natural gas prices at a 28 week low, active oil rigs at a 37 week low...

oil prices finished the week higher for the 4th time in 5 weeks, mostly on new US sanctions on Venezuelan oil exports, which were also accompanied by associated distortions in refinery product pricing and even greater spikes in grades of oil seen as replacements for Venezuelan crude​...after falling 0.7% to $53.69 per barrel on concerns over a global economic slowdown last week, prices for US oil for March delivery fell $1.70, or 3.2%, to $51.99 on Monday, as weak industrial earnings reports from both China and the United States renewed fears of a global ​downturn that would dampen fuel demand...oil prices steadied at the start of trading on Tuesday, and then jumped more than 2 percent later, after the United States imposed sanctions on state-owned Venezuelan oil company PDVSA, with March oil finishing up $1.32 at $53.31 a barrel...as Gulf Coast refiners scrambled to find more costly replacement barrels for the cheap heavy sour Venezuelan crude they were ​optimized for, US oil prices rose another 92 cents to $54.23 a barrel Wednesday, after the weekly EIA report showed a smaller than expected increase in U.S. crude inventories and an unexpected drop in gasoline supplies...after oil prices rose to two-month high of $55.37 a barrel on Thursday morning, economic concerns​ again​ overtook the rally that afternoon, when Trump’s suggestion that a trade deal with China could be postponed triggered a move nearly 3% lower, with oil ending the day down 44 cents to $53.79 a barrel, but still finish​ing the month of January 18% higher, the largest gain for that month on record...oil prices then jumped with the stock market on Friday morning after the Labor Department reported a larger than expected surge in US employment and continued rallying throughout the day, first on signs that U.S. sanctions on Venezuelan exports had tightened supply and then after weekly data showed U.S. drillers cut back on the number of oil rigs they were running, with oil finishing $1.47 higher at $55.26 a barrel...​thus US crude prices for March ended the week nearly 3% higher, while Brent crude for April, the currently traded international oil benchmark, finished at $62.75​ a barrel, ​a gain of $1.16 or 1.8% from the prior week's close...

natural gas prices, meanwhile, were down 4 out of 5 days in falling to a six month low, despite the coldest weather outbreak in years, as gas traders looked ahead to forecasts of a quick weekend warm-up and the likelihood that we'd finish the heating season without a supply crisis...after ending last week down 8.7% at $3.178 per mmBTU, prices for natural gas for February delivery fell another 8% or 26.7 cents on Monday alone, on a pronounced drop in the Gas Weighted Degree Day forecasts for the beginning of February...that February gas contract rebounded 3.9 cents on ​renewed ​cold mid-February risks to expire at $2.950 per mmBTU, while contracts for March natural gas delivery, which had ended last week priced at $3.072 per mmBTU, rose 3.0 cents to 2.903 per mmBTU, after ​having dropped 19.9 cents on Monday...prices for March gas then fell daily from there, first by 4.9 cents on Wednesday, then by 4 cents on Thursday, and by 8 cents on Friday​,​ to end the week at $2.734 per mmBTU, the lowest close since July 23rd of 2018...

with natural gas prices now back at a 6 month low, we'll include a graph of the recent price trajectory, to show you all what the ​latest ​​move has looked like..

the above graph is a Saturday afternoon screenshot of the interactive US natural gas price graph at Daily FX, an online platform that provides trading news, charts, indicators and analysis of the markets...each bar on the above graph represents natural gas prices for a day of trading between mid July of 2018 and Friday of this week, wherein the green bars represent the days when the price of natural gas went up, and red bars represent the days when the price of natural gas went down...for green bars, the starting natural gas price at the beginning of the day is at the bottom of the bar and the price at the end of the day is at the top of the bar, while for red or down days, the starting price is at the top of the bar and the price at the end of the day is at the bottom of the bar...barely visible on this "candlestick" style graph are the faint grey "wicks" above and below each bar, to indicate trading prices during the day that were above or below the opening to closing price range for that day...note that the lighter red & green bars at the bottom of the graph represent the trading volume for each day, which doesn't concern us ​right now, except to note the poor graph design that has natural gas price​ bar​s crossing into the trading volume metrics...

we can see that before October, natural gas prices had stayed below $3 per mmBTU (really all year), and it was only when the possibility of a wintertime natural gas shortage became widely talked about that prices began to move higher...then prices shot up to nearly $5 when November turned cold, and withdrawals of gas from storage were much above normal...then, with the milder temperatures and smaller withdrawals from storage during December and January, natural gas traders figured that the crisis had passed, and hence natural gas prices have since fallen back to below their previous baseline...ultimately, if prices ​should ​hold at these levels, this ​would be accompanied by reduced drilling, setting us up for the same go-round next year...

the natural gas storage report for the week ending January 25th from the EIA indicated that the quantity of natural gas in storage in the US fell by 173 billion cubic feet to 2,197 billion cubic feet over the week, which meant our gas supplies were 14 billion cubic feet, or 0.6% above the 2,211 billion cubic feet that were in storage on January 26th of last year, but still 328 billion cubic feet, or 13.0% below the five-year average of 2,525 billion cubic feet of natural gas that have typically been in storage as of the 4th weekend in January....this week's 173 billion cubic feet withdrawal from US natural gas supplies was a bit less than the consensus estimate that 183 billion cubic feet ​of stored gas ​would be needed, but it was somewhat more the average of 150 billion cubic feet of natural gas that have been withdrawn from US gas storage during the same week of January over the last 5 years....67 billion cubic feet was pulled from natural gas supplies in the Midwest ​during the week, and hence the region's natural gas deficit increased to 8.6% below normal for this time of year, while withdrawals from other regions was about on par with normal...natural gas supplies in the Pacific region, which were only down 7 billion cubic feet this week, still remain 26.4% below their five year average for this time of year, the worst deficit of any region...

The Latest US Oil Supply and Disposition Data from the EIA

this week's US oil data from the US Energy Information Administration, reporting on the week ending January 25th, indicated that due to a significant pullback in US oil refining, we still managed a small addition of surplus oil to our commercial crude supplies, despite a big drop in our crude oil imports...our imports of crude oil fell by an average of 1,108,000 barrels per day to an average of 7,083,000 barrels per day, after rising by an average of 644,000 barrels per day the prior week, while our exports of crude oil fell by an average of 91,000 barrels per day to an average of 1,944,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,139,000 barrels of per day during the week ending January 25th, 1,017,000 fewer barrels per day than the net of our imports minus exports during the prior week...over the same period, field production of crude oil from US wells was estimated to be unchanged at a record 11,900,000 barrels per day, so our daily supply of oil from the net of our trade in oil and from wells totaled an average of 17,039,000 barrels per day during this reporting week...

meanwhile, US oil refineries were using 16,463,000 barrels of crude per day during the week ending January 25th, 586,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period 131,000 barrels of oil per day were reportedly being added to the oil that's in storage in the US....thus, this week's crude oil figures from the EIA would seem to indicate that our total working supply of oil from net imports and from oilfield production was 445,000 more barrels per day than the oil that was added to storage plus what refineries reported they used during the week....to account for that disparity between the supply of oil and the disposition of it, the EIA inserted a (-445,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as "unaccounted for crude oil"....(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....  

further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 7,662,000 barrels per day last week, which was 4.5% less than the 8,020,000 barrel per day average that we were importing over the same four-week period last year.... the 131,000 barrel per day increase in our total crude inventories was entirely a 131,000 barrel per day addition to our commercially available stocks of crude oil, while the oil stored in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported unchanged at 11,900,000 barrels per day because the rounded estimate for output from wells in the lower 48 states was unchanged at 11,400,000 barrels per day, while a 2,000 barrel per day decrease to 489,000 barrels per day in oil output from Alaska was not enough to change the rounded national total...last year's US crude oil production for the week ending January 26th was at 9,919,000 barrels per day, so this week's rounded oil production figure was 20.0% above that of a year ago, and 41.2% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...     

US oil refineries were operating at 90.1% of their capacity in using those 16,463,000 barrels of crude per day during the week ending January 25th, down from last week's 92.9% of capacity, but remarkably still the highest refinery capacity utilization rate for the last weekend of January since 1999....likewise, the 16,463,000 barrels per day of oil that were refined this week were again at a seasonal high for the date for the 31st time out of the past 35 weeks, and 2.8% higher than the 16,013,000 barrels of crude per day that were being processed during the week ending January 26th, 2017, when US refineries were operating at 88.1% of capacity... 

even with the big drop in the amount of oil being refined, the gasoline output from our refineries was a quite a bit higher, rising by 300,000 barrels per day to 9,904,000 barrels per day during the week ending January 25th, after our refineries' gasoline output had increased by 20,000 barrels per day the prior week....with the big increase in this week's gasoline output, our gasoline production was 3.5% higher than the 9,567,000 barrels of gasoline that were being produced daily during the same week last year....meanwhile, refineries' production of distillate fuels (diesel fuel and heat oil) decreased by 185,000 barrels per day to 5,019,000 barrels per day, after that output had decreased by 208,000 barrels per day the prior week....however, despite those decreases, this week's distillates production was still 8.8% higher than the the 4,613,000 barrels of distillates per day that were being produced during the week ending January 26th, 2018.... 

even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week fell by 2,235,000 barrels from last week's record high to 257,380,000 barrels by January 25th, after jumping by a near record of 19,619,000 barrels over the prior three weeks....our gasoline supplies fell this week largely because the amount of gasoline supplied to US markets rose by 696,000 barrels per day to 9,564,000 barrels per day, after increasing by 303,000 barrels per day the prior week, while our imports of gasoline fell by 38,000 barrels per day to 523,000 barrels and as our exports of gasoline rose by 60,000 barrels per day to 607,000 barrels per day....despite this week's decrease, our gasoline inventories are still at a seasonal high for the last weekend of January, 6.2% higher than last January 26th's level of 242,060,000 barrels, and roughly 5% above the five year average of our gasoline supplies for this time of the year...

with the decrease in our distillates production, our supplies of distillate fuels decreased for the 13th time in nineteen weeks, falling by 1,122,000 barrels to 141,270,000 barrels during the week ending January 25th, after our distillates supplies had decreased by 617,000 barrels over the prior week...our distillates supplies decreased this week because our exports of distillates rose by 213,000 barrels per day to 1,192,000 barrels per day while our imports of distillates fell by 220,000 barrels per day to 135,000 barrels per day, even as the amount of distillates supplied to US markets, a proxy for our domestic demand, fell by 546,000 barrels per day to 4,122,000 barrels per day...even with this week's decrease, our distillate supplies were still 2.4% above the 137,900,000 barrels that we had stored on January 26th, 2017, even as they remained roughly 2% below the five year average of distillates stocks for this time of the year...

finally, with refineries seasonally slowing, our commercial supplies of crude oil increased for the 3rd time in​ the past​ 9 weeks, rising by 919,000 barrels over the week, from 445,025,000 barrels on January 18th to 445,944,000 barrels on January 25th...however, with a run of 10 large weekly increases before the recent smaller decreases, our crude oil inventories are still roughly 7% above the five-year average of crude oil supplies for this time of year, and more than 30% above the 10 year average of crude oil stocks for the last weekend  of January, with the disparity between those figures arising because it wasn't until early 2015 that our oil inventories first rose above 400 million barrels...since our crude oil inventories had mostly been rising since this past Fall, after falling until then through most of the prior year and a half, our oil supplies as of January 25th were thus 6.6% above the 418,359,000 barrels of oil we had stored on January 26th of 2018, while  still remaining 9.8% below the 494,762,000 barrels of oil that we had in storage on January 27th of 2017, and 5.4% below the 471,344,000 barrels of oil we had in storage on January 29th of 2016...    

This Week's Rig Count

US drilling activity, as evidenced by the number of drilling rigs active at the end of the week, fell by double digits for the second time in 3 weeks this past week, and is now at it's lowest level since August​, ​probably due to the depressed oil prices ​in recent months​,​ and ​due to ​the ​7.1 month backlog of uncompleted wells....Baker Hughes reported that the total count of rotary rigs running in the US fell by 14 rigs to 1045 rigs over the week ending February 1st, which was still 99 more rigs than the 946 rigs that were in use as of the February 2nd report of 2018, but down from the shale era high of 1929 drilling rigs that were deployed on November 21st of 2014, which was the week before OPEC announced their attempt to flood the global oil market...  

the count of rigs drilling for oil fell by 15 rigs to 847 rigs this week, which was the lowest oil rig count since May 18th, but still 82 more oil rigs​ ​than were running a year ago, while it was well below the recent high of 1609 rigs that were drilling for oil on October 10th, 2014...at the same time, the number of drilling rigs targeting natural gas bearing formations increased by 1 rig to 198 natural gas rigs, which was also 17 more rigs than the 181 natural gas rigs that were drilling a year ago, but way down from the modern high of 1,606 natural gas targeting rigs that were deployed on August 29th, 2008...

drilling in the Gulf of Mexico decreased by 1 rig to 19 rigs this week, with all of those​ remaning​ deployed offshore from Louisiana...that was still 3 more Gulf rigs than were drilling a year earlier, when 15 rigs were deployed offshore from Louisiana and a rig was also active offshore from Texas....since there is still no other offshore drilling off either coast or off Alaska at this time, nor was there during the same week of 2018, this week's Gulf of Mexico totals are again identical to the overall US offshore totals...

the count of active horizontal drilling rigs decreased by 7 rigs to 925 horizontal rigs this week, which was still 117 more horizontal rigs active than the 808 horizontal rigs that were in use in the US on February 2nd of last year, but was down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014....at the same time, the directional rig count decreased by 2 rigs to 57 directional rigs this week, which was also down from the 72 directional rigs that were in use during the same week of last year...in addition, the vertical rig count decreased by 5 rigs to 63 vertical rigs this week, which was also down from the 66 vertical rigs that were operating on February 2nd of 2018... 

the details on this week's changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes...the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins...in both tables, the first column shows the active rig count as of February 1st, the second column shows the change in the number of working rigs between last week's count (January 25th) and this week's (February 1st) count, the third column shows last week's January 25th active rig count, the 4th column shows the change between the number of rigs running on Friday and those running before the equivalent weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 2nd of February, 2018...    

the 4 rig increase in the Mississippian shale, which for the purpose of this drilling report, straddles the Kansas - Oklahoma border, is problematic, considering the 1 rig decrease in Kansas and the 4 rig decrease in Oklahoma; however, since Kansas is left with no activity, it's evident that those Mississippian rigs were added in Oklahoma, displacing rigs in other Oklahoma basins, not all of which ​appear to be named above...for starters, since activity in Texas Oil District 10 (the panhandle​ area​) was unchanged, that means the 3 Granite Wash rigs that were shut down were pulled out of Oklahoma, in addition, Oklahoma also lost rigs in the Cana Woodford and Arkoma Woodford...still, to end up down 4 rigs after the addition of 4 Mississippian rigs, Oklahoma​ drillers​ still had to have shut down 3 more rigs in basins not tracked separately by Baker Hughes...meanwhile, all three Permian rigs were pulled out of Texas; two from Texas Oil District 8, which is the core Permian Delaware, and one from Texas Oil District 8A, which is the northern Permian Midland...for ​changes in ​natural gas, one natural gas rig was pulled out of the Arkoma Woodford, while two natural gas rigs were added in 'other' basins not tracked separately by Baker Hughes...​and ​in addition to the major producing states shown above, note that Alabama had the only two rigs that had been drilling in the state shut down this week; a year ago they had one rig running; that Montana also had its only rig shut down, after seeing as many as 4 running in the state at the beginning of December, and that a single land based rig was ​started back​ up​ in Florida, where there has been on and off drilling with one rig since May of the past year..

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Ohio moves into top five for recoverable shale natural gas reserves - Ohio has moved into the top five for recoverable shale natural gas reserves in the United States.Data released by the U.S. Energy Information Administration shows the state saw a 24.5 percent increase in proved shale gas reserves from 2016 to 2017, bringing it to 25.6 trillion cubic feet. That moves Ohio past Oklahoma and behind only Pennsylvania, Texas, West Virginia and Louisiana.Proved reserves is a measure of oil and natural gas that can be recovered in the future. JobsOhio and economic development groups have said that a robust shale industry will create jobs in Appalachia and reduce energy costs, making it cheaper for other businesses to invest here.Before development of the Utica Shale, Ohio’s peak year for natural gas production was in 1984 at 186 billion cubic feet. In 2017, it was 1.7 trillion cubic feet, said Dan Alfaro, spokesman for Energy in Depth, an advocacy group launched by the Independent Petroleum Association of America.What the EIA data tell us is Ohio’s status as a premiere gas-producing state is secured," Alfaro said. "Most importantly, the trends for the natural gas market bode well for continued economic growth and investment in the region."Proved reserves of both U.S. crude oil and natural gas broke records from the year before – crude jumped 19.5 percent to 39.2 billion barrels and surpassed the previous peak level of 39 billion barrels set in 1970. Proved reserves of natural gas were up 36.1 percent to reach 464.3 trillion cubic feet in 2017, surpassing the 388.8 trillion cubic feet record set in 2014.

Rig Count Slips to 14 in Ohio's Utica – The number of rigs operating across Ohio’s Utica shale dropped to 14 during the week ended Jan. 26, according to the latest data from the Ohio Department of Natural Resources. The rig count during the previous week stood at 16, according to ODNR. Last week, the agency issued 10 permits for horizontal wells across the Utica, all of them to Ascent Resources Utica LLC of Oklahoma City. Ascent secured eight permits for Guernsey County and two permits for new wells in Jefferson County. As of Jan. 26, ODNR has issued 2,992 horizontal well permits in the Utica. Agency data show that 2,517 of these wells are drilled and 2,138 wells are in production across the state. The majority of these wells are in the southern portion of the play, where geological pressure is more pronounced and the wells generally more productive. There have been no new permits issued in the northern tier of the Utica play – that is, Columbiana, Mahoning and Trumbull counties – since July. The last permit awarded in the northern region was on July 24, when Hilcorp Energy Co. secured two permits to drill horizontal wells in Fairfield Township in Columbiana County. Nor were there any new permits issued in nearby Lawrence and Mercer counties in western Pennsylvania, according to the Pennsylvania Department of Environmental Protection.

Settlement with Patriot Water might be end of gas and oil wastewater treatment in city - Youngstown Vindicator - Though a lawsuit filed by an environmental group against the company Patriot Water is still pending, the recent settlement by Warren would suggest Patriot’s experiment in treating wastewater from the gas and oil industry and have it end up in the Mahoning River might be over. An attorney for Freshwater Accountability Project of Grand Rapids, Ohio, and Warren Law Director Greg Hicks say Warren resolved its part of the case by agreeing to pay $116,616 of Freshwater’s legal fees and no longer allowing Patriot to discharge “drilling mud,” which is wastewater from the gas and oil industry, into the city sewer system, as it did starting in 2011. Patriot stopped discharging wastewater into Warren sewers June 16, 2017, after the Freshwater suit was filed June 27, 2017, and has not resumed.The plant is still open, however, its president, Andrew Blocksom, said earlier this month. Blocksom said he could not comment on the matter because legal action with Freshwater Accountability is still pending.Hicks said he does not believe Patriot will ever be able to resume discharging gas and oil wastewater into Warren’s treatment facility.Atty. Megan Hunter of Akron, who represents Freshwater, said the settlement with Warren bars the city from accepting total dissolved solids, total suspended solids and barium from Patriot above a certain limit. That effectively stops the city’s wastewater treatment plant from receiving drilling muds, which were causing significant problems for the treatment plant.

Enbridge restores some natgas flows on damaged TETCO pipe in Ohio (Reuters) - Enbridge Inc restored southbound natural gas flows over the weekend through parts of its Texas Eastern (TETCO) pipeline in Ohio that were damaged in an explosion last week. The blast last Monday forced drillers using the pipe to reduce output in the Marcellus and Utica shale in Pennsylvania, Ohio and West Virginia, the nation's biggest gas producing region, during the week before a polar vortex is expected to freeze the eastern half of the United States. Total output in the Marcellus and Utica returned to 30 billion cubic feet per day (bcfd), the same as before the pipe blast, which cut production there by around 1 bcfd last week, according to financial data provider Refinitiv. TETCO told customers in a notice late Sunday that it increased capacity on a couple of lines around the blast site, but could not say when it would restore full service through the area. Those flows will help deliver much-needed fuel to utilities in the U.S. Midwest as temperatures plunge later this week, boosting gas demand to a forecast daily record high, according to Refinitiv data. Before the Jan. 21 blast, which injured two people and damaged three homes near Summerfield in Noble County in southeastern Ohio, about 1.2 bcfd of gas was flowing south on TETCO from Ohio toward the Gulf of Mexico, according to Refinitiv. After the explosion, however, TETCO started moving up to 0.3 bcfd of gas north into Kentucky and Ohio. But with southbound service restored through parts of the Ohio blast site, about 0.3 bcfd was expected to flow south on the pipeline on Monday. Enbridge said the damaged section of 30-inch (76.2-cm) pipe was built in 1952-53. The 9,029-mile (14,531-km) TETCO pipeline was designed to carry gas from the U.S. Gulf Coast and Texas to high-demand markets in the mid-Atlantic and Northeast, according to the company's website. TETCO became bidirectional over the past five years, enabling it to also carry gas from the Marcellus and Utica shale, where production is growing rapidly, to markets in the U.S. Midwest and Gulf Coast. 

Air Pollution Permit Appeal Filed Against PTT Global Cracker Chemical Plant in Belmont County OH — A national environmental group and three partner organizations are challenging the state’s decision to issue an air permit-to-install for a proposed petrochemical complex in Belmont County. The Sierra Club and its partners filed an appeal Friday with the Environmental Review Appeals Commission seeking to have the permit issued on Dec. 21 vacated. If it is not overturned, the permit will allow Thailand-based PTT Global Chemical and its partner, Daelim Industrial Co. LLC of South Korea, to build an ethane cracker plant that is projected to process 1.5 million tons of ethane from the local natural gas stream annually. Cracker plants use ethane to create ethylene, a component of plastics and chemicals such as antifreeze, solvents and cleaners, as well as many consumer products including textiles, adhesives and paints. Ethane is an abundant part of the natural gas stream found in the Utica and Marcellus shales that underlie much of Eastern Ohio and parts of West Virginia and Pennsylvania.Proponents of the facility say it would bring thousands of construction jobs and hundreds of permanent positions to the Ohio Valley and would attract additional related industry to the region.PTT and Daelim have invested millions of dollars in design work and planning, and to buy property at the proposed site at Dilles Bottom. However, they still have not committed to building the project, which could cost as much as $10 billion. Opponents — such as the Sierra Club and its appeal partners the Center for Biological Diversity, Earthworks and the Freshwater Accountability Project along with some local residents – believe the plant would cause air and water pollution that would endanger the surrounding environment, public health and the overall climate. They say it would emit harmful amounts of particulate matter and dangerous chemicals, including benzene, nitrogen oxides, volatile organic compounds, carbon dioxide and other greenhouse gases.

A Field Guide to the Petrochemical and Plastics Industry – DeSmog - The shale gas industry has been trying to build demand for fossil fuels from its fracked oil and gas wells by promoting the construction of a new petrochemical corridor in America's Rust Belt and expanding the corridor on the Gulf Coast. To help demystify terms like “natural gas liquids” and “cracker plants,” DeSmog has begun building a guide to some of the equipment and terms used in the plastics and petrochemical industries.This guide, which will expand over time, is intended to serve as an informal glossary of sorts and an introduction to what happens to fossil fuels that are transformed into chemicals, plastics, vinyl, Styrofoam and a variety of other materials. This field guide is part of Fracking for Plastics, a DeSmog investigation into the proposed petrochemical build-out in the Rust Belt and the major players involved, along with the environmental, health, and socio-economic implications.These fossil fuels have a significant global warming impact of their own. The methane leaks associated with the natural gas drilling and distribution industry are so pronounced that many experts say burning natural gas for electricity is worse for the climate than burning coal.While hydrocarbons that are used as raw materials for petrochemical products aren’t burned (and therefore don’t release carbon dioxide into the atmosphere), that leaky infrastructure still results in methane pollution. Methane itself is a powerful greenhouse gas, capable of warming the climate 86 times as much as an equal amount of carbon dioxide over the first two decades after it’s released to the atmosphere.Making petrochemicals also requires a huge amount of energy — some of the largest petrochemical plants like crackers may have their own power plants on site — and that energy comes from burning fossil fuels. Executives from major oil and gas companies, wary of the impacts that carbon dioxide pollution controls might have on their long-term prospects, have told investors that they see petrochemicals as the place where demand for fossil fuels will continue to grow, even if the world takes serious action on climate change.

Penn State professors present collaborative documentary project, book on fracking - The Daily Collegian Online -In 2018, Penn State professors Julia Spicher Kasdorf and Steven Rubin released their book and project titled, “Shale Play: Poems and Photographs from the Fracking Fields.”Kasdorf, a professor of English and women’s studies at Penn State, and Rubin, a documentary photographer and associate professor of art, combined Rubin’s documentary photography and Kasdorf’s poetry to release their investigative book.Rubin’s photographs have been published in The New York Times Magazine, National Geographic, Time, Newsweek, The Village Voice and more. He has traveled through many areas of the world working as a freelance journalist.Kasdorf has published four books of poetry: “Sleeping Preacher,” “Eve’s Striptease,” “Poetry in America” and now “Shale Play.” She also has a few poetry awards, such as Agnes Lynch Starrett Poetry Prize and a Pushcart Prize.The book covers the impact of fracking along the Marcela Shale, an area that has a high concentration of oil and gas in the rock and extends through mainly New York, Ohio, West Virginia and Pennsylvania. Rubin said this is where the term “Shale Play,” stems from — the industry’s term on the extraction in the Marcella Shale. The duo focused solely on the impact in Pennsylvania after seeing the effects of extraction with their own eyes.

Impact fee collected from gas drillers expected to reach new record in Pa. -- The fee Pennsylvania collects from natural gas drillers is expected to reach a record $247 million this year, according to figures released Thursday by the state’s Independent Fiscal Office.Each year, Pennsylvania drillers are required to pay what’s known as an “impact fee” for every well they drill. The cost hinges on the type of well and number of years it’s been in operation. The funds get distributed to state agencies and local governments, with those in heavily drilled regions receiving the most money.The IFO cites two reasons for the projected uptick in revenue, which is expected to come in $37 milion above the previous year. For one, the 779 new wells drilled in 2018 will offset a drop in revenue from older wells, because the fee declines as wells age.Furthermore, some low-producing “stripper” wells have historically not paid the fee. But a recent state Supreme Court decision means potentially hundreds more will now have to comply.Pennsylvania has an impact fee in lieu of a severance tax, which is common in other energy-rich states. Such a tax would collect revenue based on the amount of natural gas a well produces.Pennsylvania lawmakers have debated enacting a severance tax for a decade. It’s supported by Gov. Tom Wolf, a Democrat, and a tax could result in higher revenue for the state.But the natural gas industry and Republican leaders h ave pushed against a severance tax, saying it could harm investment and job growth.

Pennsylvania governor seeks natural gas tax to raise $4.5 billion (Reuters) - Pennsylvania Governor Tom Wolf on Thursday proposed a tax on extracting natural gas to pay for his plan to spend $4.5 billion over the next four years to improve the state’s infrastructure. The state legislature, however, has refused to approve the tax over the past couple of years. Wolf said Pennsylvania is the only state in the country without a severance tax on extracting natural gas. Pennsylvania is the second biggest gas-producing state behind Texas. The state produces about 18 billion cubic feet per day (bcfd) from the Marcellus and Utica shale basins, which is a little over 20 percent of nation’s total gas production. One billion cubic feet of gas is enough to supply about 5 million U.S. homes for a day. “With every passing year our state is losing out on the opportunity to reinvest the benefits of these resources to stimulate out economy and move Pennsylvania forward,” Wolf said. The state’s gas industry, however, said the tax is not necessary since the state already has a per well impact fee. The proposed tax would increase if the price of gas rises and would start March 1, 2020. 

PUC sets investigation into shut-down Mariner East 1 pipeline - The Pennsylvania Public Utility Commission’s Independent Bureau of Investigation and Enforcement , which includes the PUC’s Pipeline Safety Division, has launched an investigation including detailed geological surveys at the site of a sinkhole that developed last Sunday along the Mariner East right-of-way on Lisa Drive in West Whiteland. The working Mariner East 1 pipeline was shut down statewide by the PUC within six hours and 44 miles of the pipe was purged. The investigation will “help engineers and geophysical consultants “get a better picture of what’s going on underground,” Nils Hagan-Frederiksen, PUC press secretary, said. “We’re actively monitoring what’s going on. “We’ll use the data to discuss the next steps.” Hagan-Frederiksen said the ME1 pipeline will remain shut down until I & E “says something different.” Geophysical surveys around the Lisa Drive site are scheduled to begin Saturday, and will be closely monitored by pipeline safety engineers from the PUC and geophysical consultants. The testing, which will be used to evaluate underground conditions, is expected to take several days to complete. I&E pipeline safety engineers and geophysical consultants will be on-site monitoring the collection of geophysical data. Results of the testing will be shared with I&E’s engineers and I&E’s geophysical consultants for independent analysis and review. Additionally, PUC engineers and geophysical consultants have been working with municipal officials and Sunoco to monitor and track storm water flow around the incident site, including investigation of storm drains in the area. Analysis of testing results and information from the ongoing safety engineering investigation will be used by I&E as a basis for data-driven discussions about next steps at the Lisa Drive site, along with any other work that I&E believes is necessary. Sunoco is not permitted to resume the transportation of product through ME1 until approval is received from I&E.

Sink Holes Along Mariner East Pipeline are a Risk Now Taken More Seriously - The Pennsylvania Public Utility Commission’s Independent Bureau of Investigation and Enforcement , which includes the PUC’s Pipeline Safety Division, has launched an investigation including detailed geological surveys at the site of a sinkhole that developed last Sunday along the Mariner East right-of-way on Lisa Drive in West Whiteland. The working Mariner East 1 pipeline was shut down statewide by the PUC within six hours and 44 miles of the pipe was purged. The investigation will “help engineers and geophysical consultants “get a better picture of what’s going on underground,” Nils Hagan-Frederiksen, PUC press secretary, said. “We’re actively monitoring what’s going on.” “We’ll use the data to discuss the next steps.” Hagan-Frederiksen said the ME1 pipeline will remain shut down until I & E “says something different.” Lisa Dillinger, Sunoco spokeswoman, responded on Friday. “We will continue to work alongside the Pennsylvania Public Utility Commission’s Bureau of Investigation and Enforcement and its consultants to conduct geophysical testing to determine if additional work is necessary,” Dillinger wrote in an email. “This will include re-inspecting the section of the line at Lisa Drive. The Commission and its consultants remain on site with us every day and will continue to do so throughout this process.” Geophysical surveys around the Lisa Drive site are scheduled to begin Saturday, and will be closely monitored by pipeline safety engineers from the PUC and geophysical consultants. The testing, which will be used to evaluate underground conditions, is expected to take several days to complete. I&E pipeline safety engineers and geophysical consultants will be on-site monitoring the collection of geophysical data. Results of the testing will be shared with I&E’s engineers and I&E’s geophysical consultants for independent analysis and review. Additionally, PUC engineers and geophysical consultants have been working with municipal officials and Sunoco to monitor and track storm water flow around the incident site, including investigation of storm drains in the area.

