Old-Ruffneck + 1,223 er March 30, 2019 15 minutes ago, AcK said: Dude JJCar, Apologies but I do get the feeling you give precedence to your political views more than technical aspects of drilling and oil production. The Feb-19 data you are quoting is prelim ie subject to revisions. The most reliable dataset for us crude oil production was released yesterday by eia - jan-19 shows a decline over dec-18. Link below... https://www.eia.gov/petroleum/production/ Second, the production profile of a shale oil well has a sharp decline curve, irrespective of who drills. So with high tech there is modest improvement possible (third year production at 20pc of first year, better than 15pc) but as Tom keeps repeating his hamster wheel thesis, there is no doubt you will have to keep rig count high/keep drilling more wells just to keep output from falling. The consistent decline in oil rigs does indicate moderating growth. Sorry but seem to living in the post-truth world, being so much enamored with US energy independence and oil majors (although I have nothing against either - have actually invested in the latter). Actually JJCar has done his research and is quite correct on lot of the aspects of the drilling side and production. The tech of row and cube drilling means less rigs and more output. And don't forget the 7000 DUC wells yet needing completed. I don't put my faith in EIA graphs and charts anymore as they only see backwards, forward they seem to miss the mark consistently, like the NWS lol. Tom is just one person this forum and will I respect his views, he should get out from behind the desk and go take a trip to the areas producing. Billions of dollars on pipeline investments tell me the Permian isn't about to run out of oil any time soon. See the big picture, not just a week or two data from EIA, and go see or read for yourself this amazing feat the USA is doing. Can't count on the Middle East anymore so best get ourselves non-dependant on them. I personally would say invest closer to home, as above I stated. Quote Share this post Link to post Share on other sites
Carlos1955 + 4 ce March 31, 2019 On 3/12/2019 at 7:08 PM, Tom Kirkman said: Tom, I have a quick question, but first, I worked for a semi-major for 35 years, now retired. You have to include Chevron and Exxon as the larger shale producers, but you keep referring that all shale producers are taking on debt and financing wells with debt. I follow Chevron's and Exxon's Balance sheet and I am not noticing any significant increase in debt, actually in 2018 a reasonable decrease, and it appears these wells in Permian by these two companies are very profitable due to technology. I respect your comments, but do not understand why you believe they are financing with debt? On 3/12/2019 at 7:08 PM, Tom Kirkman said: Thanks @Rodent for your astute observations. @cbrasher1 fair enough question if you are new here. Note that over the years I have written literally over 10,000 comments about international O&G, and getting close to 15k comments these days. I have over 15 years in international Oil & Gas, and have dealt with O&G companies and EPCs in 30 countries. I am strongly pro - oil & gas and darn proud of it. My beef with the U.S. Shale Oil industry as a whole is it strikes me as debt trap. Up through last year, the U.S. Shale Oil industry as a whole has LOST MONEY. It has SPENT more than it EARNED. It was financed by easy credit. Google it. While OPEC is trying to pull back production to push prices to around $70-ish range, the coffee-guzzling frantic herd of untamed cats known as U.S. Independent Shale Oil producers are maxing out their credit to go ever deeper into debt, while flooding the world with oil. It causes havoc to global oil & gas. It's not the havoc created that I mind so much (heck, I adore Trump's 'bull in a china shop' upending of the Status Quo) but the endless cycle of debt that U.S. Shale industry as a whole keeps digging itself deeper into. It's not sustainable. Why the heck is U.S. Shale Oil industry continuing to overproduce and sell oil & gas (LNG) overseas at cut rate prices, the oil & gas that would be far better suited for DOMESTIC use. When U.S. Shale Oil production starts declining in a few years (less than 5 years from now) .... then what? Short-sightedness, fueled by easy credit and my old analogy of U.S. Shale Oil industry using new credit cards to make payments on maxxed-out old credit cards is a slow-moving train wreck. From a GLOBAL OIL & GAS perspective, my view is $70 oil [Brent] is currently around the optimum sustainable balance between global oil producers and global oil consumers. U.S. Shale Oil industry has shot itself in the foot by overproducing, and actively driving the price difference between WTI and Brent. Don't blame OPEC if you consider WTI prices to be too low. OPEC had been trying to fix this, and the herd of cats in the U.S. are merrily overproducing with joyful abandon, oblivious to their own self-inflicted foot bullets of OVERPRODUCING USING CREDIT. Clearly, I have a minority opinion, many others do not share my opinion. But hopefully I just gave you some views that you can poke around and perhaps reconsider your own opinion. Time to trot out my oil trusty tag line before I piss off too many gung-ho truuuu believers of the U.S. Energy Independence pipe dream pitched by MSM.... Just my opinion; as always, you are free to disagree. Quote Share this post Link to post Share on other sites
Keith boyd + 178 KB March 31, 2019 Just as American shale output starts declining, say 3-10 years from now the keystone xl pipeline should be competed by then so that alberta supplies can fill the gap with the capacity to ship it to where it is needed. Oil sands dont decline, mines have a life cycle of about 40 years and we have a few brand new ones that just opened. Pipeline bottlenecks are throwing a wrench into bringing up production to capacity but in the meantime America can enjoy the artificial canadian oil blockade and drill baby drill while it lasts. 1 Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 1, 2019 On 3/28/2019 at 9:11 PM, Old-Ruffneck said: Spoken like a true Liberal Leftist. If you or any of your family designed a new operating system and made trillions I would say Great!!! This is America, where dreams can be fulfilled. 50 to 55 WTI is a fair price and the oil companies are making good money. Some wells might be alittle tight some older wells making excellent returns. Averaging them all out (talking all producing wells from late 30's on) the price of 50 to 55 is good for America. Get greedy and watch the economy quickly slow. It's been shown time and again. You are wrong about 50-55 per barrel being a "fair price" for oil companies. Nobody will invest at that price as $65/b at the refinery gate is needed just to break even on the average Permian basin well after 64 months. The oil companies are not charities run by "liberal leftists", they are in business to make money and $55/b does not do it, just ask oil pros from Texas like Mike Shellman. Quote Share this post Link to post Share on other sites
Old-Ruffneck + 1,223 er April 1, 2019 11 minutes ago, D Coyne said: You are wrong about 50-55 per barrel being a "fair price" for oil companies. Nobody will invest at that price as $65/b at the refinery gate is needed just to break even on the average Permian basin well after 64 months. The oil companies are not charities run by "liberal leftists", they are in business to make money and $55/b does not do it, just ask oil pros from Texas like Mike Shellman. I worked long enough and have a good insight as what price point is decent and don't need Mike Shellman to tell me his opinion on pricing. He isn't in the Frackin' business and when I spent 2 month just recently in West Texas where the drilling is at, I inquired with Company Men and drillers and even Floor Hands. The cost are now Break-even 20 bux to 25 bux outta the hole. And in some cases less. Some more. It doesn't take that much to move it refine it to an overall cost of 35bbl. So reasoning 20 per bbl is a decent profit. Get greedy as I said before and the whole market goes to hell. Its effect on the whole economy causing inflation is good? 1 1 Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 1, 2019 (edited) 39 minutes ago, Old-Ruffneck said: I worked long enough and have a good insight as what price point is decent and don't need Mike Shellman to tell me his opinion on pricing. He isn't in the Frackin' business and when I spent 2 month just recently in West Texas where the drilling is at, I inquired with Company Men and drillers and even Floor Hands. The cost are now Break-even 20 bux to 25 bux outta the hole. And in some cases less. Some more. It doesn't take that much to move it refine it to an overall cost of 35bbl. So reasoning 20 per bbl is a decent profit. Get greedy as I said before and the whole market goes to hell. Its effect on the whole economy causing inflation is good? Old-Ruffneck, Mike has a lot of contacts in the Permian basin and has working interests in shale wells. Perhaps you don't understand the variability that exists from well to well. I am talking about basin wide average well productivity, you perhaps are talking about the top 1% of well productivity. Quick question for you, have you looked at the 10K for most tight oil companies? Can you explain why if they are breaking even at $20/b why at $50/b they are losing so much money? Bottom line, Mike is correct. Perhaps you don't understand well economics, you have to pay for the cost of the well, about 9 to 10 million for all in costs for a 10,000 foot lateral horizontal Permian well. There are royalty payments and taxes of about 33% of wellhead revenue, Lease operating expense of at least $13/b, transport cost to the refinery of at least $5/b. Let's take $50/b at the well head as an example (this would be $55/b at the refinery gate). Deduct 33% for royalty and taxes and we are left with $33.50/b, then deduct $13/b and we are left with $20.50/b, of "profit", but wait we have just dropped $9 million for D+C, land costs, gathering lines, well pads, storage tanks, and other overhead needed to operate a well and we need to cover that cost in 36 to 60 months (60 months would be a lousy well according to Mr. Shellman and he has been doing this for about 40+ years as an independent oil producer, he aims for 36 month payout). The average Permian basin horizontal tight oil well produces about 284,000 barrels in the first 60 months of production. So 284,000 times $20.5/b of net revenue at the well head gets us $5.8 million in revenue and we are $3.2 million short of breakeven at 60 months (note that $9 million for the well cost is likely to be an underestimate of actual full cycle well cost, Mr. Shellman estimates about $10 million is more reasonable for 2018 well cost). This explains why nobody is making any money at $55/b in the Permian basin, in short you are wrong. Inflation in the US has been very reasonable for the past 10 years or so, typically very low inflation rates (or worse deflation such as 1930-1933) indicates a very poor economic situation. Also very low oil prices might lead to a shortage of supply which would not be good for the economy as energy is a necessary economic input. Edited April 1, 2019 by D Coyne Quote Share this post Link to post Share on other sites
