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17 hours ago, ronwagn said:

I am just going by all the posts we have had about shale oil running out in a decade, or so, I didn't write any of it and don't think it will happen that soon. Also, we could be importing but we are burning off natural gas to use what we have. I hate that, so I keep trying to get people to act rationally in the interest of all of us. 

I hadn't seen the posts about shale oil running out but, like you, I'd be wary.. my understanding is that shale oil wells, by their nature, don't send very long in one place.. but anyway.. I will go one step further and ask what's the objection to using natural gas rather than import? Its a market thing and there's plenty of gas.. 

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On 1/10/2020 at 12:49 PM, 0R0 said:

 

Thanks again, Comparing the two charts, the median seems to be 85k for 2010-2018, and 95k for 2015-2018. So it isn't showing a decrease trend (yet) in the overall stats. A mild decreasing trend in Niobrara and Eagle Ford isn't terribly worrisome for me yet as they are smaller formations and have less child well problems. . Still in line with Gautreau's charts of annual initial productions for the shale play as a whole still increasing. From what you told us, the length adjusted 12 mo. initial EUR is possibly starting a downtrend, but in any case not showing improvement since 2016 or 2017. ..

Note that the increase is due to both increasing average lateral length, increaseing numbers of frack stages per lateral foot, and higher levels of proppant per lateral foot, productivity per lateral foot may have increased a bit from 2010 to 2016 as the well setup was optimized, since 2016 the output per well has been flat when normalized for lateral length (output per foot of lateral) for Permian and Bakken.  It is unclear how long that plateau can be maintained, at some point average new well productivity will decrease, probably within 2 or 3 years for the start of that decrease for Permian basin, and sooner for Bakken.

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Not really concerned with the increased intensity of fracs, since the cost of it has diminished rather than increase for the past few years. Which would imply continued production growth given similar price levels, unless EUR/ft drops rapidly, which you appear to expect some years forward.. 

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18 hours ago, 0R0 said:

Not really concerned with the increased intensity of fracs, since the cost of it has diminished rather than increase for the past few years. Which would imply continued production growth given similar price levels, unless EUR/ft drops rapidly, which you appear to expect some years forward.. 

The growth in production will depend on the price level, two scenarios below with low and medium price level (oil price scenario is read from right hand axis).  The medium scenario is more likely in my view, but if oil prices remain low as many on this board seem to believe, then tight oil output will not grow very much, if these two oil price scenarios bracket the real oil price going forward, then tight oil output might fall somewhere between these two scenarios.

tightscen2001.png

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6 minutes ago, D Coyne said:

The growth in production will depend on the price level, two scenarios below with low and medium price level (oil price scenario is read from right hand axis).  The medium scenario is more likely in my view, but if oil prices remain low as many on this board seem to believe, then tight oil output will not grow very much, if these two oil price scenarios bracket the real oil price going forward, then tight oil output might fall somewhere between these two scenarios.

tightscen2001.png

Great thinking on the price effects.

My thinking is that we have a huge energy cost differential between NG NGLs and Oil. In the realms where the difference is enormously large and a large chunk of costs - that is the near 30% of oil that goes to Marine Transport and Petrochem inputs. The business pressure on this spread is enormous and will cause mass migration as the infrastructure of bunkering LNG vessels around the planet fill that spread, and plants either move to the Ohio Valley and Permian to be supplied with NGLs, Oil demand will shrink relative to trend. While NG will rise. It will be similar to the decimation of coal in the US. 50% within half a decade is in the cards. I.e. ~13-15% of oil demand.

Beyond that, the pricing of NG and Oil should be coupled with a persistent discount to NG energy content. They will eventually rise gradually in tandem as depleting resources, So the supply and price relationships need to be calculated in tandem. The price plateaus are not really what you should expect in this arena, but a more gradual trend towards a cap..

The cap is set by the threshold cost of Solar to Methane/methanol/ethane/ethanol process. So far, the pilot programs in Denmark and Germany, and the Science in the US and engineering at Siemens are bringing down the threshold. While coming off the initial pilot program in the US, the projected cost estimate was $150 oil equiv. Bbl, That was 5 years ago. The cash cost analysis right now is about $70-80 oil. But capital cost is the stumbling block, You can run the capital at the natural supply level of Solar - i.e. 30% of the time, (similar with wind at 50-60% in the good corridors most of the year)  so you would need 3X the capital. Using battery storage you will still need double the capital unless battery tech becomes cheaper by 1/2 again, which would make it 1.5X capital and a realistic commercial investment. So the basic building blocks of the technology are already there, but the cost of capital is the major impediment. It is a more attractive proposition at ZIRP than at Baa not to speak of CCC interest rates. It is hard to get it to be a high grade credit project because the output pricing (NG) is so volatile.

But I will put a finger to the wind estimate of start up at $100/BO basis 2018 and a grind down in real costs once that threshold is breached - to $70/BO at 2018 dollars. Which will probably be a long term cap (barring a rare mineral catalyst supply problem)..

I think the Saudi's sale of Aramco (they continue selling shares after the IPO) is driven by their need to grab a part of the technology lead in hydrocarbon energy from solar/wind and participate in the NG displacement of oil's revenue stream. 

Is there any way you can combine the NG and Oil curves? 

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Oro 

You consistently seem to both identify and correctly analyze pertinent aspects in this ever evolving narrative of the 'energy world' and I am in close agreement with most of what you forsee.

To assist, perhaps, in your ongoing evaluations, I offer these ...

