All information below pertains to the Bakken unless stated otherwise.
Information below is all personal opinion based on my "reading" of the tea leaves.
I wear "oily-covered glasses" when looking at Bakken data.
This is is posted only for conversational purposes. There will be typographical and factual errors. Do not make any investment, financial, job, travel, or relationship decisions based on what you read here or think you may have read here.
Wells yet to be drilled: 20,000 to 70,000
Time frame: 20 years to 50 years
It all depends on demand.
Tiers:
Tier 1: locations in the Bakken that show increased activity when prices stay below $50
Tier 2 locations move to Tier 1 locations: when WTI trends from $50 to $65
Tier 3 locations move to Tier 1 locations when WTI trends toward $100
Trending now:
12 wells in 1280-acre drilling units in Tier 1 locations
adding those overlapping 2560-acre units to capture "orphan" oil along section lines
setback rules have been changed: we might see more re-entry drilling to extend existing laterals; if extended, the wells will be re-fracked; consider it a new well
Formations targeted:
middle Bakken/Three Forks: about a 60/40 split, I suppose, a "wag"
CLR is the "only" operator routinely testing the second bench of the Three Forks
Re-frack: "every well" drilled/completed before 2014, maybe 2016, will have to be re-fracked; they will be re-fracked based on many criteria, but Tier 1-2-3 will be a good starting point
Best metric to follow right now: "frack team / rig" ratio; I don't have that number for the Bakken
in the Permian, it is being reported today that the "frack team / rig" spread is narrowing (increasing number of frack spreads / rigs holding steady or slowly increasing
500 rigs
150 frack spreads (for newbies: a "frack spread" is oil patch jargon for all the resources required to frack a well -- personnel; equipment; water; sand; ceramic; etc
Permian frack spread / rig ratio: 30 percent
Permian rig / frack spread: 3:1
Boom vs manufacturing stage:
the Bakken is said to be in the manufacturing stage
the Permian: still in the boom stage
For newbies: the best way to determine when a tight field/basin has transitioned from "boom" to "manufacturing": when pad drilling becomes the norm
one is definitely in the manufacturing stage when mega-pads (at least 6 wells per pad) become the norm
The Permian:
Production at the Permian Basin, the largest shale play, is set to
exceed 4 million barrels per day for the first time in March. As such,
this shale play alone significantly exceeds the amounts produced by the
United Arab Emirates, Brazil and Kuwait. Only five countries produce
more oil than the Permian Basin, excluding the US.
February 12, 2019: continuing the discussion --I have looked at almost 1,000 scout tickets from file number #28000 to #28700, and then #18000 -- #18037. Some observation, with regard to "Bakken" wells. Again, this is from the scout tickets alone, regarding the "pool" designation:
almost 100% of scout tickets designate "Bakken" as the pool; the only ones not designated as "Bakken" are about ten "Bakken/Three Forks" pool wells in Keene oil field
the "Bakken" is designated as the pool regardless of whether the formation targeted is the middle Bakken or any of the benches of the Three Forks
of the almost 1,000 scout tickets I have looked at so far, one field is unique: every "Bakken" wells in the Keene oil field is designated at "Bakken/Three Forks" on the scout ticket. This is regardless of operator, and extends back to the first "Bakken" well to the most recent "Bakken" well
I have found not one scout ticket that designates the pool at "Three Forks"
the fields immediately surrounding the Keene oil field, all use the "Bakken" pool designation and not "Bakken/Three Forks"
looking at the geologist's reports for Keene oil field, the field has the typical geology seen across the Williston Basin where the Bakken exists: upper Bakken, middle Bakken, lower Bakken, Three Forks (benches may or may not be separated out), Birdbear
there are a dozen or so "Sanish" wells but that designation is better understood
February 10, 2019: The original post brought us full circle to an issue that we discussed in the early days of the boom.
A reader responding to the original post has it exactly right.
His interpretation helps explain what I was missing and what I could not figure out and why I was so confused. For now, I will post the reader's interpretation -- which I think is exactly on target -- and perhaps later, make some additional comments. It's a long note, but the bottom line is that the "Bakken" production referenced in the original post includes both the middle Bakken and "most/all" of the Three Forks wells, all benches, drilled during the Bakken boom.
If I correctly understood your comparisons of Bakken and Three Forks production by years, I think there might be something lost
in terminology.
The ND Oil and Gas Division has chosen to use the term “Bakken” for all zones from 50 feet above the upper Bakken shale to
the top of the Bird Bear formation. This group term includes the middle Bakken and all four benches of the Three Forks. In
this case the name Bakken does not mean only Middle Bakken.
When you review the individual well files, the group name “Bakken” includes about 6500 middle Bakken wells and 5500 Three
Forks with some over 80% of these being 1st bench, with balance being mostly 2nd bench and only very few 3rd bench. The
wells in Divide County and southern Billings County are mainly Three Forks wells but by the ND O&G group definition of “Bakken”,
these Three Forks wells are included as Bakken wells. I guess this overlapping naming system makes it easier in writing
and enforcing regulations, but is makes it confusing when trying to get detail on which specific zones of the Bakken/Three Forks
complex are involved in oil and gas production.
The ND O&G production summery includes zones such as Bakken/Three Forks and Three Forks only. Many of
the wells in these categories are old vertical wells which were completed in overlapping zones. Some might be newer horizontal
wells which were drilled on the edges of the basin where the lower Bakken shale is not present and the horizontal well made
intermittent contact with both the middle Bakken and Three Forks bench one.
The Three Forks wells do make a major contribution to ND oil and gas production but their production is often lost in
the group name “Bakken”.
The reader provided his methodology:
FYI, here’s my methodology. I took each township in what appears to be the core area and assigned it an EUR potential. This included the number of pay zones (MB, TF 1, 2, 3) and their quality which
resulted in an ultimate potential of each spacing unit in that township. I did the same for each township in non-core areas. Most of these non-core units have only two pay zones and some only one. It was an
interesting challenge.
Now technology and the price of crude can take over and do their magic!
The last two years have brought unbelievable changes.