Old-Ruffneck + 1,223 er April 1, 2019 5 minutes ago, D Coyne said: Old-Ruffneck, Mike has a lot of contacts in the Permian basin and has working interests in shale wells. Perhaps you don't understand the variability that exists from well to well. I am talking about basin wide average well productivity, you perhaps are talking about the top 1% of well productivity. Quick question for you, have you looked at the 10K for most tight oil companies? Can you explain why if they are breaking even at $20/b why at $50/b they are losing so much money? Bottom line, Mike is correct. Perhaps you don't understand well economics, you have to pay for the cost of the well, about 9 to 10 million for all in costs for a 10,000 foot lateral horizontal Permian well. There are royalty payments and taxes of about 33% of wellhead revenue, Lease operating expense of at least $13/b, transport cost to the refinery of at least $5/b. Let's take $50/b at the well head as an example (this would be $55/b at the refinery gate). Deduct 33% for royalty and taxes and we are left with $33.50/b, then deduct $13/b and we are left with $20.50/b, of "profit", but wait we have just dropped $9 million for D+C, land costs, gathering lines, well pads, storage tanks, and other overhead needed to operate a well and we need to cover that cost in 36 to 60 months (60 months would be a lousy well according to Mr. Shellman and he has been doing this for about 40+ years as an independent oil producer, he aims for 36 month payout). The average Permian basin horizontal tight oil well produces about 284,000 barrels in the first 60 months of production. So 284,000 times $20.5/b of net revenue at the well head gets us $5.8 million in revenue and we are $3.2 million short of breakeven at 60 months (note that $9 million for the well cost is likely to be an underestimate of actual full cycle well cost, Mr. Shellman estimates about $10 million is more reasonable for 2018 well cost). This explains why nobody is making any money at $55/b in the Permian basin, in short you are wrong. Please read some of my earlier posts. I can guarantee you Exxon and Chevron wouldn't be piling rigs in West Texas unless they are going to make money at 25bbl. I can tell you while I do appreciate Mike Shellman, he and I are same age, old school hands and everyone has an opinion. I have mine he has his. The reason you see so many DUC wells is because far West Texas is where the action is at present and equipment now pulled to there as easier faster money. Take a drive and go learn. Reading peoples comments on here is not proof positive it's accurate. I have a good idea as I actually am from West Texas, S.E. New Mexican and still have enough friends in the patch working and giving info. One neighbor was operator of 20 rigs and he had no reason to lie. Told me around the Pecos area in early January 18 bux Break-even. And just getting better with the tech. 2 Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 1, 2019 (edited) Old Ruffneck, I agree there are many opinions, keep in mind that just because there is one well that might break even at $20/b, does not mean that all wells will. The average 2017 Permian Basin horizontal well produces about 280 kb in the first 60 months of production, do a little math and you will quickly see one would need an average well cost of about $6 million for the average well to break even at $50/b at the well head. At $25/b at the wellhead, one would need a well cost of $1 million for the average Permian well with cumulative output of 285 kb over the first 60 months to break even (that is for net revenue to pay for the cost of the well in full over those first 60 months, that is what break even means). What are your contacts telling you about the average cost of a horizontal fracked well costs in the Wolfcamp shale, is it less than $1 million, I have read that D+C alone tends to be around 7 million these days? See https://shaleprofile.com/2019/04/01/permian-update-through-december-2018/ and look at "well quality" tab, focus on 2017 wells, there are 3578 of them which I fit a standard Arp's hyperbolic to project output to 60 months, the fit is likely to be too optimistic rather than pessimistic. The numbers do not lie, $59/b is needed at the wellhead for a $9.75 million dollar well to break even in 60 months, for a better 43 month breakeven oil price for the same $9.75 million well, $65/b is needed at the well head ($70/b at the refinery gate). Chart with data from page linked above below Edited April 1, 2019 by D Coyne Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 1, 2019 19 hours ago, Keith boyd said: Just as American shale output starts declining, say 3-10 years from now the keystone xl pipeline should be competed by then so that alberta supplies can fill the gap with the capacity to ship it to where it is needed. Oil sands dont decline, mines have a life cycle of about 40 years and we have a few brand new ones that just opened. Pipeline bottlenecks are throwing a wrench into bringing up production to capacity but in the meantime America can enjoy the artificial canadian oil blockade and drill baby drill while it lasts. Keith, It takes much longer to ramp up oil sands production and the US tight oil output will decline pretty fast after 2025, it is not likely that Canadian output will be able to make up the difference at least based on the 2018 CAPP forecast. US tight oil output may increase by 3.5 Mb/d to about 11 Mb/d by 2025 but will fall by about the same amount over the next 9 years, falling back to the Feb 2019 level (about 7.5 Mb/d) by Jan 2034. Not sure Canadian output will be able to rise by 3.5 Mb/d over a 9 year period as the best prospects may have been developed by 2025 and further increases might be more difficult. The CAPP forecast calls for about a 1 Mb/d increase in oil sands output from 2018 to 2030 from 2800 kb/d in 2018 to 3800 kb/d in 2030. Perhaps with higher oil prices the rate of increase will be greater, but a factor of 3 faster would still not be fast enough. Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 1, 2019 https://www.iea.org/newsroom/news/2019/march/united-states-to-lead-global-oil-supply-growth-while-no-peak-in-oil-demand-in-si.html https://www.bizjournals.com/sanantonio/news/2019/03/27/dallas-fed-slowing-growth-doesnt-stifle-outlook.html?ana=smartbrief https://www.eia.gov/todayinenergy/detail.php?id=38832 Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 1, 2019 Technology in the shale patch _________________- Oasis Petroleum is focusing on generating free cash flow at oil prices in the $50/barrel West Texas Intermediate range. The Williston Basin and Delaware Basin operator will spend less capital this year compared to last to generate free cash flow operations. The push for free cash flow means Oasis will spend roughly $540 million to $560 million across its two operating basins. Three-fourths of its 2019 capital will be put towards the Williston Basin. ________________________________________________ New shale tech provides real-time picture, avoids frack hits A new technology that allows hydraulic fracture engineers to view a real-time picture of a created fracture network in shale oil and gas wells has received $10.5 million in backing. Quantum Energy Partners, an energy investment firm, has infused Austin, Texas-based Seismos with money to help the frack tech provider grow its operations. Panos Adamopoulos, founder and CEO of Seismos, said the system allows E&Ps to customize stage treatment designs on-the-fly. The system helps “quantify the impact of each stimulation variable to the properties of the fracture system developed, compensate for variations in geology, avoid frack-hits and optimize well spacing and field development.” Seismos has developed a trademarked product called Seismos-Frac, to allow engineers to adjust and optimize their treatment operations. In addition to the real-time monitoring, the system provides a better understanding of geometry downhole, allowing engineers to enhance flowback into the wellbore. According to the company, the system has already been successfully deployed in multiple U.S. shale plays, including the Permian, Eagle Ford, DJ Basin, and Haynesville shale. Developed in conjunction with Stanford University faculty members, the technology has proven to be effective to initial users, according to Jeffrey Harris, venture partner at Quantum Energy. “The increasing number of exploration and production companies repeatedly using Seismos’ technology supports the need for additional resources to meet growing market demand,” Harris said. _____________________________________________________________________- ExxonMobil will boost Permian profits with help of Microsoft ExxonMobil said a new partnership with Microsoft will make its Permian Basin operations the largest-ever oil and gas acreage to use cloud technology and is expected to generate billions in net cash flow over the next decade through improvements in analyses