Blogs

 

What's the crucial difference between a Media Interview and a Presentation on Electric and Hydrogen Vehicles? pt.1

What's the crucial difference between a Media Interview and a Presentation on Electric and Hydrogen Vehicles? pt.1 "The West's rush for EV's lacks perspective. The main forces pushing the EV industry are rarely mentioned, nor is the 'elephant in the room' ". This is a good clear start to a Presentation but terrible for a Media interview. There might not be time to add the details.   The Presentation continues ... "The two main forces are: the guilt-agenda of green lobbying power on governments and industry; and resulting government initiatives pushing EV's in a bid to signal green credentials and garner votes. The 'elephant' is about how all the massive extra amount of required electricity will be produced - certainly it won't be by renewables, which represent, even now, only a tiny percentage of world energy production.  Natural Gas and LNG are currently abundant, relatively clean, excellent sources of electricity generation and fuel for vehicles. China despite its lip service to Greenery is currently building coal-fired power stations. Germany is unwinding its Green leadership and exploiting coal again to reduce domestic and industrial costs."  How would the Media Interview best be started? See the Presentation's conclusion in part 2.

Roger Crisp

Roger Crisp

 

WTI and Brent very predictable and technical

In my previous review, I wrote that I closed deals to BUY. Someone might be out of the market or looking for a new position for long. But the prevailing pattern is good for the SELL position. This is obvious to a professional. Therefore, the teachings of all the great market gurus about stop loss cause me only a grin. They do not know much more.
  I closed my short transactions. Maybe for someone it's a trifle, but it's a nice little thing .. Today I watch the Grail .....

aP

A/Plague

 

So About That Petronas Dividend From Its Cash Reserves

The Petronas Dividend of RM 30 Billion has been in the Malaysia news lately. Here's an excerpt from an article yesterday: Pakatan MP questions need to use Petronas reserves for special dividend A Pakatan Harapan MP today questioned the rationale in using 36% of national oil company Petroliam Nasional Bhd’s cash reserves for the special dividend of RM30 billion. Wong Chen (PH-Subang) pointed out that Petronas’ cash reserves, as of last year, stood at RM128 billion, and the profit after tax was RM46 billion. “This worries me because we know there is a huge possibility Malaysia will be stuck in the trade war between US and China. “If we use all the money now, the financial power of RM54 billion, we may run out of ‘financial bullets’ when the crisis really hits,” he said in the Dewan Rakyat when debating the Budget 2019. The RM30 billion special dividend is part of RM54 billion that Putrajaya is asking from Petronas next year. It will be utilised to fully settle the outstanding tax refunds estimated at RM37 billion — RM18 billion in income tax and RM19 billion in goods and services tax (GST). Wong stated that while he understood Finance Minister Lim Guan Eng’s anger and frustration in inheriting the financial woes of the previous administration, he was of the view that Parliament needs a guarantee that a special dividend of this nature cannot be repeated in next year’s budget.   Yesterday, I had commented on LinkedIn a bit about this. Generally, my view is that if this is a one-off higher than normal dividend from Petronas, then it shouldn't be a problem. My concern is if this is an old crutch that is getting long in the tooth from decades-old age and too much reliance on Petronas to provide money. For some perspective, let me turn back the clock a couple years, when I interviewed Dr. Mahathir about Petronas in 2016. Here is an excerpt of my one-on-one interview: Interview with Former Petronas Advisor Dr. Mahathir Mohamad Dr.  Mahathir bin Mohamad was the 4th Prime Minister of Malaysia. He held the post for 22 years from 1981 to 2003, making him Malaysia's longest-serving Prime Minister. After stepping down as Prime Minister, Dr. Mahathir took on the role of Petronas Advisor in 2003. On March 11 2016, the Malaysian government terminated the services of Dr. Mahathir, due to a political dispute between former Prime Minister Mahathir and the current Prime Minister Najib Razak. The Prime Minister's Office said in a brief statement that the Cabinet had discussed the actions of Dr. Mahathir, and decided that since he was "no longer supporting the current Government, he should no longer hold any position related to the Government." On 30th March 2016, Dr. Mahathir was kind enough to agree to an interview with Oilpro Moderator Tom Kirkman, to discuss Petronas. ... Question:  In August 2015, the Petronas CEO told reporters that Petronas had RM 126 billion in cash reserves.
And in January 2016, the Petronas CEO told reporters that Petronas had RM 88 billion in cash reserves.
That's a RM 38 billion reduction in Petronas cash reserves in 5 months.
What is your opinion on Petronas current cash reserves? Dr. Mahathir:  Well, Petronas is regarded by the government as some kind of cash cow.  When the government is short of money, or needs to have some investment, usually they pump it off on Petronas.  And currently, the government is really short of money.  They have mismanaged things, including borrowing huge sums of money.  So they are in deficit.  And what we do know is that they have been cutting back on budgets, by 20% last year, and again 20% this year.   I am told that Petronas was told to make up for the loss of government revenue.  And of course Petronas reply was that they need the money for their capex. They have to invest all the time.  I think the rumors are they were told “Look, you are a government company. You are 100% owned by the government. Whatever you earn belongs to the government.  You give the money to the government, then you can borrow.  If you need money, you can borrow.” It would seem that the government finds difficulty borrowing.  So, asking Petronas, which has more credit-worthiness, I think, is the way for them to borrow.
  Things have changed quite a bit since that interview in March 2016. Personally, I think Dr. Mahathir and Lim Guan Eng (the Finance Minister) and the new federal government are doing an overall great job in rescuing and repairing the country's financial mess, left behind by the previous administration.  Notably, working to clean up the mess of 1MDB. And I understand a stop-gap measure of increasing the Petronas Dividend this year to help alleviate the budgetary shortfall as the federal government works to pay down earlier commitments and reduce debt.  Again, cleaning up the financial nuclear fallout from 1MDB won't happen overnight. This time around, Petronas actually has sufficient cash reserves to pay a higher dividend. Compare that with the situation a couple years ago... here's another question and answer from my interview in 2016: Question: Petronas has recently stated that they may have to borrow money in order to pay their RM 16 billion dividend for 2016. Petronas originally wanted to pay only RM 9 billion in dividends for this year, but the government announced that Petronas was going to pay RM 16 billion in dividends for this year. About a month ago, Petronas announced that they will likely have to go in debt in order to pay the government dividend this year.  Do you have an opinion about that? Dr. Mahathir: Well, I think the government, as I said just now, is short of money. Petronas will have problems paying them more than what Petronas can afford. But the government is in such a desperate state, that they don’t care what happens to Petronas. As I said just now, Petronas can borrow money more than the government can borrow. So Petronas will have to cough up the amount of money that the government directs it to pay to the government.     Again, if this is a one-off higher than normal Dividend this year from Petronas, then it should be no problem. Next year, the dividend should be reduced, to allow Petronas to re-invest more in new Exploration & Production activities, both domestic and overseas.   Just my opinion; as always, you are free to disagree.   “I have always strenuously supported the right of every man to his own opinion, however different that opinion might be to mine.  He who denies to another this right, makes a slave of himself to his present opinion, because he precludes himself the right of changing it.” – Thomas Paine (1737-1809)  

Tom Kirkman

Tom Kirkman

US - update through July 2018

This interactive presentation contains the latest oil & gas production data from 95,093 horizontal wells in 10 US states, through July. Cumulative oil and gas production from these wells reached 9.3 Gbo and 102.9 Tcf. Ohio and West Virginia are deselected in most dashboards, as they have a greater reporting lag. Visit ShaleProfile blog to explore the full interactive dashboards Oil and gas production from horizontal wells kept setting new records through the first 7 months of this year. The 5,600 new producers contributed ~2.2 million bo/d and 10.4 Bcf/d in July, versus 4,600 new producers in the same period last year (which contributed 1.6 million bo/d and 9.1 Bcf/d in July last year).   The steady increases in well productivity between 2012 and 2017 are clearly visible in the 2nd tab, ‘Well quality’, where the oily basins have been preselected. Almost 12 thousand wells were completed in these plays in 2014, more than in any other year, which is why this curve is drawn with the greatest thickness. The final tab shows the production and location of the wells operated by the largest operators, as measured by their cumulative production in the past decade. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected, and wells are grouped by the year in which production started. You can see in the graph above that the 7,600 wells that started in 2017 recovered on average almost 100 thousand barrels of oil in the first 8 months on production, while declining from 600 bo/d to 274 bo/d. More recent and granular data can be seen by grouping the wells by the quarter or month in which production started.   The 2nd tab, ‘Cumulative production ranking’, ranks all counties with horizontal production based on cumulative oil production. McKenzie and Mountrail counties, both in North Dakota, are in the lead, but Karnes (Eagle Ford) and Weld (Niobrara) are catching up on the number 2. Early next week I will have a new post on North Dakota, which will soon release September production data. In our ShaleProfile Analytics service we keep all data up-to-date on a daily basis, and for most states we already have August or even September production in. If you’re interested, you can request a demo or trial here. Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below. FracFocus.org Colorado Oil & Gas Conservation Commission Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories. Montana Board of Oil and Gas New Mexico Oil Conservation Commission North Dakota Department of Natural Resources Ohio Department of Natural Resources Pennsylvania Department of Environmental Protection Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data. West Virginia Department of Environmental Protection West Virginia Geological & Economical Survey Wyoming Oil & Gas Conservation Commission   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2DBiiE9     Follow us on Social Media: Twitter: @ShaleProfile
Linkedin: ShaleProfile
Facebook: ShaleProfile

