Guest “you can’t win them all” by David Middleton
Apache calls it quits on Alpine High after $3 billion charge
Rachel Adams-Heard, Bloomberg, Thursday, February 27, 2020Apache Corp. is officially calling it quits on a highly publicized but disappointing shale discovery in West Texas after vehemently defending the prospect for about three years.
The Houston-based company posted a roughly $3 billion writedown on its Alpine High project, a find from 2016 that fizzled when it turned out to hold more natural gas than oil. Apache will instead focus on offshore riches in Suriname, where the explorer recently struck crude and enlisted French oil titan Total SA as a partner.
“Apache has no current plans for future drilling at Alpine High,” Clay Bretches, chief executive officer of Apache’s pipeline spinoff, Altus Midstream Co., said in a statement.
[…]
The Alpine High was announced in September 2016 to much fanfare and claims the field held 3 billion barrels of crude and 75 trillion cubic feet of gas. But it quickly became apparent that that corner of the prolific Permian Basin was far richer in natural gas and its byproducts than more-valuable oil. The Alpine High became even more worrisome for investors as gas supplies in the region ballooned and prices cratered.
[…]
Houston Chronicle
Part of the problem is the news media’s consistent conflation of resources & reserves, field & plays and fields & basins. The assumption seemed to be that Apache had discovered a giant oil field with proved reserves of 3 billion barrels (Bbbl) of oil and 75 trillion cubic feet (Tcf) of natural gas.
Apache discovered a giant oil field in Texas and its shares are leaping
Swetha Gopinath and Ernest Scheyder, Reuters Sep 8, 2016
Apache Corp announced a major oil discovery in Texas on Wednesday, the latest sign the strongest shale companies are not only surviving the steepest price crash in a generation, but growing despite it.
Apache’s shares spiked as much as 14 percent to $58.99 in early trading after the company said it had assembled contiguous parcels of more than 300,000 acres for $1,300 an acre in the field it calls “Alpine High,” most of which is in Reeves County, Texas.
[…]
Apache estimated that its acreage holds about 75 trillion cubic feet of mostly wet gas and 3 billion barrels of oil in the Barnett and Woodford regions of the field. It also said there is significant oil potential in the shallower Pennsylvanian, Bone Springs and Wolfcamp formations.
The company cautioned that it has yet to determine the precise boost to proved reserves.
“This really is a giant onion that is going to take us years and years to peel back and uncover,” Chief Executive Officer John Christmann told analysts at a Barclays conference on Wednesday.
[…]
“This is a world class resource. You’ve got reservoir consistency, continuity, which is going to lead to very repeatable and predictable drilling results and targets.”
[…]
Apache said it has identified 2,000 to 3,000 drilling locations that can make money at $50 a barrel oil and $3 per thousand cubic feet of natural gas. The field has just 19 wells on it now.
To move product to market, Apache needs to install gas processing infrastructure in the field, beginning with temporary capacity in the second half of this year.
[…]
Business Insider
“Alpine High” may very well, still be “a world class resource”… The problem is that it was mainly a gas resource in 2016. 75 Tcf of natural gas is the Btu equivalent of about 12.5 billion barrels of oil, or 12.5 billion barrels of oil equivalent (BOE). 80% of the resource was gas and apparently, the more they drilled, the gassier it became. Since 2016, the benchmark price of natural gas has rarely topped $3 per thousand cubic feet (mcf).
And Permian Basin natural gas prices are much lower than the Henry Hub benchmark.
Natural gas spot prices at the Waha hub in western Texas, located near Permian Basin production, settled at $1.55/million British thermal units (MMBtu) on August 15, the highest price since March 2019. This price increase coincides with the 2 billion cubic feet per day (Bcf/d) Gulf Coast Express Pipeline (GCX) preparing to enter service. GCX will provide much-needed additional natural gas takeaway pipeline capacity from the Permian region of western Texas and southeastern New Mexico.
Limited natural gas pipeline takeaway capacity from the region has kept prices very low, or even negative, in recent months. During the first eight months of 2019 (through August 19), the Waha spot price averaged just 65¢/MMBtu. The Waha spot price has been consistently lower than the Henry Hub spot price—the national benchmark price for natural gas.