and enhancements to operational efficiencies. The application of Microsoft technologies by ExxonMobil’s XTO Energy subsidiary—including Dynamics 365, Azure, Machine Learning and Internet of Things—is anticipated to improve capital efficiency and support Permian production growth by as much as 50,000 oil-equivalent barrels per day by 2025. “The combination of Microsoft’s technologies with our unique strengths in oilfield technologies, production efficiency and integration will help drive growth in the Permian and serve as a model for additional implementation across the U.S. and abroad,” said Staale Gjervik, senior vice president, Permian Integrated Development for XTO. “The unconventional business is fast moving, complex and data rich, which makes it well suited for the application of digital technologies to strengthen our operations and help deliver greater value.” ExxonMobil’s partnership with Microsoft includes an integrated cloud environment that securely and reliably collects real-time data from oil field assets spanning hundreds of miles. The data will enable ExxonMobil to make faster and better decisions on drilling optimization, well completions and prioritization of personnel deployment. Importantly, leak detection and repair response times could be further reduced with enhanced access to emissions data, strengthening XTO’s voluntary actions to manage methane emissions. ExxonMobil’s application of these technologies in its Permian Basin acreage, which covers a 9.5 billion oil-equivalent barrel resource base and more than 1.6 million acres, represents industry’s largest acreage position using cloud technology. Alysa Taylor, corporate vice president of Microsoft Business Applications and Industry, said ExxonMobil is taking a leadership approach in its digital strategy. “ExxonMobil is leading the way for industry, grounding their goals in making data-driven decisions that will result in safer operations for their employees and more profitable activities for the company,” said Taylor. “Our cloud infrastructure and business applications will continue to support ExxonMobil as it fully realizes its strategy across the Permian.” Microsoft’s platforms, including Azure Data Lake, will enable ExxonMobil to rapidly incorporate third-party solutions at scale across the Permian. Examples include mobile field data apps to optimize well performance, and AI algorithms for analyzing drilling and completions data to improve performance. With the additional layer of Microsoft’s intelligent business applications, such as Dynamics 365, ExxonMobil and XTO will have a complete, end-to-end view of the Permian operations. “Digital technology is a fundamental enabler for our Permian development,” said Gjervik. “Through our partnership with Microsoft, we’re combining our technical and engineering expertise with cloud and data analytics capabilities to develop the Permian resource in the most capital-efficient manner. Collaboration with Microsoft is key to our future development efforts, which include predictive maintenance capacities, innovative tools for employees, and artificial intelligence and machine learning integration.” ____________________________________________________ Reveal releases FracEYE system to reduce frac hits in shale wells To minimize the effect of frac hits in mutliwell pads, Reveal Energy Services has developed a new product it calls FracEYE. The monitoring system allows operators to make timely adjustments to wells being fracked on mutliwell pads that feature parent (previously completed wells) and child (recently drilled wells being completed in the same or near formation as parent well). “Because infill development and frac hits are a pressing concern, our goal was to develop a service with a fast turnaround time so operators would have the information to update their next completion designs, if necessary,” said Sudhendu Kashikar, CEO or Reveal. “We’re pleased that we can add to the understanding of frac hits.” According to the company, it all starts with its pressure-based technology. The system categorizes the type and severity of interwell communication by measuring the pressure response from a parent well as hydraulic fracturing proceeds normally in child wells. Geoscientists and completion engineers can use the pressure-response timing and geomechanics to classify the observed response into one of four categories: -direct fluid transport: large and rapid overall pressure increase in the offset well -fluid migration: gradual pressure increase that lingers post-stage completion -undrained compression: instantaneous pressure response in the offset well -no signal: no significant pressure change in the offset well Reveal first signed a contract with a major operator in the Marcellus in June last year. Since then, the company has performed in multiple shale basins and received two patents for pressure based fracture maps. Prior to joining Reveal, Kashikar was the vice president of engineering at Microseismic Inc. Reveal Energy’s board of directors includes representatives from Lime Rock Resources and Statoil Technology Invest. ________________________________________________________ Whiting reveals impact of Gen 5 frac designs for Bakken Whiting Petroleum used 2018 to assemble and organize a new executive team and implement and prove-out a new generation of hydraulic fracture design for the Williston Basin. The 2018 focus is paying off. Much of Whiting’s acreage once considered Tier 2 could soon be considered core when the right, generation five frack design is used. “The way we are driving proppants is driving results,” said Brad Holly, Whiting president and CEO. The generation 5.0 design concentrates more of the stimulation near new infill wells, uses lower sand loading, more entry points and more diversion techniques for infill wells. The team is also trying to create a mix of far-reaching fractures and near-wellbore concentrations that feature higher sand loading, adequate entry points and diversion to ensure the entry points are connected. The new designs all try to optimize the completions to well spacing along with geology. A range of 635 lbs./ft of proppant to 900 lbs./ft of proppant are placed on stage spacing at a range of 220 feet to 280 feet. Per foot, 15 barrels to 25 barrels of fluid is used. All wells are fracked with a cemented liner using plug-n-perf technology along with diversion technology. Several members of the executive team touched on the new design as reason for optimism going into 2019 where the company may pursue acreage acquisitions armed with its new completion design knowledge. Holly said the team will never try and find a cookie-cutter design for completing Bakken wells, however, and that they will always being looking for the next best thing. On the executive team additions and changes, Holly was confident in the moves. “If we get the right people on the bus in the right seats,” he said, “we can drive from good to great.” This year, Whiting expects to grow production by roughly 11 percent and spend $820 million, all of it in the Bakken. Each quarter, Whiting will drill more than 30 wells. The company will complete 30 wells in Q1, 52 wells in Q2, 43 wells in Q3 and 29 wells in Q4. Although Whiting will only bring on 12 wells to production in Q1, it will ramp up in Q2 by bringing 58 wells onto production, followed by 45 and 31 wells onto production in Q3 then Q4. The North Williston Team will get $216 million to drill and complete wells in the Cassandra and Wildrose areas. The East Williston Team will receive $180 million to drill 60 wells, complete 40 wells and put 37 wells on production. Some of the wells will be Three Forks infill wells. The South Williston team will use $266 million to focus on drilling 53 wells and completing 57 wells. To help drive cash costs down, the company has established water gathering systems for produced water, renegotiated lower rates for existing produced water systems and implemented well monitoring and intervention technologies. At $55 NYMEX oil prices, Whiting will grow free cash flow. __________________________________________________________ Baytex plans 30 new wells for Eagle Ford Baytex Energy Corp. is focusing on two plays in 2019: the Eagle Ford of Texas and the Viking shale play of Canada. To produce 97,000 boe/d, Baytex intends to invest $650 million. The Eagle Ford will receive 38 percent of the total budget and represents a major production focus for Baytex next year. The Canadian exploration and production company that merged with Raging River Exploration earlier this year, intends to bring 30 new wells online in 2019 from the lower Eagle Ford. Nearly all of the capital budget is going towards production and drilling, with roughly 45 percent of the planned activity scheduled for the first half of the year. At $52/b West Texas Intermediate pricing on oil, Baytex said it will earn a $22/b operating net back. The company has hedged roughly 30 percent of its production for next year. A US$1.00/bbl change in the price of WTI impacts Baytex’s annual adjusted funds flow by approximately $30 million on an unhedged basis ($24 million on a hedged basis). Following its merger, Baytex has reduced is headcount at its heavy oil assets including the number of executives needed to oversee the assets. Ed LaFehr, president and CEO, said the company will be disciplined with capital allocation in 2019 and that it will keep “operational flexibility,” to adjust spending plans based on changes in the commodity price environment. __________________________________________________________ A Cushing-to-Houston light oil pipeline project pitched to help Bakken and Midcontinent producers send crude to the Texas Gulf Coast could expand to take additional barrels from the Permian. Magellan Midstream Partners LP and Navigator Energy Services have been holding an open season call for a 300,000 barrel per day pipeline project that would move shale oil sent to Cushing onto refineries or an export site in Houston since early 2019. The partnership recently announced a plan to extend the open season until May 31 to allow for the possibility of adding an oil origination point