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Share Name Share Symbol Market Type Share ISIN Share Description
Royal Dutch Shell Plc LSE:RDSB London Ordinary Share GB00B03MM408 'B' ORD EUR0.07
  Price Change % Change Share Price Bid Price Offer Price High Price Low Price Open Price Shares Traded Last Trade
  -17.20 -1.25% 1,359.60 1,354.60 1,355.40 1,369.80 1,340.60 1,366.00 6,820,531 16:35:09
Industry Sector Turnover (m) Profit (m) EPS - Basic PE Ratio Market Cap (m)
Oil & Gas Producers 260,049.0 19,217.3 148.5 9.4 50,389

Royal Dutch Shell Share Discussion Threads

Showing 25101 to 25122 of 25125 messages
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DateSubjectAuthorDiscuss
22/1/2021
09:18
Oil Majors Are Eyeing A Suriname Offshore Boom By Felicity Bradstock - Jan 21, 2021, 12:00 PM CST Join Our Community Majors are eying Suriname as the next big oil player. With recent success in neighbouring Guyana, Suriname offers hope for low-cost oil exploration and production going into 2021. Exxon Mobil, Royal Dutch Shell, Total, Apache are all showing interest in the South American state, hoping Suriname will provide oil for as little as $30 to $40 a barrel thanks to lower production costs. This is well below the average US production cost of almost $50 per barrel. After years of political unrest, Suriname is eager to make a name for itself in the oil world and encourage economic stability and growth. The hard-hit economy has been further hampered by the Covid-19 pandemic, with the new government looking at the country’s oil potential to drag them out of economic disaster. Attracting oil investment from foreign companies only became possible after the successful discovery of oil in deep wells in 2015, following around 60 years of failure in shallow waters. At present, state-owned Suriname’s national oil company Staatsolie controls most of the industry. To encourage investment, Suriname is offering companies 30-year production-sharing agreements, around 10 years longer than those of Latin America’s other oil-rich countries. Following a difficult 2020, emerging oil states such as Suriname and Guyana are expected to dominate licensing rounds this year with such attractive terms. Oil experts believe there to be at least three to four billion barrels of reserves in Suriname’s waters, providing foreign companies with a bet worth taking for the future of the region’s oil. Related: Canada Is Cleaning Up Its Oil Sands Earlier this month, Total and Apache Corporation made an important oil and gas discovery off the coast of Suriname at the Keskesi East-1 well, in Block 58. This brings the total number of oil discoveries in the country to four in 2020, or 1.4 billion barrels of oil equivalent. Total’s Senior Vice President Exploration Kevin McLachlan stated “We are… excited, as new operator of the block, to start the appraisal operations designed to characterize the 2020 discoveries, while in parallel start a second exploration campaign on this prolific block in 2021.”. In addition, ExxonMobil announced oil and gas finds in Suriname in December. Mike Cousins, Exxon’s Senior Vice President of exploration and new ventures, explained “Our first discovery in Suriname extends ExxonMobil’s leading position in South America, building on our successful investments in Guyana. We will continue to leverage our deepwater expertise and advanced technology to explore frontier environments with the highest value resource potential.” One recent partnership that’s caught attention in the region is the contract between Maersk Drilling and Total E&P, valued at $100 million. The partnership’s deepwater oil rigs Maersk Valiant and Maersk Develop in Block 58 are expected to start operations this month. Suriname hopes to follow in the footsteps of neighbouring Guyana, which has attracted significant foreign investment in its oil industry in recent years. Exxon in particular has been investing heavily in the region, commencing production in Guyana’s Liza oilfield in 2019; an area capable of pumping 120,000 bpd. Exxon is now looking to develop the Stabroek Block, having signed a sharing agreement with the government, expected to produce 750,000 bpd by 2026. Oil production in Guyana could extend beyond the next 30 years, presenting an attractive opportunity for longer-term exploration and low-cost production. In 2020, Guyana had an anticipated economic growth of around 50 percent, mainly owing to its burgeoning oil industry. According to the IMF, the country can expect an average annual real GDP growth of around 13 percent over the next four years. As companies are less willing to become entangled with neighbouring Venezuela, due to its complex political situation and current US sanctions, with the country’s oil exports falling to its lowest levels in 77 years in 2020, Guyana and Suriname offer a bright alternative. While it is early days for drilling in Suriname, success in Guyana and a clear interest from international oil majors could put the small South American state on the map. By Felicity Bradstock for Oilprice.com
florenceorbis
21/1/2021
19:00
Thanks Grumpy
mavis5
21/1/2021
18:53
And FWIW All major european oilies sold off today
the grumpy old men
21/1/2021
18:39
Quite a drop in the share price today. Any views as to the cause?