Original Post
With Some Editing Following The Reader's Comments Above
30-second elevator speech:
production from the Bakken, calendar year, 2017: 360 million bbls
production from the Three Forks, calendar year, 2017: 2 million bbls
USGS 2013 Survey, technically recoverable oil
Bakken: 3.7 billion bbls
Three Forks: 3.7 billion bbls
*********************************************
The Post
Production in the Williston Basin by formation (link here):
YEAR
Bakken
Three Forks
2017
361,131,625
1,713,089
2016
348,961,329
2,063,186
2015
397,684,040
3,198,603
2014
361,654,835
3,477,315
2013
284,554,268
1,631,693
2012
215,490,552
735,568
2011
126,178,063
563,459
2010
85,075,338
464,976
The graph:
Modified graph: it is impossible to see the Three Forks production in the graphic above, so I modified the graph by changing the middle Bakken production -- moving the decimal to the left by two spots. In other words, in the graph below, for it to be accurate, the middle Bakken production is 100x more than shown. The Three Forks data is unchanged.
Note: this was done quickly, not triple-checked and there are likely to be typographical and facutal errors. If this information is important to you, go to the source.
**************************************
Number of Wells Drilled In North Dakota, 2000 - 2017
Includes all wells, including salt water disposal wells and injection wells. Link here.
Year
Number of Wells
2017
1,033
2016
756
2015
1,579
2014
2,350
2013
2,176
2012
1,995
2011
1,300
2010
862
2009
522
2008
581
2007
359
2006
317
2005
240
2004
223
2003
216
2002
164
2001
190
2000
138
The graphic:
Production:
And imagine: the Bakken is said to be "peanuts" in size compared to the Permian. Can you imagine?
***********************************
Idle Calculations
Using Back-of-the-Envelope
In round numbers, the Bakken/Three Forks first bench is producing 400 million bbls of oil each year.
Over twenty years that translates to 8 billion bbls of crude oil. Not boe but crude oil.
Some folks think that "they" will drill for 70 more years. Let's say 50 years.
Unfettered, it was assumed by some that the Bakken could produce 2.2 million bopd.
Let's say 1.5 million bopd, not much more than the current production rate.
x 365 days = 550 million bbls/year (which is in the current ballpark of 400 million bbls/year).
x 50 years = 27,750 million bbls or nearly 30 billion bbls.
A reader asked: If a well is on confidential (with the 6 month experation date listed)
and does not appear on frac focus data base, does that mean is was never
fracked? ie a DUC?
My not-ready for prime-time reply:
I'm not sure if I understand the question, but here are my observations and understanding (not necessarily factual).
1.
"Every" Bakken well is eventually fracked. There are exceptions. That's
why "every" is in quotes. Just as I say there is "never" a dry Bakken
well.
2. In the "old" days, wells were drilled and then completed
(fracked) almost immediately. You can assume any Bakken well drilled
(with a test date) before the end of 2012 was fracked, but prior to 2012
(or some such date; I forget exactly when) FracFocus won't have the
data. Operators did not have to provide data to FracFocus until after
2012 (or some such date; I don't know the exact date). But when I see a
Bakken well drilled before the end of 2012 and there is no frack data, I
assume it was fracked, just not captured by FracFocus.
3.But even for wells drilled before 2012, the NDIC will have a frack report in the file folder.
4.
In the old days, the operators had one year to complete the well (to
include the frack) after it was first spud. Around late 2014 (I forget
exactly when), operators were given two years to complete (to include
the frack) from the date the well was first spud (there are some legal
arguments about "first date the well was spud" -- but that's another
story.
5. Operators can now drill wells in about 10 - 30 days;
many wells remain in "DRL" status while the rest of the wells on the
same pad are being drilled. Technically, they are drilled but
uncompleted (DUCs) but they are not given that classification if the
operator plans to complete them once all the wells on the pad are
drilled, and if the operator plans to frack them in quick succession.
The wells are generally on CONF status at this time; maybe DRL status:
and remain on CONF status until the six month conf status is up. Those
wells are never (administratively) DUCs.
6. If an operator drills
a well (or a number of wells on one pad) with the intention of drilling
to depth (TD = total depth) but not planning on completing them until
after six months or longer (up to two years) they are administratively
DUCs -- drilled to total depth (including the horizontal leg) and then
shut in -- for months, or maybe a year or so -- until the operator goes
back in and fracks the wells. During this period the well is DUC (SI/NC
-- shut in/not completed).
7. At the time the well is fracked,
the operator sends that information to FracFocus (there must be a
regulation that requires contemporaneous reporting / timely reporting,
even if the well is administratively a DUC). This is where it gets
tricky. I can find an SI/NC well (administratively) -- the paperwork has
not caught up with the folks at the NDIC) but I can go over to
FracFocus to see if it has been fracked. If a DUC (SI/NC) well is
producing a significant amount of oil, I assume it has been fracked, and
FracFocus will confirm it.
8. "Modern wells" -- wells drilled
after 2012 (or whatever the date was) will have a FracFocus report, it
seems to me, almost as soon as the well has been fracked. I'm not sure
what the time lag is but it can't be much.
9. I did not proofread the above; there are probably typos. I don't know if I answered the question.
10. If you are looking at a specific permit / well, I can look it up and give you my opinion what is going on.
11.
Having said all that, there are occasional -- very rarely -- Bakken
wells that have never been fracked. But if the operator has no intention
of fracking them and they are producing and they are off the
confidential list, they are NOT considered DUCs. A DUC means that it has
been "drilled, but not completed." An operator can complete a well
without fracking it. There is much to do to "complete" a well, to
stimulate a well, even if it's not fracked. Vertical wells, for example,
are not (generally?) fracked, but they are stimulated.
Remember: this article is from a year ago, during the early stages of the "depression."
It's a long article and covers many areas, so let's go through some of the data points with my comments thrown in.
Most remarkable prognostication from the article, from Mark Papa, "a legendary figure in the shale fraternity and now at Riverstone Holdings":
“I can see a case where US shale is the biggest supplier of oil in the world by 2020. We could turn the whole thing on its ear, producing 13-14m b/d. But it will be really ugly getting through this valley,” he said.
Most interesting comment from the article, also from Mark Papa:
Mr Papa said it will not be long before engineers work out how to double the efficiency of shale extraction to the 50 percent levels seen in conventional oil wells. "It'll probably come in the next ten years. That's the next big break-through," he said.
For newbies, as I understand it, Mr Papa is talking about "primary production" and does not include enhanced oil recovery using waterflooding or CO2 injection.
This raises the question: what is the current primary production estimated to be in the Bakken? At the beginning of the boom, it was widely accepted that primary production would range between 1 and 3 percent. For a 500-billion bbl original-oil-in-place reservoir, that worked out to 5 to 15 billion bbls.