Lawmaker calls on officials to investigate pipeline players - The state legislator whose district includes areas that have been beset by problems involving a controversial natural gas pipeline has asked two Harrisburg officials to open separate investigations into the pipeline.State Rep. Kristine Howard, D-167th Dist., in a press release called on state Attorney General Josh Shapiro and state Auditor General Eugene DePasquale to open the inquiries into the Mariner East 1 and Mariner East 2 pipelines, which bring natural gas from the interior of Pennsylvania through Chester and Berks counties to ports in Chester, Delaware County.The East 1 pipeline has been operational for decades, while the East 2 pipeline is under construction.Howard, a Democrat who was elected in November, ousting state Rep. Duane Milne, said she wants Shapiro's office to investigate the pipeline's owners for possible criminal charges, and for DePasquale to audit the Public Utilities Commission and the Department of Environmental Protections.Her release did not specify what crimes may have been committed by the pipelines owners or operators, or what financial irregularities the PUC or DEP may have committed in their oversight of the pipelines.The Chester County District Attorney's Office is currently investigating the pipeline question with a grand jury.Howard said her actions were spurred by the opening of a large sinkhole in a residential area of West Whiteland on Jan. 20, which exposed the Mariner East 1 pipeline. This is the latest in a series of pipeline-related incidents in the high-density area, including numerous other sinkholes and complaints of tainted well water. The area’s limestone geology is a large factor in the appearance of sinkholes, and many critics have noted the unsuitability of the area for pipeline development.

PA: State conducting criminal investigation of shale gas production -- State Attorney General Josh Shapiro is pursuing criminal investigations of “environmental crimes” committed by the oil and gas industry in Washington County and possibly throughout the state. In an Aug. 16, 2018, letter to attorneys in a civil case before the Washington County Court of Common Pleas, Mr. Shapiro and his office said they already had accepted a referral and “assumed jurisdiction over several criminal investigations involving environmental crimes in Washington County.” By that time Washington County District Attorney Eugene Vittone already had discussed with and referred claims of environmental problems in shale gas development to the attorney general’s office. Three Washington County residents told the Post-Gazette that they have spoken with AG investigators and were told they could be called to testify, with a Washington County woman saying that she already presented testimony before an investigative state grand jury in Pittsburgh. Joe Grace, spokesman for Mr. Shapiro and the state Office of Attorney General, said, “We cannot confirm or deny the existence of an investigation.” The AG’s letter was introduced as an exhibit during an August court hearing on the civil case brought by Stacey Haney in 2012 against Range Resources Appalachia LLC, and specially referenced as the “Stacey Haney/Range Resources Investigation.” “It has come to our attention that one of the potential criminal investigations involves your respective clients,” said the two-paragraph letter signed by Courtney Butterfield, deputy attorney general and obtained recently by the Pittsburgh Post-Gazette from someone not involved in the case. The letter noted that a significant record of documents, statements, depositions, scientific tests and physical evidence had been compiled for the civil case. It requested that attorneys preserve that record, under penalty of law if they failed to do so.

Trump Looks To Neutralize Pipeline Opponents --The White House is preparing measures that will reduce states’ powers over the approval or ban of new energy projects, notably oil and gas pipelines, Bloomberg reported last week, citing three unnamed sources in the know. The implications of such measures would be bad news for a state such as New York, which has already put the brakes on a natural gas pipeline, but they could be good news for consumers. Last week, FreightWaves.com reported that residents of the Northeastern states are being increasingly burdened by high electricity bills coupled with unreliable supplies, the root cause of which is the lack of enough natural gas pipeline capacity to bring in the fuel needed for power plants. The report followed an announcement by a regional utility, Con Edison, that it will stop taking on new customers in Westchester County on the grounds that “new demand for gas is reaching the limits of the current supplies to our service area.” In other words, the utility cannot supply electricity to all who need it because it cannot produce enough electricity to satisfy demand and the reason it cannot produce it is lack of sufficient gas supply. What’s more, New York is not the only state struggling with growing electricity demand and insufficient supply because of pipeline opposition on the political level, according to the FreightWaves.com report. All New England states are in the same position and even worse, author Henry Carmichael reports, citing a scientist from the Institute for Energy Research. The situation is reminiscent of that in northern China last year, when the authorities were in a rush to switch from coal to gas in power plants but were not quick enough to construct the necessary distribution network, so several million households ended up without heating in the midst of winter.  Meanwhile, New York’s governor, a staunch opponent of new fossil fuel infrastructure, announced a so-called Green New Deal with the goal to have 100 percent of the electricity used in the state to be sourced from renewable alternatives to oil and gas by 2040. According to media reports on the news, this is the most aggressive renewables goal in the United States. It also means New York will need to reach a portion of 70 percent renewable power by 2030. It was probably part of this cleaner energy drive that led New York State to block a natural gas pipeline project that was approved by the Federal Energy Regulatory Commission and that would have increased the flow of gas into New England. Now, if the White House’s plans come to fruition, the pipeline project could be back on the table with nothing Governor Cuomo could do about it except perhaps challenge it in court.

Environmental groups attack federal approval of Mountain Valley Pipeline - — The good of the Mountain Valley Pipeline — a steady supply of needed natural gas — met the bad Monday, when opponents told a federal appeals court there’s really no public need for a project that is already polluting Southwest Virginia.In a sweeping attack, a coalition of environmental groups asked the U.S. Circuit Court of Appeals for the District of Columbia to reverse a federal agency’s approval of the 303-mile pipeline.When the Federal Energy Regulatory Commission green-lighted the pipeline in October 2017, it voted 2-1 that its public benefits will outweigh any adverse impacts.But in finding there was a market demand for the natural gas, FERC relied entirely on contracts between the pipeline’s owners and its shippers, which are all part of the same corporate structure.The complex affiliations of Mountain Valley Pipeline LLC were not the result of “arms-length negotiations” that would have demonstrated a true market based on public need, the court was told by Ben Luckett of Appalachian Mountain Advocates, a nonprofit law firm that represented pipeline opponents during Monday’s oral arguments.Attorneys for FERC and Mountain Valley countered that the partners would never have invested in the $4.6 billion venture unless they were convinced it was worth the risk — an argument that seemed to resonate with the three-judge panel hearing the case.“They’re putting skin in the game, which tends to show they are using their best judgment about future demand,” Judge Gregory Katsas said in one of several questions put to Luckett.And the pipeline’s capacity is fully subscribed to the Mountain Valley shippers, is it not? asked Judge David Tatel. Yes, Luckett responded, but 80 percent of the end users — the homeowners, businesses or power plants that will actually burn the gas — have yet to be identified and are based solely on speculation.

New proof: entire Mountain Valley Pipeline project based on known falsehoods - Before approving the Mountain Valley Pipeline (MVP), the Federal Energy Regulatory Commission (FERC) had to show that it would do no substantial environmental harm, supposedly demonstrated in the Final Environmental Impact Statement (FEIS) they issued on June 23, 2017 (Accession No. 20170623-4000). In granting the FEIS, the FERC relied on MVP’s stream scour and erosion analyses and plan containing specific information about pipeline construction at stream crossings along the entire pipeline route.Yet within months of starting the project, MVP submitted a variance request asking permission to change its plan. In doing so, MVP admitted to the FERC that: “The [MVP plan] was a theoretical desktop analysis and did not take site specific constructability issues (elevations, terrain, and workspace) into account. During its subsequent field reviews, [MVP] determined thatexecution of the mitigation measures, as written, would pose increased environmental or landslide risks or be unsafe or impractical due to terrain or geology.”In response, FERC’s own expert consultant stated that MVP should be required to “provide a site-specific scenario… for each location [where MVP proposed to change its original plan].”So it is clear that the FERC-approved FEIS does not protect the environment. Despite MVP’s confession, Paul Friedman (FERC Project Manager) or someone at a higher level overruled the FERC’s own expert consultant by

1. Rejecting the expert’s directive that MVP do a site-specific analysis of every water body crossing on the route where MVP proposed to change its original plan.
2. Allowing MVP to produce revised plans with lower environmental standards (June 2018).
3. Failing to provide state environmental agencies or the public an opportunity to comment on revised plans.
4. Approving, without opportunity for public comment, a project-wide variance (MVP-006) on September 26, 2018 that allows MVP to violate Best Management Practices without oversight.
5. Producing this hasty variance approval at EXACTLY the same time that MVPannounced a lengthy delay and major cost increase. MVP and its investors – not clean water, landowner rights and protection of public lands – seemed to be the core FERC audience for this action.
6. Hiding the relevant correspondence from the public, the courts and both federal and state regulators.
7. Trying to hide the name of the FERC Project Manager in documents that ICWA acquired through a Freedom of Information Act Request (FOIA).

U.S. court stays ruling against Dominion Atlantic Coast natgas pipe (Reuters) - A U.S. appeals court has stayed a previous court decision against Forest Service permits that allowed Dominion Energy Inc to build the $6.5-$7 billion Atlantic Coast natural gas pipeline across national forests and the Appalachian Trail. The Fourth Circuit Court of Appeals on Tuesday froze the previous decision by a three-judge panel until the full court decides whether it will rehear the case en banc. The appeals court panel had said in December that the U.S. Forest Service had “abdicated its responsibility to preserve national forest resources” when it issued the permits. Dominion argued that the ruling by the three-judge panel to vacate the Forest Service permits went beyond the court’s authority and created an “impregnable barrier (from Georgia to Maine) dividing energy sources west of the (Appalachian) Trail from consumers east of the Trail.” Dominion spokesman Karl Neddenien said on Wednesday the company remained confident it would complete the 600-mile (966-kilometer) pipeline from West Virginia to North Carolina, even though the timing is “somewhat fluid” due in part to federal lawsuits. In the past, Dominion said it expected to finish the project in mid-2020, but the company has suspended all construction since early December after the Fourth Circuit stayed a federal permit in another lawsuit. That other lawsuit involved the U.S. Fish and Wildlife Service’s Incidental Take Statement, which authorized the pipeline to build in areas inhabited by threatened or endangered species. Given the composition of the Fourth Circuit, analysts at Height Capital Markets in Washington, D.C. said “a rehearing en banc could plausibly bode well for Atlantic Coast.” Height Capital Markets said the panel was comprised of three judges nominated by Democrats, while 7 of the 12 remaining active circuit judges were appointed by Republicans. “While the appointing president’s party doesn’t necessarily define a judge’s legal perspective, we continue to see political affiliation play an outsized role in debates involving environmental rules,” 

Report: The Vanishing Need for the Atlantic Coast Pipeline - Diminishing consumer demand coupled with more affordable renewables are casting doubt on the overall feasibility and potential profitability of the Atlantic Coast Pipeline, according to a report released today by the Institute for Energy Economics and Financial Analysis (IEEFA) and Oil Change International. The report, The Vanishing Need for the Atlantic Coast Pipeline, raises new questions about the future viability of the pipeline,  a multi-billion-dollar project to deliver natural gas from northern West Virginia to Virginia and North Carolina“The demand outlook for gas has changed dramatically since the project’s inception and much of the original justification for the pipeline has evaporated,” said Cathy Kunkel, IEEFA energy analyst and co-author of the report.The pipeline is a joint venture of three companies — Dominion (48%), Duke Energy (47%), and Southern Company (5%) — that was approved by the Federal Energy Regulatory Commission in October 2017. Originally projected to cost $5.1 billion,have raised projections by about 30% to $6.5 to $7 billion, excluding financing costs.[2] But cost overruns are only the beginning of the challenges faced by the project. Key findings of the report include:

• In its most recent long-term integrated resource plan (IRP), four out of five of Dominion’s modeled scenarios show no increase in natural gas consumption from 2019 through 2033.
• Dominion’s 2018 IRP was rejected by Virginia state regulators, in part for overstating projections of future electricity demand. This implies that future natural gas consumption will likely be even less than forecasted in its IRP.
• The most recent IRPs of Duke Energy Progress and Duke Energy Carolinas show that previously planned natural gas plants have been delayed further into the future.
• Over the next decade, it is likely that the demand for natural gas in Virginia and North Carolina erode further as renewable energy and storage technologies continue to rapidly decline in price.

Dominion delays U.S. Atlantic Coast natgas pipe, boosts costs (Reuters) - Dominion Energy Inc said on Friday the estimated cost of its Atlantic Coast natural gas pipeline from West Virginia to North Carolina has risen to $7.0 billion-$7.5 billion, adding that it has delayed the expected completion date to early 2021. The company said previously the project would cost an estimated $6.5 billion-$7.0 billion, excluding financing, and be completed in mid 2020 due to delays caused by numerous environmental lawsuits. “We remain highly confident in the successful and timely resolution of all outstanding permit issues as well as the ultimate completion of the entire project,” Dominion Chief Executive Thomas Farrell said in the company’s fourth-quarter earnings release. He noted the company was “actively pursuing multiple paths to resolve all outstanding permit issues including judicial, legislative and administrative avenues.” Earlier this week, the U.S. Fourth Circuit Court of Appeals stayed a previous court decision against U.S. Forest Service permits that allowed Dominion to build the Atlantic Coast pipeline across national forests and the Appalachian Trail. Dominion said it expects construction could recommence on the full 600-mile (966-kilometer) pipeline route during the third quarter of 2019, with partial in-service in late 2020.

VA: Bill limiting pipeline costs to ratepayers advancing (AP) — A little-noticed piece of legislation advancing through the Virginia General Assembly could pose a serious threat to Dominion Energy’s planned Atlantic Coast Pipeline.The bill would add new restrictions on Dominion’s ability to pass along costs of transporting gas from the ACP to its Virginia-based power stations. That could reduce the potential revenues of a project whose costs have already ballooned in the face of fierce opposition from environmentalists and land owners.A House committee that almost always sides with Dominion endorsed the bill by an 8-2 vote last week. The measure is backed by an unusual coalition of tea party conservatives and green groups, as well as Democratic Attorney General Mark Herring and his conservative predecessor Ken Cuccinelli.The bill’s sponsor, Republican Del. Lee Ware, said his goal isn’t to block construction of the pipeline but to “ensure customers are only paying for capacity that the utilities actually need.”The legislation would require Dominion to show an identified need for increased natural gas capacity and that the ACP was the lowest-cost option before the State Corporation Commission could approve passing along pipeline-related costs.Dominion said the legislation is unnecessary because regulators already have the ability to make sure any fuel costs from the pipeline are reasonable and prudent. “The SCC already has a strong process in place to protect consumers,” said Dominion spokesman Karl Neddenien. Dominion and other developers announced in 2014 plans to build the 600 miles (965 kilometers) pipeline to carry natural gas from West Virginia into Virginia and North Carolina. Most of the capacity for the pipeline is set to go to power plants owned by the companies building the pipeline.  The projected costs have gone up $2 billion since the project was announced to as high as $7 billion. That’s in part of because of a series of legal setbacks. Critics of the pipeline have long questioned the project’s need, saying there’s already enough pipeline capacity in Virginia to supply Dominion’s natural gas power plants. One expert has calculated the ACP’s costs to Virginia ratepayers at $1.6 billion to $2.3 billion over 20 years.

Climate impacts are 'virtually unknowable' — FERC - Federal energy regulators last week defended a controversial policy shift on the government's climate analysis obligation in natural gas pipeline reviews.The National Environmental Policy Act (NEPA) does not require the Federal Energy Regulatory Commission to study upstream and downstream greenhouse gas emissions associated with the natural gas projects the agency authorizes, government lawyers wrote in a Friday filing with the U.S. Court of Appeals for the District of Columbia Circuit.Because gas infrastructure demand follows gas production, "it is unknown — and virtually unknowable — whether the gas to be transported on the Project will come from new or existing production," federal counsel wrote in the brief."Absent that basic information, it is nearly impossible to assess whether there will be any additional production activities in connection with the gas to be transported on the Project," FERC attorneys argued. "As a result, any greenhouse gas emissions from any additional, incremental production activities are not reasonably foreseeable."FERC's brief is a response to a lawsuit filed by the nonprofit group Otsego 2000 contesting the agency's decision last year to scale back its consideration of climate impacts in natural gas project approvals (E&E News PM, May 18, 2018).Six states and the District of Columbia last month called on the D.C. Circuit to scrap the policy shift, which was announced in a procedural document denying a request to rehear FERC's authorization of Dominion Energy Transmission Inc.'s New Market Project in New York.FERC's Democratic commissioners, Richard Glick and Cheryl LaFleur, supported the denial but disagreed with the inclusion of the policy change.Both cited the D.C. Circuit's 2017 ruling in Sierra Club v. FERC, which ordered the agency to more closely examine downstream greenhouse gas emissions from the Southeast Market Pipelines Project, which includes the Sabal Trail pipeline. "This decision clearly signaled that the Commission should be doing more as part of its environmental reviews," LaFleur wrote in her dissent.

New York Regulators to Analyze Downstate Natural Gas Shortages - The New York Public Service Commission (PSC) said this week it plans to analyze and report on the changing market conditions that prompted Consolidated Edison Co. (Con Ed) to impose a moratorium on new natural gas customers in Westchester County. The PSC said it would develop recommendations to ensure utilities across the state are able to meet customer needs in a way that is consistent with Democratic Gov. Andrew Cuomo’s aggressive energy conservation goals.“Specifically, staff will analyze short-term and long-term market conditions, along with the capacity of natural gas infrastructure and alternatives, and their role in aiding the transition to a clean energy economy,” the commission stated.Con Ed said this month that it could no longer accept applications for new natural gas service in Westchester County as demand is quickly outpacing pipeline-constrained supply. The utility warned that the moratorium would remain in effect until sufficient supply is available to meet the region’s needs.The report and recommendations are to be submitted to the PSC and State Energy Planning Board by July 1 for review and assessment of policies, programs and regulations to ensure reliable energy is available for customers and economic growth, while also aiding the state’s renewable energy goals. Those steps, the commission added, would aid broader efforts to help lower gas demand. Con Ed said it “made every effort” to explore alternatives, including solutions to cut gas use and employ compressed or renewable gas. However, the utility said those alternatives aren’t enough to meet demand. National Grid has also warned of a similar supply squeeze on Long Island if Transcontinental Gas Pipe Line Co.’s Northeast Supply Enhancement Project is not approved. That project has already had difficulties with state regulators during the application process for a water quality certification, which has slowed it down.

Drillers Are Easing Off the Gas - In an industry not known for restraint, Appalachia’s shale giants are decelerating natural-gas output as prices languish.  Some of the companies responsible for flooding the U.S. with natural gas are dialing back on drilling amid worries that supplies of the fuel are outpacing demand and potentially sending already depressed prices into a tailspin. Pittsburgh-based EQT Corp. on Tuesday became the latest big gas producer to say it will spend less on drilling this year than it did last year, and that it aims to maintain its present level of output rather than increase it. Gulfport Energy Corp. outlined a similar strategy earlier in the month

Murphy Urges Full Fracking Ban in Delaware River Basin -- Gov. Phil Murphy yesterday called for a full fracking ban in the Delaware River Basin, urging fellow members of the Delaware River Basin Commission to prohibit all activities related to the controversial technology that’s used to drill for natural gas. In a letter to the DRBC, the governor called for a rule proposal currently before the intrastate agency to be expanded beyond banning the practice of hydraulic fracturing within the basin to also include prohibitions on the storage, treatment and disposal of waste from fracking operations and on exporting water from the watershed to abet drilling operations elsewhere. The proposed bans would mark a significant victory for environmental groups and residents in the region, who have waged an eight-year fight to turn a temporary moratorium on fracking — the practice of injecting huge amounts of water into shale formations to extract the gas — into a permanent ban within the watershed. For that to happen, however, Murphy, the chair of the DRBC, needs to convince at least two of the three other governors on the commission to back his full ban, a prospect fracking critics are optimistic will happen. “I think there is plenty of room for all three Governors to come around and do the right thing,’’ said Maya van Rossum, Delaware Riverkeeper. “This is the no-nonsense approach we critically need to prevent the inevitable degradation and pollution that fracking activities would bring to our watershed.’’ The natural-gas boom that has lowered fuel costs for consumers and businesses is one of the more divisive issues within the four states the river basin is in — New Jersey, Pennsylvania, New York and Delaware. Environmentalists and residents fear fracking within Pennsylvania and neighboring states threatens the drinking water from the Delaware River, the source of potable water for 15 million people. 

The Merger That Made a U.S. Gas Giant Is Failing – WSJ - When EQT Corp. agreed to buy Rice Energy Inc. for $6.7 billion a little over a year ago to create the country’s largest natural-gas producer, it promised that the combined company would be able to make more by spending less. Those promises have so far fallen flat, and what many cheered as one of the first deals in a hoped-for wave of consolidation among shale companies is turning out to be a cautionary tale, demonstrating that in fracking, bigger isn’t always better. EQT shares have plunged around 42%—accounting for EQT’s spinoff of its pipeline business in November—since the deal closed in late 2017, as the efficiencies executives envisioned have failed to materialize. The two Appalachian shale drillers’ combined market value has lost about $4 billion since the deal was announced in June 2017, factoring in the spinoff.The union officially turned acrimonious last month, when the brothers who ran Rice Energy launched an effort to boot EQT’s current management and take over the merged company, and gained the support of two influential activist hedge funds. EQT’s acquisition of Rice, which gave it more U.S. natural-gas production by volume than Exxon Mobil Corp. , was largely motivated by the idea of drilling supersize horizontal wells beneath the two companies’ contiguous acreage in the Marcellus Shale, one of the largest gas fields in the world. Spurred by investors, many shale companies have explored consolidation, hoping that larger combined landholdings and scale would help them turn fracking more profitable. But the EQT-Rice merger got off to a rocky start, partly because of cultural differences between the companies, according to people who have worked for the companies.

Trump Admin Eyes Limiting States' Powers to Block Pipelines -- The Trump administration is considering taking steps to limit the ability of states to block interstate gas pipelines and other energy projects, according to three people familiar with the deliberations. The effort, possibly done through an executive order, is aimed chiefly at states in the Northeast U.S., where opposition to pipeline projects has helped prevent abundant shale gas in Pennsylvania and Ohio from reaching consumers in New York and other cities. New York used a Clean Water Act provision to effectively block the construction of a natural gas pipeline being developed by Williams Partners LP to carry Marcellus shale gas 124 miles (200 km) to New England. The project got the green light from the Federal Energy Regulatory Commission but ran into obstacles in New York, where regulators denied a water quality permit. While mostly targeted toward boosting limited pipeline capacity in the Northeast, the initiative could help drive permitting and construction of other energy projects, including coal export terminals. For instance, Lighthouse Resources’ proposed coal export terminal in Longview, Washington, was ensnared when the state’s Department of Ecology denied a critical Clean Water Act permit, citing concerns about air quality and increased railroad traffic to serve the site. The new initiative dovetails with expectations that President Donald Trump would use his State of the Union address to tout efforts to accelerate permitting and construction of oil and gas pipelines, though he’s postponed the speech and the exact timing of any announcement remains unclear. The potential White House action was earlier reported by Politico.Pipeline advocates who say states are abusing their authority under the Clean Water Act have advanced ideas for reining it in. “It just never made sense to me that a state could be able to use the Clean Water Act and effectively veto a federally approved project,” Dena Wiggins, president of the Natural Gas Supply Association, said during an event on Thursday. “There’s got to be something to done to address that issue.” But it’s not clear how much -- if at all -- an executive order could curtail states’ special powers under the statute. Industry officials said real change may require legislation to alter the statute itself, such as a bill advanced in 2018 by Senator John Barrasso, a Wyoming Republican.

Prices Retreat Despite Bullish Weather As Inventories Return To Above Last Year - Highlights of the Natural Gas Summary and Outlook for the week ending January 25, 2019 follow. The full report is available at the link below.

• Price Action: The February contract fell 30.4 cents (8.7%) to $3.178 on a 39.9 cent range ($3.356/$2.957).
• Price Outlook: Despite weather forecasts that were in general still bullish, the duration of extreme temperatures forecast last week has been somewhat moderated, especially at the end of forecast. With national inventory adequate, there is little fear of storage deliverability issues. However, the still extreme cold forecast the upcoming week may see explosive regional cash prices as demand soars for a few days.  CFTC data has not been updated due to the US government shutdown. Aggregated CME futures open interest rose to 1.332 million as of January 25. The current weather forecast is now cooler than 9 of the last 10 years. Pipeline data indicates total flows to Cheniere’s Sabine Pass export facility were at 3.3 bcf. Cove Point is net exporting 0.8 bcf. Corpus Christi is exporting 0.000 bcf. Cameron is exporting 0.000 bcf.
• Weekly Storage: US working gas storage for the week ending January 18 indicated a withdrawal of (163) bcf. Working gas inventories fell to 2,370 bcf. Current inventories rise 74 bcf (3.2%) above last year and fall (320) bcf (-11.9%) below the 5-year average.
• Supply Trends: Total supply rose 1.3 bcf/d to 83.4 bcf/d. US production rose. Canadian imports rose. LNG imports rose. LNG exports fell. Mexican exports fell. The US Baker Hughes rig count rose +9. Oil activity increased +10. Natural gas activity decreased (1). The total US rig count now stands at 1,059 .The Canadian rig count rose +23 to 232. Thus, the total North American rig count rose +32 to 1,291 and now exceeds last year by +6. The higher efficiency US horizontal rig count rose +3 to 932 and rises +124 above last year.
• Demand Trends: Total demand rose +11.8 bcf/d to +106.6 bcf/d. Power demand rose. Industrial demand rose. Res/Comm demand rose. Electricity demand rose +2,171 gigawatt-hrs to 79,211 which trails last year by (8,602) (-9.8%) and trails the 5-year average by (1,969)(-2.4%%).
• Nuclear Generation: Nuclear generation rose 1,113 MW in the reference week to 94,715 MW. This is (1,395) MW lower than last year and +761 MW higher than the 5-year average. Recent output was at 94,691 MW.

The heating season has begun. With a forecast through February 8 the 2018/19 total cooling index is at (1,999) compared to (1,771) for 2017/18, (1,617) for 2016/17, (1,609) for 2015/16, (1,909) for 2014/15, (2,175) for 2013/14, (1,847) for 2012/13 and (1,814) for 2011/12.

Warmer First Third Of February Eliminates Winter Gas Premium -It was another bloody day for natural gas bulls, with the February gas contract gapping down significantly and an early intraday bounce failing as well. The contract ended up settling down over 8% into options expiry.  The role of weather in the move was incredibly clear with the February contract logging by far the largest loss of the day.  This helped easily pull the March/April H/J spread to new lows.  Our Morning Update showed just how pronounced the GWDD losses were over the weekend, with most of them confined in the medium-range.   The Climate Prediction Center has been showing this more consistently too, with their Afternoon Update remaining quite warm through the 6-10 Day period.  In our Natural Gas Weekly Update for clients today we took a deeper look at the impact these warm trends have had on natural gas storage projections, and outlined our thoughts on this Thursday's EIA number as well. We highlighted that it will easily hold the largest draw of the season so far with significant GWDDs last week.   Yet on a weather-adjusted basis the print looks to be looser than last week, due in thanks to demand destruction from the Martin Luther King Jr. holiday last Monday.

Natural gas tumbles on warmer February forecast, after brutal cold snap -- Natural gas prices fell sharply Monday, as weather forecasts for February show more normal and even warmer-than-normal temperatures for parts of the U.S., following a brutal cold snap this week. Natural gas futures for February fell 7.2 percent to $2.95 per million British thermal units."The forecast tuned a little milder for next week, and they took the bottom out of the market again. The storage picture has been altered a bit, and there really are no worries. If February doesn't turn out to be the coldest month of winter, justifying a plus $3 price is hard for the market," said Gene McGillian, manager market research at Tradition Energy. The market has been volatile this winter with worries about low amounts of gas in storage, but high levels of production have helped alleviate that concern."Last week was the first week compared to a year ago that we flipped to a small surplus for the first time in about 18 months," McGillian said. Inventories still remain below the five-year average. Forecasters had been expecting a longer period of cold temperatures."Weekend weather model guidance moved in about as bearish a direction as possible, with incredible warming in the medium-range as cold in the short-term quickly gets kicked out and replaced by ridging across the East," Bespoke Weather noted. Bespoke said risks of cold temperatures return in the medium to longer range, and moderate cold could return in the middle of the month.

U.S. natural gas demand to hit record high during freeze (Reuters) - U.S. homes and businesses will likely use record amounts of natural gas for heating on Wednesday as an Arctic-like freeze blankets the eastern half of the country, according to energy analysts. Harsh winds brought record-low temperatures across much of the Midwest, unnerving even residents accustomed to brutal winters and keeping them huddled indoors as offices closed and mail carriers halted their rounds. That brutal cold could also temporarily reduce gas production by causing freeze-offs in the Marcellus and Utica shale, the nation’s biggest gas producing region, in Pennsylvania, Ohio and West Virginia, the analysts warned. Freeze-offs occur when water and other liquids in gathering lines freeze, blocking the flow of gas. Overnight lows on Wednesday-Friday will drop to -20 Fahrenheit (-29 Celsius) in Chicago and the single digits along the East Coast from New York to Boston, according to AccuWeather, a weather forecaster. The cold, however, will be short lived with high temperatures in New York and Chicago expected to rise into the 40s F this weekend. The normal high at this time of year is 32 in Chicago and 39 in New York. Financial data provider Refinitiv predicted gas demand in the Lower 48 U.S. states would hit a daily record of 145.2 billion cubic feet per day (bcfd) on Wednesday as consumers crank up their heaters to escape the bitter cold. That would top the current all-time high of 144.6 bcfd set on Jan. 1, 2018. One billion cubic feet is enough gas to supply about five million U.S. homes for a day. In early estimates, gas production in the Lower 48 states will slip about 0.9 bcfd to 85.8 bcfd on Wednesday, according to Refinitiv. That is the lowest daily output since Enbridge Inc started to restore flows through some gas pipes in Ohio following a pipeline explosion there on Jan. 21. “Based on our analysis of historical freeze-offs, temperature conditions forecasted for Jan. 30-31 pose a risk of a freeze-off occurring in the Marcellus/Utica...in the ballpark of 1 bcfd,” said Rishi Iyengar, senior analyst natural gas markets at IHS Markit’s OPIS PointLogic. In early estimates, Marcellus/Utica production was down about 0.7 bcfd to 29.6 bcfd on Wednesday, according to Refinitiv. 