Check out the short 2018 presentation from NP Resources describing their work in the Elkhorn Field  if you wish to learn  why Tier 2/3 rock is producing so - relatively - well. Essentially, it is a summation of what scrappy, small operators are doing when they effectively implement many of the technologies described earlier throughout this thread.

Speaking of small and scrappy, an ultra ballsy Australian outfit - Australias - is drilling their 6th Tuscaloosa Marine Shale well. At vertical depths way over 17,000 feet, these guys deserve a freakin' medal.

The transition to gas lift and jet pump is continuing apace in the Bakken.

So much natgas - relatively speaking - is now being utilized onsite for both power and production purposes, that the ND DMR folks have started an additional classification to well production reports  ... 'gas flared'. This is alongside the 'gas produced' and 'gas sold' categories as the implied difference between produced/sold is no longer 100% flared. Economic/revenue/taxation issues are behind this more granular breakdown.

When Dennis and others make future hydrocarbon production projections, there has been (to my eye, anyway) an almost complete absence of forward looking technologies.

Long derided as "Cornicopian" views by the more pessimistically inclined, I would think the 13 million barrel per day current output might prompt some deep level introspection from the more skeptically inclined.

EOR will be a game changer.

More effective, economical artificial lift will enhance current production as well as increase economic attractiveness across all present and future plays.

As an aside - re US LNG production - week ending January 8 saw 19 vessels leave US ports with a capacity of 68 Bcf ... almost 10 Billion cubic feet per day.

Operational issues including retaining the heel would diminish the actual number somewhat, but ... still ... 10 Billion per day? Place that on your chart from a few days back for visual impact. 

End of the day, ORO, CNG will surpass LNG and gasoline/petrol for primary fuel for road transport as the rapid advances in the field of adsorption are already showing success.

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(edited)

23 hours ago, Coffeeguyzz said:

Oro 

You consistently seem to both identify and correctly analyze pertinent aspects in this ever evolving narrative of the 'energy world' and I am in close agreement with most of what you forsee.

To assist, perhaps, in your ongoing evaluations, I offer these ...

Check out the short 2018 presentation from NP Resources describing their work in the Elkhorn Field  if you wish to learn  why Tier 2/3 rock is producing so - relatively - well. Essentially, it is a summation of what scrappy, small operators are doing when they effectively implement many of the technologies described earlier throughout this thread.

Speaking of small and scrappy, an ultra ballsy Australian outfit - Australias - is drilling their 6th Tuscaloosa Marine Shale well. At vertical depths way over 17,000 feet, these guys deserve a freakin' medal.

The transition to gas lift and jet pump is continuing apace in the Bakken.

So much natgas - relatively speaking - is now being utilized onsite for both power and production purposes, that the ND DMR folks have started an additional classification to well production reports  ... 'gas flared'. This is alongside the 'gas produced' and 'gas sold' categories as the implied difference between produced/sold is no longer 100% flared. Economic/revenue/taxation issues are behind this more granular breakdown.

When Dennis and others make future hydrocarbon production projections, there has been (to my eye, anyway) an almost complete absence of forward looking technologies.

Long derided as "Cornicopian" views by the more pessimistically inclined, I would think the 13 million barrel per day current output might prompt some deep level introspection from the more skeptically inclined.

EOR will be a game changer.

More effective, economical artificial lift will enhance current production as well as increase economic attractiveness across all present and future plays.

As an aside - re US LNG production - week ending January 8 saw 19 vessels leave US ports with a capacity of 68 Bcf ... almost 10 Billion cubic feet per day.

Operational issues including retaining the heel would diminish the actual number somewhat, but ... still ... 10 Billion per day? Place that on your chart from a few days back for visual impact. 

End of the day, ORO, CNG will surpass LNG and gasoline/petrol for primary fuel for road transport as the rapid advances in the field of adsorption are already showing success.

Coffeeguyzz,

Further technological progress would simply reduce cost per barrel produced, there are already plenty of assumptions in my models, the technology assumption is really no different than an assumption of high prices.

I know you love technology, but generally the laws of physics and basic economic principles will rule the day.

For the past 3 years cumulative output per foot of lateral for tight oil plays has been on a plateau.  Perhaps there will be some technological breakthrough, a lot of the pie in the sky predictions will remain so.

0R0,

I have not done an in depth analysis of shale gas, but keep in mind that if the EUR of the average tight oil well falls below a level that is profitable at prevailing prices, the natural gas coming from tight oil wells will no longer be profitable to produce.  Also if the combination of EVs and natural gas reduce demand for oil then the low price scenario becomes more likely and leads to less profitability and less cumulative output from tight oil.  In addition, if consumption of natural gas starts to expand more quickly than production we may see rising natural gas prices, this in turn might lead to a reduction of demand for natural gas in the electric power sector, driving down natural gas prices eventually as PV and wind expand and achieve cost savings due to economies of scale,  In addition the sweet spots in shale gas plays will become fully drilled and eventually we will see new well EUR fall.  This is just geophysics in action, something that has occurred in every oil field ever discovered.

In a battle between technology and geophysics, my money is with the physics, every time.

Note that I include both natural gas and tight oil in my Permian basin analysis, though NGL revenue should also be included in the analysis.

I am unclear on this question:

Is there any way you can combine the NG and Oil curves? 

Edited by D Coyne

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22 hours ago, Coffeeguyzz said:

Oro 

You consistently seem to both identify and correctly analyze pertinent aspects in this ever evolving narrative of the 'energy world' and I am in close agreement with most of what you forsee.

To assist, perhaps, in your ongoing evaluations, I offer these ...

