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    New Software Puts Real-time Drilling Monitoring in Reach (Saturday, 17 February 2018)

    17 Feb 2018, 12:00 am

    Software puts real-time drilling monitoring in reach Proactive Real Time Systems (PRTS) has launched its new software product called the Real-Time Advisory System (RTAS).

    RTAS has been under development for more than a year and is designed to offer an improved and scalable solution for utilization of wellsite information transfer standard markup language (WITSML) information from any source involved in measuring and monitoring wellsite operations. In addition to state of the art IT architecture and security,


    the software offers a unique physics based analysis of well conditions. This analysis results in timely predictive watches that avoid the common problem of many existing real-time systems—notification after an undesired event occurs, often too late to mount an effective response.

    Historically teams have had to struggle with gathering, analyzing, and using WITSML data in an effective way. The software was designed to solve the problems teams have encountered, with previous real-time IT systems - ease of use, team collaboration, cost, and effectiveness. Monitoring can be done with any internet enabled device including laptops, tablets, and smart phones.


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    Woodside Crafts New LNG Expansion Plan After Striking Exxon deal (Friday, 16 February 2018)

    16 Feb 2018, 11:00 pm

    Australia’s Woodside Petroleum finally got what it wanted from Exxon Mobil. And it only cost $744 million.

    As far back as 2013, Exxon planned to develop a floating liquefied natural gas venture for the Scarborough field offshore Western Australia. Woodside had a different idea. After buying into the project in 2016, it tried to convince the world’s largest publicly traded oil company to send the gas onshore to its own LNG plant. With no sign of an agreement, the Perth-based company said Wednesday it will buy up Exxon’s stake, gaining control of the development.


    The purchase, funded as part of a broader A$2.5 billion ($2 billion) share sale, may accelerate development of the remote gas project to help feed an expansion of the Pluto LNG plant and meet demand from Asia, CEO Peter Coleman said on an earnings call Wednesday.

    Woodside may pay as much as $7.9 billion of the estimated $9.7 billion cost of delivering the Scarborough project, which includes a pipeline and a second Pluto LNG train, according to a company presentation. BHP Billiton holds a quarter stake and a final investment decision is due 2020, with production scheduled to start in 2025.

    Funding its share of Scarborough and the development of its Browse LNG venture with no near-term production pay-off may cause concern among Woodside investors, JPMorgan Chase & Co. analyst Mark Busuttil said in a research note Wednesday.

    Raising capital at the current point in the oil cycle “is a bold move and somewhat premature in our view,” Neil Beveridge, a senior analyst at Sanford C. Bernstein & Co. in Hong Kong, said in an email. “While the stock will react negatively to this announcement, there is method in the madness if you believe in LNG market growth.”

    Woodside requested its shares temporarily halt trading until it announces the outcome of the institutional component of the share sale. The company also announced full-year net income of $1 billion, in line with analyst estimates.

    For Exxon, Scarborough’s once-promising 7.3 trillion cubic feet of gas fell out of favor with the energy giant as more profitable, less risky LNG opportunities arose in places like Papua New Guinea and Mozambique. Still, the company remains wedded to the floating-production model: ships built to process and export crude are linchpins of Exxon’s plans to harvest massive offshore crude discoveries in Guyana.

    Woodside will also use funds from the share offer to develop its SNE oil project in Senegal and bring its Browse project to a final investment decision by 2021, a year later than previously planned. Up to 10 million tons of LNG could be developed from Browse at the North West Shelf complex at an overall project cost of $20.5 billion with Woodside funding up to $6.3 billion of the planned capital expenditure.


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    Over $58.5bn Will be Spent on North Sea’s Upstream Capex by 2020, says GlobalData (Friday, 16 February 2018)

    16 Feb 2018, 8:00 pm

    An average capital expenditure (capex) of $19.5bn per year is forecast to be spent on 568 oil and gas fields in North Sea between 2018 and 2020, according to GlobalData, a leading data and analytics company.

    Capital expenditure in the North Sea's traditional oil projects will add up to $35.5bn over the three-year period, while heavy oil fields will require $5.1bn over the same period. Investments into gas projects in North Sea would total $17.9bn in upstream capital expenditure by 2020.