shaleprofile

shaleprofile

Thoughts on Multiculturalism in Europe

Twenty-plus years ago I lived in England, had a Sri Lankan boyfriend, an Israeli best friend who shared a flat with a Palestinian guy, and a Persian housemate. This is still my idea of multiculturalism. Yet 20 years later what I read and see about Europe -- and Turkey but that's a different question altogether -- suggests the multicultural model governments have been shoving down people's throats has begun to backfire and it is backfiring spectacularly. Take the hidden camera film about the encapsulated Muslim neighbourhoods in Paris. This is no spin and no fake news. I have a friend who lives and Paris and she has vouched for the genuineness of these neighbourhoods. There are similar places in Germany, too, if we are to believe none other than Angela Merkel, who said in an interview such encapsulated areas have no place in the German society. Ironic, given she put a lot of effort into taking migration to ridiculous levels. Then there's Denmark, where I saw (hopefully because I only had three days) multiculturalism still working, probably because the country, as far as I remember, limited its intake of economic (sic) refugees. There I saw people of various colors all smiling and friendly, as befits one of the happiest nations in the world. And then I saw a boy that eyed me suspiciously for several minutes until I felt extremely uncomfortable (I went out to smoke and forgot the keys to the Airbnb, okay? Don't tell anyone). That one single boy is new to the country, I'm sure. I really hope he won't look at this very typical Middle Eastern way at people in five years. Because he will have assimilated. Assimilation is the only sensible way of actually accomplishing multiculturalism that doesn't give rise to racist extremists. I will here quote Mr. Schwarz, an expat in a country neighbouring his home one, who, after 20 years here says "We" when he talks about the locals and "they" when he talks about his countrymen and countrywomen. The only way to have a decent life in a foreign country even one that is culturally close to your home one, is to assimilate, learn the language and the culture, and make it your own. This emphatically does not suggest you need to give up your own culture or religion. What it does suggest is that if you want to live in a society you need to become a part of it, rather than an appendage that feeds from a society, operates in it, but remains a separate part of that society and, ultimately, does not contribute to the greater good. That's what encapsulation is all about and to me, it is the one single negative aspect of the recent migration waves that can bring the whole European Union down. How did we get here? We need to thank PC gone mad and congenital human stupidity. The more you force a group of people to accept something new and unfamiliar as normal and familiar without giving them enough time to process this thing, the more they will clench their teeth and refuse to eat it. The pendulum, as I like to say, always swings. The further it swings into one direction, the further it will then swing into the opposite one. it's just one of these laws that can't be violated. And personally, I believe Western Europe is being so stupid because they have no group memory of the Ottoman empire ruling over them. We do although we won't continue to have this memory for long as history is being rewritten. Literally.

Marina Schwarz

Marina Schwarz

Eagle Ford - update through July 2018

This interactive presentation contains the latest oil & gas production data from all 21,344 horizontal wells in the Eagle Ford region, that started producing since 2008, through July. Visit ShaleProfile blog to explore the full interactive dashboards In July 228 horizontal wells started production, the highest number in more than 3 years. Although the graph above shows a dip in production in July, this is partially because of reporting lag, and I expect that when these wells have a full month on production in August total output will show a bump.   Average production profiles haven’t changed much in the past couple of years, especially since 2017, as you can see in the ‘Well quality’ tab. Laterals (at ~ 7k feet) didn’t get any longer in 2018, while proppant intensity increased with about 10%. More information on these trends can be learned in our ShaleProfile Analytics service.   EOG is already for more than 5 years the top oil producer in this area, and it currently operates about 20% of total production capacity (“Top operators”).   The ‘Advanced Insights’ presentation is displayed below: In this “Ultimate Recovery” overview, the relationship between production rates and cumulative production is revealed. Wells are grouped by the year in which production started. These curves appear to bend slightly downwards, hinting at a hyperbolic decline with a b-value smaller than 1. Production profiles with a harmonic decline (= hyperbolic decline with a b-value of 1) show up on this type of plot as a straight line. The wells that started in 2014 (the year which saw the greatest number of new producers), are on track to recover on average 150 thousand barrels of oil (and ~0.6 Bcf of natural gas) before hitting a production rate of 30 bo/d.   Devon and ConocoPhillips are still showing the best well results on average, as measured by the cumulative oil production in the first 2 years (see “Productivity ranking”).   Early next week we will have a post on all 10 covered US states.   Production data is subject to revisions, especially for the last few months. For this presentation, I used data gathered from the following sources: Texas RRC. Production data is provided on lease level. Individual well production data is estimated from a range of data sources, including regular well tests, and pending data reports. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2Jtl5zq     Follow us on Social Media: Twitter: @ShaleProfile
Linkedin: ShaleProfile
Facebook: ShaleProfile

shaleprofile

shaleprofile

 