Consumers Energy, DTE ask customers to turn down thermostats - In the midst of a polar vortex that has brought record-breaking low temperatures to Michigan, Consumers Energy has called for customers to reduce their natural gas usage and DTE Energy is asking customers to reduce electricity usage. Consumers Energy sent an urgent text alert on cellphones shortly after 10:30 p.m. urging utility customers to lower thermostats and reduce energy usage or risk a dangerous gas shortage in the wake of record-breaking cold.The temperature in metro Detroit hovered at minus 11 degrees at 10:30 p.m., smashing the record for Jan. 30 of minus 4 degrees set in 1951.And the Michigan Public Service Commission has ordered a suspension of all utility shutoffs during the cold spell, according to a news release from the Lansing regulators.  In addition to individual residential customers, General Motors has been requested by Consumers Energy to suspend operations at several manufacturing sites.

Appeals flood consumers: Use less gas after utility fire — Consumers Energy said its customers' reduced gas usage is helping it deal with a hobbled gas compressor station in Macomb County. "Consumers Energy greatly appreciates conservation efforts by all natural gas customers across Lower Michigan to assist with a supply issue on the company’s gas distribution network," officials with the energy company said Thursday in a statement. "Conservation, even by gas customers served by other utilities than Consumers Energy, is making a difference." The news comes hours after the company's top executive called on the company's customers to cut usage after a Wednesday morning fire at its Ray Compressor Station. She also said there would be brief, localized shutoffs if customers ignored the request. "This truly is an unprecedented crisis," Consumers Energy CEO Patti Poppe said Wednesday. "We have never been in this situation before." The governor and the public service commission also urged customers to cut gas usage due to the fire. On Thursday, the company said it was "cautiously optimistic that our public requests to reduce gas use are having a positive effect." Still, it pleaded with customers to continue conservation measures through the end of the day Friday because of Thursday’s historically cold weather. "Repairs at our Ray Compressor Station are ongoing and the station is partially in service, providing natural gas to our distribution system," officials said. "However, we are asking that all customers continue to conserve until the end of the day Friday, Feb. 1, to allow for temperatures to moderate and additional repairs to the Ray Station."

GM halts operations at 11 Michigan plants after utility's urgent appeal (Reuters) - General Motors Co said late on Wednesday it will temporarily suspend operations at 11 Michigan plants and its Warren Tech Center after a utility made an emergency appeal to users to conserve natural gas during extreme winter cold. Fiat Chrysler Automobiles NV also said it had canceled a shift on Thursday at both its Warren Truck and Sterling Heights Assembly plants and was considering whether it would need to cancel additional shifts. GM said it had been asked by Consumers Energy, a unit of CMS Energy Corp, to suspend operations to allow the utility to manage supply issues after extreme cold temperatures and a fire at a compressor station. It said workers were told not to report for the shifts at its Orion Assembly, Flint Assembly, Lansing Delta Township Assembly and Lansing Grand River Assembly plants, as well as other stamping and transmission plants on Wednesday evening and early Thursday. GM said it was still assessing when employees could return to work. Workers at its Warren Tech Center were also told to stay home on Thursday. In a video message posted on Facebook, CMS Energy Chief Executive Patricia Poppe said large companies, including Fiat Chrysler, Ford Motor Co and GM, had agreed to “interrupt” production schedules through Friday to tackle the issue prompted by a fire at a Michigan facility and the record-breaking cold. Poppe said the usage cuts by large businesses were not enough, and urged 1.8 million Michigan customers to turn down thermostats as much as they could to cut natural gas use in order to protect critical facilities like hospitals and nursing homes. “I need you to take action right now,” she said. Ford Motor said it had also taken steps to reduce energy use at its four Michigan plants supplied by Consumers Energy, but added the situation remained fluid. A spokeswoman said it had reduced heating levels at Livonia Transmission and Van Dyke Transmission, stopped heat treatment processes at Sterling Axle and shut down the paint process at Michigan Assembly.

US natural gas storage volume falls 173 Bcf to 2.197 Bcf: EIA— US natural gas in storage decreased 173 Bcf to 2.197 Tcf in the week that ended January 25, the US Energy Information Administration reported Thursday. The withdrawal was well below the expectations of an S&P Global Platts' survey of analysts, which called for a 197 Bcf pull. The draw was completely outside of the range of survey responses. The lowest response was for a 176 Bcf withdrawal. The withdrawal was considerably above the 126 Bcf pull reported in the corresponding week in 2018 as well as the five-year average draw of 150 Bcf, according to EIA data. As a result, stocks were 14 Bcf, or 0.6%, under the year-ago level of 2.211 Tcf and 328 Bcf, or 13%, below the five-year average of 2.525 Tcf. The NYMEX March gas futures contract slid 2 cents to $2.83/MMBtu following the data announcement. The EIA reported a 39 Bcf withdrawal in the East to trim regional stocks to 527 Bcf, compared with 529 Bcf a year ago; a 67 Bcf draw in the Midwest to drop inventories to 606 Bcf, compared with 601 Bcf a year ago; a 7 Bcf pull in the Mountain region to cut stocks to 114 Bcf, compared with 138 Bcf a year ago; a 7 Bcf withdrawal in the Pacific to drop inventories to 178 Bcf, compared with 222 Bcf a year ago; and a 52 Bcf draw in the South Central region to decrease stocks to 771 Bcf, compared with 720 Bcf a year ago. Total inventories are now 48 Bcf under the five-year average of 575 Bcf in the East, 57 Bcf below the five-year average of 663 Bcf in the Midwest, 35 Bcf lower than the five-year average of 149 Bcf in the Mountain region, 64 Bcf below the five-year average of 242 Bcf in the Pacific and 125 Bcf under the five-year average of 896 Bcf in the South Central region. An early forecast for the week that ended February 1 calls for a withdrawal of 255 Bcf, which is 105 Bcf larger than the five-year average draw. It would be the largest pull ever for reported for the corresponding week. During the polar vortex of 2014, 231 Bcf was drawn down during the same week.

Weekly Natural Gas Storage Report - Mother Nature Not Coming To The Rescue - EIA reported a storage draw of 173 Bcf for the week ending Jan 25. This compares to the -189 Bcf we projected and consensus average of -183 Bcf. The -173 Bcf was higher than the five-year average of -160 Bcf and much higher than last year's -99 Bcf. For the week ending Feb. 1, we have a storage draw of -240 Bcf. This would be compared to the five-year average draw of -151 Bcf and last year's -119 Bcf. Our EOS forecast is now 1.312 Tcf. Natural gas prices are still getting hammered with March contracts falling to just $2.818/MMBtu down from $3.30+ just a few weeks ago. The culprit is once again mother nature with the first week of February revised warmer than normal. For example, you can see that our estimate for Feb 1 storage draw is -240 Bcf, but the following week is only expected to show a storage draw of -120 Bcf. This delta is the result of the cold blast being very temporary and as a result, markets are punishing prices for that. As you can see from the gas-weighted heating degree days chart, HDDs are expected to plummet going into the first week of February before rebounding. The question for where gas prices are headed will be entirely dependent on the weather outlook for the second half of February. With the first half of February turning out to be a disappointment, natural gas prices will be extremely sensitive to forecasts for the second half. If the second half turns out to be warmer than normal, then we could see prices plunge to a low. But early indications are that the second half will be colder than normal resulting in another long shot opportunity.

Colder Forecasts Can't Save Gas After Bearish EIA Storage Number - It was another red day in the natural gas market, as prices initially rallied overnight on colder weather model guidance but were pulled back lower on weaker physical prices. A bearish EIA print then helped the March contract settle a bit more than a percent lower.  We can see how the whole strip made a solid leg lower that was actually led down by later contracts.   The result was that the March/April H/J spread actually ticked higher on the day despite all 2019 contracts logging decent losses on the day.   At first, prices were strong as we added some GWDDs overnight, as we showed in our Morning Update.  We also warned clients that afternoon weather model guidance was likely to trend colder, which verified well with most models increasing cold risks in Week 2.  Yet EIA storage data came out incredibly bearish, with the EIA announcing only 173 bcf of gas was withdrawn from storage.   We were looking for a draw of 189 bcf and even then were slightly below the market consensus that was a bit higher. This print was very loose on a weather-adjusted basis, even when taking into account the Martin Luther King Jr. holiday.

Natural gas prices slump despite US winter weather blast (AP) — While the polar vortex is driving up demand for natural gas, it isn’t doing the same for the price. The massive weather system is blanketing much of the Midwest and Northeast in a deep freeze, and demand for natural gas is spiking as homeowners crank up the heat to stay warm. Yet natural gas prices have fallen this week and are in the throes of a two-month skid. The bone-chilling cold stretches from Bismarck, North Dakota, to Portland, Maine, but it will be relatively short-lived. And forecasters say warmer than normal weather is coming to replace it. An early blast of winter weather coupled with U.S. natural gas stockpiles hovering at a 13-year low drove the price of natural gas to $4.84 per 1,000 cubic feet in mid-November, the highest closing price in more than four years. Natural gas prices began to decline around mid-December as the early November winter weather gave way to above-normal temperatures. That weather pattern continued into January and natural gas fell below $3. The relative warm spell allowed for supplies of natural gas to be replenished. Greater supply is a counterweight to the market pressures that can drive prices higher. The price rose to $3.59 in mid-January amid a brief cold spell but by Thursday had dropped to $2.81 per 1,000 cubic feet. That’s down 42 percent from that 2018 peak and 6 percent lower than a year ago.

US LNG export project timelines face uncertainty in market amid regulatory questions - — The Federal Energy Regulatory Commission's inaction on Venture Global LNG's permit application for its Calcasieu Pass export terminal in Louisiana is raising concerns in the market about a broader impact on approval schedules set for other projects. The stakes are high: US developers are already facing significant headwinds on the commercial side from trade tensions between Washington and Beijing. Also, the partial government shutdown that lasted for more than a month before an apparent breakthrough Friday -- albeit one that may only be temporary -- impacted several agencies that are involved in the project review process. New regulatory hurdles could further complicate developers' efforts at a time when they are racing to make final investment decisions so they can start up the second wave of US liquefaction facilities by the early- to mid-2020s to meet expected global LNG demand. Venture Global LNG acknowledged the urgency when it requested earlier this month that FERC keep to its previously stated schedule, which called for a decision on certification by January 22. That date passed without a decision, and as of press time Friday afternoon the commission still had not acted. "We believe the timing of the approval is particularly important for VG as it had made plans to begin site construction in early 2019 upon FERC approval, but prior to formal FID," Wells Fargo Securities analyst Michael Webber said in a note to clients Wednesday. "Beyond VG, we think the idea of modest regulatory delays seems at least somewhat likely, at least in terms of final project approval -- however, it's unclear how evenly distributed any delays will be, if at all." In an email Friday responding to questions, FERC Commissioner Cheryl LaFleur said she believes there is a path forward on the dockets for the pending LNG export projects. "I hope that through constructive engagement by the commissioners we can work toward that goal," she said. Eagerly watching are developers of the dozen projects that in August 2018 received environmental review schedules and expected final authorization timelines that allowed for the possibility that permit certificates would be issued for most of them this year. In addition to Calcasieu Pass, projects that received environmental review and/or final permit schedules with decisions expected within the next six months include Tellurian's Driftwood LNG in Louisiana and Sempra Energy's Port Arthur LNG in Texas. Tellurian spokeswoman Joi Lecznar said Friday that company officials have "no concerns and remain on schedule to begin construction mid-2019." That would be subject to FERC approval, and a final investment decision. Sempra still believes it will receive its final environmental impact statement by January 31 for Port Arthur LNG, spokeswoman Paty Ortega Mitchell said.

US Magnolia LNG seeks new offtake deals after sole agreement lapses — Australia's LNG Limited acknowledged a level of urgency Thursday to secure offtake agreements with potential buyers of capacity from its proposed Magnolia LNG export terminal in Louisiana, after its only publicly disclosed long-term deal lapsed in December. The developer's CEO, Greg Vesey, said in a letter to shareholders posted on the company's website that the pricing offer to potential customers being courted in Asia, Europe and elsewhere is market competitive and would provide an attractive commercial opportunity.At the same time, Vesey did not specify an exact timeframe of when LNG Limited expects to make a final investment decision on the project. The company had planned to reach FID last year, but in October delayed that until 2019 amid China's imposition of a 10% tariff on imports of US LNG. Vesey's latest letter said only that LNG Limited envisions an FID, and that it is moving expeditiously toward that goal."Our marketing efforts continue with an appropriate balance for the need to close capacity sales at Magnolia LNG while providing acceptable returns to shareholders," Vesey said as the company released its latest quarterly financial results.He said commercial discussions "with select Asian counterparties progressed substantially in the period despite uneven trade discussion rhetoric."At the World Gas Conference in Washington in June 2018, Vesey said that an interested Chinese buyer was holding off completing a purchase agreement with Magnolia LNG until there was greater certainty about tariffs that at the time were being threatened by Beijing. The tariffs that China eventually did impose started in September 2018.Magnolia LNG won permit approval from the Federal Energy Regulatory Commission in April 2016, and since then it has vied, along with multiple US developers, to line up contracts and financing to support construction. The company recently petitioned US regulators to increase the authorized capacity of the project from 8 million  mt/year to up to 8.8 million mt/year.

Exxon, Qatar Petroleum Continue $10-Bln LNG Project Without ConocoPhillips -Exxon and Qatar Petroleum will proceed with a US$10-billion expansion of their Golden Pass LNG import terminal in Texas to turn it into an export facility as well, Reuters reports, citing source familiar with the matter. The third partner in the venture, ConocoPhillips, however, will not be joining them in the expansion and has decided to sell the 12.4-percent interest it holds in Golden Pass, the sources also said, adding that Exxon, which has a 17.4-percent stake in the project, is the most likely buyer. Qatar Petroleum is the majority shareholder in the venture with 70 percent.The Golden Pass terminal can accommodate up to 2 billion cu ft of natural gas for regasification right now. The sources did not detail the capacity of the future export part of the facility.The Reuters sources also noted that Exxon and Qatar Petroleum have been forging closer ties in the liquefied natural gas segment across the world, from Qatar itself to Mozambique and the United States, which has thanks to the shale gas boom become an increasingly important exporter of LNG.At the same time, Qatar is planning huge investments in U.S. natural gas as it seeks to retain the number-one LNG exporter spot, which last November was threatened by Australia. Down Under emerged as the largest LNG exporter globally for that month.Qatar plans to invest US$20 billion in U.S. natural gas, part of a larger U.S. investment campaign by the Qatar Investment Authority that will total US$45 billion as it diversifies away from Europe. Meanwhile, LNG capacity is growing along with demand. Earlier this week, oilfield services provider Baker Hughes’s chief executive, Lorenzo Simonelli said he expected new LNG projects with a total capacity of 100 million tons per year could be approved this year alone. Global LNG consumption is seen to double by 2030, reaching 550 million tons.

The United States is expected to export more energy than it imports by 2020 -- EIA projects that, for the first time since the 1950s, the United States will export more energy than it imports by 2020 as increases in crude oil, natural gas, and natural gas plant liquids production outpace growth in U.S. energy consumption. Different assumptions about crude oil prices and resource extraction affect how long EIA projects that the United States will export more energy than it imports. The United States has been a net exporter of coal and coke for decades, began exporting more natural gas than it imports in 2017, and is projected to export more petroleum and other liquids than it imports within the decade. The United States has imported more energy than it exports on an annual basis since 1953, when trade volumes were much smaller. Since then, when imports of energy totaled 2.3 quadrillion British thermal units (Btu), gross energy imports generally grew, reaching a peak of 35 quadrillion Btu in 2005. Gross energy exports were as low as 4 quadrillion Btu as recently as 2002 but have since risen to more than 20 quadrillion Btu in 2018, largely because of changes in liquid fuels and natural gas trade.EIA’s projected changes in net energy trade are driven mostly by evolving trade flows of liquid fuels and natural gas. In the Reference case of EIA’s newly released Annual Energy Outlook (AEO), the United States exports more petroleum and other liquids than it imports after 2020 as U.S. crude oil production increases and domestic consumption of petroleum products decreases. Near the end of the projection period, the United States returns to importing more petroleum and other liquids than it exports on an energy basis as a result of increasing domestic gasoline consumption and falling domestic crude oil production in those years. U.S. natural gas trade in the AEO Reference case, which includes shipments by pipeline from and to Canada and to Mexico as well as exports of liquefied natural gas (LNG), is increasingly dominated by LNG exports to more distant destinations. Increasing natural gas exports to Mexico are a result of more pipeline infrastructure to and within Mexico, allowing for increased natural gas-fired power generation. As natural gas demand grows in Asia and U.S. natural gas prices remain competitive, LNG export capacity increases further before leveling off after 2030 when additional suppliers enter the global LNG market and U.S. LNG is no longer as competitive. EIA projects the difference between natural gas exports and imports to increase throughout the AEO projection period, reaching a high of 23 billion cubic feet per day (Bcf/d) in 2050.

Interior approved drilling permits for Bernhardt-linked companies during shutdown - Former oil and gas lobbyist David Bernhardt became acting head of the Interior Department on January 2, midway through the historic government shutdown. Under Bernhardt’s command, the Interior Department formally changed its shutdown plans, recalling employees to process drilling permits, both offshore and throughout the Mountain West. A new analysis by the Center for Western Priorities finds that dozens of drilling permits approved during the shutdown were for companies that serve on the boards of major trade associations that were recent clients of David Bernhardt. According to data from the Bureau of Safety and Environmental Enforcement, 71 offshore drilling permits were approved during the shutdown. Of those, 53 permits were for companies that sit on the board of directors for the National Ocean Industries Association (NOIA), a major offshore drilling trade association and former Bernhardt client. Before joining the Interior Department, Bernhardt represented NOIA in a lawsuit against the Interior Department over offshore drilling leases after the Deepwater Horizon spill, and lists the trade association on hisethics recusal. Similarly, of the 38 onshore drilling permits approved by the Bureau of Land Management during the shutdown, 20 were for companies that sit on the board of directors of the Independent Petroleum Association of America (IPAA) or affiliates of the U.S. Oil and Gas Association (USOGA), both former Bernhardt clients. When seeking office at the Interior Department, Bernhardt listed both trade associations on his ethics recusal and noted IPAA was a source of personal income on his financial disclosure.

US crude exports to Asia to swell in Mar, Apr on cheaper freight — US crude exports to Asia are set to swell over March and April as a drop in freight rates makes US cargoes more competitive against barrels from Asia or the Middle East, according to market participants and shipping fixtures Friday. Industry sources indicated that US crudes continued to attract the attention of plenty of Asian buyers as various flagship North American export grades have been consistently trading at a discount against comparable light and medium Persian Gulf grades. "Arbitrage economics remain highly favorable for more US crude purchases. The latest OPEC cut seems to be keeping the Dubai price complex relatively expensive," a senior official at Seoul-based Korea Petroleum Association said. Freight rates from the US Gulf Coast to Asia have fallen by about a third since early-December, making the case for greater loadings of US crude to the region. Around 17 VLCCs have been fixed to load crude from the US Gulf Coast to Eastern destinations for February-loading cargoes, shipping reports showed, with many more likely booked outside of reported fixtures. For January-loading cargoes, 16 VLCCs were seen carrying US crude from the US Gulf Coast to Eastern destinations, according to Platts vessel tracking software cFlow and shipping reports. December-loading US crude cargoes, meanwhile, saw only seven VLCCs leave the US Gulf Coast for the East, cFlow and shipping reports showed. Among fixtures seen, US producer Occidental Petroleum had four VLCCs for the USGC-East route for February-loading cargoes -- Landbridge Majesty on February 7, Hong Kong Spirit over February 20-25, DHT Colt on February 24 and Maran Ares on February 27. South Korean refiner SK Innovation is slated to load three VLCCs -- Apolytares on February 5, Nasiriyah on February 9 and New Horizon over Februray 15-17 -- all for delivery to South Korea. Other charterers of February-loading cargoes for the USGC-East route include Vitol, Equinor and South Korea's GS Caltex, among others.

GOM Oil Export Growth Hurts US Refiners-- Crude exports from the Gulf of Mexico are picking up at the worst time for American refiners. Rising production and falling freight rates are behind a surge of overseas shipments of Mars crude, a medium sour oil produced in the U.S. Gulf of Mexico. This comes as sanctions on Venezuela and OPEC’s production cut agreement are limiting the availability of similar types of oil that U.S. refiners are optimized to process. At least 6 million barrels of the crude will load in February for shipment to South Korea and Europe, according to people who asked not to be identified because the shipment data is proprietary. This compares with about 2 million that left for foreign markets this month, they said. Canada also produces comparable crude but production plans implemented by Alberta in January may have resulted in some suppliers experiencing steeper cuts than the originally targeted 325,000 barrels a day. Production from the Gulf of Mexico is set to increase by 200,000 barrels day this year compared with last year after 11 new projects came online, according to the U.S. Energy Information Administration. Six more projects are expected to come online this year. “Gulf of Mexico crudes like Mars are logically placed for export with connections to Louisiana Offshore Oil Port,” said Elisabeth Murphy, an analyst at ESAI Energy Llc.    Mars exports planned for next month would amount to about a third of the barrels that flowed in November on the system operated by Mars Oil Pipeline Company, according to latest data from the Louisiana Department of Natural Resources. Daily throughput on the system rose about 30 percent from January to November last year as new production started in the Gulf of Mexico. Despite rising production, Mars Blend prices have strengthened as demand seems to be outpacing supply. Last week, the Mars premium to West Texas Intermediate futures hit a four-year high. The sanctions on Venezuela and the potential force majeure the country is considering on U.S. oil shipments jeopardize nearly 12 million barrels of crude that would have gone to U.S. refiners in February. They will likely replace just over half of the 500,000 barrels a day of Venezuela oil the plants receive with Canadian crude by rail and potentially some crude from the Arab Gulf, Murphy said. 

With Venezuela sanctions looming, USGC refiners face premiums for replacement barrels — The Trump administration is poised to impose sanctions on US imports of Venezuelan crude oil, a move which will leave US Gulf Coast refiners scrambling for more costly replacement barrels, sources said. If sanctions are imposed, flows of heavy crudes into the US are most likely to increase from Mexico, Canada, Saudi Arabia and Iraq, analysts said this week. "Essentially, if you have sanctions that don't allow the current 500,000 b/d of Venezuelan crude to come to the US then you'd have a reallocation of trade flows around the world," said John Auers, executive vice president of Turner, Mason & Company. "But it's not going to be a perfect reallocation." An increase of imports of each grade poses a challenge, from infrastructure constraints to government-imposed output curtailments. "US refiners would likely pay a premium due to infrastructure constraints, competition for market share in Asia, and continued OPEC supply limits," analysts with Rapid Energy Group said in a note Friday. The sanctions would also likely be imposed at a time when heavy barrels are trading at a premium to light crudes. In fact, Saudi Arab Medium for US buyers moved to a 40 cent/b premium to WTI MEH this month, according to S&P Global Platts calculations. This time last year, Arab Medium for US buyers was at a $3/b discount to WTI MEH. But an exit of Venezuelan crudes from the USGC market would only exacerbate this dynamic, likely raising prices of other similarly heavy grades even further at the expense of Gulf Coast refiners. Gulf Coast coking margins for Venezuela's Mesa crude have averaged around $5/b so far in January, roughly equal to those for US benchmark medium sour Mars. But these are nearly double those for coking Saudi Arab Heavy or Arab Medium or Mexican Maya. Sources said that if the heavy market tightens further, refineries --- many of which have invested significantly in crackers and cokers -- will be faced with the choice of chasing more expensive barrels or switching to a less optimal lighter crude diet. "Complex refiners will buy all the heavy sour because the residue allows them to turn it into the most profitable of products,"  "The battle will be between running more light sweet or more medium sour."  Analysts said they expect the Saudis could increase exports to meet increased demand in the Gulf Coast. "I do think [the Saudis] will be opportunistic, as they always are, with the slate of crudes that they're offering and the crudes that they're directing to different places,"

America Is Producing the Wrong Kind of Oil -- The shale boom has created a world awash with crude, putting a lid on prices and markedly reducing U.S. dependence on imported energy. But there’s a growing problem: America is producing the wrong kind of oil. Texas and other shale-rich states are spewing a gusher of high-quality crude -- light-sweet in the industry parlance -- feeding a growing glut that’s bending the global oil industry out of shape.Refiners who invested billions to turn a profit from processing cheap low-quality crude are paying unheard of premiums to find the heavy-sour grades they need. The mismatch is better news for OPEC producers like Iraq and Saudi Arabia, who don’t produce much light-sweet, but pump plenty of the dirtier stuff.The crisis is Venezuela, together with OPEC output cuts, will exacerbate the mismatch. The South American producer exports some of the world’s heaviest oil and Trump administration sanctions announced this week will make processing and exporting crude far more difficult. American refiners are scrambling for alternative supplies at very short notice. Crude isn’t the same everywhere: the kind pumped from the shale wells of West Texas resembles cooking oil -- thin and easy to refine. In Venezuela’s Orinoco region, it looks more like marmalade, thick and hard to process. Density isn’t the only difference -- the sulfur content is also important, dividing the market into sweet and sour crude. Heavy crude tends to have more sulfur than light crude.As Saudi Arabia, Russia and Canada cut production, and American sanctions force Venezuelan and Iranian exports lower, the market for low-quality crude is feeling the impact."The strength in the physical crude market continues, led by sour crude shortages," Amrita Sen, chief oil analyst at consultant Energy Aspects Ltd. in London, said echoing a widely held view within the market. For consumers and politicians focused on the headline oil price for Brent and West Texas Intermediate, the most popular benchmarks, it may not matter much. Car drivers could even benefit, because too much light-sweet crude often leads to too much gasoline, and lower prices. On the flip side, truckers may find themselves short-charged, as refiners prefer heavy-sour crude to make diesel.

U.S. gasoline consumption stalls, adding to oil producers' problems (Reuters) - U.S. gasoline consumption was flat in the first 10 months of 2018 as escalating motor fuel prices offset the impact of a strong economy and big employment gains. Flat-lining U.S. gasoline consumption combined with surging U.S. shale production and a slowing global economy to push the oil market towards surplus and explains the plunge in prices late last year.Gasoline consumption averaged 9.34 million barrels per day (bpd) between January and October 2018, which was slightly down from 9.36 million bpd in the same period in 2017.Full-year consumption is forecast to have declined by around 40,000 bpd, according to estimates from the U.S. Energy Information Administration ("Short-Term Energy Outlook", EIA, December 2018).Consumption has shown little or no growth since 2017 after four years of variable but strong gains between 2013 and 2016 ("Petroleum Supply Monthly", Energy Information Administration, December 2018).Fuel use has flattened off even as the rate of economic growth has accelerated to an annual rate of more than 3 percent and almost 5 million non-farm jobs have been created since the end of 2016.But stagnating gasoline consumption has been consistent with a sharp slowdown in the growth of traffic on the nation's roads in the last two years (https://tmsnrt.rs/2S6klHd).Traffic volumes surged between 2014 and 2016, with vehicle-miles travelled often rising at year-on-year rates of 2-3 percent or more, but slowed sharply in 2017 and 2018, with gains slowing to 1 percent or less.Traffic volume in the three months from September to November 2018 was just 0.3 percent higher than in the same period a year earlier ("Traffic Volume Trends" Federal Highway Administration, December 2018). In the last quarter of a century, traffic growth has been closely correlated with both the state of the economy and changes in the cost of fuel.While the economy has remained supportive, higher oil prices have been strongly negative for gasoline consumption.

Exxon OK's project to nearly double size of Texas refinery: sources (Reuters) - Exxon Mobil Corp has given final approval to an expansion that would nearly double the size of its 365,000 barrel-per-day (bpd) Beaumont, Texas, refinery, making it the largest in the United States, said two people familiar with the company’s plans. The largest U.S. oil producer, which has been considering a third processing unit at the plant since at least 2014, has authorized financing for equipment needed to convert shale crude from its West Texas oilfields into precursors for gasoline, diesel, jet fuel and other refined products. The authorization is the final step to begin building a third crude distillation unit (CDU) that would process between 250,000 and 350,000 bpd of light crude at the refinery located 87 miles (140 km) east of Houston. With a 250,000 bpd CDU, the plant’s total capacity would reach 615,644 bpd, placing it ahead of the nation’s largest, Motiva Enterprises’ 603,000 bpd refinery, in nearby Port Arthur, Texas. “It has been approved,” said one of the people familiar with the refinery expansion. Employees have been asked to keep the approval confidential, said the person, who could not be identified because of the restrictions. The company has not publicly disclosed the cost of the expansion, which is part of a $20 billion investment program outlined in 2017 to increase its U.S. Gulf Coast manufacturing over 10 years. Exxon spokeswoman Sarah Nordin said on Monday she had no updates on the status of the project. In October, she had confirmed that site preparation work had begun in advance of a final decision. Last October, Exxon has said construction on the project was expected to begin this year after a final investment decision, and estimated the work would be completed in 2022. Exxon aims to triple its daily crude production in the Permian Basin of West Texas and New Mexico to 600,000 barrels of oil equivalent (boepd) by 2025. Last year it agreed to form a joint venture with Plains All American Pipeline LP that would build a pipeline able to carry 1 million bpd of oil to its refineries in Baytown and Beaumont. 

ExxonMobil, Plains, Lotus to proceed with 1 million b/d Permian crude pipe to feed Beaumont expansion— A 1 million b/d crude pipeline that would transport Permian Basin crude to the US Gulf Coast received the formal go-ahead from its backers and is expected online in the first half of 2021, according to a statement released Wednesday by partners ExxonMobil, Plains All American and Lotus Midstream. "The new common-carrier pipeline system will provide more than 1 million b/d of crude oil and condensate capacity and will be constructed from the Permian Basin in West Texas to the Texas Gulf Coast," they said. Plains, ExxonMobil and Lotus Midstream formed the Wink to Webster Pipeline LLC Joint Venture and have already ordered nearly 650 miles of domestically sourced 36-inch-diameter line pipe. Plains will be the operator of the line during the construction phase. The pipeline announcement was expected after ExxonMobil on Tuesday confirmed it was beginning construction at its 365,644 b/d Beaumont, Texas, refinery of a 250,000 b/d crude unit to run the light, sweet oil produced from its holdings in the Permian Basin, which would provide shipping commitments substantial enough to make the pipeline commercially viable. The pipeline will have origin points at Wink and Midland, Texas, and multiple destination points in the Houston area including Webster and Baytown, where ExxonMobil is currently expanding light sweet crude processing capacity at the 560,500 b/d refinery by about 60,000 b/d. Pipeline connectivity will also be provided to Texas City and Beaumont, the project's backers said. ExxonMobil's Beaumont crude unit expansion is expected to be completed by 2022. ExxonMobil in 2018 announced its "Growing the Gulf" initiative, which would expand the processing capacity of its three large US Gulf Coast refineries -- Baytown, Beaumont, and Baton Rouge -- of growing light, sweet crude production from its Permian Basin holdings. At that time, ExxonMobil said it expected to triple its Permian production to more than 600,000 b/d. Crude processing capacity is expected to increase by 17,000 b/d at the 502,500 b/d Baton Rouge refinery. The pipeline announcement did not divulge if the project would be combined with a similar project, the Permian Gulf Coast pipeline.

