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  1. 7 points
    I have been a trader since 1980. I started trading options in late 1983. I lost every penny of a $1.6 million portfolio in the crash of October 1987. What doesn't kill you makes you stronger. I have a undergraduate degree in Finance. I have a Masters degree in Economics. I have completed about half the requirements of a PhD in Financial Economics. I don't advise pursuing a PhD unless you want to be a teacher. It will not make you a better investor/trader. I developed a trading strategy involving shorting calls against GUSH in 2015 that I managed for a trucking firm to alleviate the strains of high fuel prices. Early in 2019 the owner of the trucking company sold the company and devoted his time to managing just the strategy itself. He said that he expects to make more profit in 2020 from writing calls against GUSH and writing puts and calls against his WTI contracts than his 32-truck transportation company ever did...all from his home...in his pajamas.
  2. 7 points
    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.
  3. 5 points
    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
  4. 3 points
    Brexiters hit back at Tusk for commenting that they deserve a special place in Hell for Brexit happening without a deal. Welsh first minister says it would be a catastrophe for Wales if Brexit happens without a plan. Nearly 5 m British and EU people could be stuck in Limbo if Brexit happens without a deal, though Brexiters hit back saying it's an insult to 17.4 m who voted for Brexit and want apology from Tusk.
  5. 3 points
    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.
  6. 3 points
    I read an article today from The Independent reminiscent of many similarly themed articles. It was about solar panels. The personal use kind—the kind you install on your roof. It didn’t really tell me anything new. The gist of the article was that there was this new survey conducted. And in this survey, they asked British folk whether they wanted to install solar panels on their roofs. The survey had found that “the majority of” British people would like to install solar panels if “greater government assistance was available,” the article read. If you’re looking for the actual figures, that “majority” is 62 percent. And then 60 percent would like to install an energy storage device. Then 71 percent would like to join a community energy scheme—again, if there was government support. Too bad their government deep-sixed its green subsidies. On the surface, I guess you could interpret those figures like, “Holy cow! Most British people want to be greenies and install solar panels!” But let’s be real. What the study shows is that 60-some percent of people would do it if someone else paid for it. Lovely. But well, you know, that means 40-some percent of people are NOT interested in installing solar panels or energy storage devices—EVEN IF the someone else paid for it. Not exactly a stellar endorsement. So look. This green thing is peachy. I’m not against renewables. I’m not even apathetic about renewables. I’m just realistic—it doesn’t have to be all or nothing when it comes to fighting climate change or just going green. It's talked about in absolutes. Renewables being the death of coal and oil. Or renewables are dead in the water as Big Oil fights back. This black and white view of things is narrow-minded and impractical. If you think the world is excited to fight that climate change, you are going to be disappointed. Well, people are generally disappointing I guess, so no shocker there. There are probably many people who are interested in greenifying their lifestyle—but only if it costs them nothing, and only if they have to give up nothing. Unless maybe you’re a Hipster (which I suppose you wouldn’t call yourself that even if you were), then I suppose you feel good about your greenness. You probably recycle your rainwater in some barrel on your roof. You ride your bicycle to work. You don’t use plastic water bottles and you recycle almost everything, including your skinny jeans and your cans of Pabst or Schlitz. Woot woot. But your green contributions, as noble as they may be, are lost in the sea that is Asia, who is offsetting any dip in US emissions, and then some. There are some true believers, though, and I salute them. I used to do transcription work, and one of my transcripts was an interview with a woman who was all-in on this green lifestyle. She didn’t buy anything that was packaged. She went to the butcher and would take a reusable container to put meat in that she had purchased. They didn’t use plastic of any kind. They didn’t use soap (it’s packaged). She would bring buckets of water from the river to flush their toilet. Now that’s all-in. I respect that. She’s not driving her 4X4 to some hippie protest of an oil pipeline in ND, creating in their wake millions in cleanup costs. (photo courtesy BBC) She sacrificed something (a whole lotta something) instead of jumping up and down asking the rest of the world to do the sacrificing. She’s not flying her fossil-fuel-burning jet or yacht to chastise the world for our dirty global warming ways. Photo courtesy Eric Worrall, wattsupwiththat.com And she’s not immersed in the latest fossil fuel cause celebre, just because it is the cause celebre. Photo courtesy of Instagram Oh, there are many self-righteous individuals who are eager to bash fossil fuels while enjoying the fruit of the Big Oil tree. Cities suing Big Oil for their role in climate change, all the while consuming the very product they are so vehemently opposed to. She’s not loudly divesting from oil. Phooey, you sanctimonious grandstanders. I’m calling you out. If you want to give up your plastic straws and trade your truck for an EV, you do it. Without the fanfare, preferably. And if you’re not ready to give up fossil fuels, SILENCE PLEASE.
  7. 2 points
    So here's where it started through OP and Douglas Buckland, we spoke for a great deal of time March 2019, the car was bought as is seen and was transported to Juniors shop as you can see its very old school and mainly a bike shop, in reality we were storing it there. Never would we have stopped the two wheeled marvels to go to four, but now, its on. The photos are to give you a general idea of what I and now Doug and Dan and my Mechanic are up against. I have also thrown in a photo of and HRD Vincent a 1950s Rapide going through mechanical until we would then take the bike up the posh shop for dismantling, paint, chrome and finishing for client (photos I will post later)
  8. 2 points
    Pt.3 The Media - Information sources - Electric/Hydrogen/Natural Gas Vehicles/ Nuclear Energy "Oh dear". This blog is about how to engage positively and effectively with the Media (TV, Radio, Press, Social Media, Bloggers. Vloggers) - mainstream, regional, local, international - from my own "mainstream" experience: e.g. BBC World Service. The content I use will be controversial and often, given that this is a fossil fuels website, not pleasing to some. All the content is sourced and available in the mainstream Media. My consultancy work is giving Media advice to all industry sectors, face-to-face and via Skype - e.g. DHL. KIA Motors, Nord Stream, UK Independent Schools' Council. The different Media, like individuals, will often choose the sources of information that reflect their wishes, values and bias. Thus, understanding the (often political) agenda of different Media before you or your company engages with them is extremely important. Two key professional interests of mine are: 1. Investigating why the Fossil Fuel Industry has never fought back against claims such as: - it is destroying the planet and that CO2 emissions are a Climate problem - "Big Oil" is throwing money to Climate Sceptic individuals and organisations; which is demonstrably not so, but is the result of a clever and long-term campaign by Greenpeace who targetted Exxon some years ago to label it "Evil Empire". 2. The philosophy of science: especially Popper v Kuhn. Posts will not normally be this long, but here are a few bullet points with regard to the above title and in relation to various comments: Fossil fuels: - yes, pollution is a factor and is increasingly being limited - CO2, however, is not a pollutant and is vital for life on Earth. - produced and are still producing the high standard of living we expect and want - are not subsidised everywhere, and the use of them is usually very highly taxed to provide national governments with a massive source of income for public services - there are different grades of all these fuels; varying down to low-level pollutants - even coal can be non-polluting: e.g. Professor Rosemary Falcon heads the Sustainable Coal Research Group at the University of the Witwatersrand (Wits), Johannesburg (where Nelson Mandela studied law in the 1950's). LPG/LNG vehicles: I too drive an LPG vehicle and gas, having done so for years Renewables: - are all subsidised and paid for by taxpayers either in their domestic energy bills and in the government subsidies - often both - produce less energy than was used to manufacture, erect and dismantle them after their short life (20-30 yrs). These three processes create large amounts of industrial pollution. Global energy needs are expected to increase by 250% by 2050 as living standards rise. Estimates vary on global energy use and production - e.g. in 2017 renewables produced 8% of global energy according to BP. The most optimistic projections from the pro-renewables IEA estimate that by 2040 renewables will still represent only 30% of global energy production - and of that the biggest contributors will be Hydro-Electric Power and Waste, not the beloved wind and solar sources. Sources are contradictory and confusing because of inherent political (not scientific) agendas). On average it seems that global energy use has risen by 150% in the last 20 years, and as a percentage of energy production the world is even more reliant on fossil sources than before. Solar panelscannot be simply buried in landfill because they contain toxic chemicals such as lead, cadmium, antimony; the glass is usually not pure enough to recycle; plastics are an integral part of construction. The problem of solar panel disposal “will explode with full force in two or three decades and wreck the environment”because of "a huge amount of waste and they are not easy to recycle. Contrary to previous assumptions, pollutants such as lead or carcinogenic cadmium can be almost completely washed out of the fragments of solar modules over a period of several months, for example by rainwater.” Sources: (http://www.scmp.com/news/china/society/article/2104162/chinas-ageing-solar-panels-are-goingbe-big-environmental-problem) 40-year veteran of US solar industry (https://www.solarpowerworldonline.com/2018/04/its-time-to-plan-for-solar-panel-recycling-inthe-united-states/) (https://www.welt.de/wirtschaft/article176294243/Studie-Umweltrisiken-durch-Schadstoffe-in-Solarmodulen.html) Research scientists - German Stuttgart Institute for Photovoltaics. The International Renewable Energy Agency (IRENA) in 2016 estimated there were about 250,000 metric tonnes of solar panel waste in the world at the end of that year. IRENA projected that this amount could reach 78 million metric tonnes by 2050. (http://www.irena.org/publications/2016/Jun/End-of-life-management-Solar-Photovoltaic-Panels) Wind power is even less efficient than solar for all the production reasons above and is more unpredictable as an energy source; kills flying creatures to such an extent that in some areas it has become the "apex predator" where it takes out birds of prey. Nuclear towers do not create such carnage because they do not move and are highly visible. Nuclear Energy is the cleanest, safest and most reliable energy source we have. When there are problems they can certainly be on a large scale (Three Mile island, Chernobyl, Fukushima) but result in very few deaths. If you consider CO2 to be a major problem, nuclear energy produces none at all. Ironically, this year (2018) the floating wind turbine erected as at Fukushima as a symbol of renewal is being dismantled because of its high maintenance costs. "The price tag to remove the ¥15.2 billion turbine, which has an output capacity of 7,000 kilowatts, is expected to be around 10 percent of the building cost. Studies on the two other turbines are due to conclude in fiscal 2018, but the study period is expected to be extended to seek any possibility of commercialization. ... Its utilization rate over the year through June 2018 was 3.7 percent, well below the 30 percent necessary for commercialization. The two other turbines, of different sizes, have utilization rates of 32.9 percent and 18.5 percent, respectively." Source: Japan Times Nuclear "waste" is in fact a resource and not to be feared! " ... fission waste does not migrate even where there is significant groundwater, and ... ancient waste had none of the multi-layer engineered safeguards that are now developed, nor the careful geological siting." " by far the biggest resource in radwaste is in the transuranics and unburnt uranium. This could be used to increase the energy available from nuclear fuel by several orders of magnitude using fast breeder reactors, but such use is no longer being pursued in many countries, including the UK ([which] used to be the world leader up until the early 1980s), as uranium is too cheap to make it economically attractive at present." Source: Rolls Royce expert and recipient of the Institute of Physics Nuclear Industry Group Lifetime Achievement Award And no, it can't be used to make a nuclear bomb; and there are much easier ways for terrorist groups to make the usual "dirty" bombs than trying to get hold of nuclear residue. It is calculated that there are about 120,000 cubic metres of nuclear waste in the world - i.e. not enough to fill a soccer stadium, since the start of the nuclear industry in the 1950's. Nuclear use is already part of our daily lives. We already use radio cobalt in irradiating food and medical supplies; strontium or plutonium for generators in space travel; americium in smoke detectors; tritium in emergency-exit signage; various radio isotopes are used to diagnose and treat diseases. Soon it is expected that we will be able to split further uranium isotopes and all uranium's heavy metal derivatives. Given that my first interest is helping you and your company to deal with the Media, mainstream and otherwise, it is important to judge your audience and then tailor your information to help them take it in. My presumption so far here in this blog is that readers are well-informed, wish to be given reasons to reflect, think and debate civilly on what are very important matters affecting how we live. I also presume such readers are thinkers rather than activists. Trigger warning: further topics will include references to and buzz words such as coal, climate change, CO2, sea levels, non-AGW, geological time scales, IPCC, Greenpeace, Big Oil and the like.