TETRA Technologies: A Diamond In The Rough That Can Triple In The Next Year

This article was recently published on Seeking Alpha.  It might be of general interest to this community and, of course, I would be interested in any comments that might help to prove or disprove my thesis.   TETRA Technologies: A Diamond In The Rough That Can Triple In The Next Year Summary Tetra Technologies, Inc. (TTI) is a deeply undervalued small cap energy services company that will not stay so small and undervalued for long. Excluding its controlling investment in CSI Compressco (CCLP), the stock sells at an enterprise value multiple of just 4.0x run-rate EBITDA, despite strong free cash flow generation and growth prospects. The company's breakthrough new CS Neptune completion fluid has a multi-billion dollar market opportunity ahead of it, with >80% EBITDA margins, no competition and long term patent protection. The company recently signed a joint marketing and development agreement with industry leader Halliburton to distribute this product globally. TTI stock can double just to get to the low end of my fair value range.  Over the next year, it can triple and more. TETRA Technologies, Inc. (TTI) is a smallish company that’s been around for a long time. Until recently, it has been an unremarkable company, sort of both everywhere and nowhere at the same time. As I will explain in this lengthy article, I think that is about to change in a big way. Against its most recent closing price of $3.65, I think the stock is easily headed into the teens over the next year or two. I think this is a stock to own right here, right now, because not only is it extremely cheap but I think perceptions could begin to change rapidly starting with the upcoming Q3 conference call. INTRODUCTION TETRA is an oil and gas service company now focused squarely on three businesses: high technology completion fluids, which will benefit from both increasing shale drilling and, particularly, the accelerating recovery in deepwater drilling; water and flowback services, which will benefit from the increased importance of water management in shale drilling; and compression sales and services, in which it participates through its ownership and control of CSI Compressco, LP (CCLP), a separate publicly-traded MLP. As I will explain, I think that TETRA is well positioned to assume a position of technological leadership in both the completion fluids and water management businesses. Its investment in CSI Compresso is valuable, but in my opinion, may ultimately be a candidate for divestiture.   INVESTMENT THESIS Over the last year, TETRA has quietly and remarkably transformed itself into a focused company with the potential for market leadership in two large and growing oil services markets: completion fluids, where it has a blockbuster new ultra-high-margin product; and water and flowback services, where it is the number two provider of such services nationwide. Over the past year, the company has sold divisions, shed liabilities, and reduced and refinanced its debt. Where the “old” TETRA was a bit of a mish-mash with no particular corporate logic; the “new” TETRA is a highly focused company with a coherent and well-defined corporate strategy. In my opinion, the new TETRA is a winner—a long-term growth story that can double over the short term and triple or quadruple beyond that. While I am bullish on energy related stocks, most of them are highly cyclical and inextricably tied to the commodity price. TETRA has a unique set of secular growth drivers that most other energy stocks do not have. Investors haven’t yet taken notice, but I think they are about to. TETRA last closed at $3.65, at the lower end of its range over the last year. While analyst targets are in the $6 to $8 range, I conclude a value between $8.38 and $13.09 per share. MAY 31, 2018: TETRA HOLDS AN “INVESTOR DAY” CONFERENCE On May 31, 2018, TETRA management held an “investor day” conference in New York City in which the CEO, CFO and the heads of all their divisions gave lengthy presentations and answered questions. This may be the first time this company has ever hosted such an event. Certainly, it is the first time in recent memory. I think the best way to analyze this investor day is in terms of human nature. Hosting an investor day is a lot like hosting a dinner party to celebrate your new house. You wouldn’t be doing it if you didn’t feel proud of what you had accomplished and where you were headed. It is a sign that management is both excited by their prospects and confident they can deliver. It may also be a sign that they think their stock is a real opportunity.   I was very impressed with the company’s 117-page analyst day presentation. Clearly, a lot of thought and effort went into this presentation. Not only did management explain their business and corporate strategy coherently, they put forth explicit 2018 guidance for each of their business units. I don’t think they would have done that unless they were confident the could deliver at least as much as they promised. In fact, on their earnings call just two months later, they already began raising guidance, however modestly. I have been following TETRA closely since their investor day presentation. At the time, I didn’t see any need to rush out and buy, but I’ve recently changed my mind. I think the time to buy is now, in front of what I think will be strong Q3 earnings and a meaningful upward revision to Q4 guidance. As well, I think 2019 is shaping up to be a breakout year. Nobody knows a company better than its own management. But, for obvious reasons, management cannot tell us everything they know. Looking back on the investor day presentation, and what has happened since then, I am convinced that management likely has in store a string of important positive announcements that will cause investors to fundamentally revalue the company significantly higher. SINCE INVESTOR DAY Since the investor day, the company has made three important announcements. First, the company announced a joint marketing and development agreement with Halliburton (HAL) for its revolutionary new CS Neptune completion fluid. Halliburton is one of the global leaders in drilling and completions fluids and controls about a quarter of the market. Driven by Halliburton's global reach, I think revenue and profits from this single product alone can cause the stock to at least double over the next year. Second, the company reported very strong Q2 revenues of $260 million (versus analyst estimates of $238 million) and earnings per share of $0.04 (versus analyst estimates of $0.01). Third, the company raised both 2018 revenue and EBITDA guidance, although by not nearly as much as the Q2 outperformance would suggest.   TETRA will report Q3 earnings in early November and I expect that it may represent a critical inflection point in how the company is perceived by investors. I expect the company will report a strong quarter and raise Q4 guidance, perhaps substantially. Management may also give a preview of 2019 guidance. FLUIDSDOC: CREDIT WHERE CREDIT IS DUE Before I begin, let me give credit where credit is due. Fellow Seeking Alpha contributor, Fluidsdoc, has been writing about TETRA for more than the past year, and it is their enthusiasm for their new Neptune completion fluid product that initially drew me in. According to their Seeking Alpha profile, they are an industry expert. Now, Fluidsdoc has been recommending TETRA for the past year and, frankly, they have been early. As I will explain, they connected the dots between what happened in 2017 and what will happen in 2019 and beyond far faster than the market, which in fact still hasn’t connected those dots. That’s often what happens when you know too much and that’s a large part of the opportunity in TETRA today. When it comes to completion fluids, Fluidsdoc is the ultimate industry insider. I’m pretty sure they are going to be right on TETRA. Even if they are only half right, this will be a very rewarding stock. Let’s now go through each of TETRA’s operating divisions. COMPLETIONS FLUIDS & PRODUCTS TETRA’s Completion Fluids & Products division is an industry leader with a greater than 30% market share for high value fluids. When transitioning from drilling a well to completing a well, completion fluids are used to displace the drilling mud while keeping downhole pressure intact. If you want to know more about the technical details of these fluids, I urge you to read Fluidsdoc’s many articles. They are the real thing when it comes to understanding the science and application of these fluids. For the purposes of this article, suffice it to say, if you are completing a well, you will need completions fluids. Depending on the type of well you are completing, the fluid you will use can range from a relatively low-cost commodity fluid like calcium chloride for a typical shale well to a very expensive and highly engineered fluid using hazardous or even rare elements for a high-pressure, high-temperature deepwater well.   Source: Company presentation While TETRA provides fluids for both onshore and offshore completions, what is really driving my excitement is their new CS Neptune product for the complex and expensive wells in the deep waters offshore. This is where the big companies spend the big money and a single project can run into the many billions of dollars. Every well that uses the company’s Neptune completion fluid can add millions to the bottom line. That’s a lot for a small company like TETRA. (With 126 million shares outstanding, each well can potentially add a couple of pennies of EPS.) As Fluidsdoc explains, there have traditionally been two alternatives for deepwater completion fluids. The first, zinc bromide, is extremely toxic, bio-accumulates in the food chain and is a known teratogen, meaning it causes fetal malformation. These health, safety and environmental issues are real. The U.S. has classified zinc brines as "marine pollutants" and they are prohibited from use in the North Sea altogether. The second alternative, a cesium formate based brine, does not have the same environmental risks, but is extremely expensive and its use frequently difficult to justify. A cesium formate based completion fluid can cost up to ten times as much as a zinc bromide fluid. In sum, what TETRA has done is to develop a revolutionary new zinc-free completion fluid which is far superior to what exists today. Because it is zinc-free, it has none of the health, safety and environmental issues associated with a zinc bromide fluid; and because it uses no cesium formate, its cost is very reasonable. According to Fluidsdoc, both Schlumberger and Halliburton, the two leading completion fluids companies, have been working to come up with a zinc-free alternative. They have been unable to do so and, as they write,   According to the company, CS Neptune was developed for use in a multi-billion-dollar investment deepwater well in the Gulf of Mexico. Had a zinc-based fluid been used on this project, a separate FPSO (floating production storage and offloading) unit would have had to be contracted just to dispose of the zinc-laden fluid. In other words, the E&P company would have had to hire one of these (as in the picture below) just to dispose of the contaminated fluid. Source: Company presentation All-in, the use of CS Neptune resulted in savings of greater than $100 million. That’s a huge savings and explains why this product can command such high margins. According to the company’s 2017 annual report, (Emphasis mine.) The critical question is, is this true or is this just so much corporate puffery? This is where Fluidsdoc comes in. According to Fluidsdoc,   And, If so, that’s enormously consequential from a financial perspective. Let’s take a look at the potential financial impact of Neptune on the company.Source: Company filings, author's calculations Neptune is a product in its infancy. In Q2 and Q3 of 2017, TETRA provided Neptune completion fluids for a major Gulf of Mexico project. While this was not the first well that Neptune was used on, it was the first truly large-scale application of Neptune on an ultra-high-value well. What we don’t know is exactly how much revenue and EBITDA were generated by this project. But we can guess. Just looking at how both revenue and EBITDA popped during those two quarters (and also taking into consideration the typical seasonal strength in Q2) suggests that this single project generated in the range of an incremental $20-25 million in revenues at an EBITDA margin of at least 80%. That really made me sit up and take notice. There are two important takeaways here. First, if Neptune gains traction, it can drive an enormous amount of profitability with virtually no incremental capital investment. Second, Neptune earnings deserve a high multiple and can catalyze a fundamental revaluation of the company. So, the next question is, how big is this market? According to the company, there is an untapped market opportunity of over 600 offshore leases with wells that could benefit from CS Neptune. As shown below, 143 of these are in the North Sea, where Norway has banned zinc-based fluids for environmental reasons. Another 224 are in the Gulf of Mexico, where TETRA has already proven the success of Neptune.   Source: Company presentation Using the company’s estimate of 600 wells, at an average of $5 million per well, would suggest a $3 billion revenue opportunity. (Recall, that a single large project can potentially generate up to $20-25 million in revenue, so this estimate may be conservative.) At an 80% margin that’s close to a $2.5 billion profit opportunity. That’s a lot of opportunity for a small company like TETRA. In its investor day presentation, TETRA disclosed that it wanted to partner with a “global drilling and fluids market leader” to enhance its distribution and service capabilities for Neptune. That’s actually a tall order for a small company but, on July 2, just over a month later, TETRA was able to announce that it had signed a global marketing and development agreement with Halliburton. The fact that a company like Halliburton would team up with TETRA is a strong testament to the importance and potential reach of this unique product. Once again, the best analysis of this event comes from Fluidsdoc, who wrote, This gets back to something I said earlier. While management knows what’s going on better than anyone else, they obviously cannot disclose everything they know. But sometimes they can hint. For example, on the May 31 investor day, management stated that one of its goals was to “partner with [a] global drilling and fluids market leader” for the distribution of Neptune. Obviously, the deal with Halliburton was at a substantially advanced stage by then. In retrospect, management’s statement of strategy was more in the nature of a hint of what was to come.   So, when TETRA management writes, “The success of the Neptune technology project simply cannot be overstated,” and when they describe Neptune as “transformational, disruptive technology” what are they really trying to say? Is it a hope, an opinion, or a hint? I don’t know the answer, but given their recent track record, I’m open to the possibility that it may be a hint. I also found Fluidsdoc’s next statement extremely interesting. This is how I interpret this statement. “Every major service company has been looking to create equivalent fluids technology.” In other words, Schlumberger has been trying hard but, despite its considerable resources, has thus far been unable to duplicate what TETRA has done. Industry giants like Schlumberger need to figure out a “response.” In other words, Neptune presents a significant enough competitive threat to Schlumberger’s base fluids business that they cannot afford to just ignore it. Neptune is a patented technology and, it looks like their lawyers have sewn things up pretty tightly. Cf., Fluidsdoc’s August 18, 2017 article on TETRA where they wrote, “I'm not sure that CS Neptune is patentable or not; there just isn't enough information disclosed about it yet.” TETRA has a track record with Exxon Mobil in the Gulf of Mexico. Clearly, this “multi-billion-dollar investment well” in the Gulf of Mexico was with Exxon Mobil. I’m sure that’s pretty common industry information but, as an outsider, I did not know that. For ratification of an important new industry technology, you cannot get much better than that. If you read carefully, there's a lot of good information there. So, let’s return to my earlier question, how big and important is the market for CS Neptune? The answer is that it is big enough and important enough for Schlumberger and Halliburton both to have been seeking to develop a zinc-free drilling brine; and it is big enough and important enough for Halliburton to partner with TETRA when it found it could not duplicate its success. Remember, Tetra is not a large company and so it does not take all that much to move the needle here.   And what about Schlumberger? Fluidsdoc doesn’t say specifically, but notes, I read that statement to mean that Schlumberger is a long way from having a competitive product. The Halliburton Marketing and Development Agreement In the short term, the agreement with Halliburton will dramatically accelerate the global acceptance and reach of Neptune. That’s why I am excited about the stock in the short term. Once investors figure this out, the shares should start trading meaningfully higher. Remember, stocks anticipate. Here’s the full text of the press release announcing the agreement,   What’s important is that this more than a joint marketing agreement. It is also a joint technology sharing and development agreement. On the second quarter conference call, the company gave further clarification on the both the short term and long term potential for this agreement. But, as I said, the real opportunity is even bigger than that.   As Fluidsdoc notes, In other words, the joint agreement with Halliburton is really just the beginning. Expect to see more products based on the combination of Neptune and Halliburton technology. The potential for Neptune to be used as a base drilling fluid as well suggests the potential for dramatically higher volumes. If all of this bears fruit, I would not be surprised to see a more formal tie-up, such as between Schlumberger and M-I Drilling and, perhaps eventually, such as between Schlumberger and parent company Smith. Financial Results and Guidance The fluids division had a really terrific Q2—much more terrific than it looked. Source: Company filings, author's calculations As can be seen, Q2 fluid revenue increased 44% sequentially and 3.4% year-over-year. While Q2 tends to be seasonally strong as a result of the European chemicals business, what’s notable is that results even increased year-over-year despite significant Neptune revenues in the year ago quarter and none in the current quarter. Without any contribution from Neptune, margins could not of course match the year ago quarter, but nevertheless they improved substantially on a quarter-over-quarter basis, rising from 11.7% to 17.9%.   