Around 2014 or so, Whiting and others were suggesting that operators were achieving 7% primary production in the Bakken and reading between the lines, it appeared that some operators might have been achieving as much as 12% or at least trying to hit that target.
At 10% primary production, a 500-billion bbl original-oil-in-place reservoir works out to 50 billion bbls of recoverable oil.
Currently, the Bakken is producing about 350 million bbls annually, or 1
billion bbls every three years. Unfettered, Bentek estimated (and some
continue to estimate) that the Bakken can produce 2.2 million bbls daily
if the "price was right."
The second most interesting comment from the article: I vividly recall analysts saying that it was impossible for frackers to "turn on a dime," that it would take months for frackers to spud a well and bring it to production. I remember that vividly because I was not seeing that in the Bakken. From spud to production, operators could measure it in days -- generally about 30 days. And bringing in more rigs was not all that difficult. The biggest problem for the Bakken was competition from the Permian for skilled work crews but with things starting to turn a bit sour in the Permian, the Bakken may have some relief. But I digress. From the article:
"Restarting production may be easier than people think. Everything is ready to go. There are plenty of rigs. All the ingredients are there. There is a lot of money looking for the bottom of the cycle, waiting to get back in," he said.
In the first two or three years of the Bakken boom, there was minimal infrastructure and constrained takeaway capacity. Both of those have been resolved.
Not mentioned in the article, in the Bakken alone:
850 DUCs
1,500 wells that are shut in for various reasons
At the end of this quote, IHS was thinking specifically of the Bakken, but since 2016, everything changed when the DAPL came on line (early 2017):
IHS said there are three groups of 'invisible barrels' likely to bear the brunt as the market stabilizes: small-scale 'stripper wells' of around 2m b/d, half of them in the US; those with high-fixed costs in North Sea and the Gulf of Mexico that are going into steeper decline; and those in remote locations or with long pipelines, and a $10-$12 disadvantage. "
They are in the eye of the storm," it said.
Hess disagrees:
The great unknown for world oil markets is how fast the frackers will come back. John Hess says it will take two years once prices recover.
"It is a big logistical undertaking. You've got to mobilize rigs and find people. Assets need permits in the US, and that takes 90 days," he said.
"Balance sheets are in disrepair and there is too much debt. The high-yield market has basically dried up and that was the primary source of financing for the shale boom. Debt agencies are in a panic and running everything through $30 oil for the next few years," he said.
I think where Hess and I disagree has to do with the definition of "recover." It may take two years for E&Ps to return to historical levels of prosperity (as measured by share price or market capitalization) but it certainly won't take two years to see an incredible rush back into the Bakken if oil prices a) began to trend toward $60; and, b) tea leaves suggest that the trend would continue.
Possibly the most incorrect prognostication:
Scott Sheffield, head of Pioneer, expects trouble in the Eagle Ford and Bakken fields, but it is a different story in the lucrative Permian Basin of West Texas, the "crown jewel" holding steady at 2m b/d even at current prices. He claims it is as big as the giant Ghawar field in Saudi Arabia, and could eventually produce 6m b/d.
I agree that production will remain steady (or grow) in the Permian, but it may be more financially challenging than first expected. Paying $60,000/acre in an era of "lower for longer" is not going to cut it, as BHP found out.
Break-evens for US operators: no one knows. The "number" is all over the place. Everyone agrees that "very few things make sense at $30. It's better to leave the oil in the ground."
David Hager, head of Devon Energy, said shale frackers have slashed cuts costs way more than outsiders generally realize since the heady days of the boom, when service fees and wages were rocketing.
"A lot of plays work at $45-$50, and the vast majority from $55-$60. They certainly don't need $90," he said.
This is optimistic. A study by Rystad consultants in Norway puts the break-even price at $68, but nobody knows for sure and frackers disagree among themselves.
Shake-out: again, Mark Papa -- Mr Papa said the 70 percent crash in oil prices since mid-2014 will wipe out those companies that leveraged to the hilt betting that crude prices would stay above $100 forever.
BHP Billiton is a great example. The company itself agrees that it overpaid when it spent $20 billion to enter US shale plays (the Eagle Ford and the Permian), previously posted/linked. Only because of its size and other mining businesses did BHP survive (and thrive, for that matter).
Re-Balancing: perhaps by end of 2016, into 2017, but difficult to predict. This is what caught my eye, and many readers say the same thing. A new bust-boom cycle:
Mr Papa expects the global balance of supply and demand to tighten by 1.6m b/d this year. This would mop up the glut, before gradually eating into record stocks next year.
"The market is going to grow to 100m b/d. Where is the quantity going to come from? Capital spending on mega-projects has stopped cold,” he said.
“I can see a case where US shale is the biggest supplier of oil in the world by 2020. We could turn the whole thing on its ear, producing 13-14m b/d. But it will be really ugly getting through this valley,” he said.
By the way, I disagree with Mark Papa on this point:
"The
market is going to grow to 100m b/d. Where is the quantity going to
come from? Capital spending on mega-projects has stopped cold,” he said.
The tea leaves suggest there is more than enough oil out there to preclude that concern. But the tea leaves also suggest I am in the distinct minority. Most agree that shale cannot make up for all the off-shore CAPEX that has been deferred or canceled. The reason I disagree: Mideast potential, especially Iraq. Much could be written but perhaps for a different day.
Not just shale.
"Most companies will survive to take advantage of the recovery. We will ramp up, stay alive, meet the challenge, and look forward to a brighter day. It is not just shale that doesn't work at today's prices, nothing much at all works," said Mr Hager.
I did not post it but there was a recent article suggesting that "stripper wells" are returning. Operators that had shut down stripper well operations are are now returning. I didn't post the story because it seemed to be a press release from oil companies in California where fracking is not panning out for political and geologic reasons. But if I'm wrong, and strippers are coming back, that speaks volumes for the oil sector.
Not mentioned in the article: fracking strategies. Sand is getting more expensive; ceramics remain very expensive. The trend toward ever-increasing amounts of proppant to complete a well seems to be coming to an end. Much more sand is being used, but more sand is being mined, and, either God or nature again seems to smile on the US frackers: huge amounts of fracking sand have been discovered in west Texas, in/near the Permian. Rail won't be required; truckers will do the job. Ceramics appears to be "out" -- too expensive and experience suggests sand does just as well. All those concerns about sand "not holding up" may have been more marketing than real. The big change in sand has to do with size of sand. Operators are going to "smaller" sand.
