Tuesday, 24 September 2019

#32 pictures with short text

Post 31 shows tweetable pictures with text. It worked fine until the format changed and only horizontal pictures showed well. I changed to landscape and had to shorten the texts. Here are the results


Friday, 23 February 2018

Post 31 Blog summary, tweetable pictures

Since it is not easy to find specific points on this blog I decided last year to show pictures with text on my Facebook timeline. I also started tweeting and discovered that a tweetable text page with one or more pictures is very effective. That greatly increased the readership of the blog. I will use these tweetable pages to show the main points about climate change and required action.  There is little room for references on the pictures so I include them at the end of this post. I only recently saw the devastating effects of methane emissions from permafrost and why we have to reach 0 emissions before 2100. The beginning of this post is therefore more elaborate than the rest. I will try to post each picture close to where it is first referred to in the text points A-Z onwards, like 45 in A.  If the picture contains data which are covered by another point it will be referred to by number and letter in the first point where it is shown. Following the list of references there are more pictures covering some additional points and newly found information.

Under-estimate of global warming and rising sea levels
This is covered under Q of post 30. Picture 45 shows that previously the IPCC made 7 major points look much better than reported in Paris. Melting of icefields and methane emissions from permafrost were left out because the scientists could not agree on figures (1) Q in post 30 also describes the findings of Dr. Hanson’s team. Only just recently he showed how warm water currents undermine ice fields. Picture 45 shows that the sea absorbs 93% of all trapped energy, hence accelerates the melting.
The components of greenhouse gas (GHG)
Most of it is water vapour. Some people doubt the importance of Carbon dioxide (CO2) because up to 95% can be water vapor making the 5% of CO2 and other gases look insignificant. It is the CO2, methane and a few other gases that create the water vapour. CO2 is therefore the measurement of GHG. Methane is 85 times more potent than CO2 but it breaks down fast. Its 20year global warming potential (GWP) is 85 times that of CO2, dropping to 25- 35 in 100 years. It is measured as CO2 equivalent. (4)  Since the coming 20 years are critical, methane emissions should be restricted.
Avoidable methane emissions
Emissions from fracking should be avoided and all efforts should be made to trap cow emissions like Argentina started with fart packs. They extract about 300 liters of methane a day in backpacks carried by the cows. According to the EPA, cow farting (and burping, actually a lot of it is burping) accounts for 5.5 million metric tons of methane per year in the United States — that's 20 percent of total US methane emissions (6) Collecting the methane from all waste will be required. Livestock emissions make up anywhere between 14.5 and 18 percent of total global greenhouse gas emissions. (7). One tonne of nitrous oxide is equivalent to 298 tonnes of carbon dioxide. (8) Cow manure emissions also contain nitrous oxide. (9).
Methane emissions from melting permafrost
These can be diminished by sticking to our 0 emission, limiting global warming to 1.5 degrees
 The story behind Picture 42 is that scientists used aerial sampling of the atmosphere to locate methane sources from permafrost along a 10,000 square-kilometer swath of the Mackenzie River Delta in northwestern Canada. Deeply thawed pockets of permafrost, the research suggests, are releasing 17 percent of all the methane measured in the region, even though the emissions hotspots only make up 1 percent of the surface area. In those areas, the peak concentrations of methane emissions were found to be 13 times higher than levels usually caused by bacterial decomposition. This would confirm that the gas has been buried deep beneath Arctic permafrost for millennia.  Some of that gas appears to be finding new paths to the surface through permafrost that starts to resemble Swiss cheese (15)

Arctic and sub-Arctic marine sediments are thought to host vast reservoirs of methane stored in methane hydrate. (5) Near Norway over 250 plumes of gas have been discovered bubbling up from the sea floor to the west of the Svalbard archipelago. They are created by the West Spitsbergen current, which has warmed by 1 °C over the past 30 years. The entire hydrate deposit around Svalbard could be releasing 20 mega tonnes a year. It does not reach the surface yet but could, if larger bursts occur. (10). Another article explains how large reservoirs of methane formed underneath the Barents sea when it was still ice. Following melting, pressure from the gas lifted the seafloor to create the giant mounds.  During small leaks microbes in the water use up the methane before it reaches the atmosphere but larger burbs are possible (11) In 2007, air monitors detected a rise in methane concentrations in the atmosphere, apparently from far northern sources. Russian researchers in Siberia expressed alarm, warning of a potential surge in the powerful greenhouse gas, additional warming of several degrees, and unpredictable consequences for Earth's climate (13) In Siberia Zimov is out to prove that recreating the ancient Arctic ecosystem could be a viable way to halt the threat of permafrost. In a movie he shows that by poking holes in the snow you can ignite the methane, reducing the global warming potential (GWP) from 85 to 1. The movie also shows inspection tunnels in the Siberian permafrost and one of the biggest methane craters (18) Such craters are the result of large mounds described above, exploding, which can happen again. Researchers have discovered hundreds of huge craters, with many over 3,000 feet wide, on the seafloor of the Arctic Ocean. The craters in the Barents Sea, north of Norway and Russia, formed through huge mounds full of methane exploding suddenly and catastrophically around 12,000 years ago, and are still leaking methane. (23)
Global warming caused by fluorocarbons
The CO2 equivalent includes fluorocarbons, which are 1000 times more potent than CO2. They are also responsible for ozone reduction which increases sun radiation at the pole. This is well recognized and scientists work hard at curbing their levels in the atmosphere. The ozone-destroying chlorofluorocarbons (CFCs), have now been widely banned under the Montreal Protocol, but the two other main types also present environmental problems. Neutralizing fluorocarbons has required a process whose high temperature drives up its cost. Researchers at Brandeis University used a silyium-carborane catalyst to break carbon-fluorine bonds at room temperature. This promises to make it easier and more effective to dispose of pollutants. The strength of the fluorine-carbon bond makes fluorocarbons valuable in chemically resistant and durable materials such as stain repellants, non-stick cookware, and coolants. (14)
Rising CO2 levels and effect on temperature
During the previous 3 ice ages the CO2 levels went up and down between 180 and 290 ppm, now we are above 400 ppm Only 2% is caused by forest fires and volcanic action, the rest is caused by humans mainly during the last 50 years. In 2015 we added a record 3.05 ppm. (2)

Global warming is determined by 4 organizations which take daily temperature readings of thousands locations on land and in the sea. Each is compared to the 30 year average at the specific time of the day. The global warming Is shown as averages obtained by each of the 4 organizations and the graphs show that there is little difference between the 4 organizations. (18) There are 2 parts less steep than the others. They are referred to as mini ice ages due to the influence of the sun. That influence is debatable. One graph shows the sun activities going up and down regularly without significant spikes. It appears that variable CO2 emissions are the cause.  One article shows that 2017 was at 1 degree the hottest year without an el nino effect. 2016 which had an el nino rose to a peak of 1.3 degrees.  The 1998 el nino peak was 0.9 degrees. That 0.4-degree rise is common for all temperatures during the last 18 years according to their graph (19)
The case of 0 emission earlier than 2100
The graph in Picture 42 D suggests that, according to the IEA we will reach the important 2 degrees before 2040 unless we take drastic action. As shown in F) above we had .04 degrees global warming during the last 18 years. That is .02222 degrees per year. Provided methane emissions remain the same it would raise el nino peaks like the present 1.3 to 2 degrees in 2048.  Another source (10) explains that the projections for 2100 are based on the 100 years life of methane while the 20 year figure of 85 times potency over CO2 should apply. Their warning is: “The world really needs to worry that we are likely to cross dangerous tipping points long before then, including the irreversible loss of enough ice on Greenland and Antarctica to raise sea levels perhaps 40 feet or more”. In Q of post 30 Dr. Hanson explained that during the previous ice age, sea levels rose 9 metres under similar temperature conditions. That could be the 3.6-5.3 degrees shown by the IEA. You can see their point. Such fast 0 reductions seem impossible. Fortunately, scientist and industries are working on many technologies other than renewables.
Required action to reduce emissions
In June 2016 the G7 nations signed an agreement to try to come to 0 emissions by 2100 in order to limit global warming to 2 degrees. As shown above, 2050 is a better target. In Paris some 195 countries submitted plans on how they would reduce emissions. For most it covered the first 30 years. More drastic reductions are required to reach the 2 degree target.
Progress made since Paris

