Saturday, August 25, 2018

Natural Gas Inventories "Dangerously Low" -- Contributor Over At Oilprice -- August 25, 2018


September 4, 2018: so much for CO2 and global warming. The Brits are going to use a lot of coal this winter. Natural gas getting too expensive; coal is cheap. Link at Platts (beware: lots of jargon):
Bullish NBP spot and winter contract gas prices have focused the power market's attention on the UK's coal-fired power plants, which have recently become more economical to run in the summer as well as in the winter.
The gap between prompt NBP gas and the coal switching channel indicates that, if and when needed, thermal generation is going to be predominantly coal-fired this winter, with higher gas prices opening the way for increased coal-fired generation, despite a strong hike in carbon prices.
Data show 35% efficient coal-fired plants are competing with 45% gas-fired plants.
The UK month-ahead coal-switching price for 45% efficiency was 68.43 pence/therm on Monday, slightly lower than the NBP day-ahead contract assessment of 69.70 p/th.
However, UK month-ahead CSP for 50% efficiency was 78.19 p/th. Platts CSPI is the theoretical threshold at which gas is more competitive than coal in power generation.
When the gas price is higher than the CSPI, CCGTs are more expensive to run than coal-fired plants.
"Despite the gains in carbon over recent months, coal generation has been supported this week by particular strength in the gas market," according to S&P Global Platts Analytics.
"We forecast gas to lose ground this winter too, with the Q1-19 Clean Dark Spread above the Clean Spark Spread. As a result we expect coal generation to be stable year-on-year this winter, despite the closure of 2GW of capacity, while gas generation is forecast to fall more than 3 GW vs Winter-17."
August 26, 2018: Europe's natural gas prices surge to record for summer season.
Europe’s natural gas market is the most bullish it has been in years, as higher-than-expected summer demand and a tighter market drive natural gas price futures to levels last seen during this past winter’s supply crunch and to the highest for a summer season.
Natural gas prices are expected to stay strong and may still have room to rally, ahead of the next winter heating season in Europe that begins in October. 
Contrary to the typical summer lull in Europe’s gas prices, this year the front-month gas price in the UK—Europe’s biggest gas market—for example, is nearing the winter price from December 2017 when a deadly explosion in Austria’s gas hub at Baumgarten squeezed supplies throughout Europe. Immediately after the explosion, the price of gas for immediate delivery in the UK reached its highest level since 2013.
August 26, 2018: natural gas production in the US --
Gulf of Mexico Fact Sheet, EIA: Gulf of Mexico federal offshore oil production accouts for 17% of total US crude oil production and federal offshore natural gas production in the Gulf accounts for 5% of total US dry production. Comment: I believe the EIA data is for the entire US, including Alaska. RBN Energy often limits their NG production discussions to the "lower-48."
US natural gas production: EIA update, December 4, 2017.

From the EIA:
Drilling wells in the Appalachia region has become very productive.
The average monthly natural gas production per rig for new wells in the Appalachia region increased by 10.8 million cubic feet per day since January 2012.
EIA attributes this increase to efficiency improvements in horizontal drilling and hydraulic fracturing in the region, which include faster drilling, longer laterals, advancements in technology, and better targeting of wells.
For example, in West Virginia, the average lateral length per well has increased from about 2,500 feet in 2007 to more than 7,000 feet in 2016. Some operators have recorded lateral lengths as long as 15,000 feet in the Marcellus and 19,000 feet in the Utica. Along with longer horizontal drilling, the days it takes for completion have decreased from about 30 days in 2011 to 7 days in 2015.
Comment: For comparison, lateral lengths in the oily Bakken are around 9,000 to 10,000 feet, and take about 10 days to reach TD, but the range can be quite wide, some still taking as long as 30 days (of course, that is not continuous drilling).
Note: in the EIA graph above, the Appalachia region was producing about 20 billion cf/d as of 2017. The chart below suggests about 25 billion cf/d during 2017. But notice the current rate of production in the Marcellus, nearing 30 billion cf/d in September, 2018. Maybe that's why folks are not concerned about that widening gap in the "natural gas fill rate" as noted in the original post.

Current Appalachia production, ycharts:

Original Post

The following was previously posted, just a few days ago.

