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Traders Look To Store Diesel At Sea As Second Wave Hits Demand | OilPrice.com

Hey, anybody wanna buy a tanker load of diesel?

Covid could stall demand in Europe. The is bad for crude demand, but refiner margins have got to be sucking right now.
You're certainly welcome to join me on the tanker train, plenty of seats available! Frontline(FRO) currently sitting at a fresh 52 week low!

Dividends continue, but the SP is down to nothing. I guess no one sees any medium term value in this tanker/storage dynamic. Holding strong til at least Groundhog Day to see how she goes.

Meanwhile....I was chatting with some US Virgin Islanders and it seems the giant refinery operator in St Croix is literally refusing to open after refurbishment. BP threatening to pull their supply deal if they don't open by year-end. Ugly out there in the refinery sector.
 
Thanks. Modeling is pretty powerful way to understand system trade offs. I tried to build the simplest model that would provide some insight. I downloaded demand data and solar production from California ISO (caiso.com). This data is available for 1 hour time periods. I used a presimulation period of 3 months to preload the storage and then the main simulation was for 1 year where I measure what percentage of power is provided over that year. I reran the simulation for different sizes of solar and storage.

My most recent run uses demand data from San Diego (SDGE) and solar production data from southern california (SP15 region in the data set) with the main simulation period from Apr 2019 to Mar 2020. For that I see results that look like this:

solar:100% 0h:43.7 4h:59.6 8h:74.0 12h:83.8 16h:85.6 20h:86.0 24h:86.3 50h:87.2 100h:88.0
solar:150% 0h:45.7 4h:62.0 8h:77.9 12h:91.3 16h:95.2 20h:95.5 24h:95.7 50h:96.2 100h:96.7
solar:200% 0h:46.9 4h:63.4 8h:79.6 12h:93.1 16h:97.4 20h:97.9 24h:98.2 50h:98.9 100h:99.4
solar:300% 0h:48.4 4h:65.0 8h:81.4 12h:94.8 16h:98.8 20h:99.2 24h:99.4 50h:99.9 100h:100
solar:400% 0h:49.3 4h:65.9 8h:82.4 12h:95.6 16h:99.3 20h:99.5 24h:99.7 50h:100 100h:100

This table summarizes 45 simulation runs with a matrix of different sized solar production and battery storage. To read this chart, each line shows different amounts of solar production from 100% of annual demand (0% over capacity) to 400% of annual demand (300% over capacity). Across each line, I show different size batteries, "0h" = no battery, "4h" = 4 hours of battery, where 4 hours is relative to annual demand (annual demand / 365days / 24h * 4h).

From this chart, you can see (on the second line, 5th result) that 150% solar (50% over capacity) plus 16 hours of storage covers 95.2% of demand. I think this will be a cost competitive system in the next few years.

A few caveats: 1) in a real system, demand response and pricing signals will shape the demand to better match with generation, which makes this model pessimistic. 2) a single year simulation doesn't capture annual variation and rare events, which makes this model optimistic.
 
Welcome to our thread. Tell us about your model. I'm interested in how you get to 95%.

My own view on hydrogen is that before it gets used for generating power, we will want it to supply the heating and industrial gases markets. So this gets the electrolyzer fleet to a multi TW scale. At that scale a lot of the seasonal balancing needed for ordinary power consumption will be provided by curtailing electrolyzer production. This would mitigate the need for long-term electricity storage, albeit non-power gas markets will need long-term storage. A caveat here is that not all regions will be economical producers of hydrogen, so there is some scope for an export market. Net hydrogen importers may well generate power from hydrogen, but net exporters not so much.

One thing I don't get about hydrogen - how easy/hard is it to convert hydrogen gas to methane or something that's usable as an energy store, without being so damned hard to keep in one place or is as explosive? I'm thinking here of an electrolysis process to turn energy into hydrogen, and then turn the hydrogen into methane (my limited understanding of chemistry has methane as the obvious target).

I guess this isn't the good way to go, as we need hydrogen for fuel cells to convert the hydrogen back into energy, where methane just won't do.


Hmph.