 Progress has been made in renewable energy from wind and solar but far more needs to be done. The   action trackers on picture 40 shows that present anticipated emissions will result in 3.3-3.9 degrees warming while the committed national determined contributions will require a drop of 40 Gigatonnes of CO2 equivalent and will result in 2.5-2.8 degrees warming. O emissions will result in 1.5 degrees but requires another 30 Gt drop beyond the Paris commitments. Canada and the US have identical Copenhagen agreements, which can’t be met. Both extended the same trend to reach the Paris commitment. The US is doing better than Canada but both countries have to use CCU and hydrogen power to come even close to their commitments. China had in the past a steep increase and agreed to level off. It is expected to achieve it by spending a lot on climate action as shown in picture 45  A. India knew that it could not yet level off and exceed their commitment. There are many stories of phenomenal growth in wind and solar power, so that may be the reason.
Carbon capture is essential
Picture 21 shows that the IEA counts on 31% carbon capture to reach 0 emission. The IPCC has done a series of studies over the years determining how CCS improves flexibility and how it can reduce the over-all cost of mitigation. The latest version I saw is 2005. At that time, they found that 15-55% CCS was required for world-wide mitigation. It includes storage cost but none of the money which can be made by utilizing the captured CO2
Recycling of carbon captured from the air.

Reforestation is one way to take more carbon out of the atmosphere. It takes a long time and when we let it rot away it releases the CO2. When used to generate heat or power it is therefore a carbon neutral biomass. Algae grown in lagoons grow much faster than forests and can easier be processed into biomass. Picture 6 shows that production of carbon neutral jet fuel is quite feasible but costs more than regular fuel. Algae yield 10-100 times more fuel than other crops, requires little water and require only 0.42% of all US land to produce all the petroleum fuel in the US. There are at least 3 plants in operation that capture CO2 from the air.  Climeworks in Switzerland has been praised as the first operating plant. The CO2 sells for $400 per tonne, feeding greenhouses. An earlier article (24) gives a review of 3 plants and states that Climeworks captured CO2 is sold to make diesel fuel. Picture 25 shows the huge Carbon Engineering plant in Squamish BC, Canada. Because it has not yet been in commercial operation it is classified as a pilot plant. It will produce carbon neutral fuel.


Most carbon so far has been captured from gas wells and the cost is low. Norway’s Statoil collects a carbon tax of $70 per tonne of CO2 for marine operations, captures and pumps its CO2 under the sea bed for $ 17 per tonne, providing a huge heritage fund for the country.  In the US 4500 miles of pipeline networks are full of compressed CO2, costing around $ 35 per tonne which are used for enhanced oil recovery (EOR). Canada’s Saskpower carbon capture equipment for a coal fired plant can’t compete at such low prices (picture 18). It was thought that it could compete with natural gas but since those prices dropped a lot, that hope was squashed as well. Apart from that there have been a lot of technical problems with their amine based system, bringing the price to 60-100 per tonne. The CBC revealed a lot about the problems (20-22)

 New technologies for carbon capture and utilization

Picture 25 K shows 3 different technologies to capture from stack emissions,  one from India and 2 from Canada. All have been proven to work and are patented so lots of money can be made by propagating this equipment around the world. Profitability depends largely on what customers are prepared to pay for the captured CO2 but all 3 show much lower capture cost than the amine process.  Power consumption for post combustion capture is about 30% and a major cost problem. The exception is CO2 solutions, picture 25 K. CO2 Solutions’ technology solves these challenges by employing the most powerful known catalyst for carbon management, the enzyme carbonic anhydrase (27)

Picture 33 shows that the Canadian company Carboncure can improve concrete and save cement by using captured CO2, which is one example of utilization. Others are production of ethanol,

fertilizers and plastics. Capturing of CO2 from gas wells has proven to be rather cheap. Now I see that the cost of CO2 for the large food and beverage market is coming down. Union Engineering reduced their cost 30% to $ 23 per ton via the Flash CO2 process. It is a refinery process High purity liquid CO2 ( >99,99%) is recovered from the bottom of the CO2 distillation column its pressure can be increased to the required pressure for EOR, Urea or methanol production. Depending on the feed gas quality it might also be partly used as food grade quality. (25,26).

PS 6         July 30 2018
CarbonCure is expanding its business rapidly and has acquired yet another supplier for their CO2

CarbonCure’s technology injects carbon dioxide (CO₂) sourced from the refineries of industrial emitters into concrete, where the CO₂ becomes mineralized, thereby enhancing the strength of the concrete. The innovative solution helps concrete producers to lower production costs and make a meaningful contribution toward the global effort to reduce atmospheric CO₂ emissions. Airgas offers concrete producers a complete value-added CO₂ supply and service solution, supported by its large and reliable Gulf Coast distribution network.
CarbonCure is the world leader in a breakthrough market known as CO₂ utilization, with nearly 100 installations of its technology across North America.  The Global CO2 Initiative estimates that CO2 utilization in the concrete sector alone represents a $400 billion market opportunity.

 I had the impression that Aemetis mentioned in picture 33 uses post combustion capture with similar enzymes as CO2 Solutions. They don’t but produce ethanol from organic waste The Aemetis integrated demonstration unit was built to showcase high yield cellulosic ethanol production through the integration of advanced gasification from InEnTec with patented microbial fermentation from LanzaTech,”(28) Aemetis has also  entered into an agreement with Denmark-based Union Engineering to design and construct a 300 ton per day capacity  liquefied carbon dioxide facility.”(29). That is a completely different process used in refineries and petrochemical plants. Steam Methane Reformers, with CO2 recovery can generate higher H2 yield and CH4/CO fuel gas at the same time as it offers a high CO2 concentration source that can be recovered at a reasonable cost. (26)


Market for captured CO2

The variation is staggering. Source and quality play a major role. Here are a number of quotes:


In the US pipeline system, the cost of CO2 for EOR can vary from $15 per tonne to $ 45 per tonne. The latter applied when oil prices were $100 per barrel. The $ 15 is the cost for compression and transport and will apply when more CO2 is captured than needed for EOR (30)


The text in picture 25 K shows that In India, Carbon Clean Solutions operates at $30 per tonne. This is confirmed by the recent merger with Veolia (31). Their own website shows $40 per tonne (32) The 600,000 tonnes per year is a misquote It is 60,000 tpy. Their website has a counter. From 2009 till 25 Jan 2017 they captured 319,039 tonnes. Considering that it captures from a coal fired plant it is quite encouraging.


Inventys, the Canadian company in picture 25 K will build it’s first plant in Saskatchewan and based on many test runs the cost is expected to be below $30 per tonne (33)


CO2 solutions, the other Canadian Company in picture 25 K has 2 partially funded projects, one for 30 tonnes per day and another for 300 tons per day. “At large scale, technology delivers costs of $25 to $35 per tonne of CO2captured”. They are also aiming at the high priced soft drink market with 10 tpd plants like the proposed 10 tpd carbon capture unit at a “Caribbean beverage bottling plant •Will supply CO2captured from local boiler for carbonation of soft drinks”. (34)


Union Engineering’s Flash CO2 process will deliver liquid CO2 at $23 per tonne and some of it will be food and beverage quality. It also produces hydrogen but not green hydrogen obtained from electrolysis. (25 26)


Aemetis, which will produce CO2 for the Keyes ethanol plant shown in picture 33 M is quite clear about the price for the food and beverage industry “Right now, the end user price of pure CO2 is about 8 cents per pound ($160 per ton). The Keyes plant would likely about 180,000 tons of CO2 per year, with peaks and valleys in CO2 production level based upon the fermentation cycle, and the CO2 plant would convert 110,000 tons (the consistent, base production level from fermentation) into liquid CO2.’ (29) No wonder they asked Union Engineering in N5 above to join them and use their $30 per ton expertise as well.


