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    Return Energy Acquires Rycroft Area Gas Production in Alberta (Tuesday, 25 April 2017)

    25 Apr 2017, 11:00 pm

    Return Energy Inc. has acquired, through its wholly-owned subsidiary, Winslow Resources Inc., certain partner interests in its core area of Rycroft, north of Grande Prairie, Alberta, for cash consideration of $750,000 (subject to final adjustments).

    The interests acquired include production of approximately 60 boed (80% natural gas), and the non-operated 50% interest in the Company’s operated Rycroft gathering system and gas plant (Return’s ownership is now 100%). All of the acquired production is processed through the Rycroft gas plant. Based on the Company’s existing independent reserve report prepared by Sproule Associates Limited, dated effective Dec. 31, 2016 (the Reserve Report), the acquisition includes prorated proved developed producing reserves of 171,600 boe and proved plus probable reserves of 228,400 boe. Before tax, net present value of future net revenue discounted at 10% equals $989,000 for proved developed producing reserves and $1,266,000 for proved plus probable reserves.


    Ken Tompson, Return’s president & CEO, commented, “This consolidation of interests at Rycroft has been a key part of the development plan put in place since acquiring our Peace River Arch assets in October 2016. Sole ownership of the gas plant will give us greater flexibility and control over plant through-put, in addition to allowing for potential increased revenue derived from future processing of third-party volumes.”


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    Russia Indicates It Can Lift Oil Output If Deal On Curbs Lapses (Tuesday, 25 April 2017)

    25 Apr 2017, 10:00 pm

    Russian oil output could climb to its highest rate in 30 years if OPEC and non-OPEC producers do not extend a supply reduction deal beyond June 30, according to comments by Russian officials and details of investment plans released by oil firms.

    The Organization of the Petroleum Exporting Countries, along with Russia and other non-OPEC producers, pledged to cut 1.8 million barrels per day (bpd) in output in the first half of 2017.

    With global inventories still bulging, Gulf and other producers have shown increasing willingness to extend the pact to the end of 2017. Saudi Arabia and Kuwait signaled last week they were ready to prolong cuts. [nL8N1HS1D7]


    Russia, whose contribution to the cuts was 300,000 bpd, has yet to state publicly whether it wants cuts to run beyond June, although Moscow was represented on a panel monitoring the pact that on Friday recommended an extension. [nL8N1HT4UA]

    But Russian officials have also indicated that local oil companies were ready to push up output once the pact runs out.

    "According to investment programs of (Russian) companies, it is possible Russian oil production will increase once the deal expires," Deputy Prime Minister Arkady Dvorkovich said, adding firms had been held back while the deal was in place.

    "If there are no restrictions, they will decide not to hold back," he said, speaking at the weekend on the sidelines of an economic conference in the East Siberian city of Krasnoyarsk.

    He did not give figures, but Energy Minister Alexander Novak told Reuters in March that output could reach 548 million-551 million tonnes a year in 2017, equivalent to 11.01 million-11.07 million bpd, the highest average since 1987. [nL5N1GF2XX]

    In 2016, Russia produced about 547.5 million tonnes, or an average of 10.96 million bpd. [O/RUS1]

    Under the deal with OPEC, Russia was to cut production to 10.947 million bpd from 11.247 million bpd, the level achieved in October 2016 that was the highest in the post-Soviet era.


    Although Russia has not said publicly it wanted cuts extended, Novak has said he would meet Russian oil companies this month to discuss the issue. He also said an extension would be discussed with OPEC on May 24.

    Without an extension, Raiffeisenbank analyst Andrey Polishchyuk forecast Russian output rising about 2 percent in the second half of 2017 to a peak of about 11 million bpd.

    "That's because we have new oilfields," he said.

    Projects and statements by Russian firms also indicate they are ready to increase output once restraints are lifted.

    Russia's biggest oil producer Rosneft has said it plans to boost output this year thanks to newly acquired oilfields, including Kondaneft group of fields in Western Siberia, the heartland of Russian production. [nL8N1HJ3MX]

    The company had targeted 2 percent annual output growth in 2015-2017. Without any acquisitions, that would push 2017 production to more than 214 million tonnes, or 4.3 million bpd.