mavis5
21/1/2021
18:21
SHELL A : Gets a Buy rating from Jefferies 01/21/2021 | 08:47am GMT Jefferies is positive on the stock with a Buy rating. The target price is unchanged at GBX 1780.
the grumpy old men
21/1/2021
04:32
Another thing Art generally maintains if I understand and remember correctly from older interviews, is that the EIA weekly report which is kind of an early guesstimate available here hTTps://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&;s=WCRFPUS2&f=W tends to overstate actual production as subsequently recorded numbers are much lower in the more accurate EIA Monthly Data released a few months later here hTTps://www.eia.gov/petroleum/production/ In above interview he says everyone thinks US is now 11m to 11.3m but the latest report (monthly, for October) just out says it's barely over 10m. I crunched the numbers from those two reports for Months 1 to 10 2020, the latest available, which showed the average overstatement for those 10 months was 282K bopd/month. Suggesting the EIA weekly report is 97.4% accurate. The weekly forecast for Oct 2020 published 3 months ago suggested 10.6m vs 10.4m Actual Oct 2020 monthly number just released. Feel free to check the EIA data. So when Art says US production is 10M now (i.e. 11m current weekly report - 1m) maybe it is more like (11m - 0.3m) = 10,700,000 bopd? We'll find out in April.
xxnjr
21/1/2021
03:25
ac1 go to 43m 46s of hTTps://www.youtube.com/watch?v=ijyYiqHRPEY&t=1771s Listened to above about 10 days ago. IIRC according to above interview, apparently Art previously thought US production would fall off a cliff starting Q4/2020 from 11m declining maybe as low as 7.5m bopd. He now admits he got that modelling wrong (shut in wells/rig count etc). But apparently it will start to happen this quarter. OTOH OPEC and EIA have just released forecasts that suggests 2021 US production will stay flat around 11m, or even increase to 11m+. OK 11m is 2m less than 13m at the peak, before covid forced shut-ins/deferred drilling etc but US 11m today is still a huge number and a number (if I remember correctly) that was unlikely to ever be reached according to Arts various earlier predictions of shale doom when say US production was 7m/8m/9m/ and rising? Maybe wrong as I have never really been an avid follower but I kind of thought Art's central messaging over the years has been (a) "Shale is a Ponzi Scheme" and (b) "shale output will collapse". One can debate (a) but (b) just hasn't happened. You mentioned subscriptions, and some!..... $525 for the gas sub. $525 for the oil sub. $150 for the rig count sub. Newsletter $200. US Annual costs. e.g. hTTps://www.artberman.com/plans/gas-comparative-inventory-packages/
xxnjr
20/1/2021
22:19
I've never understood Art's slides on Shale..... they do tend to bamboozle. Not convinced his shale output forecasts are terribly useful either (just a feeling) as my perception is most times he gets it wrong. But I guess, like Trump, he has his followers. Perhaps because he tells them what they want to hear?
xxnjr
20/1/2021
15:43
Interesting comments POO side. "Will An Oil Price Spike Be The Next Blow To The Economy? Art Berman predicts a 30% price increase in 2021" hTTps://www.peakprosperity.com/will-an-oil-price-spike-be-the-next-blow-to-the-economy/ hTTps://www.youtube.com/watch?v=7PjXDrP5OG0&feature=emb_title
geckotheglorious
20/1/2021
13:33
agree. silly article.