Check out the short 2018 presentation from NP Resources describing their work in the Elkhorn Field  if you wish to learn  why Tier 2/3 rock is producing so - relatively - well. Essentially, it is a summation of what scrappy, small operators are doing when they effectively implement many of the technologies described earlier throughout this thread.

Speaking of small and scrappy, an ultra ballsy Australian outfit - Australias - is drilling their 6th Tuscaloosa Marine Shale well. At vertical depths way over 17,000 feet, these guys deserve a freakin' medal.

The transition to gas lift and jet pump is continuing apace in the Bakken.

So much natgas - relatively speaking - is now being utilized onsite for both power and production purposes, that the ND DMR folks have started an additional classification to well production reports  ... 'gas flared'. This is alongside the 'gas produced' and 'gas sold' categories as the implied difference between produced/sold is no longer 100% flared. Economic/revenue/taxation issues are behind this more granular breakdown.

When Dennis and others make future hydrocarbon production projections, there has been (to my eye, anyway) an almost complete absence of forward looking technologies.

Long derided as "Cornicopian" views by the more pessimistically inclined, I would think the 13 million barrel per day current output might prompt some deep level introspection from the more skeptically inclined.

EOR will be a game changer.

More effective, economical artificial lift will enhance current production as well as increase economic attractiveness across all present and future plays.

As an aside - re US LNG production - week ending January 8 saw 19 vessels leave US ports with a capacity of 68 Bcf ... almost 10 Billion cubic feet per day.

Operational issues including retaining the heel would diminish the actual number somewhat, but ... still ... 10 Billion per day? Place that on your chart from a few days back for visual impact. 

End of the day, ORO, CNG will surpass LNG and gasoline/petrol for primary fuel for road transport as the rapid advances in the field of adsorption are already showing success.

Thanks Coffeeguyzz

I am a bit skeptical of CNG on adsorption media since they end up being bulky and are easily poisoned. Just one bad batch of contaminated NG will spoil the tank. So I will believe it when I see the successful use over time. It may not be an issue in practical use.

That LNG shipment volume is impressive, indicating a 40% growth in just a month or two. Would make an internet company jealous.

I am waiting to see EOR go from pilots and test wells to practical commercial production.

Thanks for the heads up. I was wondering if fields depleted of Tier 1 plays are being sold/sublet to smaller operators who can employ newer and riskier techniques on the tier 2 and 3 rock and come up with much better than projected output, as they don't need to prove them to the corporate office before applying them, and they are not putting high value rock at risk.

My perspective is economic and the spread between commodity costs coming out of the ground and the market value of the goods and services produced from them is essentially "the economy" which produces profits and wages along with tax revenue and thus capital formation. That means that intermediate and long term economic and financial forecasting is more about predicting forward commodity costs than about anything else but for demographically driven demand. 

Within the commodity world, price differentials are key and many in the industry seem detached from the competitive position of NG and NGLs as a displacing source of energy and carbon competing against oil for market share in heavy transportation, chemical feedstock etc.Aramco is obviously preparing for a world in which oil is not the cheapest transportation energy source and feedstock to use. Their hoped for depletion pricing for oil is rapidly becoming less and less likely and far smaller in scale. They are not divesting the lowest cost and largest oil supplies because they see a depletion, but because they see oil falling in market share and being restrained in pricing for the foreseeable future 

In the same timeframe, NG is also being pushed out by marginally economical renewables as when they are combined with battery storage essentially makes the cash cost nearly nothing - vs. the rather volatile and seasonal NG price. 

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6 minutes ago, D Coyne said:

Coffeeguyzz,

Further technological progress would simply reduce cost per barrel produced, there are already plenty of assumptions in my models, the technology assumption is really no different than an assumption of high prices.

I know you love technology, but generally the laws of physics and basic economic principles will rule the day.

For the past 3 years cumulative output per foot of lateral for tight oil plays has been on a plateau.  Perhaps there will be some technological breakthrough, a lot of the pie in the sky predictions will remain so.

0R0,

I have not done an in depth analysis of shale gas, but keep in mind that if the EUR of the average tight oil well falls below a level that is profitable at prevailing prices, the natural gas coming from tight oil wells will no longer be profitable to produce.  Also if the combination of EVs and natural gas reduce demand for oil then the low price scenario becomes more likely and leads to less profitability and less cumulative output from tight oil.  In addition, if consumption of natural gas starts to expand more quickly than production we may see rising natural gas prices, this in turn might lead to a reduction of demand for natural gas in the electric power sector, driving down natural gas prices eventually as PV and wind expand and achieve cost savings due to economies of scale,  In addition the sweet spots in shale gas plays will become fully drilled and eventually we will see new well EUR fall.  This is just geophysics in action, something that has occurred in every oil field ever discovered.

In a battle between technology and geophysics, my money is with the physics, every time.

Note that I include both natural gas and tight oil in my Permian basin analysis, though an inclusion of NGL should also be included.

I think the first issue is that oil depleted shales are still gas producers. Second, the relative pricing of gas and crude oil will be converging to 1 over time. Perhaps asymptotically, but still heading that way this decade. So the two depletion models need to be calculated in tandem pricing. Third point is modeling refracs. Since most of the HC content remained in place in the fracs so far (88-96%), unlike conventional oil and gas, the depleted field will still be a viable future source. Just that the stats are not in hand for commercial refracs yet, so I can't expect you to model it unless you are really adventurous in your assumptions. 