    Lukoil, the country's second-largest producer, has said it sees its oil output rising slightly if the global deal is not extended and could restore production to its pre-deal level in three to four months. [nL5N1GC47G]

    Mid-sized producer Tatneft said it expected to increase 2017 output by 0.5 million tonnes a year, or about 10,000 bpd, if the global production pact lapsed. [nR4N1HJ02P]


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    Statoil Plays Down Risks Ahead of Arctic Drilling (Tuesday, 25 April 2017)

    25 Apr 2017, 8:00 pm

    Norway's Statoil on Monday played down concerns that drilling in the Arctic is risky, days before it kickstarts its drilling campaign in the Barents Sea, where the country believes around half of its remaining resources could be located.

    Despite opposition from environmentalists, the company plans to drill five wells in the Norwegian sector of the Barents Sea, including Korpfjell, which will be the world's northernmost well and in a formerly disputed border area with Russia

    "We will start drilling the first well, Blaamann, during May ... followed by Kayak, Gemini (Nord), Korpfjell and Koigen (Central)," said a Statoil spokesman, adding each might take about a month to drill.


    All the wells are in areas free of sea ice thanks to the warm Gulf Stream, with sea and wind conditions similar to the North Sea, and some 400 km (250 miles) away from the "ice edge zone" - where at least 10 percent of the sea is covered by ice.

    "All wells will be drilled so far south of the existing ice that in the event of any spillage, no oil would never reach the marginal ice zone," Statoil said.

    Even in winter, there have only been 10 days of ice in the last 14 years in the areas where drilling is planned, it said.

    Greenpeace, which is taking the Norwegian government to court over Arctic drilling plans, said any permanent oil platforms in the region would be particularly risky.

    "Both the Korpfjell and Koigen Central licenses are within the reach of the historic marginal sea ice edge for the last 30 years," Truls Gulowsen, head of Greenpeace in Norway, said.

    "Statoil should not drill in the Barents Sea because of the pending legal case, because of environmental risk and because the world doesn't need more oil," he said.

    Statoil said the statistical probability of a blow-out, an uncontrolled oil spill from a well, was 0.014 percent - or one for every 7,100 exploration wells.

    The state-controlled company said drilling the Koigen Central well, some 109 kilometers from Bjoernoeya (Bear Island), one of the largest seabird colonies in the Arctic, posed the biggest environmental risk.

    Its own estimates showed an oil spill at Koigen Central could reach Bjoernoeya within 10 days. The company said it would have vessels on standby round the clock in case of any emergency.

    Statoil also said Norway and Russia had a joint contingency plan in case an oil spill from the Korpfjell well drifted to Russian waters some 37 kilometers away.

    Songa Enabler, a rig owned by Songa Offshore, was on its way to drill the first well, Blaamann, 26 kilometers from Eni's Goliat field, the world's northernmost field in production, shipping data showed.

    Gulowsen said Greenpeace planned to send its vessel to observe Statoil's Arctic drilling.

    In 2014, Greenpeace activists tried to stop Arctic exploration by boarding the Transocean Spitsbergen rig headed to drill for Statoil near Bjoernoeya.

    Greenpeace declined to comment on whether it planned any similar protests this year.


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    Lundin Norway Completes Drilling of Edvard Grieg Appraisal Well (Tuesday, 25 April 2017)

    25 Apr 2017, 6:00 pm

    Lundin Norway AS, operator of production licence 338, has completed the drilling of appraisal well 16/1-27 at Edvard Grieg field in the central part of the North Sea.

    The well was drilled about 3 km southwest of the Edvard Grieg platform.

    The field was proven in the autumn of 2007, and consists of Cretaceous and Jurassic/Triassic reservoir rocks. Before well 16/1-27 was drilled, the operator’s resource estimate for the field was 35 MMscm of recoverable oil equivalents.