zangdook
20/1/2021
11:54
Lots in the 921 article, from I don't know where, that I find odd, for example. "For me to consider it as being investable again, it would need to demonstrate that management is capable, it has a plan to sustain or increase earnings in so far as it can do so with the levers it can pull (of which oil price isn’t one) and that the dividend has a logic which doesn’t just run it up for years or decades and then heavily cut it again in future. For now, I consider it to fail on all three metrics." Give them a bit of credit, author: they appear to base their divi increases (4% after a 70% cut ain't exactly big) on the near to medium term outlook. In no way does that mean that they'll "heavily cut" in the future; there are other ways of dealing with the divi should the future turn out to be more of a struggle - merely not increasing it? Seems like the author's got a bee in his/her bonnet.
poikka
20/1/2021
10:57
George Herraghty20 Jan 2021 9:08AMBeware Bursting Bubbles?Will the green economy trigger the next crash?Wind investments just don't perform like promised in the fancy brochureshttps://capx.co/will-the-green-economy-trigger-the-next-crash/
xxxxxy
19/1/2021
16:16
Shell: What It Will Take To Be Investible Again Jan. 19, 2021 5:15 AM ET| Summary Shell's dividend cut and unpredictability last year cost it a lot of shareholder confidence. I outline three metrics I think show whether it's investable again. On all three metrics, I continue to see it as uninvestable with confidence. U.K.-based oil major Shell (RDS.A, OTCPK:RYDAF) didn’t have a great time of it last year when it came to shareholder relations. With its mammoth dividend cut and poor signaling thereof before it was made, a lot of shareholders ditched the holding. I sold my entire stake and reinvested the proceeds in more Exxon Mobil (XOM). Below, I outline what I think are the key challenges to Shell being investable at this point. 1. Shareholders Need Faith in Management The single biggest challenge facing Shell’s prospects right now, in my view, is the low quality of its management from an investor’s perspective. The way that the dividend cut was handled was terrible. Shell is a key holding for many U.K. and Dutch holders, including pension funds and the like. So, a 70% cut just a couple of months after guiding investors not to expect a cut is simply not professional at all, in my view. It doesn’t behoove management of as large and economically important a listed company as Shell to behave in this way. Management lost credibility with many shareholders, and frankly, it was on such a scale that I won’t have faith in current management again, period. I thought the chief executive ought to have done the decent thing and resigned. But I also don’t see evidence that current management deserves to regain investor confidence even if one isn’t as critical of how they handled the dividend cut. For example, in comments accompanying the third quarter earnings presentation, the finance chief said: “we re-based our dividend to protect our balance sheet in response to the profound impacts of the pandemic”. That feels disingenuous to me. A 70% cut on an ongoing basis is not justifiable purely in terms of pandemic impact. The company seems to continue to message its shareholders without respecting their intelligence. For me, this is the biggest issue at the moment when it comes to the investment case for Shell. Whatever its asset base or strategy, if it doesn’t have appropriately skilled, reliable management, it’s a speculative punt, not an investment. 2. Visibility on Future Earnings Streams One of the big debates in the energy sector is future demand for oil and gas versus other forms of energy. I’ve set out elsewhere why I don’t think oil demand is going to fall anytime soon, but there are well-considered and very different perspectives across the spectrum of the debate. For an example, I recommend Tudor Invest Holdings’ piece Royal Dutch Shell: More Than Just Oil And Gas. One approach, which I would say Exxon is taking, is doubling down on the core business of oil and gas. That is a straightforward play on future oil and gas demand and pricing. An alternative approach is to move to an asset portfolio which over time produces more energy from sources other than oil and gas. Some are more environmentally damaging, in my view (wind turbines, for