Two proposed pipelines to bring 1.3 million barrels of crude oil to Houston -- Two proposed pipeline projects could bring a combined 1.3 million barrels of crude oil and condensate from multiple shale plays to refineries and export terminals in Houston by 2021. Plains All American Pipeline of Houston and Exxon Mobil of Irving said Wednesday that the two companies finalized a joint venture with Lotus Midstream to develop the Wink-to-Webster Pipeline, a project to move 1 million barrels of crude oil and condensate per day from the Permian Basin of West Texas to Houston. Magellan Midstream Partners of Oklahoma and Dallas pipeline and storage terminal operator Navigator Energy Services are extending the open season to book capacity on their proposed Voyager Pipeline, a project to move 300,000 barrels of crude oil and condensate per day from storage terminals in Cushing, Okla. to refineries and export terminals in Houston. Spanning some 650 miles, the Wink-to-Webster Pipeline is a 36-inch-diameter pipeline, which analysts previously said carried a $2 billion price tag. Plains will lead the construction of the project and has already begun pre-construction activities. If approved by regulators, the pipeline could be in service by the first half of 2021. Magellan Midstream reported that the Voyager Pipeline received significant interest and that the extension provides these potential shippers additional time to finalize their commitments across other pipelines. Also expected to cost up to $2 billion, the proposed project is a 20- or 24-inch-diameter pipeline that will span 500 miles to connect Magellan's terminal in Cushing to the company's terminal in East Houston. If approved by regulators, the pipeline could be in service by late 2020.

Central Texas pipeline reignites fight over land rights - A fight over a pipeline is never only about the pipeline. It’s about the environment, property rights, public safety and a community’s sense of itself. Just such a fight is now brewing in the Texas Hill Country, where company Kinder Morgan plans to lay a part of its 430-mile natural gas Permian Highway Pipeline. The Houston-based company says the time is right for the project. An unprecedented drilling boom in West Texas means there’s more oil and gas coming out of the ground than companies can ship to market. The pipeline would carry natural gas to the Gulf Coast, where it can be sold domestically or exported. The quickest way there is through the Hill Country, including places like the Hershey Ranch in Gillespie County. The ranch, a 1,500-acre spread of rolling hills and weathered terraced fields, is dotted with trees, ponds and structures dating from the 1800s. If the pipeline is built underneath it, Kinder Morgan would also control about a 100-foot-wide swath of land above the pipeline to maintain it. “It will go right through the heart of the ranch,” says owner Andy Sansom. Sansom is a well-known conservationist, who once headed up the Texas Parks and Wildlife Department. He’s especially upset about the pipeline because the Hershey Ranch is private conservation land, where no development is supposed to occur. But, he says, his neighbors with more traditional properties don’t want the pipeline either. “There are few parts of our state that are as iconic as the Hill Country,” he says. “It’s very clear that the people who live out here see this as an assault.” The idea that the Hill Country may be too “iconic” for this pipeline is something you can expect to hear more of as the project gets underway. Opponents have already raised concerns over the potential environmental, aesthetic and public health impacts. Kinder Morgan says it’s willing to make small adjustments to the route to accommodate landowners. But the pipeline is coming.

America Needs More Oil And Natural Gas Pipelines – Forbes - Despite a 140% boom in U.S. crude oil production and a 50% jump in natural gas output since shale took flight in 2008, the midstream infrastructure to pipe this new supply around the country has simply not kept up. This is a major problem for us because pipelines are easily the safest and most economical way to transport energy. In addition, hardly “going away,” oil and gas will still supply the bulk of U.S. energy through at least 2050, according to just released modeling from the U.S. Department of Energy in the Annual Energy Outlook 2019.The Permian basin in West Texas, giving a third of all U.S. crude production, confronts a pipeline bottleneck from a surge of activity. Yet, most of this will be rectified as the build-out in our largest oilfield continues to catch up. After all, although stronger than you might think, the pipeline pushback in oily Texas from “environmental groups” is not as potent as in other states. In contrast,  New York and the six New England states are really ground zero for our pipeline problem where “environmentalists” – despite significantly relying on oil and gas themselves in their daily lives – remain steadfast against new builds.  Indeed, gas is increasingly being utilized in these anti-pipeline regions for generating both electricity and heat. In New England, for instance, gas has accounted for over half of all electricity: "New England's Known Need For More Natural Gas Pipelines." It is no wonder then that these anti-pipeline areas have 1) the highest energy and electricity prices, 2) fleeing high paying manufacturing jobs, and 3) great concerns over electric reliability in periods of high demand: "What Happens When You Don't Build Natural Gas Pipelines?" New York though might pose the biggest threat. Not just anti-pipeline, Governor Cuomo will not consider developing the state’s portion of the giant Marcellus shale gas play that has so benefitted Pennsylvania, Ohio, and West Virginia. The contradiction from The Empire State is again palpable: despite producing no gas itself, New York relies on gas for a leading 40% of its electricity.

Trio of earthquakes hit near Eagle Ford town of Three Rivers - The U.S. Geological Geological Survey has confirmed that a trio of earthquakes was recorded near the Eagle Ford Shale town of Three Rivers, including one whose epicenter was inside a state park. The first earthquake, a 2.6-magnitude tremor, hit in a rural area near Interstate 37 and FM 2040 at 7:30 p.m. Friday. A 2.7-magnitude earthquake hit another rural area just north of Interstate 37 and State Highway 72 at 10:53 p.m. Friday. The epicenter of a third earthquake, registered directly below a cove at the North Shore Unit of Choke Canyon State Park at 9:48 p.m. Saturday. Choke Canyon State Park is a popular destination for sports fishermen, campers and picnickers. Officials with the Texas Parks & Wildlife Department, the state agency that oversees the South Texas fishing spot, told the Houston Chronicle that park staff had no knowledge of the earthquake. Although area residents took to Facebook to talk about the tremors, the Live Oak County Sheriff's Office reported that dispatchers did not receive any calls about the earthquakes and that there were no reports of damage. Environmentalists, however, blame the earthquakes on saltwater disposal wells, which inject wastewater generated in the hydraulic fracturing process and other oil and natural gas activities deep underground. Regulations: Railroad Commission launches online tool for enforcement, inspection data Saltwater disposal wells are regulated by the Railroad Commission of Texas. A review of agency records show that there are more than 200 injection and disposal wells in Live Oak County. Railroad Commission officials told the Houston Chronicle that its regional office has received no complaints regarding the weekend earthquakes in the area.

Company to pay following crude oil spills in Texas, LA and OK - Years after three oil spills in three states, a company has to agree to pay up.Sunoco Pipeline L.P. will pay civil penalties, state enforcement costs and will implement corrective measures to resolve alleged violations of the Clean Water Act and state environmental laws under a proposed consent decree lodged on Jan. 30 in the U.S. District Court of the Western District of Louisiana. Sunoco will pay the United States $5 million in federal civil penalties for the Clean Water Act violations and pay Louisiana Department of Environmental Quality $436,274.20 for civil penalties and response costs to resolve claims asserted in a complaint.The company will take actions to prevent future spills.The incidents stem from allegations from Sunoco and Mid-Valley Pipeline Company crude oil spills in 2013, 2014 and 2015 in Oklahoma, Texas and Louisiana.“This settlement holds Sunoco and Mid-Valley accountable for the harms to the environment caused by their oil spills and requires Sunoco to improve its environmental safety compliance for the oil pipelines that it operates in Texas, Louisiana, and Oklahoma,” said Assistant Attorney General Jeffrey Bossert Clark for the Justice Department’s Environment and Natural Resources Division, in a news release.“This excellent result shows how a strong federal and state partnership can bring about effective environmental enforcement to protect local communities in these states,” Bossert Clark said.In 2013, 550 barrels of crude oil was spilled in Tyler County Texas. In 2014 a spill of approximately 4,500 barrels were spilled in Caddo Parish near Mooringsport, Louisiana and a 2015 spill in Grant County, Oklahoma were 40 barrels were spilled. The Louisiana spill—the largest of the three—flowed to Tete Bayou, a tributary of Caddo Lake.The Texas spill affected Russell Creek, which flows to the Neches River; and in Oklahoma, the spill flowed into two creeks that connect to the Arkansas River. Only about half a mile of area was affected. The cause of all three spills were from pipeline corrosion.

New EPA policy would offer alternative to penalties for some oil, gas polluters - The Environmental Protection Agency’s (EPA) office of enforcement will soon unveil a new finalized audit policy that will offer significant new penalty reductions for the oil and gas industry, according to two internal memos obtained by The Hill.The New Owner Clean Air Act Audit Program, tailored specifically for oil and natural gas producers, will focus on offering more flexibility to new company owners who choose to self-audit their emissions and report any failures to meet EPA’s regulations, according to the December draft memos for the new policy.The policy originally was slated to be rolled out in late December but was delayed due to the partial government shutdown, according to an EPA source with knowledge."Policy finalization has been delayed; we can provide more details when we have a final policy to announce,” an  EPA spokesperson said of the rule.The flexibilities include giving new owners of oil and gas companies nine months since the company is acquired to come forward to the EPA and announce any emissions issues they believe may exist. That’s an increase from the six months the agency first proposed in its original draft template of the rule.Companies would also be given 180 days from the date of discovery to correct the emissions issue. The previous draft gave companies 60 days.  The policy proposal was first reported by The Hill and unveiled last April.  The changes come after EPA’s Office of Enforcement and Compliance Assurance (OECA) received feedback from oil and gas industry players who thought the previous timeline was too burdensome.

ExxonMobil reports 90% increase in Permian shale production -  — Fueled partly by a dramatic increase in Permian output, ExxonMobil announced Friday a 4% jump in liquids output in Q4 from the same quarter last year. ExxonMobil's net production of crude oil, natural gas liquids, bitumen and synthetic oil averaged nearly 2.35 million b/d in Q4, up from 2.25 million b/d in Q4 2017. US liquids production averaged 583,000 b/d in Q4, up from 525,000 b/d in Q4 2017, the company said."Permian unconventional production continued to ramp up in the fourth quarter, with production up more than 90% from the same period last year," the company said.For all of fiscal 2018, liquids production averaged about 2.27 million b/d, down slightly from 2017, when the company's output averaged about 2.28 million b/d.Including natural gas, ExxonMobil averaged production of 4.01 million boe/d in Q4, up from 3.99 million boe/d in Q4 2017.The company reported estimated earnings of $20.8 billion in 2018, up from $19.7 billion in 2017, an increase it attributed partly to higher natural gas prices.

Natural gas flaring in West Texas severely under-reported, satellite analysis shows - Oil and gas companies in West Texas’ Permian Basin burned off nearly twice as much natural gas they reported to regulators, according to an analysis of satellite data by an environmental advocacy group. Operators are required to report the amount of flaring, or burning of excess product, to the Texas Railroad Commission, the state agency that oversees the energy industry. In 2017, companies reported 55 billion cubic feet of flared natural gas. But an analysis performed on satellite data collected by the National Oceanic and Atmospheric Administration indicates that 104 billion cubic feet of flared gas may have been flared, according to the Environmental Defense Fund.The Environmental Defense Fund’s analysis suggests that operators burned away 4.4 percent of all natural gas produced in the Permian that year, valuing the lost gas at $322 million. S&P Global Market Intelligence, a research and data analysis firm, reached similar conclusions of severely under-reported flaring in a report published in October. The S&P Global analysis also used data from NOAA satellite scans, which analysts said are more accurate than reports companies file with regulators. Between 2012 and 2017, the analysis found, oil and gas companies in Texas reported only about half the volumes of gas burned compared to what the satellites showed. Greenhouse gases Burning associated gas, the raw natural gas that is a mixture of methane and other hydrocarbons, emits carbon dioxide and air pollutants such as nitrogen oxides and sulfur dioxide. Flaring has been found to be a significant contributor to U.S. greenhouse emissionsand pose a significant health risk for local communities and those who work in oil fields. Natural gas is a byproduct of oil production, and in booming West Texas, large volumes are being produced along with record amounts of oil. A lack of pipeline capacity has left energy companies with lots of natural gas with no place to go, according to S&P Global analysts, and provided an incentive to under report flaring to maintain high levels of crude production. 

Water needed for hydraulic fracking has more than doubled - The amount of water needed for hydraulic fracturing operations has more than doubled in recent years and is slated to top 6 billion barrels in 2021, the consultancy Rystad Energy said in a note. It's a metric of the massive scale of the U.S. oil boom that has sent production to record levels. That's largely thanks to growth in shale formations — most notably the Permian Basin in Texas and New Mexico — where hydrocarbons are pried loose using high-pressure injections of water, sand and chemicals.  A Rystad analyst said in the note that the industry will be able to get the water it needs as production grows and water demand soars with it.  "This surge is driven by both increased activity and higher proppant intensity. But even with such steep growth, market concerns about sourcing challenges and bottlenecks appear to be minimal,” Rystad SVP Ryan Carbrey said in a statement. However, the report also warns of looming constraints for dealing with wastewater that comes out of wells. "With produced water in the Permian set to increase by a third by 2021 there will be local disposal constraints, but at a macro level spare disposal capacity will remain," it states.  The volumes of water needed to support the growth of shale production has long been an ecological concern.  A study by Duke University researchers found that water use per well in major shale oil-and-gas basinshas risen by as much as 770%. Yesterday, the Energy Information Administration forecast that oil production from shale formations would rise by 62,000 barrels per day in February to reach 8.18 million barrels per day. Via S&P Global Platts, the forecast rise of 23,000 barrels per day in the Permian basin "would be the lowest rate of monthly growth the EIA has forecast for the Permian since September 2016."

New Study Links Fracking To Unsustainable Water Use - Everybody is talking about a new report that credits the US oil and gas fracking boom with a 770% increase in water consumption over the past few years. The sharp increase is certainly eye-catching but it’s not exactly a surprise. The force of the water-energy nexus is strong within the fossil fuel industry, especially when the idea is to force massive volumes of water into underground rock formations. . The Avner Vengosh Research Group at Duke University’s Nicholas School of the Environment is behind it, and that should be one tipoff that this particular study is particularly significant.The team has been investigating the impact of fracking on water resources since the US fracking boom began gathering steam and they have assembled quite a body of research.The new study builds on earlier research, which suggests that fracking adds another layer of stress in areas that are already experiencing water resource issues.That stress doesn’t necessarily have to directly impact public health or the environment. It could also impact economic activity.Here’s the money quote: The amount of water used per well for hydraulic fracturing surged by up to 770 percent between 2011 and 2016 in all major U.S. shale gas and oil production regions, a new Duke University study finds.The volume of brine-laden wastewater that fracked oil and gas wells generated during their first year of production also increased by up to 1440 percent during the same period, the study shows.If this rapid intensification continues, fracking’s water footprint could grow by up to 50-fold in some regions by the year 2030 — raising concerns about its sustainability, particularly in arid or semi-arid regions in western states, or other areas where groundwater supplies are stressed or limited. In other words, the study could provide communities with a fact-based platform for limiting or prohibiting fracking, even if there is no evidence of water contamination.

The intensification of the water footprint of hydraulic fracturing - Unconventional oil and gas exploration in the United States has experienced a period of rapid growth, followed by several years of limited production due to falling and low natural gas and oil prices. Throughout this transition, the water use for hydraulic fracturing and wastewater production in major shale gas and oil production regions has increased; from 2011 to 2016, the water use per well increased up to 770%, while flowback and produced water volumes generated within the first year of production increased up to 1440%. The water-use intensity (that is, normalized to the energy production) increased ubiquitously in all U.S. shale basins during this transition period. The steady increase of the water footprint of hydraulic fracturing with time implies that future unconventional oil and gas operations will require larger volumes of water for hydraulic fracturing, which will result in larger produced oil and gas wastewater volumes. The environmental impacts of a fossil fuel–powered economy have led many nations across the world to begin developing greener energy and transportation solutions. In particular, the water footprint of fossil fuel exploration and electricity production has been projected to have major environmental impacts. It has been estimated that global water withdrawal for energy production constitutes 15% of the world’s total water consumption (1). Rapidly diminishing global water resources due to population growth and climate change have further exacerbated energy dependence on water availability, particularly in water-scarce regions (2–5). The beginning of the 21st century marks a special era with respect to global energy and water resources. The development of new drilling technologies and production strategies such as horizontal drilling and hydraulic fracturing has significantly improved the production of natural gas and oil by stimulating fluid flow from impermeable shale rocks previously not considered viable energy sources. Since the mid-2000s, these developments have spurred exponential growth of unconventional gas and oil well drilling across the United States and are spreading now to other parts of the world (Figs. 1 and 2) (4, 6–10). The rise of unconventional energy development has generated public debate on its environmental implications (11–16), especially with respect to both water availability and quality (2, 4, 8, 17–21).

Is The Permian Bull Run Coming To An End? -  The bad news coming out of the shale oil fields of America could all be put down to slumping oil prices. That is certainly a big factor. But as investment professionals like to say, when the tide goes out, we all find out who's been skinny-dipping. The pattern of negative news from shale country is not just related to price, however. Oil production, it seems, is being overstated industry-wide by 10 percent and 50 percent in the case of some companies, according to The Wall Street Journal.The CEO of one of the largest players in the industry, Continental Resources, predicted that growth in shale oil production could fall by 50 percent this year compared to last year. In reality, we should expect worse as the industry for obvious reasons tends to exaggerate its prospects.The place where the damage to investors has become severe is in private equity firms who hold a large portion of the shale oil industry's high-yield debt. The plan for the firms was always to unload the debt on somebody else when better opportunities presented themselves. But the firms overstayed their welcome and are having a hard time even finding a bid in the market for these bonds.With the big Wall Street players now questioning the value of their existing investments in shale oil, the industry is finding it hard to raise money. Not a single bond sale has come off since November in an industry which must continuously raise capital to survive.To add to the problems, the future of U.S. shale oil production seems to be in the Permian Basin in Texas which has been providing the lion's share of oil production growth for the entire country. But ongoing drought in an already arid West Texas has raised doubts about whether the Permian will have enough water to meet all the demand for fracking new wells.Because of the rapid declines in the rates of production from shale wells, companies must first drill enough new wells to offset the loss of production from previous wells—a task akin to walking up the down escalator.This was not such a difficult task when the shale boom was just beginning. But with the huge increase in the number of operating wells, companies are having to spend more than half of their capital budgets on simply replacing lost production before drilling wells that add to production. That number is expected to reach 75 percent by 2021. At some point it could reach 100 percent. (For this reason some analysts refer to shale oil development as a Ponzi scheme.) With rig counts dropping; capital expenditures likely to be cut in the face of low prices; and more and more of that budget being used simply to replace existing production, it's possible that the death spiral long anticipated by the industry's critics has arrived.

Cleanup underway after northern Oklahoma crude oil spill - Crews are working to contain thousands of gallons of crude oil that leaked into a creek in northern Oklahoma. Oklahoma Corporation Commission spokesman Matt Skinner said Wednesday oil extends for about 5 miles (8 kilometers) in Black Bear Creek in rural Garfield County. Skinner says the spill was reported Tuesday by Great Salt Plains Midstream of Oklahoma City, a pipeline operator. The oil apparently leaked from an open valve on a tank. Skinner says the cause is under investigation. He says about 750 barrels, or 31,500 gallons (119,240 liters), leaked and that crews are "working around the clock" to remove the oil. Skinner says there's no threat to those people who live in the area. A representative of Great Salt Plains Midstream didn't immediately return a call seeking comment.

Broomfield Homeowners Sue To Stop "Forced Pool" Oil Drilling Under Their Land - A group of Broomfield homeowners on Wednesday filed a lawsuit that challenges the nearly century-old practice that allows oil and gas companies to drill under their property using “forced pooling.”   Forced pooling gives oil and gas companies the right to drill — without property owners’ consent — as long as the company makes a “reasonable” offer and at least one homeowner signs the lease.  With that sole thumbs up, the company can then ask the Colorado Oil and Gas Conservation Commission, the state body regulating the industry, to “pool in” the remaining land — over the objections of other owners. More than half the states in the country have some variation of this law, which originated in the 1930s as a way to insure that a property owner who didn’t want oil and gas rigs on his property could not deprive his neighbor of the right to develop them.  Once the pooling happens, non-consenting property owners have fairly little recourse. By refusing to sign the forced-pool lease, homeowners can be punished: they receive a limited royalty and are required to pay up to three times what consenting owners have to shell out to cover parts of the fracking project. The lawsuit was initiated by the Wildgrass Oil and Gas Committee, a group of anti-fracking activists out of Broomfield. It represents more than 900 local residents who WOGC says were forcibly pooled into one parcel, according to a permit application that Extraction Oil & Gas filed with the COGCC.  Extraction Oil & Gas officials did not respond to a request for comment from The Independent. But the Colorado Oil and Gas Association said the practice has long legal precedent and that land owners have ample opportunity to decide if they want to allow drilling.

Colorado court asked to reconsider ruling in oil-gas case (AP) — The Colorado Supreme Court was asked Thursday to reconsider its decision in an oil and gas lawsuit filed by Hispanic and Native American plaintiffs because a disciplinary panel found that a lower court judge who had a role in the case used a racial slur. The request asks the court to revisit its Jan. 14 ruling against the plaintiffs, who wanted oil and gas regulators to make health and environmental protection their top priority in setting rules for the industry. The Supreme Court ruled that state law does not require regulators to do that. In their new filing, the plaintiffs said the Supreme Court relied in part on an opinion written by Colorado Court of Appeals Judge Laurie Booras, who resigned this month after a disciplinary panel recommended she be removed from the court. The panel said Booras had written an email using racial slurs and demeaning nicknames for a Native American woman and a Hispanic woman. The Hispanic woman was a fellow Court of Appeals judge. The panel said Booras’ language “creates a double-barreled appearance of impropriety” and undermined public trust in her impartiality. The plaintiffs say Booras’ comments reflect “racism, bias and a lack of impartiality.” The disciplinary panel also said Booras told a third party that she intended to write an opinion against the plaintiffs, a violation of confidentiality rules. Booras did not immediately respond to a phone call and email seeking comment Friday. The Colorado Oil and Gas Conservation Commission, which regulates the industry and was a defendant in the lawsuit, had no immediate comment. The state attorney general’s office declined comment. The original lawsuit argued that state law requires the oil and gas commission to ensure energy development does not harm people’s health or the environment. The six young plaintiffs asked the commission in 2013 to require those protections before issuing any drilling permits. The commission refused, saying the law required it to balance health and environmental concerns with other factors. The Supreme Court agreed with the commission. 

Weld County oil and gas spill report for Jan. 27 -  The following spills were reported to the Colorado Oil and Gas Conservation Commission in the past two weeks. Information is based on Form 19, which operators must fill out detailing the leakage/spill events. Any spill release that may impact waters of the state must be reported as soon as practical..

• • NOBLE ENERGY INC, reported Jan. 18 a historical well spill in Evans, near Hawk Drive and 27th Avenue. Between one and five barrels each of oil, condensate and produced water spilled. Crews found historical soil impacts during plugging and abandonment. About 30 cubic yards of soil was excavated and taken to the Ault Landfill operated by Waste Management.
• • SRC ENERGY INC, reported Jan. 17 a historical tank battery spill in Windsor, south of Weld County roads 63 3/4 and 23. Less than five barrels of produced water spilled. Waters of the state were impacted or threatened. Crews found the spill during abandonment.
• • PDC ENERGY INC, reported Jan. 16 a tank battery spill about 1 mile southeast of Greeley, near Weld roads 54 1/2 and 45. An unknown amount of more than five barrels of oil spilled. Crews found the spill inside secondary containment at the compressor unit.

US oil lease near sacred park pushes forward (AP) — U.S. land managers will move forward in March with the sale of oil and gas leases that include land near Chaco Culture National Historical Park in New Mexico and other areas sacred to Native American tribes. The sale comes as Democratic members of Congress, tribal leaders and environmentalists have criticized the federal Bureau of Land Management for pushing ahead with drilling permit reviews and preparations for energy leases despite the recent government shutdown. With limited staff over the last month, the critics complained that they were locked out of the process because the agency didn’t release any information about the sale. They also questioned whether the agency would be able to adequately review the land that’s up for bid and whether it would consider protests to the move. U.S. Sen. Tom Udall told The Associated Press in an email that he’s concerned about the latest attempt to lease potentially culturally significant land in New Mexico without a more comprehensive plan in place. “It’s a mistake that while critical public services were shuttered for 35 days during the government shutdown, BLM still moved forward with this opaque process,” the New Mexico Democrat said. Agency spokeswoman Cathy Garber said officials decided to push back the lease sale by a couple of weeks to accommodate a public protest period that was delayed because of the shutdown. The agency quietly confirmed on its website that it would accept comments starting Feb. 11 and that the sale was scheduled for March 28. Depending on the outcome of the protests, it’s possible for the agency to put off or withdraw nine parcels of land that are within 10 miles (16 kilometers) of Chaco, a world heritage site with massive stone structures, kivas and other features that archaeologists believe offered a religious or ritualistic experience. Accessible only by rough dirt roads, Chaco takes effort to reach, and supporters say they want to protect the sense of remoteness that comes with making the journey. For tribes, the fight is centered on preserving what remains of a ceremonial and economic hub that dates back centuries. In all, more than 50 parcels in New Mexico and Oklahoma will be up for bid. 

Feds to Sell Even More Public Land for Fracking Near Sacred Park -The U.S. Bureau of Land Management (BLM) is pushing ahead with the sale of oil and gas leases on land outside of Chaco Culture National Historical Park and other sites revered by Native American tribes, The Associated Pressreported.The latest listing—which quietly appeared on the BLM website not long after the government reopened after the shutdown—comes about a year after then-Interior Secretary Ryan Zinke postponed a lease sale in the Greater Chaco Region in response to intense public pressure over cultural and environmental concerns.BLM will open a protest period for comments from Feb. 11 through Feb. 20 for a sale scheduled for March 28, according to the agency's notice. More than 50 parcels in New Mexico and Oklahoma will be on the auction block. During the record-long government impasse, Democrats, environmentalists and others fiercely criticized theTrump administration for moving ahead with drilling permits on public lands while most other agencies were shut."It's a mistake that while critical public services were shuttered for 35 days during the government shutdown, BLM still moved forward with this opaque process," Sen. Tom Udall, Democrat of New Mexico, told the AP about the latest lease.The AP noted that it is possible for BLM to withdraw the latest land sales depending on the outcome of the protest period.For years, environmental groups, tribes and other opponents have raised flags about fracking encroaching on and threatening Chaco Canyon, a major center of ancient Pueblo culture and a UNESCO World Heritage Site. As it happens, the park sits in the central San Juan Basin in northwestern New Mexico that's booming with shale gas extraction. Roughly 90 percent of the Great Chaco Region is already leased for oil and gas development, but more fossil fuels lie beneath those lands. The New Mexico BLM wants to sell parcels that are close or just along the park's 10-mile, no drilling buffer zone.

Navajos Speak out on the Cultural and Biochemical Dangers of Fracking around Chaco Canyon - As a member of the Navajo Tribe, the majority of my 29 years have been spent within 15 miles of one of America's truly most sacred indigenous sites, Chaco Canyon, especially sacred to the Hopi and other pueblo groups, which descended from the Anasazi. This sacred site was constructed more than 900 years ago, as primarily a repository and residence for an agricultural priesthood that used the archeo-astronomical observatory called the Sun Dagger to predict the solstices, and thus the best time for planting. If you drew a triangle between Crownpoint, Farmington, and Cuba, New Mexico, you would be looking at the great Chaco Canyon area, which the Trump administration turned over to the Bureau of Land Management to in turn make available to large energy companies for fracking. In northwestern New Mexico's high desert lie the threatened ruins of Chaco Canyon containing the remnants of kivas, ancient roads and sacred places built a millennium ago by indigenous people proficient in architecture, agriculture, astronomy and the arts. This is at risk from the Trump administration in allowing oil-and-gas drilling. In the early 20th century, when archaeologists became alarmed by the plunder and damage to some of these accessible and fragile sites, Chaco Canyon was the catalyst for Congress's protection by authorizing the president to declare them national monuments. Theodore Roosevelt signed the Antiquities Act in 1906, and in 1907 he invoked it to declare Chaco one of the first national monuments deserving the protection of the United States government. Chetro Ketl, another of the large structures known as great houses that were built by indigenous inhabitants of Chaco Canyon. The surrounding area is the domain of the Bureau of Land Management and the Bureau of Indian Affairs whose missions do not emphasize protecting historically significant sites. The 2 agencies previously agreed to defer all new drilling leases within a 10-mile radius of Chaco until consultations could be completed with affected communities and tribes. The B.L.M. district manager says the bureau plans to lease 26 parcels of land in the area.

TransCanada seeks water permits for Keystone XL construction -- South Dakota regulators are considering several water-permit applications for the proposed construction of the Keystone XL crude-oil pipeline. TransCanada, the Canadian company seeking to build the pipeline, recently applied for three permits to withdraw water from the Cheyenne, Bad and White rivers in western South Dakota. Additionally, at least two sets of western South Dakota landowners recently applied to use existing wells as backup water supplies for pipeline construction workforce camps. In the three applications from TransCanada, the sum of the requested water withdrawals is about 167 million gallons annually. The applications say the water would be used during the construction of the pipeline for dust control, horizontal-directional drilling, pump-station construction and hydrostatic testing of the pipeline. The chief engineer of the state Department of Environment and Natural Resources has recommended approval of the permits, which are scheduled to be considered by the state Water Management Board at 1 p.m. March 6 in the Joe Foss Building at Pierre. The hearing will be automatically delayed for at least 20 days if anyone files petitions against the applications and asks for a delay by Feb. 25.