  9. 2 points
    These interactive presentations contain the latest oil & gas production data from all 14,162 horizontal wells in North Dakota that started production since 2005, through October. Visit ShaleProfile blog to explore the full interactive dashboards Oil production in North Dakota climbed to 1,392 kbo/d in October, a month-on-month increase of more than 2%, and again a new record for the state. In the first 10 months this year 1,045 wells were brought online, which was more than in each of the two years before. The 2nd tab (“Well quality”), shows that recent wells are performing slightly better than those from 2017, which recovered on average 160 thousand barrels of oil in the first year on production. In the “Well status” tab you can find the status of all these wells. By selecting the status ‘First flow’, you’ll find that 112 wells started producing in October (vs. 153 in September). All leading operators have grown production in 2018 (“Top operators” tab). ConocoPhillips has almost taken over the 2nd spot from Whiting. 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. It reveals that the wells that started in Q3 2017, marked by the dark green curve at the top, have shown so far the best performance, although the wells from 2018 are closely tracking a similar path. The 2nd tab (‘Cumulative production ranking’), ranks all wells (from unconventional reservoirs) by cumulative production. The top 2 wells have produced each more than 1.6 million barrels of oil, and each of them still produces at a decent rate (>100 bo/d). Five more wells have also produced more than 1 million barrels of oil so far. The median well has produced a little below 200 thousand barrels of oil. The ‘Productivity over time’ dashboard shows clearly how well productivity (as measured by the cumulative oil or gas production in the first x months), has increased in the past few years. We have a similar dashboard in our online analytics service, which allows you to normalize production, and which also shows the trends in well design (lateral length & proppant loading). It offers the possibility to quickly compare the performance of operators over time, in relation with how each has changed its completion practices. We will have a new post on the Marcellus just after Christmas. In our chat on enelyst, tomorrow (Dec 18th) at 10:30 am EST, we will take a closer look at the Bakken. If you are not yet an ign up for free at: www.enelyst.com, using the code: “Shale18”.enelyst member, you can s 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/2SRAuN9 Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  10. 2 points
    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
  11. 2 points
    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.
  12. 2 points
    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
  13. 2 points
    This interactive presentation contains the latest oil & gas production data through June from all 16,770 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009. Visit ShaleProfile blog to explore the full interactive dashboards Even though data for the last few months is still somewhat incomplete, it is already clear that the Permian set another production record in June, producing well above 2.4 million bo/d from these horizontal wells. The ~2,000 wells that started so far this year already contributed more over 1 million bo/d in June, as reflected in the height of the dark blue area. The most prolific formations are the Wolfcamp and Bone Spring, together good for ~80% of total production (set ‘Show production by’ to ‘Formation’ to see this). Although output is still rising, with more than 10 wells starting to flow every day, well productivity is no longer increasing as it did between 2013 and 2016, as you’ll notice in the ‘Well quality’ tab. The 3 largest producers here, Pioneer Natural Resources, Concho Resources, and EOG, all increased production at a similar speed since early 2017 (see ‘Top operators’). 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. The thickness of these curves is an indication of how many wells are included. E.g., the thick curves since Q4 2017 reflect the more than 1,000 wells that started in each of the recent quarters. Although the number of new producers is high, also this plot shows that since Q2 2016 well performance hasn’t significantly changed anymore. In fact, if you normalize production by the lengths of these laterals (which is possible in our ShaleProfile Analytics service), you’ll find that productivity improvements have stagnated since then. Given that proppant loadings are also up (~16 million pounds per completion in Q1 2018, vs ~11 million pounds in Q2 2016), operators are getting less bang for their buck (or more accurately, less oil for their ‘bang’). This may explain why proppant loadings have on average not further increased since Q4 2017 in the Permian. Pioneer Natural Resources, which completed many wells since the end of last year with more than 20 million pounds of proppant, seems to also have scaled down its completions in recent months, based on preliminary data. Later this week I will have a post on the Eagle Ford, followed by one on all 10 covered states in the US early next week. 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/2zIbdyk Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  14. 2 points
    This interactive presentation contains the latest oil & gas production data through July, from all 8,221 horizontal wells that started production in the Niobrara region (Colorado & Wyoming) since 2009/2010. Although we had a post on this region just 3 weeks ago, as we now have reliable data up through July, I wanted to share another update. A few percent of the wells were not yet reported in July, so there will be some upward revisions. Visit ShaleProfile blog to explore the full interactive dashboards Total oil production from horizontal wells in these 2 states increased by about 50% since early 2017, to close to half a million barrels of oil per day. In July, the wells that started in this period (>= 2017) contributed around 75% to this production. Completion activity is still a bit behind the record levels seen at the end of 2014, with ~120 wells per month added (vs. ~160 in the 2nd half of 2014). In the “Well quality” tab we can see that the wells that started in 2017 clearly outperformed any earlier wells, on average. The ones that started in 2018 appear to be slightly behind in terms of initial performance. Anadarko, the leading operator here with close to 20% of total oil output, was above 100 thousand barrels of oil per day of gross production again in July, as the last tab shows. The average gas oil ratio for its wells in Weld County is rising rapidly (>40% in the past 3 years), and there are some signs that this is impacting long-term recovery potential. As shown also in my previous update on North Dakota, we recently added a new dashboard in our analytics tool (for which you can request a trial here), in which these trends can be analyzed in all detail. The ‘Advanced Insights’ presentation is displayed below: In this “Ultimate Recovery” graph, the average cumulative production of all these horizontal wells is plotted against the production rate. Wells are grouped by the quarter in which production started. Although average well productivity in general increased until early 2017, this plot shows that since then it appears to have fallen slightly. Recent wells may on average fall just short of recovering 140 thousand barrels of oil, before becoming stripper wells (< 15 bo/d). In the ‘Productivity ranking’ overview, operators are ranked according to the average cumulative oil production in the first 2 years. Of the large operators (>100 operated wells), EOG has the best performance with 125 thousand barrels for this metric. If you click on its result, you will see in the map below that most of its wells are located in Campbell County (WY). Next week we will have updates on both the Permian and the Eagle Ford. Production data is subject to revisions. For this presentation, I used data gathered from the following sources: Colorado Oil & Gas Conservation Commission Wyoming Oil & Gas Conservation Commission FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2QdcmDv Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  15. 2 points
    This interactive presentation contains the latest oil & gas production data through March from all 15,294 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009. Oil production in the Permian has kept its upward trajectory through the first quarter of this year. The percentage growth since mid last year was even larger in New Mexico (50%), than in Texas (toggle the basins in the ‘Basin’ selection to see this). Despite the increase in drilling & completion operations, well productivity has not deteriorated in recent quarters. The ‘Well quality’ tab shows the production profiles for all wells that started in a particular year, and here you can see that on average, recent wells are tracking the performance of wells that started in 2016. Those are on a path to recover ~200 thousand barrels of oil in their first 2.5 years (30 months) on production. In the bottom graph in the ‘Well status’ overview you can see the percentage of wells that are producing at a certain production level. In March, just over 400 wells were producing above 800 bo/d (a new record). The percentage of wells that are producing below 50 bo/d has remained steady at about 50% in the past couple of years. The 4 leading oil producers in this basin are producing at or near record output levels, as shown in the final tab (‘top operators’). 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. If you want to figure out which operator has the best average well results, the ‘Productivity ranking’ tab is a good place to start. Here you can see the ranking of all operators by the average cumulative production over the first 24 months. If you change this measurement period to 12 months, and select only the years 2016/17 using the ‘Year of first flow’ selection, you can see that of the large operators (>100 operated wells), EOG scores the best, with an average cumulative oil production of 207 thousand barrels in the first year for all its 147 wells that started producing in 2016 & 2017 (Jan-April only). Early next week I will have an update on the Eagle Ford, followed by a post on all covered states in the US. We will be present at the URTeC in Houston later this month, so if you would like to meet us, or learn more about our upcoming analytics services, I hope to see you there. 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 2010, 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 https://shaleprofile.com/index.php/2018/07/04/permian-update-through-march-2018/ Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  16. 2 points