example), so I don’t use the moniker “green”. The point is, they’re not from oil and gas. A number of – primarily European – energy majors have committed to this approach. While it’s the case for Shell, it is also happening at BP (NYSE:BP), Total (NYSE:TOT) and Equinor (NYSE:EQNR), for example. So, Shell management is basically moving in lockstep with the European energy sector in its approach here, rather than acting independently. However, in terms of being investable, the question is what this means for future earnings. Exxon’s approach is simple to understand: one needs to look at future demand, pricing and the company’s production volume and costs. While those are all moving parts, it’s fairly easy to construct different models depending on one’s broad thesis about future oil and gas demand. By contrast, earnings from the sorts of energy sources Shell is getting into now are much harder to forecast. Markets remain heavily subsidized and immature, so the long-term economics are unclear. I set out in my piece Shell And The Myth Of Oil Major Green Energy my concerns that the company’s strategy was slow to execute, with unproven results. That remains the case. In its third quarter earnings, upstream and midstream results both came with financial figures attached. The so-called “growth” business did not. Shell now sees its upstream energy business as a cash cow to fund its move into other areas, and pay shareholder distributions. This is clear from a slide it shared with its Q3 earnings. Source: Q3 earnings presentation That also matches the approach the company management is taking to its oil production. The CEO is reported as saying that Shell’s oil production probably peaked in 2019. So, the company expects to reduce its output of its cash cow product, meanwhile expanding in other areas whose profitability is unproven and unknown. The key point here is not whether oil demand peaks, factor outside the company’s control. The issue is that the company is proactively planning to move to a product mix, which seems less profitable, and which is likely, therefore, to lead to structurally lower earnings in the long term, notwithstanding fluctuations in the oil price. 3. A Clear Dividend Logic Shell set out its new, clear dividend policy with its third quarter result: a dividend increase of c. 4% annually, subject to board approval. Additionally, it set out (as a lower priority) total shareholder distributions of 20-30% of operating cash flow on reaching net debt of $65 billion. Net debt at the end of September stood at around $73.5 bn. Once the debt comes down, these additional distributions could include both share buybacks and dividends. That means that, at its current price, Shell has a prospective forward yield around 3.5%, which is decent for an FTSE-100 constituent. The cut has also increased dividend cover, something the company highlighted alongside its inaugural 4% increase last year, although it's hard to say for now what the long-term cover is likely to be. So, there is a dividend policy. But I do not see a solid logic in it. First, why a meaty (4%) raise just months after a 70% cut? I just stole your wallet but, hey, here’s your cab ride home! Longer term, why 4%? It sounds attractive to potential investors. But with oil price movements and the unproven economics of Shell’s future focus, setting out a plan for a consistent annual rise lacks logic. While the clear dividend policy is welcome, I would like for a clear dividend logic also. Currently, I think it’s missing. That matters because if the dividend keeps growing by 4%, sooner or later (perhaps later), the company will come up against the same challenge it faced last year: how to sustain a payout level which has been rising, if oil prices crash? Conclusion: I Regard Shell As Uninvestable I sold my Shell position at a loss and reinvested it in Exxon, because I maintain faith in oil and gas as a long-term investment theme but don’t maintain faith in Shell. For me to consider it as being investable again, it would need to demonstrate that management is capable, it has a plan to sustain or increase earnings in so far as it can do so with the levers it can pull (of which oil price isn’t one) and that the dividend has a logic which doesn’t just run it up for years or decades and then heavily cut it again in future. For now, I consider it to fail on all three metrics.