****************************
*****************************
Addendum
Playing Around With Numbers
In the examples below, one can pick whatever numbers in bold one wants.
The North Dakota Bakken (middle Bakken plus Three Forks first bench)
Williston to Minot: 120 miles
Williston to Belfield: 100 miles
100 miles x 100 miles = 10,000 square miles -- the North Dakota Bakken
78,125 bbls OOIP/acre x 1280 acres/drilling unit = 100 million bbls OOIP / 1280-acre drilling unit
500 billion bbls OOIP / 5,000 1280-acre drilling units = 100 million bbls OOIP / 1280-acre drilling unit
12 wells / 1280-acre drilling unit
100 million bbls OOIP x 7% production rate = 7 million bbls recoverable oil / 1280-acre drilling unit
7 million bbs / 12 wells = 583,333 bbls / well
Summary: at 7% production rate across the middle Bakken/Three Forks first bench yields: 583,333 bbls/well
Whether one agrees with the assumptions or not (the numbers in bold) it is amazing that the law of large numbers seems to work. I think everyone agrees that EURs of 600,000 bbls is not unrealistic (yes, I know there are a lot of poor Bakken wells out there, but one can also argue that a lot of those poorer Bakken wells were drilled under less than optimal conditions, beginning with poor understanding of the geology and extending through inexperienced roughnecks.
If, in fact, operators are approaching 14% productivity rate in the Bakken, then one can expect million-bbl EURs.
Idle chatter but it helps me validate OOIP estimates; company talk about production rates; and, EURs of wells that are being drilled over time.
It took a bit of doing, but I found the original links for this two-part
article. A reader -- thank you, very much, alerted me to Part 2, but
Part 1 is just as important.
So, here is the original link, with links to Part 1 and Part 2, which, I believe, will download as PDFs in both cases.
Part 2, in this post, has to do with how the shale revolution is changing global geo-politics. This second part is titled: Shale is reshaping the world: three new wars.
Russia vs Europe
Iran vs Saudi Arabia
an Asian tanker war
When I look at just this much of this interview I think immediately: politicians like Angela Merkel and Ted Cruz won't understand it. Business men like Rex Tillerson and Donald Trump will understand it. Ideologues like Barack Obama and Al Gore won't understand it, but worse, they both bet on the wrong horse. Even if one doesn't understand horse-racing one can still get lucky and win a big race (my wife has proven that); but in Al Gore's case, and in Barack Obama's case, they bet on the wrong horse.
It took a bit of doing, but I found the original links for this two-part article. A reader -- thank you, very much, alerted me to Part 2, but Part 1 is just as important.
So, here is the original link, with links to Part 1 and Part 2, which, I believe, will download as PDFs in both cases.
In the very first answer to the very first question in Part 1, one gets the feeling that this article is a must-read.
The interviewee interpreted the first question to be this: "we've" been doing horizontal drilling and fracking since at least 1947. What's different this time that has made it so successful? The answer: seismic technology.
Seismic has been around in the industry since the late 1970s. It's not new, either. But the old seismic is a radically different creature from what we have today. It's like comparing a Toyota hybrid to an 18-wheel from the 1950s. Yes, technically, they're of the same technological tree, but they're so radically different. With the old seismic, you have these giant bulbs of oil-saturated rock that didn't require much of a sonar cross-section to show up when you would do seismic. The news one can pick up deposits about the size of a 500-ml water bottle.
Did I mention that North Dakota has the largest buried microseismic array in the world. Something tells me that some of the new acreage bought in the Permian for $40,000/acre does not have such an array in place, yet.
And, note: that was in 2010 that it was reported that North Dakota had the largest buried microseismic array in the world. That was seven years ago; one can imagine how much has been done since then.
Very early in the article, the interviewee says that "micro-seismic is so new it did not exist 30 months ago."
Obviously there's a disconnect. But we will press on.
Later: re-fracking -- going back to fields for the second, third, and fourth time. One can leave the micro-seismic geophones in place, to be used the next time a well is re-fracked, or a new well is fracked for the first time.
The interviewee suggests that most companies are not yet using micro-seismic technology.
So many incredible data points in the article, like this one, which I have said so many times, I have lost count:
"Rig count is now a meaningless number in shale plays in general, and even more so in shale plays using micro-seismic technology."
I was getting a bit worried about Mr Filloon. I had not seen something from him in quite some time.
This morning Don sent me a wonderful surprise! A link to a great Filloon article over at SeekingAlpha. The frosting on the cake? This is the first installment of a two-part series.
The comments are also interesting to read. I see folks are having the same problem I had trying to find the spot price for Bakken crude oil. A reader provided the best link to date and I've included it at my "Data Links" page. Plains All American appears to be the best non-subscription site. I understand that Platts and Bloomberg both post prices at Clearbrook but for a costly subscription. Some time ago I posted a comment at SeekingAlpha providing a link to a site that provided an answer to someone's question but it was rejected and I got a note from SeekingAlpha that said hyperlinks were not allowed, and if I persisted in posting links (that was the first time I had done that), I would be denied access to the site. Whatever.
As usual, the article by Mike is outstanding.
His second installment will "will cover Bakken operators in a good position going into 2014."
His first installment was very, very long, and he probably did not have time or space to post everything he knows. If he mentioned the huge strides in infrastructure since 2011, he did so in passing. In the big scheme of things, the cost of building and maintaining roads to all the drilling pads must be inconsequential because no one ever talks about them. But if the cost of building/maintaining these roads are not inconsequential look at the savings gained by pad drilling. Instead of one road being built to service one well, one road now goes to a 5-well, 10-well, or even a 14-well pad.
Since 2011, a lot more pipeline has been laid: natural gas pipeline; crude oil pipelines; and, water/waste pipelines. By the middle of 2014 there is going to be another huge pipeline on-line, the one from Killdeer to Dickinson which will pretty much hook into the entire southern half of the Bakken. Trucking costs have had to come down significantly.
A third cost? Leases. A thing of the past, for the most part.
That's on top of drilling costs dropping from $10 million to $8 million, per well.
Mike touched in passing on the glut of oil hitting the Gulf coast, and how other sources of oil could "displace" Bakken oil from east coast refineries. RBN Energy has talked about this at length for quite some time. But the capacity for light, sweet oil on the west coast will increase over the next few years. Having said that, I don't think folks understand to what degree the "flood" of new domestic oil will have on the market.
