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16 hours ago, 0R0 said:

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. .

0R0,

I believe most studies that look at life cycle analysis of renewables vs coal will show that coal does worse, it is a matter of degree, calling studies you do not agree with as "dishonest" is a cop out.  (or dishonest).

The point of the study is a wide dispersion of wind and solar resources, power lines can be built where needed and will be if it is cheaper than alternatives (and if someone will make a profit by doing so).

The storage will be a minor piece of the puzzle, excess renewable capacity widely dispersed and beefing up the grid where necessary may be the cheaper option.  Is it your expectation that natural gas will remain at $3/MCF or less for the next decade or perhaps more?   The differential of Henry Hub and LNG exports is about $3.10/MCF (Oct 2019).  A year ago LNG in China and Japan peaked at about $10/MCF, if US prices were to rise to that level and the LNG/HH spread remains $3/MCF, that would imply US HH prices at $7/MCF.  At that price (which may become reality by 2025) a lot of wind, solar, and power lines get built, note that I doubt 99% renewable load hours is likely soon, but 90% by 2040 is not unrealistic and 99% by 2060 is also not unlikely (say a 60% probability).  In addition higher energy costs will lead to better energy systems analysis where far less energy is wasted and the higher resulting efficiency will reduce overall energy needs, also primary energy needs are reduced when we aren't wasting 60% of primary energy.

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2 hours ago, D Coyne said:

0R0,

I believe most studies that look at life cycle analysis of renewables vs coal will show that coal does worse, it is a matter of degree, calling studies you do not agree with as "dishonest" is a cop out.  (or dishonest).

The point of the study is a wide dispersion of wind and solar resources, power lines can be built where needed and will be if it is cheaper than alternatives (and if someone will make a profit by doing so).

The storage will be a minor piece of the puzzle, excess renewable capacity widely dispersed and beefing up the grid where necessary may be the cheaper option.  Is it your expectation that natural gas will remain at $3/MCF or less for the next decade or perhaps more?   The differential of Henry Hub and LNG exports is about $3.10/MCF (Oct 2019).  A year ago LNG in China and Japan peaked at about $10/MCF, if US prices were to rise to that level and the LNG/HH spread remains $3/MCF, that would imply US HH prices at $7/MCF.  At that price (which may become reality by 2025) a lot of wind, solar, and power lines get built, note that I doubt 99% renewable load hours is likely soon, but 90% by 2040 is not unrealistic and 99% by 2060 is also not unlikely (say a 60% probability).  In addition higher energy costs will lead to better energy systems analysis where far less energy is wasted and the higher resulting efficiency will reduce overall energy needs, also primary energy needs are reduced when we aren't wasting 60% of primary energy.

The $3 spread is going to shrink. It is too high a return on investment not to be rapidly closed. Cheniere charges $2/MMbtu and makes 33% margins. That is down from 75% margins. That is still a very good gross margin to attract competition. It is likely that incremental improvements in economies of scale and tech to lower the liquefaction fees. $1 is likely. I don't expect the $3 mark to be hit till the LNG capacity becomes bigger than ongoing production. It would be a short term peak and then pipelines and production, particularly from the majors, will get it back down. I don't know to net out the transportation charges to get a field price at the wellhead. 

I am really happy to see renewables expand to those levels. But copper production to supply the transmission capacity to even out production and demand mismatches on the grid, will not be at $2.50 copper, it would be $4-5/lb. So it won't happen. It will eventually be cheaper to use excess power periods to make "electric gas" (methane and methanol with bits of ethane and ethanol) from air and water and then ship those to be used wherever needed on legacy NG generation capacity. I don't know how practical shipping charged up batteries on barges and rail would be in comparison. But the Tesla battery containers definitely look the part for wire free electric capacity wherever you might choose to place a business or home. Couple that with 5G and low orbit micro satellites  and you can work by telepresence in a virtual office. The threat to metro regions is real. The Millennial generation now with the belly of the cohort at 30 are moving out of metro centers, getting driver's licenses and looking at exurbia to live and perhaps work there (eventually) I would not be a real estate investor in silicon valley or any global tech center. Particularly if you finally can overcome the need to air gap your internal communications. 