Obviously gas is not going to continue pricing as a waste product. At some point, LNG flows will overtake waste gas volumes and provide a pull towards the sustainable NG price of $3 in the next few years. But that requires huge investment around the world. It is happening, but not fast enough for the Permian drillers with a debt canon at their backs. Indeed, the NG displacement of coal and oil is consuming so much capital that the world economy is growing at a crawl for a decade now, as displaced production is not increased production, its economic contribution is in lowering costs, producing more is a question of how much more demand can be generated by those lower costs. US plastics production global market share is already 40% driven by NGL feedstocks at dirt prices. So after a $300 Billion investment spree the US plastics industry is questioning whether going for another 20% chunk of the market won't destroy pricing. But it will continue to expand, though much more slowly.  Similarly for nitrogen fixing fertilizers producers. They don't want their product to be priced as a secondary waste from oil drilling. .  

Central banks have been oblivious to the structural changes in the global economy due to the shale revolution. They are also challenged by the interpretation of the demographic cliff of OECD+China as 1/3 of the population retires and cuts its spending by up to 75% in 10 years, being replaced by a smaller cohort in the labor market and having an as yet unknown spending priority, and willingness to pursue income growth. The unprecedented huge credit and monetary inflation in China has been destroying market signals in the global economy and driving OECD monetary policy in the wrong direction for decades as they tried to control the commodities inflation that China created with interest rates at home, where demand was not really changing. Thus they undermined investment for decades and brought monetary growth to levels insufficient to service the economy and an overhang of debt that can't be serviced because all the cash is in China (2/3 of global monetary growth for 2 decades). They will eventually "fix" it with a large inflationary wave, or the markets will fix it for them with a huge deflationary wave.  For oil and gas, the difference in response is enormous in financial terms, and in practical terms as well, as China would not be able to maintain its level of oil imports if the deflationary path is followed, nor would any emerging market show growth for a decade. The inflationary option will translate into a hyperinflation in China, where the money has accumulated. That would produce an inflationary bubble in oil and gas, more in oil than gas as it is easier to hoard it during the inflation.  

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(edited)

14 hours ago, 0R0 said:

I think the first issue is that oil depleted shales are still gas producers. Second, the relative pricing of gas and crude oil will be converging to 1 over time. Perhaps asymptotically, but still heading that way this decade. So the two depletion models need to be calculated in tandem pricing. Third point is modeling refracs. Since most of the HC content remained in place in the fracs so far (88-96%), unlike conventional oil and gas, the depleted field will still be a viable future source. Just that the stats are not in hand for commercial refracs yet, so I can't expect you to model it unless you are really adventurous in your assumptions. 

Obviously gas is not going to continue pricing as a waste product. At some point, LNG flows will overtake waste gas volumes and provide a pull towards the sustainable NG price of $3 in the next few years. But that requires huge investment around the world. It is happening, but not fast enough for the Permian drillers with a debt canon at their backs. Indeed, the NG displacement of coal and oil is consuming so much capital that the world economy is growing at a crawl for a decade now, as displaced production is not increased production, its economic contribution is in lowering costs, producing more is a question of how much more demand can be generated by those lower costs. US plastics production global market share is already 40% driven by NGL feedstocks at dirt prices. So after a $300 Billion investment spree the US plastics industry is questioning whether going for another 20% chunk of the market won't destroy pricing. But it will continue to expand, though much more slowly.  Similarly for nitrogen fixing fertilizers producers. They don't want their product to be priced as a secondary waste from oil drilling. .  

Central banks have been oblivious to the structural changes in the global economy due to the shale revolution. They are also challenged by the interpretation of the demographic cliff of OECD+China as 1/3 of the population retires and cuts its spending by up to 75% in 10 years, being replaced by a smaller cohort in the labor market and having an as yet unknown spending priority, and willingness to pursue income growth. The unprecedented huge credit and monetary inflation in China has been destroying market signals in the global economy and driving OECD monetary policy in the wrong direction for decades as they tried to control the commodities inflation that China created with interest rates at home, where demand was not really changing. Thus they undermined investment for decades and brought monetary growth to levels insufficient to service the economy and an overhang of debt that can't be serviced because all the cash is in China (2/3 of global monetary growth for 2 decades). They will eventually "fix" it with a large inflationary wave, or the markets will fix it for them with a huge deflationary wave.  For oil and gas, the difference in response is enormous in financial terms, and in practical terms as well, as China would not be able to maintain its level of oil imports if the deflationary path is followed, nor would any emerging market show growth for a decade. The inflationary option will translate into a hyperinflation in China, where the money has accumulated. That would produce an inflationary bubble in oil and gas, more in oil than gas as it is easier to hoard it during the inflation.  

You want to be careful with monetary growth, the Chinese annual inflation rate has been under 3% since 2012 and has averaged 2% per year for the past 20 years.  See

https://fred.stlouisfed.org/series/FPCPITOTLZGCHN

Also World real GDP per capita has grown at a pretty steady rate from 1982 to 2018 grew at a pretty constant rate of 1.55% per year (except for the GFC) see

https://fred.stlouisfed.org/series/NYGDPPCAPKDWLD#0

so the slow down in growth is mostly the OECD, which is normal for mature economies.

Perhaps natural gas prices will rise to the level of oil in energy terms, note that a $3/MCF wellhead natural gas price would be equivalent to an oil price of $17.40/bo at the well head.  Tight oil will never be viable at that price.  A $50/bo oil price would be equivalent to natural gas at $8.62/MCF.  For the average Permian 2017 well, if we assume $33.4/bo at well head and a natural gas price of $5.76/MCF (5.8 MCF=1 bo) at wellhead and NGL price at $8.35/b (25% of crude price) the well breaks even.

If we assume $3/MCF for natural gas at wellhead and oil at $43.20/bo at wellhead and NGL at $10.80/b the average 2017 Permian well also breaks even.  Note that the average well will likely see smaller EUR in the future so the breakeven price will increase over time, despite the magic of technology.