Law officers respond to suit over pipeline protester injury - — Law enforcement officials in North Dakota say they aren’t to blame for a severe arm injury a New York City woman sustained while protesting the Dakota Access oil pipeline and that public statements they made blaming her weren’t aimed at damaging her character. They’re asking a federal judge to throw out a lawsuit that Sophia Wilansky filed in November seeking millions of dollars in damages for alleged excessive force, assault, negligence, emotional distress and defamation. Defense attorneys argue in court documents filed this week that Wilansky has no plausible evidence that her civil rights were violated. Wilansky was injured during a violent November 2016 clash between protesters and police during the unsuccessful months-long protest in southern North Dakota against the $3.8 billion pipeline. Texas-based Energy Transfer Partners built it to move North Dakota oil to a shipping point in Illinois, which it began doing in June 2017. Wilansky, 21 at the time, suffered a left arm injury in an explosion and has since had five surgeries. Protesters allege the blast was caused by a concussion grenade thrown by officers, but police maintain it was caused by a propane canister that protesters rigged to explode. Who is right is still unknown. Wilansky last November sued local and state law enforcement officials and Morton County in federal court, alleging that an unknown law officer threw a flashbang device directly at her, and that officers laughed rather than help her as she lay on the ground in agony. Wilansky also says law enforcement made untrue and defamatory public statements about her allegedly carrying an explosive device.

How Police, Private Security, and Energy Companies Are Preparing for a New Pipeline Standoff - Minnesota police have spent 18 months preparing for a major standoff over Enbridge Line 3, a tar sands oil pipeline that has yet to receive the green light to build in the state. Records obtained by The Intercept show that law enforcement has engaged in a coordinated effort to identify potential anti-pipeline camps and monitor individual protesters, repeatedly turning for guidance to the North Dakota officials responsible for the militarized response at Standing Rock in 2016.Enbridge, a Canada-based energy company that claims to own the world’s longest fossil fuel transportation network, has labeled Line 3 the largest project in its history. If completed, it would replace 1,031 miles of a corroded existing pipeline that spans from Alberta’s tar sands region to refineries and a major shipping terminal in Wisconsin, expanding the pipeline’s capacity by hundreds of thousands of barrels per day.The expanded Line 3 would pass through the territories of several Ojibwe bands in northern Minnesota, home to sensitive wild rice lakes central to the Native communities’ spiritual and physical sustenance. Given that tar sands are among the world’s most carbon-intensive fuel sources, Line 3 opponents underline that the pipeline is exactly the kind of infrastructure that must be rapidly phased out to meet scientists’ prescriptions for mitigating climate disasters.The Line 3 documents, which were obtained via freedom of information requests, illustrate law enforcement’s anxiety that pipeline opponents could galvanize support on a scale similar to the Dakota Access pipeline struggle, which drew thousands of protesters to the Standing Rock Sioux reservation in southern North Dakota.  A police response like the one in North Dakota is a significant concern for Line 3 opponents. At Standing Rock, law enforcement used water cannons, rubber bullets, armored personnel carriers, and sound cannons in an operation that resulted in serious injuries. Aided by private intelligence and security firms working for the pipeline, they gathered information on protesters via aerial surveillance, online monitoring, embedded informants, and eavesdropping on radio signals. In a time of growing resistance to fossil fuel industries, the public-private partnership served as a chilling example of law enforcement agencies acting as bulwarks of the oil industry.

L.A. Neighborhood Learns About Methane Blowout a Week After It Happened -  Residents, lawmakers and environmentalists from a seaside community in Los Angeles County are questioning why it took a whole week for government officials to inform them of a well blowout that sprayed natural gas and other fluids nearly 60 feet into the air for several minutes. On Jan. 11, hotel construction workers in a populated area in Marina del Rey dug into an abandoned, 1930s-era oil well, causing an eruption of mainly methane, heavy abandonment mud and water. Video footage shows the fluids shooting high into the sky, and a worker rappelling away to avoid injury. The oil well was last sealed in 1959 and was in the process of being re-sealed before the release. But government officials did not notify the public about the incident for at least a week, LAist reported, prompting major concern from local residents and L.A. City Councilman Mike Bonin, who said on Facebook that "the site is immediately across the street from the homes of several hundred City residents I represent." "I am particularly concerned at the lack of notification to neighbors, and at continued risks of leaks due to a potential lack of structural integrity of the well, which state officials said was a 'serious concern.' This incident also raises concerns about other old and abandoned wells in the area," he added. On Jan. 18, the California State Department of Oil Gas & Geothermal Resources (DOGGR) issued an emergency order to bring the well under control, to permanently plug the well and to investigate why it occurred. The statement noted that the Jan. 11 blowout was a threat to life, health, property and natural resources. "Because of the serious concerns about the structural integrity of the well and the sensitive location of the well, efforts to secure the site and properly plug and abandon the well must be undertaken without delay," DOGGR stated.

Iconic landscapes threatened by drilling and fracking proposal - The Bakersfield Californian’s Jan. 15 story (“'Overwhelming' opposition to oil activity may present challenge to local industry”) about public opposition to a Bureau of Land Management (BLM) proposal to open over one million acres of federal land and mineral estate to new oil drilling and fracking demonstrates just how unpopular the proposal is in Kern County and throughout central California.  Almost 5,000 acres of land within one mile of Sequoia National Park are listed as “open” for fossil fuel leasing under the BLM’s proposal. This would be new drilling and fracking on federal land along the park’s boundary — an area where there’s currently no oil development. The plan could also open over 2,000 acres near the southern entrance to Yosemite National Park. The agency’s plan would allow oil and gas leasing of a combined 44 square miles of federal land along the boundaries of the Carrizo Plain and Giant Sequoia National Monuments near Bakersfield. Both monuments only recently survived an attempt by the Trump administration to shrink or eliminate them.Over 240 square miles of land along the boundaries of four national forests — Sequoia, Sierra, Inyo and Los Padres — would be open to leasing as well. Many of these areas are directly adjacent to protected wilderness areas. To top that off, at least nine parcels of land overlapping the world-famous Pacific Crest Trail would also be open to oil and gas development under the proposal.The plan would also open over 70 square miles of land in and around national wildlife refuges and state ecological reserves to leasing, jeopardizing important habitat for many threatened, endangered and rare plants and animals. Areas such as Bitter Creek National Wildlife Refuge and the Bakersfield Cactus, Canebrake and Carrizo Plains Ecological Reserve are at risk of being opened to drilling and fracking.The plan could even threaten Bakersfield’s water supply. Approximately 87 square miles surrounding Lake Isabella — one of the city’s primary sources of drinking water — would be open to drilling and fracking leases under the plan. Not only would this have major implications for Bakersfield residents, much of the leasing in the Lake Isabella area would be in and around neighborhoods.

King County Council approves 6-month moratorium on major fossil-fuel facilities - The King County Council on Monday approved a six-month moratorium on building or expanding major fossil-fuel infrastructure, joining other local governments in the Northwest with similar measures that aim to use local zoning laws to restrict fossil-fuel pipelines, storage facilities and other infrastructure.The ordinance, introduced by Councilmember Dave Upthegrove, disallows permitting for fossil-fuel projects in unincorporated King County. It also directs the county executive’s office to produce a survey of existing facilities, study those facilities’ impacts on communities, analyze the existing regulations that apply to them, recommend changes to regulations and permitting, and evaluate county-owned facilities for health impacts. The ordinance also declares a state of emergency.“Reducing the pollution that causes climate change is quite possibly the greatest moral imperative facing my generation,” said Upthegrove. “Our action makes it clear, here in King County, our future is not fossil fuels but a clean-energy future.” The moratorium is fairly limited. The ordinance does not apply to gas stations or other fossil-fuel products sold directly to consumers. It does not disallow existing infrastructure or directly address rail lines or pipelines, w hich are regulated by the federal government. It excludes fuel storage for airports, marine servicing facilities and railyards.

US Oil and Gas Production to Outpace Russia and Saudi Arabia by 2025 - U.S. oil and gas production is expected to exceed the combined production from Russia and Saudi Arabia by 2025, according to research firm Rystad Energy. Rystad expects U.S. liquids production – such as crude oil, lease condensate and plant natural gas liquids – to surpass 24 million barrels per day over the next six years, beating out Russia and Saudi Arabia combined. “The United States, having regained its position as the world’s top liquids producer in 2014, is poised to accelerate into a league of its own over the next six years and eclipse the collective output of its two closest rivals by 2025,” said Rystad Energy partner Artem Abramov. The growth in U.S. liquids production will be fueled by major shale basins such as the Permian. In the past, the United States, Russia and Saudi Arabia have juggled among each other which is the top of the global list of liquid producers. However, the U.S. market-driven oil activity and production has built a great deal of momentum for the country. Abramov added that as long as average prices stay above $50, U.S. production is expected to remain positive.

New US oil and gas drilling to unleash 1000 coal plants' worth of pollution by 2050 - Amid mounting calls to phase out fossil fuels in the face of rapidly worsening climate change, the United States is ramping up oil and gas drilling faster than any other country, threatening to add 1,000 coal plants’ worth of planet-warming gases by the middle of the century, according to a report released Wednesday.By 2030, the U.S. is on track to produce 60 percent of the world’s new oil and gas supply, an expansion at least four times larger than in any other country. By 2050, the country’s newly tapped reserves are projected to spew 120 billion metric tons of carbon dioxide emissions into the atmosphere.That would make it nearly impossible to keep global warming within the 2.7 degrees Fahrenheit above pre-industrial averages, beyond which United Nations scientists forecast climate change to be catastrophic, with upward of $54 trillion in damages.The findings ― from a report authored by the nonprofit Oil Change International and endorsed by researchers at more than a dozen environmental groups ― are based on industry projections collected by the data service Rystad Energy and compared with climate models used by the United Nations’ Intergovernmental Panel on Climate Change (IPCC), the world’s leading climate research body.The report casts a new light on the impact of the U.S. fracking boom and calls into question the Trump administration’s stance that China, which surpassed the U.S. as the world’s largest emitter of carbon dioxide in 2007, remains the biggest impediment to halting warming.“The United States is moving further and faster to expand oil and gas extraction than any other country,” said Kelly Trout, the report’s lead author and a senior research analyst at Oil Change International. “We need to be transitioning off oil and gas, and the United States dumping huge amounts of dirty oil on the world market is incompatible with effectively and equitably addressing climate change.”

Trouble In Paradise For U.S. Frackers - Forecasters project a large increase in U.S. oil production over 2019. The size of this increase ranges from four hundred and twenty thousand barrels per day (Citibank) to 1.7 million barrels per day (OPEC). The most recent forecast, issued January 18 by the IEA, sees an increase of almost eight hundred thousand barrels per day. (Figure 1 presents the production history and forecast from the EIA’s latest Short-Term Energy Outlook.) The output increase is primarily associated with the rise in production in the key onshore provinces where fracking occurs: Anadarko, Bakken, Eagle Ford, Niobrara, and Permian. The optimism expressed in these forecasts is understandable when considering just how spectacular the production surge from these areas has been.This continued expansion and the realization of these optimistic forecasts, however, could be threatened by the collapse of fracking’s silent companions: oil future buyers. Reuters reported recently on the demise of several energy hedge funds in 2018. One commentator noted the “massive decline in the number of funds and no replacements.” He even went so far as to suggest that there had been “a near ‘extinction event’ in commodities hedge funds.” The article notes that the number of hedge funds focused on oil or gas declined to 179 in 2018 through September from 194 in 2016. The authors added that many funds lost money in 2018 because they placed “increasingly large bets on the rally continuing” through the end of 2018. They were harshly punished when prices fell from $85 to $50 per barrel.The decline in speculative interest in oil will probably create a serious problem for some independent producers because these firms need to hedge some or all incremental output against price declines. Declining interest in oil will raise the cost of hedging, possibly putting it out of reach of some firms. This, it can be argued, is fracking’s Achilles’ heel. The frackers’ problems will be compounded by continued demands that producers pay dividends and return capital. As the various investors quoted by Bethany McLean in Saudi America explained, the fracking business has rarely if ever been cash-flow positive. The consequence could be stagnation or even a decline in U.S. production from end-December 2018 levels by the close of 2019.

Trump's Price Policies Hurting US Shale Activity - With oil prices around the mid-50s, more than three quarters of U.S. shale E&P companies are unable to cover capital spending from operating cash flow. Because, as Rystad Energy ShaleWellCube notes, the well-head break-even prices for 2018 were on average too low for comfort at Eagle Ford $47.68; Bakken at $44.13; $42.76 in the Permian Midland and $37.94 in Permian Delaware. The decline in U.S. West Texas Intermediate (WTI) crude futures from a near four-year high of $76.90 Oct. 3, 2018 to a one-year low of $53.76 Jan. 18 has hit the over-leveraged independents hard. In addition, the industry faces rising competition if President Trump expands drilling rights in Federal lands and offshore. The decline of more than a third in U.S. West Texas Intermediate (WTI) crude futures since the autumn owes much to record output from Saudi Arabia and Russia, a response to rising oil prices and encouragement from the President. On Nov. 21, President Trump publicly praised Saudi Arabia and encouraged the downward price trend, saying, “let’s go lower,” broadcaster CNBC reported. Meanwhile, thanks to gushing oil wells in the Permian shale basin, the United States became the world’s largest crude producer at 11 million barrels a day, according to the EIA. Nevertheless, December’s OPEC, Russia, and Kazakhstan meeting formally agreed to cut output from January by 1.2 million barrels a day (MMbpd) rather than the widely expected 1.4 MMbpd needed to rebalance supply and demand. In practice, OPEC’s output fell by 751,000 barrels per day to 31.6 during December with Saudi Arabia cutting 468,000 barrels per day. Brent crude price responded, rising to $62.70 in January. It is rumored that the United States' grant of waivers to eight major customers of Iranian oil eroded Saudi support for lower oil prices. A more likely explanation is that many OPEC members need higher oil prices. For example, Saudi Arabia needs at least $73 a barrel to balance its budget, according to the IMF, and possibly as much as $85 a barrel to finance its Vision 2030 Plan. One thing is clear, the actions of OPEC and friends to cut back output this year could be good news for U.S. shale frackers as crude prices rise, trade tensions ease and world demand for crude holds up—but it could be disappointing for President Trump.

Has U.S. shale oil entered a death spiral? -- The bad news coming out of the shale oil fields of America could all be put down to slumping oil prices. That is certainly a big factor. But as investment professionals like to say, when the tide goes out, we all find out who's been skinny-dipping. The pattern of negative news from shale country is not just related to price, however. Oil production, it seems, is being overstated industry-wide by 10 percent and 50 percent in the case of some companies, according toThe Wall Street Journal. The CEO of one of the largest players in the industry, Continental Resources, predicted that growth in shale oil production could fall by 50 percent this year compared to last year. In reality, we should expect worse as the industry for obvious reasons tends to exaggerate its prospects.The place where the damage to investors has become severe is in private equity firms who hold a large portion of the shale oil industry's high-yield debt. The plan for the firms was always to unload the debt on somebody else when better opportunities presented themselves. But the firms overstayed their welcome and are having a hard time even finding a bid in the market for these bonds.  To add to the problems, the future of U.S. shale oil production seems to be in the Permian Basin in Texas which has been providing the lion's share of oil production growth for the entire country. But ongoing drought in an already arid West Texas has raised doubts about whether the Permian will have enough water to meet all the demand for fracking new wells. Because of the rapid declines in the rates of production from shale wells, companies must first drill enough new wells to offset the loss of production from previous wells—a task akin to walking up the down escalator. This was not such a difficult task when the shale boom was just beginning. But with the huge increase in the number of operating wells, companies are having to spend more than half of their capital budgets on simply replacing lost production before drilling wells that add to production. That number is expected to reach 75 percent by 2021. At some point it could reach 100 percent. (For this reason some analysts refer to shale oil development as a Ponzi scheme.) With rig counts dropping; capital expenditures likely to be cut in the face of low prices; and more and more of that budget being used simply to replace existing production, it's possible that the death spiral long anticipated by the industry's critics has arrived.

The Oil Shock That Never Was-- Three years ago, influential figures in the oil industry were sounding a clear warning: prices were too low, investment was collapsing and by the end of the decade the world would face a shortage. In reality, the market today is looking at several more years of plenty, so much so that OPEC is beginning its third year of production cuts just to prevent a surplus. “We’re in an age of abundance,” said Ed Morse, head of commodities research at Citigroup Inc. in New York. “A supply crunch is not likely at all.” So what happened? Oil’s biggest slump in a generation earlier this decade forced companies to slash spending, leading to a flurry of warnings that there wouldn’t be enough growth in oil supplies to meet rising demand and also offset production lost from aging fields. Investment in oil and gas production collapsed by about $350 billion, or more than 40 percent, from 2014 to 2016 -- the sharpest contraction since the 1980s -- after crude fell from over $120 a barrel to less than $30, according to the International Energy Agency. The number of new projects approved in 2017 dwindled to the lowest in 70 years, the Paris-based agency said. In November 2015, the IEA cautioned that supply growth outside OPEC would grind to a halt by 2020. Three months later it was ringing “alarm bells” for a coming crisis. Total SA Chief Executive Officer Patrick Pouyanne foresaw a shortfall of as much as 10 million barrels a day, about the volume Saudi Arabia was pumping at the time. The concerns were echoed across the industry, from Royal Dutch Shell Plc executives to hedge fund veteran Andy Hall. Instead, supply has turned out to be plentiful. The U.S. is estimated to produce about 12 million barrels a day of crude this year, a level it was earlier forecast to reach only in 2042. Russia has raised output to a record and Iraq’s is near unprecedented levels. Brazil is set to pump at the fastest pace in at least 15 years in 2019, according to the IEA. Bank of America Corp. estimates three-quarters of non-shale projects over the next five years will be profitable at just $40 oil, bringing new crude from the North Sea to Guyana even if prices stay low. These have kept benchmark Brent near $60 a barrel, despite a brief surge to a four-year high above $86 in October as American President Donald Trump’s sanctions against Iranian exports threatened to disrupt the market.

How the Peak Oil Story Could Be “Close,” But Not Quite Right - Gail Tverberg  - Fossil fuel producers tend to extract the fuels that are easiest to extract first. Over time, even with technology changes, this tends to lead to higher extraction costs for the remaining fuels. Peak oilers have been quick to notice this relationship.The question that then arises is, “Can these higher extraction costs be passed on to the consumer as higher prices?” Peak oil theorists, as well as many others, have tended to say, “Of course, the higher cost of oil extraction will lead to higher oil prices. Energy is essential to the economy.” In fact, we did see very high oil prices in the 1974-1981 period, in the 2004-2008 period, and in the 2011-2013 period.Unfortunately, it is not true that higher extraction costs always can be passed on to consumers as higher prices. Many energy costs are very well “buried” in finished goods, such as food, cars, air conditioners, and trucks. After a point, energy prices “top out” at what is affordable for citizens, considering current wage levels and interest rate levels. This level of the affordable energy price will vary over time, with lower interest rates and higher debt amounts generally allowing higher energy prices. Greater wage disparity will tend to reduce the affordable price level, because fewer workers can afford these finished goods.The underlying problem is that, from the consumer’s perspective, high oil prices look like inefficiency on the part of the oil company. Normally, being inefficient leads to costs that can’t be passed along to the consumer. We should not be surprised if, at some point, it is no longer possible to pass these higher costs on as higher prices.If higher extraction costs cannot be passed on to consumers, this is a terrible situation for energy producers. After not too many years, this situation tends to lead to peak energy output because producers and their governments tend to go bankrupt. This seems to be the situation we are reaching for oil, coal and natural gas. This is a much worse situation than the high price situation because the high price situation tends to lead to more supply; low prices tend to collapse the production system. The underlying problem is that low prices, even if they are satisfactory to the consumer, tend to be too low for the companies producing energy products. Peak Oilers miss the fact that a two-way tug of war is taking place. Low prices look like a great outcome from the perspective of consumers, but they are a disaster from the perspective of producers.

Canadian province of Alberta lowers oil curtailments as glut eases (Reuters) - The Canadian province of Alberta will ease oil curtailments in February and March, earlier than expected, saying on Wednesday that its rare step to limit production had eased a glut of crude. Alberta’s move to scale back its curtailments came at the end of a volatile month, in which Canadian prices improved dramatically but producers were affected disproportionately. U.S. refiners are also scrambling to find a replacement for Venezuelan heavy crude - similar to what Alberta produces - because of U.S. sanctions on that country’s state-owned oil company. Prices for Alberta oil fell in October to record lows compared with U.S. futures prices because of congested pipelines that backed up crude in storage tanks and prompted the curtailments. “We’re not out of the woods yet, but this temporary measure is working,” Premier Rachel Notley said in a statement. The province said it would set production for February and March at 3.63 million barrels per day (bpd), up by 75,000 bpd from January. Storage levels have fallen by 5 million barrels to a total of 30 million barrels since curtailments were announced in December, faster than expected, the provincial government said. They have decreased by about 1 million barrels a week this month, it said. The oil cuts averted disaster for many small producers that were selling crude in some cases below cost. But they have sharply divided larger producers, illustrating the messy task government faces. Producers that do not fully own refineries, such as Cenovus Energy Inc and Canadian Natural Resources Ltd, pressured Alberta last year to impose the curtailments. 

In 'Victory for Land and Water,' Canada's Supreme Court Rules Bankrupt Fossil Fuel Companies Must Clean Up Pollution Left Behind -- Green energy campaigners in Canada applauded a precedent-setting Supreme Court ruling on Thursday which ordered the bankrupt Alberta-based oil and gas company Redwater Energy to clean up its failed wells instead of leaving the task to the public.  Observing the "polluter pays principle," the 5-2 ruling overturned two earlier decisions by lower courts which had sided with a federal law stating that insolvent companies could prioritize paying back their creditors over fulfilling their environmental obligations."Bankruptcy is not a license to ignore rules," Chief Justice Richard Wagner wrote in the ruling, which was celebrated as one that would set a new precedent for the entire country.A victory for our lands and waters. Energy companies shouldn't be able to walk away from responsibility to clean up abandoned wells. #SCC @Redwaterhttps://t.co/FTfVtWXtHt "The Supreme Court of Canada has prioritized paying clean up costs before creditors when extractive companies go bankrupt. This outcome reinforces the growing understanding that polluters are responsible for their clean up obligations," said the Pembina Institute, a think tank focused on clean energy and environmental policy. "Working families across this province, as well as all of Canada, should not have to pay for the financial and environmental liabilities left behind when companies walk away from their obligations," said Energy Minister Margaret McCuaig-Boyd. "Upholding the polluter-pays principle is good news for Albertans and it's good news for Canadians."

Canada May Have Overpaid For Trans Mountain Pipeline - Canada’s government negotiated a price to buy the controversial Trans Mountain Pipeline at the higher end of estimates, while further delays in the expansion project would reduce the final price that the federal government can obtain when it re-sells it, Canada’s Parliamentary Budget Officer (PBO) said in a report on Thursday.The Trans Mountain expansion has become one of the most controversial pipeline projects in North America as it pitted two provinces—Alberta and British Columbia—against each other. Alberta’s heavy oil producers need more pipeline capacity as their production grows, but pipeline capacity has stayed the same. British Columbia, however, is against any new oil pipelines. The fierce opposition in British Columbia has forced Kinder Morgan to reconsider its commitment to expand the Trans Mountain pipeline, and to sell the project to the Canadian government in August 2018.Canada bought Trans Mountain Pipeline (TMP), the Trans Mountain Expansion Project (TMEP), and related assets for US$3.35 billion (C$4.4 billion), while PBO estimates that the TMP and TMEP have a value of between US$2.74 billion (C$3.6 billion) and US$3.5 billion (C$4.6 billion), assuming that the pipeline is built on time and on budget. PBO’s valuation could be understated, if all related assets are included, the watchdog for Canada’s public finances noted.Yet, PBO underlined that “One significant finding of this study is that delays in pipeline construction, an increase in construction costs and/or changes in the risk profile of the TMEP (reflected by the discount rate) can negatively influence the final sale price that the Government can negotiate for the TMP, TMEP and related assets.”The PBO calculates that completing the project one year behind schedule would reduce the value of the TMEP by US$528 million (C$693 million), while a 10-percent rise in construction costs would lower its value by US$345 million (C$453 million).As it stands, the Trans Mountain expansion project faces an uphill battle with environmentalists and appeals at courts to be completed “on time and on budget.” 

Mexico Seizes Tanker Trucks Used for Fuel Theft -  Mexican security forces seized tanker trucks from a fuel-theft ring in the central state of Guanajuato, the navy secretary said Wednesday. Elements of the Santa Rosa de Lima Cartel were pilfering fuel from a pipeline running through the town of San Salvador Torrecillas, Adm. Jose Rafael Ojeda said during President Andres Manuel Lopez Obrador’s daily press conference. The gang blocked roads in the area to obstruct the military operation, but the marines managed to push through and seize 33 vehicles. Ojeda also said that “irregularities” were found in the navigation log and fuel registry of two vessels impounded in the Gulf coast port of Dos Bocas, located in the southeastern state of Tabasco. Stealing fuel from pipelines belonging to state oil company Petroleos Mexicanos (Pemex) and re-selling it on the black market has become a major criminal enterprise in Mexico. News of the Lopez Obrador administration’s battle against a racket that cost Mexico $3.4 billion last year dominated Wednesday’s press briefing, which was cut short as the president was due to receive visiting Spanish Prime Minister Pedro Sanchez. Since his Dec. 1, inauguration, the leftist president has deployed thousands of police and troops to increase the surveillance of pipelines. Lopez Obrador revealed that authorities were investigating a company suspected of acting as a front for theft from fuel pipelines in Mexico City.

Mexican Oil at a Crossroads - Having taken office, President Andres Manuel Lopez Obrador has both challenge and opportunity with regards to setting policy for the Mexican oil industry. Historically, policy has been driven by nationalist sentiments and a preference for government over private ownership, both of which have had some negative consequences. Recent reforms have already achieved significant results and should be furthered, but it appears he will not do so. Naturally, being so close to the giant U.S. economy and oil industry, concerns about foreign domination have influenced policy (just as in Canada), however, the modern industry is so nationally diverse that the threat of any given country or company wielding undue influence is much diminished. Countries from Bolivia to Venezuela have demonstrated that national sovereignty cannot be challenged in the modern era. Pemex has accomplished much over the decades, but political control over it has hamstrung its operations in a variety of ways. Budgeting often reflects the government’s fiscal realities more than the company’s needs and opportunities, decision-making has added layers of individuals with their own agenda and increased delays, and political interference reduces efficiency. Moody’s Investor Services estimated that Pemex was only covering about half of its costs when prices dropped after 2014, while development plans for new discoveries by private companies have tended to estimate costs below $30/barrel. The New Energy Model, enacted in 2013, has shown great success and should be modified only on the margins. The government has received over a billion dollars in bonuses from its early auctions of oil leases, and initial exploration has turned up, among other things, four offshore fields that should produce, at a peak, over 300 thousand barrels per day. Further discoveries should add to this, and government revenue from these developments should be several billion dollars a year, dependent on prices, at no cost to itself. The Venezuela example is valuable, especially the marginal fields exploitation. Where the Venezuelan state-owned company had allowed production in some older fields to decline naturally, the 1990s aperture or opening included leasing them to private companies. This meant that new investment and methods were brought into play, adding several hundred thousand barrels a day to the country’s production and providing billions in revenue—at little or no cost to the government. Mexico has a similar potential and should exploit it.

Trump administration imposes sanctions on Venezuelan oil industry -At a White House news briefing on Monday, National Security Advisor John Bolton and Treasury Secretary Steven Mnuchin announced the imposition of wide-ranging sanctions against the Venezuelan state oil company, Petróleos de Venezuela, S.A. (PDVSA).The sanctions constitute an act of war in support of the US-led regime-change operation against the government of Venezuelan president Nicolás Maduro. They are aimed at securing the support of the Venezuelan military for a coup that would place power in the hands of Juan Guaidó, a right-wing politician and State Department asset who proclaimed himself “interim” president on January 23.The sanctions prevent US companies and individuals from doing business with PDVSA properties and interests, including its US-based subsidiary, Citgo, unless any earnings from those transactions are placed in accounts from which the Maduro government is blocked. While it has been reported that European and Caribbean companies will be given some time to wind down transactions, it is unclear how far-reaching the sanctions are, and neither Bolton or Mnuchin provided any details.As the US imports approximately 41 percent of Venezuela’s oil production, the de facto embargo is a huge blow to Venezuela’s already crippled economy, with Bolton himself estimating that the sanctions would deprive Venezuela of $11 billion in earnings. Oil exports constitute about 95 percent of the country’s total export earnings, meaning that the new sanctions will result in further shortages of food, medicine and other commodities.Although it is expected that the Maduro government will seek other buyers for its oil, some of the more natural options, including Russia and China, may not be viable, as Venezuela is deeply in debt to both and already sends oil to those countries in payment. Venezuela is the fourth-largest source of US oil imports, amounting to around 580,000 barrels per day (bpd), which is around 6 percent of US oil imports. This is a significant decline from the 1.2 million bpd that Venezuela supplied just 10 years ago. Venezuelan oil exports last year fell by 33 percent compared to 2017, and Venezuelan refineries are reported to be operating at one-third capacity, largely due to shortages of parts and other necessary supplies.

U.S. sanctions Venezuela state oil firm, escalating pressure on Maduro (Reuters) - The Trump administration on Monday imposed sweeping sanctions on Venezuelan state-owned oil firm PDVSA, aimed at severely curbing the OPEC member’s crude exports to the United States and at pressuring socialist President Nicolas Maduro to step down. Russia, a close ally of Venezuela, denounced the move as illegal interference in Venezuela’s affairs and said the curbs meant Venezuela would probably have problems servicing its $3.15 billion sovereign debt to Moscow. Minutes before the sanctions announcement, Juan Guaido, the opposition leader who proclaimed himself interim president last week with U.S. backing, said congress would name new boards of directors to the company and its U.S. subsidiary, Citgo. Guaido, supported by the United States and most countries in the Western Hemisphere, says Maduro stole his re-election and must resign to allow new, fair polls. Maduro, in a live national broadcast on Monday, accused the United States of trying to steal U.S. refining arm Citgo Petroleum, the OPEC member’s most important foreign asset, which also manages a chain of U.S. gas stations. He said Venezuela would take legal actions in response. In the first sign of serious retaliation, three sources with knowledge of the decision said PDVSA had ordered customers with tankers waiting to load Venezuelan crude bound for the United States to prepay for the cargoes or they will be authorized to fill the vessels or leave the ports. The Trump administration sanctions stopped short of banning U.S. companies from buying Venezuelan oil, but because the proceeds of such sales will be put in a “blocked account,” PDVSA is likely to quickly stop shipping much crude to the United States, its top client. 