    The objective of the well was to investigate the scope of the field, its reservoir properties and total oil column in the southwestern part of Edvard Grieg field. The objective also included optimizing the drainage strategy in order to ensure the best possible placement of development wells in this area.

    Well 16/1-27 encountered a total oil column of 15 m in Cretaceous and Triassic/Jurassic sandstone with very good reservoir quality. Overall, the sandstone interval was 94 m, an increase from 38 m expected before the well. The oil/water contact was encountered 1948 m below the sea surface, which is 9 m deeper than the contact in the other part of Edvard Grieg field.

    Extensive data acquisition and sampling have been carried out.

    Preliminary calculations shows that the results from the well can lead to an increase of between 1.6 to 4.8 MMscm of recoverable oil in this part of Edvard Grieg field. Further work is expected to reduce the uncertainty in this estimate. The results have provided valuable information with regard to final placement of production and water injection wells.

    16/1-27 is the 11th exploration well in Production Licence 338 and the eighth exploration well on Edvard Grieg. The licence was awarded in APA 2004.

    Appraisal well 16/1-27 was drilled to a vertical depth of 2229 m below the sea surface and was terminated in granitic basement. The well has been permanently plugged and abandoned.

    The well was drilled by the Island Innovator drilling facility.


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    Five Majors to Finance Nord Stream 2 Pipeline (Tuesday, 25 April 2017)

    25 Apr 2017, 2:00 pm

    Gazprom-led Nord Stream 2 has signed financial agreements with five major energy companies, including supermajor Shell, for the Nord Stream 2 pipeline project.

    In addition to Shell, financial deals were signed with France’s Engie, Austria’s OMV, and Germany’s Wintershall, and Uniper.

    “These five European energy companies have committed to provide long-term financing for 50% of the total cost of the project, which is currently estimated to be US$10.3 billion (€9.5 billion),” Nord Stream 2 said. “Each European company will fund up to $1 million (€950 million).”


    “Gazprom is and will remain the sole shareholder of the project company, Nord Stream 2 AG,” the company confirmed.

    The 1220km Nord Stream 2 gas pipeline, with a total capacity of 55 Bcm a year, will provide a direct link between reliable Russian gas reserves and European gas consumers from the coast of Russia via the Baltic Sea to Greifswald, Germany. Construction work will begin in 2018 and will be completed by the end of 2019.

    “The financial commitment by the European companies underscores the Nord Stream 2 project’s strategic importance for the European gas market, contributing to competitiveness as well as medium and long-term energy security especially against the background of expected declining European production,” Nord Stream 2 said.

    Earlier this month, Nord Stream began the environmental impact assessment (EIA) procedure in Russia for the project by disclosing relevant project documents.

    The company also finalized a contract with Allseas for the offshore pipelay of the pipeline though the Baltic Sea, with work for both lines to start in 2018 and 2019. Allseas will use three pipelay vessels for the project; the mega vessel Pioneering Spirit, Solitaire and Audacia.


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    Should Oil and Gas Companies Have to Leave the North Sea as They Found It? (Tuesday, 25 April 2017)

    25 Apr 2017, 12:00 pm

    The principle is simple – if oil and gas companies are going to put lots of steel and concrete in the ocean to extract fossil fuels from the seabed, they should return it to its initial state once they are done.

    So it’s understandable and entirely predictable that Scotland’s environmental NGOs including WWF and Greenpeace disagreed with Shell’s current plans to decommission its Brent oilfield. Those plans include leaving large sections of the concrete bases of its platforms in place, instead of removing all the drilling equipment from the sea bed.

    The comparative societal, environment and economic assessments undertaken by oil and gas companies to justify their decommissioning address options from full removal to leave in place. The requirements of the associated marine legislations are also a vital element of the analysis; particularly the OSPAR Directives.


    What these assessments miss is the key role of the taxpayer – the taxpayer will fund at least half of the costs.

    As taxpayers, we should be asking the government to show us that the agreed decommissioning plan is the best solution for taxpayers from a societal, environment and economic position. That has to take into account what else could be done with the taxpayers’ money – for example compare it with the benefits that the taxpayers’ money would give if directed into green energy.