Refracks are not likely to be profitable particularly in a low oil price environment.

The world will need to move to cheaper energy alternatives such as wind and solar as fossil fuels deplete and their cost of production increases for the marginal barrel or cubic foot.

The gas from tight oil wells will only be produced if the tight oil is profitable to produce, otherwise the wells will never be profitable to drill and complete.

Let's take and extreme example and assume the price for tight oil at the well head falls to $17.40/bo, with NGL at $4.35/b and NG at $3/MCF, the average 2017 Permian basin tight oil well would need a capital cost of $4.034 million for full cycle capital cost (including D+C, facilities and other overhead, and land cost).  Currently the average Permian well is at a capital cost of about $10.5 million, so we would need capital costs to be cut to 38% of current costs for such a well to break even in this assumed three stream price scenario.  I am skeptical that technology will ever get us to this level of reduced cost.

Coffeeguyzz would claim this is no problem.  :)

Edited by D Coyne

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1 hour ago, D Coyne said:

 

The world will need to move to cheaper energy alternatives such as wind and solar as fossil fuels deplete and their cost of production increases for the marginal barrel or cubic foot.

 

Cheaper energy alternatives?  LOL!  These alternatives are not cheaper by any means nor are they likely sustainable since they require FF energy to produce the components, build the facilities and service the constantly failing mechanical components of the wind mills.

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(edited)

3 hours ago, wrs said:

Cheaper energy alternatives?  LOL!  These alternatives are not cheaper by any means nor are they likely sustainable since they require FF energy to produce the components, build the facilities and service the constantly failing mechanical components of the wind mills.

Consider this

https://www.lazard.com/perspective/lcoe2019

Do the wells, equipment, refineries, pipelines, trucks, fuel stations, etc get built without using any fossil fuel?

Natural Gas can barely compete in high wind resource (midwest and parts of Texas) or high solar resource areas (Southwest US).  Coal plants are being shut down at a high rate because it cannot compete with natural gas, wind or solar.  This is with current LCOE for wind in solar, and natural gas prices at historic lows.  Care to guess what happens if natural gas price goes up to to $3/MCF or to $5/MCF?  The solar and wind power plants will become the cheapest resource to produce electricity.

Then add to that the historic fall in LCOE for solar (19.8%/year decrease in LCOE for past 10 years) and wind (11.3%/year decrease in LCOE for past 10 years) and fossil fuels will have a tough time in the electric power industry.

lcoe-2.png

Edited by D Coyne

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I consider that LCOE is a made up number to sell solar to homeowners.

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2 minutes ago, wrs said:

I consider that LCOE is a made up number to sell solar to homeowners.

The Lazard analysis program is for investors. You can see how expensive the rooftop solar is. Not a seller of that. 

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4 minutes ago, wrs said:

I consider that LCOE is a made up number to sell solar to homeowners.

Power producers take it very seriously as they will be out of business before long.

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1 minute ago, 0R0 said:

The Lazard analysis program is for investors. You can see how expensive the rooftop solar is. Not a seller of that. 

0R0,

Those in the solar PV utility scale business say that in high resource areas (Arizona, New Mexico, Southern California) nothing can compete with utility scale solar.  I imagine wind farms in Iowa, say much the same thing, eventually the decreases in the cost for wind and solar will slow down, but your analysis suggesting that natural gas prices will rise to $3/MCF (equivalent to only $17.40/bo if the price equivalence you suggest is reached).  If oil prices must be at least $40/b for long term supply to satisfy demand, that would imply a natural gas price of $6.90/MCF at energy equivalent prices.

Not much natural gas fired electric power will be able to compete at that price.  Also despite claims to the contrary the natural gas resource is not unlimited, it is likely to peak by 2035 and may become very expensive, if consumption is not reduced, so we will need wind and solar to supplement natural gas power, eventually natural gas will just be used as backup in the electric power industry and coal is likely to be eliminated in the electric power sector.

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3 minutes ago, D Coyne said:

Power producers take it very seriously as they will be out of business before long.

Not really representative, those in solar friendly locales in SW US definitely should worry if they just built NG plant. SE US is looking to remain at NG combined cycle equivalence. North is a no go for solar, days are too short in the winter, perhaps if the best tech in the R&D labs makes it to commercial at equivalent costs to current thin film tech, then at 40% solar recovery it is viable in US North but not clear about Canada. Wind corridors are unsteady most places in the North and change seasonally. The coasts provide steady powerful wind corridors, The texas plane does as well. The Ohio valley is not where you will find competition to Fossil Fuel.  . 

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(edited)

20 minutes ago, 0R0 said:

Not really representative, those in solar friendly locales in SW US definitely should worry if they just built NG plant. SE US is looking to remain at NG combined cycle equivalence. North is a no go for solar, days are too short in the winter, perhaps if the best tech in the R&D labs makes it to commercial at equivalent costs to current thin film tech, then at 40% solar recovery it is viable in US North but not clear about Canada. Wind corridors are unsteady most places in the North and change seasonally. The coasts provide steady powerful wind corridors, The texas plane does as well. The Ohio valley is not where you will find competition to Fossil Fuel.  . 

0R0,

Consider the cost to move the electricity over HVDC lines vs natural gas at $6/MCF.  You had suggested an eventual one to one correspondence between oil and natural gas ( I assumed you meant on an energy equivalent basis, 5.8 MCF=1 bo).  What is your expectation for the long term price of oil?  I have seen analyses that suggest oil would need to fall to $40/bo for diesel ICEV to compete with future EVs and $30/bo for gasoline ICEV to compete with EVs.  Are you expecting perhaps a $35/bo future price of oil?  If so that would imply about $6/MCF for natural gas.

