Tuesday, November 17, 2015

What We Will Be Talking About Wedneday -- SunEdison Shares Plunge -- November 17, 2015

Media-ite is reporting:
For First Time Ever, Both Fox News and FBN Rank in Top 5 of All Cable TV Last Week. 
FBN hosted the GOP presidential debate earlier in the week, and all networks covered the Islamic terrorist attack in Paris. Unlike CNBC, FBN was given very, very marks for the way they "managed" the debate.

What We Will Be Talking About Wednesday

This is not an investment site. Do not make any investment or financial decisions based on what you read here or think you may have read here.

Barron's is reporting:
Shares of solar installation firm SunEdison are down $1.51, or 33%, at $3.05, continuing to feel the after-effects of a disappointing Q3 report on November 10th, that has been followed by stock sales by prominent hedge funds.
Today’s news brings some potentially troubling findings about the company’s debt position, and some worrying signs from Vivint Solar, the residential installation firm that SunEdison is acquiring for $2.2 billion.
Yesterday afternoon, Vivint reported Q3 revenue that topped analysts’ expectations, and profit that was short by a couple pennies. The stock today is down $1.16, or 12%, at $8.42.
The results “severely call into question the health of the Vivint Solar organization (especially in the context of strong results from Sunrun and SolarCity)” writes Credit Suisse’s Patrick Jobin, who has a Neutral rating on the shares.
In particular, installations of only 61 megawatts in the quarter, and a 7% decline in megawatts booked, suggest that “For the company to still achieve prior 2015 guidance of 290-310 MW, Q4 installations would have to be 118-138 MW (+95-128% sequential), a very long putt in our view.”
Jobin thinks the poor showing implies the acquisition itself may be hurting operations, and also that SunEdison investors should be concerned about what the company is likely to be acquiring at this point.
This was from just a few days ago (November 10, 2015): SunEdison Tanks --
Despite revenues increasing more than expected, shares tank. Business Insider is reporting:
SunEdison shares dropped by more than 22% in trading on Tuesday. 
The renewable-energy firm reported third-quarter results before the market open, and posted a wider-than expected loss (excluding some items) of $0.92, versus the estimate for $0.65, according to Bloomberg.
Revenues of $476 million beat the consensus forecast for $452.6 million.
Data points:
  • at $5.59/share; lowest in more than two years
  • announced last month to lay off 15% of its workforce 
  • major investor: hedge fund, Greenlight Capital
  • Greenlight Capital recorded its worst monthly performance since October, 2008, most due to SunEdison
  • shares popped by as much as 6% on October 30, 2015, on rumors that another hedge fund billionaire had bought a position in SunEdison
For more on Vivant and Solar City (both with similar business models), see this dismal outlook as reported by Motley Fool
Long term, I think it's becoming clear that leases and power purchase agreements won't be the dominant financing option for homeowners. SolarCity may already be playing from behind with these market changes.

Five (5) New Permits; HRC Reports Two High-IP Bakken/Three Forks Wells -- November 17, 2015

Active rigs:

Active Rigs64184183187201

One producing well completed:
  • 29391, 1,142, XTO, Johnsrud Federal 34X-14H, Bear Den, 18-foot target zone with the first bench TF; within target zone 94.%; t11/15; cum 2K 9/15 (10 days of production); API 33-053-06257; from FracFocus:
    • 8/22 - 25/15: 2.6 million bbls water, proppant 11%
    • 9/30 - 10/1/15: 1.6 million bbls water, proppant 13%
Wells coming off the confidential list Wednesday:
  • 27103, 2,808, HRC, Fort Berthold 148-94-27C-22-8H, McGregory Buttes, 23 stages, 3.5 million lbs, t5/15; cum 88K 9/15;
  • 27105, 2,552, HRC, Fort Berthold 148-94-27C-22-7H, McGregory Buttes, a Three Forks well, 31 stages, 4.7 million lbs, t5/15; cum 69K 9/15;
  • 31100, SI/NC, Hess, BL-Iverson C-LE-155-96-1423H-1, Beaver Lodge, no production data,
  • 31140, SI/NC, Statoil, Cheryl 17-20 XE 1H, Banks, no production data, 