Mike did not mention the recent derailments and the safety alerts coming from the government. The emotional anxiety this will cause investors will result in share price volatility but it will be temporary. There are four pipelines that are particularly interesting and relevant to this discussion:
the Keystone XL 2.0 South will start flowing oil out of Cushing on January 22, 2014, but the huge influx of western Canadian heavy oil that was to replace it via the Keystone XL 2.0 North won't be on-line by 2016, if ever. There may be a reason that Harold Hamm has said the Keystone XL is no longer needed;
the Killdeer-to-Dickinson pipeline will be on-line by the middle of this year;
the Enbridge Sandpiper project; this one won't be completed until 2016; in addition, I have some concerns whether it will be completed/delayed due to activist environmentalist concerns, but with the rail issues, the advantage may have turned in Enbridge's favor; and,
the Double H pipeline from Dore, North Dakota, to Guernsey, Wyoming. I haven't seen anything on that recently; updates should be in the annual report, if nowhere else.
When takeaway capacity was first being talked about in the Bakken, the conversations only related to pipeline. Experts suggested that pipeline capacity would exceed Bakken production by this time (or at least that was my recollection). For various reasons, CBR has turned out to be more successful than anyone originally anticipated. But now with additional pipeline in place (locally, regionally, and nationally) recent CBR events might be less concerning than they otherwise might have been.
This Mike Filloon article is an excellent update. It will be linked as a favorite commentary at the sidebar at the right.
Oh, by the way, did you all see this in his opening paragraph: "... the Three Forks' four benches will produce significantly more resource than the middle Bakken." There are two story lines or two data points in that one short phrase.
It's one of the most economic and best resources that we have, not only in the U.S., but, really, in the world. There's lots of running room and we're very early into the play with lots of acreage still to be drilled. We could be up there for 50 or more years drilling very, very strong wells and putting lots of oil into U.S. tanks. The Eagle Ford and the Utica in Ohio have interesting and up-and-coming plays, but the Williston really has been shown to be as economic as any other, if not the best. It's always nice to be in an asset that has the best type of results.
Needs repeating:
It's one of the most economic and best resources that we have, not only in the U.S., but, really, in the world. There's lots of running room and we're very early into the play with lots of acreage still to be drilled. We could be up there for 50 or more years drilling very, very strong wells and putting lots of oil into U.S. tanks. The Eagle Ford and the Utica in Ohio have interesting and up-and-coming plays, but the Williston really has been shown to be as economic as any other, if not the best. It's always nice to be in an asset that has the best type of results.
Analyst is Jason Wrangler, based in Houston. Interviewed and transcript placed on SeekingAlpha.com.
The article is full of Bakken oil company recommendations. A nice report for the weekend. Enjoy.
By the way, that "drilling could go on for 50 years." The UND oil and gas consultants agree; see "Basic Analysis of the Bakken Boom" linked at the sidebar at the right. The folks there think active drilling will take 30 years and production will continue through 2100. Legacy wells that were drilled in the 1950's are still active in a few cases.
For newbies, I think analysts should remember all the things going for drillers in the Williston Basin:
Original-oil-in-place estimates keep rising
There are "no" DRY holes in the Bakken; only Saudi Arabia has similar success rate
It's the best kind of oil: sweet, light oil
Multiple pay zones
Infrastructure in place
Takeaway capacity keeping up with production - no longer true as of late 2011
Business climate is pro-oil. Very pro-oil.
North Dakota has relatively small BLM footrprint. It's largest footprint is the reservation, and the reservation is drilling as fast as it can; Montana, Wyoming, Utah hampered by BLM footprint
Major oil service companies have been in the Williston Basin for decades and know the area well (Schlumberger, Baker Hughes, Halliburton, just to name the ones that are most familiar)
Bakken: industrial research -- testing new techniques, procedures in the field
UND with best stratigraphic core library in the world, according to many
World's largest microseismic array in place
No terrorists in North Dakota
Adequate transportation for workers in and out of state (air, Amtrak, 4-lane divided highway -- try driving to Saudi; try driving in Saudi if you are female)
No need for air conditioning most of the year
Cool winters keep the riff-raff out; crime low
English still the language of choice
North Dakota not known to be as litigious as some states
I forget which CEO said it during the 2Q11 earnings conference call, but you could hear the frustration in his voice, that analysts were misunderstanding the Bakken. It was not Harold Hamm. Actually, now I remember who he was, but I think I will avoid quoting him, afraid of misinterpreting what he said, or putting words in his mouth.
But the takeaway I took from this CEO is that Wall Street analysts are absolutely missing how huge the Bakken is.
He mentioned two things: a) these are monster wells; and, b) there are "no" DRY holes in the Bakken. I have said that many, many times, that the fact there are "no" DRY holes in the Bakken is a huge development.
He also did not mention that technology is improving exponentially, and the wells now being drilled are so much better than wells that were first drilled in this boom in Montana in 2000. Mostly it has to do with completions: in 2000, it was single stage fractures; in 2008 it was 12-stage fractures; now the standard is moving to 32-stage fracture completions.
Last night, I looked at the well files of 55 consecutive permits isssued back in 1978 / 1979, or thereabouts.
The permit numbers were from #6665 to #6719, inclusive.
That's 55 consecutive permits.
Five of those permits were canceled, so money was spent on 50 of those permits.
Seventeen of those 50 wells drilled were DRY. 17/50 --> a third of all drilled wells in that series were DRY.
Of the 33 wells that did hit oil, most have since been abandoned.
9 of those wells never reached 50,000 bbls.
Another 5 did not reach 100,000 bbls.
9 wells reached 100,000 but did not reach 200,000.
There was one great/memorable well: >1.4 million bbls.
So, maybe, of the 50 wells drilled for permits issued in that time period, maybe 19 were good wells; Only a handful were great wells. Now, in comparison:
A Bakken well EUR is 603,000 bbls. That's an average.
There are "no" DRY Bakken wells.
There will be many phenomenal Bakken wells, well above the million-bbl mark.
Total cumulative production of these wells noted above (#6665 - #6719), in order of total production, not drilling order, or permit order, were:
Actually, not quite true. I started the site to try to keep track of what was going on in the Bakken. I initially considered "Word" documents, etc., but then realized HTML was the way to go. I decided to share the HTML postings when I first saw two other sites suggest the Bakken was being hyped and I wanted to provide some balance. Actually, not a balance, but a rebuttal, I guess. I certainly wasn't balanced in my enthusiasm for the Bakken.