I think it's time for me to do some research on bulk and long term storage of hydrogen, whether as gas or liquid. The bits I've read about hydrogen in mobile applications is that it is slippery - it's hard to keep in the storage vessel, it breaks down the vessel over time, it (probably) eats seals, and so forth.

Clearly there is some degree of solution to this at industrial scale. Do we just manufacture and use the gas when needed (would kind of make sense to me). If anybody already knows some of the answers to these questions or where to find them, please share.
 
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My own view on hydrogen is that before it gets used for generating power, we will want it to supply the heating and industrial gases markets. So this gets the electrolyzer fleet to a multi TW scale. At that scale a lot of the seasonal balancing needed for ordinary power consumption will be provided by curtailing electrolyzer production. This would mitigate the need for long-term electricity storage, albeit non-power gas markets will need long-term storage. A caveat here is that not all regions will be economical producers of hydrogen, so there is some scope for an export market. Net hydrogen importers may well generate power from hydrogen, but net exporters not so much.

My model shows 150% solar + 16 hours storage can cover 95.2% of electricity. One way to model this effect of large electrolyzers that can be curtailed on demand is that you effectively have additional solar power at the same price point. So instead of 150% solar power maybe you get 300% solar power at same cost. My model shows 300% solar + 16 hours storage covers 98.8% of electricity. For this case you would still want long duration storage to cover the remaining amount if your goal is 100% renewable electricity.

Not clear to me how much demand there is for industrial hydrogen. In theory if the demand is high enough it might offset the need for long duration storage. However you aren't simply doing seasonal balancing. You are also covering short periods (days) of extremely low solar production.
 
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My model shows 150% solar + 16 hours storage can cover 95.2% of electricity. One way to model this effect of large electrolyzers that can be curtailed on demand is that you effectively have additional solar power at the same price point. So instead of 150% solar power maybe you get 300% solar power at same cost. My model shows 300% solar + 16 hours storage covers 98.8% of electricity. For this case you would still want long duration storage to cover the remaining amount if your goal is 100% renewable electricity.

Not clear to me how much demand there is for industrial hydrogen. In theory if the demand is high enough it might offset the need for long duration storage. However you aren't simply doing seasonal balancing. You are also covering short periods (days) of extremely low solar production.

What happens if you combine wind resources to your model? Low solar is usually associated with a period of high wind (which are generated by rapid temperature changes and its resultant air movement), so that should supplement/complement the supply of electricity from solar and reduce the storage needs and still cover most electricity needs (SWAG'ing this claim).
 
...My most recent run uses demand data from San Diego (SDGE) and solar production data from southern california (SP15 region in the data set) ... 150% solar (50% over capacity) plus 16 hours of storage covers 95.2% of demand. I think this will be a cost competitive system in the next few years.

A few caveats: 1) in a real system, demand response and pricing signals will shape the demand to better match with generation, which makes this model pessimistic. 2) a single year simulation doesn't capture annual variation and rare events, which makes this model optimistic.
Would add further caveats of extrapolating into colder climates (including rest of CA) and that the future of heating is heat pumps wherein winter electricity demand is much higher but winter seasonal shortfall of solar PV generation remains. The average energy use in the U.S. for heating is substantially higher than cooling.

Would be interesting to know what overcapacity of solar PV plus hours of storage would be needed in CA to run a scenario where NG heating is gone and heat pumps instead heat air and water.
 
What happens if you combine wind resources to your model? Low solar is usually associated with a period of high wind (which are generated by rapid temperature changes and its resultant air movement), so that should supplement/complement the supply of electricity from solar and reduce the storage needs and still cover most electricity needs (SWAG'ing this claim).