    Shallow water projects will be responsible for over 92 percent of $58.5bn of upstream capital expenditure in North Sea, or $53.6bn by 2020. The deepwater projects will necessitate $4.9bn in capital expenditure over the period.

    GlobalData expects that Statoil ASA will lead North Sea in capital expenditure, investing $9.8bn into the region's upstream projects by 2020. Petoro AS and BP Plc will follow with $3.5bn and $3.3bn invested into North Sea's projects between 2018 and 2020.

    Johan Sverdrup, a planned conventional oil field in the Northern North Sea Basin, will lead capital investment with $8bn to be spent between 2018 and 2020. Statoil Petroleum AS is the operator for the field. Mariner, another planned oil field in the Northern North Sea Basin, follows with a capex of $2.6bn. Statoil (U.K.) Ltd is the operator of the field. Tyra, a gas producing field in Central Graben Basin, will follow next with a capex of $2bn. Maersk Olie og Gas AS is its operator. All the three fields are shallow water fields.

    GlobalData reports the average full cycle capital expenditure per barrel of oil equivalent (capex/boe) for North Sea projects at $12.82. Shallow water projects have the lowest full cycle capex/boe at $12.76, followed by deepwater developments with $15.73.


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    Norway, Russia Sent Record Gas Volumes to Europe in 2017 (Friday, 16 February 2018)

    16 Feb 2018, 6:00 pm

    Gas exports to Europe from both Russia and Norway climbed to record levels in 2017, according to fresh analysis by Rystad Energy. Russian and Norwegian gas exports to Europe (including Turkey) reached 194 Bcm and 122 Bcm, respectively, in 2017. This represents a year-on-year increase of more than 15 Bcm for Russia and 9 Bcm for Norway. Both countries have shown upward output trends since 2014.


    “The higher exports have provided reliable supply for Europe and give an indication that the strategy followed by both Russia and Norway has been to maintain their market share, benefiting European consumers as prices in NW Europe have remained rather stable. This has also kept new U.S. supplies of LNG out of the region, enabling American gas to meet increasing demand in Asia and Latin America,” says Carlos Torres-Diaz, Rystad Energy’s V.P. of gas markets.

    However, while Russia is projected to further strengthen its dominant position, Norwegian output is poised to decline in the coming years.

    Annual output from several key gas fields in Norway – Ormen Lange, Aasgard and Kvitebjorn – is expected to decline by 10 Bcm by 2020 as compared to their production levels recorded in 2017. This will only be partially offset by the 8.6 Bcm increase in projected annual gas output in the same period from the startup of Aasta Hansteen field. Similarly, production in other European countries is expected to continue declining.

    In contrast, Rystad Energy sees increased gas production in Russia going forward. “With the ramp-up and expansion of the Yamal LNG plant and the completion of the Power of Siberia pipeline, exports to Asia are expected to increase. However, the increased production, coupled with the continuation of Gazprom’s Nord Stream 2 and TurkStream pipeline projects, leaves large potential for even higher exports to Russia’s main market, Europe,” said Torres-Diaz.


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    Physical Oil Market Sends Warning to OPEC: Rout Might Not Be Over (Friday, 16 February 2018)

    16 Feb 2018, 2:00 pm

    As OPEC watches a near 15 percent drop in the oil price in three weeks, important indicators in the physical crude market are flashing signals that the decline might be far from over.

    The warnings come not from the heavily traded futures market, but from less transparent trading activity in crude oil and products markets, where key U.S., European and Russian crude prices have fallen of late, suggesting less robust demand.


    Benchmark oil futures have plunged in recent days together with global stock markets due to concerns over inflation as well as renewed fears that rapid output increases from the United States will flood the market with more crude this year.

    OPEC, including its Secretary-General Mohammad Barkindo, argues the decline is just a blip because demand is exceeding supply and that prices won’t plunge again to $30 per barrel as they did in 2015 and 2016.

    Traditionally, when oil futures decline, prices in the physical markets tend to rise because crude is becoming cheaper and hence more attractive to refiners.