NG fill rate, link here. I still think this is going to be the most interesting metric to follow this winter. If it's a cold winter, and if storage rates fall outside the historic minimum going into November, and if the US shale natural gas operators can meet natural gas demand this winter, it means tracking natural gas fill rate is almost meaningless:

Update: I think this is one of the most fascinating stories currently being followed.

If this is a cold winter, it will be interesting to see if the natural gas sector can respond. It it is a cold winter and the natural gas sector responds "without missing a beat," it will suggest to me that the tracking of this metric is absolutely unnecessary.

Having said that, look at this article today from "Ag Metal Miner" over at
Futures markets are suggesting the currently benign level of natural gas price volatility may not remain through the winter months.
According to the Financial Times, market volatility this year has been the lowest on record despite inventory levels falling 19.5 percent below average and by the time winter starts are set to be at their lowest in more than a decade.
The Financial Times puts this down to investors being lulled into complacency by a seemingly unstoppable wave of new supply from the shale market rising inexorably to meet rising demand.
The government last week forecast 81.1 billion cubic feet per day in dry gas production for 2018 — a record high — and up by 7.5 billion cu ft/d from 2017.
But is the market safe to assume shale gas will supply regardless of demand?
Natural gas producers are systematically hedging their sales throughout next year, often a sign they plan to continue an aggressive policy of drilling and expansion.
That activity has contributed to a dipping of forward prices, as there are more sellers in the futures market than buyers.
But inventory levels are low — some would suggest dangerously low — after a high summer demand due to hot weather increasing demand for air conditioning. Natural gas “power burn” surged to a record 37.7 billion cubic feet per day during July, the Financial Times reports.
So, we'll see.

The FT story is behind a paywall. I could not get to it "thru" but I was able to google and get to it "thru" a Yahoo link.

From the FT article:
When US natural gas futures passed a milestone this month, they did so quietly: volatility fell to the lowest levels since the market’s debut nearly 30 years ago. 
The event seemed improbable. Volatility usually fades when commodity stocks are ample. Yet US gas stocks are 19.5 per cent below average. 
When the winter starts they are set to be at their lowest in more than a decade. This situation is the latest example of how the world’s largest gas market has been transformed by shale drilling. While demand for gas is galloping, it has been met by waves of supply that show no sign of abating. Conditions that put traders on edge a decade ago get shrugs.
And that's way I think it will be fascinating to watch this play out this winter. Especially if it's a cold winter.

Wow, I love to blog.

Investment Update On Three Operators In The Bakken -- SeekingAlpha -- August 25, 2018

Disclaimer: this is not an investment site.

This is a few weeks old, but some folks may be interested.

From SeekingAlpha: US shale -- NAV analysis of Williston Basin E&Ps -- 1Q18 update -- NOG, OAS, OAS.

Contributor: Andre Kovensky.

Some data points:
  • Whiting Petroleum is undervalued, on July 2, 2018: $50.41
  • Oasis Petroleum is about fairly valued, on July 2, 2018: $12.64
  • Northern Oil and Gas is about fairly valued, on July 2, 2018: $3.11
Additional data points, since the contributor's last report:

OAS sale of non-strategic acreage:
65,000 acres for $283 million. Production from this acreage is 4,400 BOE per day. Applying a market metric of $40,000 per BOE of daily production, $176 million of the sale price can be attributed to the current production. Thus, OAS received $1,646 per acre for whatever future drilling locations are on the acreage. My model assigned zero value to this acreage since I assumed it would not be drilled.
NOG: NOG's net debt / 2018E EBITDA is now in line with WLL and OAS.

The group:
The group has benefitted from a market sentiment change away from Permian Basin E&Ps toward Eagle Ford shale and Williston Basin E&Ps. Permian E&Ps are receiving large price discounts for their oil due to pipeline takeaway congestion, where Eagle Ford and Williston E&Ps do not face this issue. Also, from a technical standpoint, WLL and OAS are two of the highest weighted E&Ps in the XOP ETF, which I believe has created material incremental demand for the shares. NOG’s management changes and balance sheet restructuring have enabled the market to look at its assets and profitability through a clearer lens, removing any bankruptcy fears. Also, NOG was recently added to the Russell 2000 which creates material incremental demand for the shares.
Williston Basin production is heavily weighted to oil. Also, needed Williston Basin pipeline capacity finally came online in 2017 leading to reductions in basis differentials. Together, these factors have made Williston Basin E&Ps very profitable. NOG is now generating some of the highest EBITDA per BOE among all the US shale E&Ps I follow. NOG’s EBITDA per BOE increased by about $6 in 2018 Q1 versus 2017 Q4. OAS also generates very high EBITDA per BOE, increasing $2 in 2018 Q1 versus 2017 Q4. WLL’s profitability is behind NOG’s and OAS’s primarily because of WLL’s Niobrara shale production (which WLL wants to divest).
Natural gas:
Nat gas realizations are not material to profitability. But, for those of you interested, WLL had weak price realizations at a $1.20 discount to the benchmark Henry Hub price.
The Trauma Page