I did some wind modeling for California a long time ago, but stopped modeling it for various reasons. 1) California has excellent solar resources and mediocre wind resources. 2) The best wind locations in California have already been built out, so hard to model what happens if you try to build more and not clear how much more is possible. You generally need overcapacity on the generation side so you would want a lot more wind turbines to have a major impact. 3) building out wind resources would require new transmission lines and it isn't clear how quickly that could be done, if ever. NIMBY kills many transmission projects. Solar doesn't have the same geographic restrictions and seems more feasible for a quick ramp 4) solar+storage complements each other very well. Adding wind doesn't (likely) get you to 100%, so you still need long duration storage for reliable power. For getting to 95%, solar + li ion storage is probably the cheapest option 5) There are real world systems running off grid in california using solar + battery storage (plus a backup generator for reliability), so the general concept of a high penetration solar+storage system has been proven. 6) solar prices are dropping faster than wind prices

That said I'm not against wind, but in the sunny desert southwest it is not required. If you want to model it, please do.
 
Would add further caveats of extrapolating into colder climates (including rest of CA) and that the future of heating is heat pumps wherein winter electricity demand is much higher but winter seasonal shortfall of solar PV generation remains. The average energy use in the U.S. for heating is substantially higher than cooling.

Would be interesting to know what overcapacity of solar PV plus hours of storage would be needed in CA to run a scenario where NG heating is gone and heat pumps instead heat air and water.

Good point about the future grid supplying more winter heat. A future grid will power more EVs and we tend to drive less during the winter, so that helps. A heat pump is maybe 3x more efficient than fossil fuel heat, that helps some but even so it looks like it we will still use more energy for heating than cooling across the whole country. Maybe not in desert southwest. Obviously you would not use a 100% solar system in the northern US.
 
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You're certainly welcome to join me on the tanker train, plenty of seats available! Frontline(FRO) currently sitting at a fresh 52 week low!

Dividends continue, but the SP is down to nothing. I guess no one sees any medium term value in this tanker/storage dynamic. Holding strong til at least Groundhog Day to see how she goes.

Meanwhile....I was chatting with some US Virgin Islanders and it seems the giant refinery operator in St Croix is literally refusing to open after refurbishment. BP threatening to pull their supply deal if they don't open by year-end. Ugly out there in the refinery sector.
Can I re-arrange the deck chairs or organize a shuffleboard tournament?

LAeWh-1518044088-481-quiz_question_image_-8_late_cast_members_judy_mccoy_love_boat.png
 
Reality dawns on oil industry (slowly)

Rystad Revises Peak Oil Demand Forecast

The company now sees global oil demand peaking at 102 million barrels per day (MMbpd) in 2028 as the most likely scenario. Before Covid-19, Rystad Energy was forecasting that peak oil demand of just over 106 MMbpd would be realized in 2030.

According to Rystad Energy, the persistence of the pandemic is likely to cause 2020 oil demand to decline to 89.3 MMbpd, compared to 99.6 MMbpd in 2019. Demand is then expected to recover to 94.8 MMbpd in 2021 and 98.4 MMbpd in 2022, Rystad Energy outlined, adding that it will still be stuck below pre-virus levels due to structural Covid-19 impacts, such as less work commuting and slower aviation recovery. The company says it is only in 2023 that oil demand will recover to pre-Covid-19 levels and jump back to 100.1 MMbpd.
 
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My model shows 150% solar + 16 hours storage can cover 95.2% of electricity. One way to model this effect of large electrolyzers that can be curtailed on demand is that you effectively have additional solar power at the same price point. So instead of 150% solar power maybe you get 300% solar power at same cost. My model shows 300% solar + 16 hours storage covers 98.8% of electricity. For this case you would still want long duration storage to cover the remaining amount if your goal is 100% renewable electricity.

Not clear to me how much demand there is for industrial hydrogen. In theory if the demand is high enough it might offset the need for long duration storage. However you aren't simply doing seasonal balancing. You are also covering short periods (days) of extremely low solar production.

I haven't explicitly modeled the relationship but my view on solar, for most of the world, is the same - over build the solar, add some storage, and you can get close to full replacement of fossil fuels in the electric grid.

The challenge I see, and it is purely anecdotal, though I also believe directionally accurate, is that solar isn't well distributed over the seasons. Closer to the equator - good. In the US, CA and AZ for instance - I don't live there but I expect winter solar is still pretty good.


