps (for BP) combined

arguably with oil above rather than below $50 per barrel," analysts from JP Morgan wrote this week after meeting BP's chief financial officer, Brian Gilvary.

They said BP's production growth was due to accelerate through 2017/18, pause thereafter and then see another step-up in 2020/21.

The key start-ups this year are the Zohr gas field in Egypt, Juniper in Trinidad, Khazzan in Oman, Quad 204 in Britain and Persephone in Australia, JP Morgan said.

http://www.reuters.com/article/us-bp-executives-idUSKBN16N1CS

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Attached Files

Brazil's federal audit court TCU on Wednesday allowed state-run oil company Petroleo Brasileiro SA to proceed with its divestment program, but required the company to restart the process except for two projects.

The decision means that moves by Petrobras, as the company is known, to sell off a controlling stake in its fuels distribution unit BR Distribuidora will start from scratch.

Petrobras had been prevented from signing any new asset sales while TCU reviewed its procedures and the court overturned an injunction that suspended sales in December.

The two assets that Petrobras will be able to sell without restarting the process are the rights to operate the Baúna and Tartaruga Verde offshore oil fields, and a share of Petrobras' deepwater rights in the U.S. Gulf of Mexico.

Other assets will have to be sold under new rules that were not immediately made public. Sale decisions will remain the responsibility of the board of directors, through direct negotiations with buyers instead of a bidding process.

Petrobras said in a statement it would follow recommendations by the TCU to improve the divestment process and make it more competitive.

"This decision is fundamental for the company to press ahead with its plan for partnerships and divestments, one of the pillars for reaching its target of reducing leverage," the statement said.

Saulo Puttini, the TCU's infrastructure coordinator, told reporters the new rules will increase transparency and oversight in future asset sales.

Petrobras has sold about 30 assets since 2012 when the divestment program began, Puttini said, noting that another 40 remain to be sold.

The divestment plan has also been held up by an injunction obtained by the Alagoas oil workers union in Sergipe state, Sindipetro-AL/SE. The injunction has blocked the sale of the Baúna and Tartaruga Verde oil fields, the Baúna and Tartaruga Verde oil fields, as well as the inland fields in the states of Ceará, Rio Grande do Norte, Sergipe, Bahia and Espírito Santo.

Petrobras's statement did not mention the oil worker's injunction.

The union's lawyer, Raquel Sousa, said in an interview that the oil workers would not accept the sale of Petrobras assets without a bidding process as provided for by Brazilian law to protect the country's capital.

The injunction in November forced Petrobras to suspend talks with Karoon Gas Australia Ltd on the sale of a 100 percent stake in the 45,000 barrels-per-day Bauna field, in the Santos Basin, and a 50 percent interest in Tartaruga Verde, still in development, in the Campos Basin.

http://www.reuters.com/article/us-petrobras-divestiture-idUSKBN16M3AW

Iraq pumped 4.57 million barrels a day of oil in February and plans to boost output later in the year even as the OPEC member reaffirmed its commitment to the group’s decision to cut production to counter a global glut.

The country plans to increase output to 5 million barrels a day by the end of 2017, Oil Minister Jabbar Al-Luaibi said Wednesday at a news conference in the southern city of Basra. Iraq exported 3.87 million barrels a day from its southern and northern shipment hubs in February, the ministry’s spokesman, Asim Jihad, said in an emailed statement.

Oil prices last week broke below $50 a barrel for the first time since December as rising U.S. shale oil supply muted the impact of reductions in output from members of the Organization of Petroleum Exporting Countries and 11 other nations that started on Jan. 1. Saudi Arabia, the biggest producer in the group, raised production last month, though the kingdom kept output below its ceiling under the cuts agreement and said it moved extra supplies into storage.

The expected increase in shale oil poses a challenge to Iraq, Al-Luaibi said. The country is committed, however, to OPEC’s agreement to pare output to control global oversupply and support prices, the Oil Ministry’s Jihad said in the statement.

The ministry is in talks with Exxon Mobil Corp. to develop the Ratawi and Omar oil fields, which together can produce half a million barrels a day, Hayyan Abdul-Ghani Abdul-Zahra, director general of state-run South Oil Co., told reporters in Basra. Iraq, OPEC’s second-largest producer, also plans to expand exports this year, Abdul-Zahra said.

Missan Oil, another producer in southern Iraq, wants to almost double output to 700,000 barrels a day by 2020 from its current level of 385,000, the company’s Director General Adnan Sajet told reporters in Basra. The Oil Ministry will invite bids to develop three fields in southeastern Maysan province -- Dujail, Kumait and Rifaie -- in the second half of 2017, he said.

https://www.bloomberg.com/news/articles/2017-03-15/iraq-plans-to-boost-crude-oil-production-and-exports-this-year

Our ClipperData show that U.S. crude imports from Saudi Arabia averaged 1.06mn bpd in 2015, and 1.1mn bpd last year. After averaging 1.28mn bpd for the first two months of the year - as a large wave of Saudi crude exported at the end of last year made its way to U.S. shores - volumes have dropped considerably so far this month (hark, below).

The OPEC kingpin has chosen to keep its export loadings strong into East Asia in the first couple of months, to the detriment of the U.S. That said, as Saudi loadings drop off towards East Asia in March, we are seeing a corresponding uptick in crude on the water bound for Uncle Sam.    

We saw a counter-seasonal draw to crude inventories from today's weekly inventory report. This is, however, an anomaly caused by a drop in U.S. Gulf crude imports last week due to poor weather .

Both gasoline and distillate inventories saw solid draws; the trend of stronger implied demand for distillates persists - causing a 4.2mn bbl draw to stocks when we generally see inventories holding steady. After holding at a seasonal record for the first six weeks of the year, a drop in profitability (aka crack spreads) has mired crude inputs for the last five weeks back in the five-year range.

http://blog.clipperdata.com/eia-oil-draw-due-to-lower-imports

Australia’s prime minister Malcolm Turnbull has secured commitments from two of the three Curtis Island LNG projects to contribute to the domestic gas market.

During a meeting with the gas industry representatives on Wednesday, Turnbull said measures were agreed on that will help deliver cheaper and more reliable energy to Australian households and increase gas supplies for businesses.

The two projects that have already committed to boosting the domestic gas supplies are the QCLNG and Australia Pacific LNG while Santos GLNG has taken the matter on notice.

During the meeting, gas producers guaranteed that gas will be made available to meet peak demand periods, among other measures.

Speaking of the agreements, Shell Australia chairman Andrew Smith said that the QCLNG project has already “reduced LNG export shipments to supply additional gas to the domestic market.”

However, he called for the development of additional local supply, especially in Victoria where the government banned conventional and unconventional gas exploration and development.

In addition to LNG projects on Curtis Island near Gladstone, other producers have also agreed to revise their domestic gas production forecasts, while the Australian Energy Market Operator (AEMO) will produce an updated supply outlook.

http://www.lngworldnews.com/australian-pm-secures-gladstone-lng-projects-support-to-domestic-gas-market/

U.S. crude oil refinery inputs averaged about 15.5 million barrels per day during the week ending March 10, 2017, 20,000 barrels per day less than the previous week’s average. Refineries operated at 85.1% of their operable capacity last week. Gasoline production decreased last week, averaging over 9.5 million barrels per day. Distillate fuel production decreased last week, averaging 4.7 million barrels per day.

U.S. crude oil imports averaged 7.4 million barrels per day last week, down by 745,000 barrels per day from the previous week. Over the last four weeks, crude oil imports averaged 7.6 million barrels per day, 4.4% below the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 572,000 barrels per day. Distillate fuel imports averaged 79,000 barrels per day last week.

U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 0.2 million barrels from the previous week. At 528.2 million barrels, U.S. crude oil inventories are above the upper limit of the average range for this time of year. Total motor gasoline inventories decreased by 3.1 million barrels last week, but are in the upper half of the average range. Both finished gasoline inventories and blending components inventories decreased last week. Distillate fuel inventories decreased by 4.2 million barrels last week but are near the upper limit of the average range for this time of year. Propane/propylene inventories fell 0.8 million barrels last week but are in the middle of the average range. Total commercial petroleum inventories decreased by 7.8 million barrels last week.

Total products supplied over the last four-week period averaged 19.8 million barrels per day, up by 0.3% from the same period last year. Over the last four weeks, motor gasoline product supplied averaged about 9.0 million barrels per day, down by 4.5% from the same period last year. Distillate fuel product supplied averaged about 4.2 million barrels per day over the last four weeks, up by 13.4% from the same period last year. Jet fuel product supplied is up 5.6% compared to the same four-week period last year.

Cushing up 2.1 mln bbls

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

                                                   Last Week    Last Year   Year Before

Domestic Production '000.......... 9,109          9,088           9,068
Alaska .............................................. 528              527                517
Lower 48 ...................................... 8,581           8,561             8,551

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

Mexico would require at least 15 upstream oil and gas auction rounds as successful as Round 1 to fulfill the International Energy Agency's production forecast, a Mexican Association of Hydrocarbon Companies, or AMEXHI, study showed Tuesday.

The IEA Mexican Energy Outlook forecast Mexico could produce 2.8 million b/d in 2040, adding the country requires investments of $640 billion to achieve this production level. From that 2.8 million b/d, 2.5 million b/d would come from new projects in 2040.

"This is a titanic effort," said Pablo Zarate, information director of AMEXHI's research center, said at an AMEXHI event Tuesday.

Only 2% of Mexico's total oil production comes from reservoirs that started producing in the last 25 years, Monica Boe, leader of AMEXHI's resource access committee, said at the event.

This is a small amount compared with US' 7%, Venezuela's 8%, and the UK's 35%.

"The amount of new discoveries in Mexico are very low. To reverse this, we need to explore intensively," said Boe.

To achieve the 2.8 million b/d production level, Mexico would require drilling between 20 and 30 exploratory wells and 40 and 50 evaluation wells every year until 2040, said Boe.

Under an investment analysis, Mexico would require investments of $26.6 billion per year.

Zarate said that close to half of the required investment could come from Pemex, which would have to invest $14.3 billion per year, or $300 billion until 2040.

These numbers were calculated under Pemex's investment levels in recent years, said Zarate.

Pemex invested a historical record of $16.6 billion in 2014 with oil prices at $98/b, then invested $9.6 billion in 2015 with prices at $52/b, and $6.5 billion in 2016 with prices at $43/b.

The private sector would have to invest $12.3 billion per year, or $340 billion under this period.

According to Zarate, Mexico would require investments from 15 bid rounds as successful as round 1 to raise the remaining $340 billion.

Mexico Energy Secretariat, or aSENER, predicted Round 1 would bring $41 billion. However, Zarate said after applying an exploratory risk factor, AMEXHI expects a minimum investment level of $20 billion will materialize from the round.

http://www.platts.com/latest-news/oil/mexicocity/mexico-needs-15-successful-upstream-auctions-21157831

European liquefied natural gas (LNG) import terminal operators are constantly searching for new ways to improve capacity utilisation and make it commercially viable for their customers to bring more of the chilled fuel to the continent, Stefaan Adriaens, Commercial Manager at the Dutch Gate terminal told LNG World News in an interview on Wednesday.

Despite overall natural gas demand growth in Europe in 2016, countries such as the United Kingdom, Belgium, and the Netherlands saw a decline in LNG imports as most of the fuel went to better-priced markets in Asia and the Middle East.

According to the LNG data by Gas Infrastructure Europe, utilisation of the total installed capacity at the European LNG import terminals had been critically low during 2016, a trend that is continuing into this year.

The average rate of LNG terminal utilisation in Europe has decreased significantly since 2010 to below 20 percent of the total send-out capacity last year, GIE data shows.

On utilisation of European LNG terminals and Gate, Adriaens said that “for terminal operators booked capacity matters more than actual usage. Also one has to differentiate actual utilisation rates of the jetties, storage and regasification.“

In order to keep their LNG terminals as attractive as possible, European operators have to constantly optimize utilisation at their facilities and foster investments in new LNG infrastructure.

“A common theme (among European LNG terminal operators) has been to add new services constantly, we have done that, and also all other terminals have been doing that,” Adriaens said.

“New services like truck loading, small and large LNG reloads and transshipment increase the optionality of outlets and thus make it a bit more attractive to bring in LNG,” he said.

According to Adriaens, “more than two-thirds of the LNG imported into the Gate terminal left that way over 2016/17.”

Gate terminal in the port of Rotterdam, owned by Gasunie and Vopak, is one of Europe’s largest LNG terminals, with an annual regasification capacity of 12 billion cubic meters – equal to around 180 cargoes per year.

LNG throughput volumes at Gate dropped 26.1 percent to 1.7 million mt last year as compared to 2015.