EIA
Furthermore, resources aren’t reserves. Apache’s 15.5 billion BOE was the estimated oil & gas in place, not the recoverable oil & gas.
Apache’s “giant oil field” discovery had long been recognized as a potentially massive “shale” gas resource.
LOWER 48 EXPLORATION: ALPINE HIGH
Questions about this new discovery abound—as do the barrels of oil equivalent in place. Here is an introduction to the Lower 48’s newest resource play.Nissa Darbonne, Editor-At-Large
Thu, 01/05/2017
In a 2006 paper, Denver-based consulting firm The Discovery Group Inc. reported that the Barnett Shale potential of the southern Delaware Basin may contain 800 trillion cubic feet (Tcf) of gas across a 12,000-square-mile area. Bob Cluff, the firm’s late founder, said that “Reeves County is the gas-in-place sweet spot.”
At the time, at least a dozen operators were examining the Barnett and underlying Woodford Shale’s potential in the heat of horizontal Barnett success in the Fort Worth Basin. Soon, many turned their capex to other promising unconventional-resource plays, however: the Bakken, Marcellus, Haynesville and Eagle Ford.
Cluff concluded about the Delaware targets, “Whether this shale can actually deliver gas at commercial rates remains to be seen… [It] will take at least 50 wells before industry knows if it can deliver like the Fort Worth Basin’s Barnett.”
The play resurfaced in early September with Apache Corp.’s announcement that it had zeroed in on the sweet spot, calling it “Alpine High,” and that it has a plan for monetizing it. John Christmann, CEO and president of Apache, told Investor that a newly recruited team—led by Steve Keenan, formerly an exploration manager for EOG Resources Inc.— joined Apache in 2014 to look for new resource plays in the Lower 48.
[…]
Hart Energy
Preliminary indications were that the Alpine High region, unlike the rest of that part of the Delaware Basin would be in the oil window and have lower clay content… making for an ideal “shale” oil play.
But, Apache mostly found gas…
Apache CEO Shares Insight On Permian’s Alpine High
Perceptions have changed for the better for the emerging oil and gas play as activity increases and others move into the neighborhood.Velda Addison, Hart Energy
Thu, 10/11/2018
HOUSTON—When Apache Corp. (NYSE: APA) stepped into the Delaware Basin’s Alpine High area in 2015, the company’s perceptions did not come off as a ringing endorsement: complex geology with uneconomic dry gas, infrastructure assets with minimal value and a lack of endorsement from the industry.
But today’s reality, as outlined by Apache CEO John Christmann, has put those prior perceptions to rest.
“What we’ve proven today is we’ve got 6,000-ft column and multiple targets, high BTU gas and improving oil production as well and there is a lot of wet gas,” Christmann told a crowd gathered for RBN Energy’s PermiCon. “We now have decades of high-return inventory that we are excited about.”
[…]
Apache’s vertically-stacked emerging oil and gas play sits in the Delaware Basin, mostly in Reeves County, Texas. The company announced the discovery in September 2016, estimating 75 trillion cubic feet of rich gas and 3 billion barrels of oil in place in the Barnett and Woodford formations plus potential in the shallower Pennsylvania, Bone Springs and Wolfcamp formations.
[…]
Apache exited July with a net production of about 54,000 barrels of oil equivalent per day (boe/d) at Alpine High. By 2020, that is expected to climb as high as 180,000 boe/d, with between 350 and 375 wells on production and between 425 and 450 wells drilled. The company plans to run between 10 and 11 rigs.
In September, rich gas processing capacity for Altus Midstream was at 380 million cubic feet per day (MMcf/d) and lean treating and compression at 400 MMcf/d. If all goes as planned, this will increase to about 1,300 MMcf/d and 480 MMcf/d, respectively, with five cryogenic processing plants operational by year-end 2020 as Alpine High transitions to full-field development.
[…]
Apache has focused most of its drilling and testing in the Northern Flank, primarily because of the way its lease was set up, Christmann said. “The rest is along the bottom of the Woodford because we had to drill down to the base of the Woodford to hold the acreage.”
Going forward, the company will move up the column and into more of the wet, richer gas and oil, he said.
“It’s a very, very large resource. What makes it unique is in this area of the Delaware, the Woodford and the Barnett are windows that are wet gas and oil generating,” Christmann said. “As you move farther east the Woodford and the Delaware subside away,” giving way to a deeper dry gas type of setting, he added.