The strangest price variants occur in capturing CO2 from the air. Climeworks in Switzerland does it for $ 400 per tonne feeding greenhouses (35) Eisenberger’s $24 million demonstration plant
struck deals to supply at least one customer with carbon dioxide harvested from the sky. He claims it can be done for far less than $100 and points out that the future is in using CO2 and hydrogen to produce carbon neutral fuels(36) That is exactly what Carbon Engineering is doing at their Squamish BC plant (picture 25 K). They expect it will cost between US$1 and $1.50 a litre. (36) They started their equipment, produced a small quantity of liquid fuel and will soon synthesize  1 barrel per day. (37)


General aspects of hydrogen power generation

Picture 32 shows that without CCU and hydrogen power generation Canada will be unable to meet its Paris commitment. Green hydrogen can be produced in large quantities from renew
able power using electrolysers to split water in hydrogen and oxygen. (38, 39). The hydrogen can be used as replacement of natural gas in existing power plants using gas turbines or in hydrogen fuel cell power plants operating presently on hydrogen obtained from fossil fuel. Hydrogen is already being used in large quantities to power cars, trucks and trains while development for ships is underway. If it is all green hydrogen we have a chance to meet our Paris commitments

Green hydrogen can also be generated from biofuel. Aemetis referred to in N6 for CO2 production, produces hydrogen at reasonable costs with the same cellulose fermentation process for all types of waste (40). The Fountain Valley station in California uses municipal sewage to produce hydrogen for hydrogen fuel cell vehicles (FCVs) (41) In Fukuoka, Japan, Toyota  is converting human waste into hydrogen to fuel the Mirai.(42) Toyota also hopes to complete by 2020 a manure plant in Los Angeles that provides electricity for around 2350 homes and hydrogen for 1500 vehicles.(43)


270 000 tpy of green hydrogen for the Netherlands

Picture 49 did not copy too well but shows that the plan is to produce 160 000 tpy of green hydrogen using wind power by 2030. The Netherlands has vast shale gas reserves but are concer
ned about the earthquake danger, hence the push for green hydrogen. It includes 100 000 tpy hydrogen from biogas. Most of it will be used to feed Dutch and German pipelines, produce ammonia and methanol. The hard to read transportation allotments in thousand tpy are 100 000 cars (12) 1300 buses (10) 50 trains (5) The hard to read utilisation categories are: Distribution of energy throughout regions, buffer to increase system reliance, decarbonize transport and industry energy use, serves as feedstock using captured carbon and helps decarbonizing heat for buildings.

Apart from the references in O above there is an excellent article by professor van Wijk, showing many more details (44). It includes the following statement: The total investments for the development of a green hydrogen economy in the Northern Netherlands up to the year 2030 are estimated to be between 17.5 and 25 billion euros.


Canadian progress by Hydrogenics

Picture 39 sums up the fame of this company. Most references are in various post of the blog and some new ones will be shown below. Picture 20 shows their first wind gas plant in Germany and the first Alstom train equipped with heir fuel cell technology. After careful evaluation of competitors they won an agreement, valued at over €50 million It includes the supply of at least 200 engine systems along with service and maintenance as necessary over a 10 year period. Picture 20 also mentions Hydrogenics involvement with Korean power plants. Details can be found in reference 45 below. Not yet documented on the blog is that Hydrogenics has partnered with Enbridge to pr
ovide a 2 MW storage facility in Ontario (46). This is not a windgas plant. The electricity comes from the net and the system is described as a Power-to-Gas project. Also not yet documented is that Hydrogenics won the contract for a second windgas plant in Germany (47) and another one for Palm Springs in the USA (48)

Hydrogenics is also in the automobile business. It has signed separate supply agreements with several Chinese electric vehicle integrators to bring its fuel cell and fueling station technology to China. Hydrogenics has worked closely with a number of Chinese companies throughout
the past year – already delivering over 30 propulsion systems

 for buses and other vehicle platforms from leading original equipment manufacturers (OEMs) such as Futian and Volvo. The largest bus OEM in China, Yutong, is one of the key suppliers seeking to bring fuel cell technology into the urban transit mainstream. The deals signed Friday cover more than 2,000 vehicles over the course of the next 3-5 years. (49)


Ballard makes good progress in the bus and truck business

As documented in post 30 this Canadian company sold its car expertise to Volkswagen and went in partnership with a Chinese company to supply and maintain its fuel cells for 10 000 trucks and buses. Some buses are shown in picture 20 Q Not yet documented is that they do very versatile work for other countries . In January 2017 Ballard FCveloCity® engines were powering more than 80 buses around the globe: 41 in Europe, including Belgium, Germany, Italy, the Netherlands, Norway, Scotland and the U.K.; 24 in the Cities of Foshan and Yunfu, China; 13 in the U.S.A., including the states of California, Massachusetts, Michigan and Ohio; 3 in Brazil; and 1 in India.  During the last 10 years Ballard has worked with 13 bus manufacturers to develop a variety of fuel cell bus configurations that have been deployed in a wide range of climatic conditions and operated under a host of demanding duty cycles. (50)

There are a number of other companies using fuel cells for hydrogen vehicles. Ballard has developed the necessary technology building blocks for automotive fuel cell stacks, including world leading designs and capabilities relating to anode and cathode catalysts, membrane electrode assemblies, bi-polar plates (including flexible graphite, molded carbon and metal plates), the elimination of cell voltage monitoring, and the use of advanced modeling tools to predict stack performance. (51)
PS 5       July 30 2018

Further news from Hydrogenics shows that important contracts have been signed or underway. Apart from Ballard Hydrogenics will also become a major contributor to the Chinese hydrogen bus and truck fleet. I paste some abstracts below and hope that Canadians look at these developments instead of concentrating on oil alone. Another one is CCU where new development is shown in PS 6 under point M

“Jan 29, 2015 - In 2014, Hydrogenics secured contracts for nine Hydrogen fueling ... over 10 fueling stations in California and more than 50 stations worldwide”

 “The 2.5-megawatt Zero Impact Production (ZIP) hydrogen facility in Palm Springs, California will use Hydrogenics’ state-of-the-art PEM electrolysers to convert wind and solar energy into 1,000 kilograms of renewable hydrogen per day.” The hydrogen will be used to charge cars. In 2016 6 different models were available consuming on average 1 kg of hydrogen per 100 km.. For short 50 km commuting trips that would get 2000 fossil fuel cars off the road.  It is only 0.4% of what Hydrogenics 25 MW units will have to produce in the Netherlands from wind and 4% of their solar generation (picture 49)

By Joanna Sampson5 December 2017

SinoHytec and its partners, including Foton, are promoting a fleet of 150 fuel cell buses in Zhangjiakou, where China will be hosting the 2022 Winter Olympic Games. The completion and delivery of this fleet is expected in early 2018. Trudeau had the opportunity to learn more about how Hydrogenics and SinoHytec are working together to jointly address climate change by reducing the carbon footprint related to transportation in China.

“Hydrogenics has the leading technology for providing zero-emission transit solutions to the public. We are currently completing the largest operating hydrogen fuel cell bus fleet on the planet, and we look forward to a very successful and long-term collaboration with Hydrogenics,” explained Zhang


Declining oil demand due to EVs and FCEVs

Bloomberg’s announcement in picture 44 shows a fast increase in EVs. Further details are: “Bloomberg New Energy Finance (BNEF) forecasts EVs will be as cheap as gasoline cars by 2025 and keep dropping in price until EVs overtake them in yearly sales, by which time EVs will be displacing 8 million barrels of oil a day — more than Saudi Arabia exports today”.
In addition, a whole article complete with graphs and tables shows the most likely scenario including that the 8mbpd will be reached in 2040. (52) Since the projection does not include hydrogen vehicles it may occur before that date
Problems with CCS from stack emissions

Another great help is that sales of fossil fuel vehicles will be banned. The most aggressive pronouncements are:

“India is targeting all vehicles on the road to be powered by clean energy by 2030. In Norway, over 20% of new vehicles sold today are electric and the government wants 100% of sales to be zero-emission by 2025. The Netherlands is also following suit. Germany is reviewing a similar objective. Early indications suggest that over 800,000 new energy vehicles  (NEVs, which includes BEVs and FCEVs) were produced in China in 2017. The Chinese government has set a goal of 2 million NEVs produced annually by 2020” (51)