“We have had only 15 ships unloading instead of 21,” Adriaens said. “On the other hand, we still did 12 large LNG reloads, whilst in 2015 we had 14,” he said, adding that reducing reloads in 2016 was planned by the terminal’s management as the pricing gap all over the globe narrowed making it less economical to ship the fuel elsewhere.

“The year turned out very different than it was anticipated, and we still see the same trend continuing so far in 2017,” Adriaens noted.

Gate has conducted 2 large LNG reloads since the beginning of this year. These volumes landed in 3 destinations, namely Spain, Malta and Turkey.

It has also loaded three smaller cargoes with previously imported LNG with final destinations being Norway and Sweden.

To further boost its reloading business, Gate “may make small investments to increase reloading rates this year,” but this is still under consideration, Adriaens said.

Second customer at third jetty

Gate added an additional jetty in 2016 which enables the loading of small volumes of LNG, from 1,000-cbm up to 20,000-cbm.

The third jetty will help boost the use of LNG as fuel for ships in northwest Europe.

Since the opening of the new facility in late August, 6 vessels in total have docked at the new jetty, according to Adriaens.

“An addition is also that we have a second customer at our third jetty, beside Shell as the launching customer.”

“The second customer started using the jetty this year,” he said without revealing the name of the company.

“Throughout the year, we expect the third jetty to be much more used particularly as we await the Shell bunkering vessel that should arrive in the second half of this year,” Adriaens said.

Shell’s LNG bunkering vessel will be based at the port of Rotterdam and will load from the new berth at Gate. It will deliver the fuel to LNG-powered ships in northwest Europe and other locations.

First U.S. LNG cargo to Gate?

Cheniere’s Sabine Pass liquefaction terminal in Louisana, the first of its kind to ship U.S. shale gas overseas, started exporting the chilled fuel in February last year.

Many predicted a “flood” of U.S. LNG to Europe but only a small number of these LNG cargoes landed in Europe, better said in the southern part of the continent.

The bulk of these cargoes went to Latin America, Africa and Asia.

However, only three liquefaction trains are currently in operation at the Sabine Pass facility and in the lower 48 states. The U.S. is expected to become the world’s third-largest LNG supplier by 2020 with an export capacity of 60 million mt coming from five terminals located along the Gulf Coast.

Talking about the possibility of a U.S. LNG cargo landing at Gate, Adriaens said that “it has not yet happened, but I understand it was a couple of times quite close in decision making… They still rather go to southern Europe than to northern Europe.”

“The moment will come, of course,” he added.

Looking forward, Adriaens said he expects more LNG coming to Europe in 2017 but this will vary throughout the year depending on many factors such as prices and demand in Asia and Latin America.

“There is a lot of LNG available… If European regas is economic, we should see a lot of it, if not – very little,” he said.

http://www.lngworldnews.com/interview-european-lng-terminal-owners-looking-for-new-ways-to-boost-utilization/

Iraq's talks with U.S. oil major Exxon Mobil Corp to develop two small southern oilfields are progressing well, the head of state-run South Oil Co. said on Wednesday.

Iraq has been in talks with Exxon Mobil and PetroChina about investing in a multi-billion-dollar project to boost output from the Luhais, Nassiriya, Tuba, Nahr Bin Umar and Artawi oilfields.

"We have been in talks with Exxon Mobil for more than two years to develop Nahr Bin Umar and Artawi oilfields, and we have managed to reach advanced results," SOC's chief Hayan Abdul Ghani told reporters in the southern city of Basra. He did not elaborate.

http://www.reuters.com/article/us-iraq-oil-exxon-mobil-idUSKBN16M10R

Global oil inventories rose for the first time in January as the market grappled with a swell in production last year, but if OPEC maintains its output cuts, demand should overtake supply in the first half of this year, the International Energy Agency said on Wednesday.

The IEA's monthly report struck a more bullish note than that issued by the Organization of the Petroleum Exporting Countries on Tuesday.

OPEC also flagged rising inventory levels, but raised its estimates for production outside the group and did not see a re-balancing between supply and demand until the second half of this year. 

The IEA said crude stocks in the world's richest nations rose in January for the first time since July by 48 million barrels to 3.03 billion barrels, more than 300 million barrels above the five-year average.

"The actual build in OECD stocks in January reminds us that it may be some time before global stocks start to fall," the agency said.

The increase is the product of "relentless" supply growth in the latter stages of last year, particularly from OPEC countries that pumped at record levels, and from the U.S. shale oil basin, where drilling activity began picking up 10 months ago.

Compliance by OPEC with its agreed output cut of 1.2 million barrels per day in the first half of this year was 91 percent in February and, if the group maintains its supply limit to June, the market could show an implied deficit of 500,000 bpd, the IEA said.

"If current production levels were maintained to June when the output deal expires, there is an implied market deficit of 500,000 bpd for 1H17, assuming, of course, nothing changes elsewhere in supply and demand," the IEA said.

"For those looking for a re-balancing of the oil market the message is that they should be patient, and hold their nerve."

In its October report, before the November agreement between OPEC and some of its competitors including Russia, Mexico and Kazakhstan to limit output, the IEA warned the market risked running into a third successive year of excess supply without any action from the producer group.

SAUDI OUTPUT UP, BUT NO QUOTA-BUSTING

Within OPEC, Saudi Arabia has shouldered the burden of the production cuts, offsetting poorer compliance by other nations.

In February, Saudi oil production staged a monthly rise of 180,000 bpd, but at 9.98 million bpd, its output remained below its agreed target of 10.06 million bpd and, according to tanker-tracking data, Riyadh is focusing its cutbacks on North America, the IEA said.

"At 32.3 million bpd, the call on OPEC crude during the first quarter of 2017 is higher than average output of 31.9 million bpd so far this year, which could lead to a draw in global inventories," the IEA said, adding that it was not clear if the group will extend its supply agreement.

"Beyond the nervousness about this legacy supply and concerns about rising production today from some non-OPEC countries; the implementation of the OPEC production agreement appears in February to have maintained the solid start seen in January."

Saxo Bank senior manager Ole Hansen said the report did not rock the boat as the OPEC report did yesterday.

"As long as OPEC stays on track and non-OPEC delivers on their agreed cuts the market will continue to balance," he said.

Beyond OPEC, oil production rose 90,000 bpd in February, as increasing U.S. output offset declines elsewhere.

Compared with last year, total non-OPEC supply was 285,000 bpd lower, of which the United States accounts for roughly half, the agency said.

"The recovery path of U.S. tight oil is key to rebalancing the oil market over 2017, so is the compliance of the 11 non-OPEC countries that agreed to curb output," the IEA said.

The IEA left its estimate of global demand growth unchanged from its last report at 1.4 million bpd in 2017.

"The market is still dealing with a vast amount of past supply, which will take time to work its way through the system. Meanwhile, demand growth has not provided any further encouragement after three consecutive months when we upgraded our estimates," the IEA said.

http://www.reuters.com/article/us-iea-oil-idUSKBN16M14N

LNG production at Trinidad-based gas liquefaction complex Atlantic LNG totalled 2.2 million cubic meters in January, down 9% year on year, according to a bulletin released Tuesday by Trinidad and Tobago's Energy Ministry.

Production at the Point Fortin, Trinidad, facility continues to be far short of capacity as a result of curtailments by natural gas producers.

The shortfall, caused by upgrades to gas infrastructure and decreased upstream investment by energy companies, is expected to continue through at least this year, according to industry officials.

January LNG sales and deliveries from Atlantic LNG were 52.0 million MMBtu, down 8% year on year, the ministry said.

The company's sales and deliveries of NGLs in January totalled 450,401 barrels, up 2% year on year.

The seven gas producers operating in Trinidad and Tobago produced an average 3.3 Bcf/d of gas in January, down 12% year on year. Gas production typically has averaged between 3.8 Bcf/d and 4.1 Bcf/d in recent years.

The country's LNG sector used 1.8 Bcf/d of gas in January, down 8% year on year, according to the report.

Atlantic operates and manages four LNG trains in Point Fortin, with each train owned by a holding company with various stakeholders. The shareholders are BP, BG, Shell LNG, Summer Soca LNG Liquefaction and the National Gas Co. of Trinidad and Tobago.

http://www.platts.com/latest-news/natural-gas/austin-texas/january-atlantic-lng-production-falls-9-on-year-21157808

PetroChina International has bought crude oil from the US Strategic Petroleum Reserve -- the first such purchase by a Chinese company -- in a move that further underscores growing Chinese interest in US crude.

PetroChina International, the overseas trading arm of state-owned oil giant PetroChina, bought 550,000 barrels from the SPR in the US Department of Energy's latest sale for a total of $28.8 million ($52.36/b).

A Beijing-based senior crude trader with PetroChina International Tuesday said that the deal, announced last week by the US Department of Energy, was not yet completed and they have not decided whether to bring the barrels back to China or send them elsewhere as the volume is small. PetroChina's Houston office would not comment.

"We notice that more and more crude barrels from North America are flowing into China, but we have not decided whether to send this cargo back," he said, declining to comment further.

Deliveries of the crude, both by pipeline and vessel, are expected to take place in May and June, but there may be some early deliveries in April, the US DOE said Friday.

The volume and price of the deal prompted a Shanghai-based analyst to call it a profile-building exercise by PetroChina.

"It will be a milestone and a good headline for a Chinese company to buy [crude oil from] the US SPR," he said.

http://www.platts.com/latest-news/oil/singapore/analysis-china-makes-first-ever-us-spr-crude-27790646

French oil company Total has started up production from the Moho Nord deep offshore project, located 75 kilometers offshore Pointe-Noire in Congo.

Operated by the group, the project has a production capacity of 100,000 barrels of oil equivalent per day, the oil company said on Wednesday.

“Moho Nord is the biggest oil development to date in the Republic of the Congo. A showcase for Total’s deep offshore operational excellence, it consolidates our leading position in Africa,” stated Arnaud Breuillac, President, Exploration & Production at Total.

“Moho Nord will contribute to the reinforcement of the cash flow of the Group and to its production growth.”

The Moho Nord field is developed through 34 wells tied back to a new tension leg platform, the first for Total in Africa, and to Likouf, a new floating production unit. The oil is processed on Likouf and then exported by pipeline to the Djeno onshore terminal, also operated by Total.

According to the company, there will be no routine flaring and the all-electric design improves energy efficiency by optimizing the amount of power needed to run the installations. All the produced water will be reinjected into the reservoir.

Total is the operator of the project with a 53.5% interest. Its partners are Chevron Overseas (Congo) Limited (31.5%) and Société Nationale des Pétroles du Congo (15%).

http://www.offshoreenergytoday.com/total-starts-production-from-moho-nord-off-congo/

Howard Hughes Sr. revolutionised the drill bit to more than 100 years ago to accelerate the oil boom that made Houston and Texas the nation’s energy capital. Today, his legacy company is aiming to make the next evolutionary step with new drill bits that automatically adjust to the underground rock terrain.

The pressure-sensitive technology is part of a growing effort from Baker Hughes and other power players like Schlumberger and Halliburton to build more durable and faster-drilling bits that adapt to any type of shale rock.

Houston-based Baker Hughes on Tuesday launches its TerrAdapt self-adjusting drill bit, which, for the first time, automatically extends diamond-material buttons to provide additional protection to the bit’s diamond cutters when the going gets too rough and retracts them when the rock softens up.

Oilfield services companies used to just modify more expensive offshore drilling technologies to work onshore, but now they’re increasingly developing products specifically for shale rock drilling as the U.S. onshore market increasingly dominates the industry, said Byron Pope, an energy analyst with Tudor, Pickering, Holt & Co. in Houston. After all, horizontally drilled extensions from onshore wells now extend more than 10,000 feet on average.

The new TerrAdapt drill bit that adjusts on the fly is a potential game changer, Pope said. “The difference with the technology is you don’t necessarily have to customize it for the Permian or Eagle Ford,” he said. “You can just have that one bit.”

http://fuelfix.com/blog/2017/03/14/baker-hughes-introduces-mart-drill-bit/

Inpex's $37 billion Ichthys Australian liquefied natural gas project was hit by another subcontractor dispute, involving the termination of more than 600 workers, but the Japanese company said it was still on schedule for a July-September start.

Members of a consortium building LNG storage tanks at the onshore site of Ichthys near Darwin are in dispute with each other and have stopped work, with one of them abruptly letting go 640 workers, said JKC Australia LNG, which is handling overall construction of the project, on Wednesday.

Inpex said the tanks were 91 percent complete and the project remained on schedule to start shipping LNG to customers in the third quarter.