    So I am asking the government to fund a study that would compare two options based on set sustainability criteria.

    The first option would be the current decommissioning plans.

    The alternative option is to plug and abandon the wells as currently planned but leave all of the equipment in place. Then, the money saved through not having to remove the hundreds of thousands of tonnes of steel and concrete could be redirected into green energy projects.

    The sustainability assessment would define and compare the three recognised pillars: people, profit and planet.

    For the current plans, the information could be held by the government as submitted by the companies. This would cover the cost of decommissioning to the operator and taxpayer, the jobs and other socio-economic impacts (fishing, marine transport) together with the environmental footprint (habitat, biodiversity, impact of decommissioning activities etc.).

    For the alternative, the same metrics would be evaluated.

    I am convinced a new picture, a special set of circumstances, would evolve showing clear differences in favour of green energy.

    The green energy investment could generate substantially more jobs than decommissioning. The jobs would be sustainable – design jobs, construction jobs and ongoing employment in operations and maintenance for the 25-year life of the renewable station.

    Instead of solely absorbing tax break funding, the renewable stations would be generating profit and paying back to the treasury the associated taxes during their operating life.

    The power generated by the stations would be of much more value to society than the disputed benefits from a clean seabed, and of course there would also be a huge environmental positive from carbon and other emissions reduction.

    Importantly the green energy route would offer WWF, Greenpeace and others a much better option for the environment. At the moment, all the NGOs are seeing are oil and gas companies relinquishing their obligations and saving money.

    When I took part in a recent BBC radio debate with Lang Banks of the WWF, I offered the green energy route and Lang’s comment is still ringing in my: “yes Tom has a point”.


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    Forth Underground Gas Explorer Surrenders Licences (Tuesday, 25 April 2017)

    25 Apr 2017, 10:00 am

    The move by Cluff Natural Resources will be seen as a victory for green campaigners who protested against the firm’s plan to source gas deposits by tapping and igniting coal seams far below the riverbed.

    The company – led by North Sea oil and gas veteran Algy Cluff – revealed today it had handed back its nine underground coal gasification licences to the Coal Authority.

    The company mothballed its UCG project on the Forth after the Scottish Government announced a moratorium on fracking and other unconventional energy projects.


    Cluff fully wrote down the value of its UCG projects in its 2015 accounts but maintained its licence options. Those have now been relinquished.

    Chief operating officer Andrew Nunn said: “In the absence of a supportive policy on UCG emerging from Westminster and the indefinite extension of the UCG Moratorium in Scotland, the company has today notified The Coal Authority, as the responsible authority for issuing UCG licences, that it is relinquishing its nine UCG licences.

    “Given the uncertainty around the future of these assets which has existed for some time, these licences had already been fully written down in the company’s 2015 accounts.”

    Instead of focusing on UCG, Cluff has spent the past months concentrating on developing its offshore gas assets in the Southern North Sea.

    The firm’s two core licences include eight distinct prospects in five proven reservoirs.

    Cluff’s preliminary results for the year ending December 31, show a pre-tax loss of £1.73 million, a slight improvement on the £1.88m loss of 2015.

    Chairman and CEO Algy Cluff said the company’s destiny was directly linked to the North Sea.

    He said there had been a significant improvement in sentiment both within and towards the oil and gas industry and the basin was on cusp of a new phase of its development through the bringing forward of small pool developments.

    “Notwithstanding the apparent view of many of the major oil companies that the North Sea no longer offers the prospect of major discoveries (about which they may well be in error), it is widely agreed that there remain many licences which contain high quality exploration targets,” Mr Cluff said.

    “Her Majesty’s Government has the power to render those targets even more attractive by fiscal incentive.

    “Secondly, the North Sea is well run. Thirdly, it is secure. And, fourthly, it contains many existing discoveries – which the UK’s Oil & Gas Authority (OGA) estimates to be in excess of three hundred – which remain undeveloped.