I had not planned to post anything about the investing side of the Bakken initially, but it was soon obvious that one could not separate what was happening in the Bakken (geology, technology) without following the investment activity.
I admit I am inappropriately exuberant and have said more than once that my personal financial investment in the Bakken is much more conservative than what the blog might suggest.
Having said that, I have two stories that I cannot get out of my mind. The first story is about an acquaintance (in a certain sense) just like you and me who bought into Medtronic when that company was just starting out and has since become a millionaire many times over.
The second story is about meeting another person on Amtrak, about 40 years old, who has never worked a day in his life, because his father gave the children all the Microsoft stock the father had bought when MSFT was just starting out. (I would not want his life; having never worked in his life, made for a very dull person when we actually started talking.)
But I think about those folks, who literally put their total investment dollars when they first started investing in companies like Microsoft, Apple, Medtronic, IBM, when these companies first started out.
I wonder if we might be seeing the same thing with BEXP, Whiting, CLR, Oasis? Sometimes looking at quarterly statements, daily fluctuation in the price of oil, wild volatility in the stock market results in folks like me forgetting two things: a) oil will become ever more dear over the next 30 years; and, b) CLR has almost 1,000,000 acres in the Bakken, the most incredible oil play in the lower 48, according to some.
It makes me wonder if it would be easier just to put all investment dollars in CLR, Oasis, BEXP, or Whiting, and then forget about following this stuff, and living life, doing something else. I have no doubt these companies are going to look a lot different 30 years from now.
Just rambling, but if one steps back and looks at some of the things going on in the oil patch in North Dakota, it is mind boggling. The link takes you to the wells that I updated today. These are huge wells, and they are literally the tip of the iceberg, as they say. But a Bakken well producing 100,000 bbls in the first six months and this well is expected to produce for 30 years (yes, I know, at a horrendous decline rate, but it's all about paying off the wells as quickly as possible, and the EURs).
Again, just rambling, but when I see 1,000 point-drops in the stock market and then look at companies like CLR with a million net acres in the Bakken, one can only think of some huge opportunities.
$660 million in stimulus funding authorized for Wyoming
$410 million of that was spent as of March 31, 2011
Wyoming spent money on one-time projects rather than creating new government jobs that would require state support after the stimulus money ran out
Resulted in 858 new jobs ($480,000/newly created job)
Most of the money was spent to shore up/restore projects cut by the state earlier to balance the budget
The $157 million in stimulus funding that WYDOT received, for example, essentially replaced the funding the department lost in the 2009-10 state budget, said WYDOT Director John Cox in a January media release.
“That kind of saved the day for us,” Cox said. “The timeliness of the stimulus money couldn’t have been better, given that the governor and Legislature had to balance the budget.”
Wyoming was the first state in the nation to spend all its construction stimulation money
Stimulus money was used to fund Medicaid and State Children's Health Insurance Program; both programs now have thousands of additional enrollees, and starting in 2012, the state will have to fund the programs
In many states, private insurers dropped insurance programs for children if the state provided coverage (that hasn't happened yet in Wyoming)
Takeaways for me:
The federal money restored funding for programs cut by the state earlier to balance the budget (a one-time goodie)
The state will now have unfunded obligations for larger Medicaid and CHIP programs
I do not know if the 858 jobs, at a cost of $480,000/job to create, will be around in 2012
Despite being the first state in the nation to spend all its construction stimulus money, the state has spent "only" 60% of its federal stimulus money ($410 million/$660 million)
The article did not say whether the $250 million yet to spend has been obligated or if the state is trying to figure out what else to spend it on
I have no idea what North Dakota spent its stimulus money on, but if the state had held on to it, it could now be used for road construction, repair, maintenance in the west; flood recovery efforts in the mid-section (Bismarck, Minot, and Devils Lake); and, whatever the Red River Valley thought they needed for their fair share.
There is an interesting graphic in Whiting's recent corporate presentation.
I noted some time ago that for all the rigs CLR has in the Williston Basin, it seems other drillers are completing wells at a similar rate despite having fewer rigs. It was just a "feeling."
Look at slide 26 of Whiting's most recent corporate presentation (June, 2011), in which Whiting lists about 35 drillers working in the Bakken, number of wells drilled, and six-month total production (MBOE 10); these are wells drilled since January, 2009 (I may be misreading the slide, but this is what is seems to say.) (The number of rigs is my estimate over time; subject to correction)(a select few):
Hess: x rigs; 43 wells drilled; 2,148 mboe 10; 50k/well
MRO and XTO stand out.
It's possible that one rig/Eco-Pad, and the delay in completing the fourth well, is skewing CLR's results.
WLL's impressive 6-month production results are due to the impressive wells it has in the Sanish, and the way WLL is executing its Bakken strategy: at least one Sanish well for every other well it drills.
The graphic on that page lists the drillers in order of average production/well over the last six months:
WLL: 100k/well
Murex: 89k/well
BEXP: 81k/well
Hunt: 79k/well
Slawson: 75k/well
American: 72k/well
Questar: 71k/well
SHD: 68k/well
Zavanna: 65k/well
BR: 65k/well
Petro-Hunt: 62k/well
CLR: 60k/well
EOG: 60k/well
Fidelity (MDU): 57k/well
KOG: 57k/well
Anschutz (OXY): 57k/well
SM: 54k/well
Newfield: 53k/well
Zenergy: 51k/well
Hess: 50k/well
Tracker (Hess): 49k/well
Oasis: 46k/well
Peak: 46k/well
Encore (Denbury): 45k/well
Sinclair: 44k/well
XTO: 40k/well
Lario: 40k/well
MRO: 36k/well
Baytex: 32k/well
Cirque: 30k/well
Samson Resources: 29k/well
PDC: 27k/well
Panther: 21k/well
Sagebrush: 16k/well
Again, XTO and MRO stand out. One can argue that WLL is an outlier due to its "sweet spot" in the Sanish, but it's hard to defend XTO and MRO. Even companies like Newfield in the Bakken are somewhat disappointing when one looks at this data.
June 21, 2011: I posted the original note below on June 15, 2011. It's now been about a week and time to post the first thoughts I had when I read the linked story.
First: my world view is that there is a small, but very vocal and very influential group of folks that will do anything to destroy "Big Oil," the domestic oil industry, or whatever you want to call it. They use whatever means they can, including scams like "global warming." They use existing bureaucratic agencies and regulations to stop "Big Oil" wherever they can. They co-opt legitimate entities to assist in their efforts. Examples abound.