As a point of comparison, I have a 10kw solar system on my house in the Portland, OR area. Our winter days are both short and cloudy. As a result, I routinely see 60 kWh production on summer days and even a few days of just over 70 kWh. Anything under 50 kWh is outstandingly bad for the summer, but it does happen.

The winter days though are routinely closer to 5 kWh. Days at sub 1 kWh aren't common, but they also aren't as rare as those 70 kWh days (not by a long short). Running Oregon, or at least the Portland, OR area off of solar, will require that the energy be imported. I don't know if Easter Oregon could act as Portland's generator - I don't know that area well enough. I expect significantly less clouds over the winter, but it's still as close to the pole, so days are short.


This same dynamic, but even more extreme will affect places that are farther north.


I do think we'll still get there; this isn't intended as an argument against. A purely solar grid though needs to be built around these more extreme circumstances. Using my particular situation as an example, it looks like a minimum of 1000% (10x) is needed, and it might be closer to 60x (I don't really believe it's that high).

On the plus side, all that over built solar (and as mentioned elsewhere - wind) will provide for a lot of excess power most of the time. That is going to create new economic activity that we can't fully imagine or design today. The world has never had that over abundance of energy at any point in history, any more than the world has had anything like the level of communication the internet provides today. We're still learning what to do with this abundance, and soon we'll be trying to figure out what to do with all of that abundance of energy (I can't wait to see what we do!)
 
Thanks. Modeling is pretty powerful way to understand system trade offs. I tried to build the simplest model that would provide some insight. I downloaded demand data and solar production from California ISO (caiso.com). This data is available for 1 hour time periods. I used a presimulation period of 3 months to preload the storage and then the main simulation was for 1 year where I measure what percentage of power is provided over that year. I reran the simulation for different sizes of solar and storage.

My most recent run uses demand data from San Diego (SDGE) and solar production data from southern california (SP15 region in the data set) with the main simulation period from Apr 2019 to Mar 2020. For that I see results that look like this:

solar:100% 0h:43.7 4h:59.6 8h:74.0 12h:83.8 16h:85.6 20h:86.0 24h:86.3 50h:87.2 100h:88.0
solar:150% 0h:45.7 4h:62.0 8h:77.9 12h:91.3 16h:95.2 20h:95.5 24h:95.7 50h:96.2 100h:96.7
solar:200% 0h:46.9 4h:63.4 8h:79.6 12h:93.1 16h:97.4 20h:97.9 24h:98.2 50h:98.9 100h:99.4
solar:300% 0h:48.4 4h:65.0 8h:81.4 12h:94.8 16h:98.8 20h:99.2 24h:99.4 50h:99.9 100h:100
solar:400% 0h:49.3 4h:65.9 8h:82.4 12h:95.6 16h:99.3 20h:99.5 24h:99.7 50h:100 100h:100

This table summarizes 45 simulation runs with a matrix of different sized solar production and battery storage. To read this chart, each line shows different amounts of solar production from 100% of annual demand (0% over capacity) to 400% of annual demand (300% over capacity). Across each line, I show different size batteries, "0h" = no battery, "4h" = 4 hours of battery, where 4 hours is relative to annual demand (annual demand / 365days / 24h * 4h).

From this chart, you can see (on the second line, 5th result) that 150% solar (50% over capacity) plus 16 hours of storage covers 95.2% of demand. I think this will be a cost competitive system in the next few years.

A few caveats: 1) in a real system, demand response and pricing signals will shape the demand to better match with generation, which makes this model pessimistic. 2) a single year simulation doesn't capture annual variation and rare events, which makes this model optimistic.
Nice! I used to play with the CAISO data. I was generally looking net demand for fossil generation (total demand less clean generation), and sizing up adding incremental solar, wind and batteries to meet this net demand. I found that generally around 4 hours of battery would make a pretty substantial impact on resolving net demand. This was several years back, so I'm sure the mix has changed. This sort of analysis is obviously dependent on the current generation mix to determine net demand. So it is a bit limited in that regard.

One direction you may wish to explore is adding in electrolyzer capacity. When solar is at 150%, there should be quite a number of days with surplus power. There have been some studies suggest that having RE at 150% to 200% plus 6-8h batteries and electrolyzers make for the lowest cost mix. One other point, wind does help complement solar. So a mix of both can reduce need for hours of batteries and improve the utilization of electrolyzer.