I do not know the backstory, but apparently while the family was at a soccer game, Corky sustained a head injury that required an ice pack.

By the way:

Nice Jump In Production In A Chimney Butte MRO Kupper Well -- August 25, 2018

The well:
  • 16626, 289, MRO, Kupper 34-10H, Chimney Butte, t9/07; cum 331K 6/18; FracFocus: not re-fracked:
Production profile of note:

Production following initial frack:

Hanover Federal Well: Jump In Production -- August 25, 2018

Hanover Federal wells tracked here.

FracFocus, not re-fracked:
  • 20387, 1,445, Oasis, Hanover Federal 5300 13-14H, Willow Creek, t10/11; cum 398K 6/18; recent data:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Data after first frack:


Hanover Federal Wells


October 4, 2018: update.  New graphic -- pretty much the same area as the graphic at the original post --

Original Post

The graphic:

The wells:

  • 31987, 1,063, Oasis, Hanover Federal 5300 41-11 13TX, Willow Creek, huge well; 90K in five months; t4/18; cum 160K 5/19;
  • 30392, 2,112, Oasis, Hanover Federal 5300 13-14 7T, Willow Creek, 50 stages; 4.1 million lbs, t5/17; cum 164K 5/19;
  • 28340, 459, Oasis, Hanover Federal 5300 41-11 10B, Willow Creek, t3/18; cum 173K 5/19;
  • 28339, 853, Oasis, Hanover Federal 5300 41-11 11T, Willow Creek, t4/18; cum 158K 5/19;
  • 28309, 797, Oasis, Hanover Federal 5300 42-11 9T, Willow Creek, t4/18; cum 141K 5/19;
  • 28308, 1,185, Oasis, Hanover Federal 5300 42-11 8B, Willow Creek, t3/18; cum 141K 5/19;
  • 28307, 322, Oasis, Hanover Federal 5300 42-11 7T, Willow Creek, nice well; 25K in two months; t4/18; cum 95K 5/19;
  • 27079, 422, Oasis, Hanover Federal 5300 44-11 5T, Willow Creek, t5/17; cum 185K 5/19;
  • 27078  467, Oasis, Hanover Federal 5300 44-11 4B, Willow Creek, t5/17; cum 212K 5/19;
  • 26976  532, Oasis, Hanover Federal 5300 44-11 3T, Willow Creek, t5/17; cum 166K 5/19;
  • 26975, 856, Oasis, Hanover Federal 5300 44-11 2B, Willow Creek, 50 stages; 10.1 million lbs, t5/17; cum 238K 5/19; look how old this permit was when the well was completed;
  • 26912, PNC, Oasis, Hanover Federal 5300 13-14 9T, Willow Creek,
  • 25169, 1,088, Oasis, Hanover Federal 5300 41-11 12B, Willow Creek, t4/18; cum 172K 5/19;
  • 20387, 1,445, Oasis, Hanover Federal 5300 13-14H, Willow Creek, cased hole; 4.5 million lbs, nice jump in production; not re-fracked, t10/11; cum 428K 5/19;

For Newbies: The Recently Fracked Burr Federal Wells Have Been Updated -- August 25, 2018

Much to learn from these recently fracked Burr Federal wells.

This is the production profile of an older Burr Federal well in the area that has just come back on line. According to FracFocus this well was not re-fracked:
  • 30503, 759, CLR, Burr Federal 14-26H, Sanish, API - 33-061-03522, t12/15; cum 249K 6/18;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

I track these kinds of wells over at "wells of interest" but there are now so many of them, I will add to the list simply by exception.

This is a phenomenon that is not being reported by "anyone else."