27105, see below, HRC, Fort Berthold 148-94-27C-22-7H, McGregory Buttes:

DateOil RunsMCF Sold

27103, see below, HRC, Fort Berthold 148-94-27C-22-8H, McGregory Buttes:

DateOil RunsMCF Sold


Five (5) new permits:
  • Operator: Slawson
  • Fields: Big Bend (Mountrail)
  • Comments: based on location of the pad and the name of the wells (Submariner Federal) these wells will run west-to-east under the river. Of the five new permits, four will most likely be 1280-acre spacing; one will be on an overlapping 1280- or 2560-acre drilling unit.

TransCanada: Mexico Is A Bigger Deal Than The Keystone -- November 17, 2017

BloombergBusiness, today, writes that TransCanada will build the Tuxpan to Tula natural gas pipeline in Mexico:
TransCanada won the rights last week for its sixth pipeline in Mexico, one of the company’s key targets for growth. The Nov. 10 decision came four days after the U.S. denied TransCanada’s bid to build its Keystone XL oil sands project across the border into Nebraska where it would connect to existing pipes leading to Gulf Coast refineries.
That's what it says, TransCanada's "sixth pipeline in Mexico."

But just a few days ago, Oil & Gas Journal wrote:
By 2018, with Tuxpan-Tula, TransCanada will have five major pipeline systems, with $3 billion invested in Mexico.
Yes, I checked that several times, and "cut and copied" it directly to the blog.

So BloombergBusiness says this will be TransCanada's sixth, and Oil & Gas Journal says it will TransCanada's fifth pipeline in Mexico.

Other data point points from the BloombergBusiness article:
  • TransCanada beat out Carlos Slim's Grupo Carso and Sempra Energy for this pipeline
  • TransCanada now holds the rights to develop and operate 2,000 kilometers of pipelines in Mexico
  • TransCanada currently only operates gas pipelines in Mexico but wants to expand to oil and power generation
  • with Mexico much less difficult to deal with, TransCanada argues that Mexico is a bigger deal than the Keystone XL
  • the company said it plans to extend its dividend growth plan of 8 to 10 percent annually through 2020 as more and more Mexican projects come on line
  • there is little pushback in Mexico once the government approves a project
  • Mexico plans to expand its pipeline infrastructure 75% by 2018 and is seeking as much as $10 billion in investment for 24 new projects in the short term
And then this:
  • Mexico is planning to hold as may as five pipeline auctions before the end of January, 2016, and TransCanada will look at all of them.
After all, with the Keystone XL killed, TransCanada has other eggs to fry, or whatever the idiom is.

Pipeline, The Ventures

Walmart Beats -- November 17, 2015

National Oilwell Varco to close another Texas facility, cut jobs:
The facility, at 6738 Sideview Road in San Angelo, will cease operations, which will be finalized between January 15 and January 29, 2016.
The company did not specify a reason for closing the support facilities, though it cited economic reasons for closing other Texas facilities in previous WARN letters this year. Those letters have included 85 job cuts in Houston; 150 in Willis, north of Houston; and 110 in Mineral Wells, in North Texas.
Speaking of which, a reader wrote to tell me that OXY USA took the sign off its building in Dickinson earlier today, November 17, 2015.

Wal-Mart Beats

Yahoo!Finance is reporting:
Wal-Mart (WMT) gave an upbeat earnings outlook for the current quarter after posting earnings per share that topped Wall Street views in its latest quarter. However, sales slightly missed forecasts, falling more than 1% from a year earlier on weak sales overseas. 
Shares up nicely.

And this is the answer to the oft-asked question: Wal-Mart or Walmart?

Walmart vs Kroger, Whole Foods

I don't recall ever being in a Kroger supermarket before this past weekend. I assume I have, just didn't know it or don't remember.

My granddaughter and I were looking for a place to eat during a break in the water polo tournament, and on our way to Jersey Mike's subs in Flower Mound, TX, we walked by a Kroger. I've never met such friendly employees in a grocery store before, nor have I seen a nicer store.