[…]
Hart Energy
As of the end of July 2018, Apache’s production was about 54,000 BOE/d… But their rich gas processing capacity was over 60,000 BOE/d (380,000 Mcf / 6). It’s pretty clear that most of the production was gas. Even with a decent liquid yield, Permian Basin gas is pretty well worthless, with prices often falling below $0/Mcf. This is why so much Permian Basin gas is flared.
In this business, large discoveries are usually the result of “thinking out of the box”, like Apache did here and Shell did in the Chukchi Sea. Occasionally, this will lead to a major discovery that everyone else missed… Here in this office, we call these Unicorns… It’s actually our company’s unofficial mascot. And it appeared that Alpine High might have been a genuine Unicorn.
Meanwhile, Mike Kelly, senior analyst for Seaport Global Securities LLC, wrote that some doubters “question how Apache’s knowledge of the acreage could be superior to its surrounding Permian peers.” From meeting with Apache management, Kelly and the SGS team found that it is the only operator that has shot 3-D seismic over all of the leasehold and pulled core.
Hart Energy
However, most of the time, it turns out that the consensus was right… And Alpine High turned out to primarily be a gas resource. There isn’t always a pony in the pile of horst schist under the Christmas tree.
OK, David, Apache wrote-off $3 B in sunk funds for their Alpine High play. Did they actually abandon/drop/return the lease, or did it go to standby, or did they vend it to other natural resource company with an override? This is still a lot of natural gas, and someday in the future, either due to price rise or technology advance, it could well be quite economic. For sure your story shows the tremendous amount of oil and gas production capacity in the USA, let the rest of the world fight over the other plays. Trump 2020 will keep our foot on the gas pedal!
They will continue to produce what they have drilled, but won’t put any more capital into it an the leases not held by production will expire. My guess is that they will try to sell the producing leases and gas processing infrastructure.
The Permian Basin remains a YUGE, effectively infinite, resource. In 100 years, or so, when gas gets back up to $5-6/mcf, Alpine High might become economic.
I can remember the Tuscaloosa Trend field in south Louisiana back in the early 1980s where drilling for $10/ M gas at 20,000 feet was going like gangbusters. The law of supply and demand setting prices is ironclad.
Yahoo for fracking gas!
Just curious, is the 100 year window for US methane gas pricing tongue in cheek?
I hope so… But, I don’t see anything short of a frac’ing ban driving them back over $3-4/mcf in my lifetime.. I’m 61.
I must say, as a geologist, I love reading your work.
The U.S. has 100 years of gas at $5-6/mcf. I tell people to imagine all the oil and gas extracted in the last 100 years. Then imagine we have 2-3 more entire Earth’s to extract from. That is what fracking accomplished. I just don’t see us running out, ever.
What we are doing now, regarding fracking, is just a tiny fraction of what we could be doing, if prices were higher.
Russia, Libya, Venezuela, Iran. Look at all the supply side disruptions we have had over the last 10 years. What has been the price response? A shrug. A little more fracking fixes any and all price disruptions. And any price spikes just increase the number of EVs and solar panels, immediately destroying demand.
David by comparison what are the morons in Connecticut paying for Russian LNG?
I see Cheniere Energy beat estimates at $.71/share-promising. Do you have financials that would justify US firms competing with the Ruskies? Billions of investment though. And would the Feds ever pass legislation forcing Connecticut and California to buy US produced oil and LNG?
Great article as always making my day.
We compete with the Ruskies… The problem is that Permian Basin gas, unless it’s associated with oil production, is basically worthless.
Exactly. It would be worth quite a bit in the Socialist Republic of Massachusetts – if they could only get it there.
Big finds (oil or gas either one) are great, but the infrastructure to move it to where it is needed can be lacking. North Shore product would be worthless without the Alaska pipeline.
I really didn’t like writing this one… I prefer happy endings.
Maybe they could let the escaping gas spin a wind turbine? Or not…
I agree — seems all goobermints absolutely LOVE electric-pinwheels, so why not light the escaping gas thru a nozzle & direct it at one of the ubiquitous pinwheels equipped w/ceramic blades?
David,
Why couldn’t Apache build a LNG plant and export the gas to obtain much higher prices?