maywillow
19/1/2021
15:04
More on the huge costs of decommissioning wind turbines. Really worth a read! "In Minnesota, Xcel Energy estimates conservatively that it will cost $532,000 to decommission each of its wind turbines—a total cost of $71 million to decommission the 134 turbines in operation at its Noble facility. Decommissioning the Palmer’s Creek Wind facility in Chippewa County, Minnesota, is estimated to cost $7,385,822 for decommissioning the 18 wind turbines operating at that site, for a cost of $410,000 per turbine. Restoration activities include the removal of all physical material and equipment related to the project to a depth of 48 inches. Most of the concrete foundations used to anchor the wind turbines, however, are as deep as 15 feet. The concrete bases are hard to fully remove, and the rotor blades contain glass and carbon fibers that give off dust and toxic gases. While most (90 percent) of a turbine can be recycled or be sold to a wind farm in Asia or Africa, researchers estimate the United States will have more than 720,000 tons of blade material to dispose of over the next 20 years, a figure that does not include newer, taller higher-capacity wind turbines. Decommissioning Blades Wind turbine blades are made of a tough but pliable mix of resin and fiberglass—similar to what spaceship parts are made from. Decommissioned blades are difficult and expensive to transport. They can be anywhere from 100 to 300 feet long and must be cut up on-site before getting trucked away on specialized equipment to a landfill that may not have the capacity for the blades. Landfills that do have the capacity may not have equipment large enough to crush them. One such landfill cuts the blades into three pieces and stuffs the two smaller sections into the third, which is cheaper than renting stronger crushing machines. One company has found a way to recycle blades by grinding them up to make small pellets that can be used for decking materials, pallets and piping. The company opened its first processing facility in central Texas this year and is leasing a second space near Des Moines, Iowa. Given that the United States now has almost 100 gigawatts of wind capacity and that the life span of wind power is generally 20 years—much less than the traditional capacity it is replacing—finding technologies for recycling of the parts is becoming extremely important. (This shorter lifespan of this capital investment also means the replacement power needs to be recapitalized 2 to 3 times compared to power from conventional generation technologies, a little-discussed economic burden facing consumers in the future.) Europe’s Decommissioning of Wind Turbines In 2018, 421 megawatts of wind power were decommissioned in Europe—down from 683 megawatts in 2017. Of the turbines that were decommissioned in 2018, most were in Germany (249 megawatts), followed by the Netherlands (72 megawatts), Austria (29 megawatts), Greece (15.4 megawatts), Portugal (13.7 megawatts), Sweden (13.3 megawatts), Denmark (12.7 megawatts), France (12.6 megawatts), and Finland (3 megawatts). Most of the decommissioning (407 megawatts) was in onshore wind. Out of the decommissioned 421 megawatts, a number of projects were repowered (repopulated with new turbines). The projects that were repowered in 2018 and a part of decommissioned capacity in 2017 resulted in 461 megawatts of repowered capacity. The majority of the repowered projects were in Germany, but repowering also occurred in Austria, France, Portugal, and Spain. In Europe, land is at a premium, and waste management rules result in some companies selling older parts to customers in Asia, Latin America, and Africa. Germany has over 28,000 wind turbines and by 2023 more than a third must be disposed of through decommissioning or sale to other countries. New projects commit to set aside 2 to 3 percent of the capital cost each year for decommissioning, but it is unclear whether this amount is sufficient to cover the costs when the wind turbines are dismantled twenty or so years later. Costs of decommissioning depends on location—offshore or onshore—and the age of the technology as newer turbines are larger than the older models. An offshore wind farm in the United Kingdom was decommissioned earlier this year. The Blyth offshore wind farm is a two-wind-turbine farm. One of the two wind turbines was recycled and reused for spare parts within the company’s onshore fleet, and the other was used for training purposes. The plant had a shorter life span than most commercial wind projects, operating for just 19 years. The company did not release the cost for dismantling Blyth, but indicated that it was similar to building the project. Repowering of offshore wind farms is deemed unlikely because of the rapid evolution of the offshore turbine technology. Conclusion As with other aspects of renewable energy, the decommissioning of wind turbines was not planned out well in terms of their disposal when their useful life is over. Because wind turbines have a shorter life span than most other technologies, the dismantling of these units is already in progress in Europe and will soon be needed in the United States. Due to the size of the units, landfills do not have the capacity or equipment to break down the huge rotor blades. Repowering is being done in Europe and some turbines are resold to developing nations. But, needless to say, it is expensive to decommission wind turbines and who pays when the funds are not sufficient to cover the expense is an issue."
poikka
19/1/2021
14:50
Check out the section on CCUS. hxxps://www.nationalgrid.com/our-businesses/national-grid-ventures/what-we-do/future-developments Excuse the Https bit.