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U.S. oil production hits estimated record 13 million barrels per day

U.S. crude oil production rose to an estimated record-high of 13 million barrels per day last week as the nation's energy growth crossed a new threshold, according to a weekly report from the U.S. Energy Department.

The increase production comes as the nation's stockpiles of commercial crude oil fell by 2.5 million barrels last week, but those volumes were more than offset by large spikes in gasoline and other fuel supplies.

The United States' total petroleum inventories rose by 14.5 million barrels last week as gasoline stocks jumped by 6.7 million barrels and distillate fuel oil supplies - used to make diesel and heating oils - spiked by 8.2 million barrels, according to the inventories report.

U.S. crude production increased from 12.9 million barrels a day - where it had sat for a few weeks - up to the new 13 million barrels mark.

 
 

The news comes amid falling oil prices as the U.S. benchmark could settle below $58 per barrel for the first time since Dec. 3.

 

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NEW YORK (Reuters) - U.S. crude oil production is expected to rise by 1.06 million barrels per day (bpd) in 2020 to a record of 13.30 million bpd, the U.S. Energy Information Administration (EIA) said on Tuesday, above its previous forecast for a rise of 930,000 bpd.

The output in 2021 is forecast to rise by 410,000 bpd to 13.71 million bpd, according to the EIA.

“We forecast U.S. crude oil production will reach new records in 2020 and 2021, driven primarily by higher production in the Permian region of Texas and New Mexico,” EIA Administrator Linda Capuano said in a statement.

“Both global oil supply and consumption are expected to grow in 2020, with supply from non-OPEC producers, particularly the Unites States, Norway, Brazil, and Canada, more than offsetting declining production from OPEC.”

 

A shale boom has helped make the United States the world’s biggest oil producer, overtaking Saudi Arabia and Russia.

However, the rate of growth is expected to slow into next year as U.S. oil producers follow through on plans to slash spending on new drilling for a second year in a row in 2020.

In 2019, the oil rig count, an early indicator of future output, notched its first annual decline since 2016 as independent exploration and production companies cut spending on new drilling as shareholders seek better returns in a low energy price environment.

 

For 2020, the agency expects U.S. petroleum and other liquid fuels demand to climb 160,000 bpd to 20.64 million bpd in 2020, below its previous forecast for a rise of 170,000 bpd to 20.75 million bpd.

Demand is expected to rise 70,000 bpd to 20.71 million bpd in 2021, the EIA said.

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23 hours ago, ceo_energemsier said:

For 2020, the agency expects U.S. petroleum and other liquid fuels demand to climb 160,000 bpd to 20.64 million bpd in 2020, below its previous forecast for a rise of 170,000 bpd to 20.75 million bpd.

Demand is expected to rise 70,000 bpd to 20.71 million bpd in 2021, the EIA said.

Tesla effect?

Competing models so far have more limited range and/or lower performance, and they cost more. It is early in the game, so we don't know if someone will come up with a better/cheaper battery than Panasonic/Tesla.

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The next salvo in the oil price war has been fired. Libya just shut down 800,000 bpd of output. 

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The U.S. Energy Information Administration’s (EIA) forecasts the United States to remain a net exporter of natural gas through 2021.

In its Short-Term Energy Outlook (STEO), EIA said net natural gas exports are forecast to average 7.3 billion cubic feet per day (Bcf/d) in 2020 and 8.9 Bcf/d in 2021, a 3.6 Bcf/d increase from 2019.

In 2017, the United States became a net natural gas exporter on an annual basis for the first time in 60 years.