    This interactive presentation contains the latest oil & gas production data through March from 20,615 horizontal wells in the Eagle Ford region (TRRC districts 1-4), that started producing since 2008. Growth is tepid in the Eagle Ford basin, and recent oil output remains well below the high set in March 2015, even after upcoming upward revisions. Although well productivity has also improved in this basin, as shown in the ‘Well quality’ tab, the effect has been more modest. After normalizing for the increase in lateral length, it almost disappears, despite that the amount of proppants used has doubled over the past 4 years. EOG is the largest oil producer in this area with ~ 250 thousand bo/d operated production capacity (see the ‘Top operators’ tab). 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 quarter in which production started. For example, the thick blue curve, representing the 1,024 horizontal wells that started in Q3 2013 peaked on average at a rate of 361 bo/d, and are now just below 24 bo/d, after having recovered 133 thousand barrels of oil and 0.5 Bcf (you can click on this group in the color legend to highlight the related curve). In comparison, the 474 wells that started in Q4 2017 peaked at double the rate. But will they also double the ultimate oil & gas recovery? It’s too early to tell for sure, but noting that the decline behavior has been relatively predictable in the past, it appears they will fall short of that. Later this week I will have a post on all 10 covered US states, followed by an update on North Dakota. We will be present at the URTeC in Houston later this month, so if you would like to meet us, or learn more about our upcoming analytics services, I hope to see you there. You can follow me here on Twitter: https://twitter.com/ShaleProfile 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 https://shaleprofile.com/index.php/2018/07/09/eagle-ford-update-through-march-2018/ Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  17. 1 point
    St. Petersburg State University professor Alexey Kavokin has received the international Quantum Devices Award in recognition of his breakthrough research in the development of quantum computers. Professor Kavokin is the first Russian scientist to be awarded this honorary distinction. Aleksey Kavokin’s scientific effort has contributed to the creation of polariton lasers that consume several times less energy compared to the conventional semiconductor lasers. And most importantly, polariton lasers can eventually set the stage for the development of qubits, basic elements of quantum computers of the future. These technologies contribute significantly to the development of quantum computing systems. The Russian scientist’s success stems from the fact that the Russian Federation is presently a world leader in polaritonics, a field of science that deals with light-material quasiparticles, or liquid light. “Polaritonics is the electronics of the future,” Alexey Kavokin says. “Developed on the basis of liquid light, polariton lasers can put our country ahead of the whole world in the quantum technologies race. Replacing the electric current with light in computer processors alone can save billions of dollars by reducing heat loss during information transfer.” This talented physicist believes that the US giants, such as Google and IBM are investing heavily in quantum technologies based on superconductors, Russian scientists are pursuing a much cheaper and potentially more promising path to developing a polariton platform for quantum computing. Alexey Kavokin heads the Igor Uraltsev Spin Optics Laboratory at St. Petersburg State University, funded by a mega-grant provided by the Russian government. He is also head of the Quantum Polaritonics group at the Russian Quantum Center. Alexey Kavokin is Professor at the University of Southampton (England), where he heads the Department of Nanophysics and Photonics. He is Scientific Director of the Mediterranean Institute of Fundamental Physics (Italy). In 2018, he headed the International Center for Polaritonics at Westlake University in Hangzhou, China. The Quantum Devices Award was founded in 2000 for innovative contribution to the field of complex semiconductor devices and devices with quantum nanostructures. It is funded by the Japanese section of the steering committee of the International Symposium on Compound Semiconductors (ISCS). The Quantum Devices Award was previously conferred on scientists from Japan, Switzerland, Germany, and other countries, but it is the first time that the award has been received by a scientist from Russia. Due to the coronavirus pandemic, it was decided that the award presentation will be held next year in Sweden.
  18. 1 point
    This article contains still images from the interactive dashboards available in the original blog post. To follow the instructions in this article, please use the interactive dashboards. Furthermore, they allow you to uncover other insights as well. Visit ShaleProfile blog to explore the full interactive dashboard These interactive presentations contain the latest oil & gas production data from all 26,331 horizontal wells in the Permian (Texas & New Mexico) that started producing from 2008/2009 onward, through January. Total production January oil production came in at about 4 million bo/d (after upcoming revisions). I expect to see a small increase from the December level when all data is in. In the last few weeks we have again improved our handling of the data in Texas and it is now more up-to-date and complete. Already close to 90% of February production data in the state of Texas is available in our subscription services. Supply Projection dashboard Although the rig count has also dropped significantly in the Permian in recent weeks, the relative decline has been less than other basins. The following image, taken from our publicly available Supply projection dashboard, shows that the horizontal rig count is down to 274 as of last week. However, the bottom chart reveals that even this level of drilling activity would not make a serious dent in the long-term production capacity of the basin: Projected rig count and oil output in the Permian Basin – assuming no changes. This does assume that the rig count drops no further and that no production is shut-in temporarily due to the extraordinary low prices (as well as no changes in productivity). Although these assumptions are surely highly flawed, this overview does make clear that a further reduction in drilling is needed before the Permian would turn to an overall decline to help balance the markets. Today we will have a webinar on this dashboard, at 9 am (CT). Although the maximum number of registrants has already been reached (100), we will still try to increase this number. Therefore, don’t hesitate to sign up: Register for the Supply Projection webinar Well productivity In the “well quality tab” the production profiles for all the wells in the Permian are available. The bottom chart allows you to see that well productivity has increased each year in the last decade. However, after normalizing for lateral length (possible in our advanced analytics service), we find that recent results are slightly down since 2016. Advanced Insights The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview displays the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the year in which production started. Finally As mentioned, tomorrow we will host a webinar on our Supply projection dashboard and how you can use it for your own projections. We will have a new post on the Eagle Ford on Tuesday. Production and completion data are 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. Visit our blog to read the full post and use the interactive dashboards to gain more insight: https://bit.ly/2KulL8K Follow us on Social Media: Twitter: @ShaleProfile LinkedIn: ShaleProfile Facebook: ShaleProfile
  19. 1 point
    Know your customer (KYC) and anti money laundering (AML) solutions are vital for financial institutes specially for banks as per regulatory authorities. When anyone comes to open his account in a bank, identity verification of that individual is a must to fulfil KYC requirements. To get KYC done all the required information is taken by the bank representative including source of income, document verification and biometric authentication of the individual. Like every other thing happening online. Online banking has also taken a lot of limelight. It gets a bit tricky to verify someone when he is not even sitting in front of you. So digital identity verification solutions play a crucial role here. Digital KYC for banks with document verification solutions is required to verify that the provided documents as well as the person are the real deal. Advanced AI-powered KYC solutions that carry out all the verifications and scanning tasks. At times HI (Human Intelligence) is also clubbed with AI to authenticate the individual fully. Installing such KYC and AML solutions prevent banks from falling in the pit of many financial frauds such as stolen identity and credit card frauds. Such solutions verify the person as well as check the documents for tampering and forgery. Digital KYC solutions have been quite useful for banks while operating online. How KYC solutions for Banks Work? Banks need to verify individuals for many reasons. For instance when a person wants to open a bank account online, he fills out all the requirements and can easily submit his documents by taking their picture or showing them on a webcam. Such solutions are intelligent enough to check if the document uploaded is real and authentic. By using hologram checking technology the tampered and forged documents are detected. Moreover, using OCR technology the information from the given documents is extracted and checked against many section lists and PEP lists to know the person was ever involved in any kind of criminal activity. Moreover by using facial recognition technology the system can tell if the real person was present in front of the camera. 3D liveness detection feature of facial recognition technology helps to fight back any spoofing attacks like 3D mask or video streaming instead of the real person. The face on the document picture is matched with the real face to authenticate fully. Such KYC and AML solutions do a background check of the person against global watchlists regarding terrorist organisations and money laundering. The system lets the customer proceed only if everything is crystal clear otherwise the process is halted and request is denied. KYC and AML Verification for Banks: KYC solutions are vital for banks to make sure that they are not letting fraudsters into their system. Identity verification plays an important role in catching up the criminals, Banks failing to do so will be charged hefty amounts of fines to provide a platform to such fraudsters for taking up their scams like money laundering and terrorist financing. Integrating such channels into the system of banks is totally hassle-free. Such solutions provide a win-win solution to both banks and customers in a way that it saves a lot of time and effort of businesses which is required to perform KYC and on other hand it streamlines the verification process for clients who get frustrated at times by long and complicated procedures. Banks looking for a KYC service provider can take help from online identity verification service providers verify the identity of an incoming user with the help of deploying different AI based technologies such as biometric technology, address verification, digital document verification, 2FA, handwritten notes etc.