in Midland, Texas. According to Magellan and Navigator, several potential shippers have requested the evaluation of adding a Midland origin point to the pipeline to help move barrels from the Permian. The Midland origin could be accomplished in part through Voyager’s use of an existing Magellan pipeline that may be idled in the near future as part of Magellan’s announced West Texas refined products pipeline expansions project, Magellan said. Voyager would have the ability to use an existing Magellan terminal in Frost to construct assets needed to connect to the Cushing-to-Houston segment. Magellan owns a 50 percent stake in Seabrook Logistics LLC, a gulf coast export site that will be used to send shale oil from the Bakken, Midcontinent and now potentially the Permian to locations like South Korea. In the past several months, takeaway constraints in the Permian have made oil prices from the region trade at a lower price compared to oil moved through Cushing. However, a recent update from the U.S. Energy Information Administration shows that the price disparity has been eased to additional pipeline capacity from the Permian to Houston. “WTI Midland prices still trade lower than Houston crude prices,” EIA said, “suggesting that the region still faces some takeaway constraints in shipping Permian crude oil to the U.S. Gulf Coast. Most recently,” EIA said on March 26, “the difference has been about $7 per barrel, which is less of a discount that in the middle of 2018.” Navigator Energy’s main focus is on the Midcontinent shale plays of the SCOOP and STACK. The company owns and operates at 250-mile oil gathering network. ______________________________________________ Multinational water tech firm acquires Permian water service A Fort Stockton, Texas-based hydraulic fracturing water treatment company has been acquired by a multi-national water specialist to better serve the Permian Basin. Neptune Enterprises previously worked with De Nora on water issues related to frack water treatments in West Texas. Through the acquisition, De Nora has now formed De Nora Neptune LLC. The newly named company will continue to offer “on-the-fly” frack water treatment and produced water recycling services. Neptune’s special technology utilizes salt, water and electricity to treat produced water for reuse in fracking. Like all shale plays, water in the Permian continues to be a major factor in the costs and ongoing maintenance in the life of a well. By using effective produced water recycling companies can reduce water costs and eliminate the need for disposal of water. Disinfecting water prior to use is helpful, but requires bacteria that can later produced scale in a well to be disinfected and killed off prior to the water being injected downhole during fracking operations. Neptune’s produced water recycling system can resupply frack operations with water priced at below $0.25/b. The company has been using its system in the Marcellus and the Permian since 2012 and now treats more than 50,000 barrels of water per day. Alex Gonzalez, president of Neptune, said operators have been challenging water companies to provide cost-effective and safe options for treating produced water. “This acquisition is bringing them exactly what they have asked for: the safest technology, complete bacteria kill and the lowest price in the industry,” he said. “This is really good news for all operators.” De Nora will help expand the offerings of Neptune and provide a full water service treatment instead of just the water technology. De Nora has been focused on several onshore and offshore water treatment issues, including biofouling control, sewage treatment and membrane filtration on offshore drilling platforms to onshore frack water disinfection. Terms or amount of the acquisition were not disclosed. Quote Share this post Link to post Share on other sites
Auson + 123 AD April 1, 2019 On 3/25/2019 at 1:09 AM, ceo_energemsier said: Oil Dorado: Guyana set for its own Klondike ‘black gold’ rush? Written by John Mair in Georgetown, Guyana - 18/03/2019 6:00 am It is in South America yet they speak English. Culturally and in cricket terms they are West Indian. Guyana was the setting for Sir Walter Raleigh’s mystical city of gold: El Dorado. Today the reality is that billions of barrels of quality crude has been discovered offshore. ExxonMobil has declared five and a half billion barrels in their Stabroek block alone. Others are just starting exploration. Some expect there to be up to 13 billion barrels below the seabed.First oil is due later this year and by 2025 Guyana will be in full flow. One startling statistic: There will be a barrel of oil per day per head of the 750,000 population. The nation’s GDP will double. How that oil wealth is distributed is the big question facing a nation in the midst of political chaos. The government lost a vote of confidence last December. Elections, according to the constitution, should be held by March 21. No sign. David Granger’s government is running down the clock. The earliest people here expect is September or more likely December 2019, one full year after the loss of confidence in the National Assembly. Meanwhile the discoveries continue. The Liza development, which will be the first to deliver, is a joint enterprise between Exxonmobil, China National Oil Corporation and Hess Corporation. It is 120 miles off the coast of Guyana. To date 12 wells have come up positive for oil out of just fourteen drilled, a success rate of 82%, four times the industry average worldwide. Liza One alone is expected to yield in excess of one billion barrels. Just last month Exxonmobil announced another two discoveries in their field. Others exploring other fields are being coy. Eco Atlantic thinks it will discover nearly four billion barrels in its patch. This was confirmed to this writer by one of their partners in the venture. Other franchises and fields are currently being touted; the process is held up by the political stasis in Guyana. Parliament is not sitting and will not until the Opposition PPP agrees and that depends on President Granger, who is currently in Cuba receiving chemotherapy for his leukaemia, naming an election date.Granger controls the allocation of blocks personally. The government does have an energy department, but that is headed by Dr Mark Bynoe, who is inexperienced when it comes to oil. He has little autonomy and a tiny staff. Advertisements are currently appearing in the Guyanese press for more professionals. It looks like it will be some time before the energy department gets some energy behind it. Meanwhile exploration of the new “Oil Dorado” continues apace. The oil men and women are coming to town to seek part of the action. This week past Barney Crockett, the Lord Provost of Aberdeen, was here to sign twinning agreements with Georgetown and develop links with the private sector. Trade and oilmen will follow. Guyana has set up a Sovereign Wealth Fund which it calls the Natural Resources Fund. That too is but an embryo within the Finance Ministry. The Petroleum Commission set up to regulate also looks to be still an idea rather that reality.What is real is the potential profits. The world oil price is currently around $60 per barrel. The break even price for the Liza discovery is said to be below $40 per barrel. Guyana’s oil will not only be easy to find it will also be very profitable.In 2012, the United States Geological Survey estimated that that there was 13.6bn barrels of oil and 32 trillion cubic feet of natural gas yet to be discovered in the Guyana-Suriname basin. Some nine decades ago, in 1932, the British Guyana Daily Chronicle was very prescient. “Every Man, Woman and Child in British Guyana Must Become Oil-Minded”, it declared. In 2019 the Guyanese are learning that lesson at long last. John Mair is Guyanese born. He lives in the UK but visits Guyana regularly. He has worked as a TV producer for the BBC and Channel Four. In recent years he has edited 30 books. The latest, Oil Dorado? Guyana’s Oil was published in Guyana on March 13 and will be published in the UK on March 28. Good job we keep finding all this Oil I guess it means we won't have to faff around with battery tech and E.Vs anymore ! 1 Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 2, 2019 ExxonMobil announces huge Permian production increases By ExxonMobil | March 05, 2019 ExxonMobil has revised its Permian Basin growth plans to produce more than 1 million oil-equivalent barrels per day by as early as 2024—an increase of nearly 80 percent and a significant acceleration of value. The size of the company’s resource base in the Permian is approximately 10 billion oil-equivalent barrels and is likely to grow further as analysis and development activities continue. “We’re increasingly confident about our Permian growth strategy due to our unique development plans,” said Neil Chapman, ExxonMobil senior vice president. “We will leverage our large, contiguous acreage position, our improved understanding of the resource and the full range of ExxonMobil’s capabilities in executing major projects.” “Our plans are attractive at a range of prices and we expect them to drive more value as we continue to lower our development and production costs,” Chapman said. ExxonMobil’s investments in the Permian Basin are expected to produce double-digit returns, even at low oil prices. At a $35 per barrel oil price, for example, Permian production will have an average return of more than 10 percent. The anticipated increase in production will be supported by further evaluation of ExxonMobil’s Delaware Basin’s increased resource size, infrastructure development plans, and secured capacity to transport oil and gas to ExxonMobil’s Gulf Coast refineries and petrochemical operations through the Wink-to-Webster, Permian Highway and Double E pipelines. Among the company’s key advantages in the Permian, is its acreage position. The company has large, contiguous acreage that enables multi-well pads in large development corridors connecting to efficient gathering systems, reducing development costs and accelerating production growth. ExxonMobil’s scale, financial capacity and technical capabilities enable the company to maximize the value of the resource. ExxonMobil is actively building infrastructure to support volume growth. Plans include construction at 30 sites to enhance oil and gas processing, water handling and ensure takeaway capacity from the basin. Construction activities include central delivery facilities designed to handle up to 600,000 barrels of oil and 1 billion cubic feet of gas per day and enhanced water-handling capacity through 350 miles of already-constructed pipeline. “These investments support growth plans and ensure that as production levels continue to rise, we are well positioned in processing and transportation capacity,” Chapman said. The investment plans will also bring great benefits to the local area. ExxonMobil’s expansion in the region will benefit communities in West Texas and southeast New Mexico through billions in property tax revenue, economic development and the creation of high-paying jobs. ExxonMobil remains one of the most active operators in the Permian Basin and has 48 drilling rigs currently in operation and plans to increase its rig count to approximately 55 by the end of the year. Increased use of technology, including enhanced subsurface characterization, subsurface modeling and advanced data analytics to support optimization and automation, will help the company reduce costs, improve its development plan and increase resource recovery. Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 2, 2019 On 3/30/2019 at 9:29 AM, JJCar said: EIA SHOWS DECREASE ORBITAL INSIGHTS INC REAL-TIME INVENTORY SHOWS INCREASE. Oil doesn't trade on fundamentals anymore. It is skewed by by algorithms , machine to machine program trading, hyperbola and brown-nose investment bank research analyst. As for EIA numbers they are very unreliable as described by legendary oil trader Andy Hall. The EIA numbers these days are naturally driven by the Permian. The Texas numbers are gathered and provided by the Texas Railroad Commision. As Andy Hall describes they are consistently wrong. They are continually revised and revised again. Hall says the real numbers aren't settled for at least 6 months. Orbital Insights shows US inventory up. I will start a discussion later this week but some info for now, Orbital Insight just published World inventory numbers for March: (1)World inventory rose (2) China's inventory ran up 119 million bls to new storage record. (3) OPEC's own members inventory went up ! What ? How ? How can that happen when OPEC gets help from (1) Canada has mandated production cuts 335,000 bbl/day, (2) Venezuela sanctions reduced production to under 1 million bbls/day and (3) Iran sanctions reduced their production down to 1 million bbls/day.(4) Libya's largest oil field Sharara,335,000 bbls/day has been shut down since beginning of December. Simply put . . . TOO MUCH SUPPLY WE ARE 4 MONTHS INTO OPEC PRODUCTION CUTS . . . INVENTORY HAS INCREASED . . . NOT DECREASED. . . . AND OIL PRICES HAVE GONE UP ! Go Figure. I know oil trades on anticipation of future supply . . . but OPEC members own inventories have increased not decreased four months into the cuts. All just based on "talk" . When are the analyst going to stand up and say. . . . . . . . "The king has No Clothes" I am the last person to favor Big Oil. They've been milking US consumer forever. They buy Washington influence for favorable legislation regard oil companies issues and tax regulations. They use transfer pricing and oil accounting laws to avoid paying any corporate income taxes in the US. Big Oil totally missed the shale oil revolution. But the reality is natural economic industry maturation leads to consolidation. Size matters. Politics in oil was necessary when US was at the mercy of OPEC. That has changed. However, it is difficult to get elected to national office without money from Big oil and Hedge Funds know. So the politics is still hand and with politics. Technology is transforming every industry . . . It's oil industry turn now. Oil doesn't really trade on fundamentals like it used to. I will start a discussion this week explaining what I mean. Gotta go now JJCar, The EIA production estimates are quite good, especially the monthly output estimates. US oil output is likely to grow more slowly in 2019 than in 2018 as most tight oil producers are trying to reduce the amount of debt they use for new investment and this is likely to reduce completion rates. If you look at actual average well productivity for the majors in the shale plays they are no different from the basin wide average and I doubt they will be more efficient than the top tier independents and their average well cost is likely to be similar. See "tight oil production estimates by play" and "crude oil production" at the page linked below for the best estimates of US oil output. https://www.eia.gov/petroleum/data.php Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 2, 2019 16 hours ago, ceo_energemsier said: ExxonMobil announces huge Permian production increases By ExxonMobil | March 05, 2019 ExxonMobil has revised its Permian Basin growth plans to produce more than 1 million oil-equivalent barrels per day by as early as 2024—an increase of nearly 80 percent and a significant acceleration of value. The size of the company’s resource base in the Permian is approximately 10 billion oil-equivalent barrels and is likely to grow further as analysis and development activities continue. “We’re increasingly confident about our Permian growth strategy due to our unique development plans,” said Neil Chapman, ExxonMobil senior vice president. “We will leverage our large, contiguous acreage position, our improved understanding of the resource and the full range of ExxonMobil’s capabilities in executing major projects.” “Our plans are attractive at a range of prices and we expect them to drive more value as we continue to lower our development and production costs,” Chapman said. ExxonMobil’s investments in the Permian Basin are expected to produce double-digit returns, even at low oil prices. At a $35 per barrel oil price, for example, Permian production will have an average return of more than 10 percent. The anticipated increase in production will be supported by further evaluation of ExxonMobil’s Delaware Basin’s increased resource size, infrastructure development plans, and secured capacity to transport oil and gas to ExxonMobil’s Gulf Coast refineries and petrochemical operations through the Wink-to-Webster, Permian Highway and Double E pipelines. Among the company’s key advantages in the Permian, is its acreage position. The company has large, contiguous acreage that enables multi-well pads in large development corridors connecting to efficient gathering systems, reducing development costs and accelerating production growth. ExxonMobil’s scale, financial capacity and technical capabilities enable the company to maximize the value of the resource. ExxonMobil is actively building infrastructure to support volume growth. Plans include construction at 30 sites to enhance oil and gas processing, water handling and ensure takeaway capacity from the basin. Construction activities include central delivery facilities designed to handle up to 600,000 barrels of oil and 1 billion cubic feet of gas per day and enhanced water-handling capacity through 350 miles of already-constructed pipeline. “These investments support growth plans and ensure that as production levels continue to rise, we are well positioned in processing and transportation capacity,” Chapman said. The investment plans will also bring great benefits to the local area. ExxonMobil’s expansion in the region will benefit communities in West Texas and southeast New Mexico through billions in property tax revenue, economic development and the creation of high-paying jobs. ExxonMobil remains one of the most active operators in the Permian Basin and has 48 drilling rigs currently in operation and plans to increase its rig count to approximately 55 by the end of the year. Increased use of technology, including enhanced subsurface characterization, subsurface modeling and advanced data analytics to support optimization and automation, will help the company reduce costs, improve its development plan and increase resource recovery. Mike Shellman has pointed out that for the majors there may be advantages that make the Permian profitable at $46/b for Chevron in the Delaware basin and for Exxon at $50/b in the Midland basin, if we assume a $10 million well cost for the Delaware and an $8 million well cost for the Midland with 10% annual discount rate, this results in discounted net revenue equal to well cost over the life of the well, natural gas and NGL were ignored so these are very conservative estimates as the majors will have pipeline capacity for natural gas locked up which would reduce breakeven price by perhaps $5/b (I have not run the numbers and this in part depends on NGL barrels per Mcf of gas which I do not have data on. In any case expansion for the majors will depend on the amount of pipeline capacity they can access as well as ability to either refine or export the tight oil produced. At some point Exxon and Chevron will be competing with each other for pipeline and export capacity and future growth will depend on infrastructure, at some point (probably around 2025) pipeline operators will realize they have overbuilt and the infrastructure investment may have been a waste as there will not be enough output to fill the pipe. A slow steady growth with a lengthy plateau would reduce excess capacity, probably aiming for 5 Mb/d of tight oil output in Texas would make more sense than aiming for 7 or 8 Mb/d from an investment standpoint. Quote Share this post Link to post Share on other sites
footeab@yahoo.com + 2,187 April 2, 2019 11 minutes ago, D Coyne said: A slow steady growth with a lengthy plateau would reduce excess capacity, probably aiming for 5 Mb/d of tight oil output in Texas would make more sense than aiming for 7 or 8 Mb/d from an investment standpoint. 😆🤣🤣👹🤡🙄🙄🙄🙄🙄 Since when... 1 Quote Share this post Link to post Share on other sites