Still, the disagreement is the latest potential delay in Australia's $200 billion LNG ramp-up, one of the biggest supply increases ever in the gas industry and which will lift Australia over Qatar as top global exporter of the fuel.

The Ichthys dispute is not good news for the project's timely completion, said Saul Kavonic, a Perth-based analyst for global resource consultancy Wood Mackenzie.

"Inpex is targeting a very aggressive construction completion ... to get a first cargo out by the end of September, given the central processing facility, the largest in the world, is still in a Korean ship yard," Kavonic said.

Inpex is not directly involved in the disagreement because it's a matter between subcontractors, so it is not in a position to comment, the Japanese company said.

The disagreement between consortium members Kawasaki Heavy Industries and Laing O'Rourke PLC involves a payment dispute, with JKC saying the latter has released about 245 local hires and 395 other workers that fly in and out.

Ichthys was hit by an earlier contractual dispute in January when an engineering company building a power plant for Ichthys pulled out of the project.

The Australian Manufacturing Workers' Union in a statement said the lay-offs were "due to an ongoing contractual dispute on the project regarding payments."

Kawasaki Heavy has not paid its partner for work on the project for several months, Laing O'Rourke said in a statement.

Kawasaki Heavy could not immediately comment.

Most of the LNG plants being built in Australia, including Chevron's huge Gorgon facility and Royal Dutch Shell's floating Prelude production vessel, are having trouble keeping within budget and on schedule. More delays are expected.

Once completed, Ichthys will produce 8.9 million tonnes of LNG per year.

Inpex holds 62.245 percent of Ichthys and France's Total 30 percent. The rest is spread amongst Taiwan's CPC Corp and Japanese utilities Tokyo Gas, Osaka Gas, Kansai Electric, JERA Corp and Toho Gas .

http://www.reuters.com/article/australia-lng-ichthys-idUSL3N1GS1JA

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Attached Files

A U.S. federal judge on Tuesday denied a request by a Native American tribe for an emergency injunction to prevent oil from flowing through part of the Dakota Access Pipeline, saying such a move would be against the public interest.

The ruling, issued in court documents ahead of plans to start pumping oil through the pipeline next week, follows months of demonstrations in a remote part of North Dakota, where the Standing Rock Sioux tribe demonstrated in an attempt to stop the Dakota Access Pipeline crossing upstream from their reservation.

Judge James Boasberg of the U.S. District Court for the District of Columbia issued his decision denying the request by the Cheyenne River Sioux Tribe, saying the court "acknowledges that the tribe is likely to suffer irreparable harm to its members’ religious exercise if oil is introduced into the pipeline, but Dakota Access would also be substantially harmed by an injunction, given the financial and logistical injuries that would ensue."

The pipeline is nearing completion after President Donald Trump signed an executive order last month smoothing the path for construction. He also cleared the way for the Keystone XL project that would pipe Canadian crude into the United States.

The Standing Rock Sioux and the Cheyenne River Sioux last week lost a legal bid to halt construction of the last link of the pipeline under Lake Oahe in North Dakota, which they say threatens tribal lands. The pipeline will be ready to carry oil by April 1.

Among the Republican Trump's first acts in office was to sign an executive order that reversed a decision by the previous administration of Democratic President Barack Obama to delay approval of the Dakota pipeline, a $3.8 billion project by Energy Transfer Partners LP (ETP.N).

Boasberg noted in his decision that any ruling to allow the tribe's request for an injunction preventing oil from flowing through the pipeline would likely be overturned on appeal.

Thousands of Native American demonstrators and their supporters marched to the White House last Friday to voice outrage at Trump's decision.

http://www.reuters.com/article/us-north-dakota-pipeline-idUSKBN16L2U0

Oil rebounded above $48 a barrel as a reported decline in U.S. crude stockpiles countered a boost in output from Saudi Arabia.

Futures advanced as much as 2.4 percent in New York after slumping almost 11 percent the previous seven sessions. U.S. inventories fell by 531,000 barrels last week, the industry-funded American Petroleum Institute was said to report. Government data Wednesday is forecast to show stockpiles rose for a 10th week. Saudi Arabia’s production climbed back above 10 million barrels a day in February, according to an OPEC report on Tuesday.

https://www.bloomberg.com/news/articles/2017-03-14/oil-gains-as-api-said-to-report-u-s-crude-stockpiles-decrease

East Libyan forces said they had regained control on Tuesday of the major oil ports of Ras Lanuf and Es Sider from a rival faction that seized them earlier this month.

Military spokesman Ahmed al-Mismari told Reuters that the eastern-based Libyan National Army (LNA) was pursuing fighters from the Benghazi Defence Brigades (BDB) towards the town of Ben Jawad, about 30 km (20 miles) west of Es Sider.

Akram Buhaliqa, an LNA commander in the nearby city of Ajdabiya, also said BDB fighters were retreating towards Ben Jawad. The claims could not be independently verified.

http://www.reuters.com/article/libya-security-oil-ports-idUSL5N1GR4VZ

The monthly report by OPEC shows that Saudi Arabia increased production in February back above the level of 10 million barrels a day (to 10.011 million), according to figures submitted by the kingdom.

Back on November 30, when the OPEC cartel of oil producers collectively agreed to cut production, the Saudis agreed to cut to 10.058 million barrels a day. The latest increase therefore still keeps production below the agreed-upon number.

http://uk.businessinsider.com/crude-oil-market-update-march-14-2017-2017-3?r=US&IR=T

The chairman of Australia's competition watchdog has urged east coast LNG operators to provide as much supply as possible to the struggling domestic market and raised concerns over their moves to sell additional volumes in the international spot market.

"They would be well advised to support the domestic market as much as they can at this critical time," Australian Competition and Consumer Commission Chairman Rod Sims said, according to an early copy of his speech to the 5th Annual Australian Domestic Gas Outlook conference in Sydney obtained by S&P Global Platts.

LNG exports over the past couple of years via the three terminals -- Australia Pacific, Gladstone and Queensland Curtis -- almost tripled demand in the eastern and southeastern states, Sims said.

This stretched Australia's eastern seaboard's gas supply, pushing up prices, and resulting in warnings of a likely shortage.

The ACCC conducted an inquiry in April last year and found that the east coast was expected to produce sufficient gas to meet both domestic demand and existing LNG export commitments until at least 2025.

But, if LNG operators sell in the international LNG spot market, it could change the situation.

"Most LNG producers are selling gas on the LNG spot market in addition to meeting their contractual commitments and these volumes are expected to increase going forward," he said.

"The comment that I made [advising the LNG producers to support the domestic market] seems relevant here," he added.

REGION HAS AMPLE GAS RESOURCES

Sims called the discussion on the looming gas shortage in Australia and criticism of LNG producers as a strange debate.

"As our inquiry pointed out, Australia has enormous gas reserves; gas availability is clearly not the issue," he said. "The Inquiry also pointed out that Australia has and will benefit enormously from the three large LNG projects in Queensland. These three projects also saw significant gas resources developed that otherwise would not have been."

The only criticism of the three LNG gas developers to be made it is that they fell into the "usual commodity project trap of assuming then high $100 plus oil prices would continue," he added.

Sims said that environmental restrictions, moratoria and bans on onshore gas production caught the market off guard and played a leading role in the creating supply concerns.

"I doubt anyone in the industry expected Victoria to ban all onshore gas exploration and production, which has stopped even conventional gas projects; nor could they have foreseen the delays and uncertainty over projects in New South Wales and the Northern Territory," Sims said.

SOUTH AUSTRALIA MOVES TO UNLOCK MORE GAS RESOURCES

While other states connected to the east coast's gas pipeline network are crimping access to their gas resources, South Australia -- which has suffered from widespread blackouts in recent months -- announced on Tuesday that it will provide incentives for gas exploration.

"The state government will immediately provide an extra [A]$24 million for a second round of funding to incentivize companies to extract even more gas and create more jobs. This new round will open immediately," the South Australian government said Tuesday in its new energy plan.

It will also provide 10% royalty to landowners whose property overlies a petroleum field that is brought into production, it said.

"South Australia has vast untapped gas resources. It is estimated the Cooper Basin alone could potentially supply Australia's energy needs for more than 200 years," it said. The Cooper Basin straddles South Australia and Queensland.

The South Australian government also said that it would build its own state-owned gas-fired electricity generator.

"Due to the lack of clear national policy settings, investment in new thermal generation has stalled," it said. "The generator will provide up to 250 megawatts of generation, which can be switched on in times of emergency."

http://www.platts.com/latest-news/natural-gas/sydney/australias-accc-head-urges-gladstone-lng-operators-27789923

Lukoil reported a fourth-quarter profit on Tuesday as higher crude prices helped Russia's No.2 oil producer rebound from a loss a year earlier.

Its net profit of 46.6 billion rubles ($790 million) was in line with the 45 billion forecast by analysts polled by Reuters.

A year earlier it suffered a net loss of 65 billion rubles.

Lukoil's shares were up 1.62 percent as of 1128 GMT, outperforming a 0.73 percent rise in the Moscow broader stock market.

Last month, Lukoil's larger domestic rival Rosneft reported a small decline in 2016 net income.

Lukoil, whose name comes from the names of west Siberian towns Langepas, Urai and Kogalym, has struggled with falling oil production at its brownfield sites.

Its oil output fell by 9 percent last year.

The average price of Russia's flagship Urals oil blend in the fourth quarter rose by 14 percent to $46.90 per barrel.

For the whole of 2016, the average price fell by 18 percent to $41.14 per barrel.

Fourth-quarter earnings before interest, taxes, depreciation and amortization (EBITDA) fell to 183.3 billion rubles from 186.3 billion on revenue of 1.40 trillion, up from 1.37 trillion.

Free cash flow fell to 54.6 billion rubles from 104.7 billion.

http://www.reuters.com/article/us-russia-lukoil-results-idUSKBN16L16E

OPEC said on Tuesday oil inventories had continued to rise despite the start of a global deal to cut supply and raised its forecast of production in 2017 from outside the group, suggesting complications in the effort to clear a supply glut.

The Organization of the Petroleum Exporting Countries is curbing its output by about 1.2 million barrels per day (bpd) from Jan. 1, the first cut in eight years. Russia and 10 other non-OPEC producers agreed to cut half as much.

But in its monthly report OPEC said oil stocks in industrialized nations rose in January to stand 278 million barrels above the five-year average, of which the surplus in crude was 209 million barrels and the rest products.

"Despite the supply adjustment, stocks have continued to rise, not just in the U.S., but also in Europe," OPEC said in the report.

"Nevertheless, prices have undoubtedly been provided a floor by the production accords."

In the report, OPEC pointed to a increase in compliance by its members with their deal to cut output from Jan. 1.

Supply from the 11 OPEC members with production targets under the deal fell to 29.681 million bpd last month, according to figures from secondary sources that OPEC uses to monitor its output.

That means OPEC has complied by more than 100 percent with its plan to lower output for those nations to 29.804 million bpd, according to a Reuters calculation. OPEC didn't give a compliance figure in the report.

But the report revised up its estimate of oil supply from producers outside OPEC this year, as higher oil prices following the OPEC and non-OPEC cut help spur a revival in U.S. shale drilling.

Production outside OPEC is now expected to rise by 400,000 barrels per day (bpd), 160,000 more than previously thought. U.S. oil output in 2017 was revised up by 100,000 bpd.

While the OPEC secondary sources said Saudi output fell in February, Saudi Arabia reported to OPEC that it increased

http://www.reuters.com/article/us-opec-oil-idUSKBN16L1DL

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Iran will keep its oil production cap at 3.8 million barrels per day in the second half of 2017, the country's oil minister said on Tuesday, provided other OPEC members stick to the output level they agreed in November.

"If OPEC members stay committed to the agreement (on freezing output), Iran will produce 3.8 million BPD of oil in (the) second half of the current year," Bijan Namdar Zanganeh was quoted as saying by state news agency IRNA.

The Organization of the Petroleum Exporting Countries (OPEC) agreed on Nov. 30 to cut output by 1.2 million bpd to 32.5 million bpd for the first six months of 2017, in addition to 558,000 bpd of cuts agreed to by independent producers such as Russia, Oman and Mexico.

http://www.reuters.com/article/us-iran-oil-opec-idUSKBN16L1DT

Malaysian energy giant Petronas reported a rise in its full year and fourth quarter profits despite the low oil prices and a challenging market environment.

The company’s profit after tax reached RM23.5 billion (Approx: US$5.2 billion) for the full year 2016, showing a 12 percent increase.

However, the company’s report shows that the revenue dropped 17 percent to RM204.9 billion from RM247.7 billion in 2015.