In 2017, we also saw unprecedented developments at the city level when 12 of the C40 cities – including London, Paris, Los Angeles, Copenhagen, Barcelona, Vancouver, Mexico City, Milan, and Seattle – signed the “C40 Fossil-Fuel-Free Streets Declaration” – establishing a target of procuring only zero-emission transit buses by the year 2025. Over the next few years, we expect more countries and cities to set up plans to ban ICE-based vehicles. (51)


Declining costs of wind and solar power

References not included in picture 49 P show a windfarm in Morocco, where Enel Green Power will produce unsubsidized wind power for 3c/kwh. I checked several websites and it is a great development. It involves 5 wind farms with a total capacity of 850 MW (53). The other reference shows a large solar panel field in Dubai where Masdar Consortium will supply unsubsidized solar power for 3c/kwh. Again, there are several articles about that project. DEWA has adopted the Independent Power Producer (IPP) model to build the 800MW third phase of the Mohammed bin Rashid Al Maktoum Solar Park. It has generated international interest from global business and energy companies (54)

As noted, BC has better wind conditions than Alberta and could get an even better deal rather than spending 8.7c/kwh for site C.


As documented in post 21, and summarized by me in a newspaper (55), BC has a vast surplus of hydro power because the clean energy act requires BC Hydro to buy renewable power from independent power providers(IPPs) even if they can’t sell it. The IPP power is sold via long contracts at a fixed price, ranging from 8.5-9.1c/kwh. It has to be exported at bargain prices. Some power can’t be sold or stored at all and is wasted by having to let reservoirs flow over, driving up the price to 11c/kwh. In 2015 when I published post 21, construction had not yet started and I concluded that wind power costs the same as hydro but will come down, did not require public financing and would not destroy an important valley. Still the BC government pushed ahead. Picture 31 shows how much the valley has already changed. Now that wind power costs so little we have the choice of paying several billions in cancellation cost or live for hundred years with a money losing white elephant. Based on T) above it is quite likely that BC, with better wind conditions than Alberta can reach a 20 year deal for unsubsidized power at 3.7c/kwh and continue to do so for the remaining 80 years.   Site C is expected to produce 5100 GWH per year which is 5,100,000 MWH per year. Each MWH represents $87, amounting to $ 0.444 billion per year and $44.4 billion over its lifespan. If we use 3.7c/kwh wind power instead we will save (50x44.4)/87=$25.3 billion during those 100 years.



Even when mixed with condensates to become diluted bitumen (dilbit), Alberta oil is a tar-like substance which can best be processed in heavy oil refineries. Most are in the South of the US where similar heavy Venezuela crude is handled. Until recently the US had an export ban on crude. With the prospect of the Keystone XL pipeline we could now export via the South but for Asia a direct route via the Pacific will be cheaper. The problem is that, like in the Kalamazoo disaster the bitumen sinks shortly after it hits the water because the condensates evaporate, which makes tanker traffic through BC waters a controversial issue. Probably it is too costly to accompany each vessel with a crew and equipment to contain a spill and use slick lickers to collect it. Apparently, no studies have been done on all effects of spills. Also, very little has been done to look at some well engineered alternatives for transport to Asia

Based on data documented in neilwilhees.blogspot.ca  a newspaper accepted my 400 word comment about 7 alternatives for the KM pipeline : http://www.nsnews.com/opinion/letters/letter-rail-beats-pipelines-for-safer-transport-of-alberta-oil-1.2365559 It shows that three will transport unsinkable oil while the 4 others avoid all tanker traffic through BC waters. Two of the fully estimated proposals are for refineries which would export finished products from Kitimat refineries and will be among the very few that will capture and utilize the CO2 emissions they create. The third is a huge pipeline which will carry unsinkable syncrude and export it by tanker via Prince Rupert. The Asian super refineries can easily handle dilbit, which is a sour heavy crude. Syncrude and other similar light sweet oils are more expensive but seem essential to diminish the tanker controversy in BC waters. The oil fields have 9 upgraders. Shell, Suncor and Syncrude produce the most (58) Until recently 45% of our bitumen (1.33 bbpd) was upgraded (49).

The movement of oil is complicated by new developments and the economy. The recent growth in US oil production has largely come from shale, particularly the Permian, Bakken and Eagle Ford basins. Shale oil is very light and sweet. This explosion of light oil production poses a problem for America's complex refineries, that are designed for heavy sour crude. (60) Despite present growth a downturn can be expected. The 6 major financial institution quoted in Q of post 30 claim that in order to meet emission targets most oil will have to be left in the ground, so only the cheapest is worth extracting. Picture 26 has a stronger message for investment. “2017 saw the launch of the first AODP Global Climate Index for Asset Managers, rating the world’s 50 largest asset managers on their success at managing the financial risks of climate change for their clients”. The huge Dutch ING group of banks made it clear that they won’t finance oil sands operations, including Canada’s, due to environmental concerns. I also saw that in July 2017 French oil giant Total cut off funding for the Fort Hills project. Suncor Energy Inc. stated “Total SA has cut off funding for the partners' massive Fort Hills project, a new sign of anxiety by a major international oil company over high costs in Alberta's oil sands.” (57)


I feel that as part of the KM debates a proper evaluation has to be made about the cost, benefits and risks of all eight projects. Companies have worked hard to show what can be done and little is shown by the main media except KM disputes. At the end of post 1 is a whole list of pipelines concerns. I had a 5 Email exchange with Enbridge in 2013. Enbridge acknowledged receipt of the list. Most apply to all pipelines, some have been resolved but crack detection requirements are still not defined while external leak detection is still considered too expensive. The major recent Nexen and Husky spills show that there is still danger. Far less dangerous than trains loaded with volatile oil traveling on poorly regulated railways causing infernos. It is hard to convince the public that sending neatbit by train is safer than pipelines, in particular on almost straight new tracks with minimum grades.

That leaves the $ 16 billion Eagle Spirit pipeline and the $19 billion G7G railway as main contenders. Both can carry more oil than KM, both have support from First Nations and agreements for jobs and prospects of part ownership. At present the pipeline still is subject to the tanker moratorium even though no dilbit is involved. The pipeline problems in post 1 will have to be evaluated and see how much improvement can be made. That also applies to KM. I have not seen a breakdown of capital and operating cost for the pipeline. Those for the G7G are high because the entire rolling stock of 208 locomotives and 6072 insulated cars with heating coils are included based on more than double the KM volume. All bridges and tunnels are estimated for future double track operation. Another cost is a tank farm at Delta Junction, from where the condensates will be added for transport via the existing Alaska pipeline to Valdez. It requires a condensate line from Valdez to Delta junction, which is included in the estimate. The Alaska pipeline is under-used but if, due to tax incentives for its users the volume increases and it can’t handle the Alberta oil, there are other options shown in the van Horne report. Those options are more expensive, but again, considering potential cleanup cost for KM spills it may not be expensive. There are also some savings because Valdez is a few days closer to Asian ports. As mentioned in picture 29, the main advantage of the G7G over pipelines is that as demand for oil start dwindling pipelines will lose money while railways can still transport other goods. Picture 30 shows the mineral potential, which recently was in the news again. One potential mine was declared unacceptable for environmental reasons while the others are eyed upon for power supply from the expensive site C project.