From what I can tell, analysts consider this phenomenon uninteresting to follow. Likewise, it appears that analysts don't think DUCs are worth tracking.

It should be noted that Lynn Helms predicts a huge production surge in North Dakota "this fall." The official numbers lag data from the field by two months, so if the surge occurs in October/November, we won't see the official numbers until December/January, and those numbers won't be reflected in earnings statements until after the 4Q18 has closed out. Generally speaking, companies like Whiting and Continental Resources will give us an indication of how things are going in their monthly corporate presentations prior to conference calls.

By the way, the well above was originally fracked in mid-to-late 2015. What was the original production like after the first frack?


By the way, not being talked about is the near-100% success rate of fracks. This is not trivial. New operators had a devil of a time in the early days -- they put in a nice well, drilling to depth, and then the frack went back. Even on simple vertical wells, novice operators can "screw" up a stimulation.

The fact that Bakken operators are literally scoring almost a 100% success rate of stimulation / fracking is incredible in and of itself. Staggering. The Bakken operators have set the bar so high analysts have now accepted that as the "norm." To say the least, this is neither trivial nor should it be taken for granted.

There must be a 100 folks involved in the successful fracking of a well, and if any one of them screws up, it can literally mean a failed frack. The 100 folks: all the way back to the geologist to the trucker delivering the sand.

By the way, open book test: how many more years of drilling is there in the Bakken if the price of oil supports "full" development of the Bakken?

The answer is in one of studies linked this past week.

South Carolina Nuclear Reactors -- Update -- August 25, 2018; The Question: This Story Should Concern ... Exactly ... Whom?


October 13, 2018: US has critical shortage of icebreakers. 

Original Post 

Link to WSJ  here.
The primary owner of a power plant with two partially built nuclear reactors in South Carolina walked away from the $9 billion project last summer because of high construction costs and delays. Now no one wants to pay for it.
The utility overseeing the Virgil C. Summer plant is asking ratepayers across the Palmetto State to shoulder its construction expenses of $4.7 billion, citing a law passed last decade.  But local lawmakers are trying to force South Carolina Electric & Gas Co. to pick up more of the tab.
A federal judge handed lawmakers an initial victory earlier this month, ruling that a temporary state-imposed rate cut for customers could stand. The utility, known by its acronym SCE&G, is appealing the decision.
This dust-up is part of a larger U.S. dispute over how much public support should be provided to support nuclear power at a time when the industry is struggling to compete with lower-cost natural gas and renewable energy.
The South Carolina plant and a similar project in Georgia both encountered massive cost overruns that led to the bankruptcy of nuclear project builder Westinghouse Electric Co.  The company that owns the Georgia plant, which like the South Carolina project also received state support, said earlier this month that it would take an earnings charge to cover more than $1 billion in new cost overruns.
Okay, I'm getting way ahead of my headlights here, but this should be entertaining.
Disclaimer: this is not an investment site. Comments, facts, opinions follow.

After the federal judge's ruling, SCE&G could take a financial hit.

What do SCE&G investors think?

SCANA (SCG) is the holding company for SCE&G.

SCG was up about 4% yesterday. What gives?

Back on January 3, 2018, Dominion announced it would buy SCE&G in an all-stock offer.

D also rose yesterday in trading, up less than 1%. D is "down" for the YTD and the past six months, but seems to be in a trading range, now.

Dominion's market cap: $50 billion.

The nuclear reactor tab: $5 billion.

After going through this, the bottom line(s) for me:
  • the WSJ nuclear reactor story is a non-story for investors;
  • it appears the parties involved will let this play out in court and investors appear unconcerned
  • South Carolina ratepayers are going to get up to $1,000 in cash from Dominion when the deal closes
  • what's not to like?
Dominion seems, to me, to be in the news a lot. Recently.

Northwest Passage Icebound

This was the year -- or maybe last year, or maybe the year before that -- that Algore said the "Northwest Passage" would be ice-free. Many, many nations and shipping companies were counting on that.

Not so fast.


Not only is the "northwest passage" icebound, but the ice conditions are heavier than normal.

Wow, this gets tedious.

And, not reported on the nightly news or in any mainstream media. My hunch: Scientific American won't even mention it. And based on what I've seen in Scientific American lately, it has changed its motto: all the science fit to print, as long as it's politically correct.