One of the reasons that I am particularly excited about owning a full position in TETRA right here and right now is because I think that Q3 earnings will be stellar and Q4 guidance will be revised substantially higher. To understand why, let’s take a look at the company’s investor day guidance for the fluids division.Source: Company filings, author's calculations As can be seen above, I have recorded the company’s full-year 2018 guidance in blue and the actual results for the first two quarters in black. In red, I have calculated what each quarter would look like to meet the mid-point of guidance. (For the sake of simplicity, I have assumed that both quarters would be identical.) At the investor day, the company confirmed then full-year revenue guidance for the entire company of $945-$985 million. In fact, this guidance was actually first introduced on the company’s Q1 conference call. What was new at investor day was the breakout of revenue guidance by division. Thus, we can assume that, had the company given the divisional breakout on the Q1 conference call, it would have been mostly the same as what they gave on investor day. Now, here’s where it gets interesting. On the first quarter conference call, management stated, Neptune revenues are so large and consequential that I cannot imagine other than that, if management thought there might be “one to two” opportunities, they would only incorporate one into their formal guidance. To do otherwise would risk falling materially and embarrassingly short of guidance, something I am sure management did not want to do out of the box.   But, on the second quarter conference call, management stated that it now expects revenue from two Neptune wells during the second half of the year. The company also stated, In other words, it seems that current guidance for the remainder of 2018 only includes one Neptune well, but there is a significant likelihood of a second such well. Given that one was already at a “fairly advanced stage in the drilling process,” it’s possible there will be meaningful Neptune revenues in Q3. If so, Q3 could be surprisingly strong and there could be a surprisingly substantial upward revision to Q4 guidance. WATER & FLOWBACK SERVICES DIVISION The second important division at TETRA is their Water & Flowback Services division which provides water services for unconventional wells in North America. The leader in this business is a company called Select Energy Services, Inc. (WTTR), and I have written extensively about why I think water handling and logistics is a very much underappreciated business with strong growth prospects and durable margins. TETRA is number two in the water business. While considerably smaller than Select, they also have a national footprint with operations in all the major shale basins. As far as I know, all the other players are regional. Source: Company presentation   Since TETRA’s water business is, for the most part, very similar to Select’s, I am not going to reiterate what I have written previously. Suffice it to say that water handling and logistics is an increasingly important and mission critical component of unconventional well completions and Select and TETRA are the two publicly traded companies with a national footprint. Readers are urged to read my first two articles on WTTR for more details about this business and why I think it will grow significantly over the next few years. In March 2018, TETRA doubled down on its water business by purchasing Swiftwater for $42 million in cash and 7.772 million shares of stock valued at $28.2 million. This was an excellent acquisition which gives them a substantial market position in the all-important Permian Basin. Currently, TETRA is exposed to the $9.4 billion market for the treatment, flowback, transfer and storage segments of the water business, all of which have substantial growth prospects over the next few years. The company’s objective is to deliver double the growth rate of the industry, which would suggest well better than 20% annual growth. Source: Company presentation One reason I like the water business is because, in addition to the strong growth prospects, it also generates very significant free cash flow. Source: Company presentation As can be seen above, TETRA management is forecasting EBITDA of $60-66 million for 2018 (a number which is likely quite low) against which it has maintenance capex of just $6-7 million. That bespeaks a very high quality of earnings. Management is further investing another $19 to $24 million in growth capex, on which it expects to earn a payback in 18 months or less. That suggests strong EBITDA growth into 2019 and 2020.   Financial Results and Guidance One thing I’ve come to appreciate about management is that they have given very conservative guidance that they have then handily exceeded. For example, at the time of the Swiftwater acquisition in March, they estimated that Swiftwater would contribute $16-20 million in EBITDA for 2018. Swiftwater has already generated EBITDA of $2.3 million for March and $6.8 million for Q2, the first full quarter. As can be seen, water division revenues have been growing significantly and EBITDA margins have improved significantly as well. Source: Company filings, author's calculations While the better part of the growth from Q1:18 to Q2:18 was due to the added two months of Swiftwater revenues, the segment did enjoy significant organic growth as well. On a pro forma basis, assuming Swiftwater had been acquired at the beginning of the first quarter, Q2 water revenues would have grown by 11.2% sequentially. Note also the tremendous margin improvement that the acquisition of Swiftwater has enabled. At the analyst day, management gave guidance for full-year water revenues of $285-295 million and $60-66 million in EBITDA. With the Q2 report now in hand, even the top end of that guidance seems woefully low.Source: Company filings, author's calculations As can be seen above, assuming the top end of the revenue and EBITDA guidance, results for Q3 and Q4 would have to fall very substantially below the Q2 run rate. I don’t think that’s likely. I think it is more likely that EBITDA guidance will be ranged from $60-66 million to perhaps $70-75 million.   On the Q2 conference call, one analyst addressed this issue.   In my opinion, this sounds like a company that is going to meaningfully raise its guidance for this division when it reports Q3 earnings. COMPRESSION SERVICES TETRA’s third important division, Compression, is not so much a division as an investment in a separate, publicly traded company known as CSI Compressco, LP (CCLP). Compressco is a vertically integrated compression company, meaning that they supply compression services, but they also manufacture, sell and support their own equipment. They also provide aftermarket support for third party equipment. For the most part, compression is a mildly cyclical business that fluctuates with oil and gas prices and offers rent-like returns. It is a heavy iron business, requiring lots of assets that are optimally financed by low-cost debt. Currently, this business is coming off the bottom of the cycle and management has done some smart things. First, they paid down their bank debt and issued senior notes, also adding $100 million to their cash balances in the process. The company is now in a comfortable position with no covenants and no debt coming due until 2022 at the earliest. Then, management used this additional money to invest in increasing their available horsepower. Utilizations have rebounded significantly off the bottom and Compressco’s earnings and dividend are set to move higher. Source: Company filings, author's calculations Unlike most of its peers, Compressco is vertically integrated and manufactures its own equipment and provides aftermarket support for its own and third-party compression equipment. As utilization has rebounded, the compression market has gotten tighter and there has been increasing demand for both new equipment and aftermarket service. At June 30, 2018, the company reported the highest backlog in its history, $102.2 million, which reflects an order from a single customer for $67 million—the largest such order in their history. By comparison, its backlog at the year ago period was just $24.0 million. Most of this backlog is expected to be delivered in the second half of 2018, so expect a significantly stronger second half. Whether the company can continue this momentum remains to be seen.   Bottom line, the compression division is in a good place. When management raised guidance on the Q2 conference call, it was entirely attributable to this division. It may not be the most exciting business, but it is headed higher Accounting Considerations Now, this is where things get a little complicated from an analytical standpoint. Essentially, Compressco is its own company (structured as an MLP) and at the last report TETRA owned about 37% of the common LP units, 12.6% of the preferred units and an approximately 1.6% general partner interest. In many ways, TETRA’s interest in CCLP is more in the nature of an investment than a true operating subsidiary. Like any other common holder, it benefits primarily from an appreciation in the value of CCLP stock and any dividends paid by CCLP. Other than that, CCLP is a financially and legally separate entity and there is no commingling of cash or cash flows. To the extent that TETRA owns less than 50% of CCLP, it would normally account for its interest as an equity investment. But, because TETRA also owns the general partner interest, it exerts functional control over CCLP and must therefore consolidate CCLP’s financials with its own. This makes the analysis of TETRA’s financials a bit messy. What do I mean by messy? If you look at TETRA’s most recent balance sheet, you’ll see $810 million of long term debt. The reality is that $632 million of that debt belongs to Compressco and, while TETRA must include that debt on its balance sheet, it is in no way liable for that debt under any conditions. Basically, TETRA owns about a 40% economic interest in Compressco and the best way to think of this is that TETRA’s interest is mostly like that of any common unit holder. But because TETRA must consolidate the financials of CCLP with its own, they seem much more intertwined than they really are. Valuation of Compressco I believe that, notwithstanding TETRA’s effective control over CCLP, its interest should be valued primarily as a standalone equity investment. Therefore, this is how I value TETRA’s interest in CCLP.   • At June 30, 2018, TETRA owned 15,428,587 common units of CCLP. At their last traded price of $5.48, this stake is worth $84.5 million. • TETRA also owned 559,975 shares of CCLP’s Series A preferred units. Over the next year, these shares will convert ratably each month into common units of CCLP. I value these at par, or $5.6 million. • In addition to exercising function control over the company, the general partner interest in CCLP is entitled to 1.6% of CCLP’s dividend payments plus incentive distribution rights as dividends rise beyond a certain level. Beyond the value of the dividend distributions, the value of the general partner is somewhat difficult to establish. The incentive distribution rights are too far out of the money to be a meaningful source of value, but control is worth something. Thus, I am going to somewhat arbitrarily value the general partner at $0 to $30 million. The upper end of that range presumes that TETRA will use its control to monetize its investment in CCLP at a premium, perhaps by selling the company outright. All told, I value TETRA’s interest in CCLP at $90 million to $120 million, most of which is the current market value of its securities holdings in the company. While nominally the largest of the three divisions by both revenue and EBITDA, I believe Compression is actually the least valuable division. It is also likely creating value at the lowest rate compared to the other divisions. I believe its relative value to TETRA will rapidly diminish in importance as compared to the fluids and water divisions. According to the company, there are cross-selling synergies with its other divisions; but I’m just not sure that they are sufficient to warrant keeping the division given the complexity it adds to the capital structure. Compressco is poised to do better and I think that management should use this as an opportunity to monetize their investment. While they could always sell their shares into the market place, the value of having control is they could also sell the company to a third party, likely at a premium. In my opinion, Compressco should be sold because TETRA now has bigger and better fish to fry. Given its control position, why not seek to obtain an acquisition premium?   BALANCE SHEET An important part of TETRA management’s remake of the company has been to clean up its balance sheet. Currently, TETRA has $178 million of debt versus its most recent quarterly EBITDA of $33.9 million. Source: Company filings, author's calculations A sale of CCLP could reduce its debt by at least half or more, freeing up capital which could be invested in either of its two other divisions. VALUING TETRA Before I discuss how to value TETRA, let me discuss how not to value it. Many analysts are valuing the company on a consolidated basis, that is, assigning a unitary target multiple to a consolidated EBITDA figure including Compressco. I don’t think that’s right because each of the company’s three divisions are really quite different in terms of growth prospects, capital intensity and risk. The compression division, in particular, is a horse of a different color. Notwithstanding the consolidated financial presentation, there is no commingling of assets, liabilities or cash flows between TETRA and Compressco, and so it is essentially improper to value them on a consolidated basis. Furthermore, in almost all cases, this unitary multiple is far too low because it does not consider that Neptune is a very large and high multiple product opportunity. I believe the company agrees with me that the correct way to value TETRA is a sum of the parts analysis with the value of Compressco “mapped over” from its public valuation. Source: Company presentation   So, here’s how I value TETRA on a sum of the parts basis. Current Valuation In order to establish a current valuation, I try to establish a reasonable current EBITDA run rate for the fluids and the water divisions. For the fluids division, I use the midpoint of management’s guidance less the reported first half results to establish a current run rate. For the water division, I use the Q2 actual run rate. I believe that both are likely conservative. Source: Company filings, author's calculations As shown above, this yields an enterprise valuation of approximately 4.0x the current run-rate EBITDA. That’s a very attractive valuation for a company that is both generating significant free cash flow yet also has bright growth prospects. Target Valuation Given that the calendar is pushing November, TTI should really be valued on 2019 cash flows. Since management hasn’t given guidance for 2019, I will need to provide my own. I expect that I will have a much better handle on the potential for 2019 by the Q3 earnings call, but for now I will simply grow the run-rate EBITDA by 15% for each division. I think each division is easily capable of significantly exceeding those placeholder estimates. Thus, on the low side, I think the compression division is worth $90 million, which is the market value of TETRA’s ownership position plus the value of its GP dividend interest. On the high side, I think you can add a 30% premium in a change-in-control scenario, resulting in a value of $120 million. As I noted in my articles on WTTR, this is a good business with good growth prospects, modest reinvestment requirements and robust free cash flow generation. It is a better and less capital intensive business than pressure pumping and a very much better business than frac sand, which is now beset by significant oversupply issues. On balance, I think the Water & Flowback Services division is worth at least a 7.0-8.0x multiple. This yields a valuation of $648 million to $741 million for this division.   The Completion Fluids & Products division is the most difficult to value because of the significant potential for Neptune. For now, I am going to value it at 8.0-14.0x the mid-point of current H2:18 EBITDA (the result of subtracting actual H1:18 EBITDA from full-year mid-point guidance of $58.5 million and then annualizing). I understand that’s a bit of a wide range and that a 14x multiple may seem a bit on the high side. But, if Neptune can fulfill even half of its potential, this will seem a very modest valuation in a year’s time. That yields a total value of between $710 million and $1.2 billion for this division.Source: Company filings, author's calculations Adding it all up and adjusting for corporate overhead yields a valuation range of between $8.38 and $13.09. Even the low end of the range is more than a double from these prices. Most of the variation in the valuation comes from the prospects for Neptune. The low end of the valuation range reflects an outcome in which Neptune never amounts to much more than a niche product, used in a handful of wells each year. The upper end of the valuation range assumes meaningful penetration and growth for the product. Remember, Neptune is a groundbreaking product in its infancy with drug-type margins, patent protection and, thus far, no competition. A single Neptune project contributed almost $25 million of revenue and $20 million of EBITDA in less than two full quarters. With two Neptune projects scheduled for the second half, the real question is what can 2019 and 2020 and 2021 produce in terms of Neptune earnings. If the agreement with Halliburton bears significant fruit, even the high end of the valuation range will ultimately prove far too low.   CONCLUSION I believe investors should buy TTI now, ahead of the Q3 earnings report. Even at the lower end of my valuation range, which assumes that Neptune never becomes more than a niche product, the stock can double. If I am right about the prospects for Neptune, this stock can trade in the mid-to-high teens soon enough. Disclosure: I am/we are long TTI WTTR. I wrote this article myself, and it expresses my own opinions. I am not receiving compensation for it. I have no business relationship with any company whose stock is mentioned in this article.