The drop was attributed to the downward trend of key benchmark prices coupled with the impact of lower sales volume.

The company’s fourth-quarter profit jumped 85 percent compared to the previous quarter reaching RM11.3 billion. The RM5.2 billion increase was driven by higher average realized product prices and sales volume mainly from LNG and processed gas as well as the impact of favorable exchange rate.

Revenue for the quarter increased 20 percent from RM48.7 billion in the third quarter to RM58.6 billion in the quarter under review.

Petronas also noted that the capital expenditure for the year dropped 22 percent to RM50.4 billion following project deferment and rephasing as well as cost optimization efforts.

Petronas’ LNG sales for the year hit 29.01 million tons, marginally higher compared to 28.49 million tons in 2015 mainly contributed by higher volumes from Train 9 in Bintulu and GLNG in Australia, partially offset by lower trading volume.

Looking ahead, Petronas is maintaining a conservative outlook and expects further price uncertainty through 2017.

http://www.lngworldnews.com/petronas-reports-higher-profits/

Australia's Federal Government is considering implementing a gas reservation policy to tackle the country's gas and electricity supply concerns, which may also impact the east coast LNG businesses operations, Prime Minister Malcolm Turnbull said Friday.

Platts Analytics has Australia tipped to become the world's largest exporter of LNG, surpassing Qatar, in 2019 aided by the boost in volumes by the start-up of shipments from the east coast's Australia Pacific, Gladstone and Queensland Curtis LNG terminals in the last couple of years.

But those terminals have been blamed for playing a part in putting the eastern and south-eastern states of the country on a collision course for a gas supply crunch by the end of the decade.

Now, the Federal Government is exploring options to deal with the looming crisis, including a gas reservation policy, with Turnbull saying national energy security will come before the interests of the LNG exporters.

"What the gas companies would say -- their response to an imposing reservation on them would be to say 'you're changing the ground rules. We did this exploration. We built these LNG trains on the basis that there would not be a constraint on what we could export,'' Turnbull said on FIVEaa radio.

"But clearly, security is the first responsibility of every government -- national security and energy security," he added.

The Prime Minister is due to meet with the CEOs of east gas companies this week to discuss the matter.

"They've been put on notice. I need to hear from them. I'll be demanding from them their explanation as to how they are going to deliver security for their customers," he said.

The eastern state of Queensland -- where the east coast's LNG terminals are located -- is already testing the water in terms of a gas reservation policy.

The State's Government announced in January it is allocating a small volume of potential gas supplies from freshly released land for exploration with strict Australia-only sale conditions.

Opponents to the idea of a gas reservation policy say more regulation on gas developments will result in less being produced.

"It's a very strange idea to think that the way to get more of a product is to increase regulation around that product and increase the costs of development," the Australian Petroleum Production and Exploration Association chief executive Malcolm Roberts said last month.

APPEA last week said warnings of gas shortages in the region -- which Australia's energy market operator forecasts could be seen as soon as summer (December-February) of 2018-2019 -- are "the consequence of many years of policy failure by successive state governments in Victoria and New South Wales."

"The response [to the warnings] has been policy indecision, restrictive regulations and politically motivated bans and moratoriums that have stymied exploration and development of local gas supplies," Roberts said.

The Victorian Government announced last week that Parliament passed legislation that bans all onshore unconventional gas development in that state and extends a moratorium on onshore conventional gas development until 2020. Turnbull also blamed the State Government bans and moratoriums on onshore gas production as contributing to the crisis.

"We have massive gas resources. We have so much gas. The problem we've got at the moment is the political opposition to its exploration," he said.

"I encourage all parties, Liberal and Labor, to support the development of our gas resources," he added.

Australia's LNG exports are forecast at 57 million mt in 2017, before surging to 73 million mt in 2018 and then to 83 million mt in 2019, Platts Analytics said.

http://www.platts.com/latest-news/natural-gas/sydney/australia-might-change-the-ground-rules-for-east-26683987

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Pampetrol, the state oil company of Argentina's La Pampa province, has brought back into production a formerly privately operated block, with an eye to boosting output, the provincial government said.

"Pampetrol has started the first four production wells," the government said, adding each of the wells on Salina Grande I was producing an average of 94 b/d.

The La Pampa government said these were the first of 10 existing wells that Pampetrol will gradually put back into operation on the block in the south-central province. The block had been inactive for a year, it said.

Last August, La Pampa revoked the exploration and production permit of Salina Grande I's private consortium, saying the group had failed to comply with license requirements in terms of the pace of investment since winning the permit in 2006. The consortium was made up of Gregorio, Numo y Noel Werthein, Petrosiel and Energial, the latter of which was the operator of the block.

La Pampa has also taken back under state control other blocks like Jaguel de los Machos from Brazil's state-run Petrobras.

La Pampa produces 3.8% of the country's 511,000 b/d of crude and 0.8% of its 123 million cu m/d of gas, according to the Argentine Oil & Gas Institute, an industry group.

http://www.platts.com/latest-news/oil/buenosaires/argentinas-pampetrol-restarts-oil-field-after-21143223

Planning in the supply chain: industry expects service costs to rise 10%-15%, but WPX has a firm handle on costs in the Permian

Everyone knew it would happen eventually: service costs are going on the rise. Halliburton talked about it as early as July of 2016, and over the course of the EnerCom Dallas oil and gas investment conference we heard it again and again.

As activity continues to pick up on the drilling side of the equation, E&P companies need more services from the oilfield side of the industry. After two years of layoffs and slower drilling programs that will translate into more demand for fewer crews and less equipment, which is starting to play out in a 10%-15% expected increase in service costs for the coming year, according to a number of sources ranging from E&P decision makers to buyside and sellside analysts.

Nowhere is this becoming more apparent than in the Permian, where strong returns have attracted a rush of capital and drilling activity outpaces the next most active basin by 4.5 times, according to information from Baker Hughes Industries . Many companies had the forethought to plan ahead, though, and they intend to reap the rewards moving forward.

WPX Energy operates in the Delaware Basin, right at the heart of the Permian, and the company has been able to contract approximately 70% of its drilling and completion costs through 2017, mitigating the company’s exposure to service cost inflation.

To better understand how WPX keeps its service costs in check in the most active oilfield in the U.S., Oil & Gas 360® spoke with WPX Director of E&P Services Alan Killion about the company’s supply chain management.

WPX Energy offers insight into what it takes to manage costs in the Permian Basin

“WPX has been proactive over the past year to work with the service providers on longer-term partnerships that are shielding WPX from the brisk pace of inflation,” said Killion. “Our goals are to find partners who want to grow with WPX long-term. Contracting with those companies requires an understanding of not only the current marketplace but also an alignment of goals.”

At WPX, Killion’s group specializes in contracts, negotiating, analytics and technical aspects, such as understanding the pipe market all the way back to the mill, according to WPX. Killion’s experience as both a production engineer and trader for Occidental Petroleum  before moving into his role at WPX made him the right fit to understand markets and develop those partnerships.

“The environment at WPX is an advantage because there’s so much emphasis on planning and forecasting. Since things are more predictable, we can make more of an impact,” said Killion.”

Stimulation services and sand look to be the most pressing matters for now

“The stimulation side of the business has seen the most constraint in the supply chain.  As we know from economics, anytime there’s a constraint in an area we tend to see inflationary dynamics,” explained Killion.

“Pressure pumping crews are in short supply. We estimate that the market is approximately at a 95% utilization rate.  Until future crews hit the market, pricing in the marketplace will be pressured. We have seen the pressure pumping market increase approximately 250% to 300% for horsepower since Q4 2016.  As companies continue to add crews some of the price inflation will start to subside.”

Sand will also continue to be a source of cost inflation for many companies moving forward. “Current sand capacity is listed at 110 million tons per year. In 2016, demand was approximately 40 million tons per year.  2017 projections are around 50 million tons per year, with 2018 pushing more toward 80 million tons,” said Killion, but those numbers include all types of sand, not just the fine sand that is in high demand for the increasingly intense frac jobs completed across the United States.

Sand has seen 75%-100% inflation since late 2016

“With this move to finer sand types, longer laterals and higher proppant concentrations, the sand market has experienced inflation of 75%-100% since late in 2016,” said Killion. “We see the same dynamics starting to occur in the OCTG (Oil Country Tubular Goods) market as well.”

Because of the increasing demand in those particular areas, WPX worked to ensure that it would have long-term contracts to mitigate as much inflation as possible, explained Killion. “WPX has hydraulic horsepower and frac sand contracts in place into 2018.”

Killion and his team expect to see similar increases in service cost across all basins, as well. “We have seen the inflation agnostic to basins at this time.  As frac crews and frac sand is somewhat fungible, these services try to migrate toward the most active basins when possible,” he explained.

Don’t discount continued improvements in efficiency

Many E&P companies are already including the 10%-15% increase in service costs in their forward-looking projections, but that does not mean that drilling and completion costs will rise in lock-step with price inflation. Companies continue to improve their drilling designs and increase the speed at which they can drill higher-performing wells.

“It is somewhat difficult to say [what a 10% to 15% increase in service costs would mean for well economics] because each basin and each formation holds different economics, but it could wind up being a wash when you think about how much better we’re getting on the performance side,” said Killion. “The industry continues to find ways to drill and complete wells that yield reduced drill times and increased EURs.

“WPX continues to set the bar higher on each of these fronts.

“Last year we raised EURs in all three of our basins. And we completed a 16-day well in the Permian, and we’re still in the early learning phase. We also reduced drilling times in the Bakken by 5 days from 2015 to 2016. We have seen approximately 10% to 15% increase in the number of stages our stimulation partners can frac in a single day.  These improvements should offset inflation at a minimum,” he said.

It’s all about communication and credibility

Successfully finding the sweet spot between supply chain management, operations and vendors will help Killion and his team continue to improve WPX’s supply chain moving forward, he explained.

“The two most critical pieces to making everything work are the 2 Cs – communication and credibility,” said Killion. “That ongoing, open dialogue is paramount, and the supply chain management team has to be credible and earn the trust of operations. We are not the tail wagging the dog. Our role is to support our asset teams and their business objectives. We make recommendations. They make decisions.”

http://www.oilandgas360.com/wpx-energy-keeping-permian-basin-service-costs-check-oil-gas-360-exclusive/

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U.S. shale oil production in April was set for its biggest monthly increase since October as output in the Permian Basin, America's fastest growing shale oil region, was expected to hit another record high, government data showed on Monday.

Total shale oil production was expected to rise 109,000 barrels per day to 4.96 million bpd, according to the U.S. Energy Information Administration's drilling productivity report.

Oil production in the Permian Basin in Texas and New Mexico, the largest U.S. shale oil field, was set to rise 79,000 bpd to 2.29 million bpd, the highest level on records dating back to 2007.

In the Eagle Ford region in Texas, output was expected to grow nearly 28,000 bpd to 1.14 million bpd, the highest level since November.

Production in the Bakken, however, was set to drop 10,000 bpd to 964,000 bpd, the only month-on-month decline across all seven basins used in the report. That would be the third consecutive monthly decline in the North Dakota basin.

Meanwhile, U.S. natural gas production was projected to increase to a record high 49.6 billion cubic feet per day in April, the EIA said.

That would be up almost 0.6 bcfd from March and would be the fourth monthly increase in a row.

The EIA projected gas output would increase in all of the big shale basins in April, including the Eagle Ford, where production had been declining since January 2016.

Output in the Marcellus formation in Pennsylvania and West Virginia, meanwhile, was set to grow by almost 0.2 bcfd to a record high near 19.2 bcfd in April, a sixth consecutive increase.

EIA also said producers drilled 807 wells and completed 716 in the biggest shale basins in February, leaving total drilled but uncompleted wells (DUCs) up 91 at 5,443, the most since April 2016.

http://www.reuters.com/article/us-usa-oil-productivity-idUSKBN16K2GP

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A recovery in U.S. oil output may deter OPEC and non-OPEC producers from extending production cuts beyond June and might lead to a new price war, Russia's top oil major said on Monday.

U.S. shale oil production had been in retreat as oil prices tumbled from above $100 a barrel in 2014 to below $30 in 2015, making costly fracking processes less profitable.

A deal by the Organization of the Petroleum Exporting Countries with Russia and other producers to rein in output by 1.8 million barrels per day (bpd) for six months from Jan. 1 lifted prices but also encouraged U.S. firms to boost supplies.

"It became evident that U.S. shale oil output has become and will remain a new global oil price regulator for the foreseeable future," Rosneft said in a written response to Reuters.

"There are significant risks the (OPEC-led) deal won't be extended partially because of the main participants, but also because of the output dynamics in the United States, which will not want to join any deals in the foreseeable future."