  20. 1 point
    >>The falling of the Persian Gulf oil empires is near << Oil is a blessing for the Gulf states . Oil exploration in the middle of the 20th century has made this poor and impoverished region one of the richest regions in the world. Iran , Qatar, Kuwait and the United Arab Emirates are also richer than Switzerland. Even Saudi Arabia, Bahrain, and Oman are equal with Japane and British. The period when the Gulf states and their wealth funds were money-making machines that could pay for any cost of plan(s) on any continent , is coming to an end and their national wealth reserves are running out at this low oil price. Even in the worst-case scenario, when oil prices reach $ 10 a barrel and the entire world oil industry will faced to damaged, Gulf producers will continue to save of the owns profit. But, the problem is their economy. They need higher oil prices to balance their budgets and support dollar-related currencies.Their central banks and sovereign wealth funds of those countries , have high reserves to over of such a crisis and can even withstand the long-term risk of falling demand, but their reserves will be empty of oil at such a low price. The IMF's report shows that in these four years, the net financial assets of the Gulf kingdoms have fallen by about half a trillion dollars from two trillion dollars. So , Oil by $ 20 a barrel will accelerate the depletion of these reserves and bringing it to zero. This means planning and destroying the Middle East and the Persian Gulf. as if , the Middle East must always be involved in war, poverty and suffocation to increase the assets for great world powers . Citation to link: ww.bloomberg.com/opinion/articles/2020-03-22/saudi-russia-oil-price-war-heralds-end-to-gulf-luxury-lifestyle
  21. 1 point
    These interactive presentations contain the latest oil & gas production data from all 24,208 horizontal wells in the Eagle Ford region, that have started producing from 2008 onward, through November 2019. Visit ShaleProfile blog to explore the full interactive dashboard Oil production came in again at just over 1.3 million bo/d (after upcoming revisions), as it has since the start of 2019. Well results have not improved since 2017, as is clearly visible in the bottom chart of the “Well quality” tab. In the core of the oil window, in Karnes and DeWitt, well productivity has slightly declined (select these counties using the “County” filter). This is without taking into account the fact that laterals have gotten longer and proppant intensity has gone up. In the “Well status” tab the status of all these wells can be found. The bottom chart shows the % of wells by production rate. In November, about 60% of the wells in this basin produced below 25 bo/d. After removing the gas wells (a subscription only feature), this percentage drops to 55%. EOG’s production fell below the 250 thousand bo/d, a level it first reached 5 years earlier (“Top operators”). Its December production (available in our subscription services) increased again. Meanwhile, Chesapeake set a new production record in November. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview reveals the relationship between production rates and cumulative production. Wells are grouped and averaged by the year in which production started. In this screenshot, taken from ShaleProfile Analytics, you can see all the horizontal wells in Karnes and DeWitt County, colored by the Gas/Oil ratio in the most recent month. The charts on the right show the production rate and gas/oil ratio versus cumulative oil production, by vintage: Gas/oil ratios in Karnes and DeWitt. Hz wells since 2012 only. These charts reveal that the wells that came online in 2018 became gassier faster than the wells from the year before (bottom chart), while the decline rate has increased (top chart). Early next week, we will have a new post on all covered states in the US. Production and completion 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 lease reports. FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight: https://bit.ly/2T9n693 Follow us on Social Media: Twitter: @ShaleProfile LinkedIn: ShaleProfile Facebook: ShaleProfile
  22. 1 point
    The effort by the United States to use sanctions to shut down the Nord Stream 2 pipeline between Russia and Germany by imposing sanctions on the entities involved in it is, in my opinion, is beyond outrageous. However, nobody seems to be surprised because it is part of a pattern. This is merely the most recent demonstration of the increasingly egregious violations of the laws, customs, traditions and mores that govern the behavior of civilized nations that we now expect from the United States of America. Oddly, in this case, it may be both the problem and the solution. There are reports that suggest that Russia believes it can complete the pipeline itself and bring the project to a conclusion perhaps just a few months behind schedule. The Russian business newspaper Kommersant reported that Russian President Vladimir Putin told a group of Russian businessmen that a Russian ship, the Akademik Cherskly (Academic Cherskly) can lay pipe for the Nord Stream 2 pipeline, although not as quickly as the Dutch-Swiss company’s vessel that was taken out of service due to the sanctions threatened by the United States. If Putin is being honest about this, it could be a good thing for the world and especially the European Union. The EU needs the appearance of a victory on this one. This pipeline is, in fact, essential to the long-term energy security of the European Union. The allies, possibly former allies, of the United States need to make it clear that the U.S. is not free to endanger the security of nations that are trying to be its friend. The administration of Donald Trump is behaving ridiculously with some of its sanctions. You may recall that the United States imposed sanctions personally on Iranian Foreign Minister Mohammad Javad Zarif. The explanation was that the foreign minister “is a key enabler of Ayatollah Khamenei’s policies.” Criticizing a foreign minister for being an advocate for the policies of his government is about a ridiculous as one can get. So, there needs to be some push-back against the Trump administration’s foolish and irresponsible efforts to use sanctions to force Europe to buy LNG from the U.S. and turn away the natural gas Russia wants to sell. Having said all that, if the U.S. wishes to offer Europe LNG that is less expensive than the price Russia is offering for its gas, I think that would be just fine. Some serious price competition between two of the world’s major gas producers would be a good thing for Europe.
  23. 1 point
    These interactive presentations contain the latest oil & gas production data from all 23,839 horizontal wells in the Permian (Texas & New Mexico) that started producing from 2008/2009 onward, through August 2019. Visit ShaleProfile blog to explore the full interactive dashboard Preliminary data from the state agencies already has August production at a record high (see chart above). After revisions, especially for New Mexico, I expect that August production will be revised upward to about 3.7-3.8 million bo/d. Although the horizontal rig count has fallen by 15% since the start of this year (443 to 377 in the previous week), if current drilling & completion activity and well productivity would stay constant (which they never do), production has the potential to double from current levels over time. This simple projection obviously ignores many possible constraints that could occur on the way. The “well quality” tab does show that improvements in well performance have flattened since 2016. As observed in previous posts on this basin, after normalizing production data for the increases in lateral length (which is easily done in our advanced analytics service), we see no improvement since Q2 2016. Pioneer overtook Concho in the “Top operators” overview in August. However, since the acquisition of Anadarko, Occidental is now the largest operator in the Permian (we still list both entities separately), with well over 300 thousand bo/d of operated 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 year in which production started. In previous posts we shared the operators with the best performing wells. In the following screenshot, you can find this ranking for the Permian Basin, based on the average cumulative oil produced in the first 2 years on production. Only horizontal oil wells are included that began production since 2012. Operators are only shown if they completed at least 20 wells in the selected time frame. Click on the image to see a high-resolution version, which was taken from ShaleProfile Analytics. Resolute, which was last year acquired by Cimarex, shows the best results, with an average of 250 thousand barrels of oil in the first 2 years. In the middle of next week, we will have a new post on the Eagle Ford. Production and completion data are 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 production 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: https://bit.ly/337O2cf Follow us on Social Media:Twitter: @ShaleProfile LinkedIn: ShaleProfile Facebook: ShaleProfile
  24. 1 point
    The oil price is not only relevant for insiders in the oil industry. It is important for the entire economy; politicians and central banks keep their eye on it. But how is the price of oil actually determined? Like every price, the price of oil is a result of the interplay between supply and demand. Plus, there is the economic environment which can lead to longer-term changes. An overview of the key factors: The supply There are different oil grades and countries where these are produced under different conditions. Twelve nations that produce oil around the world make up OPEC (Organization of the Petroleum Exporting Countries). OPEC covers about 40 percent of the global oil production. They influence the price development of crude oil when they restrict or increase the amount they produce. The rule is: When the supply decreases but the demand remains high, the supply becomes that much more valuable – and expensive. In the past five years the supply of oil has risen dramatically outside of OPEC countries – particularly in the US. In recent years the US has transformed from one of the biggest importers of energy to an important energy producer. The main reason is fracking. “Fracking is the technology that made shale oil production profitable in the USA,” says Johannes Benigni of the research and consulting center JBC Energy. New sources of oil were opened up, so the supply has grown. The production of natural gas and crude oil in the US have increased by 50 and 75 percent, respectively, since 2005, the consultant says. It is becoming more difficult to calculate the price since the supply is no longer coming exclusively from OPEC, now other countries also have a strong influence. However, the supply is also influenced by the conditions under which oil is produced. The price of producing one barrel can vary between a few USD per barrel and up to USD 80. Government guidelines like environmental regulations or difficult geographical circumstances increase the production costs. “Some of the most expensive barrels are those in difficult locations like the deep sea. Production in challenging geological formations also raises the price of the supply,” . “When the demand is small and the oil price is accordingly low, comparatively ‘expensive’ production doesn’t pay off anymore. This then reduces supply, which influences the price of oil,” explains Wolfgang Ernst. The demand “How much oil is needed depends on global economic development as well,” says the OMV expert. At the moment the market is primarily being driven by development in Asia. The demand in China and India, for instance, has increased sharply in the past two decades, because the economy is growing faster there than in Europe. A rise in population growth, for example, can also increase the demand for energy – and therefore oil – in the long term. But the oil price can fall in spite of a growing economy, because “the price is also determined on the demand side by other factors like taxation, weather, and environmental regulations,i. The International Energy Agency (IEA) forecasts in the current World Energy Outlook that the energy demand in Europe will fall slightly. We will also see shifts resulting from a rising demand for renewable energy. The geopolitical factors Conflicts and political crises as well as disruptions in deliveries due to weather, such as environmental catastrophes, can have a negative effect on the oil supply. In the past, these often led to a higher oil price, because declines in production were anticipated. Today Libya, Syria, and Yemen have virtually dropped out as oil producing countries due to their political instability; the years of sanctions against Iran are still applied. However, shale oil production in the USA has increased sharply. “Otherwise the oil price could have been much higher between 2009 and 2014,” The financial market Oil is also traded on the financial market in much larger amounts than OPEC produces. Wolfgang Ernst: “Many companies in the energy industry protect themselves against price fluctuations with financial market activities.” Purely financial actors then bet on price changes and try to make a profit that way. Psychological factors and expectations play a role here. “In the short term, speculations on falling or rising prices may very well determine the price development. However, almost all studies show that there is no or only a temporary limited connection between speculation and absolute price levels,”
  25. 1 point
    Welcome to the Underground Storage blog here at OilPrice.com! The blog is now open and we welcome your participation, thoughts, experiences, and insights on this segment of the market.