HC

Mr. Bert

Omnipresent Big Need for Capital... Alternatives?

Smaller producers who are finding it more difficult to secure bank credit, with many loans still under pressure, are seeking new ways to capture funding.  As prices are making it a bit easier to add to the balance sheet, versus $26 per barrel in recent times, new avenues for capital have opened up. We see the increased ability of 'non-bank' capital sources to serve these operators that have a large need for capital.  Reserve Based Lending, (RBLs), are certainly in transition and many smaller operators are simply too small to attract this capital.  Mezzanine debt and some credit funds have typically been the next horizon for capital, but other alternative methods are needed to fulfill this capital need that make sense to these sized operators. Backstory: the Comptroller of the Currency's revised lending guidelines have become stricter and banks are being squeezed.  More than $208 billion in upstream debt existed at the end of 2017, with nearly $75 billion not in compliance with the new banking strictures... So, what does this mean for the producer?  As these mature, some may be renewed, many will not and where there's a gap and if companies can't renew their RBL, they'll need other methods to fund themselves.  Solution for some, not for all: Volumetric Production Payments, (VPPs) on existing production.  Not bank debt, non-recourse and there's no equity relinquished to the private equity bunch.  We love to see PDP assets and can leverage them to grant the capital these firms need effectively and efficiently, usually within 30-45 days, versus the slog through banking procedures. It makes sense that as the traditional methods of funding are under pressure, that direct capital can be accessed through ways that make sense to the operator... he keeps the upside, typically at least 70% with facilities up to $20 million. Always open for discussion!

A New Polymer EOR Technology

Produced Water Mobility Inhibition Polymer Flooding Jay C. Reynolds, Applied Mobility, LLC, Oil City, Louisiana   Numerous reservoirs in the US are prone to early transition to high water production and produce at their economic limits in spite of often having 75-80% or more of their OOIP remaining in these developed and de-risked fields. It is the shallow reservoirs that were discovered first and mis-managed in the early days which are now in the hands of the Mom and Pops, who are notoriously late technology adopters.  This is where the big stranded reserves are in the US. The best combination for this process is homogenous geology, relatively low gravity oil, close well spacing and a strong, active, bottom water drive. That combination makes for early water coning and high percentages of stranded reserves in an active bottom water drive reservoir.   A oil cut (WOR) of 1,000/1 is typical for the Nacatoch B Sand in northwest Louisiana; a terrible Adverse Mobility Ratio. In the Nacatoch B, the oil wells are essentially water wells that make oil as a contaminant once the water cones in.  About 10,000 of these wells were drilled, a significant number during three separate periods of intense promotion because these wells had good flush production and frequently paid out in a couple of months before the water came in.  The reservoir is acting exactly as physics dictates. This oil is 19-21 gravity and it takes pumping the well down about 150’ to provide a sufficient pressure drop to mobilize oil to the well bore and that is impossible without changing the downhole physics at work. Nacatoch oil is about  250 centipoise viscosity while our water is 1 centipoise with permeability as as high as 3,000 millidarcies.  As a consequence, pumping these wells down is impossible because the water channels will expand to accommodate any given pump capacity. These factors, and the large stranded reserves, led to the develop an inexpensive polymer treatment for water control and enhanced oil production for reservoirs with a low permeability contrast such as those of the Caddo Pine Island Field’s massive blanket sand, the Nacatoch B Reservoir.   A dry polyacrylamide polymer of special design is mixed on the fly and injected into the water bearing portion of the sand with a Mobile Gel Unit.   You could think of it as inflating a balloon underground and as long as you are injecting more than you are withdrawing the area affected will continue to expand.  That makes this process site specific, you can keep the ‘polymer balloon’ and the oil on your leasehold instead of mobilizing the oil horizontally, potentially off of your leasehold as with a traditional displacement type polymer flood.  The produced oil and polymerized water is separated in the usual way and the polymerized water, having value now, is recycled.  Bottom line is turning your worst enemy, water, into your best friend.  Think of this as a polymer flood that operates vertically instead of horizontally - that lets oil move in the direction nature wants it to go, vertically. Injection continues until the polymerized water surrounds nearby producing wells.  That lets the operator pump those wells down because the wells no longer have access to low viscosity native water.  This relieves enough hydrostatic pressure in the well bore to let the reservoir energy mobilize the more viscous oil to our well bores at higher rates.  This technique lets an operator keep the oil on their lease while qualifying as Tertiary Enhanced Oil Recovery on a voluntary leasehold unitization basis in many states. Without mobility control the reservoir can only be shown about a 20 psi pressure drop no matter what capacity pump is run.  A 20 psi pressure drop will move all of the water you can possibly pump through a high permeability sand but transports very little oil.  With produced water mobility control the well can now be pumped down.  Mixing polymer into the water dramatically improves the mobility ratio and lets us pump the well down to take advantage of the reservoir pressure. To accomplish polymer placement in the desired portion of the reservoir, we continuously hydrate, blend and inject polymer at our target viscosity. Viscosity is targeted such that the polymer blend preferentially flows into the water productive regions of the sand while not displacing the oil horizontally. This development began by asking, ‘What would the cut be if the water and oil were the same viscosity?” “Change the nature of water and the physics downhole changes and a new equilibrium state with respect to how oil and water move relative to one another is established.  Darcie’s Law tells us that only three things determine the rate of fluid movement through our sand; pressure, viscosity and permeability. Which of those is easiest and cheapest to change on a large scale?  The viscosity of water. Unlike many EOR methods that rely on changing the characteristics of the oil, where the benefit is lost when the oil is produced, the polymerized water is recycled and what used to be our waste product, water, becomes an asset. James Sutphen of SNF added, “This has been a very good collaboration thus far.  Jay has come up with a game changer for a market that was not risk tolerant.  He knew from his perspective as an oil producer the game had to be changed or else geology and depletion would put him out of business.  There is a limit to how much fluid you can produce and separate and stay in operation.” Jay Reynolds (318) 208-1137, jaycreynolds@gmail.com