Now, my first thoughts when I read the story below. I think the small but very vocal and very influential group of folks intent on destroying "Big Oil" were caught flat-footed when it came to horizontal drilling and fracking oil- and gas-containing shale. Even "Big Oil" was surprised how fast this process took off and how successful it has become. Right now, the success has resulted in huge supplies of natural gas and it's very possible we may see something like that in oil.
Those who hate "Big Oil" have been very successful in stopping/delaying off-shore exploration. They are now playing "catch-up" with hydraulic fracking and will do what they can to stop that process. It's very possible they will be successful.
But, states across the nation, including financially-strapped states are starting to appreciate the oil and gas royalties coming in from oil and gas produced through hydraulic fracture stimulation.
So, that was my first thought: everyone was caught off-guard with regard to hydraulic fracking. Now everyone is playing catch-up. Including those who want to stop "Big Oil."
Natural-gas producers are pumping fuel at a record pace as advances in drilling techniques help offset a decline in rigs, signaling no respite for the world's worst-performing commodity in the past year.
Gas has tumbled 39 percent since the end of 2007 as companies increased output by about 11 percent to a monthly record in March. Improvements in drilling amid rising demand for the cleaner-burning fuel have outweighed a 45 percent drop in the number of rigs since reaching an all-time high in 2008.
Companies from Range Resources Corp. to Chesapeake Energy Corp. are using capital from joint-venture partners to simplify the process of extracting gas contained in shale. Natural gas is the only raw material that hasn't gained in the past 12 months, losing 12 percent, according to the Standard & Poor's GSCI Index. Oil has jumped 24 percent in the same period.
Then, take a moment to reflect on the first thing that comes to your mind.
I will tell you the first thought I had while reading the article -- tomorrow, unless I forget.
First two paragraphs of the story:
The U.S. shale oil and gas drilling boom boosted U.S. oil and gas reserve growth to a five-year high in 2010, while upstream spending more than doubled from 2009 to 2010 largely due to producers' acquisitions of shale properties, according to Ernst & Young's fourth annual U.S. E&P Benchmark Study.
The survey of the 50 largest oil and gas companies by end-of-year reserves found that end-of-year oil reserves grew 11 percent from 16.1 billion barrels in 2009 to 17.8 billion barrels in 2010, and natural gas reserve grew 12 percent from 156.2 Tcf in 2009 to 174.3 Tcf in 2010, the strongest combined annual growth posted from 2006 to 2010.
This is an exceptionally good article on shovel-ready jobs and how those jobs support hiring in other industries in the immediate geographical area.
From Appalachia to Alaska, the growth is eye-popping. Thousands of new jobs have sprouted up, most well-paying and all boons to their regions. There’s no denying oil and gas extraction jobs are on the rise, and not just in Texas and Oklahoma.
North Dakota is drilling oil at a blistering pace. Pennsylvania and West Virginia, along with parts of New York and Ohio, are seeing a natural gas boom with their Marcellus Shale reserves. And Colorado, Wyoming, Alaska, and other Western states are adding extraction jobs in droves.
The six fastest-growing jobs for 2010-11, according to EMSI’s latest quarterly employment data, are related to oil and gas extraction. This includes service unit operators, derrick operators, rotary drill operators, and roustabouts. Each is expected to grow anywhere from 9% to 11% this year, in an otherwise stagnant economy.
Many, many data points:
Despite seemingly more and more obstacles for the oil industry to survive, much less thrive, the industry appears to be doing quite well
The growth in oil is not limited to just one or two states, or even to one or two regions, but literally in areas as diverse as Pennsylvania, Texas, North Dakota, and California
Everything suggests that this phenomenon is not short-lived, but likely to go on for decades
Non-oil and gas companies are also benefiting where they support the oil and gas industry
"In total, nine of the top 11 fast-growing jobs in the nation are tied in one way or another to oil and gas extraction."
The discussion regarding 1099 vs W-2 pay was particularly interesting. It is amazing how the government can classify folks by the forms they fill out regarding pay.
My hunch is that regardless of where the federal government wants to take the nation in terms of shutting down the oil and gas industry, governors of debt-ridden states will be marching to a different drummer.
Oil rises $2.32 after OPEC decides not to raise production.
At the link below in the original post, this statement:
That moved China ahead of the United States as the world's biggest consumer of energy, accounting for 20.3 percent of global demand compared with 19 percent for the U.S., the report said.
The growth in Chinese energy consumption has already been breathtaking, according to the report. Over the last decade, China’s energy demand has doubled. While China used only half as much energy as the United States in 2000, it actually surpassed the United States in 2009 as the world’s largest energy user.
With China and its 1.3 billion people as a primary engine, the energy agency predicted that world energy demand should grow by more than a third over the next 25 years, [even] as new oil supplies became harder to find.
It also predicted that oil prices would rise to $113 a barrel in 2035, in current dollars, a rise of nearly $30. The agency also predicted that fossil fuels — oil, natural gas and coal — would remain primary sources of energy for the world, though renewable energy sources and conservation efforts would increase in importance. [Comment: $113/bbl in 2035! We hit $113 some time ago, although I assume this report means the annual average, not periodic spikes, but clearly we will be at $113 well before 2035.]
The analysts predicted that Chinese energy demand would soar 75 percent by 2035, accounting for more than a third of the growth in global consumption. While China today accounts for 17 percent of world demand for energy, it should account for 22 percent in 25 years. [Comment: in the article today, June, 8, 2011, just a few months from the November, 2010 report, China is already at 20 percent. I have trouble believing that it will take 25 more years for China to get from 20 percent to 22 percent.]
And this is why I am bullish on oil.
With 1.3 billion people, a one-child limit, Chinese favoring male children (i.e., boys), and a burgeoning number of unemployed, hormone-driven, young male adults, something tells me the Chinese have bigger concerns than "cap and trade."
Original Post
I didn't think China was projected to surpass the US for a couple of more years.
US uses about 20 percent of world's output of oil -- and you know? That sounds about right. I would have thought it even more. China uses about 10 percent of the world's oil output.
But this is the headline:
China's consumption rose by 11.2 percent last year compared with 3.7 percent in the United States. China's surge led a 5.6 percent increase in global energy demand, the biggest one-year jump since 1973.
There's a long discussion elsewhere on parking tickets given to truckers waiting to dispose of salt water. I have to agree with the individual who said it that giving out tickets is not exactly helpful.
I side with the truckers on this issue. They need to be helped, not made to feel like second-class citizens.