A combination of wind and solar widely dispersed and connected by the grid with an overbuild of capacity might require very little backup power and could provide up to 99% of total load hours.

See this 2012 study

https://www.sciencedirect.com/science/article/pii/S0378775312014759

Edited by D Coyne

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44 minutes ago, D Coyne said:

0R0,

Those in the solar PV utility scale business say that in high resource areas (Arizona, New Mexico, Southern California) nothing can compete with utility scale solar.  I imagine wind farms in Iowa, say much the same thing, eventually the decreases in the cost for wind and solar will slow down, but your analysis suggesting that natural gas prices will rise to $3/MCF (equivalent to only $17.40/bo if the price equivalence you suggest is reached).  If oil prices must be at least $40/b for long term supply to satisfy demand, that would imply a natural gas price of $6.90/MCF at energy equivalent prices.

Not much natural gas fired electric power will be able to compete at that price.  Also despite claims to the contrary the natural gas resource is not unlimited, it is likely to peak by 2035 and may become very expensive, if consumption is not reduced, so we will need wind and solar to supplement natural gas power, eventually natural gas will just be used as backup in the electric power industry and coal is likely to be eliminated in the electric power sector.

I am not expecting that they are going to be converging immediately. I am saying that the NG and oil price will be driven towards convergence over the next decade. The expansion of LNG to cover all the Permian waste output is the first step then Haynesville gas etc. with short pipelines to the LNG terminals on the coast. The spread between oil and NG and associated product will narrow over time. As NG is more abundant it will continue to price at a discount. But it will displace the oil demand for chemical feedstock and heavy shipping.where volumes are expected to rise 85% and 30% (?) by EIA.  

I am not concerned about renewables displacement of NG. It extends the life of the reserve and has the same economic impact as more NG. I would be happy to see renewables eat the 20-30% of utility power output that is expected to be viable from those sources at a lower cost than NG. As things are LNG is growing by leaps and bounds going to where renewables don't work. Plenty of those locations.

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In reference to the accolades surrounding renewables, a curmudgeon lurker has emerged with this small message:

Throughout the history of the earth, periods of upheaval--characterized by mass extinctions, changes in sea level and ocean chemistry, changes in prevailing climate patterns--have written their signature in layers of rock. That's the reason geologists tell us that there have been ~50 climate changes through the annals of time. It would appear, for example, that Florida has been under water more than under the sun. It should be noted that those cataclysmic epochs were not influenced by human activity: they are not our fault.

We are currently in the Anthropocene Age, whereby the actions of 8 billion (misguided) Homo sapiens now influence all those things above. We shouldn't assume that, just by replacing fossil fuels with renewables, we will always change things for the better--as is currently preached.

In a study (Nature Climate Change) of dense coverage of desert areas by solar panels, the amount of solar radiation absorbed by the earth was substantially reduced (because, obviously, it was instead being absorbed by solar panels, and transmitted away). This led to cascading effects on the local climate: 1) the temperature dropped by up to 2 degrees Celsius, 2) precipitation dropped by 20% (due to decreased cloud cover), and, 3) wind patterns changed.

So, let's race to install hundred-thousand-acre solar farms in the Great American Southwest, cover all the buttes of the Plains with giant wind turbines, and see exactly what kind of climate change we get--it'll be a jim-dandy little science experiment. And what could possibly go wrong? If the past is prologue, there will be some unexpected consequences. There may be no one around to judge, but this one is on us.

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1 hour ago, D Coyne said:

0R0,

Consider the cost to move the electricity over HVDC lines vs natural gas at $6/MCF.  You had suggested an eventual one to one correspondence between oil and natural gas ( I assumed you meant on an energy equivalent basis, 5.8 MCF=1 bo).  What is your expectation for the long term price of oil?  I have seen analyses that suggest oil would need to fall to $40/bo for diesel ICEV to compete with future EVs and $30/bo for gasoline ICEV to compete with EVs.  Are you expecting perhaps a $35/bo future price of oil?  If so that would imply about $6/MCF for natural gas.

A combination of wind and solar widely dispersed and connected by the grid with an overbuild of capacity might require very little backup power and could provide up to 99% of total load hours.

See this 2012 study

https://www.sciencedirect.com/science/article/pii/S0378775312014759

That is a great piece of work, but it misses the point that the grid is not actually able to transfer that kind of power throughput from one end to the other. The bulk of power transmission is short distance and the grid makes up local shortfalls and excess. That is why when a main generation in an area goes out, the grid can't supply enough power from other nearby regions to fully make up for it, some of the larger users need to stay offline. That connectivity has been improved but isn't where it needs to be for that study's estimates to hold. There is only so much capital to go round at any point in time. The renewables + storage will still need to be locally sufficient for the most part. I doubt the grid will be beefed up with additional long distance carrying capacity of the scale required. Not with NG for peaking and even baseload remaining cheap in the Appalachian basin at least, while wind and PV require much more storage and excess capacity in darker climes with moderate wind corridors like the NE central area being looked at. This study was done on the background of $12 NG. Not <$3.But it is structurally insightful.

The unpaid environmental and health costs being stuffed in on the fossil fuel side is equally applicable on the other side for their mining and production's large Env.&Health costs. So that artificial cost on the NG/coal side has to be taken out of the calculation. That piece of intellectual dishonesty has little significance in the real world. 