Strong natural gas export growth in recent years is mainly the result of increased exports of liquefied natural gas (LNG). U.S. LNG exports averaged 5.0 Bcf/d in 2019, 2.0 Bcf/d higher than in 2018, as a result of several new facilities placing their first liquefaction units—referred to as trains—in service.

This year, several new trains are expected to begin operations: Trains 2 and 3 at Cameron LNG in Louisiana, Train 3 at Freeport LNG in Texas, and six remaining Moveable Modular Liquefaction System (MMLS) units (Trains 5–10) at Elba Island in Georgia, EIA said.

In 2021, the third train at the Corpus Christi facility in Texas is scheduled to come online, bringing the total U.S. liquefaction baseload capacity to 10.2 Bcf/d.

LNG exports are projected to continue to grow—averaging 6.5 Bcf/d in 2020 and 7.7 Bcf/d in 2021—as facilities gradually ramp up to full production.

EIA also forecasts that pipeline exports will continue to grow through 2021. Gross U.S. pipeline exports rise from 7.8 Bcf/d in 2019 to 8.1 Bcf/d in 2020 and to 8.5 Bcf/d in 2021.

U.S. pipeline exports to Mexico began increasing after expansions of cross-border pipeline capacity were completed. From January through October 2019, U.S. pipeline exports to Mexico averaged 5.1 Bcf/d, which is 0.5 Bcf/d higher than the 2018 annual average, according to EIA’s Natural Gas Monthly.

Although U.S. net natural gas pipeline imports from Canada have been steadily declining since 2016, the United States is projected to remain a net natural gas importer from Canada through the long-term because imports from Canada will remain a supply source for the United States during the winter.

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On 1/17/2020 at 2:37 PM, 0R0 said:

The $3 spread is going to shrink. It is too high a return on investment not to be rapidly closed. Cheniere charges $2/MMbtu and makes 33% margins. That is down from 75% margins. That is still a very good gross margin to attract competition. It is likely that incremental improvements in economies of scale and tech to lower the liquefaction fees. $1 is likely. I don't expect the $3 mark to be hit till the LNG capacity becomes bigger than ongoing production. It would be a short term peak and then pipelines and production, particularly from the majors, will get it back down. I don't know to net out the transportation charges to get a field price at the wellhead. 

I am really happy to see renewables expand to those levels. But copper production to supply the transmission capacity to even out production and demand mismatches on the grid, will not be at $2.50 copper, it would be $4-5/lb. So it won't happen. It will eventually be cheaper to use excess power periods to make "electric gas" (methane and methanol with bits of ethane and ethanol) from air and water and then ship those to be used wherever needed on legacy NG generation capacity. I don't know how practical shipping charged up batteries on barges and rail would be in comparison. But the Tesla battery containers definitely look the part for wire free electric capacity wherever you might choose to place a business or home. Couple that with 5G and low orbit micro satellites  and you can work by telepresence in a virtual office. The threat to metro regions is real. The Millennial generation now with the belly of the cohort at 30 are moving out of metro centers, getting driver's licenses and looking at exurbia to live and perhaps work there (eventually) I would not be a real estate investor in silicon valley or any global tech center. Particularly if you finally can overcome the need to air gap your internal communications. 

0R0,

The spread is probably due to tranport plus processing cost.  Do we know the cost to liquify and then transport a thousand cubic feet of natural gas from the Gulf coast to Asia?  Seems currently it is about $3/MCF, it may decrease in the future, but probably not to less than $2/MCF.  

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2018/02/The-LNG-Shipping-Forecast-costs-rebounding-outlook-uncertain-Insight-27.pdf

older paper

https://www.iaee.org/en/publications/newsletterdl.aspx?id=341

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4 hours ago, D Coyne said:

The spread is probably due to tranport plus processing cost.  Do we know the cost to liquify and then transport a thousand cubic feet of natural gas from the Gulf coast to Asia?  Seems currently it is about $3/MCF, it may decrease in the future, but probably not to less than $2/MCF.  