An LNG plant in Reeves County?
LNG plants are located in ports.
David,
You will have to forgive my ignorance of Texan geography.
I apologize if I came off as rude… It just made me laugh, because Reeves County and the Permian Basin are a long way from the coast. They did recently open a new pipeline to take gas to the Gulf Coast, but it didn’t increase prices enough to make projects like Alpine High economic.
David,
What about the GTL process that Synfuels International has developed. Small scale GTL platform. Is that a viable process?
A GTL plant is supposedly in the works.
https://www.ogj.com/refining-processing/article/14073851/texas-due-new-gtl-plant
However, the GTL operator isn’t going to pay much, if any more for the gas, than the Waha price.
I worked for a private company where the owner would systematically go through all the data we could control and predict. When had done all our homework and we got to the unknowns, he’d say, “well, that’s the good ol’ oil biz, let’s drill and find out”. If someone isn’t comfortable with that stage, they need to find a different line of work.
Yep. All the science in the world doesn’t change the fact that you still have to drill it, to know what’s there.
David,
In a nutshell, that is the difference between resources science and climate research. With resources, if you need more data, you get it or stop. With climate, if you need more data, you invent it and continue. Resources targets are real. Nature put them there. No point in faking. If your work is bad, you end up driving cabs. Climate is real, Nature put it there, but you cannot see, touch, smell it like a resource find. Climate researchers are not accountable because their Target is their imagination of a resource, what suits them. If their work is bad, they still end up being paid, flying to lavish conferences to tell each other how good they are.
What a horrible way these climate people have treated science.
David, you can’t view this as an “unhappy ending” only – from a high level view, this is great – a demonstration of free markets effectively allocating capital. Imagine if Alpine High was a government project; they would waste another $3 billion or more before it was dropped, if then.
I suppose I should also look at every “shale” “unhappy ending” as less oil and/or gas on the market and a potentially happier ending for conventional players like us… 😉
What terrible news: huge gas resource was discovered.
Huston we have a problem… with basic understanding what word ‘reach’ means.
Reach doesn’t have monetary, but utilitarian meaning.
Thanks to all the deplorables working all days long, USA is so rich in gas that it can’t exchange it even against heavily inflated paper money.
Many countries in the world would wish to have same problems.
At least, maybe, this will help with the light pollution off to the north of the McDonald Observatory. It’s like a Dallas-sized city has sprung up there in the last few years.
I had to laugh. Several years ago I took my family up to the Kitt Peak Observatory for their star talk and group tour of one of the big telescopes. I bought our tickets months ahead of time. Kitt Peak is about an hours’ drive outside of Tucson and nary a Navajo hogan in sight in the wide valley between. They caution drivers coming up the peak to turn their lights off, but as we arrived late for the talk, and after dark, and the switchback road to the summit is a bit tricky, I ignored this rule. I drove slowly and carefully. When I got to the group session at the top, I was given a stern rebuke – something about stargazers who rented time on the telescopes. I said I was sorry, but mostly I was embarrassed. They still gave us our box lunches but they were not amused, and I like to imagine that my headlights panning across their viewing horizon must have looked kind of spectacular. Wish I could have seen it.
Kitt Peak had one of the first big telescopes in the States and they spent a lot of time looking for near-Earth asteroids up there.
It’s a shame that it would take billions in investment to turn that cheap natural gas into valuable intermediates like methanol, ammonia, or ethylene. I hate the economics that result in flaring a plentiful source of energy.
Even turning the gas into electrical power would require billions in investment. There are definitely areas where the electricity could be utilized. Getting electricity out of the gas would be better than releasing the heat value directly to the atmosphere.
I f grid connections are reasonably close perhaps converting the gas to electricity is an option. Of course the price of electricity must be advantageous.
https://www.ge.com/power/gas/gas-turbines/tm2500
Better than they did in KS with the horizontal Mississippi Lime play. They leased half of two counties at about 10,000% the going rate … where there was no Mississippian.
Thanks David, I remember that 3-Stooges episode. Curly “riding” on top of the oil-geyser….. 🙂
“It’s a geezer! An oil geezer!”