When we walked in, an employee asked us if we wanted coffee and a donut. I assumed it was a fund-raising effort by some organization but it turned out to be simply Kroger's way of greeting us this particular Saturday morning. She had just run out of coffee, but told me there was more coming, but if I was in a hurry, there was also (free) coffee just inside the store.

The store was bright, not particularly busy, and seemed to have a really nice selection. I didn't do much comparison shopping but did note that there was an ample supply of 20-lb turkeys for 59 cents/pound (store brand) and Butterball 20-lb turkeys for $1.19/pound. So much for the media scare that there would be a shortage of turkeys this year, and if one found them, they would be overpriced. Yes, I know there's a lot of bone in a turkey but these prices are better than the prices we are used to paying for chicken in many cases.

Throughout the store there were many samples to try, and we almost did not need to go to lunch. But my granddaughter loves Jersey Mike's (this was my first time) and so we watched what we ate at Kroger and then went to Jersey Mike's. Best subs I have ever had. I told that to my daughter, and she says Jersey Mike's subs are good, but there is one sub restaurant that was better, but she couldn't remember the name; they were in Charleston, SC.

I have trouble with those who think Walmart and Kroger / Whole Foods are competitors. I think the customer profile for Walmart is a whole lot different from that of either Kroger or Whole Foods. I'm not saying which store will do better, Walmart or Kroger financially or is a better investment, I'm just saying that if given a choice, I would go to Kroger to shop for groceries before I would go to Walmart. But then that's me, and I'm not raising a family of six on blue collar wages.

Evidence Of Communication Between Wells -- November 17, 2015


April 26, 2016: in the original post, it was noted that #26158 was taken off-line (status: inactive). As of November, 2015, this wells was back on line:
  • 26158, 3,771, Statoil, Johnston 7-6 3TFH, Banks, t11/14; cum 67K 2/16;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Original Post
This is a long note. There will be typographical and factual errors. I may be seeing things that do not exist. If this is important to you, go to the source.

While looking up this well for other reasons I happened across this little gem, which is another pixel in the Bakken mosaic, helping me to better understand the Bakken.
29564, SI/NC, Statoil, Skarston 1-12 XE 1H, Banks, no production data,
I think this is a big, big deal, but then I am inappropriately exuberant about the Bakken. I get excited about a lot of things that turn out not to be so exciting and I have been accused of "childlike glee" (yes, that accusation followed one of my book reviews over at Amazon.com).

So with childlike glee and with inappropriate exuberance I post the following -- a small excerpt -- from the file report on this well:
As a measured depth of 20,411', April 4, 2015, the decision was made to stop and circulate out gas while transferring mud and increasing the mud weight. The decision was then made to continue to circulate off bottom while preparation could be made to switch the drilling fluid to oil-based mud. The oil-based mud was then increased to 12 ppg. It was found that even with 12 ppg oil-based mud, the shut in casing pressure (SICP) continued to increase while the well was shut in. It was then decided that the mud weight should be increased further to near 14.2 ppg. This process took several days to complete.
It was later discovered that the unidentified mineral was in fact, ceramic proppant. This is sometimes used as frac sand, or in conduction with quartz sand. It was also later confirmed, that there was in fact communication with an adjacent well that had been recently completed. 
It was believed that this communication between wells was causing the increased pressure and fluid gains.
This adjacent well was the Statoil Johnston 7-6-3TFH (#26158).
The mud weight was increased to 14.2 ppg....after drilling resumed, the pressure increased, and fluid gains were seen. The decision was then made to shut the well in and circulate bottoms up. This yielded a trip gas of 4,602 units, and a large flare ....
...drilling resumed .. while drilling ahead within the lateral, the ROP was near 35 ft/hr.
The slow ROP was due largely to the high mud weight. This caused the pump pressure to be near the maximum pump pressure rating of 5,000 psi at half pump strokes of the previous salt water driling fluid. Even with the high mud weight, slow ROP, and going through the gas buster, the background gas was near 750 units, and a 3 - 10 foot flare produced.
While nearing the end of the drilling, the report continues:
Bottoms up was circulated through the choke, after getting back to bottom. This resulted in a 10'flare and a trip gas of 6,282 units. ... [several challenges ensued]...the lateral was called TD at 20,823 feet (approx 1225 feet early) on April 14, 2015.
Separation and formations:
Horizontal separation between the laterals of the Skarston well and the Johnston well: about 600 feet