The cost is going to come down more than you think: The technology is well established, the trains are not terribly expensive to build, and permits are now easy to procure.

LNG is free of contaminants: zero Hg, sulfides, long carbon chains, water or slug. Transportation is free, except for amortization of the ship and the cost of the crew. The liquid natural gas boils in the thermos bottles holding it. About 0.1% of the contents boils off and hangs above the liquid as "boil-off" gas. This is diverted into the steamers and used for transportation fuel.

LNG is going parabolic. If you look at NG piped to Mexico and to US LNG export facilities, we're at about 11-12 bcf/d, which represents 30% growth year over year. The Cameron Parish Louisiana facility (Sabine Pass) has added two new trains (now either six or seven). Corpus Christi has a couple new trains. Elba Island (Georgia) and Freeport (Tx) have opened. 

The LNG market is an infant, maybe 10% of where it will be in five years. Pipelines get paid off in about five years; thereafter it's gravy. I'll bet these LNG terminals are paid off in five years, too. This is all falling into place: Massive volumes of NG are going to be piped from the Permian into Sabine Pass, Corpus Christi, Alba Island, Freeport, and wherever else on the Gulf facilities are added. The Sabine Pass Shipping Channel is exceptionally efficient--it's only 3.7 nautical miles to open water and 23 miles to the outer buoy.

As global oil supply gets tighter, with resultant higher pricing, it will drive the drilling of more shale wells. Gas lifting (especially ethane) is already revolutionizing shale, as is holding the well-bore pressure higher for longer. Next comes refracking, the price of which is coming down dramatically (at least in the Bakken). Natural gas production will more than likely double from its current level, and almost all of that will go to LNG exports.

The recent cold snaps scared the bejiggers out of a lot of people. Without hydrocarbon heat, the human race would be forced back into the caves. It's going to take one hell of a lot of wind turbines and solar panels to replace that kind of protection from the elements. The Greenies holding ban-fracking signs, for example, would freeze their little tushes if they didn't have natural gas. 

Modi has promised to make LNG one-half of India's long-term energy requirements. China will likely follow suit, as part of the trade deal. Once countries commit to energy, it is hard to turn around. And, after all, LNG will dovetail perfectly with wind and solar--such as they are.     

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5 hours ago, D Coyne said:

0R0,

The spread is probably due to tranport plus processing cost.  Do we know the cost to liquify and then transport a thousand cubic feet of natural gas from the Gulf coast to Asia?  Seems currently it is about $3/MCF, it may decrease in the future, but probably not to less than $2/MCF.  

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2018/02/The-LNG-Shipping-Forecast-costs-rebounding-outlook-uncertain-Insight-27.pdf

older paper

https://www.iaee.org/en/publications/newsletterdl.aspx?id=341

I look at marine transport baltic rates http://marine-transportation.capitallink.com/indices/capital_link_maritime_chart.html?ticker=CLLG

The spot rates are low and steady for a while now. From the oxford energy paper, the charter portion should now be about half of what it was when the article data cutoff was.. and LNG and source is about half as well. So about $0.3 and the LNG cost itself is $3 at the source so that portion is $0.2 fuel cost (if that, industry talk is referring to it as "free") total.about $0.6. If you take Cheniere's liquefaction fee down to 15% margin then it is $1.85 so total cost would now be around $2.45 and probably still some room to fall. Some bandy about a $2 cost next year. 

So it is still going to be good at a $4.50 for Russian pipe gas as competition in Europe and we expect for China. That leaves you competitive at $2 going into the LNG plant. .   

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Today NG is at $1.94/mcf in the dead of winter, how cheap are solar and wind compared to that? LOLOL!  $3/mcf is a distant dream...................