Russia agreed to join OPEC supply curbs late last year despite initial opposition from Rosneft's boss Igor Sechin, one of President Vladimir Putin's closest allies.

"We think that in the long-term global oil demand dynamics and reduced investment during the period of ultra low prices will balance the market, but that the risk of a price war resuming remains," Rosneft wrote.

Russia has yet to deliver on the pledged cuts, while Saudi Arabia has cut its production far below the levels it had pledged, compensating for waker compliance by other OPEC states.

Rosneft said it came as a surprise to many observers that OPEC's compliance with cuts was more than 90 percent, and said the success was because the Saudi position on reducing production had "changed a great deal" from the past.

The kingdom, the world's biggest oil exporter, had long refused to cut output under veteran oil minister Ali al-Naimi. He was replaced last year by Khalid al-Falih.

"It was Saudi Arabia which initiated the pricing war in the first place with the aim of radically increasing its market share by squeezing out producers of 'costly' oil," Rosneft said, in a reference to shale producers.

"This goal became impossible to reach because of the efficiency and viability of the Russian oil industry," it added.

Naimi had forecast a collapse in output from Russia's mature fields. Instead, production has risen in the past two years to an all-time high of 11.2 million bpd, partly because a devaluation in the rouble reduced production costs.

Rosneft said the only guaranteed route to balance the market was for all producers to limit supplies, but acknowledged this would not happen because U.S. shale producers would not join any such pact. U.S. law bars them from such action.

http://www.reuters.com/article/us-oil-output-russia-idUSKBN16K1MB

Genscape Cushing +1.7mm bbls W/W

 @zerohedge  

News Release – TransCanada Corporation (TransCanada) today announced the successful conclusion of a long-term, fixed-price Open Season to transport natural gas on the Canadian Mainline from the Empress receipt point in Alberta to the Dawn hub in Southern Ontario. The company confirmed that its recent Open Season resulted in binding, long-term contracts from Western Canada Sedimentary Basin (WCSB) gas producers to transport 1.5 PJ/d of natural gas at a simplified toll of $0.77/GJ.

“Today, WCSB producers are facing a much more challenging landscape than they have in the past. This new offering helps our customers compete more effectively by utilizing existing capacity on the Canadian Mainline, and demonstrates the importance and value of this system to deliver their products to markets in Eastern Canada and the Northeast U.S.,” said Russ Girling, president and chief executive officer, TransCanada.

“This long-term agreement provides significant benefits for our customers, shareholders, communities and governments that depend on the economic benefits that are generated by natural gas exploration, production and transportation,” added Girling. “In addition to utilizing existing capacity and pipelines already in operation, the incremental revenue generated from this offering will make the Canadian Mainline more competitive.”

Key highlights of the Revised Long-Term Fixed Pricing Open Season:

Collectively, customers have signed long-term binding contracts to transport 1.5 PJ/d of natural gas from the Empress receipt point in Alberta to the Dawn hub in southern Ontario, at a single toll of $0.77/GJ.
The term of the contract is 10 years and has early termination rights that can be exercised following the initial five years of service (upon payment of an increased toll for the final two years of the contract).
The service can be provided entirely with existing facilities.
The targeted in-service date is November 1, 2017. The company intends to file an application for regulatory approval with the National Energy Board in April 2017.

Today, TransCanada transports more than 25 per cent of the natural gas consumed across North America, and millions of people rely on the energy we deliver every day to heat and cool their homes, fuel industries and generate reliable sources of power, and the Canadian Mainline is a critical piece of energy infrastructure that allows this to happen. The Canadian Mainline is a regulated cost of service system that currently transports about 20 per cent of the natural gas produced in the WCSB to serve Canadian markets and interconnects with the U.S.

http://boereport.com/2017/03/13/transcanada-announces-successful-canadian-mainline-open-season-results/

Gazprom is ready to comply with EU rules to end a five-year antitrust case and avoid fines, the bloc's competition commissioner said on Monday, signaling a thaw in business ties between Moscow and Brussels despite tensions over Ukraine.

Eight member states in the east, all formerly dominated by Moscow, now have until May 4 to object to the EU executive's view and could try to seek changes in Gazprom's offer.

The Russian state gas exporter, which supplies a third of the EU's gas, has been on the radar of EU regulators since 2012, culminating in charges in April 2015 that it overcharged customers in Central and Eastern Europe and blocked rivals.

Since then, Gazprom has offered concessions aimed at staving off a potential fine of up to 10 percent of its global turnover.

EU Competition Commissioner Margrethe Vestager, who has brought actions and levied fines against major U.S. multinationals such as Google, said Gazprom's offer allayed worries and provided "a forward looking solution".

"Combined we think that these measures are important improvements to ensure the free flow of gas at competitive prices," Vestager said.

Gazprom has agreed to fixed transparent fees and to allow clients the right to price revisions clauses in long-term contracts, EU regulators said.

As part of the deal, Gazprom will also adapt contracts to remove barriers on the free flow of gas across borders and drop clauses in its supply contracts with wholesalers and some industrial customers barring them from exporting its gas to other countries.

Within a bloc divided over its stance on Russia, some EU nations see the move towards a settlement as running counter to calls for more sanctions on Russia over its bombing in Syria.

"The fundamental question is how friendly are we going to be with Gazprom," one senior EU diplomat said. "To some, it looks strange that the Commission is going after Apple and Google but not Gazprom."

Vestager insisted during a news conference that her view was purely based on enforcing EU law and not influenced by politics.

The EU executive is likely to receive tough feedback from the eight states at the heart of the case, with many already locked in a battle with the Commission over what they view as lenient treatment of Gazprom in other cases.

Poland has said it will "play rough" with the EU across the board after a dispute on another matter last week. The other countries being asked for their views on Gazprom are three Baltic states, Bulgaria, Hungary, Slovakia and the Czech Republic.

Vestager responded to criticism by saying the decision was divorced from politics and "would be most helpful to have the future behavior of Gazprom changed".

With a settlement, Russia would accept EU authority in applying competition law - something it has long balked at. If Gazprom failed to comply and meet its commitments, the EU could resort to fines without reopening its case, Vestager said.

http://www.reuters.com/article/us-russia-gazprom-eu-competition-idUSKBN16K15J

The Hague-based LNG giant Shell said on Friday it is ending development of the proposed Prince Rupert liquefied natural gas export project in Canada’s British Columbia.

BG International Limited, a member of the Shell Group, confirmed in a statement that the company would discontinue development of the proposed LNG project, located on Ridley Island at the Port of Prince Rupert.

Acquired as part of the Shell and BG Group combination in 2016, the Prince Rupert LNG project has been part of a global portfolio review of combined assets, which resulted in the decision to discontinue further development, the statement said.

“During the global portfolio review the local project team has continued to engage locally and to support environmental initiative and social investment activities in the area,” the statement said.

The Prince Rupert office will remain open through May 2017 to complete community engagement.

Prince Rupert LNG was planned to be developed in two phases with a production capacity of up to 21 million tonnes of LNG per year. Natural gas to the Ridley Island facility would have been received from northeast British Columbia via pipeline.

The project received authorization in April 2014 from the National Energy Board to export LNG from the proposed liquefaction facility.

http://www.lngworldnews.com/shell-shelves-prince-rupert-lng-project-in-british-columbia/

It’s small when you compare it to the top ten largest U.S. refineries, most located on the Gulf coast, all having capacities between 300,000 barrels and half a million barrels per day, but a small Texas-based energy company has announced its intention to build a 50,000-barrels per day crude oil refinery in a well-selected location: in the heart of the Permian basin.

MMEX Resources Corporation (ticker: MMEX) said it will need $450 million to build the proposed refinery 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad. MMEX said the 250-acre facility intends to utilize its connection to existing railways to export diesel, gasoline, and jet fuels; liquefied petroleum gas; and crude oil to western Mexico and South America.

Why is this important?

Because the Permian basin, and the Midland basin within it, are extremely fast growing oil plays in which many independent E&Ps can drill wells, produce oil economically at today’s commodities prices—or at least at last week’s oil prices. (Prices for West Texas Intermediate dipped below $49 this week after a larger than expected inventory build, following a consistent ride in the $50-$54 per barrel range in recent weeks.) But takeaway capacity is not keeping up with the Permian basin’s growing oil production.

Calling the Wolfcamp “the largest estimate of continuous oil that the USGS has ever assessed in the United States,” the USGS last fall pegged the Wolfcamp formation in the Midland basin at 20 billion barrels. E&Ps have cemented the reputation by making the Permian a favorite target of M&A and A&D activity. And rig counts have been growing fast.

MMEX Resources President & CEO Jack Hanks said, “The existing facilities and pipeline networks are largely unequipped to handle this growth and are limiting where products can be transported. By building a state-of-the-art refinery along the region’s existing railway infrastructure, we hope to bring a local and export market for crude oil and refined products.”

MMEX said it plans to surround the Pecos County refinery with an additional 250 acres of buffer property and leverage state-of-the-art emissions technologies to yield minimal environmental impact. It also expects to feature closed-in water and air-cooling systems, which will require very little local water resources.

The company anticipates the 18-month construction process will create approximately 400 jobs in the area during peak construction, as well as foster a significant number of indirect jobs and revenue for companies in catering, workforce housing, construction, equipment and other industries.

Once operational, the facility is expected to provide an estimated 100 permanent jobs and generate substantial tax revenue for Pecos County, the company said.

MMEX purchased the rights to the project from Maple Resources Corporation. Construction is slated to begin in early 2018, following the permitting process, and the facility is projected to begin operations in 2019.

MMEX is involved in oil, gas, refining and electric power projects in Texas, Peru, and other countries in Latin America. The company’s ability to build the proposed Permian refinery is subject to the receipt of required governmental permits and completion of required debt and equity financing, MMEX said.

http://www.oilandgas360.com/proposed-permian-refinery-could-take-50000-bopd-from-west-texas-producers/

The presenter who arguably received the best questions at Wednesday’s Crude Oil Quality Association meeting in New Orleans was the US Department of Energy’s economist, Kenneth Vincent.

His presentation was part overview, such as the locations of the four salt caverns that hold the more than 700 million barrels of US oil – Texas and Louisiana, and the maximum drawdown capacity – 4.4 million b/d. But there were also some nuggets not found on factsheets such as the how the physical salt caverns are shrinking due to geological pressures and how “distribution issues are a major concern (for the DOE) currently and going forward.”

Following the presentation, the overflowing room of oil industry participants had plenty of questions for Vincent. And if they didn’t know the answers, and I didn’t know the answers, I reckon you might be interested too:

Q: Are there any restrictions on who you can sell to? Could you export oil anywhere?

A: Vincent said since the US oil export ban has been lifted, the office received a legal opinion that it can’t export but it can sell to anyone, who can then export it.

Q: Do you look at the type of oil you are storing so that it is what we need when the time comes?

A: “Yes,” Vincent said, which got some chuckles from the crowd.

After a brief pause he continued to say the strategic petroleum reserve stores about 60% medium sour and 40% sweet crudes that are amalgams from a bunch of different streams.

“Our goal is to have oil as fungible as possible and support as many types as possible.”

He said a common question is if the SPR should focus more on heavy oils, which account for a bulk of imports and are consumed by USGC refineries. However, he said no, that SPR isn’t focusing on adding more heavy oils. He said that heavy oil is “really hard” to store for long periods of time and that there is a lot more sweet oil going into the US refinery fleet.

“We ultimately decided we weren’t going to put a big stake in the ground for changing the type of oil in the reserve but that is something we follow very closely.”

Q: Do you consider the price of specific crude grades when making sales from the SPR?

A: “Yes. Absolutely.”

Vincent said there is a very rigorous process in place in trying to maximize returns for taxpayers.

Q: Does the DOE have any input on pipeline reversals?

A: “Absolutely not,” Vincent said. “We have no say.”

http://blogs.platts.com/2017/03/10/doe-economist-spr-exports-storage-sales/

Two of the biggest North Sea services players this morning revealed plans to combine.

Wood Group’s and Amec Foster Wheeler’s board of directors have reached an agreement on the terms of a recommended all-share offer by Wood Group to acquire the entire issued and to be issued share capital of Amec Foster Wheeler.

The takeover is worth £2.2billion.

Under the deal, each Amec Foster Wheeler Shareholder will receive for each Amec Foster Wheeler Share 0.75 New Wood Group Shares.

The pair have said the deal will save $134million per annum. Of that, 40% is expected to come from operating efficiencies. An addittional 30% is expected to come from corporate efficiencies, including the reduction of duplicate costs across board and executive leadership teams.