Treasury sanctions Venezuela state-owned oil firm in bid to transfer control to Maduro opposition - The Trump administration will sanction Venezuela's state-owned oil firm, a move the White House has long put off for fear that it would raise oil prices and hurt American refiners. The move comes after a turbulent week for Venezuela that has created a standoff over the country's leadership. The sanctions aim to transfer control of Venezuela's oil wealth to forces that oppose socialist dictator Nicolas Maduro and deprive the strongman of resources that could prolong his grip on power. Last week, the opposition leader of Venezuela's National Assembly, Juan Guaido, named himself interim president amid street protests. President Donald Trump soon recognized Guaido as the nation's leader and his administration has been marshaling international support for the opposition figure since then. Maduro, having recently started another term after highly disputed elections, is refusing to back down. He is supported by the country's minister of defense and Russia. Treasury Secretary Steven Mnuchin on Monday determined that people operating in Venezuela's oil sector are subject to U.S. sanctions.The nation's energy industry is dominated by state-owned Petroleos de Venezuela, better known as PDVSA. Mnuchin said PDVSA has long been a vehicle for embezzlement and corruption by officials and businessmen. The sanctions will prevent the nation's oil wealth from being diverted to Maduro and will only be lifted when his regime hands control of PDVSA to a successor government, he added.

Moscow Will Do Whatever It Takes To Defend Its Interests In Venezuela - After decrying US sanctions against Venezuela's state-run oil company PDVSA as "illegal" and enforcing "unfair competition", a Kremlin spokesman has reiterated that Russia is prepared to use "all mechanisms available to us" to defend its economic interests in Venezuela - interests that are closely tied to the Maduro regime. According to RT, Russia has extended billions of dollars of loans to PDVSA, mostly via oil firm Rosneft. The company has extended $6 billion of loans which must be repaid in crude by the end of the year. Data from S&P Global Platts shows that as of November 2018, Venezuela had a $3.1 billion outstanding loan to repay to Rosneft.Rosneft also has five joint upstream projects with PDVSA in Venezuela. Peskov said that Russia is still assessing the potential impact of the PDVSA sanctions for Moscow.According to analysts briefed by Platts, whatever becomes of Maduro, Rosneft likely won't be cut off from Venezuelan oil because the country has abundant reserves, and oil is practically the only 'hard currency' it can access. An analyst at a Western bank estimated that Rosneft assets in Venezuela are equivalent to some $2.5 billion, plus another $2.5 billion in crude supplies owed for the loans."The worst-case scenario - which is unlikely to materialize - under which Rosneft loses all the money it invested in Venezuela, would be biting but not critical for the company, with quarterly free cash flow at over $4 billion," the analyst told Platts.  Meanwhile, the US has warned that the "path to relief" for PDVSA is via the "expeditious transfer of control" to opposition leader Juan Guaido, which the US insists should be followed by Democratic elections. Though the Kremlin has denied the reports, rumors about the presence of 400 Kremlin affiliated mercenaries in Venezuela make more sense given how much money is at stake.

US Slaps De Facto Oil Ban on Venezuela -- The Trump administration dealt its toughest blow yet to the authoritarian Venezuelan leader Nicolas Maduro, issuing new sanctions on the nation’s state-owned oil company PDVSA that effectively block his regime from exporting crude to the U.S. The move ratchets up pressure on Maduro to resign and cede power to National Assembly leader Juan Guaido by cutting off the regime from the market where it gets the bulk of its cash. The U.S. and other countries recognized Guaido last week as Venezuela’s rightful president, and he said Monday he would take control of Venezuelan accounts abroad and appoint new boards to PDVSA and its Houston-based subsidiary Citgo Petroleum. President Donald Trump assailed Maduro in a letter to Congress explaining an executive order he issued sanctioning PDVSA and Venezuela’s central bank. The action would bolster Guaido, he said, while accusing Maduro’s regime of “human rights violations and abuses in response to anti-Maduro protests, arbitrary arrest and detention of anti‑Maduro protesters, curtailment of press freedom, harassment of political opponents, and continued attempts to undermine” Guaido’s government-in-waiting. “The U.S. is holding accountable those responsible for Venezuela’s tragic decline,” Treasury Secretary Steven Mnuchin said. U.S. officials had long been hesitant to apply sanctions on Venezuelan oil because they did not want to exacerbate the humanitarian crisis in the country. But with Maduro and Guaido, a 35-year-old engineer-turned-lawmaker, locked in a struggle for support in the streets and the military, they decided it’s now worth the risk. Guaido so far hasn’t been able to sway the armed forces to his side but he’s tapped deep public discontent with an economy beset by hyperinflation and vast shortages of food and medicine. In an interview with CNN en Espanol, Guaido said that he had spoken to Trump, but did not provide any details. National Security Adviser John Bolton told reporters at the White House that Trump’s action would block $7 billion in Venezuelan assets and reduce the country’s exports by $11 billion over the next year, though Maduro is sure to attempt to sell PDVSA’s crude elsewhere. Bolton urged Venezuela’s military to accept a peaceful transfer of power to Guaido. Mnuchin said that Citgo would be able to continue to operate but won’t be allowed to remit money to the Maduro regime. Its proceeds must instead be held in blocked U.S. accounts. The Treasury secretary added that in the “short term” he expects “modest” impact on U.S. refineries. He noted the sanctions wouldn’t affect oil already purchased that is being shipped, and said he didn’t expect U.S. gas prices to rise. 

US Prepares for Battle Over Venezuelan Oil Refiner Citgo - Following Monday’s imposition of sanctions against Venezuela’s oil industry, the Trump Administration is gearing up for what could be a protracted international battle over the legal control of Venezuela’s main overseas assets, the most substantial of which is Citgo.   Citgo is Venezuela’s US-based refinery business, which owns three refineries in the United States and a major chain of gas stations across the country. They are where much of Venezuela’s overseas oil exports end up.  Venezuela’s state oil company PDVSA owns the majority of Citgo, while 49% of it is owned by Russia’s Rosneft as collateral for loans. PDVSA is ordering all US-bound oil tankers to pre-pay for their oil now, as the US sanctions would effectively prevent them from getting paid. The sanctions require all payments to be put in a frozen account that PDVSA cannot access.  Venezuela’s Oil Minister says the country is examining imposing force majeure to get out of certain contracts which are no longer tenable amid the US sanctions. Force majeure would allow them to back off contracts on the grounds of forces outside of their control.

Factbox: US sanctions PDVSA, creating likely major diversions of crude, diluent flows -  — The Trump administration Monday announced sweeping sanctions on PDVSA, Venezuela's state-owned oil company, a move which could ultimately block roughly 500,000 b/d of US imports and is expected to immediately shutdown roughly 120,000 b/d in diluent the US ships to the South American nation. The sanctions are aimed at cutting off the regime of Venezuelan President Nicolas Maduro from oil revenues and diverting those revenues to the still-forming regime of opposition leader Juan Guaido, who the US formally recognized last week as the country's legitimate president. While the sanctions are widely viewed as a de facto ban on US import of Venezuelan crude, the US Treasury Department coupled the sanctions with general licenses for US companies doing business with PDVSA and a wind down period which will allow most US imports of Venezuelan crude to continue for the next three months. "The US government has gone to great lengths to try to limit the implications for the operations of CITGO and the US Gulf Coast refining industry," said Elizabeth Rosenberg, director of the energy program at the Center for a New American Security and a former senior sanctions adviser at the Treasury Department. "Nevertheless, the new financial pressure plan will have tremendous effects for US firms who are scrambling to evaluate how PDVSA and Maduro will react and whether pressure on US energy product sales to Venezuela will be next." Here's a look at the potential market impacts of Monday's US sanctions announcement:

Mexico unable to fill US demand for lost Venezuelan crude: analysts — US refiners cannot rely on Mexico to replace Venezuelan heavy oil imports as the country is battling to reverse its declining production and Pemex's oil is sold under contractual basis, analysts and others say. Pemex sends 54% of its heavy crude exports to Asia and Europe under a contractual basis, preventing US from buying more Mexican crude in the spot market, a source close to Pemex told S&P Global Platts on Tuesday. A de facto ban on US imports of Venezuelan crude announced Monday by the Trump administration has created a sudden 500,000 b/d heavy, sour crude supply gap in the US Gulf Coast. Mexican crude, particularly Maya, may be the most similar to Venezuelan crude and, due to proximity to USGC ports, the most logical replacement for US refiners of Venezuelan oil. However, US refiners won't be able to acquire the 625,000 b/d of Mexican crude sold in Europe and Asia unless Pemex and its customers is willing to renegotiate term contracts. Pemex sells 90% of its crude exports under contracts, according to the company's Securities and Exchange Commission report. There is a slim option for US refiners to access more Mexican barrels, Lourdes Melgar, a deputy hydrocarbons secretary under the previous Mexican administration of President Enrique Pena Nieto, told Platts. Mexico could do heavy-light crude swaps with the US, helping to increase the efficiency of Pemex's simple configuration refineries, she added. Mexico recently purchased a limited amount of US Bakken light crude to run at its domestic refineries. "However, I don't know if the spirit of the current administration, for what we have seen, would implement a swap strategy to aid American refiners," Melgar said. Lopez Obrador has said he does not want to export crude oil and instead wants to refine it domestically, she added.  Pemex is not considering importing more light oil at the moment. The Trump administration Monday announced sanctions which will allow US refiners to buy Venezuelan crude at least through April. But, US refiners, who import Venezuelan crude, must now pay for it through blocked US accounts, preventing President Nicolas Maduro's regime from accessing that oil revenue and, effectively, stopping flows of Venezuelan crude to the US. Major US buyers of Venezuelan crude, including Valero and Chevron, have contracts for Mexican supply, but additional barrels will be difficult to acquire due to Mexico's production declines, according to S&P Global Platts Analytics, in a research note.

Analysis- Venezuela sanctions may ripple through Asian crude markets -  — US sanctions on Venezuela's state-owned PDVSA are expected to affect crude markets in Asia as the South American country could be forced to redirect nearly half of its exports away from the US, its single largest customer. PDVSA's Asian customers, mainly private refineries in western India and Chinese independents, are expected to show buying interest for around 500,000 b/d of Venezuelan heavy crudes, partly to make up for giving up Iranian grades last year."The move could possibly shift over 500 ,000 b/d to more distant and lower-valued markets, the majority of which would likely head to China and India," said Lim Jit Yang, director of Asia-Pacific oil market analysis at S&P Global Analytics. The sanctions could also boost competition for heavy crudes from the Middle East, such as Iraq's Basrah Heavy, Bahrain's Banoco Arab Medium and Saudi Arab Heavy. However, if Middle East producers choose to trim their allotments to Asia and boost supply to the US, the market will tighten.It will not be easy for PDVSA to redirect exports to Asia, where oil refineries are configured to process mostly medium sour grades from the Middle East, and only a few refineries actively seek heavy grades on the spot market.For instance, Mumbai-listed Reliance Industries and Nayara Energy operate high complexity refineries in western India designed to process discounted heavy crudes, and receive a steady flow of Venezuelan crude through their contracts."With the PDVSA sanctions in place now, my first instinct is that more Venezuelan crudes will flow to the Indian private refiners. But we have to wait and see if that becomes a reality," a senior executive at an Indian oil company said. "Anyway, Reliance and Nayara are hardly taking anything from Iran now. So they would be looking for opportunities" to replace Iranian barrels.Another source at an Indian private refiner said: "We pay in Euros for Venezuelan crude. So we are hoping that we can buy more. We need more clarity. But there is an opportunity for private refiners since they are not receiving anything from Iran under the waiver." PDVSA's crude exports fell to 1.28 million b/d in the fourth quarter of 2018, down from 1.46 million b/d at the start of the year and from 2.19 million b/d in 2016, according to Barclays data. The US accounted for 43% of Venezuelan exports, India accounted for 19% and China 22%.

Analysis- US wants Middle East oil to offset Venezuela sanctions, but Saudi Arabia is cutting output - — The US is once again pressuring Saudi Arabia and its Gulf allies to boost crude supplies at the expense of another sanctioned OPEC member -- this time Venezuela. For now, however, the kingdom appears less inclined to answer the call as it did last year, when the US imposed sanctions on Iran. Saudi Arabia, the world's largest crude exporter, has been steadily slashing its output to reverse last year's production surge. February production will come in below January's projected 10.2 million b/d, energy minister Khalid al-Falih has said -- some 900,000 b/d less than its record 11.1 million b/d in November. But that was before the US on Monday imposed severe sanctions targeting Venezuela's state-owned oil company PDVSA, with officials saying they expect Saudi Arabia and other producers to make up for any crude shortfalls. "I'm sure many of our friends in the Middle East will be happy to make up the supply as we push down Venezuela's supply," US Treasury Secretary Steven Mnuchin said. The PDVSA sanctions could ultimately block about 500,000 b/d of US imports of Venezuelan crude, while also shutting off 120,000 b/d in US diluent exports to Venezuela. The loss of diluent would significantly inhibit PDVSA's ability to produce and market its extra heavy oil. Venezuelan production stood at 1.17 million b/d in December, according to the latest Platts OPEC production survey, down 530,000 b/d in a year, a trend the sanctions would worsen. A senior Saudi official told S&P Global Platts before the announcement that he was not aware of any request from the US for more Saudi crude, and sources indicated the kingdom would be unlikely to comply anyway, having been burned by the Iran sanctions waivers the US granted in November. The US had leaned on Saudi Arabia and other Middle East OPEC members to raise their production last summer in anticipation of the reimposition of US sanctions aimed at zeroing out Iran's oil exports, and the kingdom complied, ramping up its output by more than 1 million b/d in six months and attributing the increase to customer requests. But the US then caught OPEC off guard by issuing waivers to eight countries to continue purchasing Iranian oil, contributing to market fears of a supply glut and tanking prices over the past few months. Stung by the decision and wary of tepid demand growth in 2019, Saudi Arabia pushed OPEC to implement new production cuts, and the group agreed with Russia and nine other non-OPEC allies to commit to 1.2 million b/d in supply curbs that went into force January 1. Falih, in an interview Monday with Bloomberg Television before the PDVSA sanctions announcement, said Saudi Arabia would continue to target the US for the bulk of its output cuts. Falih has noted how much the EIA's weekly US petroleum inventories report can move the market, but he said the decision to shift flows from the US is as much a commercial one.

US sanctions to exacerbate Venezuela's fuel shortages, hit Cuba— Venezuela and its geopolitical ally Cuba could soon face crippling shortages of gasoline, diesel and other fuels, in the wake of US sanctions on PDVSA that would severely hamper its refineries' ability to operate. Venezuelan state-run PDVSA's US refining subsidiary Citgo supplies more than 50% of the gasoline and other fuels consumed in Venezuela, as well as 3 million barrels of heavy virgin naphtha monthly that PDVSA uses to dilute its heavy crude oil from the Orinoco Belt for export and processing. Those shipments would be cut off by the sanctions. PDVSA also supplies Cuba with 98,000 b/d of crude and refined products under a deal signed between the two countries in 2000, but those deliveries would also be imperiled by the sanctions, as the US seeks to weaken ties between Havana and Caracas. "Some call the country now 'Cuba-zuela,' reflecting the grip that Cuba's military and security forces have on the Maduro regime," US National Security Advisor John Bolton told reporters Monday. "We think that's a strategic significant threat to the United States." The sanctions amount to a de facto ban on US imports of Venezuelan crude, which Citgo's refineries in the US Gulf Coast rely on, as well as a prohibition on US exports of some 120,000 b/d of diluent to Venezuela. 

Controversial Nord Stream 2 Pipeline Could Be Operational By November - In what would be an early geopolitical win for Moscow, German news agency DW reported yesterday, citing one of the project’s engineers, that the Nord Stream 2 natural gas pipeline should be operational by November. Klaus Haussmann, an engineer at Nord Stream 2’s future landfall site at Lubmin on Germany’s Baltic Sea coast, told German public radio station Deutschlandfunk that the “raw” laying of the pipeline would be finished by the middle of 2019, according to the DW report. “Then comes the entire installation of the electrical equipment, security chains. And, then it’s planned on the large scale that we get the first conduit filled with gas in November, from Russia,” Haussmann said. Haussmann said his concern was more the impact of the Baltic’s winter weather and waves on construction at sea and less so the international pros and cons. “For two years or more, Nord Stream 2 has been pretty much under fire. But at the moment we have more worries with the weather outside,” he said. Nord Stream 2 is a 759 mile (1,222 km) natural gas pipeline running on the bed of the Baltic Sea from Russian gas fields to Germany, bypassing existing land routes over Ukraine, Poland and Belarus. It would double the existing Nord Stream pipeline’s current annual capacity of 55 bcm. However, it is arguably one of the most geopolitically charged energy projects ever proposed. Germany maintains that the pipeline is needed to increase natural gas supply as some EU members move away from nuclear for power generation, but not everyone agrees. The U.S., under the past three presidents including Donald Trump, has long countered that the pipeline puts European national security in jeopardy – a concern that seems grounded given Russia’s history of using gas a geopolitical weapon in the middle of winter. Ukraine, which has argued that it will lose revenue since the Nord Stream 2 project would bypass the country, has tried to form a consortium of EU-based companies to stop the new pipeline, however, those efforts have largely fallen apart and at this point would be too late to make much difference. The Nord Stream 2 project has so angered President Trump that his administration has recently threatened to put sanctions in place if the project becomes operational. In a televised meeting with reporters and NATO Secretary-General Jens Stoltenberg before a NATO summit in Brussels last year, Trump said it was “very inappropriate” that the U.S. was paying for European defense against Russia while Germany, the biggest European economy, was supporting gas deals with Moscow.

Oil major Total plans biggest exploration drive in years (Reuters) - Total is launching its biggest exploration campaign for years in 2019 as part of a turnaround plan that is ditching the company’s focus on risky long-shots in favor of areas known to contain commercial levels of oil or gas. The French major aims to drill 23 wells this year, its senior vice president for exploration, Kevin McLachlan, told Reuters, in waters off Mauritania, Senegal, Namibia, South Africa, Guyana and Brazil. While the company declined to say how many wells it drilled in 2018, McLachlan said 2019 would be Total’s largest program in years. The 23 wells planned represent about a trebling of the levels of 2017 and 2016, and is higher even than the 20 drilled in 2013, before the oil price crash. The company’s new game plan is to concentrate efforts on emerging and mature basins, which offer a greater chance of exploration success. It is moving away from its higher-risk, higher-reward strategy of targeting “frontier” areas that have not been commercially exploited, an approach which yielded scant rewards and saw outlier Total fall behind rivals. As a result the proportion of its exploration capital the African-focused company is spending on frontier areas has dropped to 15 percent, from 40 percent five years ago. “We were spending a lot of money in frontier,” said McLachlan, a Canadian geophysicist who joined Total in 2015 to lead the five-year revamp of its exploration strategy. “Now we want balance.” Most of the wells it aims to drill this year will target known giant fields, he added. Total has broken ranks with some rivals in recent years and largely ignored the rush to U.S. shale. It is looking to eke out conventional resources, particularly in Africa where it has the biggest industry presence. The strategy carries risks though, and has left the company exposed to the kind of political instability that has deterred others. 

Japan imports record US crude in 2018, imports 199,138 b/d in Dec -  Japan imported a record 199,138 b/d of crude oil from the US in December and the total US crude shipments in 2018 reached an all-time annual high, allowing the North American producer to break into the top ten supplier list for the first time last year, according to data released Thursday by the Ministry of Economy, Trade and Industry. The US was the fourth largest crude supplier to Japan in December, when there was no crude imports from Iran over November-December as domestic refiners had suspended their imports ahead of Washington's reimposed sanctions on November 5. "The US sanctions against Iran had resulted in the inflow of US crude oil to replace Iranian barrels as a consequence," Takayuki Nogami, chief economist at Japan Oil, Gas and Metals National Corp. said. Nogami also added that Japan's boosted imports of US oil was at the time that "a part of US crude not taken by China came to Japan as a result of the US-China trade dispute." China's crude oil imports from the US tumbled in the fourth quarter last year with no shipments recorded between October and December 2018, latest data released by the General Administration of Customs showed. Looking forward, industry sources said China's US crude imports this year could post a double digit percentage fall from 2018 amid ongoing China-US trade tensions.  The spike in US crude imports came as Japan did not take any Iranian oil over November-December last year after having lowered its imports to just 48,033 b/d in October, the lowest level since April 2017. Japan imported 2.52 million barrels or 84,149 b/d of of US crude in November, more than double from 34,690 b/d a year ago, bringing the North American producer as the 10th largest crude supplier in the year to date. Japan is among eight countries that received 180-day US sanctions waiver until May 4 but the country did not resume loading Iranian oil until January 20 because of the need to clarify shipping, insurance and banking rules. In December, the US supplies comprised of WTI Midland, Eagle Ford, Southern Green Canyon and White Cliffs grades, accounting for roughly 7% of Japan's total crude imports of 3 million b/d in the month, METI data showed.

Drill, China, drill: State majors step on the gas after Xi calls for energy security (Reuters) - China’s state energy giants are set to raise spending on domestic drilling this year to the highest levels since 2016, focusing on adding natural gas reserves in a concerted drive to boost local supplies. Responding to President Xi Jinping’s call last August to boost domestic energy security, China’s trio of oil majors - PetroChina, Sinopec Corp and CNOOC Ltd - are adding thousands of wells at oil basins in the remote deserts of the northwest region of Xinjiang, shale rocks in southwest Sichuan province and deepwater fields of the South China Sea. Firms are showing greater risk appetite, expanding investments faster in exploration than production, emboldened by Beijing’s political push and oil near $60 a barrel, said state oil executives and analysts at consultancy Wood Mackenzie. “We shall carry through resolutely the State Council’s call on stepping up domestic exploration and development and launch an offensive war,” PetroChina Chairman Wang Yilin was cited as saying in an inhouse newspaper in December. Offshore specialist CNOOC Ltd said last week it was confident of achieving its spending target this year, the highest since 2014. It pledged to spend twice as much this year in domestic exploratory drilling as in 2016. “With oil prices at $50, $60 and $70...we’re making decent profits,” Yuan Guangyu, CNOOC’s Chief Executive Officer, said last week. CNPC, Asia’s largest oil and gas producer and parent of PetroChina, is boosting risk exploration investment five-fold to 5 billion yuan ($741 million) this year from 1 billion yuan last year. But with oil reservoirs maturing and new discoveries tending to be smaller and more costly, even more drilling is unlikely to reverse China’s declining oil outlook, analysts say. China, set to remain the world’s top oil buyer for years to come, is forecast to slip to the 10th largest global oil producer in 2020, down from No.5 for most of last decade, said Wood Mackenzie. “China will likely continue on the same path as it has in recent years – an overwhelming focus on new gas production, leading to continued decline in its oil output,” 

Is China’s plan to use a nuclear bomb detonator to release shale gas in earthquake-prone Sichuan crazy or brilliant? - China is planning to apply the same technology used to detonate a nuclear bomb over Hiroshima during the second world war to access its massive shale gas reserves in Sichuan province. While success would mean a giant leap forward not only for the industry but also Beijing’s energy self-sufficiency ambitions, some observers are concerned about the potential risk of widespread drilling for the fuel in a region known for its devastating earthquakes.Despite being home to the largest reserves of shale gas on the planet – about 31.6 trillion cubic metres according to 2015 figures from the US Energy Information Administration, or twice as much as the United States and Australia combined – China is the world’s biggest importer of natural gas, with about 40 per cent of its annual requirement coming from overseas.In 2017, it produced just 6 billion cubic metres of shale gas, or about 6 per cent of its natural gas output for the whole year. The problem is that 80 per cent of its deposits are located more than 3,500 metres (11,500 feet) below sea level, which is far beyond the range of hydraulic fracturing, the standard method for extraction.But all that could be about to change, after a team of nuclear weapons scientists led by Professor Zhang Yongming from the State Key Laboratory of Controlled Shock Waves at Xian Jiaotong University in Shaanxi province, released details of a new “energy rod” that has the power to plumb depths never before thought possible. Unlike hydraulic fracturing, or fracking as it is more commonly known, which uses highly pressurised jets of water to release gas deposits trapped in sedimentary rock, Zhang’s torpedo-shaped device uses a powerful electric current to generate concentrated, precisely controlled shock waves to achieve the same result.He told the South China Morning Postthat while the technology had yet to be applied outside the laboratory, the first field test was set to take place in Sichuan in March or April. “We are about to see the result of a decade’s work,” he said.

RBN Energy's Rusty Braziel: Here's the most important thing going on in the oil market --The most important trend happening in the oil market has to do with China, oil guru and RBN Energy President and Principal Energy Markets Consultant Rusty Braziel tells CNBC's Jim Cramer.   Braziel, a frequent "Mad Money" guest who has correctly predicted several oil price collapses in recent years, referenced the commodity's price drop in October of last year. After starting the month near four-year highs, crude oil prices saw their biggest monthly drop in over two years.Since October, oil prices have been trading lower, a trend some have connected to incipient economic weakness in China. While Cramer wasn't convinced by that line of thinking, Braziel said in a Monday interview that it actually had merit. "If demand in China is down, if the economy in China is down, that means the total demand for crude oil is going to be down. If crude oil demand drops, then total demand drops, then … crude oil prices are likely to decline, too," Braziel said. "As a matter of fact, that's really the most important thing that's going on right now, and it's what happened back in 2014."

The Next Big Threat For Oil Comes From China - There is a widespread concern in the world regarding China’s decelerating economic growth. The slowdown, if it continues, threatens economic activity almost everywhere. Growth in Germany, for example, has already cooled due to its exports of high-quality machinery to China dropping precipitously.Those in the oil market also worry about China. The country’s economic growth has been a key driver of global crude oil consumption. Indeed, China accounts for one-third of the International Energy Agency’s projected 2019 increase in world oil use.Weak Chinese economic growth is not the end of the oil market’s prospective ills, however. Few recognize the additional trouble on tap from the Chinese independent refiners affectionally known as “teapots.” The danger occurs because lower oil demand growth in China comes just when independent refining capacity there is rising. The capacity growth has been financed primarily by debt, most likely supplied by China’s alternative lenders. As demand slows, these refiners will turn to international markets, dumping products in Singapore, the Americas, or Europe to earn hard cash. In doing so, they could plunge the global refining industry into a serious recession and drive crude prices down sharply. This will not be the first time that refineries in Asia caused a crisis in the oil sector. In 1997, Korean refiners did the same during the Asian financial collapse. That incident is described in the December 1997 Oil Market Intelligence (OMI). The report begins by noting that Korean refiners had begun to seek exports markets before the crisis hit “mostly to employ 620,000 b/d of new refining capacity that came on stream since late 1966.” The effort intensified as domestic consumption collapsed: But once the won started its second descent in two years—it dropped over 94% against the dollar between July 1 and December 10 [1997], much of it in early December—the push to export became more desperate because the five big refiners could not recoup in domestic product prices the staggering dollar price of crude oil feedstock.

Libya crude oil production averaged 1.1 mil b/d in 2018, highest in 5 years: NOC chairman Sanalla - Libyan oil output recovered sharply last year even though security and political challenges continued to impede the sector. "We achieved our highest production and revenue levels for the past five years, which we now declare openly on a monthly basis, with $24.4 billion transferred to the Libyan Central Bank in 2018, thanks to an average production level of 1.1 million b/d," Sanalla said. S&P Global Platts, which publishes a monthly OPEC production survey, pegged Libya's 2018 production at an average of 948,333 b/d. That was still its highest annual average since 2012, when it pumped 1.40 million b/d, according to Platts survey data. NOC officials told Platts on Tuesday that they were planning for a $60 billion budget, with $20 billion allocated to recover Libya's crude output to pre-civil war levels of 1.6 million b/d by year end, though Sanalla added that NOC has not received its entire capital spending allocation from Tripoli in the last two years. Despite security concerns, some international oil companies have expressed interest in resuming exploration activities in the war-torn country which contains the largest oil and gas reserves in Africa. Sanalla said Austria's OMV will start exploration work in the Sirte Basin "soon" and that NOC is conducting some technical work with Italy's Eni and BP, who are hoping to resume work in the onshore Ghadames basin. Russia's Gazprom and Tatneft are also expected to resume upstream working this year, he added. Sanalla also said NOC was very close to approving Total's agreement to take a 16.33% stake in the Waha concessions from Marathon Petroleum for $450 million. "We are in the final stages," he added. Total had announced this in March 2018 but the deal was still outstanding amid concerns the price was too low and speculation that NOC wants to make a counteroffer according to various news reports.

Oil price volatility a threat for East Med natural gas producers- Egyptian minister - — Oil price volatility continues to pose a "threat" to upstream oil and gas investment, including for the East Mediterranean's current and would-be gas producers, Egypt's petroleum minister, Tarek El-Molla, said Monday. Speaking in Florence, Italy, Molla praised the efforts of OPEC and its allies to stabilize oil prices, but said sufficient stability had not yet been achieved. While much investment and exploration activity is directed at gas projects, volatility of oil prices "is directly impacting the amount of investments. It really shapes the future of investment in the oil and gas sector," Molla told an industry conference, the Baker Hughes GE Annual Meeting. "The problem you will be faced with in the coming few years -- a big shortage of oil production -- this will be a threat in my opinion. This is the role of all of us to have a balanced price for supply and demand, whereby you can have sustainable production of oil." Molla went on to highlight his own country's efforts to foster cooperation among current and potential gas producers in the Eastern Mediterranean, and their efforts to find joint export solutions for gas. Egypt is now resuming LNG exports on the back of rising production from its giant Zohr field, he noted, and is mooted as a potential provider of infrastructure for other countries wanting to export LNG from the region. Earlier in January the country hosted an "East Med Gas Hub" forum, gathering ministers and officials from Israel, Cyprus, Greece, Jordan, Italy and Palestinian representatives. "Knowing that our neighbouring countries in the East Mediterranean basin have got some good reserves of gas as well as some good discoveries, but they're not necessarily able to monetize that, here comes the importance of cooperation," Molla said. "We need to have synergies in order to capitalize and to have the benefit of this gas that is stranded. We can cooperate using our infrastructure, using their gas resources, and look at Europe as the potential customer of our gas. We need to have synergies," he said. "We need to have not only political stability, but political cooperation."