poikka
19/1/2021
14:46
Talking about SSE and CCS.. "SSE Thermal is actively developing Keadby 3, which could become the UK’s first power station equipped with carbon capture and storage (CCS) technology by the mid-2020s. In line with our vision for a net-zero future, SSE Thermal has committed to only build power stations with a clear route to decarbonisation. With an electrical output of up to 910MW, Keadby 3 Power Station will use natural gas as its fuel and will be fitted with a carbon capture plant to remove the CO2 from its emissions. The UK Government recently announced its ambition for the UK to become a world-leader in CCS technology, with a target to remove 10MT of CO2 by 2030. Keadby 3 is expected to offset at least 1.5MT of CO2 – 15% of the Government’s target. Keadby 3 will connect to the shared infrastructure being developed through the Zero Carbon Humber partnership to transport the captured CO2 and store it safely offshore."
poikka
19/1/2021
14:36
"Hydrogen. Clean fuel. But dirty to produce? Defeats the object?" That's not the objective, nor necessarily the case. "CCS is well suited to decarbonise the production of hydrogen from natural gas. Seventeen commercial CCS plants are operating today, two of which are power plant retrofits (Boundary Dam in Canada, Petra Nova in USA) and one CCS plant is already used for hydrogen production (Quest in Canada) (Global CCS Institute). Several more are in construction or at demonstration phases. CCS is recognised as being part of a least cost climate change mitigation solution and remains the only means to fully decarbonise the industrial sector. Considering the need for CCS with hydrogen could further accelerate the deployment of large-scale CCS. Progress is already under way: Statoil, Vatenfall and Gasunie signed a Memorandum of Understanding to evaluate the conversion of the Magnum gas plant in the Netherlands to a hydrogen plant with CCS. This has the potential to reduce CO2 emissions by 4 million tonnes per year equivalent to the emissions from 2 million internal combustion engine cars." For investors, where does that leave NG. on one side, and SSE on the other? In time, of course.
poikka
19/1/2021
13:35
Hydrogen production. htTps://en.m.wikipedia.org/wiki/Hydrogen_economyAnswer, I think is nuclear and power units that a different eg UFO one's. Joking there. A bit.
xxxxxy
19/1/2021
13:30
Hydrogen. Clean fuel.But dirty to produce?Defeats the object?
xxxxxy
19/1/2021
12:36
Interesting comments regarding wind turbine energy. Got to say that I feel that wind turbines will become a thing of the past within a decade or two, but then I'm not an expert. For me, the future is more along the lines of hydrogen production and usage, mostly produced during the CCUS process. But it's going to be a mix of processes that get us out of bunging a load of CO2 into the air. One day, investors will be piling into wind turbine decommissioning businesses. Will I still be around..? Do I wanna buy an EC, or wait for hydrogen? Keep an eye on what big oil is investing in.
poikka
19/1/2021
12:02
9:10amIEA cuts oil demand forecast despite improving outlookThe International Energy Agency has cut its forecast for global oil demand by 600,000 barrels a day, a slightly decline from its estimates at the end of last year.In its January report, the Paris-based body said renewed lockdowns in many parts of the world would put pressure on demand, but said supply cuts by Saudi Arabia and its allies would present an opportunity for global stockpiles to be whittled down.It said:The global vaccine roll-out is putting fundamentals on a stronger trajectory for the year, with both supply and demand shifting back into growth mode following 2020's unprecedented collapse.But it will take more time for oil demand to recover fully as renewed lockdowns in a number of countries weigh on fuel sales.World oil demand is now expected to rise by 5.5m barrels/day this year, compared with the huge 8.8m barrels/day contraction in 2020. ... Daily Telegraph
xxxxxy
19/1/2021
10:50
Don't take this too seriously folks but if it wasn't for the Russian gas that Gasprom kindly pumps to Germany on a daily basis then folks in Germany would literally be forced to run into their forests to chop down trees and light fires to escape current freezing sub-zero polar vortex weather conditions ;-)
xxnjr
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