Vertical separation between the two laterals, approximately, 130 feet, it appears.
  • The Skarston well, TVD = 10,903 feet
    The Johnston well, TVD = 11,035 feet
The target formations:
  • Skartson: middle Bakken
  • Johnston: Three Forks

The Johnston well:
  • 26158, IA/3,771, Statoil, Johnston 7-6-3TFH, Banks, 35 stages, 4.5 million lbs sand and ceramic, t11/14; cum 18K 9/15; there is no information in the file report why this well is now inactive 
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Another Blow For Alaska -- November 17, 2015


November 20, 2015: Alaskans would rather let the state go broke and increase taxes
Alaska’s finances are unlike those of any other state. It has no income tax, no statewide sales tax and among the lowest per capita tax burdens in the U.S. Instead of from taxes, its money comes overwhelmingly from two sources: oil revenue, which provides close to 90 percent of the discretionary budget, and federal funds, of which Alaska has historically been among the top per capita recipients.
Revenues have slumped along with oil prices, however. In fiscal 2012, when oil prices spent much of the year above $100 a barrel, general fund revenues topped $7 billion. This year, with oil prices down to about $40 a barrel, the state expects to collect just $2.2 billion. Even after billions of dollars in budget cuts in the past two years, the state still faces an estimated $3 billion shortfall heading into the next fiscal year.
Alaska’s problems go beyond oil prices. Federal funding has fallen since stimulus funds dried up after the recession, and the state’s influence in Washington has waned since the electoral defeat of longtime U.S. senator Ted Stevens in 2008. The prices of other natural resources, such as gold and salmon, have also declined. Most significantly, the state’s oil production has been falling for decades, dropping below 500,000 barrels per day in 2014 from a peak of more than 2 million barrels per day in the late 1980s. Lower production means it takes higher prices to generate the same amount of tax revenue; the state estimates that it would take prices of $110 a barrel or more to balance the state budget at current production levels.
Making matters more difficult: Alaska may be entering a recession, if it isn’t in one already. “It’s at that point where my gut says we’re tipping toward recession,” economist Jonathan King of Anchorage consulting firm Northern Economics said earlier this week.
On Friday, the federal Bureau of Labor Statistics reported that after two months of job losses, Alaska added about 2,000 jobs in October compared with a year earlier. But the oil industry continued to cut jobs, as did the government, which makes up a larger share of employment in Alaska than in any other state but Wyoming. Alaska’s unemployment rate, at 6.4 percent in October, is well above the national mark of 5 percent.
Original Post
Seeking Alpha is reporting:
  • Statoil says it is exiting its Alaskan operations and closing its office in Anchorage, saying its leases in the Chukchi Sea are no longer competitive within its global portfolio
  • the decision means STO will exit 16 operated leases and its stake in 50 leases operated by ConocoPhillips
  • it follows Shell's September decision to pull out of controversial drilling off Alaska's Arctic cost after failing to find sufficient signs of oil and gas to make further exploration worthwhile
I've lost the bubble on whether Alaska has raised its taxes on oil production or if it is still being discussed.

California, Too

The Los Angele Times is reporting that California taxpayers are going to pay a lot more to bailout pension fund for state employees. 
The board of California's largest public pension fund approved a plan Wednesday to lower its estimate of future investment returns — a move that will require taxpayers to pay billions of dollars more than expected over the next decades.
For years, the California Public Employees' Retirement System has estimated it will earn an average of 7.5% or more a year from its investments. Under the new plan, the pension fund will slowly reduce that rate to 6.5%.
The plan that will reduce the rate in small increments over the next 20 years.

The vote was criticized by Gov. Jerry Brown, who had urged the board to move more aggressively to 6.5% rather than stretching the change over decades.
With investment income contributing less to the cost of government worker pensions, taxpayers must pay more.
If This Doesn't Put A Smile On Your Face ...