  26. 1 point
    This interactive presentation contains the latest oil & gas production data from all 22,637 horizontal wells in the Eagle Ford region, that have started producing from 2008 onward, through March 2019. Visit ShaleProfile blog to explore the full interactive dashboards March oil production came in at about 1.3 million bo/d, after upcoming revisions, 5% higher than a year earlier. Natural gas production is still hovering at a level close to 6 Bcf/d (switch ‘Product’ to ‘gas’). The ‘Well quality’ tab shows the average production profiles of all these wells. The wells completed in 2019 are so far slightly ahead of earlier wells. But well productivity has stagnated since 2017, as you’ll find in the bottom chart (‘Cumulative production profiles’). EOG and ConocoPhillips, the two leading oil operators in the basin are close to their historical output record, which they both set last year. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview reveals the relationship between production rates and cumulative production. Wells are grouped by the year in which production started. The 2,891 horizontal wells that started in 2012 have now recovered 150 thousand barrels of oil each, on average, while their production rate has dropped below 20 bo/d. The wells that have been completed since 2017 are on a path to do 200 thousand barrels before hitting a similar level. Of course, there are major regional differences. In the oil-rich counties Karnes and DeWitt, this metric is closer to 300 thousand barrels of oil. In the 4th tab, the operators in this area are ranked by their well performance, as measured by the average cumulative production in the first 2 years. Of the operators with more than 100 wells, Devon and ConocoPhillips are showing the best performance. Their wells recovered on average 200 thousand barrels of oil in the first 2 years. Later this week, we will have a new post on all covered states in the US. Next week we will be a few days in Houston, before traveling to Denver for URTeC, where we have a booth (#951). Please contact us if you would like to meet us in either city! 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 lease reports. FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2Xu6D4i Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  27. 1 point
    These interactive presentations contain the latest oil & gas production data from all 21,384 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through March 2019. Visit ShaleProfile blog to explore the full interactive dashboards Oil production from horizontal wells in the Permian set another record in March, at over 3.2 million bo/d, even before upward revisions. As the blue areas indicate, in March more than 2/3rd of total production came from wells that began production since 2018. Gas production also set a new record at close to 11 Bcf/d (switch “Product” to gas), although not all of it is wanted due to sometimes negative pricing. As the “Well quality” tab reveals, initial performance has increased since 2016, but nowhere near the gains seen in the 2013-2016 time frame. This also doesn’t take into account that laterals kept increasing, as did proppant loadings. The biggest change was in the number of well completions; in 2018, on average more than 400 horizontal wells came online each month, versus less than 200 in 2016. The final dashboard, “Top operators”, displays the production history of the 5 largest operators. They all set new output records in 2019. 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 year in which production started. The 2,254 horizontal wells that started production in 2016 have so far recovered the most oil, on average: 200 thousand barrels of oil. They are still producing at an average rate just north of 100 bo/d, and they may recover another 200 thousand barrels before they are down to 20 bo/d (extrapolate the curve to arrive at roughly this number). The following screenshot (from our advanced analytics service) shows how initial well productivity has evolved in the 6 top-producing counties in the Permian. Click on the image to see a high-res version of it. The graph shows the average oil recovery in the first year on production, by county and production start date. Increases in lateral length and proppant use greatly boosted initial productivity in the past 6 years. The best well performance is now seen in Midland and Lea. Interestingly, performance dropped somewhat in Reeves County in the last year. The WSJ recently published 2 articles about the Permian, for which they also found use in our analytics service (behind paywall): A Leader of America’s Fracking Boom Has Second Thoughts (last week) A Fracking Experiment Fails to Pump as Predicted (today) Later this month, we will be at the URTeC in Denver, from July 22nd until the 24th. Drop by our booth, #951, if you are in the area, for a chat and a personalized demo! Early next week we will have a post on the Eagle Ford, followed by an update on all 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/2XsKCCQ Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  28. 1 point
    This interactive presentation contains the latest oil & gas production data from all 22,421 horizontal wells in the Eagle Ford region, that have started producing since 2008, through February 2019. Visit ShaleProfile blog to explore the full interactive dashboards February oil production came in at 1,22 million bo/d, the same rate of production as a year earlier. After revisions, it will be a little higher but still below the level at the end of last year. As is visible in the graph above, the contribution of wells that came online before 2018 was just about 50% in February. The ‘Well quality’ tab reveals that the performance of the 1,800+ horizontal wells that began production in the main formations (Eagle Ford & Austin Chalk) in 2018 was equal to those that started a year earlier (see bottom chart). You can also find that typically, after 6 years on production, wells have declined to a production rate of about 20 bo/d. There are of course major regional variances, which I will show later in this post. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview reveals the relationship between production rates and cumulative production. Wells are grouped by the year in which production started. In the 2nd tab, you will find a ranking of all counties in the Eagle Ford, based on total oil production from these horizontal wells through February. Karnes is #1, with over 700 million barrels of oil produced, since 2008. Now, let’s take a closer look at how well productivity has evolved in the top 4 counties shown in this list. The following screenshot comes from our advanced online analytics service: The map shows the location of all the horizontal oil wells in these 4 counties (click on the image for a high-resolution version). The top right graph shows the average well performance over time, as measured by the cumulative oil recovery in the first 12 months. DeWitt County is in the lead, with close to 190 thousand barrels of oil recovered in the first year on production, on average. However, total oil production in this county has dropped close to a multi-year low, as completion activity has dropped (not visible in this image). Only 152 wells came online in this county in 2018 (vs. 383 in 2014). In the middle of next week we will have a new post on all covered states in the US. We still offer free trials and demos in case you are curious to know what more you could learn from our analytics and data services: request a demo or trial. 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 lease reports. FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2WisrdR Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  29. 1 point
    The only safe outcome for Libya and Libya’s contribution to the international oil market is for Tripoli to fall to General Haftar. The absence of any Tripoli based central government control of the oil producing regions of Libya, far from the capital, led to an opportunity for general Haftar to expand his influence by creating and maintaining stability in those areas. The whole country is dependant on those oil producing regions for its foreign income and relies on general Haftar to keep the oil flowing. Once General Haftar attacked Tripoli he effectively lit the bridge on fire behind him and more importantly behind the whole country. If Haftar is defeated in Tripoli and his military capabilities are reduced enough or eliminated then the stabilizing force on the oil producing regions will also likely disappear, creating a vacuum which will be filled by much less pleasant characters waiting for an opportunity to seize control. Many people seemed surprised when Trump tweeted out his support for general Haftar, I however was not. Any opposition to Haftar is effectively an opposition to about a million barrels a day of production, production Trump will be relying on when he imposes sanctions on Iran. Watch Libya carefully, if Haftar loses then the likely consequence will be attacks by rebel groups on oil installations and a subsequent drop in production or at least a meaningful risk premium on whatever production is maintained. Alex Lindsay: Alex is an energy industry technical expert with experience in most areas of oil and gas upstream operations and a keen interest in oil market analysis. A civil engineer by education and a driller by passion, always on the look out for grey and black swans in the energy market. The views expressed in any of Alex’s articles reflect the sentiment of his current portfolio.
  30. 1 point
    TODAY'S INVESTMENT GOAL: How to achieve high Internal Rates of Return, (IRR), with a properly structured transaction based on existing oil and gas production … without the market risk of most oil and gas investments. Can this be done? Requirements to achieve the strategy and returns for discussion: Buy production at a reasonable discount Evaluate the production as to the operator’s capability to deliver what is purchased Hedge the acquired oil/gas to eliminate market risk Requirement #1 Acquire production at a discount The niche is the small to medium sized producer that has found development capital difficult to raise due to banking reserve requirements after the oil/gas price crash of 2014-2018. Deal with producers that have existing PDP production that can be leveraged and provide the capital to improve it. The oil is ‘rented’ for a term under a delivery schedule obviating the risks of onerous working interest structures, joint venture follies, drilling and equipment issues and any assortment of the usual risks. The investor is not an oil company… Oil Company Benefits: Not an interest bearing loan, a footnote to the balance sheet Non-recourse Zero equity take-out, the company parts with none to the investor Requirement #2 Evaluate the operator’s capability to deliver The existing production is evaluated by a major engineering firm. They deliver a comprehensive report regarding the ability of the oil company to meet their delivery obligations for the length of the term. The amount of oil purchased varies based on the capital needs of the company. Oil/Gas is delivered on a stated monthly schedule, that matches the decline curve of the production. The investor becomes part of the division order to secure repatriation of the invested amount, satisfying the delivery contract. Requirement #3 Hedge the acquisition to avoid market risk The desire is to avoid all market risk… a put is purchased on every barrel of oil bought, matching exactly with the delivery schedule. What are the risks? 1. Market: Risk Factor – NONE Eliminated due to hedging 2. Counter party on the hedge: Risk Factor – MINIMAL Reduced by using top credit firms. 3. Delivery: Risk Factor – MINIMAL Reduced by quality engineering during due diligence. 4. Environmental and Title: Risk Factor – NONE One of the top oil and gas law practices in the country prepares the review of title and environmental risks. 5. Character: Risk Factor – MINIMAL Extensive background and credit record of the operator and producer is performed and evaluated. In Conclusion: Investor Benefits: The capability to have a high IRR, (much higher than most oil companies make historically). The investor has no downside market risk and can structure the transaction so they have upside profit potential. The investor has no operating expense, is not subject to being over-operated, has no equipment, will never get a cash call. The returns available via this structure are generous as to IRR’s, much higher than other investments with similar risk profiles.