    But in recent weeks, differentials in key European and U.S. markets such as North Sea Forties, Russia’s Urals, West Texas Intermediate in Midland, Texas, and the Atlantic diesel market have fallen to multi-month lows.

    The reasons tend to be different for most physical grades but overall the trend paints a bearish picture.

    “Physical markets do not lie. If regional areas of oversupply cannot find pockets of demand, prices will decline,” said Michael Tran of RBC Capital Markets.

    “Atlantic Basin crudes are the barometer for the health of the global oil market since the region is the first to reflect looser fundamentals. Struggling North Sea physical crudes like Brent, Forties and Ekofisk suggest that barrels are having difficulty finding buyers,” he added.

    This follows a run-up in U.S. production to 10.04 million barrels per day as of November, the highest since 1970. The increase pushed the United States into second place among crude producers, ahead of Saudi Arabia and trailing only Russia, according to the U.S. Department of Energy.

    On Tuesday, the Paris-based International Energy Agency said increased U.S. supply could cause output to exceed demand globally in 2018.

    Forties crude differentials to dated Brent have fallen to minus 70 cents, from a premium of 75 cents at the start of the year as the Forties pipeline returned to normal operations.

    Forties differentials are now not far off their lowest since mid-2017, when the benchmark Brent crude price was around $45 per barrel, compared to $62 now and $71 a few weeks ago.

    In the United States, key grades traded in Texas and Louisiana have fallen to their lowest in several months.


    A similar pattern can be observed in the Russian Urals market, one of the biggest by volume in Europe.

    At a discount of $2.15 to dated Brent, Urals’ differentials in the Mediterranean are now at their lowest since September 2016, when Brent futures were around $40-$45 per barrel.

    “Sour grades are not in good shape worldwide” and neither are Urals, said a European crude oil trader, who asked not to be identified as he is forbidden from speaking publicly.

    That contrasts with the start of 2017, when OPEC cuts to predominantly sour grades made them attractive to buyers.

    “Supply is more than ample in Europe, Urals face strong competition from the Middle Eastern grades,” said another trader on the Russian crude oil market, adding that supplies of Urals to Asia were uneconomic due to a wide Brent-Dubai spread.

    Adding pressure on Urals, traders expect loadings of the grade to rise in the coming months due to seasonal maintenance at Russian refineries.

    A decline in physical crude values generally means better margins for refiners. But it is also not happening this time.

    The profit margin refiners make on processing crude into diesel collapsed in Europe and the United States by over 18 percent in the past week, according to Reuters data.

    Europe, where nearly 50 percent of vehicles are fueled by diesel, is home to the global benchmark for diesel prices and the biggest storage hub for the road fuel as regional refineries are unable to meet local demand.

    “Oil demand isn’t that bad in general, but heating oil demand has been horrible, particularly in the United States and Germany,” Robert Campbell, head of global oil product markets at consultancy Energy Aspects, said.

    “European refineries are running at very high rates since December so there is plenty of supply in the region while the weather has been warmer than usual, which led to weaker demand.”

    The refined product markets were expected to tighten significantly in March and April due to a busy schedule for seasonal refinery maintenance. [REF/E]

    But in a further indication of wavering confidence, the spread between the April low-sulfur gasoil futures to the May contract also crashed in recent weeks from an all-time high premium of $5 on Jan. 26 to a discount of 50 cents on Tuesday.


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    Bumper West of Shetland Oil Field Project to Move Into Production Next Year (Friday, 16 February 2018)

    16 Feb 2018, 12:00 pm

    HURRICANE Energy has said it is on track to start production from the giant Lancaster field West of Shetland next year with work on the production facilities progressing well.

    Five months after Hurricane provided a boost for the hard-pressed North Sea oil and gas industry by approving plans for the $500m (£360m) Lancaster development, the company said it had passed a key project milestone.

    Surrey-based Hurricane said tests of the mooring system that will be used by the floating production storage and offloading vessel on the field had been completed successfully a week ahead of schedule in Dubai.


    The FPSO is expected to leave Dubai on schedule in the third quarter following the completion of renovation and upgrade work.