I will come back to these videos later, but if you haven't seen them, wow ... what a thrill awaits you.

A reader alerted me to Jools Holland's second episode in this documentary series, but it was so incredible, I had to go back to the first episode.

If you don't have time to look at a YouTube video today, simply click on the video below, move to 3:50, and let it play in the background while you scroll down the blog. This piano teacher charges $4 / second, according to Jools.

Walking To New Orleans, Fats Domino, Jools Holland's Walking To New Orleans
And this is why I love to blog.

What Wall Street Lawyers Are Talking About -- November 17, 2015

This is from the Energent Group, a site I seldom visit and almost never cite:

Flotek's Data Debacle
One of the big stories from last week was Flotek's data debacle that cut it's share price from $18.10 to 9.01. The company created a product called FracMax to demonstrate the economic returns of the company's complex nano-fluid (CnF).
A fund manager from Bronte Capital describes the inconsistencies in a Flotek investor presentation that provided specific operator well names and numbers based on FracMax.
That will probably be the last time you see specific well data in an investor presentation.
As an independent market research and data company, we can attest to the lack of transparency in oil and gas information. Our clients have taken rigorous steps to compare our data to public sources, internal sources, and other vendors. We take great pride in understanding the information, maintaining a high-level of quality, and monitoring the changing regulatory impacts. A difference that our clients see in our service, research, and data. Even though the FracMax production data is understated, the company is accused of providing faulty information. This story is continuing to develop, but unfortunately, this will likely become an industry issue.
I would have missed this whole story, but Mike Filloon has a long article over at Seeking Alpha on this very issue. I skimmed through it; I wasn't particularly interested. Posted for the archives.

From Filloon:
  • Bronte Capital did an excellent job of identifying incorrect well data by Flotek, but may have missed the mark as to how its well performed longer term
  • the Flotek well produced 24% more oil and 36% natural gas when compared to the average of the other three over an 11-month period
  • when doing well comparisons, it is very important to report on a per-foot basis. Lateral lengths always differ, and this better represents well performance
On Monday, Flotek  shares got crushed to the tune of 20% on a blog post by John Hempton of Bronte Capital. The stock continued lower, dropping to almost $8 from the $18 level traded last week. 
This post caused quite a stir, as it directly contradicts Flotek well production data on wells using its "Green" frac fluids.
Flotek insists its technologies have shown a consistent improvement in production when compared to wells in close proximity using other fluids. We have seen this in several presentations.
Bronte has pulled the production data from Texas, and directly refutes Flotek's numbers. It has gone as far to say that Flotek's data "looks like it was made up or at least systemically rigged."
This is a big deal, as the company has other revenue streams, but the business lives and dies with patented Complex nano-Fluid® technologies. Several law firms have announced investigations. Bronte Capital is a respected firm, and although we didn't own any Flotek shares when this was announced, we decided to crunch the numbers and check the validity of its claims.
Filloon concludes with two important issues. The first issue helps those trying to understand the Bakken:
When we break down production per foot, we see a much better result from the CnF well. The problem is a lack of data on well design, as we don't know the most important issue - well cost. We don't know stage length or the number of total stages per lateral. We also do not know the type or volume of proppant. Most importantly, we don't know whether the same number of frac clusters were used, or if any of these wells were high-density fracs. One could guess the Sabine wells were somewhat consistent, but this is still a guess. The Berger Unit is a Devon well, so there could be a completely different completion style. Another issue is lateral placement. The Eagle Ford interval is very thick and produces differently at differing depths. The Targac well is approximately 500 feet shallower. This could affect production, as well pressures increase with depth. These inconsistencies make it difficult to compare specific locations, but this is seen in most well comparisons. Wells production can change significantly from one section to the next, and we don't really know how good an area is until several locations are completed. That said, a conclusion can still be made with the data we have. The average three non-CnF wells produced 14.1 Bo/ft. and 26.96 Mcf/ft. over the first 11 months of well life. The Flotek CnF well produced almost 24% more oil and just under 36% more natural gas per foot. One could argue the shorter lateral length generally produces better production per foot as the operator has better control over the entire lateral length. But it still out produced the Gillespie well on a per-foot basis, and it was 172 feet shorter and used 2,042,250 gallons more of fluids.
The second issue has to (more) with how Bronte interpreted things, and how Bronte may have come to those conclusions:
In summary, the Bronte blog reported a significant issue with how Flotek was reporting well performance when comparing CnF to non-CnF wells. These issues are a big deal and could be bearish for the stock in the short term. It's impossible to know whether these were mistakes or intentional, but if we focus on production, we see very good numbers from the CnF well. It is important to realize every well is different. This includes lateral length, stage length, and proppant/fluids volumes. Stimulation techniques are also important and can affect production. A location's total production is important. It is also important to understand lateral length. We cannot compare a 10,000-foot lateral to one that is half that length. Well costs increase with each additional foot drilled and completed, as does production. Breaking down production per feet helps to solve the difficulty in differing lateral lengths. This was important in showing the improvements in production with respect to the Flotek CnF well. It is also very important to be forward-looking. It is great to see a well produce large volumes of resource in a short period of time, but if a huge decline rate is seen, payback times can suffer. Although Bronte made some very good points in its assessment of Flotek and the incorrect production numbers stated, it completely missed on its assessment of Molnoskey 1H.