A recent desmog article shows that Kinder Morgan has not yet found any customers for the 590 000 bpd of dilbit which was touted to be needed to gain op to $ 25 per barrel extra income from Asia compared to the US market. That may be over optimistic. In North America, oil futures are compared to the quality of one particular light sweet crude, West Texas Intermediate. Alberta’s heavy sour crude, Western Canada Select, could cost up to $15 per barrel in upgrading to meet that standard. Upgrading is done in delayed coking units (DCU) and depending on efficiencies the $ 15 may be lowered:  “light crude refineries can’t handle the heavier components in the light crude oils and so the refineries end up producing more undesirable by-products (like petroleum coke) per barrel of input. What this means is that the heavy oil refineries produce more gasoline/diesel/kerosene per barrel of heavy crude oil than the light refineries do per barrel of light crude oil and the heavy refineries produce a lot less waste petroleum coke per barrel as well. In financial terms, the heavier crudes produce much higher margins per barrel of input than their lighter crude cousins and generate less waste by-products that have to be disposed.” The Asian refineries are equipped with CCU and are increasing their capacity rapidly. Due to the above-mentioned quality advantages of processed heavy sour oil the demand is increasing. Picture 57 at the end of this post shows that China’s crude oil imports rose from 6 million bpd in 2012 to 8.5 million bpd in  2017. Absent from the 8 sources is Venezuela, a heavy oil producer. That will change. A 2017 report shows that Petroleos de Venezuela SA (PDVSA) and China National Petroleum Corp. (CNPC) have entered a series of agreements related to development and operation of the long-planned Nanhai 400,000-b/d refinery in Jieyang, Guandong Province, China. Its entire capacity is DCU to handle Venezuela heavy crude. Maoming Petrochemical Co. refinery in south China has a 1.1 million mt/year delayed coker unit.  At the same time other new Asian refineries are built which can probably handle heavy sour crude cheaper than the US so export to Asia will still be more profitable than to the US. The world’s largest and newest refinery is Jamnagar in India. It includes DCU to handle heavy crude

KM’s website shows that the main source of financing comes from 4 Canadian banks. Of the 26 sources 9 of the contributors are Canadian while the 2 Chinese contributors only represent 4% of the committed money. Competing proposals show more enthusiastic Chinese participation.  Kitimat Clean Energy: “In April 2013, Kitimat Clean signed a Memorandum of Understanding with the Industrial and Commercial Bank of China which will serve as financial advisor and cooperate in the financing of the project.” “In April, he secured a memorandum of understanding with the Industrial and Commercial Bank of China, China’s largest bank, involving $25-billion in financial backing to build the refinery, a pipeline from Alberta, and provide 10 super tankers to transport the oil to China. He said more deals with Chinese companies are on the way.” Since that time the pipeline idea has been scrapped in favor of neatbit trains from CN.

In 1982 the Canadian Constitution was amended by adding section 35 giving First Nations far more say in development of projects. First Nations have now much better access to money for their projects. RBC completed a C$545 million bond issue for the Fort McKay and Mikisew Cree bands - the largest ever private investment by a First Nation - allowing them to buy a 49 per cent stake in a Suncor Energy SU.TO 1.65% storage facility. "The deal was oversubscribed," It's assets that create cash flow," said Joe Dion, Chief Executive of First Nations-owned Frog Lake Energy Resources Corp, which produces 2,000 barrels of oil per day. "We get a piece of the action." Investment bank AltaCorp Capital is raising funds for a $16 billion oil pipeline, proposed to run from Alberta to the northern British Columbia coast. The project has modest financial backing from one of Canada's richest families, the Aquilini Group, and support from 35 First Nations to use their land. In exchange for allowing that access, the bands will own at least 35 percent of the pipeline and a corresponding share of the profits. Major Canadian oil producers including Suncor Energy Inc., Cenovus Energy Inc. and Meg Energy Corp. also want it to go ahead, while investment broker AltaCorp Capital Inc. has been lined up to organize financing. The pipeline’s right of way would be on an energy corridor that would be pre-approved by First Nations to also house gas pipelines, hydro lines and fiber optic cable. That Eagle Spirit pipeline can carry twice the KM volume. Even though no dilbit will be shipped they are subject to the tanker moratorium and have a memorandum of understanding with the Roanan Corporation to move the terminal to Hyder Alaska.

I had seen that Asia and Russia are working hard to develop new delayed coking units (picture 58) and was curious about other counties. In several European countries there are many smaller units which are being upgraded. Belgium starts one of the largest new one in Antwerp. South Africa, Mexico and Argentina also have sizable projects under way but it is not clear if this will help KM to have all or part of their dilbit refined beyond the US. (picture 60).   A number of these refineries use their capacity to extract diesel, gasoline and naphtha from derivatives obtained from non-coking refineries. Alberta’s high sulphur crude can help to eliminate the 760,000 bpd light crude which Eastern refineries import. Since neatbit railways are safer than pipelines (picture 59) a new railway through the National Corridor ( X and picture 29) seems to be a logical solution. Now that microgrids become a practical alternative to long transmission lines windfarms with battery and hydrogen backup will allow electrification (picture 38). The Senate declared this corridor of National Interest and the government has agreed.  Apart from its original purpose it only needs 6 trains per day to carry 760,000 bpd. When Eastern refineries are modernized only about 530,000 bpd (4 trains per day) will be required because heavy crude has a better yield than the imported light crude. (Picture 60)  

In the reference list 63-77 have been added. The text below shows some of the main data This includes  the new bunker oil regulations, cokers and the proliferation onf delayed coking units. Included are the backup data for our oil production, consumption and possible deduction to see how much is available for export. Our production is still rising. In 2017 it was 4.21 million bpd and the 2018 forecast is 4.49 million bpd. We could reach 5 million without creating much of that extra 30 Mtpa emission, which would further exceed our Paris commitment (picture 32). Our consumption is 2.34 million bpd so by eliminating the imports (see above) there will be 5-2.34-0.53 = 2.13 million bpd available for export. When BC introduced its carbon tax, consumption of petroleum products dropped 17 % We can expect at least 10% with a national carbon tax, which brings the amount for export to 2.13+0.23=2.36 million bpd

Ref 63 Business wire

Ref 64 Syncrude


Ref 65 Reuters

Ref 66 Mc Dermot

Delayed coking is a semi-continuous process using alternating drums that are switched off-line after filling. Support facilities include closed blowdown, coke cutting and handling, and a water recovery system. Hot residual oil is fed to the bottom of the fractionator where it mixes with condensed recycle. The combined stream is heated in the furnace to initiate coke formation in the coke drums. Coke drum overhead vapor flows to the fractionator where it is separated into wet gas, and coker liquid product such as unstabilized naphtha, light gasoil, and heavy gasoil. During the coke drum steam out and cooling period, all steam and hydrocarbon vapors are directed to the blowdown system where they are recovered and recycled back. After the coke drum cooling cycle is complete, the coke is hydraulically cut from the drum and dropped into a pit or pad, where water is separated from coke and recycled

Ref 67 Hydrocarbonprecessing

Ref 68 Gazprom

Ref 69 UK Oil

Ref 70 Reuters
The delayed coker unit, part of a $1 billion investment announced in 2014, will enable the 320,000 barrel per day (bpd) refinery to upgrade high-sulphur fuel into various types of diesel, including the variant mandated by new laws governing shipping fuels. [reut.rs/2jrMVPS 

Ref 71 Platts
- Spain's Puertollano refinery is undergoing a major turnaround from the end of January. As part of the maintenance work on the conversion units, Repsol will carry out work on the thermal insulation of one of the vacuum unit's (55,000 b/d) furnaces, as well as modifying some of the equipment in place at the head of crude distillation unit No. 2. The work also includes the FCC (38,900 b/d) and the coker (24,000 b/d). The turnaround should be concluded around March 20. The company previously said it expected the work to conclude at the end of March.

- Poland's Plock refinery is planned to carry out works in the spring involving a CDU, FCC (28,000 b/d), reformer (44,300 b/d) and one HDS (hydrodesulfurization) unit.

Tupras said the CDU unit in its Izmir refinery will be offline for the first 11-13 weeks of 2018, according to a presentation given in a teleconference. The CDU was offline for part of the fourth quarter of 2017. Tupras said the revamp of the Izmir refinery Plt 7000 crude oil unit was responsible for crude oil capacity utilization falling from 107.5% in Q3 to 89.7% in Q4, w

-- Italian refiner Saras has wide-ranging maintenance plans for the first half of this year, it said in its fourth-quarter report, with work due to be carried out on CDU units T1, T2 and RT2, vacuum distillation unit V2, the visbreaker and mild hydrocracking unit 2. In the first quarter of

Swedish refiner Preem AB reported lower throughput in the fourth quarter of 2017 following maintenance at its

Gothenburg refinery adding that more maintenance was to come in the first quarter. The company said that in early March it decided to move maintenance work on selected units, mainly the isocracker unit and fluid catalytic cracker, planned for April to March. It did not specify where this work would be but traders said maintenance is affecting the Lysekil refinery near Brofjorden, where there is also CDU and VDU maintenance in Q1. "These maintenance activities are progressing well, and the plan is to have the units back in operation with products to tank from the isocracker on March 18, and products to tank from the FCC on March 22," Preem said.