    Chief executive Robert Trice said he was delighted with the results of the trial, which involved testing the connection between the FPSO and a buoy that will form part of the mooring system.

    “With other operations continuing as planned, we remain on schedule for target first oil in H1 2019,” said Mr Trice.

    Hurricane’s progress will be followed closely in the North Sea. Its exploration success West of Shetland has fuelled hopes there could be a surge of drilling activity in what remains a relatively under-explored area.

    Hurricane expects to pump 19,000 barrels per day from an early production system on Lancaster, which it thinks could pave the way to a much bigger development.

    It reckons the Lancaster licence may contain more than 500 million barrels oil.

    Separately, Aberdeen-based oil and gas well engineering specialist Plexus Holdings said it has made progress in the key Russian target.

    The company has struck a £1.4m deal to sell two wellheads to a Russian partner, LLC Gusar, which has a licence to rent out its jack-up wellhead equipment for use in exploration in the country.

    Following the recent sale of its jack-up wellhead exploration equipment and services business to FMC Technologies for up to £42.5m, Plexus retained the right to pursue business in Russia under the licence.

    Chief executive Ben van Bilderbeek said the wider Russian region was a central area of focus for Plexus.

    He noted: “The sale of these two wellhead sets is a key step towards Gusar securing a landmark first rental order from a local Russian gas operator.”


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    Oil Policy ‘Firm’ But Faces EU Pressure (Friday, 16 February 2018)

    16 Feb 2018, 10:00 am

    Norwegian government officials have been stressing lately that the country’s oil policy remains firm, even though new coalition colleagues have viewed it as stimulating too much risky exploration. Now EU competition authorities have been asked to review whether refunds of unprofitable exploration costs also amount to illegal state subsidy, raising new uncertainty in an industry still adapting to lower oil prices.

    A vast majority of Norwegian politicians on both the left, right and center have long supported and promoted the country’s oil and gas industry. In 2005 they wanted to stimulate more offshore oil exploration, and the then-Labour Party-led government ushered in Norway’s so-called leterefusjons- ordiningen. It allows oil companies to receive refunds of up to 78 percent of their exploration costs if they don’t find oil, an incentive that’s even greater than the eventual tax write-offs the companies otherwise would receive later.


    The policy has attracted new players to Norway’s offshore oil fields over the years and been both furthered and actively promoted by the Conservative-led government coalition that took over in 2013. Its oil ministers have also been just as bullish on opening up new areas as their left-center predecessors, including blocs in the environmentally sensitive Arctic. That’s been controversial, as has the state support for the exploration, but climate and environmental activists have won little if any change, no matter which political parties hold government power.

    ‘Firm and steady course’

    The recent expansion of Norway’s current conservative coalition raised some environmentalists’ hopes that the newcomer Liberal Party would rein in the government’s most gung-ho policies. The Liberals had criticized the potential for refunds of oil companies’ exploration costs, but wasn’t able to scrap them. The Liberals did secure ongoing suspension of moves to open areas off scenic Lofoten and Vesterålen to oil drilling and secured “consideration” for environmental advice in especially sensitive areas, but the Conservative and Progress parties quickly issued assurances that there would be no major changes in oil exploration or tax policy.

    “We are furthering the strengths of Norwegian petroleum policy,” Oil Minister Terje Søviknes of the Progress Party told newspaper Aftenposten recently, stressing that it “provides long-term consistency that an industry with long lead time must have.” Søviknes added that “the most important thing you can read” out of the expanded government’s platform for the oil and gas sector “is that we’ve plotted a firm and steady course, even after the Liberals came into the government.”

    ‘Childish’ subsidy complaint

    Environmental organization Bellona, however, has filed a complaint with European competition authorities who monitor Norway’s compliance with EU regulations. Bellona contends that a refund of 78 percent of exploration costs (meant to correspond with Norway’s high 78-percent tax rate on earnings from oil operations) violates EU subsidy regulations. If the European competition authorities agree, oil companies may need to pay back refunds they’ve received over the past 10 years.

    Reaction has been predictably sharp, with Ola Borten Moe of the Center Party (a former oil minister himself who’s now among the founders of oil company Okea) calling Bellona’s complaint “childish” this week. Moe is not at all happy that one of Norway’s most lucrative tax advantages is being challenged.