How Good Are The Drillers These Days? -- November 17, 2015

In a Bloomberg/Rigzone article linked earlier today, this was reported:
Oil production in the Permian is forecast to rise 0.6 percent in December to 2.02 million barrels a day, even as drillers have idled 59 percent of the rigs there in the past year. Output in rival shale fields like the Bakken and Eagle Ford has fallen 12% and 25%, respectively, as drillers pulled out after oil prices crashed last year.
North Dakota has gone from 200 rigs to 60 rigs --
  • 60 rigs represents about 30% off the high
  • 70% of 200 = 140 -- the number of rigs lost since the high
So, I suppose one could say that there has been a lot of 70% of rigs and yet the amount of production has held up:
  • September, 2015:  1,162,253 (preliminary)
  • August, 2015: 1,187,631 (final, revised)
  • July, 2015: 1,206,996 (final, revised) 
  • June, 2015: 1,211,328 (final)(second highest; highest was December, 2014)
  • May, 2015: 1,202,615 (final)
  • April, 2015: 1,169,045 (final)
  • March, 2015: 1,190,502 (final); 1,190,582 bopd (preliminary)
  • February, 2015: 1,178,082 bopd (revised, final); 1,177,094 (preliminary)
  • January, 2015: 1,191,198 bopd (all time high was last month)
  • December, 2014: revised, 1,227,483 bopd (preliminary - 1,227,344 bopd - preliminary, new all-time high)
But it's more than just the number / the percent of rigs laid down. The 60 rigs are drilling to depth but the wells are not being completed; they are being shut in; the operators will come back later to complete / frack them. The wells that have been completed and are producing are seeing producers hold back production at these low prices.

At the risk of beating a dead horse:
I think this is the most under-talked about story in the Bakken right now, the fracklog. Everyone is concentrating on the "number," when, in fact, that's just a small part of the overall story. Here some things to keep in mind when thinking about these 1,000+ wells waiting to be fracked:
  • they are all in the sweet spots of the Bakken
  • operators have spent 7+ years perfecting completion techniques, resulting in huge 90-day production, and then 1-year production profiles
  • every well in the Bakken -- especially in the sweet spots -- will create a halo effect on neighboring wells 
  • the infrastructure is most robust in the sweet spots of the Bakken
  • 3 - 5 days to frack; once decision is made to frack, oil will moving fairly quickly after that

Bloomberg Reporting North Dakota Crude Oil Production Down 12% -- November 17, 2015