BWT, longer-term the capex of electrolyzer capacity could fall below $300/kW. Using this capacity at 30% to 60% CF to balance the grid is not a bad deal compared to spending around $900/kW for a gas powered plant that runs in the same CF range. Economically balancing the grid is about finding a lower cost mix of capital assets that sit idle waiting for occasional use. Electrolyzers have the ability to increase the capital efficiency of solar, wind and battery assets by providing dispatchable (or price-responsive) load to support power prices. A gas generator cannot help the economics of a grid at times of surplus. Pushing RE to 150% level and beyond means gas generator capacity will have very low utilization, making it exceedingly expensive capacity. Also as your results above show, increasing battery storage capacity above 16h has almost no incremental value. Or increasing solar from 150% to 200% has almost no incremental value (holding storage at 16h). So getting that last 5% of power generation (for on demand consumption) is very costly.

If the last 50% of RE is matched with the same capacity of electrolyzers, then you capture maybe about 30% (= 50% surplus * 80% availability of surplus * 70% electrolyzer efficiency) as hydrogen. Gas generation to supply the final 5% only needs to consume about half of the hydrogen. Or if the full amount of hydrogen offsets natural gas used for heat, the use of NG for generation is netted out twice over. So in effect grid at 150% RE can net out at 115% renewable after consuming NG for 5% generation but producing 30% hydrogen. That is, the grid can become net negative carbon emissions by becoming a net producer of gas. This net production helps to optimize capital efficiency, while solving climate change more broadly.

Keep us posted on anything you discover!
 
One thing I don't get about hydrogen - how easy/hard is it to convert hydrogen gas to methane or something that's usable as an energy store, without being so damned hard to keep in one place or is as explosive? I'm thinking here of an electrolysis process to turn energy into hydrogen, and then turn the hydrogen into methane (my limited understanding of chemistry has methane as the obvious target).

I guess this isn't the good way to go, as we need hydrogen for fuel cells to convert the hydrogen back into energy, where methane just won't do.


Hmph.


I think it's time for me to do some research on bulk and long term storage of hydrogen, whether as gas or liquid. The bits I've read about hydrogen in mobile applications is that it is slippery - it's hard to keep in the storage vessel, it breaks down the vessel over time, it (probably) eats seals, and so forth.

Clearly there is some degree of solution to this at industrial scale. Do we just manufacture and use the gas when needed (would kind of make sense to me). If anybody already knows some of the answers to these questions or where to find them, please share.
Yeah, there are a lot of questions here. Any transformation of hydrogen into something else adds cost and consumes energy. But as long as we are transforming methane into hydrogen, there is little need to convert hydrogen in to methane. So the bigger question is how long will we continue SMR of natural gas. Could be many decades.
 
Aramco made $12.4B in 3Q20.....and paid out it's $18.75B dividend. Things should definitely get better in 2022 though.

Any guesses on how long this can last? Payoffs to the populace must be way down, gotta think there will be some unrest in the spring.

Bloomberg - Are you a robot?

Saudi Aramco left its third-quarter dividend unchanged at $18.75 billion even as it failed to generate enough cash to cover the payout and reported a 45% drop in profit.

The world’s biggest oil company generated free cash flow of $12.4 billion between July and September, down from $20.6 billion a year earlier as coronavirus lockdowns hit demand for energy and refining margins.
Net income at the state energy firm was 44.2 billion riyals ($11.8 billion), slightly ahead of analysts’ expectations. Gearing climbed to 21.8% from 20% in June and from minus 5% in March, when Aramco had more cash than debt.

Aramco’s shares closed 0.6% higher at 34.40 riyals in Riyadh, paring this year’s drop to 2.4%. The stock has been bolstered by management’s pledge to pay a $75 billion dividend annually for five years after the completion of last December’s initial public offering.