  31. 1 point
    Russia’s Gazprombank leaves Venezuela. Rosneft still stays. Moscow, Russia. March 15, 2019 Gazprombank is minimizing risks in Venezuela. The bank has sold a 17% stake in GPB Global Resources which, in turn, owns 40% of Petrozamora, a joint venture with PDVSA, Reuters stated on March 14. The bank has confirmed the fact of leaving the joint venture without specifying any details. Petrozamora was founded in 2012 to develop oil fields in Venezuela. In 2013, Gazprombank, GPB, Petrozamora, and PDVSA agreed to allocate up to $1 billion for the development of the joint venture. Now, Gazprombank does not have any investment projects in Venezuela. Rosneft has become the only Russian company with large assets there, Kommersant noted. According to Reuters, the Russian giant oil company has lost about $9 billion on its investments in Venezuela since 2010. Rosneft is running five projects in Venezuela while producing a small share of its total oil production. The crisis in Venezuela involves the risk that the country will not be able to pay its debts. Back in 2011, more than 66% of the Neftegaz.Ru survey respondents approved the participation of Russian companies in the development of the Orinoco fields. However, right now, this heavy and highly viscous oil that the fields have produced remains unsold, as buyers have become hesitant toward purchasing sanctioned oil. Over 8 billion barrels of crude oil are now stored in offshore oil tankers, as the onshore oil terminals are full. If the situation is not improved, we can expect Russian companies in Venezuela to report serious problems. Moreover, these problems are already there. The excess of Venezuela’s oil supply has slowed down work on the Orinoco Belt, including projects for modernizing production facilities – projects which Rosneft is conducting in a joint venture with PDVSA. Rosneft has a share in five joint ventures: PetroVictoria, Petromiranda, Petromonagas, Boqueron, and Petroperija. The international rating agency Moody’s said the US sanctions against PDVSA would limit the financial and operational flexibility of Rosneft’s joint ventures in Venezuela since PDVSA owns more than 50% of each one of them. As is known, Washington has posed large-scale sanctions against PDVSA designed to limit the export of Venezuelan oil and to force President Nicholas Maduro to resign. Russia is among the countries that continue to support Maduro. Over the past few years, the Russian Federation has become Venezuela’s last resort in terms of lenders. According to Reuters estimates, the Russian government and state-owned Rosneft have lent Venezuela at least $17 billion since 2006. Dmitry Peskov, Spokesman for the Russian President, said on March 1 that no negotiations on new financial support for Venezuela were being conducted at the presidential level, but Russia continued to maintain contacts with its partners in Venezuela. “We are interested in continuing cooperation with Venezuela — especially as a number of our companies are running fairly large projects there. We hope that these projects have good potential, that they will have the potential for expansion, and of course, we wish the Venezuelan partners to cope with the difficulties they are facing, both political and economic ones, as soon as possible,” Peskov told reporters.
  32. 1 point
    Beginning of the New Year 2019 saw the Chinese President Xi Jinping belligerence towards Taiwan, officially the Republic of China (RoC). President Xi Jinping proclaimed that Taiwan unification must be the ultimate goal of any discourse regarding its future and laid out unyielding position that use of force is not ruled out should Taipei asserts full independence. This is not the first time that China openly declared its intention on Taiwan. In December 1995, Chinese officials asked US Assistant Secretary of State Joseph Nye directly what would the US do if China attacked Taiwan. Nye’s response was: “We don’t know and you don’t know. It would depend upon circumstances.” Beijing considers Taiwan( Formosa) as a breakaway province. RoC is self-governed but it has never formally announced independence from Mainland. The Taiwan’s President Tsai Ing-wen had made it clear that the island nation would never consider reunification with China under the terms offered by Beijing. United States lent its weight behind Taipei by sending guided-missile destroyer USS McCampbell and the fleet replenishment oiler USNS Walter S.Diehl through Taiwan Strait. It has further heightened tensions between the US and China. Meanwhile, US Pacific Fleet spokesperson Lieutenant Commander Tim Gorman told Cable News Network that it was a “routine Taiwan Strait Transit” under international law. On the other hand,Taiwan’s navy showcased its latest long-range surveillance drone as a push to counter China’s increasingly muscular rhetoric. Both these moves are symbolic in nature yet an attempt was made to convey to Beijing that Taiwan will not become Tibet of East Asia. Situated in the West Pacific between Japan and Phillippines, Taiwan is of strategic importance both for China and US. Taiwan (Formosa) lies at the edge of South China Sea shipping lanes. On the eve of Japan’s surrender in the World War-II, the State Department of US published a note on Taiwan which remarked: Strategic factors greatly influence the problem of Formosa. With the exception of Singapore no location in the Far East occupies such a controlling position. Regional powers like Japan in World War-II used Taiwan as a base both for defensive and offensive startegic purposes. It was a very important supply base for Japanese armies in South East Asia during their operations in Second World War. The US Navy commented in 1944 that: The island of Taiwan dominates the China coast and all coastwise shipping between Japan and South Eastern Asia. Its airfields and ports supported the movement of Japanese troops and supplies throughout the Southern theatres of action. For China, Taiwan is not just a matter of territorial sovereignty as it claims but is important from its security point of view. The control of Taiwan would help China’s operations in South China Sea. It can then more effectively assert and settle its territorial claims against Phillippines,Brunei,Vietnam etc. If Beijing succeeds in the unification of Taiwan then it will be able to use its deep water ports for its submarines to venture into Pacific Ocean. This will project China’s power in Pacific and will be a challenge to US naval assests. Beijing knows that if an external power occupies or make a base in Taiwan then it can cut-off China’s trade lines and a naval blockade could be a catastrophe for China’s rise as an economic and military power. When two elephants fight, it is the grass that is trampled. But some 23 million Taiwanese people do not want their fate to be that of grass. Taiwan’s loss of the China seat at the United Nations in 1971 was internationally the culmination of a slow erosion in support for the RoC. History reminds us of the destiny of Tibetans at a time when China was not so powerful economically and militarily. The question is can Taiwan defend itself against China if it really uses the force as claimed by Chinese President Xi Jinping? Today, the Chinese expansion of naval assets and capabilities in South China Sea will definitely alter the dynamics of war should it occur between People’s Republic of China and RoC. With UK trying to overcome Brexit imbroglio and France trying to put its own house in order, US may not get the full support of allies against China over Taiwan. Taiwan is not just a symbol of democracy at the gate of authoritarian Communist China which should be morally supported and militarily protected by Western world but its geographical location has made it a vital piece on global chess board of politics which is being played between US and China. The answer to the future of Taiwan lies in the womb of time but the clock is ticking for Taipei as China flexes its economic, diplomatic and military muscle.
  33. 1 point
    Former Chinese Communist Party leader Deng Xiaoping presented his “Cat Theory” to introduce a capitalist market economy for Mainland China. As per the theory “It doesn’t matter if a cat is black or white;as long as it catches mice,it’s a good cat.” The “Cat Theory” which he put forth was to convince policy makers for the radical shift in economic policies. “Cat Theory” is also relevant if one looks at the way China is pursuing its geo-political interests using its economic clout. There is one more distinct quality about the cat which makes it a stealth killer. When the cat advances towards its prey it hides its claws. Kenya is latest in a series of nations to feel the claws of Chinese debt. Latest report attributed to Auditor General suggests that strategic Mombasa Port could land up in the hands of Chinese Bank, EXIM Bank if Kenya fails to repay the loan amount. Though, the Audtior General Edward Ouko has issued a denial. But it does not mean that Mombasa port will not become Chinese one day as we have seen the example of how Sri Lanka handed over Hambantota port to China to pay off its debt. To sustain higher economic growth China needs unfettered access to raw materials for its factories and a market to export its finished goods. At a time when China is facing pressure from United States of America over trade,Africa offers tremendous opportunities for Chinese economy. Infrastructure investment in Africa reflects China’s decades-old strategy of using soft power. More recent investments in Kenya and Ethiopia represent an extension of the Chinese President Xi Jinping’s Belt and Road Initiative (BRI). BRI is a trillion-dollar investment strategy which focusses on developing transportation sector and infrastructure, particularly in Eurasia region but also in East Africa. The amount of Chinese loans to Kenya has grown tenfold in the five years since China unveiled its Belt and Road Initiative. In May 2014, Kenya and China inked Sh 327 billion railway line agreement. According to the terms of the agreement,China had to finance 85 per cent of the total cost through Export and Import (EXIM) Bank while Kenya had to bear the remaining 15 per cent of the projects’ cost. The rail line pened in May-2017. China financed Nairobi-Mombasa Railway link is touted as the biggest infrastructure project in the history of independent Kenya and is a part of Kenya Railways Corporation’s new Standard gauge railway (SGR) line. The Mombasa-Nairobi rail connectivity will cut down travel time by half. It will benefit passengers and cargo transportation. The SGR project is expected to link Mombasa to Rwanda with a branch line to Juba in South Sudan in future. This Mombasa-Nairobi railway line will give China access to South Sudan in near future. The oil production of South Sudan is dominated by Chinese oil majors. China National Petroloeum Corporation (CNPC) pumps nearly all of South Sudan’s oil production. After cessation in 2011,both Sudan and South-Sudan are now mutually dependent on oil revenues for their economic survival. South Sudan is landlocked and has 75 percent of the oil reserves. The oil from the fields of South Sudan is transported through 1600 kms pipeline to reach export terminals in Port Sudan and then it reaches to refiners in China. On August 30th 2018 South Sudanese President Salva Kiir Mayardit paid a visit to China National Petroleum Corporation Headquarters and had talks with Wang Yilin about further deepening oil and gas cooperation. A memorandum was also signed after talks to boost existing production and consider acquisitions of new acreage. The high profile visit signifies the closeness of South Sudan and China. Mombasa-Nairobi link when it will be joined with Juba in South Sudan through branch line then it will open an alternate route for Chinese companies and South-Sudan for trade and export of Oil. Moreover, cost is critical in the production of goods and to remain competitive in the globalized economy. Fuel is one such factor that has cascading effect on the entire supply chain right from manufacturing to retail. In September, 2018 Sudan Ministry of Petroleum signed an agreement with three oil companies operating in Sudan and South Sudan to pay a transit fees of $14 per barrel. One of the companies that signed the agreement is China National Petroleum Corporation. In addition to it, if oil is shipped through Sudan, Chinese companies will also have to pay fees for marine terminal usage. Therefore, opening up of an alternate supply route using Mombasa port and railway link will give an edge to China. Therefore, Mombasa is a strategically important port for China as it will be a gateway to South Sudan.