JR

JCR

Permian – update through July 2018

This interactive presentation contains the latest oil & gas production data from all 17,140 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through July. Visit ShaleProfile blog to explore the full interactive dashboards Output has continued to rise fast in the first half year, adding over 400 thousand barrels of oil per day from horizontal wells. The apparent drop in July is as usual due to incomplete data. As the graph above shows, more than 75% of oil production in July came from the ~5.7 thousand wells that started since the beginning of 2017. Natural gas production from these wells is also trending higher, and has now passed 8 Bcf/d.   The “Cumulative production profiles” plot in the ‘Well quality’ tab reveals the steadily increasing well performance in the past couple of years. Since 2016 this performance has increased just slightly. The average well that started in 2016 recovered ~200 thousand barrels of oil in the first 2.5 years (30 months) on production.   This area counts many operators; the top 3 operators, Pioneer Natural Resources, EOG & Concho Resources, produce together just 23% of total production. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the quarter in which production started. Over the past 5 years, laterals have increased by almost 50%, while proppant loadings more than tripled. This has greatly affected well productivity, as you can see by the ever higher recovery trajectories. But based on preliminary data, it appears that the proppant per lateral foot ratio has slightly fallen in Q2 this year, as lateral lengths increased faster than proppant usage. You can analyze this in more detail in our ShaleProfile Analytics service. Recent wells are on average on track to recover just over 300 thousand barrels of oil, before their rate has dropped to 20 bo/d (which for most operators is probably still profitable).   Early next week I will have a post on the Eagle Ford, followed by one on all 10 covered states in the US. Production data is subject to revisions. Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations. For these presentations, I used data gathered from the following sources: Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests and oil proration data. OCD in New Mexico. Individual well production data is provided. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2Jtl5zq     Follow us on Social Media: Twitter: @ShaleProfile
Linkedin: ShaleProfile
Facebook: ShaleProfile

shaleprofile

shaleprofile

 

oil market Russia's recent curious different stance on oil supply

The oil market is witnessing some interesting dynamics this week: On one hand Russia thinks (at least as stated in their public statement on Saturday) there were risks that global oil markets could be facing a deficit; on the other hand, OPEC (of which Saudi Arabia is the most influential player) hinted last week that it may have to reimpose output cuts as global inventories rise. This public divergence seems to be confusing the traders. The confusion stems from the fact that major oil players Saudi Arabia and Russia were apparently working in tandem, at least up until now, in regard to calibrating oil supplies to the world market. So why is this apparent divergence between OPEC and Russia’s view points? In oil politics (like in politics, in general), nobody is nobody's ally or friend - the key players could and would change their tune according to what is best suited to their policy objectives. Russia may be wanting the world to get the feeling that it is distancing itself from Saudi Arabia - for the time being. The reasons could be anything but apparently it might have to do with the aftermath of killing of the Saudi journalist. Though Russia has refrained from making any detailed specific comments in public about the killing, it probably wants to maintain a safe distance from all of it especially since Turkey is involved in the matter and Russia has been wooing Turkey quite diligently in the recent times. Also, Russia (and may be the OPEC members) realizes that it is better to wait and see the extent of impact of US sanctions on Iran’s oil exports. Already the oil exports from that country has reduced and it is expected to decline further. Traders would in any case automatically react to discernible impact on Iran’s oil export volumes. Further, it should be borne in mind that the impact of the US sanctions may not be that severe after all since the US was reportedly open to keep the SWIFT mechanism in place for Iran’s trade transactions, which would mean Iran may be able to export some quantity of oil, albeit, in reduced quantities.   Thus, it makes sense for Russia to keep the supply going at the current rate till the dust settles on Iran’s oil exports post-US sanctions and then make a determination whether to cut supplies or not. In any case, OPEC and non-OPEC are supposed to meet in December this year to review the situation. And, it does not hurt Russia too much if the WTI remained <$70/barrel since their president reportedly stated recently that price range of $65-$75 suits them. It may also be prudent for Russia to wait and watch how the situation in the EU unfolds after the reported decision of German Chancellor Angela Merkel to step down as leader of her party this year and as Chancellor in 2021. Russia may want to see if Merkel’s stepping down has any impact on Russia’s Nord Stream 2 project’s future. Merkel’s ally in EU - Macron of France - is not doing too well either in the popularity polls. Compounding all this is the Brexit chaos and Italy's proposed budget which EU is not willing to accept. All in all, EU seems quite directionless and muddled at the moment.  Another factor that would most likely come in to play in global policy dynamics on key issues is the outcome of the November 6 congressional elections in the US. If Democrats win the House of Representatives, political equation in the US will change significantly and President Trump’s policy trajectories might also get altered. Various key policy decisions of the US administration, e.g., USMCA, tariff spat, might get bogged down in Democrat vs Republican political football. One would like to believe that OPEC may also want to take a cue from Russia’s recent overtly stated stance on oil supply situation and decide to wait and watch the key political events unfold in the US, EU and Middle East over the next few weeks and then decide their next course of action after the OPEC and Non-OPEC meeting in Dec this year. Till then the key oil players may want to play by the ear and adjust their key policy statements and decisions, as necessary, should any key political development take place in the meantime.   In view of the above, the oil traders may not have any choice but to coast along accordingly based on the prevalent sentiment on the day.

The lonely, thankless job of heating the world in winter

It’s almost here – the darkness and the icy death grip of winter. Some may not feel the full sting of it, if you live in sunny and warm climates, while other brave souls embrace it. Having had fingers so numb I couldn’t unlock a door, I tend to be not as thrilled, but in truth it makes no sense to go through life hating one of the four seasons just because it can be unpleasant. Whether you like or loathe winter though, if your home must endure one you have to respect it. Winter can kill you. Very quickly. Perhaps you’ve had a bad experience in the dead of winter and know what I’m talking about. If you haven’t, it is very sobering. Say your car breaks down or gets stuck some distance from other people. A simple event like this can be life-threatening, and at the very least, if not prepared for it, the situation will be extremely unpleasant. Those of us in urban environments, which is most of us nowadays, don’t really think about this much because either help or shelter is never far away. That is simply a given, and a dead car on a side street is generally no more than an annoyance even at -25 degrees. We can see this readily when people pop out of cars on any given winter day with clothes that would no keep them alive for ten minutes or in footwear that couldn’t traverse more than a sidewalk’s width of snow. It doesn’t take much imagination to see how relentlessly we take for granted our heat sources. We can most easily see that phenomenon by thinking of other dangerous situations that we never forget. Imagine having a close call in traffic; say some driver blows a red light at high speed, and the only thing between you and oblivion was the fact that you happened to catch a glimpse of the idiot out of the corner of your eye in time. You will remember that split-second until the day you die, and you’ll tell the story to others for that long too. Now imagine that some errant construction worker struck a natural gas pipeline that supplied any sort of decently sized city in the dead of winter. A single incident like that could catastrophically cut off the heat supply for tens of thousands of people, instantly. And as anyone who’s experienced -25 degree temperatures (or worse) knows, you would feel the absence of that heat in minutes, or even seconds. Now consider how fossil fuels, all fossil fuels, are vilified relentlessly. The natural gas baby gets thrown out with the same bathwater that includes coal. Does anyone think for a second about the safety or integrity or even the presence of those natural gas pipelines? On balance, is the average person more likely to be scornful of natural gas as a fossil fuel, or to be filled with gratitude at having one’s life prolonged in those long winter nights? This coming winter, whenever you step outside and feel that icy blast on your face, give a thought to what made possible the heat you just stepped out of, and how incredibly fragile its existence really is. A million bad things could happen to any one of those pipelines, and your life may well depend on those things not happening, just as surely as it would be saved by glimpsing a speeding car at the right instant. And consider carefully everything you hear about how deadly fossil fuels are. This article was originally posted at Public Energy Number One

TE

Terry Etam

Bouncing Back But For How Long?