D Coyne + 305 DC April 2, 2019 1 hour ago, Wastral said: 😆🤣🤣👹🤡🙄🙄🙄🙄🙄 Since when... Actually, I just realized I was forgetting other tight oil basins in Texas and was focused on just the Permian Basin (which includes output from the New Mexico side), Eagle Ford and Austin Chalk would add another 1.5 Mb/d or so. And I agree that the fact that such a plan makes so much sense means it is highly unlikely in the real world. Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 2, 2019 Stonepeak to acquire Permian system for $3.6bn Investors selling interests in crude gathering system include Concho, WPX Private equity firm Stonepeak Infrastructure is set to acquire the largest privately held midstream crude oil operator in the prolific Permian basin of Texas and New Mexico for $3.6 billion in cash. __________________________________________________________ ExxonMobil 'eyes Nigeria sale' Local indies in asset talks as field disposals could raise $3bn for US supermajor: report ExxonMobil recently held talks on the sale of a suite of oil and gas fields in Nigeria as the company focuses on new developments in US shale and Guyana. ______________________________________________________ 01 April 2019 Share: US independents that undertook two multi-billion dollar mergers in the Permian basin last year insist that their deals are paying off — but their share price performance suggests that investors are looking for more. Concho Resources purchased smaller peer RSP Permian for $7.6bn in shares while taking on $1.7bn of debt in March 2018. This was followed by Diamondback Energy swooping up fellow Permian producer Energen in an all-stock $9.2bn transaction, including $830mn of net debt. The Energen purchase also came just days after Diamondback bought Ajax Resources for $1.25bn. Debt and equity investors saw the deals as ushering in a needed wave of consolidation in the US shale industry to cut costs and improve efficiencies in a volatile oil market. Yet the stock market response to the successes the two say they have had in achieving their synergy and cost-reduction targets has been muted at best. Concho — producing 307,000 b/d of oil equivalent (boe/d) in the fourth quarter — is trading at around $111/share, compared with $158/share in March last year when the deal was announced. Diamondback — with fourth-quarter output of 182,600 boe/d — is trading at around $102/sharecompared with $138/share when its deals were announced in August 2018. The crude price slide in the fourth quarter of last year and continuing volatility may partly explain the share price drops, yet they overshoot the S&P 500 Energy Index's fall of just 2pc since March last year (see graph). Concho's acquisition was expected to help save $2bn through operational synergies such as optimising development plans, sharing infrastructure and improving efficiency, the company said at the time. But it has since lowered its capital expenditure (capex) guidance for 2019 and 2020, cut its rig fleet for this year and pared its output growth expectations for 2019 and next year. Concho says it has met its $60mn target of cuts to general and administrative costs. But the bulk of savings are due to come from drilling longer lateral wells and larger multi-well pads, which it is still working towards. The company has not lost sight of its goals, chief executive Tim Leach says. "We are redoubling our focus on cost control, capital discipline and growing free cash flow and returns," Leach says. Concho's operating cost target for this year is $6-6.50/boe, against $6.14/boe in 2018. But it expects oil service costs to decline in the coming months as producers pare activity. And the firm will continue to shed non-core assets. US bank Tudor Pickering Holt expects Concho to deliver substantial free cash flow after 2020, when it has achieved its development and cost-saving goals. Diamondback on track Diamondback's capture of Energen similarly aimed to deliver it $2bn in cost savings. Key synergies included well drilling and completion cost reductions of $200/lateral ft across more than 2,000 locations in the Midland basin, and administrative savings of $30mn-40mn/yr. Diamondback is also looking at selling non-core assets. These plans are all on track, the firm says. Diamondback's 2019 cost guidance of $785/lateral ft for the Midland basin is a saving of $215/lateral ft compared with Energen's second-quarter 2018 cost. That implies it has already achieved 95pc of the target laid out at the time of the deal. "The benefit of size, scale and buying power on service costs has been greater than originally anticipated," chief operating officer Michael Hollis says. Diamondback expects additional savings of $150mn this yearin the Midland basin. The firm expects to lower well costs in the Delaware basin by about 7pc this year compared with 2018, saving $50-60/lateral ft. And it expects "even more capital, operating, midstream and mineral synergies,"Hollis says. _________________________________________________________________ More oil and gas pipelines in the Permian Basin will boost both production and safety West Texas' Permian Basin is a shining example of America's energy success story. One of the world's vastest reserves of oil and natural gas, the region's production dates back to the early 1900s and some of the country's first wildcatters. Over its long history, the Permian Basin has consistently defied expectations, buoyed by emerging technology that continues to unlock output capabilities. Today, nearly a century after the area's first well was drilled, the Permian shows no signs of slowing. Drillers have forecast their production in the Permian Basin will double in the next four years, a remarkable achievement that underscores the efficiency of modern extraction capabilities. Citigroup energy analyst Eric Lee has forecast Permian Basin production by 2020 at 5 million barrels of oil per day, climbing to 8 million per day by 2023. That's more oil than the entire United States produced just six years ago. This growth is no coincidence; it's the result of prudent policies and farsighted infrastructure investment. Recognizing the Permian's potential, developers and regulators have worked together to help deploy new pipelines. Francisco Blanch, head of commodities and derivatives at Bank of America Merrill Lynch, has said he expects pipeline transportation capacity in the region to triple from 3 million barrels per day last year to 9 million per day by 2021. Midstream infrastructure shortages once choked production on the Permian Basin. Only last year, the Wall Street Journal reported that the region's shale output had so far surpassed its transportation capacity that drillers were halting operations amid bottomed-out prices. The area boasted some of the nation's lowest spot prices simply due to limited means of moving products to market, creating a microcosm in which supply far exceeded demand — even though there was plenty of demand across the country and the world. Already, new pipelines that reach the Permian Basin have helped to relieve gluts at production sites. Last month, crude inventories hit a four-month low after a converted pipeline began moving oil to the Gulf Coast. As Reuters reported, inventory fell to 15 million barrels after doubling in size since June, 2018. That is an important accomplishment to help sustain the United States' march toward energy security. Last year, the U.S. surpassed Russia and Saudi Arabia to become the world's largest producer of oil and natural gas. This year the U.S. Department of Energy predicted that our country will become a net energy exporter in 2020 for the first time in nearly seven decades. These historic milestones are due not only to our vast energy resources, the technology to utilize them and smart policies to bring them online, but also to farsighted infrastructure investment, which is a public-private achievement. Pipelines are not only the most efficient, and therefore market viable, option to move energy products, they are also the safest. Compared to alternative overland options, like rail and truck, pipelines have the highest success rate of any energy transportation channel. Balanced regulation, which prioritizes safety and practicality, helps create an environment conducive to pipeline deployment and making these systems even safer. It's important policymakers stay the course and not kowtow to anti-fossil fuel special interests, many of whom wish to keep oil and gas in the ground. The Permian Basin offers a textbook example of the possibility when prudent regulation meets farsighted investment. Pipeline capabilities in the region have already begun to stimulate further infrastructure development, helping unclog impasses that once stifled growth. Last month, the Federal Energy Regulatory Commission gave the go-ahead to construction of the Calcasieu Pass LNG export terminal in Louisiana. Along with similar facilities, like Energy Transfer's proposed LNG project in Lake Charles, La., the terminal will help deliver nearly 9 million cubic feet per day of U.S. natural gas to our allies abroad. Investment in refinery plants is higher in Texas than anywhere else in the country. That progress spells good-paying jobs, economic development and long-term energy independence, locally and nationally. There is a lesson for policymakers in the Permian Basin's success: Put aside ideological rhetoric. Invite all sides to the table to engage in constructive dialogue. And prioritize our country's midstream infrastructure. Doing so will help establish our communities and our country on firm footing toward energy security. Bill Godsey is owner and president of Geo Logic Environmental Services and a former geologist for the Texas Railroad Commission. He wrote this column for The Dallas Morning News. _________________________________________________________________________________ Rystad Energy: E&P firms, awash in cash, could gain more The world’s publicly listed oil and gas exploration and production companies are bringing in cash at the best rate ever witnessed, even though oil prices have only partially recovered from the huge drop suffered in 2014 and 2015, according to Rystad Energy. Free cash flow for