  34. 1 point
    This interactive presentation contains the latest oil & gas production data from all 17,997 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through September. Visit ShaleProfile blog to explore the full interactive dashboards Last week I planned a post on the Permian, but noticed that September data for New Mexico was still quite incomplete (100 kbo/d, or ~20% of production has not yet been reported). Unfortunately, it still is, but I did not want to delay this update any further. The graph above shows clearly the astonishing rise in oil production in the Permian in the past 2 years, as oil production from horizontal wells more than doubled to over 2.8 million bo/d in September (which will be visible after upcoming revisions). More than 1.5 million bo/d in September came from ~3,200 horizontal wells that started in 2018. In New Mexico a single operator seems to be responsible for most of the missing production in September: EOG, which is also the largest producer in this state. After you exclude EOG from the graph (using the ‘Operator’ selection), you will see that the apparent drop in September has almost disappeared. In the ‘Well quality’ tab you’ll find the production profiles for all these wells. By default they are grouped and averaged by the year in which they started production. With this setting, you’ll find in the bottom plot that well productivity improved significantly in the past 5 years. Wells that started in 2013 recovered 77 thousand barrels of oil in the first 2 years, on average, while this more than doubled to 183 thousand barrels of oil for wells that started 3 years later. Since 2016 the pace of improvements appears to have slowed down, as you’ll see by following the 2017/2018 curves. The final tab shows the performance of the leading operators. You’ll see the effects of the acquisition of RSP Permian by Concho, and the missing production for EOG in New Mexico in September. 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 year in which production started. This kind of plot doesn’t assume any kind of decline behavior, but a harmonic decline (b factor of 1), will show up as a straight line with the given settings. The 2,215 horizontal wells that started in 2016 (light brown curve) are on track to recover each around 200 thousand barrels of oil, once they have declined to an average production rate of 100 bo/d. Newer wells appear to be on track to do slightly better than that. Tomorrow we will have a new show at enelyst (live chat combined with images), where we will take a closer look at the latest Permian data. The show will be available here in the enelyst ShaleProfile Briefings channel. If you are not an enelyst member yet, you can sign up for free at enelyst.com. Early next week we will have a post 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/2LUFMoY Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  35. 1 point
    The full article is here-> https://www.daily-times.com/story/money/industries/oil-gas/2018/12/18/delaware-basin-news-reveals-public-misunderstanding-oil-industry-economics/2282224002/ "This writer has warned that world oil demand is sluggish and imprecise with only references to legacy guesswork that the developing world plus China demand will support prices long term or forever. Yet, world oil consumption has increased only 5 percent in the last 10 years. OPEC, with Saudi Arabia as its leader, has expired as the world administrator of the price of crude oil. At its December meeting in Austria, Qatar quit after nearly 70 years and announced concentration in LNG production and world export as the existing market leader. OPEC emerged with a serious factional split between OPEC original and OPEC with Russia. There would have been no agreement without Russia and its old Russian Federation members as producers. Moscow is the new world oil price-setter indirectly while OPEC Original becomes a collaborator in cartel for now. Simply put, Saudi Arabia no longer is the “residual supplier” alone. The production roll-back of 1.2 barrels per day by both “OPEC” is not enough for “balance” supply and demand for world crude oil. It is being tested daily by commodity traders. In a briefing to New Mexico independent and small producers before the meeting in Austria, this writer warned that 1.7 million b/d was needed for balancing stabilization. Without that size of a production and export reduction, the average price of WTI oil in 2019 will average $50 per barrel. Nearing 12 million b/d and over the Permian producers voluntarily will be required by this price to revise capital spending and place production into DUC (non-completions) and storage. There is doubt that the export of tight or shale oil would continue if the Brent price falls lower and loses its premium over WTI. A net cutback of Permian between 500,000 to 750,00 b/d should be a non-OPEC response to an oil glut even more serious than 2014. Saudi Arabia is untouched as an American strategic ally in confronting Iran in the Middle East as a hegemonic threat."
  36. 1 point
    This interactive presentation contains the latest oil & gas production data from 96,273 horizontal wells in 10 US states, through August. Visit ShaleProfile blog to explore the full interactive dashboards Cumulative oil and gas production from these wells reached 9.5 Gbo and 104 Tcf. Ohio and West Virginia are deselected in most dashboards, as they have a greater reporting lag. Oil production from horizontal wells in these states grew by almost 2 million bo/d in the 2 years through August. This growth rate was similar as in the boom years of 2013-14. The Permian was responsible for most of this gain, which you’ll see if you show the production data by ‘Basin’ (using the ‘Show production by’ selection). Natural gas production has been setting new records as well during those 2 years and was above 47 Bcf/d in the basins we cover. The steady increases in well productivity are shown in the ‘Well status’ tab, where all the oily basins are preselected. The horizontal wells that started in 2018 are so far closely tracking the performance of the ones from 2017. In the final tab you will find the production histories and location of the largest shale operators. We’ve made a change in this dashboard; now the operators are ranked by their total production in the past 12 months (and not by their total historical production). This makes especially a big difference in the Permian, where several operators have recently increased production at a rapid rate. 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. Since about 2010 wells have been tracking ever larger ultimate recoveries. The ~1,300 horizontal wells that started in Q4 of 2016 appear so far among the best performers; they have recovered on average 160 thousand barrels of oil and are now at a production rate of ~110 bo/d (from a peak rate of 570 bo/d). These are of course averages, and there are major differences between basins, operators and formations. Major factors behind the changes in well performance are the increases in lateral lengths and the larger frac jobs. In our online analytics service, it is possible to normalize for these factors. Feel free to request a demo, in which we will discuss your interests, or 10-day trial. We sometimes get the question about what we do with wells when they stop producing. In these cases we keep adding 0 production records, to make sure that wells don’t suddenly drop out of the equations, which would lead to a survivorship bias. You can verify this, as the exact well count is shown in the tooltips that appear above the production profiles (this is also represented in the thickness of the curves). Tomorrow at 9:30am EST we will again host a show at enelyst, in which we’ll take a closer look at the Niobrara basin. Join us in the ShaleProfile channel. Early next week I will have a new post on North Dakota, which will release October production data by the end of this week. 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/2EbfM6U Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  37. 1 point
    There has been lots of rift between the Saudis and Qatar, for quite some time. Saudi Arabia is accusing Qatar of financing terrorism. The Saudis are trying to give Qatar lots of problems, and Qatar fought back, by damaging OPEC and leaving. This will be the beginning of the unraveling of OPEC as I predict more nations to leave OPEC. This will also give OPEC less control of oil prices. Therefore any production cuts from OPEC in the future could soon become meaningless.