With regard to "safety," the oil companies could hire someone to wear a reflective vest, and hold a sign with "slow" on one side and "stop" on the other side. In Boston, they use off-duty policemen for these pop-up problems until the situation is resolved. These policemen make a lot of money and generally retire at 45 years of age, and spend their retirement years reading nasty letters to the editor about how big their pensions are.
Every truck driver has a cell phone. This is not rocket science. Airports in San Antonio, Boston, and I assume elsewhere, have solved the "waiting problem."
Sounds like a 16-year-old looking for a summer job could work out a business plan in 10 minutes, propose it to the city and/or county, manage the waiting problem, and make enough money to hire a 14-year-old to manage it. He/she could contract out a lemonade stand to his/her 8-year-old sibling at the same site.
Having said all this, I see all of this as growing pains and these things will be worked out over time. But it will certainly help if folks work together on this rather than fighting it out with $20 traffic tickets.
In a fairly long post, these two paragraphs caught my attention:
On the international front, supply from Saudi is offsetting supply from Libya. However, a barrel is not a barrel is not a barrel .....
Non-OPEC supply probably won't be as resilient as EIA currently expects (up a fraction of a percent this year and then down again in 2012) ....
I would love to "cut and paste" the entire paragraphs but I think it's better if you visit his site.
With regard to Saudi Arabia, the world my get a better feeling whether OPEC can respond to a prolonged loss of sweet oil from Libya. Already there are indications that Saudi's spare capacity is declining.
In his non-OPEC paragraph he notes that a) Brazil is too far off to make a difference in the near term; b) Mexico is one day closer to becoming a net importer of oil; c) the UK is pushing the envelope by threats to increase taxes on North Sea oil; and, d) the American "moratorium" continues.
One almost wonders if investors moved the needle today -- oil up over $108 -- after reading Zman's analysis.
When I read articles like this most recent posting from Zman, all I can think of is a lost decade when our brightest engineers could have been working on coal to liquids technology rather than on wind and solar. It did not take computer modeling to understand that neither wind nor solar could make more than a small dent in the world's energy requirements.
July 12, 2015: two comments regarding methane hydrates -- 1) they won't be a big deal in my lifetime; and, 2) this is just one more example why the world isn't going to run out of fossil fuel any time soon (see original post).
Today, OilPrice suggests Japan could move to methane hydrates.
Before the [nuclear] incident, Japan’s 54
nuclear reactors provided more than 30 percent of the country’s
electricity requirement. Without nuclear energy, Japan’s domestic energy
resources could only meet less than 9 percent of the nation’s energy requirement. 2013 saw the country increase it’s spending on fossil fuel imports by 60 percent when compared to 2010.
Currently, Japan is one of the
largest net importers of crude oil, the second largest importer of coal
and the largest global importer of liquefied natural gas (LNG). Since
Japan imports almost its all of its fossil fuel requirement, it has lost
its trade surplus and has become a nation with a rising trade deficit.
Methane hydrates are crystalline
ice that is found in lower sediments of deep sea regions and polar
regions that have methane gas trapped within them. When melted, methane
hydrates turn into water and methane. Methane hydrates offer a truly
massive reservoir of natural gas trapped in ice.
In fact, the deposits of this
“burnable ice” are so large, ( Japan has around 746 locations in its
coastal waters) they could provide Japan with enough natural gas for the next 100 years at least.
And there could be much more methane hydrate deposits in the marine
sediments off the Pacific Coast of the country. These are big numbers.
Japan has also participated in an international research team that
successfully produced methane in Canada’s arctic region.
The United States has the most energy resources in the world AND the most incoherent energy policy
McQuain used one word that caught my eye, the same word I often use on this site. But more on that later.
McQuain starts with this:
According to a new report requested and paid for by Congress, America's combined energy resources (principally coal, natural gas, methane, and oil) far exceed --- ECLIPSE -- the energy resources of Saudi Arabia (3rd), China (4th) and Canada (6th).
This does not include America's shale oil deposits (such as the Bakken).
This does not include America's potentially astronomic impact of methane hydrates
Data points (some numbers rounded)
Coal:
Well known to all: US has recoverable coal reserves of 260 billion tons
Using 1 billion tons/year, US reserves will last centuries
The US has 30% of the world's coal
Natural gas:
At current rates of consumption, US has 100 years of natural gas reserves, based on conservative estimates
Congressional Research Service upped its 2006 estimate of America's enormous natural gas deposits by 25 percent
This estimate was conservative to begin with and does not include recent shale boom underway in the US
Methane hydrates (natural gas):
Government estimates of methane hydrates -- one word -- "immense" -- possibly exceeding the combined energy content of all other known fossil fuels
If just 3 percent of this resource can be commercialized, that level of supply would the US more than 400 years
Oil:
Congressional Research Services: 163 billion barrels (vs mainstream media's repeated estimate of 28 billion barrels of proven reserves)
Oft repeated US provable oil reserves represents only 20 percent of total US recoverable oil
True estimate of US oil is enough to maintain America's current rates of production and replace imports from the Persian Gulf for more than 50 years
That last statement may be a bit misleading: the US is importing less and less oil from the Midease; US is importing oil from Canada, Latin America, and western Africa
McQuain concludes his article with:
We have no coherent energy plan from this administration. Instead it seems to have gone to war with the oil industry and is doing everything it can to slow its ability to find and exploit these resources. 19,000 jobs and 1.1 billion in earnings have been lost since the imposition of the administration’s moratorium. Both former Presidents Bush and Clinton have spoken out against the delays. And the administration remains in contempt of a court order which ordered them to speed up the permitting process. As a result the EIA has estimated a loss of 74,000 barrels a day of production due to the moratorium this year.
Oh, yes, the word that caught my eye: myth.
I have long been a fan of JRR Tolkien's concept of myth and quote him often. That concept is my guiding light when it comes to energy. This is an expert's opinion of the US energy policy and how Bruce McQuain concluded his post:
Meanwhile US energy policy persists in pursuing the myth that renewables are the economically viable future, with fossil fuels already, as the president said in January, “yesterday’s energy." With 85 percent of global energy set to come from fossil fuels till at least 2035 no matter what wishful thinkers may prefer, current US energy policy – much like European – is pure political pantomime.
From my perspective: America's energy industry has been Balkanized by special interests, government bureaucracy, and environmental demagoguery. We can't even put in transmission lines for wind turbines in west Texas to get the electricity to urban centers.