Robin Watson and David Kemp, currently CEO and CFO of Wood Group respectively, will continue as CEO and CFO of the combined group. Wood Group’s chairman Ian Marchant will remain the combined group’s chairman.

Four members of the Amec Foster Wheeler Board will join the board of the combined group upon completion of the combination as non-executive directors, with Roy Franklin joining as deputy chairman and senior independent director.

The final 30% is expected to come from administration efficiencies, including the consolidation of overlapping office locations, the elimination of duplicated IT systems and the reduction of duplicate costs across central support functions.

Chairman Marchant said: “The Combination represents a transformational transaction for Wood Group, which accelerates our strategy and creates a global leader in project, engineering and technical services delivery across a range of industrial sectors. The Combination extends the scale and scope of our services, deepens our existing customer relationships, facilitates further development of our technology-enabled solutions and broadens our end market, geographic and customer exposure.

“The Combination will create an asset-light, largely reimbursable business of greater scale and enhanced capability, diversified across the oil & gas, chemicals, renewables, environment & infrastructure and mining segments.

“By leveraging Amec Foster Wheeler’s and Wood Group’s combined asset life cycle services across project delivery, engineering, modifications, construction, operations, maintenance and consulting activities, the Combined Group will be able to better capitalise on growth opportunities across a broad cross section of energy and industrial end markets.
Delivering significant sustainable synergies will also result in a leaner and more competitive Combined Group, creating value for shareholders.

Amec Foster Wheeler’s shareholders will become shareholders in the Combined Group, thereby gaining from the enhanced operating capabilities, and benefiting from a share of the synergies, a stronger balance sheet and Wood Group’s progressive dividend policy.

“The Wood Group Board is confident that the Combination will build on the individual platforms of Wood Group and Amec Foster Wheeler to the benefit and advantage of customers, employees and other stakeholders.

“The Combination has been unanimously recommended by the boards of Wood Group and Amec Foster Wheeler, and the Wood Group team looks forward to working with the Amec Foster Wheeler team to further develop the Combined Group over the longer term.”

It comes the same day Amec reported a 8% slip in revenue to £5.4billion. Its profit fell from £374m in 2015 to £318million in 2016.

John Connolly, chairman of Amec Foster Wheeler said: “Since the arrival of Jonathan Lewis as CEO, the executive management team has made significant progress towards the transformation of the business. This has been achieved through cost reduction initiatives, the disposal of non-core assets and a reorganisation of the business. The Board have fully supported the revised strategy and the preparations to deliver the appropriate balance sheet to support its standalone prospects.

“However, the Board believes that a combination with Wood adds to the standalone prospects of the Company, by accelerating the delivery of the future value inherent in the Amec Foster Wheeler business and, at the same time, helps to realise the full potential of each of Amec Foster Wheeler and Wood. The all-share structure of the offer allows our shareholders to benefit from the significant synergies and other strategic benefits that are expected to be realised from the combination. Amec Foster Wheeler will also be well represented on the Board of the enlarged group, with four of our directors joining Wood’s board, including Roy Franklin, who will be appointed Deputy Chairman and Senior Independent Director.”

The combination is expected to be completed in the second half of this year.

Wood Group said it believes the combination “represents a compelling opportunity to accelerate the delivery of Wood Group’s strategy to become a global leader in project, engineering and technical services delivery across a broad platform of industrial sectors”.

The firm also said it would afford it the ability to have a “stronger, more diversified platform better able to manage the inherent market and contract volatility that faces the oil and gas industry”.

The combined group will employ 64,000 people globally. It will have a net debt of $1.6billion.

The combination is expected to incur a one-off cost of £190million spread out over the first three years.

In a company announcement Wood Group stated: “The Wood Group Board has, in addition, made the following assumptions, all of which are outside the influence of the Wood Group Board:

• there will be no material impact on the underlying operations of either company or their ability to continue to conduct their businesses;
• there will be no material change to macroeconomic, political, regulatory or legal conditions in the markets or regions in which Wood Group and Amec Foster Wheeler operate that materially impact on the implementation or costs to achieve the proposed cost savings;
• there will be no material change in current foreign exchange rates; and
• there will be no change in tax legislation or tax rates or other legislation or regulation in the countries in which Wood Group and Amec Foster Wheeler operate that could materially impact the ability to achieve any benefits.”

Wood Group was advised by J.P. Morgan Cazenove and Credit Suisse. Amec was advised by Goldman Sachs International, BofA Merrill Lynch and Barclays.

The combination is considered a Class 1 transaction for Wood Group. As such, the combination is conditional and will need final approval from Wood Group’s shareholders at its general meeting.

Wood Group’s board said it considers the “combination to be in the best interests of Wood Group and the Wood Group Shareholders as a whole and intend to recommend unanimously that Wood Group Shareholders vote in favour of the relevant resolutions at the Wood Group General Meeting”.

If approved, Amec Foster Wheeler Shareholders would own approximately 44% of the combined group.

https://www.energyvoice.com/oilandgas/north-sea/133913/breaking-wood-group-amec-combine-share-capital-articleisfree/

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Increased high sulfur and low sulfur straight-run fuel oil output in the Middle East, most specifically in the UAE, is providing competition for European straight-run flows into Asia in the second quarter, according to sources this week.

Europe's straight-run fuel oil production is typically delivered into the US Gulf Coast or east Asia, although this latter supply pattern is being impacted by the higher output in the Middle East.

According to sources, due to lower domestic demand in the Middle East for straight-run fuel and refineries opting not to re-use the product as feed for their own purposes, there has been a surge in production and exports recently.

"Ruwais [in the UAE] is producing around 400,000 mt of very good quality fuel oil", said one fuel oil trader. "The vast majority of it is going to Asia, with around 70% to China."

"This a lot more than the refinery typically produces," a second trader added.

China is the second-biggest refiner in the world, after the US, home to a number of complex and basic refineries, and so is a key market for cheap feedstock material such as straight-run fuel oil.

"China has a lot of demand for this stuff," said the second trader.

In January, China imported 311,000 b/d, amounting to a total of 1.53 million mt of fuel oil per month, according to Platts China Oil Analytics. In the coming months, demand is expected to dip slightly to 265,000 b/d, but will again recover to above the 300,000 b/d mark.

In addition, domestic European demand for the feedstock has been curtailed of late and is expected to rise once the major refineries complete their turnarounds. Producers had been looking to the east as a market for their supply, but the stiff competition has made this somewhat difficult.

Sell tenders in the Black Sea and weak demand have already softened differentials for straight-run fuel oil in Europe, in addition to un-sold cargoes floating out in the open sea.

A total of 300,000 mt of LSSR per month will be made available to buyers via tender, traders told S&P Global Platts.

Some 200,000 mt will be supplied by Rosneft, with the remainder offered by the privately owned Ilsky refinery. Although not an unusual trend, weaker gasoline demand in the US has meant fewer willing buyers for the oil.

http://www.platts.com/latest-news/oil/london/rising-middle-east-straight-run-fuel-oil-output-26682972

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The U.S. offshore rig count climbed up to 20 units last week, according to weekly rig count reports by the oilfield services provider Baker Hughes.

The U.S. Offshore Rig Count is up 2 rigs from last week to 20 and down 7 rigs year over year.

http://www.offshoreenergytoday.com/u-s-offshore-rigs-climb-up-to-20-units/

Two new crude oil export pipelines will provide enough capacity to ship Canadian production to market until at least the mid 2020s, Enbridge Inc  Chief Executive Al Monaco said on Friday, making clear his company's Line 3 should be one of them.

Monaco's comments come amid growing speculation that Canada faces pipeline overbuild after years of struggling with limited market access.

The Canadian government approved Enbridge's Line 3 replacement project and Kinder Morgan's Trans Mountain expansion last November, while U.S. President Donald Trump invited TransCanada to reapply for a Keystone XL permit in January. TransCanada is also awaiting permits for its proposed Energy East project.

If all four pipelines get built the 2.1 billion barrel per day surge in capacity would fast outpace industry forecasts of Canadian crude production growth of 850,000 bpd by 2021.

"If you look at the supply profile and you look at our expansion replacement capacity for Line 3 and one other pipeline, that should suffice based on the current supply outlook, out to at least mid-next decade," Monaco said on a fourth quarter earnings call.

Monaco said Enbridge had another 400,000 bpd of potential capacity expansion opportunities in addition to Line 3 but the company would be guided by the amount of supply coming out of western Canada.

Wood Mackenzie analyst Mark Oberstoetter said his firm agreed with Monaco's assessment on the need for new pipelines.

"We definitely need two of these pipelines by around 2025 and after that it depends on the supply outlook," Oberstoetter said. "There's not an evident need to get three or four pipelines built."

Enbridge, Canada's largest pipeline company, also announced a C$1.7 billion ($1.3 billion) investment in a North Sea windfarm.

The 50 percent ownership in EnBW's (EBKG.DE) Hohe See strengthens Enbridge's footprint in Europe's booming offshore wind power industry.

Monaco said there could be more to come given the push towards renewable energy in a number of European countries.

Enbridge reported fourth-quarter profit on Friday that included a C$373 million before-tax impairment charge related to its Northern Gateway pipeline, which the Canadian government blocked last year.

Earnings attributable to the company's shareholders were C$365 million ($279 million), or 39 Canadian cents per share, in the fourth quarter, hurt by charges, including for asset impairment and restructuring.

http://www.reuters.com/article/us-enbridge-inc-results-idUSKBN15W19I

Drillers sent another 12 rigs this week back into oil and gas fields across the nation, Baker Hughes said Friday.

The number of active oil-drilling rigs climbed by eight, up to 768, in the eighth consecutive weekly increase. Meanwhile, gas rigs increased by five, up to 151. One rig classified as miscellaneous was removed from the oil field service company’s go-to list of active rigs.

Four of the oil rigs were sent to the DJ and Niobrara basins in Colorado and nearby states.

One went to the Permian Basin in West Texas, another went to the Utica Shale in Ohio, and several more headed for regions Baker Hughes does not track.

The nation’s rig count has climbed from 404 in late May to 768 this week, as oil prices have risen and OPEC’s oil production cut spurred drilling activity in U.S. shale plays.

http://fuelfix.com/blog/2017/03/10/u-s-oil-and-gas-rig-count-climbs-by-12/

A Frac Sand Mine Lands In The Permian. This Could Transform The Competitive Sandscape [Exclusive Details]

February 24, 2017 Infill Thoughts 4 Comments

After the market closed Thursday evening, Hi-Crush Partners quietly dropped the equivalent of an atom bomb on the frac sand business. Few seem to have noticed yet – Hi-Crush is less widely followed than some of the other large miners, yesterday was a busy earnings day, and they announced the news with little fanfare.

But make no mistake, this is big news for and from Hi-Crush. It is yet unclear if this is the start of a trend, but if it is, then it has disruptive implications for the entire frac sand value chain.

The First Frac Sand Mine Lands In The Permian

In an industry first, Hi-Crush announced plans to build a frac sand plant in the heart of the Permian Basin, the world’s busiest frac market. The new $50mm plant will produce 3mmtpa of 100 mesh frac. For context, that’s approx. 10% of expected Permian proppant consumption this year. The production will come from a 55mm ton deposit Hi-Crush has just purchased for $275mm. The plant will be built between closing in 1Q17 and early-4Q17 when it is expected to open.

Hi-Crush did not disclose the precise location of the reserves, but industry sources tell us the plant site is located just outside of Kermit TX in Winkler County off Highway 115. In a quick glance at Google Maps, the sand deposits literally jump off the map. Per their announcement, Hi-Crush bought a 1,226-acre frac sand reserve with options on additional acreage.

(click image to view in Google maps)

This Has The Potential To Transform The Competitive Sandscape

If this deal is a one-off, then it’s good for Hi-Crush and won’t impact the market much. But if this new plant is the start of a trend of regional mines entering the Permian, then this news will transform the US frac sand business. If this takes off, it has implications for the entire sand value chain.

Much of the sand consumed in the Permian originates in Wisconsin, and rail transportation is the highest cost component of this sand (see chart below). If you can eliminate rail by placing sand mines in the heart of the Permian… the possibilities get interesting.

If Hi-Crush can built a plant capable of producing 3mmtpa in the Permian, others will try to follow. If our sources are accurate, they will follow quickly.

Over the past several weeks, we’ve been picking up chatter from multiple industry contacts in West Texas about the descent of dozens of buyers interested in the region’s sand deposits. Land owners sitting on sand in the Permian have been approached by buyers from established miners to private equity firms. We understand this particular Hi-Crush purchase was a hotly contested bidding process where at least one other big sand mine participated.