Middle East gas reserves can be a catalyst for peace, Egypt minister says - Gas reserves in the Middle East can create opportunities for employment, business and peacemaking, according to Egypt's petroleum minister. Amid a push by Egypt to transform itself into a regional gas hub, the country hosted the East Med Gas Hub earlier in January and gathered officials from Israel, Cyprus, Greece, Jordan, Italy and Palestine. Speaking Monday at the BHGE Annual Meeting in Florence, Italy, Egypt Petroleum Minister Tarek El-Molla told CNBC that the commodity can aid the peace process in the region. "We were very proud to host the Palestinians the Israelis, sitting together in one room, on the roundtable together with other neighboring countries like Greece, Cyprus, Jordan and Italy," he told CNBC's Steve Sedgwick. "So the benefit will be there and the welfare will cover all the countries because gas will be the cause of the revenues to generate opportunities, job opportunities, business opportunities and it will bless all the people there (in the Middle East) hence it is the catalyst and it will be the peacemaker really," he added. Cairo is expected to become a net gas exporter by the end of 2019 and El-Molla noted that the country is seeing outside interest into the sector — particularly after the success of Egypt's Zohr gas field, an offshore natural gas field in the Mediterranean Sea operated by Italian energy firm Eni.

Anadarko Seeks Armored Vehicles for LNG Project -- Anadarko Petroleum Corp. wants a fleet of at least six vehicles with armor heavy enough to stop AK-47 bullets at its natural-gas project in Mozambique. And it needs them soon. The company called for expressions of interest from potential suppliers of so-called B6 specification vehicles, and also wants associated fleet management services, according to an advertisement published in the Maputo-based Noticias newspaper on Thursday. Anadarko is expected to spend at least $20 billion on its project in Palma, near the Tanzanian border, where a shadowy insurgency has killed more than 100 people and destroyed hundreds of homes. The attacks reached an area a few kilometers from the company’s worker camp this month, according to local media reports. “In order to ensure readiness for operations, there is an immediate need” for the vehicles, Anadarko said in the advertisement. Other oil and gas operators including Eni SpA and Exxon Mobil Corp. also have projects in Palma. Anadarko plans to reach a final investment decision on its Mozambique LNG project this year, and has already started a community resettlement project. “We take the security and safety of our people very seriously, and for that reason, we do not discuss specific security measures,” the company said in response to emailed questions. 

Is Qatar's Latest Move A Stroke Of Geopolitical Brilliance?  - Much has already been written about how Qatar, Australia and even the U.S. are jockeying to lock in global LNG market share. As more countries start to import LNG to offset over-reliance on dirtier burning fossil fuels, including coal and even crude oil, much is at stake for both producers and buyers. For Qatar, until recently unaccustomed to challenges to its top LNG spot, the stakes could be the highest of all players involved. The tiny, gas-rich kingdom already left OPEC (likely under geopolitical pressure) and is now planning to increase its already impressive 77 million tonnes per annum (mtpa) liquefaction capacity to 110 mtpa within five years. For the Qataris, not only is national pride on the line as it seeks to fend off Australia's recent attempts to usurp it from top global LNG producer, but its very survival geopolitically and economically is at stake too. Qatar finds itself in an unenviable position, mostly ostracized by its Arab neighbors over allegations of terrorism funding, which Doha denies, and still suffering a boycott instigated in 2017 by Saudi Arabia, the United Arab Emirates, Bahrain and Egypt. Qatar has little choice but to defend its LNG production and exporting prowess, as well as diversifying and investing in rival LNG producers' LNG sectors, including the U.S. Australia, though admittedly dependent on energy exports, mostly LNG and coal, is not as vulnerable as Qatar, while the U.S., which could compete with both Qatar and Australia in terms of liquefaction capacity by the mid to last part of the next decade if more projects are pushed through, has the most diversified economy in the world, including currently being the top crude oil producer with that position likely to remain at least in the mid-term.Amid all of these developments, Qatar is now courting foreign countries to invest in its gas sector. On Wednesday, a Reuters report, citing industry sources, said that Qatar is preparing to issue a tender for energy firms seeking a stake in its gas expansion project, drawing interest from long-standing partners as well as newcomers Chevron, Norway’s Equinor and Italy’s Eni. Plans to expand Qatar’s LNG facilities, already the largest in the world, by more than a third in the next five years are considered one of the most lucrative investments in the rapidly growing global gas market, the report added.

Saudi Aramco plans to buy up to 19.9% stake in Hyundai Oilbank for $1.6 bil — Saudi Aramco plans to buy up to 19.9% stake in Hyundai Oilbank from its parent company Hyundai Heavy Industries Holdings Co. for $1.6 billion, a move that could give the major Middle Eastern crude producer a strong foothold in one of Asia's leading oil consumers. Hyundai Heavy Industries said the company is currently in talks with Saudi Aramco over the sale of its stake in Hyundai Oilbank, and the deal will be finalized following the approval from its board of directors whose meeting will be held soon. Aramco is planning to buy Hyundai Heavy's 19.9% stake in the refiner for no more than 1.8 trillion won ($1.6 billion), Hyundai Heavy Industries said in a statement Monday. Saudi Aramco's move to invest in South Korea comes a year after the Middle Eastern firm decided to invest in two of Asia's biggest refining projects -- in Malaysia and in India -- a strategic push into Asia that will ensure the Middle East producer a huge outlet for its crude in coming years as oil faces increasing competition from alternative energy supplies. In 2018, Saudi Arabia was the biggest crude supplier to South Korea, with Asia's fourth biggest oil consumer importing 313.17 million barrels. However, the major OPEC producer saw its market share slide last year amid South Korea's growing appetite for light sweet crude oil from the US, Kazakhstan and Africa. Latest data from state-run Korea National Oil Corp. showed that South Korea's crude imports from Saudi Arabia fell 17.1% year on year to 24.48 million barrels in December 2018. For the full 2018, Saudi crude imports were also 1.9% lower than the 319.22 million barrels received in 2017.   "Aramco's plan to buy a stake in Hyundai Oilbank can be seen as Saudi Arabia's move to secure its market share in South Korea, one of the major demand centers in Asia,"   Saudi Arabia has somewhat struggled to maintain its grip on the Asian market share over the past couple of years as a flurry of competitive arbitrage cargoes from the US, the Mediterranean and Africa attracted many refiners in East Asia.

What’s Behind Saudi Arabia’s New Downstream Strategy?  - Saudi Aramco, the world’s wealthiest albeit state-owned oil company, continues to diversify in downstream investments. On Monday, the storied oil major said it planned to invest up to $1.6 bn for a nearly 20 percent stake in South Korean refiner Hyundai Oilbank. OilBank is South Korea’s smallest refiner by capacity. Saudi Aramco is already the biggest shareholder in South Korea’s third-largest refiner, S-Oil Corp, with a 63.41 percent stake. Saudi Aramco plans to pay 1.8 trillion won for a stake of up to 19.9 percent of Hyundai Oilbank from Hyundai Heavy Industries Holdings, which now owns 91.13 percent of Hyundai Oilbank, a Reuters report said. Saudi Aramco plans to value Hyundai Oilbank at 10 trillion won, or 36,000 won per share, according to a Hyundai Heavy Industries Holdings statement. Reuters said that a person familiar with the matter claimed the company plans to offer a discount of 10 percent to Saudi Aramco in a block deal that will require board approval from both firms next month. South Korea, along with China, has substantial market share in Asia and beyond for its finished petroleum products, producing light oil products and middle distillates such as diesel, gasoline, and jet fuel as a result of refinery upgrades in recent years. South Korea had almost 3.2 million b/d of crude oil distillation refining capacity at the end of 2017 and ranked sixth largest for refining capacity in the world, according to the US Energy Information Administration's (EIA) latest analysis of the country’s energy sector.  Saudi Aramco for its part has been keen on investing in downstream assets across Asia, the U.S. and Africa. It has also been planning to invest more to expand its nature gas footprint, especially in both the U.S. LNG sector as well as Russia’s LNG push, which could see possible conflicts of interest as Moscow and Washington jokey for geopolitical hegemony in the middle east and natural gas market share in Europe where Russia has a controversial decades-old gas monopoly dating back to the end of World War II. Saudi Aramco is also interested in diversifying more downstream ahead of its possible IPO, though the exact date of what would be the world’s largest IPO has been postponed and currently is still not certain. However, Saudi Energy Minister Khalid al-Falih said a few weeks ago that the oil giant will be listed by 2021. If so, this will once again (reminiscent of 2017-2018 when an IPO was pending) see competing bourses, like London, Hong Kong, Tokyo, New York and even Riyadh all compete for the chance to list or partiality list the historic IPO.

Saudis Pledge Deeper Oil Cuts in February Under OPEC+ Deal - Saudi Arabia expects to reduce oil output once again in February and pump for six months at levels “well below” the production limit it accepted under OPEC’s oil-cuts accord, Energy Minister Khalid Al-Falih said. The world’s biggest exporter targeted production of 10.2 million barrels a day in January and is aiming to pump about 10.1 million in February, he said. Saudi Arabia’s voluntary limit under the December cuts deal with Russia and other producers was 10.33 million barrels a day. “Saudi Arabia will be well below the voluntary cap that we agreed to” and will pump beneath its ceiling “for the full six months” of the December cuts accord, he said in a Bloomberg Television interview in Riyadh. The Organization of Petroleum Exporting Countries and allies including Russia, a coalition known as OPEC+, agreed to pare production starting this month in an effort to buttress sagging oil prices. Crude futures have gained this year as Saudi Arabia leads the way in curbing output amid a surge in U.S. shale-oil supplies. Benchmark Brent crude was trading 42 cents higher at $60.35 a barrel at 10:37 a.m. in Dubai. “Demand will start picking up at the end of the first quarter and into the second quarter,” Al-Falih said. The impact of OPEC+ output reductions “will trickle down into the global markets over the next few weeks.” The U.S. is currently “way oversupplied” with its own output and with oil from other Western hemisphere producers, Al-Falih said. “So, as we look at the oil market, and we see it in the price differentials, it’s really not rewarding us to export a lot of oil to the U.S. And as a result, as we make adjustments, it makes commercial sense that that’s the market that gets the majority of our cuts.”

Saudi energy minister: Russians promised me they'd 'pick up the pace' on OPEC cuts ---Saudi Arabia's energy minister is hoping Russia will pull its weight on recently agreed to OPEC oil production cuts despite its slow start, expressing confidence Monday that the world's second-largest exporter would come through."We're committed both to the agreement in December. ... All indications so far so good, the Russians have promised me that they will pick up the pace," Energy Minister Khalid al-Falih told CNBC's Hadley Gamble in Riyadh on Monday.OPEC members, along with several other countries, in December agreed on output cuts totaling 1.2 million barrels per day (bpd) in order to stem a sinking market and support their own export-dependent economies. "OPEC plus" refers to the group's cooperation with the non-OPEC producers like Russia and other former Soviet states.Russia was more reluctant to cut its output, as its growth is heavily dependent on robust crude exports. Russia has initially let the Saudis shoulder the bulk of output cuts. The top OPEC ally, which in late 2016 began a cooperation agreement with Riyadh to stabilize oil prices, has often said that $60 per barrel is enough to meet its economic needs. Moscow in December said it would cut production by 50,000 to 60,000 barrels per day in January, whereas Saudi Arabia reportedly pledged to cut by 900,000 barrels a day compared with November levels.Russia pumped a record 11.45 million bpd in December, an increase of 80,000 bpd on the previous month, its Energy Ministry reported in early January. Saudi Arabia's crude output, by contrast, fell by more than 450,000 bpd from November to December. Global benchmark Brent crude has bounced back 25 percent from its late December rout, but is still far from the more than $86 per barrel highs it witnessed in October. Brent was trading at $60.18 a barrel at 2.30 p.m. London time.

Industry is more important to Saudi's future than oil, energy minister says --Industrial progress is more vital to Saudi Arabia's future than oil, the kingdom's energy minister told CNBC Monday."Industry is the number one priority for the kingdom," Khalid Al-Falih told CNBC's Hadley Gamble in Riyadh."Oil is important, it's going to be important for as long as all of us live and beyond for generations to come. But the future of this nation, and the future of my children and grandchildren and the next few generations of Saudi Arabia is going to be shaped by how we plan and execute programs for implementing Vision 2030, like the program we're launching today. And I have to give it higher priority," he said.Saudi Arabia launched a National Industrial Development and Logistics Program (NIDLP) on Monday as the kingdom hopes to attract 1.6 trillion riyals ($426 billion) of foreign investment by 2030, specifically into the industry, logistics, mining and energy sectors."This is a program that integrates four major pillars of the Saudi economy, they're all active now. These are nothing new but they will be stronger, more competitive and more diverse," Al-Falih said. "The sophisticated integrative logistics sector will connect (the other pillars) and will connect the kingdom with the rest of the world and will create a platform for exports and competitiveness for the new economy for Saudi Arabia being built under the Vision 2030."

Brent-Dubai narrows sharply ahead of fresh OPEC oil output cuts, sour crude shortage - Sour crude oil differentials have risen sharply relative to sweet crude grades in the Atlantic Basin as OPEC moves to cut back on production, sending the differential between the Brent and Dubai markets to its narrowest levels since 2017. In this edition of the podcast, S&P Global Platts associate editorial director Robert Beaman and crude managing editor Paula VanLaningham look at the move in the Brent-Dubai derivatives market and discuss how this move is likely to impact the European market in the coming weeks.

Hedge funds return to oil as OPEC removes some downside risk (Reuters) - Hedge fund managers stepped up their purchases of oil and refined products last week on growing hopes of a U.S.-China trade truce and that the global economy will avoid a severe slowdown in 2019. But fund buying has been concentrated in crude rather than fuels, which is consistent with producer club OPEC tightening the supply side of the market while the demand outlook remains more uncertain. Hedge funds and other money managers boosted their net long position in Brent crude futures and options by 30 million barrels to 203 million barrels in the week to Jan. 22 (https://tmsnrt.rs/2ThSHUZ). Portfolio managers have raised their net long position in Brent in six of the last seven weeks, by a combined 66 million barrels since Dec. 4, according to exchange data. Funds now hold four bullish long positions in Brent for every one bearish short position, up from a ratio of just over 2:1 in early December, but far from the recent peak of 19:1 at the end of September. Fund managers also increased their net long position in European gasoil for the third week running by 4 million barrels to 15 million barrels. Gasoil positions are up by 13 million barrels since the end of December. In both cases, however, most of the new buying last week came from the closure of existing short positions rather than opening fresh long ones. It follows the largest sell-off ever recorded in crude and gasoil during the fourth quarter and confirms many fund managers sense prices have found a floor, at least temporarily. 

Oil falls 3 percent as US adds rigs, China weakness rattles market - Oil prices fell sharply on Monday after U.S. companies added rigs for the first time this year, a signal that crude output may rise further, and as China, the world's second-largest oil user, reported additional signs of an economic slowdown.Further weighing on oil markets, the trade dispute between the United States and China looks unlikely to end anytime soon and its impact on the Chinese economy is increasing.U.S. crude oil futures fell $1.77, or 3.3 percent, to $51.92 per barrel around 10:10 a.m. ET (1510 GMT). International Brent crude oil futures were down $1.47, or 2.6 percent at $60.07 a barrel, briefly dipping below $60 for the first time in nearly two weeks.U.S. crude production, which hit a record 11.9 million barrels per day late last year, has undermined sentiment in the oil market, traders said.U.S. energy firms last week increased the number of rigs looking for new oil for the first time since late December to 862, Baker Hughes energy services firm said in its weekly report on Friday."The increase in drilling activity in the U.S. as reported by the oil service provider Baker Hughes on Friday evening is generating headwind," Commerzbank said in a note. "Clearly the significantly lower prices in the fourth quarter are prompting shale oil producers to exercise restraint. Because prices have risen considerably since the start of the year and there is a high number of drilled but uncompleted wells, drilling activity is likely to recover soon."Even with an uncertain outlook for demand and evidence of growing supply, the oil market has benefited this month from another round of production cuts by OPEC and its partners, as well as robust trade in physical barrels of crude led by China.Investors have added to their bets on a sustained rise in the oil price this month for the first time since September, according to data from the InterContinental Exchange. But much of the demand outlook hinges on China and whether or not its refiners will continue to import crude at 2018's breakneck pace.

US crude falls 3.2%, settling at $51.99, as weak industrial earnings stoke demand fears -  Oil prices tumbled on Monday as weak industrial earnings in both China and the United States raised fresh concerns about a global slowdown that could cut fuel demand. U.S. West Texas Intermediate crude ended Monday's session down $1.70, or 3.2 percent, at $51.99 a barrel, its lowest closing price in two weeks. Brent crude, the international benchmark for oil prices, was down $1.71, or 2.8 percent, at $59.93 around 2:30 p.m. ET, slipping below $60 for the first time in nearly two weeks. Profits at Chinese industrial firms contracted in December for a second straight month, China's National Bureau of Statistics said on Monday. The latest datapoint adds to series of weak signals coming from the world's second biggest economy. Last week, Beijing reported that the economy grew at the slowest pace in nearly 30 years in 2018. Later on Monday, bellwether industrial Caterpillar issued weak guidance for future profits and reported disappointing fourth-quarter earnings, citing the impact of tariffs and slower sales in China. "Those Caterpillar earnings were sort of a canary in the coal mine in terms of industrial activity out there. Losses sped up after that hit the tape," said John Kilduff, founding partner at energy hedge fund Again Capital. Kilduff says markets will be closely watching upcoming data from Chinese state run firms and the private manufacturing sector. Also critical will be headlines coming out of the latest trade talks between Washington and Beijing scheduled for later this week, he added. The ongoing trade dispute — and the threat of higher tariffs on hundreds of billions in goods — is keeping markets on edge. But despite the trade tension, oil remains on pace for strong gains in January. WTI is up more than 14 percent this month, while Brent is on pace for a gain of about 11 percent. The price has been supported by early signs that OPEC and its allies are delivering on their pledge to cut production by 1.2 million barrels a day in order to drain oversupply from the market.

Oil prices stumble at start of week after U.S. rig count rises - Oil prices settled at a two-week low on Monday, then edged higher by in electronic trading after the U.S. Treasury unveiled sanctions on Venezuela’s state-owned oil firm, Petróleos de Venezuela SA. Prices had fallen during the regular trading session, reflecting fresh concerns over supply, and the potential for a slowdown in energy demand from China. Monday afternoon, however, the U.S. Treasury sanctioned Venezuela’s oil firm, which is also known as PdVSA, raising the risk of disruptions to oil supply from the South American nation, which is home to the world’s largest oil reserves. “The United States is holding accountable those responsible for Venezuela’s tragic decline, and will continue to use the full suite of its diplomatic and economic tools to support Interim President Juan Guaidó, the National Assembly, and the Venezuelan people’s efforts to restore their democracy,” Treasury Secretary Steven Mnuchin said in a statement. All property and interests in property of PdVSA subject to U.S. jurisdiction are “blocked and U.S. persons are generally prohibited from engaging in transactions with them.” In electronic trading, West Texas Intermediate crude for March delivery US:CLG9 was at $52.18 a barrel, just after 4 p.m. Eastern time Monday. The contract had fallen by $1.70, or 3.2%, to settle at $51.99 a barrel on the New York Mercantile Exchange after losing 0.7% last week. March Brent crude LCOH9, +1.90% was at $60.05 in electronic dealings after falling $1.71, or 2.8%, to $59.93 a barrel during the regular session on ICE Futures Europe. The contract lost about 1.7% last week. Both benchmark contract saw their lowest settlements since Jan. 14, according to FactSet data. As to whether the sanctions actually raise the risk of disrupting oil supply from Venezuela, James Williams, energy economist at WTRG Economic, said that answer is “yes and no.” “If Venezuela is willing to continue to send shipments to the U.S. even though Maduro can not get his hands on the money there is no impact,” he said. “The money will go into an account to be released when Venezuela has a legitimate government. “I suspect Maduro will attempt to sell the oil elsewhere,” said Williams. “The threat is Maduro’s reaction.”

Oil prices edge up on US sanctions against Venezuela - Oil prices rebounded on Tuesday from steep losses in the previous session after Washington imposed sanctions on Venezuelan state-owned oil firm PDVSA in a move that may curb the country's crude exports.Despite the move, which comes as the U.S government looks to pile pressure on President Nicolas Maduro to step down, traders said ample global oil supply and an economic slowdown, especially in China, were keeping crude prices in check.U.S. West Texas Intermediate crude futures were up $1.84, or 3.5 percent, at $53.83 per barrel at 10:05 a.m. ET (1505 GMT). WTI fell 3.2 percent in the previous session.International Brent crude futures rose $1.73, or 2.9 percent, to $61.66 per barrel, after tumbling nearly 2 percent on Monday.Venezuela has the world's biggest proven oil reserves, but its potential has not been realized due to a lack of investment. The country is also a member of OPEC, which is implementing a supply cut deal."The Latin American country is predominantly the producer of heavier crude, exactly what (U.S. Gulf) refiners are thirsty for," PVM said in a note."They will now have to turn elsewhere (possibly to Mexico, Saudi Arabia and Iraq) to satisfy their needs for this type of crude, which would inevitably lead to a price spike."Venezuela's exports fell to little more than 1 million barrels per day in 2018 from 1.6 million bpd in 2017, according to Refinitiv ship tracking data and trade sources.The United States has been the biggest buyer of Venezuelan oil despite their political differences, taking around half of the country's export volumes, followed by India and China.Petromatrix estimated that Venezuelan exports will drop by around 500,000 barrels a day under current conditions.While news of the sanctions against Venezuela made headlines, analysts said the fundamental issue for global oil trade remained plentiful supply. Global oil supply remains high largely due to a more than 2 million bpd increase in U.S. crude oil production last year, to a record 11.9 million bpd.

Oil Prices Bounce On Venezuela Turmoil And Saudi Cuts - After a selloff on Monday, oil prices steadied at the start of trading on Tuesday.  Renewed concerns over Chinese growth weighed on crude prices on Monday, with WTI and Brent falling more than three percent. It was the largest single-day decline in a month. Meanwhile, the U.S. oil rig count jumped by 10 last week, a sign that the U.S. shale industry could be adding rigs back into operations. “We’re seeing oil prices really start to break down here,” Phillip Streible, senior market strategist at RJO Futures in Chicago, told Reuterson Monday. “One of the factors that played in is the rising rig count that we saw on Friday.”  The Wall Street Journal reported that U.S. Vice President Mike Pence was in communication with Juan Guaidó prior to Guaidó’s declaring that he was the rightful president. The report suggests that the U.S. effort at regime change in Venezuela has been underway for some time and is tightly coordinated. The Venezuelan military is sticking with President Nicolas Maduro for now, but the WSJ report suggests the U.S. government is determined to topple him.   Saudi oil minister Khalid al-Falih said that Saudi Arabia would lower its oil production in February to just 10.1 million barrels per day, down from 10.2 mb/d this month. The reduction would also be lower than Riyadh’s commitments as part of the OPEC+ deal – its limit is set at 10.33 mb/d. “Saudi Arabia will be well below the voluntary cap that we agreed to” and will produce below its ceiling “for the full six months” of the deal, al-Falih told Bloomberg.   EQT, Antero Resources and Gulfport Energy have cut their spending plans for 2019 amid a decline in natural gas prices and pressure from investors on returns. The U.S. shale gas revolution, more than a decade old, has failed to produce the juicy profits that have long been expected. Now, investors are clamoring for a shift in focus away from production growth, with a priority on shareholder returns. U.S. shale gas companies have badly trailed the S&P 500. EQT announced a spending cut of $700 million relative to 2018.

Oil prices up 2 pct following U.S. sanctions on Venezuela (Reuters) - Oil prices gained more than 2 percent on Tuesday after the United States imposed sanctions on state-owned Venezuelan oil company PDVSA, a move likely to reduce the OPEC member’s crude exports and relieve some global oversupply worries. International Brent crude oil futures were up $1.39 to settle at $61.32 a barrel, a 2.32 percent rise, while U.S. West Texas Intermediate (WTI) crude futures increased $1.32 to settle up $53.31 a barrel, or 2.54 percent. Venezuela is among the world’s largest heavy crude oil producers, and the United States has been its biggest client, taking about half the country’s export volumes.. The Trump administration’s restrictions on Venezuelan crude, aimed at driving President Nicolas Maduro from power, stop short of banning U.S. companies from buying oil from the Latin American country. However, proceeds from such sales will be put in a “blocked account” that should deter PDVSA from shipping crude to the United States. “Today’s price advance looked like a delayed reaction to yesterday’s Venezuelan headlines as traders may have had second thoughts about the impact on domestic oil supplies,” said Jim Ritterbusch, president of Ritterbusch and Associates in a note. Additionally, “possibilities that some Gulf coast refiners may need to pay up for alternative stocks from such places such as Saudi Arabia that has already suggested that they will be steering cargoes away from the U.S.,” he wrote. Venezuela’s exports have already fallen to little more than 1 million barrels per day (bpd) in 2018 from 1.6 million bpd in 2017, according to Refinitiv ship-tracking data and trade sources. Petromatrix estimated that Venezuelan exports will drop by about 500,000 barrels per day under current conditions. Venezuela is also a member of the Organization of the Petroleum Exporting Countries, which is implementing a supply cut deal to support prices. Russia, OPEC’s biggest non-member ally, and China have both publicly denounced the sanctions. Meanwhile, Libya’s biggest oilfield, El Sharara, will remain shut until departure of an armed group occupying the site, the head of National Oil Corp said.

Oil Holds Biggest Gain in More Than a Week -- Oil held its biggest gain in more than a week as investors assessed the impact of U.S. sanctions against Venezuela, while waiting for the outcome of trade talks between Washington and Beijing. Futures in New York were steady after climbing 2.5 percent on Tuesday. Venezuela is considering declaring force majeure with the U.S. after the White House effectively banned American companies from purchasing its crude. The U.S. and China sit down in Washington on Wednesday for two days of high-level discussions after Treasury Secretary Steven Mnuchin told the Fox Business Network that he expected “significant progress” in the talks. Oil is trading in its tightest range in four months as the Organization of Petroleum Exporting Countries and its allies trim output to fight a global glut driven by record U.S. production. The crisis in Venezuela has so far had only a limited impact on prices as it doesn’t change the overall supply and demand picture. Restoring the country’s output could take years, according to Jeff Currie, head of commodities research at Goldman Sachs Group Inc. “There’s little room for oil to gain significantly unless the political situation in Venezuela blows up,” said Kim Kwangrae, a commodities analyst at Samsung Futures Inc. in Seoul. “Investors are also closely watching what happens with the trade talks in Washington.” West Texas Intermediate crude for March delivery fell 6 cents to $53.25 a barrel on the New York Mercantile Exchange at 3:29 p.m. in Singapore. The contract climbed $1.32 to close at $53.31 a barrel on Tuesday, the biggest advance since Jan. 18. Brent for March settlement was 3 cents lower at $61.29 a barrel on the London-based ICE Futures Europe exchange. The contract increased $1.39 to $61.32 in the previous session. The global benchmark crude was at a $8.03 premium to WTI. Investors are waiting to see how Venezuela responds to the latest American sanctions. If Caracas decides to declare force majeure on its crude exports to the U.S. market, almost 12 million barrels could be affected next month, according to a loading program seen by Bloomberg. Force majeure protects a party from liability if it can’t fulfill a contract for reasons beyond its control.

Trump May Soon Need to Choose between Battling OPEC Nations and Cheap Oil-- President Donald Trump may soon need to choose between two recurring fixations: battling OPEC nations, and cheap oil. After announcing sanctions on Venezuela’s state-run oil company PDVSA this week, the president is now in conflict with two of the cartel’s founding members, having imposed similar measures against Iran late last year. Trump is pressuring the Islamic Republic over its nuclear program, and squeezing Venezuela’s President Nicolas Maduro for fraudulently clinging to power. Iranian shipments have already slumped by 1.3 million barrels a day, and about 500,000 barrels a day of Venezuelan crude which has been banned by the U.S. will soon need to find new buyers. The overall disruption could be much bigger if America succeeds in choking off Iran’s exports entirely, or if sanctions on Venezuelan oil are applied more broadly, as suggested in a tweet from National Security Adviser John Bolton. However, knocking out oil-supplies from the petro-states is likely to conflict with another of the U.S. president’s goals: lowering gasoline prices to appease motorists and stimulate the American economy. Though prices remain at about $54 a barrel in New York, 30 percent below the four-year peak reached last October on concern that Trump may not grant waivers for buyers of Iranian crude, that calm might not last, and the U.S. may need to decide between the two aspirations. In May, Trump will decide whether to renew temporary exemptions that allowed eight of Iran’s customers -- including China and India -- to continue buying reduced quantities from the Islamic Republic. If these waivers aren’t extended, Iranian shipments will likely slump further. To fill the gap, Treasury Secretary Steve Mnuchin has said America’s Middle East allies, Saudi Arabia in particular, are ready to restore production. The kingdom ramped up output to record levels last autumn when it seemed Trump was serious about shutting Iran’s trade down completely. The question is whether the Saudis and their allies can increase production high enough, and keep it there, to compensate for simultaneous losses in Iran and Venezuela. Although the kingdom sits on about 1.4 million barrels a day of spare production capacity, according to the International Energy Agency, even that could be strained by a deep and prolonged outage.

WTI Extends Gains After Smaller Than Expected Crude Build  - Oil prices jumped higher today after U.S. Treasury Secretary Steven Mnuchin signaled a truce is possible in the trade war with China amid multiplying threats to global crude supplies. “The weekly inventory data will start to regain some importance over the coming weeks, as the market is looking for signs that OPEC cuts are making their way to the States," says Bart Melek, head commodity strategist for TD Securities in Toronto, in an emailed note.  API:

• Crude +2.098 (+3mm exp)
• Cushing -682k (+100k exp)
• Gasoline +2.15mm (+2.4mm)
• Distillates +211k (-2mm exp)

A smaller than expected crude build sparked only very modest buying in WTI as builds in gasoline and distillates (surprise) spoiled the bulls' party, WTI hovered around $53.20 ahead of the API print (up over 2% on trade hopes) and lifted very modestly as the data hit... “You’re getting a little bit more of a security premium built into the price today," said John Kilduff, founding partner of hedge fund Again Capital LLC in New York. “As more of the details emerge of Maduro standing tough and trying to send the oil away from Gulf Coast refiners, and the Trump administration planning to freeze bank accounts and lock up opposition, the situation is on the boil."

WTI Jumps Above $54 After Small Crude Build, Biggest Gasoline Draw In 3 Months - WTI prices are higher overnight following a smaller than expected crude build from API and ongoing concerns about Venezuela sanctions disrupting supply. mBloomberg Intelligence Senior Energy Analyst Vince Piazza comments that:Uncertainty over U.S.-China trade talks and Venezuela possibly declaring force majeure on its exports add to an already-clouded oil-market outlook. Refinery utilization has retreated while U.S. crude production remains resilient, and recent rig counts suggest a rekindling of activity.Slowing demand, an ebbing global economic growth outlook and ample gasoline supplies inform our reserved stance on balances, despite OPEC’s compliance with capacity curbs. The cartel and its partners will need to extend curbs into 2H to support benchmarks. DOE:

• Crude +919k (+3.15mm exp)
• Cushing  (+100k exp)
• Gasoline -2.24mm 30 (+2.4mm)
• Distillates  (-2mm exp)

After last week's huge surprise crude build, expectations were for another big build but DOE reports a mere 919k rise in inventories (well below the +3.15mm exp). Additionally, gasoline stockpiles dropped for the first time since November, by the most since October...  Production flatlined Week over week at record highs. U.S. Crude Imports from Saudi fall to the lowest since Oct. 2017.  WTI traded just below $54 ahead of the DOE print and spiked above it on the small build...

Oil rises as US fuel stocks fall, extending gains from Venezuela sanctions -- Oil prices rose on Wednesday, boosted by concerns about supply disruptions following U.S. sanctions on Venezuela's oil industry but pegged back by uncertainty over the global economy. Futures extended gains after weekly data showed a smaller-than-anticipated jump in U.S. crude inventories and an unexpected drop in gasoline stockpiles. U.S. West Texas Intermediate crude futures rose $1.22, or 2.3 percent, to $54.53 per barrel around 11:04 a.m. ET (1504 GMT). International Brent crude oil futures were up $1.13, or nearly 1.8 percent, at $62.45 per barrel. Crude inventories rose by 919,000 barrels in the last week, the U.S. Energy Information Administration reported. Analysts in a Reuters poll expected an increase of 3.2 million barrels. Meanwhile, gasoline stocks fell by 2.2 million barrels, compared with analysts' expectations for a 1.9 million-barrel gain. Distillate stockpiles, which include diesel and heating oil, shrank by 1.1 million barrels, versus expectations for a 1.4 million-barrel drop, the EIA data showed. Washington on Monday announced export sanctions against Venezuela's state-owned oil firm PDVSA, limiting transactions between U.S. companies that do business with Venezuela through purchases of crude oil and sales of refined products. "The sanctions so far have been mostly disruptive for refiners on the U.S. Gulf Coast, who are being forced to seek alternative heavy crude supplies, and have stepped up purchases from Canada," said Vandana Hari of Vanda Insights, an energy consultancy. Venezuelan President Nicolas Maduro said on Wednesday he was ready for talks with the opposition although he ruled out snap elections. The sanctions aim to freeze sale proceeds from PDVSA's exports of roughly 500,000 barrels per day of crude to the United States. Its output was already near seven-decade lows while the sanctions affect Venezuelan supply only to the United States, and analysts believe volumes could eventually be rerouted to China and India at discounts. "The main risks for supply could come from a violent confrontation within the country, damaging the oil infrastructure," 

U.S. oil prices end at 2-month high on modest crude supply rise, Venezuela turmoil - Oil futures settled higher Wednesday, with weekly domestic crude supplies up less than expected and U.S. sanctions on Venezuela’s state-run oil company lifting U.S. benchmark prices to their highest finish in over two months. The U.S. sanctioned Venezuela’s Petróleos de Venezuela SA, or PdVSA, earlier this week, raising the risk of disruptions to global oil supply from the Organization of the Petroleum Exporting Countries member, which is also home to the world’s largest oil reserves. West Texas Intermediate crude for March delivery gained 92 cents, or 1.7%, to settle at $54.23 a barrel on the New York Mercantile Exchange. Based on the front-month contracts, prices logged their highest finish since Nov. 21, according to FactSet data. Month to date, front-month contracts were up 19%, on pace for the best January performance since at least 1985, according to Dow Jones Market Data. March Brent crude rose 33 cents, or 0.5%, to $61.65 a barrel on ICE Futures Europe. The contract expires at Thursday’s settlement. The Energy Information Administration reported Wednesday that domestic crude supplies edged up by 900,000 barrels for the week ended Jan. 25. That was smaller than the 3.1 million-barrel rise expected by analysts polled by S&P Global Platts. The American Petroleum Institute reported on Tuesday a weekly climb of about 1.1 million barrels, but the group also upwardly revised the previous week’s total by roughly 1 million barrels. “A precipitous drop in imports has helped stave off another big build to crude stocks,” said Matt Smith, director of commodity research at ClipperData, referring to the EIA data. “A whopping drop in imports of over 1 million barrels per day has helped mitigate the impact of a substantive drop in refining activity — down nearly 600,000 bpd — leading to a minor build to crude stocks.”

Oil surges more than 18 percent this month for its best January on record -- U.S. crude oil surged this month to post its best January performance on record, breaking a three-month losing streak that saw futures lose nearly half of their value. Crude futures have powered through a steady flow of weak economic data from China, the world's second biggest oil consumer, amid an ongoing trade dispute with Washington. The energy complex has been boosted by OPEC-led production cuts aimed at draining oversupply and U.S. sanctions on Venezuela, which threaten to disrupt global trade flows and bolster prices. U.S. West Texas Intermediate crude prices ended Thursday's session down 44 cents at $53.79 a barrel, after hitting a two-month high at $55.37. WTI posted an 18.5 percent monthly gain, its biggest jump since April 2016 and its best January since the futures began trading in 1983. International benchmark Brent crude for March delivery rose 24 cents at $61.89 a barrel, finishing January up 15 percent, also the best monthly gain since April 2016. Brent's more heavily traded April contract was down 1 percent at $60.89 around 2:30 p.m. ET. Prices tumbled after U.S. Energy Information Administration reported U.S. oil production rose to an all-time high 11.9 million barrels per day in November, up from 11.5 million bpd in October. Preliminary weekly figures have long telegraphed the jump, confirmed by EIA's first monthly reading on Thursday. The drop also came after President Donald Trump said he wants a big trade deal with China, but may not reach an agreement by March 1, the deadline to prevent a rise in tariffs on hundreds of billions of dollars in goods.  "I'm not sure President Trump's comments about the China situation were helpful to the bull case," Kilduff said some traders may be taking profits after WTI jumped above $55 a barrel on Thursday for the first time in over two months. Despite the strong monthly performance, both benchmarks remain in bear market territory, with WTI down about 30 percent from its 52-week high in October. The crude price collapsed to roughly 18-month lows in the final quarter of 2018 on growing oversupply, weak demand signals and technical trading.

Oil Rises 18% In Best January On Record - Oil prices gained roughly 18 percent in January, the largest gain for that month of the year on record. “A break through $55 in WTI and $65 in Brent would be a very bullish signal for these and could be the catalyst for more significant upside, with oil having stabilised over the last few weeks following the post-Christmas bounce,” Craig Erlam, senior market analyst at brokerage OANDA, wrote in a briefing. Prices lost ground on Thursday, but there are plenty of bullish landmines lurking in the market, ranging from Venezuela and Iran outages, OPEC+ cuts, and slowing U.S. shale growth.  The U.S. government is considering a release of oil from the strategic petroleum reserve (SPR), timed with potential outages from Venezuela. Venezuela has exported roughly 500,000 bpd to the U.S., and because of American sanctions, those volumes are now in jeopardy. The only problem is that the SPR does not contain heavy crude. Already the market for heavy oil is tight while that for lighter oil is much looser.  U.S. refiners that import heavy oil from Venezuela are now looking for alternatives. Canada and Mexico have heavy oil, but have little scope to increase supply. “The region with the biggest shortfall of Venezuelan crudes, either through sanctions or inadvertently through further production declines is the U.S.,” said Michael Tran, commodity strategist at RBC Capital Markets, in a note. U.S. domestic medium and heavy sour grades, including Mars Sour, have seen their prices jump. “It’s nuts. Everything with sulfur in it is getting bid,” one U.S. crude trader told Reuters, referring to sour oil that is typically less desired. Valero, Chevron, and of course, Citgo, are the largest importers of Venezuelan oil.  PDVSA is trying to work around U.S. sanctions, seeking fuel swaps and intermediaries. “We are trying to redo the contracts. It is not yet entirely clear how because customers are being individually called, but we are studying alternatives,” a PDVSA source told Reuters. Rosneft has made billions of dollars’ worth of loans to Venezuela and could suffer if the U.S.-backed coup is successful. Rosneft’s share price fell last week after the U.S. recognized the opposition.

Oil prices rise as US reports big surge in employment - Oil prices jumped with the stock market on Friday after the United States reported a surge in employment in its monthly jobs report. U.S. payrolls rose by 304,000 in January even as the country weathered the longest government shutdown in history. International Brent crude oil futures were up 88 cents, or 1.5 percent, at $61.72 per barrel around 9:35 a.m. ET (1435 GMT). U.S. West Texas Intermediate (WTI) futures were up 66 cents, or 1.2 percent, at $54.46 per barrel. Crude traded flat earlier on Friday as hopes the United States and China could soon settle their trade disputes offset data from China that stoked concerns over an economic slowdown that could dent demand for fuel. Global markets gained support from comments on Twitter by U.S. President Donald Trump on Thursday, saying he would meet Chinese President Xi Jinping soon to try to resolve a trade standoff, though Trump later warned that he could postpone talks if a comprehensive deal remains elusive. "Many traders recognize that sense is likely to prevail and a deal will be struck after the summit - although the shape of any deal will continue to drive a jittery market," Cantor Fitzgerald Europe said in a note. "This has overshadowed bullish indicators." Crude prices were weighed down by a survey on Friday that showed China's factory activity shrank by the most in almost three years in January, reinforcing fears that a slowdown in the world's second-largest economy is deepening. The U.S.-China trade dispute and tightening financial conditions worldwide have hurt manufacturing activity in most economies, including in China, where growth last year was the weakest in nearly 30 years. With Chinese industry a key consumer of fuels such as diesel, such a slowdown is also likely to hit fuel demand.

Oil prices up on strong U.S. jobs data, Venezuela sanctions - (Reuters) - Oil prices rose about 3 percent on Friday on upbeat U.S. jobs data and signs that U.S. sanctions on Venezuelan exports have helped tighten supply, then extending gains after weekly data showed U.S. drillers cut the number of oil rigs. Brent crude oil futures rose $1.91 a barrel, or 3.14 percent, to settle at $62.75 a barrel. The international benchmark notched a weekly gain of about 1.9 percent. U.S. West Texas Intermediate (WTI) futures ended the session at $55.26, up $1.47 a barrel or 2.73 percent and gained about 3 percent on the week. Prices climbed to session highs after General Electric Co’s Baker Hughes energy services firm reported that U.S. energy firms cut the number of operating oil rigs for a fourth week in the past five, bringing the count to the lowest in eight months. Last week’s data showed the rig count in January fell the most in a month since April 2016. Oil prices got a boost from Wall Street after surprisingly strong U.S. job growth data fed demand for equities. Washington imposed sanctions on Venezuela’s Petróleos de Venezuela SA this week, keeping tankers stuck at ports. On Friday, the U.S. Treasury Department provided details. “We are beginning to see the impact to crude supplies from the sanctions on Venezuela. It has driven up domestic crude prices, cutting into refiner margins,” Andrew Lipow, president of Lipow Oil Associates in Houston, said. “That, combined with Saudi cuts and Libyan production declines has changed market sentiment as we appear to be moving toward a better balanced supply situation.” Some U.S. refiners have begun reducing crude processing as sanctions have boosted oil costs and as gasoline margins crashed to their lowest in nearly a decade, market sources told Reuters on Thursday. In January, Saudi Arabia pumped 350,000 bpd less than in December, a Reuters survey showed. Financial markets also gained support from comments on Twitter by U.S. President Donald Trump on Thursday, saying he would meet Chinese President Xi Jinping soon to try to resolve a trade standoff. But Trump later warned he could postpone talks if a deal remains elusive.

Saudi Arabia says it raised $106 billion from 'anti-corruption' drive that swept up royals - Saudi Arabia has wrapped up a long-running corruption probe that captured the market's attention in 2017 after the kingdom detained dozens of prominent princes and businessmen. The Saudi Royal Court on Wednesday said the kingdom has retrieved more than 400 billion Saudi riyals — or about $106 billion — in cash, real estate and other assets. The wave of arrests in November 2017 caught the world by surprise and turned the Ritz-Carlton in the capital city of Riyadh into a gilded prison for the scores of Saudis swept up in the campaign. The kingdom cast the detentions as part of a crackdown on entrenched corruption, while some observers said the detentions were orchestrated to consolidate power under Crown Prince Mohammed bin Salman, the next in line to King Salman bin Abdulaziz. Prince Mohammed chaired the corruption committee. Allegations of abuse and reports that detainees were being asked to exchange their assets for freedom rattled the market at a time when Saudi Arabia was accelerating its bid to attract foreign investment. The arrests came just days after the Saudis hosted an inaugural international investment summit in Riyadh. Among the prominent detainees were Prince Alwaleed bin Talal, Saudi Arabia's most prominent investor, and Prince Mutaib al-Saud, the former head of the country's National Guard. Concerns about Prince Mohammed's rule following the arrests were compounded one year later when Saudi dissident Jamal Khashoggi went missing after entering a Saudi consulate in Istanbul, Turkey. After initially denying any responsibility, the kingdom admitted Saudi agents had killed Khashoggi, a Washington Post columnist and U.S. resident, inside the consulate.

UN Experts Investigating Khashoggi’s Death Banned From Entering Crime Scene — — A team of United Nations (UN) human rights experts carrying out an international investigation into the killing of Saudi journalist Jamal Khashoggi have been banned from entering the crime scene at the Saudi consulate in Istanbul, Turkey. Leader of the investigation Agnes Callamard and her team of rights experts recently announced that it had submitted a request to the Saudi authorities to enter the consulate’s premises and meet with Saudi officials in Istanbul, Turkish NTV reported yesterday. The special rapporteur said that she was waiting for the Saudi authorities’ response, but explained that her team was able to carry out a survey on the area surrounding the consulate. “We are respectfully calling on the authorities to give us access,” she was quoted by Reuters as saying. The team arrived in Istanbul on Monday for a week-long visit to investigate the circumstances of Khashoggi’s killing on 2 October. Callamard said she had initiated the inquiry on her own, as the UN “has given no intention to conduct an international criminal investigation”. During the visit, Callamard and her team met with Istanbul’s Chief Prosecutor Irfan Fidan – who is heading the investigation – and the Turkish Foreign and Justice Ministers Mouloud Chavushoglu and Abdulhamit Gül respectively. The expert on extrajudicial, summary or arbitrary killing pointed out that she would present her report on the investigation to the UN’s Human Rights Council in June. Callamard is a long-standing advocate of human rights and freedom of expression. She was appointed as a UN special rapporteur in 2016 to investigate arbitrary executions. Khashoggi, a Washington Post columnist who wrote critically about Saudi Crown Prince Mohammed Bin Salman (MBS), was killed on 2 October after he entered the Saudi Consulate in Istanbul to obtain documents for his upcoming marriage. He was killed in what Turkish and US officials have described as an elaborate plot..

US Interrogators are Working in UAE Prisons in Yemen — US interrogators are present in UAE prisons in Yemen, the Daily Beast has revealed today, providing shocking evidence that the American military is a witness to the torture of Yemenis. In a series of interviews, two former detainees have testified to being interrogated by men with American accents, who looked on as they were beaten and electrocuted. “They would strip me naked, they would beat me very harshly and slowly you start to understand the dynamics in the room. These are the two people, one of them is overseeing the whole interrogation and the other is doing the questioning and ordering the torture,” a Yemeni man identified only as Salvatore said, suggesting that the US was more than an unwilling observer. In December, the Pentagon formally acknowledged for the first time that US military personnel operate in the Yemen prisons: “US forces do not conduct detention operations in Yemen; rather, US forces conduct intelligence interrogations of detainees held in partner custody,” the Pentagon reported. However, the latest accounts are the first that prove that the US is not only a witness but a partner to the torture of detainees. Both men say they saw Americans in military uniforms, complete with American flag insignia, and that a larger US presence was witnessed in a prison in Aden, where they were electrocuted, beaten and sexually threatened, and where others have been raped.

UAE Gender Equality Awards Go To All Male Recipients - For those not holding their breath, the results are in from the United Arab Emirates' gender equality awards. Perhaps to be expected when a foremost Sunni Gulf autocratic oil and gas state that mimics a medieval feudal monarchy decides to showcase its "progress" in the area of gender equality in the workplace, we have something that sounds straight out of The Onion, but is all too real. As The Guardian reports, social media exploded in laughter and ridicule "after it emerged that all of the winners of an initiative designed to foster gender equality in the workplace were men." Indeed the "awards ceremony" photo op was classic, featuring an all-male cast of honorees receiving awards in the following categories: Best Personality for Supporting Gender Balance, Best Federal Entity for Supporting Gender Balance, and the Best Initiative for Supporting Gender Balance.UAE Vice President and ruler of Dubai, Sheik Mohammed bin Rashid al-Maktoum, bestowed the certificates and medals in a ceremony on Sunday on the male winners representing various government ministries, including the finance ministry, the federal competitiveness and statistics authority and ministry of human resources re spectively.Thus the additional absurd element is that the UAE government was essentially handing out government "gender equality" recognition awards to itself. This included top ranking generals given that the deputy prime minister and minister of the interior, Lt Gen Sheikh Saif bin Zayed al-Nahyan, received the “best personality supporting gender balance” — supposedly for his tireless efforts implementing maternity leave in the UAE’s military.

IAEA: Iran Continues Meeting Commitments Under Nuclear Deal - As has been exclusively the case in recent years, IAEA Chief Amano Yukiya issued a statement Wednesday confirming once again that Iran is still meeting all commitments it has under the P5+1 nuclear deal. Under the deal, the IAEA is responsible for verifying that Iran is meeting all of its requirements under the pact. Since the deal’s implementation, the IAEA has consistently affirmed that Iran is meeting those requirements.  Which is a source of tensions between the international watchdog and the Trump Administration. The administration has repeatedly declared Iran in violation, but can’t get anyone else to confirm that, and has pushed the IAEA to make new demands on Iran, which the IAEA has said are unwarranted.  As the international community tries to save the P5+1 deal after the US withdrew from it, the IAEA reports are increasingly important, in underscoring that the deal was, and is, wholly intact, and it was only the US that decided to abandon it.

Iran inches closer to unveiling state-backed cryptocurrency - Shut out of the global financial system, Iran is inching closer to a workaround to US sanctions with the possible unveiling of its first state-backed cryptocurrency in the near future. The virtual currency is anticipated to be announced at the annual two-day Electronic Banking and Payment Systems conference, which kicks off on January 29 in the capital, Tehran. The theme of this year's gathering is "blockchain revolution". The blockchain is a fixed distributed ledger technology that allows a network of computers to verify transactions between two parties, as opposed to validating them through a trusted, third-party entity. Details of Iran's new cryptocurrency were revealed last summer, after the Trump administration started reimposing sanctions over alleged "malign activities". The biggest blow to Iran's economy came in November, when some of its banks were barred from SWIFT, the Belgian-based global messaging system that facilitates cross-border payments. Countries excluded from SWIFT cannot pay for imports or receive payments for exports, leaving them crippled financially, and having to rely on alternative methods of moving money. Iran's cryptocurrency is expected to be rolled out in phases, first as a rial-backed digital token, to facilitate payments between Iranian banks and other Iranian institutions active in the crypto space, and later possibly as an instrument for the Iranian public to pay for local goods and services. 

Human Rights Double Standard- Iranian Sanctions Impact the Most Vulnerable - In January 2018, following the killing of Iranians in European countries, the EU imposed new sanctions on Iran. This came after the Trump administration imposed sanctions on Iran after withdrawing from the Joint Comprehensive Plan of Action in August 2018. The International Court of Justice then issued a decision ordering the United States to lift the sanctions linked to humanitarian trade, food, medicine, and civil aviation on the basis of the 1955 US-Iran Amity Treaty. This led the Iranian foreign minister, Javad Zarif, to state on Twitter that the sanctions disregarded Iranians’ human rights.Iran is one of the countries with a long-standing history of international sanctions. The country has been impacted by three types of sanctions: United Nations sanctions, European Union comprehensive multilateral sanctions and United States unilateral sanctions. The impact of these sanctions on Iranian citizens’ human rights is under-estimated. Yet, decades of sanctions have had a deep effect on people’s lives and on society, as illustrated by the ongoing twitter testimonies found under the hashtag “TargetingOrdinaryIranians.”The renewal of sanctions against Iran raises the necessity of examining the human rights’ impact of such restrictive punishments. The main question at hand is to understand why the international community seems to support sanctions despite the violations of human rights law. How far are states ready to go when violating human rights in the name of controlling the Iranian authorities, with perhaps, the goal of changing the governance system in place? In 1996, Reisman observed sanctions rarely reach their targets – the political and military elite – and deeply impacted the population in Haiti. It is indeed impossible to separate sanctions from their economic and social impact on a population. Studies demonstrate sanctions have the same effect as war. This is why the Iranian authorities have focused on denouncing the sanctions on human rights grounds. Gholamali Khoshroo, Iran’s representative to the United Nations, stated sanctions were morally wrong and violate basic human rights.

Syria rewards Iran with raft of agreements - Syria and Iran signed 11 agreements and memoranda of understanding late Monday, including a "long-term strategic economic cooperation" deal aimed at strengthening cooperation between Damascus and one of its key allies in the civil war that has torn the country apart. The agreements covered a range of fields including economy, culture, education, infrastructure, investment and housing, the official Sana news agency reported. They were signed during a visit to Damascus by Iran's First Vice President Eshaq Jahangiri. Syrian Prime Minister Imad Khamis said it was "a message to the world on the reality of Syrian-Iranian cooperation", citing "legal and administrative facilities" to benefit Iranian companies wishing to invest in Syria and contribute "effectively to reconstruction". The agreements included two memos of understanding between the railway authorities of the two countries as well as between their respective investment promotion authorities. In relation to infrastructure, there was also rehabilitation of the ports of Tartus and Latakia as well as construction of a 540 megawatt energy plant, according to Khamis. In addition there were "dozens of projects in the oil sector and agriculture", he added. The civil war has taken an enormous toll on the Syrian economy and infrastructure, with the cost of war-related destruction estimated by the UN at about $400 billion. Iran will stand "alongside Syria during the next phase that will be marked by reconstruction", Jahangiri promised. Iran and Syria had already signed a military cooperation agreement in August while Tehran has supported Damascus economically during the conflict through oil deliveries and several lines of credit.

Defying U.S., European powers set up company to trade with Iran - France, Britain and Germany, defying threats from Washington, are this week executing their plans to set up a special-payments company to secure some trade with Iran and blunt the impact of U.S. sanctions. In the short term, the new company is expected to struggle to achieve even its initial goal of enabling Tehran to import vital food and drugs at affordable prices. After months of delays, people familiar with the plan said Tuesday the three European governments had started the process of registering the company to run a payments channel that would allow goods to be bartered between European and Iranian companies without the need for direct financial transactions. The company should be established by Thursday or Friday, the people said. The company is being registered in France and will be headed by a German official with the French, British and German governments as shareholders — an arrangement intended to ward off U.S. Treasury Secretary Steven Mnuchin’s threat of sanctioning the entity by putting it under the aegis of Washington’s traditional European allies. The European Union promised to create what is known as the special-purpose vehicle as part of efforts to persuade Iran to remain in the 2015 nuclear deal following President Donald Trump’s decision in May to pull the U.S. out of the accord and reimpose sanctions. When many smaller member countries expressed reluctance to host the company or participate directly as shareholders because of U.S. sanctions threats, the bloc’s three biggest powers proceeded with the project.

Israel Wants US to Keep Troops at Military Base in Syria to Counter Iran  — As the Pentagon appears to be moving forward on President Trump’s ordered troop draw down from Syria, administration hawks as well as foreign allies like Israel have one final card to play to hinder a total withdrawal. They argue that some 200 US troops in Syria’s southeast desert along the Iraqi border and its 55-kilometer “deconfliction zone” at al-Tanf are the last line of defense against Iranian expansion in Syria, and therefore must stay indefinitely. Despite Trump’s pledge for a “full” and complete American exit, the al-Tanf base could remain Washington’s last remote outpost disrupting the strategic Baghdad-Damascus highway and potential key “link” in the Tehran-to-Beirut so-called Shia land bridge. Foreign Policy magazine identifies this as but the latest obstacle to an actual complete withdrawal of US forces:  “Al-Tanf is a critical element in the effort to prevent Iran from establishing a ground line of communications from Iran through Iraq through Syria to southern Lebanon in support of Lebanese Hezbollah,” an unnamed senior US military source told the magazine. Washington’s initial justification for establishing the remote special operations outpost was to train local fighters to counter ISIS; however, not only has ISIS now been driven almost completely underground but Russia has accused US forces at al-Tanf of actually allowing ISIS terrorists to maintain a presence in the area in order to put pressure on Damascus.  With the Islamic State now in tatters and defeated, the “counter Iran” argument is being pushed hard in order to convince Trump to keep a small US island of occupation in the heart of a volatile desert region where Syria, Iraq and Jordan meet. Israeli Prime Minister Benjamin Netanyahu is among the foremost foreign allies pushing hard, and “has repeatedly urged the U.S. to keep troops at al-Tanf, according to several senior Israeli officials, who also asked not to be identified discussing private talks,” per Bloomberg. The Israelis have reportedly argued “the mere presence of American troops will act as a deterrent to Iran” even if in small numbers as a kind of symbolic threat.

ISIS could reclaim territory in months without military pressure, warns Pentagon in draft report — A draft Pentagon report warns that without continued pressure, ISIS could regain territory in six to 12 months, according to two U.S. officials familiar with the draft.The finding is in a draft of the Department of Defense Inspector General Quarterly Report about Operation Inherent Resolve that is expected to be released early next week. The report draws on information from the U.S. military, U.S. government agencies, and open source reports.The draft says ISIS is intent on reconstituting a physical caliphateand that with ungoverned spaces in Syria and no military pressure, the terror group could retake land in a matter of months, according to the officials familiar with the report.The report covers the three months from Oct. 1 to Dec. 31, 2018. President Donald Trump announced on Dec. 19 that the U.S. military would be leaving Syria. "We have defeated ISIS in Syria," said Trump via Twitter, "my only reason for being there during the Trump Presidency." This week the Acting Secretary of Defense Patrick Shanahan agreed. "If we wind the clock back two years, I'd say 99.5 percent plus of the ISIS-controlled territory has been returned to the Syrians," he said during a briefing Tuesday. "Within a couple weeks, it'll be 100 percent."The Defense Department Office of Inspector General declined to comment on the draft report prior to its release. The National Security Council had no immediate comment.House Foreign Affairs Committee Chairman Eliot Engel, D-N.Y., responded to the NBC News report about the draft by calling it a clear indication from the Pentagon that “ISIS has not been defeated.”“If the President didn’t ignore his senior intelligence officials, perhaps he would arrive at the same conclusion,” Engel said.

Netanyahu misleads the Israelis about cross-border tunnels and “Operation Northern Shield”: Is he preparing an electoral war on Lebanon? - There is much talk in the Levant, in Syria and Lebanon, that Israel, and more precisely Prime Minister Benyamin Netanyahu, is seriously contemplating a large-scale cross-border battle that could escalate into war to ensure his re-election. Notwithstanding his claims of a “tremendous success in “Operation Northern Shield” (ONS) launched last December, Netanyahu is sending the Israeli Army to look for other tunnels, away from the media spotlight. The Prime Minister’s premature announcement of the success of the ONS shows that he has become the hostage of his own optimism, which he would like to invest in his forthcoming re-election. Netanyahu has managed to create serious panic among the Israeli population bordering Lebanon, and further inland, by confirming that Hezbollah possesses precision missiles capable of reaching any chosen target. Meanwhile, the secret underground infrastructure between Lebanon and Israel is not entirely under Israeli control and could be decisive in any future war involving the use of infantry for the purpose of abducting Israeli soldiers or officers or attacking settlments. Hezbollah has modern excavation equipment and the tunnels will be essential for moving any war that Israel might start out of south Lebanon into territory controlled by Israel’s enemy.   According to well -informed sources, the chances are strong that Israel may start a large battle against Lebanon, potentially leading to war. These sources believe that “Netanyahu may opt to use guided missiles and air force bombing with the goal of limiting Hezbollah’s missile capability. In that case, infantry would not be required and the Israeli army would be limited to protecting its borders and ensuring that no infiltration is possible through underground cross-borders tunnels”.

US Intel Chief: Israel Strikes in Syria May Lead to Regional War - US Director of National Intelligence Dan Coats told the Senate Intelligence Committee on Tuesday that he believes Iran wants to “avoid a major armed conflict with Israel,” but that continued Israeli attacks on targets in Syria may ultimately spark an Iranian retaliation. “Israeli strikes that result in Iranian casualties increase the likelihood of Iranian conventional retaliation against Israel.” Coats added that Israeli strikes are raising growing concerns that the “conflict will escalate.” Coats’ comments actually reflect an assessment from Israeli President Reuven Rivlin made just a day before, that he believes Iran will “retaliate with greater force” against northern Israel, and that Israel can no longer trust in “understandings” with Russia to avoid Iran retaliating against attacks.  Israeli officials used to be secretive about attacking Iranian targets, but with an election looming are increasingly bragging up the strikes as proof that they are being tough with Iran. Despite this, Coats says there is no sign the Israeli strikes are deterring Iranian plans to stay inside Syria.  Israeli officials have emphasized their intention to keep acting against Iran in Syria, despite it having not accomplished anything so far, and despite concerns from both US and Israeli officials that all it is doing is risking an escalation.

Survey Shows 80% of Turks Perceive US as the ‘Most Dangerous’ Country — According to a recent survey conducted by Kadir Has University a whopping 81.9 percent of Turks consider the United States the most dangerous country for Turkey.Israel follows the US with 63.3 percent, according to the survey, titled “Turkey Social and Political Trends Research,” published by Turkish media outlets on Wednesday.The opinion poll was conducted on 1,000 people over the age of 18 in face-to-face interviews between Dec. 12 and Jan. 4 in 26 provinces. The results of the survey, which has been carried out annually since 2010, were announced at a press conference by the university on Wednesday.The same research found that 41.9 percent of respondents want Turkey to leave NATO, while 58.7 percent are in favor of continuing the country’s membership, in effect since 1952.Amid strained relations with the European Union, still almost half of the nation is in favor of continuing membership negotiations with the bloc (48.9 percent).Nearly one-fifth of the country (18.8 percent) believes Turkey is under threat of division.In accordance with the traditional trends in the country, the majority of respondents describe themselves as conservative/religious, at 44.4 percent.According to Turks, the most important problem their society faces these days is unemployment (27 percent) and the high cost of living (17.8 percent). More than half of the society, 57.1 percent, says the economy is deteriorating. In line with a recent exodus from the country, the survey found that one out of five people would like to leave Turkey to live abroad if they got the chance.