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Tm is another DUC report. But on the subject of NG .... generac has NG to AC generators far cheaper than the same size solar system but with gas payment I have no idea of the break even. I've always dreamed of making a liquid cooled NG generator that byproducts hot water ... make it small enough and have a battery to top up and you'd have a bumpin system. Closest thing would be a European micro turbine generator. Could even use the heat for home heating in the winter. Why I thought of this is because my electricity bill is 93$ for 531kWh. 47$ is delivery eventhough the distribution unit is on my street and theres a hydro station 2mins down the road.... life . 17.5c / kWh of all in costs.

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Dennis

As a few other posters have noted, that OIES paper has some great info, but it is woefully outdated, despite being a March 2018 release.

One example, for instance, is that the Panama Canal now offers transit for Qmax LNG vessels ... about a 100,000 cubic meter increase over the normal LNG carriers. 

Bigger shortfall in that paper, perhaps, is reference to a 2016 paper (Songhurst, et al) on the cost of new LNG plant operations.

Songhurst has a 2018 update that - itself - is not particularly forward looking as it does not meaningfully  incorporate the current modularization techniques and only mentions in passing (page #19) how economical new liquefaction processes are particulary effective on trains smaller than 1.6 mtpa ... which is the future blueprint of most all American LNG plants.

For people with both the interest and time, delving into these transport and build out costs of LNG - particularly US LNG - as these OIES papers describe, might be both eye opening and excellent guideposts as for what is to come.

Mentioned somewhat peripherally, the Floating Storage and Regasification Units (FSRUs) are in early stages of new paradigm setting electricity models.

Incorporating both reciprocating engines and aerodynamic turbines as juice generators, from massive Thi Vai, Son My 2, Sergipe projects to small operations in Benin, Jamaica, New Caledonia ...  electricity will/is being provided across vast swaths of the globe that heretofore would never have been possible.

Thanks, Cowboyistan.

 

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(edited)

15 hours ago, 0R0 said:

The 1 year forward is $2.70, so if you hedge you can bank that and go right ahead drilling into sub $2 NG at spot. That is supported by forward LNG contracts and is rising while spot is falling. 

https://research.stlouisfed.org/datatrends/usfd/page17.php

 

Doesn't work that way.

The $2.70 price you're talking about is only the Jan 2021 contract ($2.614 Monday evening).
The one year average (Feb 2020-Jan 2021) is $2.170. 

Natural Gas sales are in the production area.  Let's take West Texas production (delaware or midland basin) which trades off a Waha (West TX) basis.  Waha is trading between $1.40-$2.01 back of Henry Hub.  That puts residual gas revenue between $0.50 in Feb ($1.90-$1.40) and $0.20 in Oct ($2.21-2.01).  This is before low pressure gathering (on lease), high pressure gathering (to processing plant) and Gas Processing.  West Texas producers are definitely paying to get rid of their gas.  To be fair, West Texas gas production is high BTU so gas processing yield of NGL's will make total gas revenue positive.  I choose West Texas because oil production will continue and produce associated gas despite pricing.  Marcellus is on bankruptcy watch.  EQT (junk) Antero (junk) are the biggest Marcellus producers.  Haynesville is in better shape because of proximity to market vs Marcellus.  STx has crappy economics.     

Producers don't make the spot to LNG spread.  NG Producers are in a world of hurt.

Edited by Bob D
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5 hours ago, wrs said:

Today NG is at $1.94/mcf in the dead of winter, how cheap are solar and wind compared to that? LOLOL!  $3/mcf is a distant dream...................

 

50 minutes ago, Coffeeguyzz said:

As a few other posters have noted, that OIES paper has some great info, but it is woefully outdated, despite being a March 2018 release.

Vis a vis the above, in March 2018, natural gas was about $2.90--compared to $1.94 today. 

LNG is growing like it is because the end-of-pipeline price for natural gas has fallen like a stone, and it has done that because, in the shale basins, massive amounts of NG co-traffic with only modest amounts of LTO. 