The Baker Hughes US oil rig count – a proxy for health and optimism in the overall upstream sector – has just reached a 31-month high to 1067 rigs,  though nowhere near the all-time high of 1609 back in July 2014. This recent development is not surprising; crude prices have been trending upwards and reached a new 24-month peak last week as well. Looking at the breakout data, it is possible that some of the gains could be from re-started sites shut down in the wake of Hurricane Michael bypassing the Gulf Coast, but the main additions are still coming from onshore Texas. The home to the mammoth Permian and the Eagle Ford shale basins, the Permian alone has 490 active oil and gas rigs. While infrastructural bottlenecks – mainly restrained pipeline capacity – have caused drilling activities to slow down since June, there are still gains to be made. Meanwhile, the lower prices caused by shale liquids being trapped in the Permian has led drillers to look elsewhere, where prices are stronger and infrastructure less clogged up – including re-looking at the Bakken and promising areas like Austin Chalk and Niobrabra. Recent auctions have seen record-high prices for acreage in Louisiana and Alabama; even in the Permian, interest remains high, with a recent sale in the New Mexican side of the basin setting a new record of more than double the previous high. This could be key to navigating the coming global supply crunch, triggered by new American sanctions on Iran, and exacerbated by continuing problems in key OPEC producers such as Venezuela and Libya. Although Russia has raised its production and Saudi Arabia has pledged to fill the hole that Iranian crude will be leaving, the assassination of Jamal Khashoggi places the Kingdom in a position of belligerence with the rest of the world. So the US may find itself in a position to have to provide extra volumes on its own – which may be why active rigs have been increasing, and new areas being sought. There is a bit of a spanner in the works, though. The trade spat between the USA and China has led Chinese importers to slam the brakes on importing US crude, even though American crude is not yet on the list of products tariffed by China. LNG and even NGLs – propane and ethane imported to produce petrochemicals – have also seen significant slowdown. How high can the American rig count get? If prices continue to march up – and there are many that believe the US$100/b mark will be reached soon – then the number of oil rigs drilling in the US could rise past 1200 again. But to reach the dizzying heights above 1500, which was the average over most of 2014, is unlikely. Not because there are lesser volumes of liquid underground – although studies are now showing that the decline rate in mature shale fields is alarmingly high – but because of consolidation. From a collection of many, many small players in the early 2010s, the shale landscape now is consolidating into a collection of medium and large players, with behemoths like ExxonMobil, Chevron and BP also muscling in. A rising tide of crude prices is lifting American drilling activity, but the magnitude of gains in 2018 will be different – due to a combination of infrastructure bottlenecks, fragile geopolitics and sector structural changes. The main danger is short memories – the zeal of cashing in on high oil prices is what caused the 2015 crash and high corporate debt, and the enthusiasm brewing in American shale again could lead to history repeating itself. Baker Hughes US Active Rig Count: 21 October 2011 – 1079 oil rigs, 927 gas rigs 19 October 2012 – 1410 oil rigs, 435 gas rigs 18 October 2013 – 1361 oil rigs, 372 gas rigs 17 October 2014 – 1590 oil rigs, 328 gas rigs 23 October 2015 – 594 oil rigs, 193 gas rigs 21 October 2016 – 443 oil rigs, 108 gas rigs 20 October 2017 – 736 oil rigs, 177 gas rigs 19 October 2018 – 873 oil rigs, 194 gas rigs

Mineral Rich Nation Looking for Money

Pakistan is one of the very few blessed countries in the world. We should take pride GOD has blessed with all fruits, vegetables, crops and minerals a country need to prosper at all cylinders. Pakistan has got all of them. But unfortunately Pakistan never prosper in last few decades as it should have been. We reeling with energy shortages which are badly impacting our manufacturing, exports etc putting extra ordinary pressure on Pakistan’s economy. Pakistan seeking money support its import of oil and gas just to keep our industrial wheel keep on moving. Can anyone guess a country with 9 billion barrels reserves of oil and 105 trillion cubic feet gas reserves facing this situation? Anyone can be dumb founded with this stats how can a country with such energy reserves is begging for support and not able to produce the goods at a lower cost to be one of the top competitive exporters in the world. Looking for outside world to buy energy sources to keep the country moving, why not invest in exploration? It is eminent that Pakistan has to decide on this and immediately start planning for these reserves to contribute to Pakistan energy crisis. If we compare the available reserves and how much work has been initiated on these reserves as per reserve maps. These two maps resources utilized and resources available clearly shows underutilized resources. The criminal ignorance has been shown by our past governments and it has brought the Pakistan’s at brink of bankruptcy. That has exposed Pakistan to external pressure, compromising position in matter of national security. This criminal ignorance is nothing less than serious treason. Where all the past governments when charged with corruption why not they should be brought into justice for high treason playing with the security of the country. The overall mineral reserves in Pakistan can be seen in the following map. The following table shows the various reserves status of minerals found in Pakistan:                                     Estimated Reserves                                            Production Salt                 220 Million Tons                                           0.325  Million Tons/year Copper           5.9 Billion Tons Ore Gold & Copper           0.170  Million Tons/year Gold               (5th largest in World)                                    0.300 Million Tons/year Iron Ore         500 Million Tons                                           0.193  Million Tons/year The Pakistan salt mines are second largest in the world but our exports are 20th in the world that really questions are policies and decision making. When we have 2nd largest reserves why we are not among the top 10 or top 5 salt exporters in the world. Those responsible for taking the right decisions to enhance exports have not taken the decisions in the right direction. We have a trade deficit for long time and its eating up our economic growth in so many ways. The government should take immediate action and make decision that can really boost the export of our salts to contribute more towards our exports. It will not take a rocket science to push exports as the quality of our salt is 99% pure. Now let’s discuss Copper and Gold ore we have 5.9 billion tons of reserves in Reko Diq, recently Pakistan government turned its attention toward this treasure. With the help of foreign collaboration progress has been initiated, however out of this huge reserve the true potential is not touched.  Only 300,000 tons production achieved from this reserve. The total Gold reserve stands 41.5 million ounce from Reko Diq, the ore grading 0.41% Copper. Pakistan’s gold imports stood 500 kg in 2018 financial year. In 2012 Pakistan gold jewelry exports crossed $1 billion over the period declined to $12 million in 2017. Instead of  moving up we have gone down massively further aggravating current account deficit. The restriction of 25 kg import quota has further implications giving rise to illegal imports of gold. TDAP reports the gold demand was $1.2 billion however the gold imports legally showed a figure of $24.43 million in 2016. The government need to review the policy that local demand of jewelry can only be met with recycled jewelry. Iron production ranks Pakistan 40th in world with 193,000 tons per annum against total reserves stands at more than 500 million tons. The imports of iron and steel stood at $3.5 billion in 2017. A country with huge iron reserves has to import of this volume is a shame for the country. The efforts should be made to increase production. The largest Steel Mill of the Country is making records of history. Nothing in this respect is on cards to this day. There seems no efforts, plans and policy on Chiniot iron reserves exploration work. The total production capacity of Pakistan Steel Mills (PSM) is 1.1 million tons monthly annual production capacity 13.2 million tons to achieve 80% capacity the PSM needs monthly 125,000 metric tons of iron ore and 1.5 million tons of iron ore annually which can be easily fed by local iron ore production resulting in foreign exchange savings. Pakistan is not investing enough time on these avenues no special teams are formed to work on these areas. A formal plan should be formulated and implementation phase should be prioritized. The government is maintaining that foreign investors are more than willing to invest in exploration process in Pakistan. The government should be alert while signing the contracts with the foreign companies for exploration make mandatory to feed the local manufacturer requirements then they will be allowed to export the raw materials. The value addition always bring back more rate of return on exports instead of exporting the raw materials.

Bilal Zaidi

Bilal Zaidi

Marcellus (PA) – update through August 2018

This interactive presentation contains the latest gas (and a little oil) production data, from all 8,406 horizontal wells in Pennsylvania that started producing since 2010, through August. Visit ShaleProfile blog to explore the full interactive dashboards Gas production from horizontal wells in this state set another record in August, at 17 Bcf/d. An important factor behind this was a large number of wells that were brought online during the month; 108, the highest in almost 4 years. Almost 25% of total gas production in August came from just 265 wells, that each produced at a rate higher than 10 MMcf/d (change ‘Show production by’ to ‘Production level’ to see this).   On average though, new wells peak at a rate of 10 MMcf/d, similar as in 2017 (see “Well quality”).   The 5 largest natural gas operators were all at or close to their historical highs in August (see “Top operators”). Cabot is now in the lead with 2.4 Bcf/d operated production, with almost all its wells in Susquehanna County. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate Return” overview shows the relationship between gas production rates, and cumulative gas production, averaged for all horizontal wells that started producing in a certain year. For more recent and granular data, you can change this grouping to quarter or month, using the ‘Show wells by’ selection.   In the 2nd tab (“Cumulative production ranking”), the counties with horizontal wells are ranked by their cumulative gas production through August. Susquehanna is clearly in the lead, followed by Bradford. You can change this ranking to the level of well, in order to see the best performing wells to date. It will reveal that of the 8,400 wells, 9 have produced now each more than 17 Bcf, all of which are operated by Cabot or Chesapeake.   Early next week I will have a new update on the Permian, followed by the Eagle Ford later in the week. Production data is subject to revisions. For this presentation, I used data gathered from the following sources: Pennsylvania Department of Environmental Protection FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2PLW8Br     Follow us on Social Media: Twitter: @ShaleProfile
Linkedin: ShaleProfile
Facebook: ShaleProfile

shaleprofile

shaleprofile

Pakistan Oil Requirement at a Glance

Crude oil also known as black gold is the commodity keep the country’s wheel moving. If a country is deprived of this natural resource it has to import it from outside world, which makes it everything expensive and heavy reliance on countries selling it. With each day world political scenario changing each day the prices keeps moving. In the world there are countries in the world always prefer to control their own resources and keep country economy under their control. They make every effort to keep the exploration goes on and production is kept in line with the consumption. Pakistan is one of the richest country in natural resources. It has estimated shale oil reserves of 9 billion barrels, however its current consumption is 440,000 barrels crude oil per year and refined approximately 600,000 barrels. Out of total 9 billion estimated reserves the proven reserves of 0.4 billion barrels or 400 million barrels. These proven reserves are consumption increase up to 800,000 barrels per month they will last for 500 years (5 centuries). The installed capacity of refineries stands at 409,000 barrels or 19 Million Tons Per Day (MTPA) against consumption of 24MTPA. Currently seven refineries are operating in Pakistan the highest capacity is of Byco 155,000 barrels per day or 7.0 MTPA. To meet the countries requirement Pakistan need 1 more refinery with 150,000 to 200,000 barrels production capacity in near future. This will save the foreign exchange reserves deficit which is always a problem for Pakistan Economy.   The total account deficit for financial year July 2017 – June 2018 stood at $17.99 billion which is more than 5% of GDP and total oil imports of Pakistan was $12.93 billion almost 72% of total account deficit. The US sanctions on Iran will further grow dim the Pakistan current account deficit to avoid further smash up  situation the government of Pakistan have to work on exploration of 400 million barrels proven reserves on war footing. The foreign companies will be interested in enhancing production and take up the new explorations as the oil prices using it as a carrot to foreign companies. The government is negotiation with Kingdom of Saudi Arabia for setting up oil refinery in Gwadar. If the previous Pakistani governments have worked on this area and planned the Pakistan economy should not have been in mess what it is in today. This criminal negligence on governments part is unpardonable. These governments went on and choose the LNG import option again a burden avenue was opted. For the oil import bill the government kept on availing new loans. Now this is high time the new government should immediately come with concrete plan for bringing proven oil reserves and make it good for reducing oil import bill and excess production exporting taking advantage of steeping oil prices in global market.