It is good that people are seeing what Wolf Street showed, here commented :
https://wattsupwiththat.com/2020/02/11/us-chamber-of-commerce-what-if-we-banned-fracing/#comment-2914242
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The Great American Shale Oil & Gas Bust: Fracking Gushes Bankruptcies, Defaulted Debt, and Worthless Shares
by Wolf Richter • Jan 22, 2020
Texas at the epicenter. We’re witnessing the destruction of money that loosey-goosey monetary policies encouraged.
——
Yet again is no mention of this – a financial blindspot, what?
Anyway, the so-called US “fracking revolution” starts to look just like the “German Great Energy Transformation” – and that’s downright embarrassing!
It is high time to go for higher energy density power – in no way thereby saying turn off “fossil”, as Sir mini-Mike Bloomberg promises. Such an energy economic platform is not geological – it puts the limelight on economics.
I love my man Middleton.
However, dear old Apache has always had the reputation of (and, in fact, been), ahem, “promotional.”
Yep. I didn’t go into that particular aspect of this… But, elements of the story made me think of McMoRan and Davey Jones.
The worst of all time was Jim Bob Moffett at Freeport/McMoRan.
Everything that came out of that man’s mouth was either a wild exaggeration or or a flat-out untruth. He got away with it for decades because the Wall Street investment bankers (i.e., the “sell side”) got paid a lot of money from his serial empire building M&A and corporate finance deals.
I don’t know if I would go quite that far… But he was definitely a promoter… And the team that put together Davy Jones and the rest of the deep Wilcox shelf play were big time promoters as well.
“Promoters” LMAO. Okay that is one VERY polite way of looking at it. I’ve heard them called a lot of things but that has to be the nicest.
If you get tired of your current work David you have a great future as a publicist.
Great article as well and I agree it is sad that it can’t be put to use. Like you say, can’t win them all.
Curious, why is dry gas found underneath wet gas and oil? Seems backwards. A gas should be above its liquid state, not underneath it. Appears I have more reading to do…
The deeper you go, the hotter it gets. Heat cracks the wet gas and oil to dry gas. If they can migrate up and mix, yes, the gas will end up on top, but if they stay in their rock layers more or less, dry gas is found deeper.
And then there is gas prone vs oil prone source rock. Some organic matter geochemically tends to cook into gas more than liquids. Coal is a good example of gas prone source.
Temperature. The deeper formations are too hot for oil.
Thanks Doug. Spot on.
I found more on this subject here:
https://offshoreengineering.com/oil-and-gas/petroleum-geology/1-hydrocarbon-formation
under 1.2.2 Maturation
As Doug pointed out, the deeper you go the higher the temperature. Lower temperatures favor the formation of liquid petroleum, higher temperatures favor a mixture of lighter hydrocarbons that when found together are called “Wet Gas”, and even higher temperatures favor the formation of primarily methane gas (or “Dry Gas”).
If the gases are mobile, you end up with the typical picture of a reservoir that I am familiar with – that is a gas is on top and the petroleum beneath it. If the gases are not mobile, they can end up possibly trapped beneath liquid reserves – or there can be multiple capping formations involved separating different deposits.
It was interesting to see the different definitions of “Dry Gas” versus “Wet Gas”, but essentially if you have somewhere in the neighborhood of 20% butane, propane, and other hydrocarbons you have wet gas. Apparently some of this can also be water vapor in the gas flow. They remove the water before the gas enters a pipeline for transport to avoid freezing, and then use various forms of fractional cooling to separate the various hydrocarbons. Because wet gas produces useful chemical feed-stocks, it is more valuable than a dry gas.
Well, this was fun… Never know what I am going to learn next at this site.
It’s not water vapor, the condensate is natural gas that condenses into liquid once it cools at the surface. This liquid is very light with an API gravity of 55-120. Light crude is between 31-55, medium from 22-31, heavy between 10-22, and extra heavy – dead oil or asphalt – less than 10.
The best analogy I can come up with is cooking an onion. The oil phase is like the translucent phase of cooking an onion. At this point the sugar (oil) has started separating from the fiber. Then the sugars start to caramelize, this is when the sugar molecules start breaking apart and starts to become thicker and many aromatics (natural gas) are released in the wet phase. Then the onion runs out of sugar to break free from the fiber and it is only thickens as it cooks the hydrogen and oxygen out of the carbon (dry phase). If you cook long enough you run out of hydrogen and oxygen to cook out and are left with nothing but black carbon (asphalt/gilsonite).