The Oxford Institute has never taken into consideration this American conundrum--not in March 2018 or today. 

 

 

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(edited)

10 hours ago, Gerry Maddoux said:

LNG is growing like it is because the end-of-pipeline price for natural gas has fallen like a stone, and it has done that because, in the shale basins, massive amounts of NG co-traffic with only modest amounts of LTO. 

BINGO !!! and for folks who don't understand the mechanics of Ng in West Permian, the flares keep going. Cheaper to blow it off than pay to remove. Ya can't just compress to liquid and haul away the amounts of hard to get to wells and the distances required to truck it. It sux to blow it off into the atmosphere but until a viable cost process put in place it's still the by-product of OIL.

Edited by Old-Ruffneck
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17 minutes ago, Old-Ruffneck said:

BINGO !!! and for folks who don't understand the mechanics of Ng in West Permian, the flares keep going. Cheaper to blow it off than pay to remove. Ya can't just compress to liquid and haul away the amounts of hard to get to wells and the distances required to truck it. It sux to blow it off into the atmosphere but until a viable cost process put in place it's still the by-product of OIL.

People don't realize how desolate it is out in West Texas and how far out everything is.  That is why the infrastructure has been so long in coming but it's all falling into place now.  I think the flaring will be reduced substantially this year.  However with NG prices this low, it's not much help to sell it.

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3 minutes ago, Old-Ruffneck said:

BINGO !!!

Agree  Marcellus and Haynesville are the NG Shale basins with "massive amounts of NG and modest amounts of LTO" and their growth over the last few years has brought on this price environment.

However, Haynesville and Marcellus growth prospects in this price environment will not materialize.  As I previously highlighted, the biggest producers are junk.  Our forecasts have modest to no growth in the NG Shale Basins. 

The issue moving forward is NG growth from associated gas production in the Oil Shale Basins (Permian Bakken).  In fact, our forecasts have NG growth in the Oil Shales exceeding NG growth in the NG Shales.  I have clients in the Midland basin whose production revenue is 90% oil, 10% gas (7% ngl's, 3% ng).  This is common in the Midland Basin and the oil curve supports standing up a rig.  I have clients in the Delaware basin whose production is similar but as you move west the GOR increases to where production volume is 50% oil and 50% gas but this is still an 85% oil revenue / 15% gas revenue split.  NGL revenue is vital because NG revenue in west Texas could be negative.  This happened in 2018 twice on a Index (full month price negative) and commonly occurred in daily pricing.  The biggest loser day was ($9.00) for one day at Waha.  Producers paid buyers $9 to take their gas that day.  Oil is king and gas is considered an unfortunate by product.

 

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Shocking, just shocking!!! Not just a shale fiasco but an entire industry fiasco!!!(sarcasm)

Does this mean that the "shale deniers" should go after these majors as well and tell them to shut down because they are not sustainable? That includes conventional oil and gas !!!!

 

 

____________________________________________________

 

 

‘A sector in disarray’: Oil majors live beyond their means on investor payouts, study finds

 

 

A Chevron drilling operation in Texas. A think tank that favors renewable energy released results of a study that it says shows oil companies are “a sector in disarray.”

 
 

The largest oil and gas companies for years have lived beyond their means and paid more money to investors than they can reasonably afford, according to a new report.

The study from the Cleveland-based Institute for Energy Economics and Financial Analysis found that the five largest Big Oil majors — Exxon Mobil, Chevron, Royal Dutch Shell, BP and Total — spent $536 billion on shareholder dividends and stock buybacks since 2010 while bringing in just $329 billion in free cash flow.

“The oil majors are consistently under-performing the market and may believe that shareholders won’t notice, as long as they receive generous dividends,” said Tom Sanzillo, co-author of the report and director of finance for the institute, a think tank that supports renewable energy. “As these companies continue to sell off assets and acquire more debt, they reveal a sector in disarray.”