Bilal Zaidi

Bilal Zaidi

North Dakota – update through August 2018

These interactive presentations contains the latest oil & gas production data from all 13,899 horizontal wells in North Dakota that started production since 2005, through August. Visit ShaleProfile blog to explore the full interactive dashboards Oil production in North Dakota came in at 1,291 kbo/d in August, after a month-on-month rise of 1.7%, setting again a new record. As the graph shows, the 782 wells that started production in 2018 contributed already to more than 1/3rd of total production in August, producing more than the ~10k wells that started before 2015. After the high number of new producers in July (141 horizontal wells), 133 more came online in August. As this year around 100 wells were drilled so far each month, these recent completion numbers reduced the number of DUCs.   The production profiles for all these wells can be seen in the “Well quality” tab. The 2018 wells are so far tracking closely the performance of the wells from the year before.   The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the quarter in which production started. The 275 wells that started in Q3 2017 still show the best results so far (dark brown curve). They recovered on average 178 thousand barrels of oil in the first year of production. They appear to be on a path to recover about 1 more time that amount, before turning into stripper wells (<= 15 bo/d).   In the 4th tab (“Productivity ranking”), all operators are ranked based on the average performance of their wells, as measured by the total oil recovered in the first 2 years. If you only select recent years, 2014-2016 (using the “first production year” selection), you’ll find that Enerplus comes out clearly on top. The 47 operated wells that started in this time frame recovered on average 289 thousand barrels of oil in the first 2 years.   Next week I plan to have a new post on the Marcellus. For these presentations, I used data gathered from the following sources: DMR of North Dakota. These presentations only show the production from horizontal wells; a small amount (about 30 kbo/d)  is produced from conventional vertical wells. FracFocus.org   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2CrnRnk     Follow us on Social Media: Twitter: @ShaleProfile
Linkedin: ShaleProfile
Facebook: ShaleProfile

shaleprofile

shaleprofile

US - update through June 2018

This interactive presentation contains the latest oil & gas production data from 93,991 horizontal wells in 10 US states, through June. Cumulative oil and gas production from these wells reached 9.1 Gbo and 101.4 Tcf. Visit ShaleProfile blog to explore the full interactive dashboards In just one and a half year, production from these wells grew by more than 1.5 million bo/d and 10 Bcf/d. Operators increased the pace of drilling and completion activity, and as the ‘Well quality’ tab shows, average well performance also slightly increased from 2016. Wells were completed with longer laterals on average, and proppant loadings increased even more. You can try out our ShaleProfile Analytics service for more details on these trends, e.g. on an operator/basin basis.   The two largest shale oil operators, EOG and ConocoPhillips, set new records in June (‘Top operators’ tab).   The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected, and wells are grouped by the quarter in which production started. You can see that wells have been tracking steadily higher recoveries over the past years. Since the end of 2016, the pace of improvements appears to have slowed down.   Later this week I will have a new post on North Dakota, which just released production figures for August. Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below. FracFocus.org Colorado Oil & Gas Conservation Commission Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories. Montana Board of Oil and Gas New Mexico Oil Conservation Commission North Dakota Department of Natural Resources Ohio Department of Natural Resources Pennsylvania Department of Environmental Protection Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data. West Virginia Department of Environmental Protection West Virginia Geological & Economical Survey Wyoming Oil & Gas Conservation Commission   Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2CJZ2DJ     Follow us on Social Media: Twitter: @ShaleProfile
Linkedin: ShaleProfile
Facebook: ShaleProfile  

shaleprofile

shaleprofile

 

OILESS

Oil use is overestimated. Our perceived outlook on the importance of oil is completely distorted.  Humans have a hard time looking both into the past, and also into the future.  Unless someone has done extensive research on history of all eras, and had real conclusions on just how the world works, until someone has then used this same historical approach and applied it to the future, how then can one really have a bearing on where they stand in the scale of things.  OIl is a revenue generator, like war.  The speed at which humans can transform, especially today, is unprecedented, even in a sequence of long changing systems- computerization, social media, free thinking, healthy cultural development, are contributing to this impending correction of industries.  Historically speaking, industry was much more dependent. Thankfully populations rarely exceeded industry potential, and when such circumstances arrived- (human biological surplus), the ruling elite would simply go to war.  Still Today, in certain regions of the planet, military is the only option of employment, and this will barely be the food you eat.   Industry development is part of the healing process of our Fu%$ed up degraded systems that create military heroes, who in and of themselves have endured years of physical and psychological abuse.  War in and of its self is the most disgusting part of humanity.  Religion has accentuated the problem.  Judaism, Catholicism, Islam are basically a SEX and VIOLENCE club.  Many people are confused between being religious and being philosophical.  Many philosophers think they are religious, because this is what society has eluded to- in relating to deep and introspective thinking. Believe in yourself before believing in god.  Oil is poisonous.  WE are slowly poisoning ourselves to death.  Climate change is a secondary issue, when compared with air pollution. Rising sea levels is the best thing that could happen to hummanity.  Air pollution is not.  FYI, the rising seas, and the increasing natural disasters are one of the best things that could be happening.  AS many of you know, many cities are built on the ocean, and these cities have been using dykes, canals, and managing water systems for thousands of years.  A rising sea, and coastal region vulnerabilities have been on the minds of humanity for a long time.  And as an economist, it appears to me, we are about to embark on the largest infrastructure projects on the planet.   China is leading the way with whats possible with infrastructure.   However, to become carbon neutral, we will have to completely re imagine our priorities for infrastructure  Furthermore, and you heard it here first,  we are going to line, where necessary, the entire coastlines of the planet. We are going to build automated dike systems along major rivers, and along coastlines, that are literally going to be built along the entire stretches of important coast lines, and around islands. literally automated walls coming out of the ground, with unlimited height, and to such a degree that the automated dike system on the southern eastern coast of the USA, the walls will extend 100s of feet high to withstand hurricane winds.    WE will have automated domes with 10km diameter circling a vulnerable community. as the storm approaches, with incredible infrastructure we will combat the natural disasters.       ......................automated walls that line the important and neccesarry coastlines.   The amount of copper, iron, lithium, zinc, graphite, cobalt, steel, aluminum and every other mineral we are going to need to embark on these projects is incredible.  Im long term bullish on all the minerals. Im bullish on oil, because, like a dying lion, oil will push and push hard.   Electricity will replace oil.  Im bullish electricity. Gold will be a safe haven during so much confusion among currencies and economies.

Danial Gable

Danial Gable

 

Crumbling america

Under certain conditions the economy becomes very wasteful, and this is a recipe for disaster.   The public debt load is unsustainable under the current economic conditions. They are reasonable under real growth, but currently, the US is not under stable conditions.  The largest Us global corps are falling deeply behind the rest of the world. Companies like Lockheed and Boeing are large employers in the arms trade. This is an extremely vulnerable industry. The oil and gas, coal and even natural gas, are going to produce unmanageable expenses  related to pollution.  The health care system has so much potential, but the system seems unsustainable.  Pharmecuetical corporations are loosing, and obviously so! as potent pharms are unsustainable for the consumers.   An economy needs strong social tenets. Capitalism is great, if those in charge are capable.  Capabilities  are dependent on teaching and learning. Although the US likes to admit they are leaders in science and tec, this is not entirely true. These are multinational companies, acquiring the brightest minds from around the world.  Religion tends to relinquish personal power, and therefor diminishes our own personal capabilities.  Charity culture pervades the united states, and as people feel sorry for them selves, they miss out on the great adventure of life.  Unabated science is the best and most realistic avenue for growth.  The united states is along ways away from this reality.   near term, long term Short USD long gold

Danial Gable

Danial Gable

 

Bull Run Not Over?

Oil is on an upward climb. I dont see this bull run easing. In my opinion, This industry only has so much life left in it, as we can all clearly see a carbon free future. With so little time, and still so much money to make, it makes more sense to drive up the price real high. This is beneficial on many levels, as it encourages green tec development, almost real time with each increase in price.  Also, then the billions of dollars produced will and can help catapult society into a green era.  It will produce capital expenditure, but only to a degree, with the forsight of the industry completely ending, develpoment today is much different then 30 years ago. Even the 2014 oil crash is still fresh on the minds of many explorers, on just how vulnerable the indusrty is. The capital expenditures and prospective projects are probably going to be moderate, and with carbon goals, the industry has to be careful or they could loose out big time.   

Danial Gable

Danial Gable