public E&P firms skyrocketed last year to nearly $300 billion, marking the return of the “super profit” for industry majors. For these players, this year could turn out to be another blockbuster. “The fact that E&P companies are able to deliver the same shareholder returns despite much lower oil prices points to an impressive increase in profitability,” says Espen Erlingsen, head of upstream research at Rystad Energy. A Rystad Energy analysis of estimated global free cash flows (FCF) for all public E&P companies since 2010 shows that FCF peaked in 2011. In the years between 2012 and 2014, FCF declined as E&P companies took on more commitments and investment budgets increased. In 2015, as the oil price collapsed, FCF was reduced considerably. Since 2015, FCF has recovered gradually to the all-time high we see today. “Our analysis of the latest annual reports from the majors clearly indicates that ‘super profits’ are back for large E&P companies. Free cash flow before financing activities was at a record high in 2018, and the mega profits were typically used to pay down debt and increase payments to shareholders,” Erlingsen added. For 2019, Rystad Energy believes the high free cash flow for E&P companies will continue, hinting that this could be another blockbuster year for these players. Three main factors drive this increased profitability: • Higher oil prices: The oil market has gradually returned to balance after a period of oversupply. • Lower costs: Since 2014 the cost of developing new projects has fallen on average by 30%. • Lower activity: Global investments within the upstream industry have fallen from around $900 billion to $500 billion. Rystad Energy has analyzed recent cash flow statements from all the majors plus Norway’s Equinor to get a better sense of who benefits from these profits. For these companies, cash from operations (defined as revenue, minus all operational costs and taxes) was $211 billion in 2018. Investments totaled $117 billion in 2018, leaving a profit of $94 billion before financing. Out of this, $25 billion was spent on reducing debt, while $69 billion was paid as dividends to shareholders. “This means that almost 70¢ for every dollar in profits generated last year for these companies ended up in shareholders’ pockets,” E Quote Share this post Link to post Share on other sites
Old-Ruffneck + 1,223 er April 3, 2019 8 hours ago, D Coyne said: The EIA production estimates are quite good, especially the monthly output estimates. US oil output is likely to grow more slowly in 2019 than in 2018 as most tight oil producers are trying to reduce the amount of debt they use for new investment and this is likely to reduce completion rates. If you look at actual average well productivity for the majors in the shale plays they are no different from the basin wide average and I doubt they will be more efficient than the top tier independents and their average well cost is likely to be similar. Wow, is about all I can say!! I think the API report is well more accurate than the feds. They EIA tends to bloat numbers in recent years, that's fact. Oil output slowing down as take-away infrastructure nationwide is lacking and can't take on more bbl.'s per day. You can only stuff so much through a pipe. And there's just not enough pipe laid. So reasonable output will slow. Doesn't take a rocket scientist to equate production capacity and take-away. I don't tend to believe everything the EIA says as the whole truth. 1 Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 3, 2019 4 minutes ago, Old-Ruffneck said: Wow, is about all I can say!! I think the API report is well more accurate than the feds. They EIA tends to bloat numbers in recent years, that's fact. Oil output slowing down as take-away infrastructure nationwide is lacking and can't take on more bbl.'s per day. You can only stuff so much through a pipe. And there's just not enough pipe laid. So reasonable output will slow. Doesn't take a rocket scientist to equate production capacity and take-away. I don't tend to believe everything the EIA says as the whole truth. There will be enough pipelines, crude oil and gas gathering, processing facilities built in the Permian that the production volume management for transport wont be an issue. XOM is going to build another pipeline and so will CVX among other companies. I have posted that info on this topic. 2019 and beyond will see a shortage of take away capacity. _______________________________ Cushing-to-Houston pipeline to move Bakken, Midcon, Permian oil A Cushing-to-Houston light oil pipeline project pitched to help Bakken and Midcontinent producers send crude to the Texas Gulf Coast could expand to take additional barrels from the Permian. Magellan Midstream Partners LP and Navigator Energy Services have been holding an open season call for a 300,000 barrel per day pipeline project that would move shale oil sent to Cushing onto refineries or an export site in Houston since early 2019. The partnership recently announced a plan to extend the open season until May 31 to allow for the possibility of adding an oil origination point in Midland, Texas. According to Magellan and Navigator, several potential shippers have requested the evaluation of adding a Midland origin point to the pipeline to help move barrels from the Permian. The Midland origin could be accomplished in part through Voyager’s use of an existing Magellan pipeline that may be idled in the near future as part of Magellan’s announced West Texas refined products pipeline expansions project, Magellan said. Voyager would have the ability to use an existing Magellan terminal in Frost to construct assets needed to connect to the Cushing-to-Houston segment. Magellan owns a 50 percent stake in Seabrook Logistics LLC, a gulf coast export site that will be used to send shale oil from the Bakken, Midcontinent and now potentially the Permian to locations like South Korea. In the past several months, takeaway constraints in the Permian have made oil prices from the region trade at a lower price compared to oil moved through Cushing. However, a recent update from the U.S. Energy Information Administration shows that the price disparity has been eased to additional pipeline capacity from the Permian to Houston. “WTI Midland prices still trade lower than Houston crude prices,” EIA said, “suggesting that the region still faces some takeaway constraints in shipping Permian crude oil to the U.S. Gulf Coast. Most recently,” EIA said on March 26, “the difference has been about $7 per barrel, which is less of a discount that in the middle of 2018.” Navigator Energy’s main focus is on the Midcontinent shale plays of the SCOOP and STACK. The company owns and operates at 250-mile oil gathering network. 1 Quote Share this post Link to post Share on other sites
Old-Ruffneck + 1,223 er April 3, 2019 4 minutes ago, ceo_energemsier said: There will be enough pipelines, crude oil and gas gathering, processing facilities built in the Permian that the production volume management for transport wont be an issue. XOM is going to build another pipeline and so will CVX among other companies. I have posted that info on this topic. 2019 and beyond will see a shortage of take away capacity. There are a couple pipelines running Pecos east then southeast to the gulf. One was 48'' the other was 36'' or 42''. They probably be completed early 2020, just guessing as I didn't ask. The inspectors said more lines out of west Texas in couple years. Takes time. Even S.E. New Mexico has new lines being run, think though the 24'' one I saw by Loving is going to Midland refinery. Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 3, 2019 8 minutes ago, Old-Ruffneck said: There are a couple pipelines running Pecos east then southeast to the gulf. One was 48'' the other was 36'' or 42''. They probably be completed early 2020, just guessing as I didn't ask. The inspectors said more lines out of west Texas in couple years. Takes time. Even S.E. New Mexico has new lines being run, think though the 24'' one I saw by Loving is going to Midland refinery. Sorry , meant to type that 2019-2020 , and beyond will NOT see a shortage of take away capacity 1 Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 4, 2019 Key Buyers Push US Oil Exports to Record Highs Constantly evolving hydraulic fracturing and horizontal drilling technologies have opened up more U.S. petroleum resources than ever imagined. Crude production has boomed 140 percent over the past decade to 12.1 million barrels per day (bpd). During the course of 2018, for instance, output rose nearly 25 percent, even more impressive since domestic prices (WTI) had fallen 23 percent to $46 per barrel by the end of December. This flood of supply is just one of a number of key factors that have allowed U.S. oil exports to rapidly grow. The U.S. oil business was gifted its historic lift at the end of 2015, when a law change allowed crude sales to go beyond neighbor Canada. In addition, U.S. shale oil is a lighter, sweeter grade, and the country’s refining system is mostly configured to process heavier, sour kinds that have historically been imported from Mexico, Canada, and Venezuela. In other words, combined with very high but flat domestic demand, the U.S. has had a surplus of oil to ship abroad. Meanwhile, production cuts from OPEC and Russia (a block that is keeping 1.2 million bpd off the global market) have opened up more market share for other suppliers. As compared to the Brent international benchmark, U.S. crude exporters have been bolstered in recent months by a $8-10 per barrel discount for WTI. They can generally make money when the spread is at least $3-4. Thanks to these factors, U.S. crude oil exports have accompanied production in reaching record highs. Sales have even surpassed 3.6 million bpd in recent weeks. For total crude and products, the U.S. has been exporting around 8.2 million bpd. U.S. crude oil exports reached 24 nations in December. South Korea and Canada have been the two primary buyers, taking in 40 percent of total sales in December (see Figure). The UK and Netherlands have also been taking in more than expected. Source: EIA But the essential goal for the U.S. of course is to better supply the fast growing Asian markets, namely China and India. China is the obvious prime target because it is now the largest oil importer in the world, with crude purchases at 10.3 million bpd in February. Effectively installed in June 2018, however, the U.S-China trade row has been a critical obstacle. China has not officially tariffed U.S. crude but purchases have still plummeted due to CCP pressure on domestic importers. Up until last June, China had accounted for over 20 percent of all U.S. crude exports, but this sunk to less than 4 percent by the end of December. Even more bearish, U.S. President Trump recently stated that tariffs could remain on China for “a substantial period of time.” Now taking just 8 percent of U.S. crude, India’s plan to lower purchases from U.S.