Thank goodness my homemade French Onion soup doesn’t do that…
What does a “negative price” for natural gas mean? I can understand that if a gas well is too far from an established pipeline, clients may not be willing to pay anything for the gas, if the cost of piping it to market is higher than the price the pipeline company can get, but in that case, the seller can plug his well and leave the gas in the ground, waiting for a better market. But does Apache really need to pay someone to take their gas? It doesn’t make sense…
It means you have to pay the pipeline operator to take your gas.
You can’t plug the well and produce it again. If you plug the well, the lease is off production and expires.
It would appear that making a decent profit in the oil & gas business requires a mix of excellent technical know-how combined with better-than-average business management competence.
I guess this means it will be to my heirs to see anything from our northern Eagle Ford property…..maybe a couple of generations out.
Hi David,
I would like to discuss with you a rational energy strategy for North America – Canada and the USA. Some preliminary thoughts:
USA capital has been over-invested in fracking and this has cratered the price of oil, and especially the price of natural gas. Capital destruction, especially in the USA, is enormous. Field performance on average has been less than forecast and full-cycle economics do not support much investment at current prices. Ultimately, market forces will prevail and oil and gas prices will recover and solve this problem.
CO2 is NOT a harmful emission and CO2 abatement programs, based on false unscientific hysteria, are costly, imbecilic and harmful to humanity and the environment. Increased atmospheric CO2, whatever the cause, is hugely beneficial due to significantly-increased plant and crop yields.
Therefore, almost all forms of “green” energy are uneconomic and ineffective and must be excluded from further consideration. This includes grid-connected wind and solar energy, hydrogen-fuel systems and most or all biofuels, including corn ethanol. The one green technology that makes sense is waste processing – our cities are overflowing with garbage and it can be processed into fuel and energy.
Nuclear power is proven technology, but there is absolutely no justification for shutting down fossil-fueled power plants and replacing them with nuclear, because CO2 is NOT a pollutant. Such decisions should be based on economics.
As you know, the energy-equivalence of natural gas to a typical crude oil is about 6:1 mcf/bbl (m=1000).
So crude oil at US$48/bbl is energy-equivalent to natural gas at US$48/6 = $8/bbl, but natural gas is typically prices at US$2.00 to $2.50 – so gas on an energy-equivalent basis is 1/3 to 1/4 the price of oil. Everybody in the energy business knows this – it’s been true for decades.
There has been a sensible shift in electrical generation from coal to gas, because gas is cheaper and cleaner than coal. Coal emissions (NOx, SOx and particulates) can be cleaned up, but at a cost. If gas ever gets much more expensive than coal, then we can switch back to coal. Newer coal-fired power plants should be not be demolished, just mothballed as economically appropriate.
The practical solution to greatly improve in-city air quality is to get rid of diesels – and there is little or no need for diesel in cities. Diesels are great for highway hauling, but propane or natural gas (and even gasoline) vehicles are adequate for in-city. We changed the fuel standards for diesel several decades ago, but they still stink – just not as much. I chaired a team that approved the investment of hundreds of millions in a mid-distillate hydrotreater at Syncrude Canada, to improve the cetane index of diesel and the smoke point of jet fuel.
For long haul trucking and rail transportation , it’s hard to beat diesels. LNG has been tried, but my friend who owns a large trucking company says LNG reliability is still an issue. One truck breakdown wastes a lot of money so he doesn’t run LNG heavy haulers. I suggest that we still need diesel fuel for highway haulers and locomotives, at least for a while.
The ~same mid-distillate fraction is used for jet fuel, and I see no practical alternative.
The ~same mid-distillate fraction is used for home heating in areas where natural gas is not available. Ridiculous obstructions to the building of natural gas pipelines should be eliminated and gas should replace oil heating across the continent.
Heavy fuel oil, which is highly polluting, is still used for large ships. Not sure what a practical solution looks like. Suggestions?
Regards, Allan
As recently as about 2005, the 6:1 ratio generally applied to prices.
I generally think that the free market should determine energy policy… However, I think nuclear power and coal are essential to grid resilience. So, I don’t object to the government taking some measures to support them.