- Gazprom Neft has started construction of a delayed coker at its Pancevo refinery, with a target date for completion of 2019. The delayed coker will have 2,000 mt/day capacity and will help increase the depth of processing to 99.2% and diesel production by more than 38%. The refinery will start producing coke, currently not produced in Serbia.

- Swiss commodity trader Gunvor is looking at various options for its refinery in Rotterdam aimed at meeting the International Maritime Organization's requirements for low sulfur marine fuel from 2020, the company said, adding that it hasn't made any decision yet. Late last year, the Dutch authorities said that, in response to a Gunvor inquiry, it had clarified that there was no need for an environmental assessment for a delayed coker. But a Gunvor spokesman said the company has not made a decision regarding upgrade wo

Ref 72 oilprice.com
Total Completes $1.2B Upgrade At Its Biggest Refinery In Europe

By Tsvetana Paraskova - Nov 30, 2017, 3:00 PM CST

 France’s oil supermajor Total SA said on Thursday that it had completed the upgrade of its Antwerp refinery, its largest refining and petrochemicals platform in Europe,

The new refining complex will reduce the high-sulfur heavy fuel oil yield, in anticipation of the new marine fuel regulation that will take effect in 2020,” Total said.

Another oil supermajor with a facility at Antwerp in Belgium, ExxonMobil, said earlier this week that it planned to complete the construction of the new delayed coker unit towards early 2018 and would then proceed with the start-up process. The delayed coker unit will be fully operational in the first half of 2018.

Ref 73 coking.com
2018 will be a big year for Delayed Coker projects.

ExxonMobil will complete it’s DCU in Antwerp in early 2018.

The LOTOS Gdansk delayed coker cokes on line in 2018 as part of their Effective Refining Project.  Read More

Construction has started on the Delayed Coker at Serbia’s Pancevo Refinery.

INA is tendering bids for a DCU in Rijeka, Croatia.  Read More

PEMEX has plans for a $2.1 billion delayed coker project.

Lukoil has decided on a Delayed Coker at Nizhny Novgorod Refinery. Read More

Because of MARPOL VI, resid conversion flexibility is needed b

Ref 74 Oil and gas technology
The coking unit will be installed at the Campana Refinery in Buenos Aires Province, Argentina. It will be based on Foster Wheeler’s proprietary SYDEC delayed coking technology. SYDEC is a thermal conversion process to upgrade heavy residue feed and process it into high-value transport fuel

Ref 75 Google
Crude oil imports grew to 759 Mb/d in 2016, a 1% increase. The U.S. share of these imports, which had been growing consistently for several years, decreased from 63% to 54%. Canada's main sources for overseas imports in 2016 were Saudi Arabia (11%), Algeria (11%), Nigeria (10%), and Norway (6%).Mar

Ref 76 ceic data
Canada’s Oil Consumption was reported at 2,343.25 Barrel/Day th in Dec 2016. This records an increase from the previous number of 2,298.82 Barrel/Day th for Dec 2015. Canada’s Oil Consumption data is updated yearly, averaging 1,800.31 Barrel/Day th from Dec 1965 to 2016, with 52 observations. The data reached an all-time high of 2,382.87 Barrel/Day th in 2013 and a record low of 1,108.12 Barrel/Day th in 1965. Canada’s Oil Consumption data remains active status in CEIC and is reported by BP PLC. The data is categorized under World Trend Plus’s Association: Oil and Gas Sector – Table RO.BP.OIL: Oil: Consumption.

Ref 77 neb-one.gc.ca
ARCHIVED - Estimated Production of Canadian Crude Oil and Equivalent

4212602 bpd in 2017

4490351 bpd 2018 forecast

PS 3- 8 June 2018

While neatbit railways are safer and not much more expensive than pipelines (pictures 53 and 54), that only applies to transporting to upgraders or complete refineries that can process it, The PS of 23 May 2018 shows why Kinder Morgan has no chance to reach the Asian market with dilbit. The same applies to the G7G railway which therefore has been planning to use newly developed Auterra oils. They are light oils with less than 1% sulphur, close to syncrude but at a much lower cost. While China has little capacity to process dilbit they import and refine a lot of oil heavier than the Brent or WTI trading benchmarks. In fact, they recently established their own Shanghai standard against which heavier oils will be rated and traded. Picture 57 shows how Chinese crude imports have grown from 6 million bpd in 2012 to 8.5 million bpd in 2017. Despite increased protests about our exports the world demand is still rising for at least 7 years and will level off for many more years. We may as well go along with the trend rather than letting others create the same quantity of GHG that people are complaining about. When we keep extracting at a soon to be reached 5 million bpd there is lots of export opportunity for blended heavy oils. I will prepare a further PS with picture to document the new developments about the competition. Some politicians and oil magazines still claim that we can make much more money by selling to Asia rather than the US.  It is not as much as they think but still worthwhile.

 PS 3 and picture 61 in post 31 shows that Chinese crude blends will be in high demand for quite some time and that by transporting them with the G7G railway to Valdez will cost $ 5 less per barrel than with small tankers from Burnaby to Valdez from where the oil has to be transferred to larger, more economical tankers. This PS and picture 62 show with many references why our main crude, WCS is worth far less than what is traded based on Brent and WTI qualities.  Chinese refineries have no extra capacity for dilbit but high demand for heavy oil. This PS also has a lot of information about competitiveness and widely varying shipping costs. The $5 per barrel in savings has been increased to $6.20 because the amazingly high tanker cost is based on Anacortes to San Francisco rather than Anacortes to Los Angeles.  That $ 4.00 is clearly shown on the Dec 2015 Oil Sands Magazine map. That map shows the cost of 14 US pipeline, tanker and railway transportation modes from Edmonton and Fort Mc Murray. There are no pipelines to the West coast but 5 pipeline and 3 railway options to reach the Southern refineries. Picture 60 only shows the 3 cheapest pipeline routes which are $7.51, 8.38 and 11.40 per barrel. Our WCS oil costs $ 15 for upgrading to WTI standard so with those transportation rates the present price difference of $24 is not out of line.

The demand for Chinese crude blends is according to https://www.platts.com/latest-news/oil/singapore/cnpc-forecasts-chinese-2018-oil-demand-to-grow-27906041  growing 7.7 % in 2018. Even though fossil fuel for cars will soon be banned, the GDP will increase 6% while oil product exports are forecast to surge 30.7% year on year.

According to a 1 June article in the Globe and mail “Continued investment in the oil sands generally, and in the Trans Mountain pipeline specifically, means Canada is doubling down on a no-win bet. We’re betting that the world will fail to meet the reduction targets in the Paris Climate Agreement, thus needing more and more oil, including our expensive and polluting bitumen. We’re betting, in other words, on climate disaster. If, however, the world finally gets its act together and significantly cuts emissions, then Canada will lose much of its investment in the oil sands and the Trans Mountain pipeline expansion, because the first oil to be cut will be higher-cost oil such as ours”.