So ultimately, the penetration of renewables+storage will make it to high levels, but probably not anywhere near 99% till long after the cheapest NG is depleted. We will have to see what decisions are made as we go along. But CA's premature forcing of PV energy has been a disaster in costs (10 X other grids), as it was all premature, inefficient, and will practically all be replaced before the decade is out. The carbon footprint of this mistake is enormous. 

NREL has more detailed analysis of battery storage cost projections centered at about $200/kwh @2030 

https://www.nrel.gov/docs/fy19osti/73222.pdf

Here is another survey, still partial, it refer's to an MIT study. The main point to consider is how much renewables penetration you can get at a given storage cost. The complete displacement level nationally is $20/kWh as the benchmark. Lithium is not anywhere near that. The compressed air and hydro storage require geological features that don't exist outside mountain areas with good water supplies. A sulfur in water system that I don't know a thing about is in early commercial pilot stages. 

Hydrocarbon and hydrogen production from excess electricity is an alternative storage mechanism that can make use of existing NG infrastructure. That is more interesting because it can be transported rather than being locked onsite.

This is all coming slowly in relative terms, but will definitely kick out NG where storage requirements aren't that large.or cheap storage options are available. .

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Dennis/wrs/oro

Geez, Dennis ... you really ought not to have referenced Lazard's 2019 LCOE without willing to 'get into the weeds' as you and I have done on your site over the years on these presentations.

For the folks primarily interested in current 'shale stuff', this divergence into the world of power generation may seem off topic to you all.

Fascinating arena, however, as the electricity universe - especially how it is generated/transmitted/consumed - profoundly impacts all of us, the hydrocarbon industry particularly so.

Dennis ... the difference between version 12 and 13 (page #18) increases the Fixed O&M cost (median) from $5.75/Kwh-yr to $12.75 ... the Variable O&M from $2.75/Mwh to $3.40 as applied to the CCGT boys.

Can you tell me why?

Likewise, in the appendix for Methodology - page 18 - the median cost for a 550 Mw plant is $800/Mw. Seriously?

The 2 dozen CCGT plants going up in Ohio and Pennsylvania are running 1,000 to 1,400+ Megawatt capacity with costs just at or above  $1 billion.

(Yesterday's release from Pennsylvania shows another record of over 19.6 bcfd, btw).

Fuel cost, as depicted on page #11 being a significant expense for the CCGPs, is $3.45/mmbtu. As of this post, it is $2.05.

Biggest blind spot in this entire "Mine is cheaper than yours" brouhaha, is the GROSS misconflation of CAPACITY factor with UTILIZATION factor.

While your beloved whirleys are going all out in the 3 AM time frame, ensuring people's alarm clocks are running, the CCGP boys are standing by NOT burning fuel when the price/revenue of the marketed electricity is squat.

As the morning and evening windows call for huge upsurge in hourly demand (typically 6 to 11 AM, 3 to 8 PM), the gas plant operators put down their coffee, push a few buttons, and - viola - uber fast ramp times coinciding with 63% efficiency rates provide the cheapest, most reliable electricity anywhere on the planet outside of Iceland.

And THIS lies behind the ferocious demonization of all things hydrocarbon as the Renewable Industry (along with MANY other players) recognize that they are going the way of the SST just before they truly got off the ground.

Quick addendum, Dennis (or anyone) ... check out last February's LCOE/LCAE paper from the EIA. It covers much of the same ground as Lazard, but a more 'realistic/comprehensive' overview that is not as favorable to the Ra and Zephyr acolytes. Pretty good comparative data, however.

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18 hours ago, 0R0 said:

I am not expecting that they are going to be converging immediately. I am saying that the NG and oil price will be driven towards convergence over the next decade. The expansion of LNG to cover all the Permian waste output is the first step then Haynesville gas etc. with short pipelines to the LNG terminals on the coast. The spread between oil and NG and associated product will narrow over time. As NG is more abundant it will continue to price at a discount. But it will displace the oil demand for chemical feedstock and heavy shipping.where volumes are expected to rise 85% and 30% (?) by EIA.  

I am not concerned about renewables displacement of NG. It extends the life of the reserve and has the same economic impact as more NG. I would be happy to see renewables eat the 20-30% of utility power output that is expected to be viable from those sources at a lower cost than NG. As things are LNG is growing by leaps and bounds going to where renewables don't work. Plenty of those locations.

0R0,

The scenario I painted is over the next couple of decades.  What is likely to happen is that natural gas prices will rise as more gets transported as LNG there will be a World price for LNG and at the wellhead the price will be World price minus transport and processing cost, eventually there will be a World demand supply balance that is difficult to predict.  My main point is that just like C+C the natural gas is a limited resource, and just like C+C the output will eventually peak and decline (2025 for C+C and 2035 for natural gas).  As oil peaks and becomes very expensive the demand for natural gas will likely accelerate and this could potentially push the natural gas peak to an earlier date (perhaps as early as 2030).  In every case the more expensive cost of oil and then natural gas will lead to an acceleration of the installation of wind and solar power, these sources could become dominant (say 80% or more of total energy output by 2050 to 2060.)

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Is the US Shale Boom Really Slowing Down?

 

Since taking flight in 2008, the American shale oil revolution has probably been the biggest energy story since the end of World War II. U.S. crude oil production has leaped 160 percent to almost 13 million b/d. Shale has transformed global energy markets and obliterated the long-held notion that U.S. crude production peaked in 1970 at 9.7 million b/d.

In fact, thanks to shale, the U.S. has accounted for almost all new global oil production over the past five years. For 2019 alone, the shale industry added some 1.2 million b/d of crude, enough to even cover new global demand.