  38. 1 point
    This interactive presentation contains the latest oil & gas production data from all 21,540 horizontal wells in the Eagle Ford region, that started producing since 2008, through August. Visit ShaleProfile blog to explore the full interactive dashboards Since the low point two years ago, oil production in the Eagle Ford has kept growing. I expect that after revisions August production will eventually come in at around 1.3 million bo/d (~100 kbo/d higher than shown now). Natural gas production follows a very similar pattern. If you switch ‘Product’ to gas, you’ll find that in 2018 total gas production was just below 6 Bcf/d. The underlying decline is clearly visible in this graph; you can see that the horizontal wells from before 2015 peaked at over 1.6 million bo/d in Dec 2014, and that the same group produced just 0.3 million bo/d in August. The main reason for the recent increase in oil production is not higher well productivity, as this has not significantly changed in the past 2 years (see ‘Well quality’). But about 5 wells have been completed every day in 2017 & 2018, on average, versus just 4 in 2016. 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. Declines here are steeper than in the Permian or the Bakken, and that means that a greater part of the oil EUR is recovered in the first year on production (about half). I wanted to have a closer look at the well performance of the two leading operators, EOG & ConocoPhillips. Here you find this comparison, for horizontal wells that started between 2014 & 2017, taken from our ShaleProfile Analytics service. For each operator & year combination, you can see the performance curve on the right plot. Striking here is the difference in well behavior. EOGs wells decline in a fairly straight line from the peak, while the wells operated by ConocoPhillips are able to maintain a higher flow rate for several months, before they display a steepening of the decline. Early next week we will have a post on the Permian again. 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/2Q2eRwV Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  39. 1 point
    This interactive presentation contains the latest gas (and a little oil) production data, from all 8,512 horizontal wells in Pennsylvania that started producing since 2010, through September. Visit ShaleProfile blog to explore the full interactive dashboards Gas production from horizontal wells came in higher again in September, at 17.4 Bcf/d. Output has grown by about 10% in the 4 preceding months, driven mostly by an increase in well completions; In both August and September, 107 wells started production, the highest since the end of 2014. This increase in completion activity didn’t have a negative effect so far on well productivity. In the ‘Well quality’ tab you’ll find the production profiles for all these wells, averaged by the year in which they started. Group the wells by the quarter in which they started (using the ‘Show wells by selection’), and you’ll see that the best initial performance came from the wells that started in Q3 this year, at over 13 MMcf/d. Of the 5 leading operators, Cabot stood out as it increased gas production by 18% in just 2 months (see the final tab). 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 quarter. Well design has changed significantly over the years; in 2012 about 4 million pounds of proppant was used per completion, on average, while this has recently increased to over 18 million pounds. The plot clearly shows how this has had a positive impact on well productivity. Early next week I will have a new update on the Niobrara. If you missed our live chat last Tuesday with John Sodergreen and Het Shah, about the Permian Basin, you can still read back our discussion here in the enelyst ShaleProfile Briefings channel. Next week Tuesday, at 10:30 am (EST), we’ll take a closer look at gas production in Pennsylvania, and there is enough time to ask questions. If you are not an enelyst member yet, you can sign up for free at www.enelyst.com, using the code: “Shale18” Happy Thanksgiving! 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/2DVzQLg Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  40. 1 point
    Electric and Hydrogen Vehicles - the crucial difference between a Media Interview and a Presentation? 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. Contact: rogercrisp@gmx.co.uk / rogercrisp.com Speaker & Conference Presenter on Energy - Climate Change / Media Interview Advisor & Trainer
  41. 1 point
    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
  42. 1 point
    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.
  43. 1 point
    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!
  44. 1 point
    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
  45. 1 point
    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.
  46. 1 point
    These interactive presentations contains the latest oil & gas production data from all 13,628 horizontal wells in North Dakota through July, that started production since 2005. July oil production in North Dakota came in at 1,269 kbo/d, after a month-on-month rise of 3.4%, setting a new record for the state. Visit ShaleProfile blog to use and explore interactive dashboards An important factor behind this jump were the 141 new wells that started production, the highest number in 3 years. Completion activity was higher in the first 7 months of this year compared with last year (649 vs 525 wells). Several operators set new production records, including Continental Resources and ConocoPhillips, which just surpassed Whiting as the 2nd largest producer in this area (see ‘Top operators’). 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. It shows that so far the wells that started in Q3 2017 had the best start; after 11 months they recovered on average 169 thousand barrels of oil. Although lateral lengths haven’t changed much in North Dakota, proppant loadings have doubled in the past 4 years, to close to 1,000 lb/ft. In our online analytics service, these trends can be easily analyzed by play and operator. Request a free trial here! 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/2MIA8oV Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  47. 1 point
    This interactive presentation contains the latest oil & gas production data through May, from 91,810 horizontal wells in 10 US states. Cumulative oil and gas production from these wells reached 8.9 Gbo and 98.6 Tcf. Their total oil production was close to 5.5 million bo/d in May, or more than half of total US oil supply, while gas production topped 50 Bcf/d. If you group this total oil production by ‘production level’, using the ‘Show production by’ selection, you will find that in May ~4 million bo/d came from just ~12 thousand wells that each produced over 100 bo/d. All other wells combined (~80k) produced just the remaining 1.5 million bo/d, although that also includes gas wells. The ‘Well status’ tab shows the status of all these wells over time. Looking at the ‘First flow’ status, or wells that have just started production, reveals that since the 2nd half of 2017 between 800 and 1,000 new horizontal wells were brought into production each month (taking into account upcoming revisions), versus less than 600 in 2016. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between cumulative production, and production rates, over time. The oil basins are preselected, and wells are grouped by the year in which production started. As the curves show, well productivity improved each year since 2012. The ~5.3 thousand horizontal wells that started in 2016 recovered each on average 134 thousand barrels of oil in the first 18 months, and they are on a trajectory to recover one more time that amount, before declining to level of ~20 bo/d. Early next week I will have a new post on North Dakota. We are still handing out free trial accounts for our ShaleProfile Analytics service, which covers more dashboards and up-to-date data. If you’re interested, you can apply for a 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/2CJiam9 Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  48. 1 point
    This interactive presentation contains the latest gas (and a little oil) production data through June, from all 8,236 horizontal wells in Pennsylvania that started producing since 2010. Gas production from these wells has hovered around a level of 16 Bcf/d in the first half of 2018. During this period, 351 horizontal wells started production versus 299 in the year before. In the ‘Well quality’ tab, the production profiles of all these wells can be found, averaged by the year in which they started. If you group them by county instead (using the ‘Show wells by’ selection), you will see in the bottom graph that wells in 3 counties in the north east of Pennsylvania have the best average performance: Wyoming, Susquehanna and Sullivan. The final tab (‘Top operators’) shows the output and location of the 5 leading operators in this area; Chesapeake, Cabot, Range Resources, EQT and Southwestern Energy. It also reveals that Chesapeake appears to follow a strategy to ramp up gas production before each winter, before letting it decline again. 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 quarter. It shows that well productivity has steadily risen over time, and that there was a significant jump in performance in Q4 2016. Since then, the improvements have leveled off. Later this week I plan to have a new update on the Permian, followed by one on the Eagle Ford early next 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/2NmJ44d Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  49. 1 point
    This interactive presentation contains the latest oil & gas production data through May from all 13,545 horizontal wells in North Dakota that started production since 2005. May oil production in North Dakota came in at 1,245 kbo/d, after a month-on-month increase of 1.6%. This pushed production higher than the previous all-time high in December 2014. Recent wells are closely tracking the performance of the wells that started in 2017 (see the bottom graph in the ‘Well quality’ tab), on average. In May 109 new wells started flowing, the highest since September 2015 (see the ‘first flow’ status in the ‘Well status’ overview). In the final tab (‘Top operators’) you’ll find that ConocoPhillips has grown production the most in the past 1.5 year (percentage wise), to almost 100 thousand barrels of oil per day, making it the 3rd largest producer in this state, behind Continental Resources and Whiting. 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 year in which production started. More wells started in 2017 than in 2016 (970 vs 724), and their initial performance was also substantially higher, as the plot above shows. They recovered on average almost 100 thousand barrels of oil in the first 6 months on production, a level that took almost 12 months for wells that started 2 years earlier. If you group the wells by the quarter in which they started (using the ‘Show wells by’ selection), you’ll see that the initial performance of the wells that started in the 3rd quarter last year was especially high, with close to 150 thousand barrels in the first 9 months. Although not so profitable, associated gas production rose even more, which becomes visible if you change the ‘Product’ selection to ‘Gas’. This is displayed in more depth in the 9th tab (‘Gas oil ratio’), where you can see in the bottom graph that this ratio has risen almost uninterruptedly in the past decade. As mentioned in my last posts, next week we will be present at the URTeC in Houston, so if you like to know more about our upcoming analytics services, I’ll be more than happy to show you our vision and give you a demo. We’ll start posting again in the week after. Production data is subject to revisions.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 https://shaleprofile.com/index.php/2018/07/19/north-dakota-update-through-may-2018 Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  50. 1 point
    This interactive presentation contains the latest gas (and a little oil) production data through April, from all 8,137 horizontal wells in Pennsylvania that started producing since 2010. After the significant jump in output at the end of last year, gas production has remained fairly steady at a level around 16 Bcf/d, and just like in the past 3 years there was a small dip in May. Only 252 horizontal wells started production in Pennsylvania in the first 5 months of this year, which was the lowest number since 2010. The initial performance of these new wells is similar to the ones that started in 2017, which were the best to date (see the bottom graph in the ‘Well quality’ tab). Cabot has taken over the lead from Chesapeake as the largest gas operator in this area, as you’ll see in the ‘Top operators’ tab. The top 5 operators shown there operate more than half of total unconventional gas production in this state. 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. The ~600 wells that started in 2010 have now recovered on average 3.3 Bcf, and are now at a flow rate of 600 Mcf/d. By extrapolating the 2014 curve, you’ll see that these wells are likely to recover about double this number by the time they’ve declined to this flow rate. In the 6th tab (‘Productivity map’), you’ll find which areas in Pennsylvania are the most productive, as measured by the average cumulative gas production in the first 2 years. Last week we launched the ShaleProfile Analytics portal at the URTeC, in which the performance of more than 100 thousand horizontal wells in the US can be analyzed in even more detail than here on the blog. This portal also allows you to see the detailed location of all these wells, and analyze how changing lateral lengths and proppant loadings has affected well performance, among many other capabilities. We’ll have soon more information about this on our webpage. If you’re interested you can already find some brief information, and the possibility to request a trial license, in this link. Next week I plan to have new updates on the Permian and the Eagle Ford. 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 https://shaleprofile.com/index.php/2018/08/02/marcellus-pa-update-through-may-2018/ Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile