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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
    My Topic on China https://docs.google.com/document/d/1Wb2YoQGpSWTz32ljsiA_ey6FLVqc2Dpe7Fnpiqn9lBs/edit# Recent Stories https://www.theepochtimes.com/sen-ted-cruz-on-the-strategy-to-defeat-chinas-communist-party_3506709.html Sen. Ted Cruz on the Strategy to ‘Defeat’ China’s Communist Party BY JAN JEKIELEK September 19, 2020 Updated: September 21, 2020
  18. 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.
  19. 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
  20. 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.
  21. 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
  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
    USDCAD LONG at WEEKLY DEMAND
  24. 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
  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
    Moscow, Russia, May 13, 2019. As the situation with the quality of oil transported from Russia to Europe via the Druzhba oil pipeline is gradually improved, financial issues have come to the fore. Or, more precisely, the amount this accident will cost Russia has become of great concern. On May 11, 2019, President of Belarus A. Lukashenko reported that Belarus had lost an enormous amount of money; in particular, it had not received any profit, currency earnings, or transit. A. Lukashenko said the estimated loss of hundreds of millions of dollars was not far from the truth. Vedomosti cites the possible amount of losses on May 13, 2019, as being in the range of $271.3 million to $435.3 million. The main components of the damage are the loss of transit profits, the loss of oil refining profits, the cost of cleaning, and, possibly, the replacement and repair of damaged equipment. Loss of Oil Transit Profits In 2018, the transit fee for 1 ton of Russian oil via Belarus in the direction of Poland, Germany, and Ukraine was US $0.84/100 km. The length of the Druzhba oil pipeline in the territory of Belarus is 1900 km (i.e., the payment for the entire route is US $15.96/ton). Different sources have discussed different oil transit volumes for 2018: the volume is about 48.9 million tons according to Transneft and 58.8 million tons according to Gomeltransneft Druzhba. That is, Gomeltransneft Druzhba’s profits could amount to $780.4 million to $938.5 million for transit in 2018. If the tariff and the volume of transit remain the same, Gomeltransneft Druzhba’s lost profits for 14 days could range from $29 million to $35 million. The Russian Ministry of Energy expects the situation with the quality of oil in the Druzhba pipeline to normalize in the 2nd half of May 2019. In this case, normalization entails cleaning one run of the pipeline in each of the main export destinations. As a result, the pipeline throughput capacity will decrease. According to Gomeltransneft Druzhba estimates, the throughput capacity of the Druzhba pipeline may be reduced to 40 million tons/year after the accident. As a result, the company will transit 8.9 million to 18.8 million fewer tons of oil in 2019 than in 2018 (equal to a loss of $142 million to $300 million). Loss of Oil Refining Profits The poor quality of oil has forced the Mozyr Oil Refinery and the Naftan Oil Refinery to reduce their production of oil products. According to Belneftekhim, on May 11, 2019, the Mozyr Oil Refinery started to refine oil the quality of which meets the standard. By that time, Naftan was still suffering from a reduced load because the oil transit via the uncontaminated Surgut–Polotsk pipeline is insufficient for the optimal load of the plant. The damage amounted to US $100 million of lost profits. Losses Due to Equipment Damage The Mozyr Oil Refinery almost immediately claimed that equipment had been damaged. The management of the company said the equipment was damaged due to the high content of organochlorine — which has a high corrosive activity — in the incoming oil. Failures of a number of heat-exchange tubes of the HK-105 air cooler consisting of 6 sections were revealed at unit LK6U No. 2 (the primary distillation unit) of section C-100 on April 20, 2019. According to experts’ estimates, such tubes cost 3.5 million rubles each (a total of US $323 thousand). An independent expert investigation with the involvement of the Belarusian and Russian parties is necessary for an objective assessment of the damage to the equipment. Is the Damage Recoverable? The amount is staggering, and the issue of compensation will require serious discussion. However, not everything is as critical as it seems at first glance. Interfax, citing its sources, said that most of Belarus’s losses from contaminated oil in the Druzhba pipeline at this stage are not irrecoverable. The lost transit and under-utilization of the refinery will be rectified as the delivery schedule gets caught up with by the end of 2019. Possible damage to the refinery equipment would be the most serious damage, but it will take time to assess the situation. Moreover, the issue of the poisonous oil which is still on the territory of Belarus remains unresolved. Background What Happened On April 19, 2019, Belneftekhim complained about a deterioration in the quality of the Russian Urals supplied to Belarusian refineries via the Druzhba oil pipeline. Almost immediately, it became clear that this referred to the pollution of oil with organochlorine, which is a chlorine compound released during distillation. The polluted oil has damaged the equipment of the Mozyr Oil Refinery in Belarus. Belarus had to stop the export of light oil products to Poland, Ukraine, and the Baltic countries; Europe had to stop importing oil from the Druzhba. Oil contamination in the Druzhba pipeline, which accounts for up to 8% of the EU’s annual imports, has reached the level of interstate relations between Russia and Belarus and has raised the price of oil throughout the world. As of April 13, the main channel for oil export from Russia to Poland and Germany is still completely paralyzed, but the first success of cleaning the Ukraine-Hungary minor southern string has been achieved. What is the Druzhba? The Druzhba oil pipeline, built in the 1960s with the support of the Volga region oil fields, was one of the main integration projects of the USSR with the countries of the Council for Mutual Economic Assistance. The Druzhba remains an important supplier of oil to Europe; refineries in Belarus, Poland, Hungary, Slovakia, Germany, and the Czech Republic still depend heavily on this pipeline. The Druzhba transits about 65 million tons of oil per year, which is a quarter of Russia’s total exports. About one-third of this oil is refined in Belarus, and almost all the remainder is received by the EU.
  28. 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.
  29. 1 point
    These interactive presentations contain the latest oil & gas production data from all 14,469 horizontal wells in North Dakota that started production since 2005, through January. Visit ShaleProfile blog to explore the full interactive dashboard January oil production in North Dakota was unchanged from the month before, at 1.4 million barrels of oil per day. In January, which is typically a slow month, just 85 wells started production. The growth in natural gas production has been steeper in the past few years. Compared with January 2015, natural gas production rose by 88%, versus 18% for oil. The reason for this is that almost all wells experience a rising gas oil ratio, and even stronger for newer wells. In the ‘Well quality’ tab, you’ll find the production profiles for all these wells. After several years of improving initial well productivity, the 2018 vintage eked out another small gain. All 5 leading operators in North Dakota started the year at a higher production level than a year earlier (“Top operators”). Continental Resources was the first operator in the history of the state to reach 200 thousand barrels of oil production capacity in January. It doubled its output in the past 2 years. From our analytics service (Professional), we can see how Continental Resources has changed its completion practices in the last couple of years: In this dashboard we can see that Continental Resources did not change the length of its laterals by much since 2013 (yellow curve), but it did almost quadruple the amount of proppant used, from 3 million pounds per completion in 2013, to 12 million pounds in 2017/2018 (shown by the pink curve). The impact that this had on the amount of oil recovered in the first 12 months is shown in the plots on the right side; the bottom plot shows the same information, but now normalized by lateral length (1,000 feet). 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. The almost 1,800 horizontal wells that started in 2012 have now recovered just above 200 thousand barrels, and are now producing at a rate of 40 bo/d, on average. The 971 wells that started 5 years later (2017) are, with an average recovery of 175 thousand barrels of oil after 14 months on production, not far behind, and they are still operating at a rate of 227 bo/d. Early next week we will have an update on gas production in Pennsylvania, which just released January production data as well (already available in our subscription services!). It just set another record at over 18 Bcf/d. 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 40 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/2ueHidA Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  30. 1 point
    These interactive presentations contain the latest oil & gas production data from all 19,047 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through November. Visit ShaleProfile blog to explore the full interactive dashboard November oil production came in above 3 million bo/d (after revisions), at a y-o-y growth rate of 1 million bo/d. More than 4,200 horizontal wells were completed in 2018 through November, double the number in the same period in 2016. Average well productivity has only increased slightly since 2016, after big gains in the years before, as the ‘Well quality’ tab shows. The 2 largest producers, Pioneer Natural Resources & Concho Resources, are now above 250 thousand bo/d of operated capacity (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 year in which production started. If you extrapolate these curves, you’ll find that recent wells (2016/2017) are on a path to recover on average about 300 thousand barrels of oil, before their production rate has fallen to 40 bo/d. Associated gas production is high in the Permian, at well over 9 Bcf/d. If you switch ‘Product’ to gas, you can find the average gas production for the same wells. Newer wells are on average likely to recover 1.5 Bcf of natural gas or more. Today (Tuesday) at noon (EST) we will also present an update on the Permian and the Eagle Ford on enelyst, where we will share our insights in these basins based on the latest data. Last month many of you subscribed to our analytics service, which offers access to more dashboards, well data, and more recent production data. Thank you! The cheapest subscription version, Analyst, costs just $52/month per user, and you can try it for 1 month for only $19. With this, you will experience some of the analytical power of ShaleProfile Analytics. Later this week we will have a post on the Eagle Ford. 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/2HgILaR Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  31. 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.
  32. 1 point
    The recent market volatility has left investors and capital seekers seeking he same consensus: where does it end and what's the upside? The age old question continues to perplex both parties. I'm taking the position from both sides.. first as a former exploration company President who had sought capital from the banks, from P/E firms, mezzanine debt and from the public markets and secondly as a capital provider. We currently manage substantial amounts of capital that are looking to deploy into the energy sector, so being on both sides in a past and current life, I speak from experience. Oil and gas companies that seek us out for capital come in a number of flavors and sizes. Typically, they are smaller entities, or juniors. This is our financing niche. Their needs are the usual: drill PUDs, re-work, acquire non-cores, get a leg up on OPEX and generally seek growth in fractious times. In nearly every case, the banks are exhausted as much as the juniors are. These companies are far too small for the P/E firms to get involved and the old 'Third for a quarter' deal won't cut it. What to do? As a capital provider, we seek to obviously entreat the best companies we can to provide this dearly needed money. Some have said that the smaller deals that come in to any facility seeking capital are the deals no one else will touch. We disagree. The old saying, "Oil and gas doesn't care who owns it,' serves a point. Economies of scale are persistent relative to size. Nearly all the companies we review are sitting on oil, and what better place to produce from than an existing field? Have the production and a good development plan? Are these good oil people with a solid history of exploration and exploitation? We take these into account, among other things as we review and allocate due diligence resources to determine if the underpinnings are there and there's sufficient existing PDPs to support the capital raise over a term. A word about the raise.. it's non-recourse, not a loan, off balance sheet, no equity take out and there's no back-in after payout. Oil companies seek a better, more efficient way to utilize and pay back capital and there is a better way than the old tried and perhaps not so true way... In these times, we feel a floor has been reached and tested market wise. Wise firms can access wise money now, versus looking for it when the recent 30% drop has been recovered and capital costs and service costs will likely erode portions of this gain. Companies can't afford to hand wring now... it's time to set up for the future and plan capex budgets now.
  33. 1 point
    This interactive presentation contains the latest gas (and a little oil) production data, from all 8,567 horizontal wells in Pennsylvania that started producing since 2010, through October. Visit ShaleProfile blog to explore the full interactive dashboards New production records have been set in the 2nd half of every year since 2010, and 2018 was no different. Gas production in October from horizontal wells came in at 17.6 Bcf/d, about 20% higher than October 2017 (14.1 Bcf/d). The 687 wells that started production in the first 10 months of 2018 already contributed more than 1/3rd of total gas production in October (6 Bcf/d). Well productivity made a big gain in 2017 (see ‘Well quality’ tab), but it did not rise much further in 2018, based on preliminary data. Newer wells recover on average more than 4 Bcf in the first 2 years on production, compared with 3 Bcf from wells that started in 2016. All major operators increased production in 2018, except Chesapeake (‘Top operators’). 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 came online in a certain year. The improved performance over the past years is clearly visible here. If you change the ‘Show wells by’ selection to ‘quarter’, you can see more recent and granular data. It will also reveal that newer wells peak at a level of over 12,000 Mcf/d, more than three times the rate of the wells that started in 2012. The 2nd tab (‘Cumulative production ranking’), ranks all counties in Pennsylvania by cumulative gas production. If you change the ranking to ‘Well’, you’ll see the cumulative production for each of those 8,500+ wells. The most productive one is above 20 Bcf. Later this week we will have a new post on the Permian. We wish you all a Happy New Year! 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/2s048ED Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  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
    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
  38. 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
  39. 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.
  40. 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
  41. 1 point
    The Baker Hughes US oil rig count – a proxy for health and optimism in the overall upstream sector – has just reached a 31-month high to 1067 rigs, though nowhere near the all-time high of 1609 back in July 2014. This recent development is not surprising; crude prices have been trending upwards and reached a new 24-month peak last week as well. Looking at the breakout data, it is possible that some of the gains could be from re-started sites shut down in the wake of Hurricane Michael bypassing the Gulf Coast, but the main additions are still coming from onshore Texas. The home to the mammoth Permian and the Eagle Ford shale basins, the Permian alone has 490 active oil and gas rigs. While infrastructural bottlenecks – mainly restrained pipeline capacity – have caused drilling activities to slow down since June, there are still gains to be made. Meanwhile, the lower prices caused by shale liquids being trapped in the Permian has led drillers to look elsewhere, where prices are stronger and infrastructure less clogged up – including re-looking at the Bakken and promising areas like Austin Chalk and Niobrabra. Recent auctions have seen record-high prices for acreage in Louisiana and Alabama; even in the Permian, interest remains high, with a recent sale in the New Mexican side of the basin setting a new record of more than double the previous high. This could be key to navigating the coming global supply crunch, triggered by new American sanctions on Iran, and exacerbated by continuing problems in key OPEC producers such as Venezuela and Libya. Although Russia has raised its production and Saudi Arabia has pledged to fill the hole that Iranian crude will be leaving, the assassination of Jamal Khashoggi places the Kingdom in a position of belligerence with the rest of the world. So the US may find itself in a position to have to provide extra volumes on its own – which may be why active rigs have been increasing, and new areas being sought. There is a bit of a spanner in the works, though. The trade spat between the USA and China has led Chinese importers to slam the brakes on importing US crude, even though American crude is not yet on the list of products tariffed by China. LNG and even NGLs – propane and ethane imported to produce petrochemicals – have also seen significant slowdown. How high can the American rig count get? If prices continue to march up – and there are many that believe the US$100/b mark will be reached soon – then the number of oil rigs drilling in the US could rise past 1200 again. But to reach the dizzying heights above 1500, which was the average over most of 2014, is unlikely. Not because there are lesser volumes of liquid underground – although studies are now showing that the decline rate in mature shale fields is alarmingly high – but because of consolidation. From a collection of many, many small players in the early 2010s, the shale landscape now is consolidating into a collection of medium and large players, with behemoths like ExxonMobil, Chevron and BP also muscling in. A rising tide of crude prices is lifting American drilling activity, but the magnitude of gains in 2018 will be different – due to a combination of infrastructure bottlenecks, fragile geopolitics and sector structural changes. The main danger is short memories – the zeal of cashing in on high oil prices is what caused the 2015 crash and high corporate debt, and the enthusiasm brewing in American shale again could lead to history repeating itself. Baker Hughes US Active Rig Count: 21 October 2011 – 1079 oil rigs, 927 gas rigs 19 October 2012 – 1410 oil rigs, 435 gas rigs 18 October 2013 – 1361 oil rigs, 372 gas rigs 17 October 2014 – 1590 oil rigs, 328 gas rigs 23 October 2015 – 594 oil rigs, 193 gas rigs 21 October 2016 – 443 oil rigs, 108 gas rigs 20 October 2017 – 736 oil rigs, 177 gas rigs 19 October 2018 – 873 oil rigs, 194 gas rigs
  42. 1 point
    These interactive presentations contains the latest oil & gas production data from all 13,899 horizontal wells in North Dakota that started production since 2005, through August. Visit ShaleProfile blog to explore the full interactive dashboards Oil production in North Dakota came in at 1,291 kbo/d in August, after a month-on-month rise of 1.7%, setting again a new record. As the graph shows, the 782 wells that started production in 2018 contributed already to more than 1/3rd of total production in August, producing more than the ~10k wells that started before 2015. After the high number of new producers in July (141 horizontal wells), 133 more came online in August. As this year around 100 wells were drilled so far each month, these recent completion numbers reduced the number of DUCs. The production profiles for all these wells can be seen in the “Well quality” tab. The 2018 wells are so far tracking closely the performance of the wells from the year before. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows how all these horizontal wells are heading towards their ultimate recovery, with wells grouped by the quarter in which production started. The 275 wells that started in Q3 2017 still show the best results so far (dark brown curve). They recovered on average 178 thousand barrels of oil in the first year of production. They appear to be on a path to recover about 1 more time that amount, before turning into stripper wells (<= 15 bo/d). In the 4th tab (“Productivity ranking”), all operators are ranked based on the average performance of their wells, as measured by the total oil recovered in the first 2 years. If you only select recent years, 2014-2016 (using the “first production year” selection), you’ll find that Enerplus comes out clearly on top. The 47 operated wells that started in this time frame recovered on average 289 thousand barrels of oil in the first 2 years. Next week I plan to have a new post on the Marcellus. For these presentations, I used data gathered from the following sources: DMR of North Dakota. These presentations only show the production from horizontal wells; a small amount (about 30 kbo/d) is produced from conventional vertical wells. FracFocus.org Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2CrnRnk Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  43. 1 point
    This interactive presentation contains the latest oil & gas production data from 93,991 horizontal wells in 10 US states, through June. Cumulative oil and gas production from these wells reached 9.1 Gbo and 101.4 Tcf. Visit ShaleProfile blog to explore the full interactive dashboards In just one and a half year, production from these wells grew by more than 1.5 million bo/d and 10 Bcf/d. Operators increased the pace of drilling and completion activity, and as the ‘Well quality’ tab shows, average well performance also slightly increased from 2016. Wells were completed with longer laterals on average, and proppant loadings increased even more. You can try out our ShaleProfile Analytics service for more details on these trends, e.g. on an operator/basin basis. The two largest shale oil operators, EOG and ConocoPhillips, set new records in June (‘Top operators’ tab). The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between production rates and cumulative production over time. The oil basins are preselected, and wells are grouped by the quarter in which production started. You can see that wells have been tracking steadily higher recoveries over the past years. Since the end of 2016, the pace of improvements appears to have slowed down. Later this week I will have a new post on North Dakota, which just released production figures for August. Production data is subject to revisions. For these presentations, I used data gathered from the sources listed below. FracFocus.org Colorado Oil & Gas Conservation Commission Louisiana Department of Natural Resources. Similar as in Texas, lease/unit production is allocated over wells in order to estimate their individual production histories. Montana Board of Oil and Gas New Mexico Oil Conservation Commission North Dakota Department of Natural Resources Ohio Department of Natural Resources Pennsylvania Department of Environmental Protection Texas Railroad Commission. Individual well production is estimated through the allocation of lease production data over the wells in a lease, and from pending lease production data. West Virginia Department of Environmental Protection West Virginia Geological & Economical Survey Wyoming Oil & Gas Conservation Commission Visit our blog to read the full post and use the interactive dashboards to gain more insight http://bit.ly/2CJZ2DJ Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  44. 1 point
    This interactive presentation contains the latest oil & gas production data through May, from all 7,962 horizontal wells that started production in the Niobrara region (Colorado & Wyoming) since 2009/2010. As shown in the graph below, 2017 was a similarly strong year for oil production growth as 2013, with more than 150 thousand bo/d added. Since end of last year, production from unconventional horizontal wells has remained just below half a million bo/d. In May about 70% of total oil production came from wells that started since the beginning of 2017. Gas production has now reached a level of 2.5 Bcf/d (set ‘Product’ to ‘gas’). 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). A big factor behind the recent output levels is then also improved well productivity, as shown in the ‘Well quality’ tab. Wells that started in 2017 performed better than earlier wells; on average they reached the 100 thousand barrel mark within the first year of production, while this took at least 1.5 years for earlier vintages. Anadarko and Noble Energy are the largest operators in this region (see “Top operators”), but Extraction Oil & Gas is catching up rapidly. 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. The jump in performance since Q4 2016 is clearly visible here. Since then however no further improvement is seen. If you group the wells by month, to see more recent and granular data, you’ll note that the best performance so far is shown by wells that started in Dec 2016. Many of the wells here are already at or close to stripper well status. Wells that started before 2014 are producing now on average at a level of 15 bo/d or lower. More dashboards, with other types of data (completion sizes, lateral lengths, etc) and more up-to-date data are available in our online analytics tool, for which you can request a free trial. We just started a YouTube channel in which we are sharing some movies on how you could perform particular analyses using this new tool: ShaleProfile Analytics on YouTube The following is a screenshot from a dashboard that shows a map with the gas-oil ratio (GOR) of all wells in the heart of the DJ-Niobrara basin, in their most recent month. On the right side you can see their ultimate recovery curves, with the related GOR plotted below. Also in this basin you can find areas where the GOR is rising faster for more recent wells, and that this is negatively impacting long-term recovery rates (not shown here below). [right-click and view/download to see a higher resolution version] Early next week I have an update on all 10 covered states in the US. 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/2x25WQp Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  45. 1 point
    This interactive presentation contains the latest oil & gas production data through May from all 16,326 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009. In this update we were able to include more recent wells, which explains the higher (~10%) production level. Output has surged higher in the first 5 months of 2018, following the rapid rise in 2017. As the graph shows, about 75% of total oil production in May came from wells that started producing since the beginning of last year. Associated gas production has followed a similar growth path, and is now well above 7 Bcf/d (switch product to ‘gas’). By selecting only New Mexico (using the ‘Basin’ selection), you can see that oil production in this area of the Permian really accelerated since September last year, and is now close to half a million barrels of oil per day. Almost double the number of wells started production in the first 5 months compared with last year (331 vs 176). In the “Well quality” tab the production profiles for all these wells are visualized. The bottom graph presents the cumulative production for each vintage. You can see that the wells that started in early 2016 are now closing in on the 200 thousand barrels of oil mark, on average, after about 2.5 years of production. It appears that more recent wells will do slightly better than that. In the ‘Well status’ overview, you’ll find the status of all these wells. If you select the status ‘First flow’, you can see that in the past year more than 300 wells started production each month, a level far higher than in the past. All leading operators are at, or near, record production levels (‘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. Recent wells are peaking at an average rate of ~700 bo/d in their first full calendar month, and are tracking a recovery slightly above the wells that started in Q2 2016. Early next week I will have a post on the Eagle Ford, followed by one on the Niobrara. Don’t want to wait to see the latest production data for each state? Check out our ShaleProfile Analytics service, in which we keep the data always up-to-date. For example, it already contains over 80% of June production in Texas, as well as Q2 for Ohio. If you’re interested, you can start with a free trial. 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/2wth6fY Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  46. 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
  47. 1 point
    This interactive presentation contains the latest oil & gas production data through April, from 90,168 horizontal wells in 10 US states. Cumulative oil and gas production from these wells reached 8.7 Gbo and 96.7 Tcf. The number of well completions in the 2nd half of 2017 was about 60% higher than the average level in 2016, which explains most of the rise in output over the past year. Average initial well productivity in the oily basins did not change much over this period, as shown in the ‘Well quality’ tab. EOG, with an operated production capacity of almost half a million bo/d, is the largest shale oil producer in the US (see the ‘Top operators’ overview). The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between cumulative production, and production rates, over time. Also here the oil basins are preselected, and wells are grouped by the year in which production started. By changing the ‘Show wells by’ selection to ‘Quarter of first flow’, you’ll see more recent and granular data. It also reveals that since Q4 2016, the average production profile hasn’t changed as much as before, as noted before. The 1,323 horizontal wells that started in Q4 2016 have recovered each on average just over 140 thousand barrels of oil through April, and declined to a production rate of 140 bo/d. Later this week I will have a new post on North Dakota, which just released June production. 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/2ORa9Nn Follow us on Social Media: Twitter: @ShaleProfile Linkedin: ShaleProfile Facebook: ShaleProfile
  48. 1 point
    This interactive presentation contains the latest oil & gas production data through March, from 88,617 horizontal wells in 10 US states. Cumulative oil and gas production from these wells reached 8.6 Gbo and 94.2 Tcf. The latest data for Ohio, which just released Q1 production figures, is also included. Only data for West Virginia is not up-to-date, and therefore this state has been deselected in most views. With the surge in drilling and completion activity since early 2017 both oil and gas production from these horizontal wells reached new records in recent months, at over 5 million bo/d and 50 Bcf/d. Current production is heavily dependent on recent completions, as the decline rates are high; for example, oil production from wells that started producing before 2015 is contributing just 23% of current production, as shown by the top of the dark green area in the above graph. Between the basins there are major differences, with some setting records each month (Permian, Appalachia, Niobrara), while others have not fully recovered yet (Eagle Ford, Haynesville), and a few appear to be in terminal decline (Barnett, Granite Wash). The major underlying reason for these differences is changing well productivity, which can be analyzed in the ‘Well quality’ tab. Note that the oily basins have been preselected in the ‘Basin’ filter, which you can manually adjust. The ‘Advanced Insights’ presentation is displayed below: This “Ultimate recovery” overview shows the relationship between cumulative production, and production rates, over time. Also here the oil basins are preselected, and wells are grouped by the year in which production started. The major increase in initial well performance in the past 2 years is clearly visible here. Later this week I will have a new post on North Dakota, which just released May production. Next week we will be present at the URTeC in Houston, so if you like to know more about our upcoming analytics services, come visit our booth. 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 https://shaleprofile.com/index.php/2018/07/16/us-update-through-march-2018/ 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