That promise, along with a $69 billion acquisition of chemicals maker Saudi Basic Industries Corp., has seen debt levels balloon even with Aramco cutting capital expenditure and laying-off hundreds of foreign workers. Net debt rose $6 billion to $83 billion by the end of the third quarter, putting the company even further from its gearing target of between 5% and 15%.

Aramco may have to take on more debt to fund the dividend payments given its slumping cash flow. It drew down a $10 billion loan in late July. That revolving credit facility matures in May 2021, though it can be extended for another year.

Downstream was even worse than their crude business and there's no real hope in sight for fat margins. Working through this global glut might take us all the way through 2022, and that's if OPEC+ cooperates.

The clock is ticking. This spring should be very interesting in the kingdom. I expect BIG moves, like removing all OPEC limits to flood the US and multinationals out of the market.
 
IRunning Oregon, or at least the Portland, OR area off of solar, will require that the energy be imported.

Portland is 45deg north. San Diego is 33deg north. The average world population lives 24 degree from the equator (to account for southern hemisphere). So solar will dominate for much of the world without necessarily dominating in the northern US. Portland has hydro and wind and a big transmission line to CA, designed for exporting hydro power, but useful in the future for importing solar. Fortunately most cloudy places have hydro or wind power available and a renewable energy system designed for the Pacific NW will be much different than one designed the desert southwest. In fact Yuma, AZ which is on the California border is the sunniest city in the world by hours of sunlight, so it is a very very favorable climate for solar power.

I would loosely divide the US in to 6 regions southwest, south central, southeast, northwest, north central, and north east. Each one will require a different strategy to switch to renewable energy. Northwest has major hydro power resources and some wind. North central has lots of wind. Northeast has lots of off shore wind. Southeast will be mostly solar. Southcentral with be wind/solar mix. Southwest has abundant sunshine.
 
My model shows 150% solar + 16 hours storage can cover 95.2% of electricity. One way to model this effect of large electrolyzers that can be curtailed on demand is that you effectively have additional solar power at the same price point. So instead of 150% solar power maybe you get 300% solar power at same cost. My model shows 300% solar + 16 hours storage covers 98.8% of electricity. For this case you would still want long duration storage to cover the remaining amount if your goal is 100% renewable electricity.

Not clear to me how much demand there is for industrial hydrogen. In theory if the demand is high enough it might offset the need for long duration storage. However you aren't simply doing seasonal balancing. You are also covering short periods (days) of extremely low solar production.
Industrial uses include steel making, ammonia production, and other petrochem.

To get a sense of the scale consider replacing all of natural gas with hydrogen on an energy basis. Last year gas production was 144EJ or about 40k TWh. About 17.5k TWh was used to produce 6300 TWh of electricity, so WSB can replace this portion. What is left over is 22.5k TWh of gas not used for power. Electrolysis is about 70% efficient, so replacing 22.5k TWh gas with hydrogen call for about 32k TWh of electricity. In 2019 total power generation was 27k TWh. Thus, we are looking at expanding power generation by about 120%.

Average global generation is about 3.1TW to generate 27k TWh in a year. This nearly 12TW of solar and wind. But to include electrolysis, we'd need to generate 59k TWh. This would call for about 27 TW of solar & wind (conservative average 25% CF), 25 TWh battery storage (8h), and 15 TW electrolyzers (25% CF). The point here that this sort of transformation just to replace the natural gas consumption while decarbonizing the grid is huge. What is excluded is replacing oil and coal not used for power. Of course, there are some efficiencies like replacing gas heat with electric heat pumps, which reduce the amount of hydrogen needed to replace natural gas. I'm also ignoring growth in energy demand over the next few decade. All told, I think global grid gets 4 to 5 times larger in a couple of decades.
 
Portland is 45deg north. San Diego is 33deg north. The average world population lives 24 degree from the equator (to account for southern hemisphere). So solar will dominate for much of the world without necessarily dominating in the northern US.
Interesting, I had not heard the 24 degree average before. It is helpful for trying to imagine how the industrial geography will change long-term in response to solar becoming the cheapest energy source in the world. Will we see high energy industries migrate closer to the equator? Will we see more economic activity move toward the equator? Political obstacles notwithstanding, it seems this could be possible.
 
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