    “The OGA is due to announce the 30th round of licence awards and we are advised that this round will include such “small pools” of oil and gas which will reduce much of the exploration risks whilst offering, in some cases, immediate resources.

    “We have been giving much thought to this eventuality and are determining how to respond with the intention of applying when the round is announced.

    “It is my view that this could herald a North Sea Phase Two with the OGA estimating that as much as 3.4 billion barrels of oil equivalent is distributed amongst these pools.”

    Shares in Cluff Natural Resources pushed more than 12% higher in early trading following the market update.


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    Chrysaor: Sizing Up The North Sea’s Biggest New Player (Tuesday, 25 April 2017)

    25 Apr 2017, 8:00 am

    Earlier this year, UK-based oil firm Chrysaor became an overnight sensation in the North Sea oil and gas sector. At the end of January, the company agreed on a $3bn acquisition of North Sea assets from Royal Dutch Shell.

    When the deal completes, which is expected in the second half of this year, Chrysaor – previously best known for its stake in the Solan Basin west of Shetland – will find itself propelled to the position of the largest independent oil and gas operator in the North Sea. The acquired assets consist of Shell’s interest in fields Beryl, Bressay, Buzzard, Elgin-Franklin, Erskine, Everest, the Greater Armada cluster, J Block and Lomond, as well as a 10% stake in the Schiehallion field west of Shetland. Chrysaor will become the operator at the Armada, Everest and Lomond fields, while the other interests have been acquired as non-operated investments.

    All told, the assets produced 115,000 barrels of oil equivalent per day in 2016 with the redeveloped Schiehallion expected to add more production when it comes back on-stream later in 2017. In one swipe, Chrysaor has taken ownership of more than 50% of Shell’s North Sea output.


    “These are producing assets, so as you’ll see, Chrysaor gets catapulted, upon completion, to become one of the largest UK oil and gas producers,” says Chrysaor communications director Andrew Vickers. “So this is very much about investing for the long term, and potentially this transaction, as a good producer of cash flow, could be a springboard for more activity. That’s certainly what we would like to do.”

    The deal – the biggest North Sea acquisition since 2010 – can be seen as emblematic of a gradual shift in the demographic of North Sea operators, with the supermajors realigning towards priorities elsewhere and smaller, private equity-backed firms stepping in to play a larger role in UK waters. So why did Shell make the deal, and how can smaller producers contribute to a productive future for the UK North Sea at this mature stage of its lifecycle?

    Shell and the North Sea: retreat or readjustment?

    Shell’s decision to divest a large portion of its presence in the North Sea is broadly in line with the company’s strategy since its $52bn takeover of BG Group early last year. Shell’s leadership has already discussed its intention to sell off $30bn in assets, both onshore and offshore, from its global portfolio by 2019 to reduce its debt burden and balance its books.

    Outside of the North Sea deal with Chrysaor, other major upstream divestments announced by Shell this year alone include the sale of the company’s 22.2% stake in Thailand’s Bongkot gas field to Kuwait Foreign Petroleum Exploration Company for $900m in January, and the $587m deal for its onshore oil assets in Gabon with Carlyle Group subsidiary Assala Energy in March. Shell is currently around two-thirds of the way to meeting its divestment target, and CEO Ben van Beurden has previously noted that many sales would come towards the end of its divestment period to take advantage of a prospective oil market recovery.

    Still, the sale of such a large portion of Shell’s assets in the North Sea has led to assumptions by market analysts that it’s the extreme maturity of the region, with high production costs and the looming spectre of decommissioning commitments, that has made the North Sea a key divestment prospect for Shell and others.

    For Vickers, who joined Chrysaor in December last year after nearly three decades at Shell, the sale isn’t an indication of any doom-and-gloom prognostication over the North Sea’s future; rather, it’s a signal of the shifting priorities of an oil company with a global footprint and a need to pare back its operations to areas in which it feels it can compete effectively, such as liquefied natural gas and deepwater exploration.