If others can repeat Hi-Crush’s approach, we can imagine a world where 25-50% of Permian frac sand demand is supplied locally. Here are a few implications if this trend takes off and scale in local mining capacity is achieved:

·         Wisconsin reserves will be devalued.

·         It could eliminate the biggest cost of sand (rail transportation) for a portion of proppant consumed in the Lower 48’s biggest frac sand market.

·         That is a game changer because the Permian is expected to consume half the frac sand produced in the US going forward.

·         Wisconsin minegate sand prices could face some new headwinds.

·         Rail transportation demand could fall shy of current expectations (implications for cars and trains)

·         If it takes off, Permian transload demand could be adversely impacted.

·         More hauling would start at the mine not the terminal.

But there is work to be done before this becomes a trend. There are potentially limiting factors that could cap the rise of Permian mines. Here are a few that come to mind:

·         Transportation infrastructure. If our sources are correct about Hi-Crush’s location, then it is right off the highway in a prime location. Deposits further away from the road may be harder to develop (and more costly).

·         Access to water. It is essential in sand mining (perhaps especially if the mines amount to scraping dunes) and could become constrained around these sand deposits in West Texas (especially those in more remote locations).

·         Stubborn Owners. We’ve heard that land owners sitting on sand have been hesitant to sell – continuous acreage around infrastructure may not be for sale at a reasonable price.

·         Seller’s Market. Hi-Crush paid a pretty penny in a hotly contested bidding process for this sand. Will other buyers be able to float the price to play in the Permian sandbox?

·         Regulation. As you move south in the sand deposit chain we believe Hi-Crush bought into, you approach the Monahans State Park (see map below). This area will likely be preserved from development by state law.

·         Geology. Hi-Crush has identified pay that it obviously believes it can develop – they wouldn’t buy this sized deal without geological conviction in the pay. Broader West Texas geology may pose limits to this trend. There are obviously dunes in the area, but how deep is the pay in other deposits? How good is the quality of the sand? What are  the grain sizes and what does that mean for import mix in the basin? It is yet unclear if the mine capacity Hi-Crush disclosed (3mmtpa) is repeatable in scale in the Permian.

This is HUGE. Where’s The Fanfare?

In a busy press release that disclosed two other transactions, Hi-Crush discussed in muted tones its plans for this game changing mine. They also released the news on one of the busiest earnings days of 4Q16 reporting season.

There is a reason Hi-Crush slipped this announcement out with little fanfare: this is a transformative development, and they are now the first mover. If our sources are correct, others will soon attempt to follow.

The End Justifies The Means (Mostly)

At $5/ton, the purchase price Hi-Crush paid for these reserves might seem a bit high to folks used to seeing reserves trade at half that level. But the Permian Basin is expected to consume >40% of total US sand production this year and in 2018. Permian sand demand is as close to a sure thing as you will find in the oilfield these days. The next closest frac sand mine is more than 200 miles away in Brady, TX. This mine is within 75 miles of the Midland and Delaware Basin hot spots.

Water access may play into the price, however details are limited at this point. As a first mover, Hi-Crush will be able to charge a premium by eliminating rail costs and selling its products FOB the plant to customers that are primarily completing wells in the Midland and Delaware Basins. Or they may even try to sell at the well site given proximity.

All of the above factors support the price Hi-Crush paid. On the flip side, while finer grains have been en vogue lately, 100 mesh may be too fine in some cases. And 100 mesh is what Hi-Crush says they’ve bought here. We’ve recently heard talk of conductivity issues at 100 mesh, which has caused some E&Ps to mix slightly coarser grades into the blend. That said, these issues have been one-offs, and Hi-Crush can address with Permian imports.

What’s The Over / Under On Permian Mine Capacity Announced By June?

There’s big potential for a Permian mine trend to develop here, and the Hi-Crush deal proves it. This isn’t the last we’ll hear about it, but whether it marks the start of a Permian sand grab remains unclear at this point. If the E&P industry is an analog, perhaps the next acreage valuation bubble will form around Permian sand deposits.

If you are familiar with West Texas then you know these sand deposits in the heart of the play as recreational areas where families play and camp out on the weekends among the sand dunes.

On a personal note, this author spent plenty of time riding the dunes among the sand hills of the Monahans State Park as a kid growing up in Odessa, TX. In those carefree days, we never could have anticipated a more productive use for the sand than the quick adrenaline rush from whizzing down a dune on a perfectly waxed board.

But the guys in suits have been knocking on land owner’s doors out in West Texas in growing numbers this year. We’ve heard of some property owners getting as many as 20 inquiries for their sand.

There is a large sand formation that spans about 30 miles from Monahans in the south up to Kermit in the North. The deposits around Monahans are part of a state park and would-be exploiters will likely face regulatory challenges there. But the further up you go, the more these deposits are held by private interests with discretion over the mineral rights.

There are also a few other deposits around the Permian that may have some potential, but it looks like Hi-Crush took the sweet spot in the first sand deal in the area.

Will the Hi-Crush transaction thaw the new Permian dune market resulting in a rash of transactions, or freeze it because they took the sweet spot and priced others out of the marekt? It’s too early to tell, but this may be the beginning of a highly disruptive trend in the competitive landscape for sand supply.

Now just imagine if US-style hydraulic fracturing starts to take off in Saudi Arabia… they’ve got an ocean of sand… 100-mesh you think?

 

Global LNG outlooks test conventional wisdom of supply glut

When Shell last month presented its first global LNG Outlook since its 2016 acquisition of the UK's BG Group, it surprised some by effectively denying the existence of a global LNG supply glut, pointing instead to a well balanced market where all produced LNG cargoes were being consumed.

Much of the commentary in recent months has been telling us the LNG market is already suffering a supply glut and is heading for a period of sustained oversupply until at least the start of the 2020s.

LNG prices across the globe have fallen to multi-year lows -- other than a mostly weather-related spike in late 2016 -- and the expected slew of new project start-ups in 2017 from Australia and the US has been forecast to lead to a hugely oversupplied market with demand growth unable to keep pace.

The report from Shell -- which is now more exposed than ever to LNG market dynamics since the BG purchase -- was in stark contrast to other views from the industry.

Some players already talk of an oversupplied LNG market, with things only set to worsen in the coming years.

Pablo Galente Escobar, head of LNG at global trader Vitol, said at a London conference last month his view of the LNG market was "very different" to Shell's.

"We think the market will be significantly oversupplied over the next five years," he said, pointing to expected LNG supply growth to 400 million mt/year by 2020 from 240 million mt/year in 2015.

This growth, he said, was unprecedented in the history of commodities, and represented the biggest "supply shock" he had ever known.

The CEO of Italy's Eni pointed last month to a period of oversupply that would end only in time for some of its new LNG projects to start operations.

"In LNG we have a situation of oversupply and we expect a re-balance early next decade when demand catches up," Claudio Descalzi told analysts at a London strategy presentation.

"Then, we see a need for new supply, which is a huge opportunity for our gas projects coming on stream," Descalzi said, referring to Eni's planned Mozambique and Egypt LNG export projects, among others.

BP, in its latest energy outlook in January, also pointed to strong LNG supply growth in the period 2017-2021, while Norway's Statoil said in its own outlook that the critical question was whether new gas supplies would be developed in time to meet future forecast demand, or if the current gas surplus would turn into a deficit and a tight market.

"The global LNG market is exposed to boom-and-bust cycles -- the underlying growth in world LNG demand is itself not sufficient to absorb the scheduled growth in supply," Statoil said.

But, as Statoil says, markets have to balance.

Therefore, the LNG glut is likely to accelerate the transition of global LNG into a more regular commodity market.

And this is an increasingly widely accepted view -- that LNG is becoming more and more commoditized and more and more of a global fuel.

AGENDA-DRIVEN OUTLOOKS

So, are these 'views' driven by the agenda of the view-giver?

Probably.

Vitol and the other global commodity traders are always on the lookout for opportunities to exploit margins, buoyed by price volatility, and over- and under-supply often lead to fast and unpredictable price movements.

In addition, traders are more willing to trade with credit-risky countries -- the likes of Egypt -- which are using LNG imports to either replace domestic production or to kick-start a gas-to-power industry.

A well supplied market is more likely to entice new countries into becoming LNG importers, giving traders like Vitol more room in a market that has been traditionally dominated by major oil companies.

Likewise on the demand side, Hoegh LNG -- a leading supplier of floating storage and regasification units (FSRUs) -- said last week the "long LNG market and competitive LNG prices" had led to increasing utilization of new importing facilities, "the majority of which are FSRUs".

No surprise there.

As for Shell, well having spent more than $50 billion to buy BG in February 2016, it now has LNG sales of 57 million mt/year, around 22% of the global market.

The sales price for its LNG obviously matters given its vast LNG portfolio, so the more balanced the market the better for its bottom line.

"We read about a flood of LNG, and that is clearly not the case -- we just do not see it," Steve Hill, Shell's head of energy and gas marketing and trading, said at the London briefing in late February.

Shell justifies its stance on LNG market dynamics by pointing to various pieces of evidence:

1) Every cargo that could be physically produced in 2016 was produced and was consumed;

2) LNG flows to the liquid markets of Europe -- often seen as the market of last resort in an oversupply situation -- were flat, and to Belgium and the UK down, which Shell said was a good sign and a "very clear demonstration" of the strength of demand in LNG;

3) LNG prices were "healthily" priced as a percentage of crude oil.

Hill said last month that demand growth would keep pace with supply growth in coming years and demand growth would be accelerated by low prices and many growing markets are those with already mature infrastructure like Egypt and Pakistan.

'CRYING WOLF?'

Shell is not alone, meanwhile, in signaling caution over predictions of LNG market oversupply.

The Oxford Institute for Energy Studies (OIES) last month published a paper entitled "The Forthcoming LNG Supply Wave: A Case of 'Crying Wolf'?" that warned against taking the wave of LNG supply growth for granted.

Author Howard Rogers argued that the eventual outcome and levels of LNG supplied can be very different from expectations due to:

1) Project construction schedule slippage (often associated with cost escalation above budget);

2) Commissioning problems -- new plants can suffer unscheduled shutdowns and may remain offline for weeks during which modifications are carried out before commissioning is attempted again;

3) Feed gas supply issues, which can constrain supply below nameplate capacity until upstream issues are resolved.

The OIES echoed Shell's view that the market was not oversupplied in 2016 and that Europe did not take the bigger volumes it had been expected to absorb.

But, despite its caution, the OIES said the wave would eventually come -- maybe more slowly than thought -- and that it would have an impact on Europe, the market of last resort for LNG.

Platts Analytics' Eclipse Energy also sees evidence the market last year was more balanced than had been expected, due to a series of unplanned outages at the beginning of the year, coupled with the continued shutdown of the Yemen LNG plant and unexpected issues at Gorgon and Angola LNG.

Asian LNG demand was also higher than expected, with Chinese imports up to support the drive for cleaner air and Japan and South Korea both needing more LNG than expected due to issues around nuclear generation.

"Going forward the issues observed in 2016 remain key uncertainties to the realization of a global surplus, however the amount of new supply coming online should see the realization of an oversupplied market," Platts Analytics said.

Looking at how much Europe -- the market of last resort -- imports is key to defining whether the global LNG market is oversupplied or not.

Platts Analytics data showed European LNG imports remained flat in the 2014-2016 period despite the fact that a market becoming oversupplied may be expected to see European imports rise to soak up the oversupply.

However, the relatively low LNG prices for much of 2016 did nothing to entice LNG into Europe despite higher demand.

Instead, it was met by pipeline gas from Algeria, Norway and Russia.

Of course, the main beneficiary of an oversupplied market for any commodity is the customer, not only because of cheaper prices but also to ensure security of supply.

The International Energy Agency said in an LNG security report last November that the massive expansion of LNG export capacity was coming at a time of weaker-than-expected global gas demand, and that the temporary excess of supplies resulting from this situation "is providing a buffer that would mitigate the impact of possible supply disruptions".

http://www.platts.com/latest-news/natural-gas/london/analysis-global-lng-outlooks-test-conventional-26683006

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From Pakistan to Turkey, the world's largest independent oil trader Vitol is betting on a spike in gasoline and diesel demand in young and growing nations by snapping up filling stations that disappointed oil companies are prepared to sell.

With the sharp drop in global oil prices, major integrated oil companies have been shedding assets, including the marginally profitable retail outlets, to cut costs.

But privately-held Vitol, which trades 6 million barrels per day of crude oil and refined products, says these assets present an opportunity to strengthen its presence in end-markets and in up-and-coming hubs.

This month, Vitol secured more than 23 percent of Turkey's retail market after it agreed to buy Petrol Ofisi from Austrian oil firm OMV for $1.45 billion.

