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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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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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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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

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

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

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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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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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/

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/

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

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

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?