    “If you look at where Shell is heading, whether it’s some of the deepwater stuff they’re doing, or if you look at their strategic thrust, like most companies they seem to be focusing on those things they think they can do best,” Vickers says, while also noting that Shell has hardly cut all ties with the North Sea.

    “I did note, by the way, that both Shell and Chrysaor were successful in the [UK’s 29th] bid round last week,” he adds. “There was a lot of west of Shetland stuff in there – in terms of Chrysaor’s interest, it’s not big bucks in terms of some other stuff, but in terms of Shell in the North Sea, they actually won a lot of acreage. I can’t speak for Shell even though I worked for them for a long time, but actually all their actions are not of them retreating, but readjusting.”

    The right assets in the right hands

    Chrysaor clearly considers that there is decades worth of productive life left in UK waters; the company and its investors – including EIG investment vehicle Harbour Energy – have made a multi-billion dollar bet on it. Does the company think the gloomy predictions over the North Sea’s future prospects are overblown?

    “We think they are,” says Vickers. “If you look at the Oil & Gas UK data on the yet-to-be-produced resources, we could be just halfway through [the region’s lifecycle] or thereabouts. I think it’s also worth saying that there’s been a massive change in the business model in the North Sea over the past two or three years. Operating costs have come down almost by a half. There is a false notion that this is high-cost oil and gas, whereas if you look at the data, the reality shows that this isn’t the case. As we pointed out in our press release, the operating costs on this portfolio fall well beneath $15 a barrel.”

    Chrysaor chairman Linda Z. Cook – another migrant from Shell – noted in a January statement that this stage of the North Sea’s lifecycle, combined with successful recent efforts to reduce operating costs, “signals a moment for a generational change in the basin”. So what difference can a smaller company make when it comes to innovation and investment in North Sea production?

    For a start, argues Vickers, Chrysaor’s relatively small size gives it a focus and decision-making agility that is hard to achieve for a corporation as large as Shell. “When you are an organisation of the size and relative simplicity of Chrysaor compared to a Shell, the decision-making is pretty timely, to say the least,” he says. “One of the reasons Chrysaor is so excited about these assets is we do have a very strong North Sea focus. It’s the only thing that Chrysaor does, whereas for Shell and other super majors of the world, the North Sea is one of many. There isn’t necessarily the same degree of attention and interest in the assets as we have.”

    Chrysaor is also committed to continued investment in its new assets, even when a supermajor’s instinct might be to pull the plug. The Armada field is a good example – while Shell had been considering ceasing production at the project, its successor is keen to channel more money to the field to extend its operating life. These sorts of plans dovetail nicely with the UK government’s stated aim of maximising economic recovery on the UKCS.

    “It’s what I would call getting the right assets in the right hands,” Vickers says.

    Managing the transition

    Now, with the deal made and set to complete later this year, Chrysaor’s focus is on stewarding a transition on a scale exponentially larger than it would have experienced before.

    “That means the safe transfer of the assets from Shell to Chrysaor,” Vickers says. “That in its own right is such a large and important task that, while we have some ideas for transformation, the priority at the moment is the safe transition. If you try to do a transition of this scale – and it really is quite a substantial scale – and introduce transformation at the same time, that is not a healthy or good recipe.”

    As well as taking over as operator at three fields, with all the attendant regulatory requirements, around 400 Shell employees are due to transfer over to Chrysaor upon completion.

    Chrysaor has committed to maintaining the same terms and conditions of employees for its new influx of staff, and while details such as whether various onshore employees working on multiple projects would be covered by the acquisition, a town hall meeting with workers on the day of the transaction has convinced Vickers that the staff due to transfer are feeling positive about their new employer.

    “We have growth aspirations for assets that perhaps were not destined for that, so that probably underlines that sense of warmth towards what we’re doing,” Vickers says.

    So Chrysaor has a busy couple of years ahead as it manages the transition of the massive tranche of Shell assets and gets used to its sudden position towards the top of the North Sea pecking order. The company now has a springboard from which to grow its business in the North Sea, and appears intent on doing so. Whether it has the resources and know-how to make the most of its new assets, only time will tell.


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