"The volume we trade means integration into the distribution chain makes sense. Retail also allows you to participate in markets on an on-going basis, so it's not always ad hoc or spot," Chris Bake, a top Vitol executive, told Reuters.

"It allows us to have different kinds of discussions with our suppliers," said Bake, who sits on Vitol's executive committee and is the chairman of retail unit Vivo Energy.

The purchase will add another 1,700 outlets to Vitol's portfolio of 3,000 stations acquired through investments in the last few years in Viva Energy in Australia, Vivo Energy in Africa, Varo in central Europe and OVH in Nigeria.

It has also consolidated its initial investments such as by buying Royal Dutch/Shell's stake in Vivo and Viva and its aviation business in Australia last year.

The eastern Mediterranean is a major import market and Vitol sees Turkey as a good destination because of its proximity to transport routes from the Mediterranean, Black Sea and Red Sea.

"With fuel and non-fuel retailing, we can optimize the system. We are able to look closely at how to streamline the assets and we are willing to invest capital. With Vivo, we have added around 100 new service stations per year," Bake said.

Of its main trading competitors, only Trafigura is also vying for a piece of the retail pie. It has a large presence in Africa through its subsidiary Puma Energy and is set to acquire a large stake in India's Essar Oil.

Glencore, Gunvor and Mercuria have favored upstream or midstream assets. Last year, Gunvor bought a refinery in Rotterdam, Mercuria bought oil and gas marketing and distribution assets in the United States and Glencore invested in oil deposits in Chad.

Vitol's retail investments fit in with its view that transport will be the major driver of fuel demand growth, with aviation demand to outstrip that for cars, which is slated to peak in about 10 years time.

"Global demand for gasoline and diesel will peak but you can't apply the macro picture to individual countries that have high growth prospects like Pakistan where the Chinese are investing tens of billions of dollars in the CPEC (China Pakistan Economic Corridor), so demand will grow compared with developed economies," Bake said.

Last year, Vitol increased its stake in Pakistan's Hascol Petroleum Ltd that runs around 450 service stations from 15 to 25 percent.

Like Turkey, apart from its own growth prospects, Pakistan will become even more a gateway to the rest of Asia as CPEC will see the Chinese government invest $57 billion, mainly in a network of rail, road and pipeline projects, to connect Western China to Pakistan's sea port of Gwadar.

http://www.reuters.com/article/us-vitol-oil-retail-idUS

Libya's oil output has fallen to 620,000 barrels per day, a drop of about 80,000 bpd since clashes erupted around some of the country's major export terminals, the head of the National Oil Corporation (NOC) said.

Mustafa Sanalla told Reuters that production by Waha Oil Co, a joint venture between NOC and foreign partners, had been entirely halted. Waha pumps oil to Es Sider, one of two ports that the eastern-based Libyan National Army (LNA) lost control of last Friday to a rival faction.

A port official at Ras Lanuf, a neighbouring terminal that the LNA also withdrew from, said that production by another NOC joint venture, Harouge Oil Operations, had also been affected, without giving details.

Libyan oil officials say staff at Es Sider and Ras Lanuf have been reduced to a minimum since a faction known as the Benghazi Defence Brigades (BDB) seized them in clashes, and that the area is effectively a military zone.

The BDB say they have handed the ports over to a Petroleum Facilities Guard (PFG) force sanctioned by the U.N.-backed government in Tripoli, and that they would allow oil to flow.

http://af.reuters.com/article/libyaNews/idAFL5N1GM7WY

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Attached Files

Repsol and partner Armstrong Energy state that they have made the largest U.S. onshore conventional hydrocarbons discovery in 30 years.

Repsol and partner Armstrong Energy stated that they have made the largest U.S. onshore conventional hydrocarbons discovery in 30 years.

The Horseshoe-1 and 1A wells drilled during the 2016-2017 winter campaign confirm the Nanushuk play as a significant emerging play in Alaska’s North Slope, Repsol said in a company statement.

Contingent resources identified with the existing data in Repsol and Armstrong Energy’s blocks in the Nanushuk play in Alaska could amount to approximately 1.2 billion barrels of recoverable light oil, Repsol revealed.

The Madrid-based energy company has been actively exploring Alaska since 2008, and since 2011 the company has drilled multiple consecutive discoveries on the North Slope along with partner Armstrong.

“The successive campaigns in the area have added significant new potential to what was previously viewed as a mature basin,” a Repsol representative said in a company statement.

“Additionally Alaska has significant infrastructure which allows new resources to be developed more efficiently,” the representative added.

Repsol holds a 25 percent working interest in the Horseshoe discovery and a 49 percent working interest in the Pikka Unit. Armstrong holds the remaining working interest and is currently the operator.

The Horseshoe discovery extends the Nanushuk play more than 20 miles south of the existing discoveries achieved by Repsol and Armstrong in the same interval within the Pikka Unit during 2014 and 2015, where permitting for development activities are underway.

Preliminary development concepts for Pikka anticipate first production there from 2021, with a potential rate approaching 120,000 barrels of oil per day.

The Horseshoe-1 discovery well was drilled to a total depth of 6,000 feet and encountered more than 150 feet of net oil pay in several reservoir zones in the Nanushuk section. The Horseshoe-1A sidetrack was drilled to a total depth of 8,215 feet and encountered more than 100 feet of net oil pay in the Nanushuk interval as well.

http://www.rigzone.com/news/oil_gas/a/148803/Repsol_Makes_Largest_US_Onshore_Discovery_in_30_Years?utm_source=GLOBAL_ENG&utm_medium=SM_TW&utm_campaign=FANS

Kremlin spokesman Dmitry Peskov told reporters on Friday that President Vladimir Putin had met new Exxon Mobil chief executive officer Darren Woods on Thursday.

Russia's energy minister, Alexander Novak, and Rosneft head Igor Sechin attended the meeting, according to the spokesman.

"This is a very big company and it is a major investor. This is why it receives special treatment," Peskov said in reference to Exxon Mobil.

He also said Moscow will keep working on improving the environment for all foreign investors.

http://www.reuters.com/article/us-russia-putin-us-oil-idUSKBN16H14L

Deepwater oil drilling can be expensive, time-consuming and a hard sell to investors. But the world's top energy firms are restarting their search for giant oilfields under the ocean after a two-year lull.

A recovery in oil prices to about $50 a barrel from a 12-year low in 2016 is reviving oil majors' appetite for risk.

Reductions in offshore production costs mean that some projects may be able to compete with North American shale fields, executives said at an energy conference in Houston this week.

The recovery in the industry has so far been focused on onshore shale output from the largest U.S. oilfield, the Permian Basin.

"Our competition over the past years has evolved from 'we want to be the best in deepwater' to 'we want to compete with shale' to 'we want to beat the Permian'," Wael Sawan, Royal Dutch Shell's executive vice president for deepwater, said in an interview.

Shell is the largest deepwater producer among the world's top publicly traded oil companies and is set to pump 900,000 barrels per day (bpd) from such projects by the end of the decade.

Firms such as Shell and Exxon Mobil, who specialize in complex offshore exploration, slashed budgets after oil prices collapsed in 2014. Spending cuts were so drastic that the Paris-based International Energy Agency warned this week of a looming supply crunch beyond 2020.

Shell has cut well costs by at least 50 percent, reduced logistics cost by three quarters and cut staff by nearly a third to make developments in areas such as the Gulf of Mexico and Nigeria profitable at oil prices below $40 a barrel, on par with the most profitable shale wells, Sawan said.

Other companies such as France's Total have seen similar cost cuts.

SNIPER FOCUS

After cutting the cost of deepwater development, companies are also reviving the search for new resources.

They are focusing exploration efforts on areas close to existing fields to maximize the chances of discovery and minimize costs. Many such areas are in Brazil, the Gulf of Mexico and Southeast Asia.

"It is a very selective, sniper focus," Sawan said.

Some firms are poised to benefit from decreased competition, lower costs of marine seismic studies and drilling rigs, and cheaper opportunities to acquire exploration licenses from governments eager to attract investment.

"Right now, we've entered the best time in the last decade to be in the exploration business," Gregory Hebertson, who heads Murphy's western hemisphere exploration, said at the CERAWeek conference in Houston. "There is probably a two- or three-year window that we can capture the cost efficiency in the market."

Discovering new resources is essential for oil firms to grow and to offset natural decline of fields. But deepwater exploration requires money, time, expertise - and luck.

Some shareholders would prefer that oil firms stick to other, less risky growth options, said Federico Arisi Rota, executive vice president Americas for Italy's Eni, which operates major offshore drilling projects.

"We must compete with alternative growth options that might be considered more attractive," such as growth through mergers and acquisitions or investing in shale oil production, Rota said.

Pressure to limit company spending amid a slow recovery in oil prices is also putting a break on big exploration campaigns.

"We know exploration spending is not always appreciated by investors," Kevin McLachlan, head of exploration for Total said.

RISKIER PLANS AHEAD

Eni is considered one of the most successful explorers after the discovery of giant gas fields in Egypt in recent years. It aims at discovering 2 to 3 billion barrels of oil and gas this year through drilling 115 offshore wells near Africa, Mexico, Norway and Asia, Rota said.

A "more aggressive" exploration program is planned to start in 2018 in riskier and more expensive regions such as the Arctic, which offer the potential big discoveries, he said.

Deepwater resources will be required to keep up with the growing demand, regardless of output growth in shale oil fields, Total's McLachlan said.

Such projects are "key to our long-term plan, and we believe it is the same for the industry no matter the near-term focus on the Permian," McLachlan said, referring to the largest U.S. oilfield in west Texas.

Hess Corp Chief Executive John Hess said the company's Liza development, off the coast of Guyana, was crucial to his company's growth potential and estimated to have as much as 2 billion barrels of oil.

"This is one of the largest oil discoveries in the last 10 years," Hess said in an interview.

http://www.reuters.com/article/us-ceraweek-exploration-idUSKBN16H0KM

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Attached Files

Russia’s Gazprom has delayed the launch of its planned Baltic liquefied natural gas facility to 2022-2023.

The project’s commissioning date could be revised once the project documentation is finalized, Reuters reported citing a prospectus for a Eurobond issue.

The liquefaction and export plant will have a capacity of 10 million mt of LNG a year. Initially, the production was expected to start in 2021.

In June last year, Gazprom and Hague-based LNG giant Shell signed a memorandum of understanding regarding the Baltic LNG project.

Under the MoU, the two companies agreed to study the possibilities for the construction of an LNG export plant in the port of Ust-Luga in the Luga Bay of the Gulf of Finland.

http://www.lngworldnews.com/report-gazprom-delays-baltic-lng-start/

France’s Engie SA plans to sell its entire 10 percent holding in India’s biggest importer of liquefied natural gas.

GDF International, an Engie unit, has written to the four Indian state-owned companies that together own half of Petronet LNG Ltd. to offer shares in proportion to their holding in the company, Petronet said in a stock-exchange filing Thursday.

“It is mandatory for GDF to offer its holding to other founders as per the shareholders agreement,” R.K. Garg, finance director of Petronet LNG, said in a phone interview. “Only if the other founders don’t buy, GDF can sell it to anyone it wishes.”

Explorer Oil and Natural Gas Corp., refiners Bharat Petroleum Corp. and Indian Oil Corp., and gas distributor GAIL India Ltd. form the founder group, with a 12.5 percent stake each in Petronet. If any of the founders buy the stake, Petronet, which operates as a joint venture, could become a wholly government-owned company that would reduce its flexibility to take independent decisions.

The founders may not buy the stake, said A.K. Srinivasan, director finance at ONGC.

“It is not necessary for us to buy,” he said. “The structure has to be maintained otherwise government approval is required.”

ADB Stake

In 2014, Asian Development Bank had sold 39 million shares of Petronet LNG. It had first offered these to the four founders, who chose not to buy the shares. It eventually sold its 5.2 percent stake in the open market.

Engie holds 75 million shares in Petronet valued at about 29 billion rupees ($434 million) at current market prices. Petronet rose 0.3 percent at 387.55 rupees as of 2:47 p.m. after falling as much as 2.2 percent following the announcement.

“I’m not sure they can sell a 10 percent stake easily in the market,” said Sabri Hazarika, a Mumbai-based analyst at Phillipcapital India Pvt. “Some other strategic investors can come in like companies from Qatar or the UAE.”

Subir Purkayastha, director finance of GAIL India, A.K. Sharma, the finance head of Indian Oil and P. Balasubramanian, director finance at BPCL, couldn’t be reached for comment on their mobile phones.

https://www.bloomberg.com/news/articles/2017-03-09/engie-seeks-to-sell-entire-stake-in-india-s-biggest-lng-importer