The emerging question now is whether or not the U.S. shale oil boom is slowing down. In truth, however, the more poignant question is whether or not the industry is just “growing more slowly.” Indeed, these are fundamentally different questions that too often get conflated. Regardless, already accounting for a rising 80 percent of U.S. crude production, without shale there may be no new U.S. supply.

For sure, rapid shale well decline rates mean more drilling, higher debt, and smaller profits. The question of peaking shale though really lies in West Texas’ Permian basin. The Permian is now one of the largest oilfields in the world and accounts for over 35 percent of U.S. crude production. The Permian though has some 3-4 million b/d of new pipeline capacity coming within the next few years, with numerous additional gas pipelines meaning less flaring and more oil.  

Further, if oil prices can stick above $65 or $70, U.S. shale would be given the proverbial “shot in the arm” to better its finances. Such low prices in recent years have already forced the industry to slash costs and greatly increase efficiency. Many producers have sharpened their knife so much that they have breakevens in the $40 range. 

But the real driving force behind more U.S. oil production is the ongoing importance of oil.  Let us be clear: oil supplies some 33 percent of global energy and projections of absolutely declining demand are speculation since oil currently has no material substitute. Although lower in 2019, global oil demand usually rises at 1.3 million b/d.

Any slower growth in oil demand comes more from slower economic conditions than any structural change. Electric cars are overstated since they are not affordable. The average Tesla buyer, for instance, makes a whopping $400,000 per year. The rise of gas-guzzling SUVs in the still developing nations will likely compensate for oil demand reductions that come from electric cars.

Indeed, an ever-expanding U.S. oil export complex will mandate more domestic production. We already know that the oil is there: in December 2018, the “largest U.S. oil and gas discovery ever” was made in the Permian basin. Nationally, proven reserves have more than doubled over the past decade to 65 billion barrels. The resource available is many times that.

To be sure, however, such high growth rates for U.S. crude production like we have seen in recent years cannot be maintained. With significant CAPEX reductions, some see output rising in 2020 at less than half the rate of 2019. Farther out, IEA still has the U.S. supplying 85 percent of new global crude in the 2020s. A peaking at 16 million b/d for total U.S. crude output seems possible, but do not expect drastic declines in the absolute sense. Oil is just too important, and we simply have too much of it.  

Ultimately, beyond shale, the next U.S. oil revolution could be one that not even the industry itself is promoting enough. This would be the widespread deployment of CO2-EOR technologies. This tertiary oil recovery process centers on capturing anthropogenic CO2 from industrial facilities and pumping it safely into the ground to lower the viscosity of the crude left after primary and secondary operations. CO2-EOR is a net carbon reducer and importantly has been supported by the Intergovernmental Panel on Climate Change.

 

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14 hours ago, Coffeeguyzz said:

Dennis/wrs/oro

Geez, Dennis ... you really ought not to have referenced Lazard's 2019 LCOE without willing to 'get into the weeds' as you and I have done on your site over the years on these presentations.

For the folks primarily interested in current 'shale stuff', this divergence into the world of power generation may seem off topic to you all.

Fascinating arena, however, as the electricity universe - especially how it is generated/transmitted/consumed - profoundly impacts all of us, the hydrocarbon industry particularly so.

Dennis ... the difference between version 12 and 13 (page #18) increases the Fixed O&M cost (median) from $5.75/Kwh-yr to $12.75 ... the Variable O&M from $2.75/Mwh to $3.40 as applied to the CCGT boys.

Can you tell me why?

Likewise, in the appendix for Methodology - page 18 - the median cost for a 550 Mw plant is $800/Mw. Seriously?

The 2 dozen CCGT plants going up in Ohio and Pennsylvania are running 1,000 to 1,400+ Megawatt capacity with costs just at or above  $1 billion.

(Yesterday's release from Pennsylvania shows another record of over 19.6 bcfd, btw).

Fuel cost, as depicted on page #11 being a significant expense for the CCGPs, is $3.45/mmbtu. As of this post, it is $2.05.

Biggest blind spot in this entire "Mine is cheaper than yours" brouhaha, is the GROSS misconflation of CAPACITY factor with UTILIZATION factor.

While your beloved whirleys are going all out in the 3 AM time frame, ensuring people's alarm clocks are running, the CCGP boys are standing by NOT burning fuel when the price/revenue of the marketed electricity is squat.

As the morning and evening windows call for huge upsurge in hourly demand (typically 6 to 11 AM, 3 to 8 PM), the gas plant operators put down their coffee, push a few buttons, and - viola - uber fast ramp times coinciding with 63% efficiency rates provide the cheapest, most reliable electricity anywhere on the planet outside of Iceland.

And THIS lies behind the ferocious demonization of all things hydrocarbon as the Renewable Industry (along with MANY other players) recognize that they are going the way of the SST just before they truly got off the ground.

Quick addendum, Dennis (or anyone) ... check out last February's LCOE/LCAE paper from the EIA. It covers much of the same ground as Lazard, but a more 'realistic/comprehensive' overview that is not as favorable to the Ra and Zephyr acolytes. Pretty good comparative data, however.

Coffeeguyzz,

Nobody in the shale gas industry is happy with $2.05/MCF, if the price remains at that level many of these producers will fail.

My guess is Lazard is taking industry averages, rather than cherry picking the cheapest power plants that have been built.

The fact is that costs for wind and solar have been decreasing.  As demand for natural gas increases, its price will increase, or if that does not occur, many shale gas producers will fail as the price is less than average cost of production at present.

You may believe that profits do not matter, but most investors would disagree.

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