 Looking at both sides you will see in post 29 and picture 32 that we should not increase oil extraction beyond present levels. That will eliminate the 30 Mtpa for expansion but we can’t stop our present production. Oil companies would go bankrupt while other countries would use their oil to create the same amount of GHG. According to https://www.neb-one.gc.ca/nrg/sttstc/crdlndptrlmprdct/stt/stmtdprdctn-eng.html our production will soon reach 4.6 million bpd and there is no reason to increase it. https://www.ceicdata.com/en/indicator/canada/oil-consumption Indicates that our consumption is about 2.4 million bpd, which leaves 2.2 million bpd for export. When the BC carbon tax was introduced consumption dropped 17%. With the coming national tax, we can expect at least a 10% drop which bring the exports to 2.4 million bpd

Tanker traffic to and from the Burnaby refineries is limited to the dept and bridge clearance of our port. According to https://www.portvancouver.com/about-us/.../petroleum-products-and-tanker-safety/  the largest tanker the port can accommodate has a capacity of 120,000 tonnes. At 6.92 barrels/ton that is a capacity of 830 000 barrels. The tankers can’t be fully loaded. https://ca.reuters.com/article/businessNews/idCAKBN13G016 reports that “the largest-sized oil tanker that can dock in Vancouver is an Aframax, which can carry 500,000 to 700,000 barrels. Vessels at the port can only be loaded up to 80 percent capacity due to depth and other restrictions, meaning a vessel can only be filled to around 550,000 barrels. That’s a stark contrast to the one million-barrel Suezmaxes, or the two million barrel very large crude carriers (VLCCs) commonly found in Iraq or Singapore.” Valdez and LOOP in Louisiana are the only US ports that can utilize VLCCs. https://www.bloomberg.com/.../giant-oil-tankers-from-u-s-seen-cutting-time-money-a.. . reports that transferring crude costs $0.20 per barrel

 The big advantage of using Valdes as a shipping point for Canadian blends to China can be seen in a January 2016 report: https://www.reuters.com/article/us-usa-crude-asia/traders-eye-alaskan-oil-exports-to-asia-as-shipping-ban-ended-idUSKBN0UM0FM20160108  reported that Oman crude, a Middle Eastern grade similar in quality to Alaska North Slope (ANS), delivered to North Asia on a Very Large Crude Carrier would cost about $30.60 a barrel, including freight. Meanwhile, ANS costs closer to $31.80 a barrel including $3 per barrel in freight costs on a Suezmax tanker, according to calculations by Reuters and trade sources.

    Alaska North Slope has been at roughly a $3 to $4 per barrel discount to the similar Russian ESPO blend so far this month. Freight costs from the Russian port of Kozmino to South Korea are currently about 80 cents per barrel.

  Even so, medium-sour Alaskan crude fits well with most Asian refineries that are geared towards processing high-sulfur Middle East crude, dealers say, and shipping time is half the four-week journey from the Gulf. Present spot rates for VLCCs can be seen in https://www.hellenicshippingnews.com/more-scrapping-may-lift-oil-tanker-rates-in-late-2018-frontline-ceo/Spot rates for very large crude carriers (VLCCs), with a capacity to transport 260,000 tonnes of oil, have recently dropped to a loss-making $13,000-14,000 per day, far below Frontline’s cash breakeven rate of $21,600”. Since 1 tonne is about 6.9 barrels it amounts to 1,794,000 barrels for $21,600 per day=1.2c per barrel per day.  When operating at the quoted loss it will be 0.75c per barrel per day. For the two-week journey the $21,600 amounts to 16.8 c/barrel to reach Asia from Valdez. There must be some more cost than $21,600 because the 16.8 c is unbelievable low.

The 550 000 barrel limitation for the Burnaby tankers makes their transport very costly.  It costs $ 4 per bitumen barrel from Anacortes to San Francisco. That can be seen on the map in the Dec 2015 Oil Sands Magazine. Via the branch TM line to Anacortes it costs $2.76/Bbl from Edmonton bringing the total to $ 6.76, compared to $14 per train. That saves them $7 per bitumen barrel. Since Long Beach Cal also has no pipeline access, Alberta dilbit will gain even more by tanker to those refineries.  The railway cost is $17 per barrel. The $7 savings may soon disappear because the TMX may double the transport cost from Edmonton to Anacortes while railway cost to SF could drop $ 4 per barrel https://dogwoodbc.ca/newblended heas &/kinder-morgan-delivering-oil-california/Indicates with markings that a lot of TM dilbit goes to Long Beach near los Angeles. If Alberta decided to export a heavy crude blend to China like is already been done by US rail via Portland Oregon I would cost a lot more than can be achieved with the proposed G7G railway. I tried to find marine distances  but  https://www.aquaplot.com/privacy and

https://www.sea-seek.com/tools/tools.php required signing for free membership but I could not find the apps. My best measurements are 1600 km from Vancouver to San Francisco and 2400 km from Vancouver to Valdez. That brings the cost to Valdes to $ 6.00 per bitumen barrel. Add 20c to transfer to a large tanker and the G7G railway savings over blended crude from Alberta via Burnaby will be $6.20 per barrel but could be less if only the largest allowable tankers are used

 https://oilprice.com/oil-price-charts shows  the June 7 & 8 2018 futures market prices as follows: WCS sold for $40.95, WTI $65.74 and Brent $76.46 That $ 24 difference between Alberta’s heavy sour and North America’s light sweet is easy to understand. Upgrading at Southern refineries costs $ 15 and transporting dilbit to the refineries can cost up to $20. The 11 Canadian blends ranged from $51.95 to $65.95. The 47 US oils traded at $49.99-$69.53 .  These are the blends which we have to watch carefully. http://business.financialpost.com/commodities/energy/canadian-crude-is-finding-a-new-way-to-asia-without-a-pipeline reports that Alberta crude has been exported to China via rail to Portland Oregon. That shows that we can be competitive. Previously crude oil arriving by train at the Columbia River was sent by tanker to Puget Sound. That most have been dilbit. See https://1bps6437gg8c169i0y1drtgz-wpengine.netdna-ssl.com/wp-content/uploads/2017/legacy/Tar_Sands_Report.pdf

 I have not been able to find prices on the Shanghai Futures Exchange (ShFE). but it may be a help for Canada. I also don’t know if there is still that much difference as reported by Dogwood 2 years ago: “In 2016, Asian refineries paid even less than U.S. refineries for comparable blends of heavy crude – as much as eight dollars less per barrel.” I. The price difference between our oil and that of the US is well expressed in http://www.oilsandsmagazine.com/news/2015/12/26/how-much-for-that-heavy-oil which states: “Shipping crude oil from Mexico or the Middle-East to the US by tanker is only a few dollars a barrel. Shipping oil from Alberta to the Gulf Coast by rail or pipeline ranges from $10 to $20/bbl”.

 A lot has been written about the ShFE https://www.brookings.edu/blog/order-from-chaos/2018/04/19/chinas-currency-displacing-the-dollar-in-global-oil-trade-dont-count-on-it/On March 26 2018, China launched crude oil futures contracts priced in renminbi (RMB) on the Shanghai International Energy Exchange. These contracts are the first RMB-denominated futures that foreigners can directly buy and sell. https://www.reuters.com/article/us-china-oil-futures-explainer/china-aims-to-challenge-brent-wti-oil-with-crude-futures-launch-idUSKBN1GY0S9 States: “The launch of China’s yuan-denominated oil futures will mark the culmination of a decade-long push by the Shanghai Futures Exchange (ShFE) aimed at giving the world’s largest energy consumer more power in pricing crude sold to Asia”. Replacing the US dollar gives some problems as noted by https://www.brookings.edu/blog/order-from-chaos/2018/04/19/chinas-currency-displacing-the-dollar-in-global-oil-trade-dont-count-on-it/“China will need to liberalize its financial markets and its capital account. In practice this means allowing foreigners to easily buy Chinese stocks and bonds and to move money in and out of the country as needed.  Given the large debt overhang that has developed in China, opening its capital account quickly would in fact be risky”. “An additional challenge to RMB as a trading currency for oil is that several important oil and gas producers in the Middle East have currencies pegged to the U.S. dollar, including Saudi Arabia, the United Arab Emirates, Oman, and Qatar. Kuwait’s currency is pegged to a basket of currencies dominated by the dollar. These pegs came about to provide stability to oil-producing countries when the United States was the world’s largest oil importer. Recent low oil prices challenged the pegs, as economic growth in the United States led to gradually increasing interest rates at the same time that oil revenues for the oil-producing countries were declining, arguing for lower interest rates in those countries. Despite this challenge, the pegs held and rising oil prices have improved fiscal conditions in the producing countries”

The export of dilbit to the US via the TM pipeline has gone on for quite some time and the people in the Anacortes area are quite upset about the dangers involved. As reported in http://vancouversun.com/news/local-news/washington-state-officials-very-concerned-canadas-oil-pipeline-spill-plan-lacking

“Canada’s approval of Kinder Morgan’s Trans Mountain pipeline is raising concerns with Washington State officials, who say they have not received adequate assurances that U.S. waters will be protected in the event of an oil tanker spill.” “I think quite frankly this is a Canadian oil industry project and to think that they can buy the social licence of Canadians by putting U.S. waters at greater risk is wholly irresponsible and will be vehemently fought,”

shows that Whatcom County has imposed a temporary moratorium on all projects that will increase the Puget Sound tanker traffic. https://earther.com/canadian-oil-pipeline-could-drive-famous-puget-sound-wh-1826860189

notes that there is a chance the local Orca whale population will become extinct by adding 360 tanker exits per year. compared to the present 40. These Orcas feed in the same channels and eat less with so much extra sound.