It’s not possible to categorically state that CO2 emissions are wholly beneficial. However, the harmful aspects and potential threats have been grotesquely exaggerated. The best way to keep coal-fired plants operating is to make it economical to use the CO2 for enhanced oil recovery.
You have good ideas on transportation, I just don’t think trying to micromanage it will work very well
Micromanage? – not so – I said economics should govern.
I am suggesting a 95%+ reduction in energy regulation – no carbon taxes and other such nonsense.
The only regulation I see as helpful is to greatly reduce diesel in cities – Compressed Natural Gas (CNG) and other technologies are cleaner and cheaper. There are simple cost-effective ways to achieve this.
If I might add my two cents…
I think the rationale at this time for nuclear is in the research to develop better/safer reactors. I agree with David in that economics should drive investment, so using natural gas for electricity makes a lot of sense until it becomes more expensive (and this will happen, just not soon). The same for liquid gasoline for cars – there is still room for improvements to the pollution they emit but there is no good alternative. Diesel is more polluting (particulates) and has more room for improvement.
Nuclear research is likely to take 20 years to produce working advanced reactors at a commercial scale, and there is not really a long term alternative (at least that I recognize). At some point in the future, we need a reliable base-load power infrastructure, and it isn’t likely to be coal in advanced societies (too dirty). It will never be intermittent power sources like solar.
“At some point in the future, we need a reliable base-load power infrastructure, and it isn’t likely to be coal in advanced societies (too dirty).”
Not so, In Alberta, most of our power is generated from from coal and natural gas. Our former NDP government vilified “coal pollution” – but forest fire smoke is ~1000 times worse than coal pollution – coal is quite clean.
I should clarify – I agree with this part of your comment:
“Nuclear research is likely to take 20 years to produce working advanced reactors at a commercial scale, and there is not really a long term alternative (at least that I recognize). At some point in the future, we need a reliable base-load power infrastructure… It will never be intermittent power sources like solar.”
Longer term, nuclear is the answer and it is highly desirable to improve and simplify the technology, especially from a safety standpoint – in the meantime, we have plenty of natural gas and coal.
It seems that GTL to make diesel would be more desirable than gasoline like the Primus project mentioned above, provided that economics are similar. Such formed diesel has superior properties (high cetane, low sulfur, low aromatics, etc.) and would be useful for blending.
GTL to make diesel – waht are the economics?
It’s working in Qatar and Malaysia and has been for many years. It’s just an assumption that the economics work there at whatever the supply and production conditions are. It may be a matter of scale driving the economics.
Shell’s Pearl GTL plant in Qatar “works” because the gas is free. The plant cost $24 billion and converts 1.6 Bcf of gas to 140,000 bbl of liquids per day and it is uneconomic below $40/bbl.
Apache’s gas production from Alpine High is about 1/4 of 1.6 Bcf/d. Let’s say they could find a place to build a GTL plant in Reeves County for 1/4 of what Shell spent… $6 billion.
Apache is writing off their $3 billion investment in a failed oil play… Not looking for a reason to write off another $6 billion.
Thank you all for your comments – here is a concise ~final version.
Best, Allan
A RATIONAL ENERGY STRATEGY FOR AMERICA.
CO2 is NOT a harmful emission and CO2 abatement programs, based on unscientific hysteria, are costly and harmful to humanity and the environment. Increased atmospheric CO2 is hugely beneficial due to increased plant and crop yields.
Therefore, almost all forms of “green” energy are uneconomic and ineffective and must be rejected. This includes grid-connected wind and solar energy, hydrogen-fuel systems and most or all biofuels, including corn ethanol. One green technology that makes sense is garbage processing into fuel and energy.
Nuclear power is proven technology, but there is no reason to shut down fossil-fueled power plants and replace them with nuclear.
The energy-equivalence of natural gas to a typical crude oil is about 6:1 mcf/bbl (m=1000). Therefore crude oil at US$48/bbl is energy-equivalent to natural gas at US$8/bbl, but natural gas is now priced at US$2.00 to $2.50 – so gas on an energy-equivalent basis is 1/3 to 1/4 the cost of oil.
There has been a shift in electrical generation from coal to gas, because gas is cheaper and cleaner than coal. Coal emissions (NOx, SOx and particulates) can be cleaned, but at a cost.