 

This study covers the period of the last oil bust from 2014 to 2017, when a lot of companies limited their reductions in dividends in buybacks — as revenues fell more sharply — to stop investors from abandoning their firms. BP also was a shrinking company during most of the last decade, selling off many assets after the 2010 Deepwater Horizon tragedy in the Gulf of Mexico.

 

The study found that asset sales — from BP and others — played a big role in funding dividends and buybacks. The study noted that Shell, for example, sold $68 billion in assets from 2010 through late 2019.

 

Of course, Shell also bought the London-based BG Group for $53 billion in 2016 and, as a result, sold many assets to help pay for the megadeal and reduce debt.

The institute also highlighted the decision this week by the world’s largest fund manager, BlackRock, to better align itself with the Paris climate accord goals and invest much less in energy companies, starting with coal companies and utility firms that rely on coal. So there’s an ongoing investment move away from the energy sector.

“Investors are gradually moving away from energy stocks. A look behind the dividend payments of the leading companies helps explain why. For the core business of these companies, there is more money going out than coming in.”  Sanzillo said

 

https://www.chron.com/business/energy/article/Oil-majors-live-beyond-their-means-on-investor-14980162.php

 

 

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10 minutes ago, wrs said:

People don't realize how desolate it is out in West Texas and how far out everything is.  That is why the infrastructure has been so long in coming but it's all falling into place now.  I think the flaring will be reduced substantially this year.  However with NG prices this low, it's not much help to sell it.

New oil pipelines, EPIC, Cactus II and Grey Oak,  have the incremental capacity to bring 1.5-2.0 million barrels a day to Houston/Corpus Christi.  The Oil production to fill these pipes includes associated gas.  Thankfully for the NG prices (unfortunately for the environment) gas Midstream companies are capital constrained or they'd be spending money to gather and process that flared gas.  Estimates of Permian NG flaring range 0.6Bcf/d to 1.5Bcf/d.  The Bakken ranges from 0.4Bcf/d to 0.75Bcf/d.  Imagine what would pricing look like if the infrastructure was in place to flow this gas?  

 

See the source image 

See the source image

image.jpeg.83ea12d025ffc528a8c8d68dc571f39c.jpeg

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(edited)

17 minutes ago, ceo_energemsier said:

Shocking, just shocking!!! Not just a shale fiasco but an entire industry fiasco!!!(sarcasm)

Does this mean that the "shale deniers" should go after these majors as well and tell them to shut down because they are not sustainable? That includes conventional oil and gas !!!!

 

 

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‘A sector in disarray’: Oil majors live beyond their means on investor payouts, study finds

 

 

A Chevron drilling operation in Texas. A think tank that favors renewable energy released results of a study that it says shows oil companies are “a sector in disarray.”

 
 

The largest oil and gas companies for years have lived beyond their means and paid more money to investors than they can reasonably afford, according to a new report.

The study from the Cleveland-based Institute for Energy Economics and Financial Analysis found that the five largest Big Oil majors — Exxon Mobil, Chevron, Royal Dutch Shell, BP and Total — spent $536 billion on shareholder dividends and stock buybacks since 2010 while bringing in just $329 billion in free cash flow.

“The oil majors are consistently under-performing the market and may believe that shareholders won’t notice, as long as they receive generous dividends,” said Tom Sanzillo, co-author of the report and director of finance for the institute, a think tank that supports renewable energy. “As these companies continue to sell off assets and acquire more debt, they reveal a sector in disarray.”

 

This study covers the period of the last oil bust from 2014 to 2017, when a lot of companies limited their reductions in dividends in buybacks — as revenues fell more sharply — to stop investors from abandoning their firms. BP also was a shrinking company during most of the last decade, selling off many assets after the 2010 Deepwater Horizon tragedy in the Gulf of Mexico.

 

The study found that asset sales — from BP and others — played a big role in funding dividends and buybacks. The study noted that Shell, for example, sold $68 billion in assets from 2010 through late 2019.