Meantime it is clear that the twinning will help exporting to the 5 refineries in the Anacortes Ferndale area. http://www.oilsandsmagazine.com/news/2016/3/03/why-vancouver-desperately-needs-a-new-oil-refinery reports that following closing of BC refineries we now import 70% of our gasoline and 60% of our jet fuel from the Puget Sound area in Washington. That is where most of the TMX oil will go. The Puget Sound line, which branches from the Trans Mountain line before Burnaby can carry at the moment 240,000 bpd which is 80% of the present TM volume. According to http://www.sightline.org/2017/06/05/an-oil-pipeline-expansion-in-washington/“The Puget Sound pipeline is capable of being expanded to increase its capacity to approximately 500,000 bpd from its current capacity of 240,000 bpd.” Twinning will bring the total capacity to 890,000 bpd. If 500,000 goes to Puget Sound and 50, 000 is refined at Burnaby while according to www.timescolonist.com/.../key-facts-about-the-trans-mountain-pipeline-expansion-1.2

15% ( 45,000 bpd} is delivered as refined products, 295,000 bpd will still be exported to California apart from the 400 tankers per year from Puget sound

Further data about the Auterra oils are shown in picture 61 below the references

Picture 29 has been updated to reflect transport of heavy crude blends rather than neatbit (pictures 60-62) The original Mid Canada Corridor was a concept developed by Canadian Major-General Richard Rohmer. It would create an East West belt, well away from the US with a railway at its spine. Rohmer convened a conference of 150 business, political leaders and advocates to discuss how the North would be developed A large Engineering company provided many maps and reports on the technical aspect, mining and forest resource locations, soil conditions, climate aspects and significance for First Nations. When Rohmer presented the final report to prime minister Pierre Trudeau at Rideau Hall in 1971, it was refused virtually on the spot. The meeting continued, with Trudeau responding to Rohmer’s arguments with indifference. Leaving Rideau Hall to go to question period, Trudeau was still “testy and agitated”.

In 2017 the Senate submitted a new version of the Corridor which includes a link to the Arctic. This time a new PM, Justin Trudeau reacted completely different than his father. He endorsed the report, clearing it for adaptation. Picture 63 shows some aspects of the new report but here are some quotes from a 25 October article in the Yukon News to show how important the MCC was to those who studied it:

Great national efforts left their mark the late 1960s, and for decorated Canadian Major-General Richard Rohmer, the changing atmosphere of the 1960s was just what was needed for his expanding plan to move the country North.

“The development corridor, as it is envisioned, is a belt that traverses Canada through its mid-North and northern regions, with a railway as its spine,” read a 1967 introductory pamphlet.

“Within this belt will grow new towns, new industries, new highways, enlarged ocean ports, new agricultural areas and a new transportation grid for the whole of Canada,” it said.

In 1969, Rohmer convened a conference of 150 business, political leaders and advocates to discuss how the North would be developed, what needed to be done, and the imperative of doing it soon.

As it planned the future, the conference was determined to “avoid the mistakes of the past — the degradation and exploitation of the true native Canadian peoples, wanton pollution of air and water and indiscriminate destruction of the only pure, virtually untouched region on this continent,” wrote Rohmer in 1970.

In a country where First Nations had only received the vote nine years previously, the conference was remarkable for its close involvement and consultation with First Nations peoples. “If we, the white men, who are so impatient to get out the wealth and tame the area, cannot devise ways to involve our native brethren, then we had better stay away until we can,” said a conference participant.

Not shown in the Yukon News is that Acres, a large engineering company did 2 years of work, preparing maps of mining, forestry and First Nations interest. Also maps about climate, soil conditions and proximity to existing railheads. They also prepared a lengthy complementary report. To no avail

“I think that he thought at the time that I was a Conservative, and that anything we were doing was not worth looking at,” said Rohmer. The meeting continued, with Trudeau responding to Rohmer’s arguments with indifference.

Leaving Rideau Hall to go to question period, Trudeau was still “testy and agitated,” wrote Rohmer.


The carbon tax problems

So many environmental problems can be solved with a global revenue neutral carbon tax. It would allow people and businesses to decide how to spend their refunds on green projects and make above average gains.  Via a carbon export tax an international fund could pay for CCU and green hydrogen power on a per tonne basis. The costs of wind and solar power are already about equal to fossil fuel but, as shown in picture 21 J, CCU is essential. Picture 25 K shows 4 different modern carbon capture plants.  Picture 33 M gives an excellent example of CO2 utilization. Picture 49 P shows how much can be achieved with green hydrogen.

I started reading and recording articles from the US Carbon Tax Center and saw in 2013 that the US had a number of carbon pricing bills. I only looked closer at the Waxman Markey bill, designed to meet the Copenhagen commitment and the Sanders Boxer bill, which is a carbon tax bill. At the same time the BC had its revenue neutral bill. Both the Waxman Markey and the BC bill were contested by powerful organizations, producing completely wrong figures how it would affect families by leaving out all the refunds. It is all detailed in post 1 and we still live with the problem. Post 3 shows how much export tax BC could raise when we don’t export our carbon for free. Post 9 reports the losses endured by the European rejection of the Northern Gateway. It was not only about the lack of carbon tax but also the unfair subsidies. When in London, Mr Harper was met by 40 protests groups while 6 MPs signed motions to keep Alberta oil put of Europe.  Post 10 stresses again that without taxing, demand for oil will keep rising. We don’t have to cut our production and give our share to others creating the same amount of GHG but hope for a global decline. Post 12 shows that 3 major oil companies demand a global carbon tax because with their vast natural gas reserves they can kill the coal industry. The second part analyses a speech, which the Canadian MP, Mr. Leef gave in the house, showing that he has no idea how a revenue neutral carbon tax works and that there are no MPs which can give him the correct figures on the spot. Post 19 and points F), G) and H in post 27 again show all the advantages of taxing carbon via a revenue neutral system. Points 1-7 in post 30 show how close the US can come to a global tax. Their proposed $40 tax forces countries with a lesser tax to pay import duties. China is a main target. Since all money raised will go to citizens, they shut out industries because those already will receive tax cuts. It is clear that illegal immigrants don’t get any refund. Of the 11 million illegal people 8 million work. That is 5% of the total labor force. So, it is not revenue neutral but raises the standard of living of working people.

While the BC carbon tax was revenue neutral and used as an example by other countries, dangerous flaws have occurred. I have often tweeted picture 37 in reply to tweets from others. Just recently one tweeter referred to a Globe and Mail article (61) showing that pre-existing subsidies like those to the film industry and interactive digital media had been sneaked in as carbon tax refunds. Worse yet, the present provincial budget appears to scrap the law that all tax collected has to be refunded to businesses and individuals who paid for it. A few days later I got from another tweeter the Financial Post article (62) with a similar stora including figures and a graph to show how bad it is. Please, let’s tell the government to restore our original system.

When Mr. Trudeau agreed in Paris to start taxing carbon he should in the national interest have made it a national revenue neutral carbon tax. By leaving it to the provinces we are faced with a hodgepodge of cap and trade, specific environmental projects and an array of subsidies for items like cars or solar panels, which are not necessarily what individuals want to spend their refunds on. We hope that it will result in prevention of excessive global warming.































PS March 22 2018
Since I published post 31 I added 5 more pictures with references. They don’t need any further explanation. Here they are