-sanctioned Iran could open the door more for U.S. exporters. The current speculation, however, is that the largest buyers of Iranian crude, including China and India, will receive waivers from the Trump administration again once the current ones expire in early May. As for the 1 million bpd of U.S. gasoline exports, neighbor Mexico has been taking around 60 percent. Mexico (21 percent), Brazil (13 percent), and Chile (7 percent) were the main buyers of the 1.4 million bpd of U.S. exports of distillate fuels in December. And Japan purchased 33 percent of the 1.6 million bpd of U.S. natural gas liquids shipped abroad, with Canada second at 15 percent and Mexico third at 9 percent. Total weekly U.S. crude and product exports should be consistently outpacing imports starting in 2020. The U.S. is now expected to surpass Saudi Arabia as the largest oil exporter before the end of this year. Democratic with a market economy, U.S. oil remains attractive to those nations seeking to buffer the outsized influence of OPEC and Russia. To reach full potential, however, the U.S. needs more pipelines and deeper and wider ports along the Gulf of Mexico to access larger crude carriers. Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 4, 2019 Next US Shale Wave Will Need Fewer Heads, Different Skills U.S. shale oil and gas explorers are once again in the limelight, following the International Energy Agency’s forecast that a “second” shale revolution was on the horizon. The next wave would drive U.S. oil output to 19.6 million barrels per day (bpd) by 2024 up from 15.5 million bpd in 2018, noted the agency that advises some of the biggest, predominantly Western governments on energy related issues. The IEA also forecast that U.S. gross crude exports are "expected to double" over the period making it a net energy exporter, underpinned by efforts of shale explorers. The upbeat assessment, published at the start of the recently concluded IHS Markit CERAWeek 2019 conference, an energy industry jamboree held every March in Houston, Texas, triggered ecstatic dialogues about both the viability and future direction of the industry. Like a broken, albeit on the money record, several commentators at the conference expressed the opinion that should the oil market take a turn for the worse, many shale players with viable acreages could survive at $35-40 per barrel prices. For hidden deep in the IEA’s take on the U.S. shale industry is an accolade that’s not alluded to enough when such quips are made – how process optimization and technological efficiencies are keeping players competitive in a cutthroat industry. Following the oil price slump of 2015-16, visits to fracking sites and onstream wells from the Denver-Julesburg basin and to the Permian would illustrate how things are changing. Seismic studies are now heading beyond 4D, solar panels power personnel quarters, eight wells are often seen producing more oil and gas volumes than 16 previously did, processes and assets are more productive, and unmanned remotely managed rigs, hitherto largely seen offshore, are becoming visible onshore. What’s more drilling times are being reduced and in many cases halved, driven by data obtained from smart sensors. Regina Mayor, Global Sector Head, Energy and Natural Resources at KPMG, says the “second wave” is being powered by a different kind of ingenuity and more agile capital planning. “You cannot escape how exploration and production companies in the shale patch are learning to do more with technology. Agile capital planning means these companies do not have to spend as much, as well as spend differently, and that applies to their hiring patterns and strategies.” Hydrocarbon extraction objective remains the same but given the emerging profound changes in methodology and scope of the process, the type of personnel and their headcount is altering too. Mayor adds: “Headline hiring of manual labor may or may not stall, but empirical evidence suggests that drillers are conducting their operations by deploying fewer heads with a different skill-set, and managing to improve efficiencies ranging from flow rates to health and safety. “Sometimes it's down to something as basic but crucial as controlling the drill-bit. Instead of more onsite personnel, more data scientists and fewer onsite staff are being brought into the equation with dramatically more positive rates of efficiency. Conventional rig workers are becoming digitally savvy engineers.” Furthermore, if a second wave of shale barrels is coming, it might be led by oil majors with the likes ExxonMobil and ConcoPhillips leading the charge, who even tend to buck seasonal deceleration in activity. Lai Lou, Senior Analyst for North American Shale Research at Rystad Energy, says 2018 offers a case in point. “For instance, towards the end of 2018, there is evidence that seasonal activity deceleration might have started in all major plays except Eagle Ford, including a considerable slowdown in Bakken and Niobrara based on our estimation. “But some major operators appear to have bucked the general slowdown. The largest operator – ExxonMobil – experienced a strong uptick in October, making it one of the months with the highest number of fracked wells in this period. Energen Corporation also appeared unaffected by the slowdown.” In terms of absolute count, the reduction in the number of fracking jobs for top 10 operators came in around 10 percent from June to October 2018, while the corresponding percentage for the remaining operators was as high as 48 percent in the same timeframe. Available empirical and anecdotal evidence should not come as a surprise, says Mayor. “Big oil’s incremental push into the shale patch is likely to be less capital intensive, and they’ll manage the cycles more quickly and effectively. As the majors lead the shale charge, I remain bullish they would deploy state-of-the-art solutions.” Every aspect is being catered to via integrated well and site asset management drives initiated by oilfield services (OFS) companies at competitive prices and contracts, details of which are rarely made public for individual project sites. Technological solutions and workforce upskilling – whether the end user is an OFS firm or an E&P company – is assisted by kit from vendors such as Emerson, Schneider Electric, ABB and Honeywell. Peter Herweck, Executive Vice President of Industrial Automation at Schneider Electric, says the next shale wave will not just be about “surviving but thriving.” “If you are talking about integrated asset management, new software and hardware is required and deployed. We see tremendous opportunities as the oil industry optimizes and the natural gas business experiences renewed interest in the global economy’s march to a low carbon future. The industry is changing – so is the workforce and the advanced tools it deploys. There is no turning back.” So it is settled then – manual, mechanical and digital skills-sets have started overlapping like never before. Demand for multi-skilled, digitally savvy oil industry workers required to spend quicker turnaround times on the rig to kick-start things and more time indoors making the well maximize throughput is perhaps set to rise. Quote Share this post Link to post Share on other sites
ceo_energemsier + 1,818 cv April 4, 2019 Private equity firm buys Permian Basin-focused Oryx Midstream in $3.6 billion deal New York private equity firm Stonepeak Infrastructure Partners bought Permian Basin-focused pipeline operator Oryx Midstream in a $3.6 billion deal. The two companies announced the deal on Tuesday with Stonepeak buying all of Oryx's assets. With more than 1,200 miles of pipeline and 2.1 million barrels of storage, Oryx is touted as the largest privately-held crude oil pipeline and storage terminal operator in the Permian Basin of West Texas and New Mexico. "As we begin our next chapter and new partnership with Stonepeak, we look forward to the operational and capital support they will provide our team as we continue to aggressively grow our footprint in the Permian Basin," Oryx Midstream CEO Brett Wiggs said in a statement. Under the deal with Stonepeak, Oryx will be able to keep its name and headquarters in Midland. Oryx was in the middle of an expansion project at the time of the sale. Once complete, the company will be able to move 900,000 barrels of crude oil per day for its 20 customers. In a statement, Stonepeak partner and energy business head Jack Howell described Oryx as the most attractive Permian Basin midstream company that the private equity firm had evaluated. "Our critical focus will be on continuing to provide Oryx's diversified customer base with best in class service offerings to accommodate their growing production while also pursuing new commercial opportunities across the value-chain," Howell said. Oryx was launched and owned by affiliates of Quantum Energy Partners, Post Oak Energy Capital, Concho Resources, WPX Energy and other investors in 2013. The Midland pipeline operator recently completed construction on the first phase of a crude oil gathering system in an area of the Permian Basin known as the southern Delaware Basin, which includes parts of southern New Mexico and West Texas 2 Quote Share this post Link to post Share on other sites
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