The practical solution to greatly improve in-city air quality is to get rid of diesel – and there is little need for diesel in cities. Diesels are great for highway hauling, but propane or natural gas (even gasoline) vehicles are cleaner for in-city.
For long haul trucking and rail transportation , it’s hard to beat diesels.
The ~same mid-distillate fraction is used for jet fuel, and I see no practical alternative.
The ~same mid-distillate fraction is used for home heating in areas where natural gas is not available. Obstructions to new natural gas pipelines should be eliminated and gas should replace oil heating.
Economics should govern. We need a 95%+ reduction in energy regulation – no carbon taxes and other nonsense. The only recommended regulation is to reduce diesel in cities.
Why can’t they pair this with a gas electric power plant? Is the cost to the electrical grid too high? Probably, there are no subsidies as in lonely desert solar power plants…
“Why can’t they pair this with a gas electric power plant?”
Good question – that is perhaps the best use of this reservoir and it would be highly competitive, without any govt subsidies. The problem may be reservoir location, too far from markets, and the current oversupply and low price of natural gas. Longer term, the reservoir will still be there when prices improve.
Monetization could involve two alternatives:
– Produce electricity using gas turbine generators and ship the electricity – short distances via AC lines or long distances via DC lines.
– Pipeline the gas to markets or to coastal LNG export facilities.
This would make less economic sense than just building an LNG export terminal in the Permian Basin.
Thank you David – my comment was not intended to preclude a new LNG plant.
Alpine High’s distance from the ocean precludes any type of LNG plant.
It would be even less feasible for Apache to build a power plant than an LNG export facility in the Permian Basin.
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/101619-power-sector-working-to-expedite-power-to-permian-basin-oil-gas-production
Agreed David – at today’s very low gas prices – I wrote above:
“The problem may be reservoir location, too far from markets, and the current oversupply and low price of natural gas. Longer term, the reservoir will still be there when prices improve.”
My uncle Donald Fraser MacRae MC said the same thing about the Alberta oilsands – starting in the 1950’s: “It’s money in the bank.”
Canada in 2018 was the 4th largest oil producer in the world and the largest foreign supplier of oil to the USA. About 80% of Canadian oil production is from Alberta, and ~84% of that is oilsands production.
Re DC power lines – this is an old complaint – but it still rankles me. Politicians of all stripes should avoid energy policy – they are susceptible to large bribes and always see to mess it up.
https://wattsupwiththat.com/2017/10/19/doe-secretary-rick-perry-resiliency-pricing-rule-for-coal-fired-and-nuclear-power-plants/#comment-2185775
Here in Alberta the cost of generating natural gas-fired or coal-fired power is about 2-4cents/KWh.
Then this cost ~QUADRUPLES due to the way our idiot politicians have mismanaged the costs of Transmission, Distribution and Administration. Costs also increase due to the addition of unreliable, non-dispatchable wind power.
Alberta recently added a new $2 billion DC transmission line that actually has higher (AC-DC-AC Conversion + Line) losses than the old AC system, because the AC-DC-AC conversion losses are about 5%, much higher than the line losses of the old AC lines (which obviously require no AC-DC-AC conversion).
Then had to take power off the old AC lines and put it on the new DC line – otherwise the new DC line would have run at less than 10% of capacity.
The math IS that simple, but clearly too much for our Alberta politicians.
Warren Buffet owns the new DC line and gets a guaranteed utility rate-of-return from this nonsense.
Preliminary Scoping and Engineering was apparently done by Phoebe Buffet.
“At some point in the future, we need a reliable base-load power infrastructure, and it isn’t likely to be coal in advanced societies (too dirty).”
Not so, In Alberta, most of our power is generated from coal and natural gas. Our former NDP government vilified “coal pollution” – but forest fire smoke is ~1000 times worse than coal pollution – coal is quite clean.
Agreed David – at today’s very low gas prices – I wrote above:
“The problem may be reservoir location, too far from markets, and the current oversupply and low price of natural gas. Longer term, the reservoir will still be there when prices improve.”
My uncle Donald Fraser MacRae MC said the same thing about the Alberta oilsands – starting in the 1950’s: “It’s money in the bank.”
Canada in 2018 was the 4th largest oil producer in the world and the largest foreign supplier of oil to the USA. About 80% of Canadian oil production is from Alberta, and ~84% of that is oilsands production.