From IceAgeNow:

CCG icebreakers cannot safely escort pleasure craft.” At least 22 vessels affected and several have turned back to Greenland. From the Canadian Coast Guard:
Due to heavier than normal ice concentrations in the Canadian arctic waters north of 70 degrees, the Canadian Coast Guard, recommends that pleasure craft do not navigate in the Beaufort Sea, Barrow, Peel Sound, Franklin Strait and Prince Regent. CCG icebreakers cannot safely escort pleasure craft. Operators of pleasure craft considering a northwest passage should also consider the risk of having to winter in a safe haven in the Arctic, or in the case of an emergency, be evacuated from beset vessels. Safety of mariners is our primary concern.
The List of Predictions
A Few Past Forecasts of Ice-less Arctic Summers

A comment from the story at this post, a few past forecasts of iceless Arctic summers:
  • in 1972 in The Christian Science Monitor's Bernt Balchen predicted no ice by 2000;
  • in 2006 Marika Holland of National Center for Atmospheric Research predicted an ice free Arctic by summer 2040;
  • in 2007 Jonathan Amos of the BBC forecasted ice free Arctic by summer 2013;
  • In 2007 Al Gore in his Nobel speech predicted an ice-free Artic by 2014;
  • In 2008 Robin McKie in the Guardian predicted an ice-free Arctic in summer 2013;
  • in 2008 De Gheldere, climate ambassador of Al Gore publicly forecasted Arctic summer ice would have disappeared by 2013-2018;
  • In 2008 in National Geographic David Barber, of the University of Manitoba, predicted an ice-free Artic in summer 2008;
  • ditto Steve Connor in the Independent;
  • In 2009 in a speech to the U.N. climate conference Al Gore predicted an ice free Arctic by 2014;
  • in 2010 ("Arctic ice expert") Robert Correll predicted an ice free Arctic by summer by 2030;
  • in 2011 Keith Pickering in Daily Kos predicted an ice-free Arctic by summer 2018;
  • In 2011 Joe Roma predicted an ice-free Arctic by 2030;
  • in 2011 Professor Peter Wadham ("One of the world's leading ice experts") predicted that by 2031 the Arctic would be ice-free;
  • in 2012 the same Prof Peter Wadhams predicted an ice free Arctic by 2016;
  • in 2012 Jarvis Cocker (another of the 97% consensus?) predicted an ice-free Arctic by 2032;
  • ditto Catherine Brahic in the New Scientist;
  • and I could go on and on...
  • in 2017 the Economist predicted ice-free summers in the Arctic by 2040
  • what do these prediction have in common ?
  • they are all over the place;
  • all those unlucky enough to make relatively short-term prediction have found to be utterly wrong;
  • those smart enough to make predictions for when they will be in retirement and hope that we haven't bookmarked their forecasts look like they will be wrong too; and,
  • none mention anything about the Antarctic ice mass which is 10 times bigger and growing, because that would be - ermmm... - inconvenient

Week 34: August 19, 2018 -- August 25, 2018

This is a shorter list than usual because I posted the "top stories" later than usual last week.

Having said that, the top stories are quite interesting.

What don't you want: Bakken holds on to top spot among IRRs

From others
Whiting bucks trend: thinks different; works smart 
CLR: using max amounts of proppant
Enerplus has an "Aussie animal" pad
Busy: eight new permits; fourteen permits renewed; five producing wells reported as completed;

Whiting bucks trend; using "less" proppant

Legacy Fund deposits drop for the month of August, 2018

Enbridge to buy Spectra Energy Partners 

Latest GDP Forecast -- 3Q18 -- What Don't You Want? -- 4.6%

From "Federal Reserve Atlanta":

Latest forecast: 4.6 percent
August 24, 2018
The GDPNow model estimate for real GDP growth (seasonally adjusted annual rate) in the third quarter of 2018 is 4.6 percent on August 24, up from 4.3 percent on August 16.
After yesterday’s releases on new-home sales and costs from the U.S. Census Bureau, the nowcast of third-quarter real residential investment growth increased from -4.5 percent to -1.1 percent.
After this morning’s advance durable manufacturing report from the Census Bureau, the nowcast of third-quarter real nonresidential equipment investment growth increased from 6.4 percent to 7.5 percent and the nowcast of the contribution of inventory investment to third-quarter real GDP growth increased from 1.92 percentage points to 2.03 percentage points.
So, what don't you want