In a Bloomberg/Rigzone article linked earlier today, this was reported:
Oil production in the Permian is forecast by the government to rise 0.6 percent in December to 2.02 million barrels a day, even as drillers have idled 59 percent of the rigs there in the past year. Output in rival shale fields like the Bakken and Eagle Ford has fallen 12% and 25%, respectively, as drillers pulled out after oil prices crashed last year.
From the monthly Director's Cut posting North Dakota crude oil production:
  • September, 2015:  1,162,253 (preliminary)
  • August, 2015: 1,187,631 (final, revised)
  • July, 2015: 1,206,996 (final, revised) 
  • June, 2015: 1,211,328 (final)(second highest; highest was December, 2014)
  • May, 2015: 1,202,615 (final)
  • April, 2015: 1,169,045 (final)
  • March, 2015: 1,190,502 (final); 1,190,582 bopd (preliminary)
  • February, 2015: 1,178,082 bopd (revised, final); 1,177,094 (preliminary)
  • January, 2015: 1,191,198 bopd (all time high was last month)
  • December, 2014: revised, 1,227,483 bopd (preliminary - 1,227,344 bopd - preliminary, new all-time high)
Doing the math:
  • the all-time high: 1,227,483 bopd, back in December, 2014
  • the most recent figure: 1,162,253 (preliminary)
  • 1,227,483 - 1,162,253 = 65,230 / 1,227,483 = 5.3%
Disclaimer: I often make simple arithmetic errors, and often make factual and typographical errors, but that 12% decrease reported by Bloomberg seemed on the high side.

For the record, 88% of 1,227,483 = 1,080,185 bopd.

A Shout-Out To The NDIC -- November 17, 2015

In a post over at SeekingAlpha, Mike Filloon says this:
Those who have experience in state production data know these are not always the best venues to navigate. Some states provide little to no information, while others are very concise, like the NDIC. Being from North Dakota, I may be a little biased, but there are few that will argue it has one of the best sites in the country.
I agree completely: the NDIC has been superb in providing data about the oil and gas industry in North Dakota. The commission has also done a superb job with rules / regulations walking a fine line among all the participants in the oil sector. I am very, very biased, but even if I was not biased, I would have to say that the NDIC is the best of all agencies reporting oil and gas exploration and production data. 

It had the blog possible possible.

Tuesday, November 17, 2015

Active rigs:

Active Rigs63184183187201

RBN Energy: Mexico's oil sector in a state of flux.
Mexico’s energy relationship with the U.S. is undergoing radical changes as its oil production sags, its refineries produce too much high-sulfur fuel oil and too little gasoline and diesel, and its imports of U.S. natural gas and transportation fuels rise. Add to this already complicated story the Mexican government’s efforts to inject competition and private-sector participation into a national energy sector long-dominated by state-owned PetrĂ³leos Mexicanos (Pemex) and that company’s plan to swap light U.S. crude for heavy Mexican oil. In today’s blog, “With A Little Help From My Friends—Mexico’s Oil Sector in a State of Flux,” Housley Carr begins a look at the ongoing transformation of U.S.-Mexico hydrocarbon trade and what it may mean for U.S. players—and Pemex.
A number of RBN posts over the past couple of years have detailed the evolution of the U.S. –Mexican energy relationship.
The most significant development to date has been a large increase in Mexican imports of U.S. natural gas – aided by new cross-border pipelines and Mexico’s build out of gas fired power generation assets.
More recently we covered the existing and potential market for imports to Mexico of U.S. liquefied petroleum gas (LPG _ a mixture of propane and butane – mostly propane.
But the energy trade traffic is not all in one direction.
The U.S. is a significant importer of heavy Mexican crude that is refined by Gulf Coast refineries and we have described the battle for market share at those refineries between Pemex and rival Western Canadian oil sands producers. In the past year the U.S./Mexico crude oil relationship has gotten even more complex with the advent of crude oil swaps that we described in “Have Another Swap of Mexican Crude” and which were finally approved to begin in early November 2015 at a rate of 75 Mb/d.
Fillon's update, but it does not address the Bakken, except in passing.

Oil producers hungry for deals in the Permian -- BloombergRigzone.

Oil dealmakers find slim pickings among premium-priced producers -- Bloomberg/Rigzone

Russia in talks to allow China into offshore Arctic projects -- Reuters/Rigzone.