    “The contention that this amounts to illegal subsidy is a problem Bellona has created because it’s opposed to the entire (oil) industry,” Moe told newspaper Dagens Næringsliv (DN) on Monday. He stressed that there’s a solid majority in Parliament in favour of the refunds for exploration costs: “After (Bellona) lost through normal democratic processes, they’re trying to go through the EU competition authorities, or the courts.”

    Moe, deputy leader of a party that champions subsidies for the agricultural industry, claimed Bellona and its leader Frederic Hauge are “mounting an attempt to destroy the Norwegian people’s self-rule.” Moe went on to add that “it’s childish of Bellona to file its complaint … Frederic Hauge is a bad loser.”

    Exercising ‘opportunities for influence’

    Hauge himself retorted that the Norwegian Parliament long ago agreed to be a member of the European Economic Area (EEA, called EØS in Norwegian) after Norway voted against joining the EU itself. The EEA membership obligates Norway to follow most EU regulations, including those applying to subsidy and competition, in return for full access to the EU market.

    “Borten Moe’s comments are on a level I won’t spend much time on,” Hauge told DN. “We have agreed to be a member of the EEA, against (Moe’s) Center Party’s will, and that gives us rights and opportunities for influence that we’re using.”

    DN noted that Moe’s own Trondheim-based oil company, Okea, has received oil exploration refunds of nearly NOK 4 million, even though its business model targets oil discoveries that haven’t been developed as opposed to engaging directly in exploration itself. Moe admitted that the refund program “can become more important” for his company in the years ahead.

    Potentially expensive lack of new discoveries

    Meanwhile Moe and others in the oil industry call it “perhaps the most profitable measure Norway has introduced during the past 30 years.” At a time when oil prices have been rising, companies including Statoil are reporting record profits and optimism is returning to the industry, exploration may pick up.

    Last summer’s exploration in the Barents Sea, however, was disappointing and the lack of new discoveries may prove expensive for the state when refunds of costs don’t eventually lead to profits that can be taxed. Statoil CEO Eldar Sætre himself said last week, after reporting a huge jump in profits on lower operating costs, that his only major concern now is the lack of new, large discoveries of more oil and gas. Even though Norway’s Johan Sverdrup field is being called “a money machine,” Statoil, other oil companies and the oil service sector need new projects for the future.

    Oil Minister Søviknes shares the concern: “We must keep searching (for more oil) so that the oil service sector will have new projects to work on.”


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    Statoil to Lead North Sea Spending (Friday, 16 February 2018)

    16 Feb 2018, 10:00 am

    More than $58 billion in North Sea spending is expected over the next two years, and most of that is from the Johan Sverdrup field offshore Norway, data show.

    A review of capital expenditures in the North Sea from GlobalData, an analytics company, found an average of $19.5 billion annually will be spent on more than 560 oil and gas fields in the North Sea to 2020.


    According to its review, emailed to UPI, Norwegian energy company Statoil will lead the pack in the North Sea with close to $10 billion in spending expected by 2020. The company will spend nearly all of that, about $8 billion, on developing the Johan Sverdrup oil field.

    Contracts worth more than $5.7 billion have been awarded by Statoil for Johan Sverdrup project so far and most of those have gone to companies in Norway.

    Statoil, which holds a majority share in the field, said in early February the resource range has been updated slightly, from 3 billion barrels of oil equivalent to 3.1 billion barrels of oil equivalent.

    Phase 1 of the field's development is currently underway and about 70 percent completed. All told, Johan Sverdrup could represent a quarter of total Norwegian production and first deliveries from the field are expected to begin in late 2019.

    Elsewhere, GlobalData's review found Statoil continues its leadership in the Mariner oil field development. The Norwegian energy company estimates the Mariner field in the British waters of the North Sea holds an estimated 250 billion barrels of oil and peak production should be around 55,000 barrels of oil per day, with first oil expected in production later this year.

    Statoil had an income of $5.2 billion in the fourth quarter of 2017, compared to a loss of $1.9 million in the same period of 2016.


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