 

Of course, Shell also bought the London-based BG Group for $53 billion in 2016 and, as a result, sold many assets to help pay for the megadeal and reduce debt.

The institute also highlighted the decision this week by the world’s largest fund manager, BlackRock, to better align itself with the Paris climate accord goals and invest much less in energy companies, starting with coal companies and utility firms that rely on coal. So there’s an ongoing investment move away from the energy sector.

“Investors are gradually moving away from energy stocks. A look behind the dividend payments of the leading companies helps explain why. For the core business of these companies, there is more money going out than coming in.”  Sanzillo said

 

https://www.chron.com/business/energy/article/Oil-majors-live-beyond-their-means-on-investor-14980162.php

 

 

Ahhhh   The Houston Comical; a once great newspaper.  LOL

No doubt capital hates energy.  I believe it's the worst performing sector of the stock market over the last 10 years.  None other than Warren Buffet stated in early 2019 that Pension Funds, Endowments, Insurance companies, Family offices are kidding themselves if they aren't writing down the value of their energy investments.  The Private Equity industry shifted in 2016 to raising bigger funds.  The point was THEIR compensation; 2% management fee 20% return.  The point was to collect the 2% management fee when capital was deployed.  2% of a $5B fund raise is $100mm for the principals.  It almost doesn't matter if the investments make money.  

Back to the article, these companies can either fight to stay alive (drill, cut costs, innovate) or just roll over and die.  It's not in an oilman's DNA to roll over and die.  They will fight to stay alive and many will die fighting.

  

Edited by Bob D
grammar spelling bias overhype

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5 minutes ago, Bob D said:

New oil pipelines, EPIC, Cactus II and Grey Oak,  have the incremental capacity to bring 1.5-2.0 million barrels a day to Houston/Corpus Christi.  The Oil production to fill these pipes includes associated gas.  Thankfully for the NG prices (unfortunately for the environment) gas Midstream companies are capital constrained or they'd be spending money to gather and process that flared gas.  Estimates of Permian NG flaring range 0.6Bcf/d to 1.5Bcf/d.  The Bakken ranges from 0.4Bcf/d to 0.75Bcf/d.  Imagine what would pricing look like if the infrastructure was in place to flow this gas?  

 

See the source image 

See the source image

image.jpeg.83ea12d025ffc528a8c8d68dc571f39c.jpeg

Great info.

But the capital constraint is also a problem for LNG terminals on both ends. Yet 30-40% growth rates are there despite all that. On the consumption side for LNG and NG on the final markets, that too requires huge amounts of capital to transition from coal to NG (or renewables where relevant), for petrochemical feedstocks, and for shipping engines/ships. The LNG bunkering ships are coming to market slowly as the LNG powered ships come online.

The funny thing is that economically, it produces the same final goods levels (perhaps a bit more) but consumes lots of capital to end up with lower prices. The central banks have been scratching their heads the entire decade as the NG (and oil) abundance crashes decades of models incorporating depleting resource economics, many of which do not even acknowledge the existence of natural resources that are, nonetheless implicit in their economic data. .It also means that banks can't obtain positive spreads on interest (paid vs received - NIM).. That creates a slow monetary expansion and a decay of the global payments system, while central banks stare in disbelief and pile on more regulations to prevent the inevitable blowups inherent to slow or negative monetary growth. Shale has been disrupting the world more than the internet has, but central bankers don't see it because it is not in the final numbers but upstream. That is outside the macroeconomic Fisher-Keynes models for which the actual economy is a black box. 

Re the nat gas hedging, the forward curve will rise with LNG orders being hedged long by the intermediaries as contracts are inked in EU and SE and N Asia. The contango to outside the peak season should increase more. I don't know any producer but perhaps EQT (expect breakeven at <$2) selling into long dated futures at <$2.20. . .  

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