largest mid-November addition of natural gas to storage in 19 years; DUC wells down on subdued drilling; well completions remain 69% lower than a year ago..
oil prices rose for a third consecutive week on the continued promise of a Covid-19 vaccine and hopes that OPEC would extend their production cuts into the new year... after rising 8.1% to $40.13 a barrel last week on hopes that a new vaccine would soon end the pandemic, the contract price of US light sweet crude for December delivery opened higher on Monday on data showing a rebound in China and Japan, the world's second and third largest economies, and never looked back, closing $1.21 higher at $41.34 a barrel, as news of another promising vaccine helped to ease concerns about Covid-19 lockdowns that would lower energy demand....oil prices edged higher again early Tuesday on expectations OPEC and its allies would extend oil production cuts for at least three months but ended mixed as traders awaited weekly data on crude supplies from the American Petroleum Institute that evening and the EIA the next day, with US crude finishing up 9 cents at $41.43 a barrel...oil prices then edged lower in post-settlement trade on Tuesday after the API reported a bigger build of U.S. crude stockpiles than had been expected, and thus opened lower on Wednesday, but recovered to close 39 cents higher at an eleven week high of $41.82 a barrel on hopes that OPEC+ would delay a planned increase in oil output while the EIA reported a smaller-than-expected increase in U.S. crude stockpiles...however, oil prices moved sharply lower Thursday after U.S. jobless claims rose for the first time in five weeks and as virus restrictions mounted, before recovering to close just 8 cents lower at $41.74 a barrel, as the dollar slipped late in the trading session, boosting prices of commodities priced in dollars...oil prices then rose 41 cents, or almost 1% on Friday, buoyed by successful Covid-19 vaccine trials, to settle at $42.15 a barrel, as trading in the US crude contract for December expired with a gain of 5% on the week, while US crude for January, which will be quoted as the price of oil next week, closed 52 cents higher at $42.42 a barrel, also up 5% on the week...
meanwhile, natural gas prices fell for the 2nd time in seven weeks, as the cold weather outbreak disappated and inventories grew at a near record pace for this time of year....after rising 3.7% to $2.995 per mmBTU last week as a winter weather outbreak in the Northern Plains pushed eastward, the contract price of natural gas for December delivery opened 4% lower on Monday and tumbled 10% to a near one-month low of $2.697 per mmBTU on forecasts for milder weather and lower heating demand, and on a steady rise in natural gas output...natural gas prices flipped between slight gains and losses during Tuesday’s session and ultimately settled at $2.692/MMBtu, down a half-cent on the day, as traders weighed weak weather-driven demand and rising production against continued strength in exports...while gas prices rose 2 cents on Wednesday as cold air moved out of the Upper Midwest, they then slid 12 cents, or 4.4%, to $2.592 per mmBTU on Thursday as U.S. forecasts shifted warmer through early December and EIA data showed an unusually big gain in stockpiles for this time of year...but prices bounced back 5.8 cents to close at a $2.650 per mmBTU on Friday, buoyed by record-high liquefied natural gas (LNG) exports and forecasts for cooler weather and higher heating demand in early December, but still ended the week 11.5% lower than the previous Friday close...
the natural gas storage report from the EIA for the week ending November 13th indicated that the quantity of natural gas held in underground storage in the US increased by 31 billion cubic feet to 3,958 billion cubic feet by the end of the week, which left our gas supplies 293 billion cubic feet, or 8.0% more than the 3,665 billion cubic feet that were in storage on November 13th of last year, and 231 billion cubic feet, or 6.2% above the five-year average of 3,727 billion cubic feet of natural gas that have been in storage as of the 13th of November in recent years....the 31 billion cubic feet that were added to US natural gas storage this week were well above the average forecast for a 22 billion cubic foot addition by analysts polled by S&P Global Platts, while the injection into storage contrasted with the average withdrawal of 24 billion cubic feet of natural gas that are typically pulled out of natural gas storage during the same week over the past 5 years, and the 66 billion cubic feet withdrawal from natural gas storage during the corresponding week of 2019....that 31 billion cubic feet that was added was also the largest addition of natural gas to storage for the 2nd week of November since 33 billion cubic feet were added during the week ending November 16, 2001, and dramatically contrasted with thelargest October natural gas storage withddrawal on record that we reported just two weeks ago..
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending November 13th indicated that because this week's increase in refinery use of crude oil just about matched the increase in our production while our imports decreased just modestly, we still had a surplus of oil to add to our stored commercial supplies for a second consecutive week and for the 6th time in the past seventeen weeks...our imports of crude oil fell by an average of 245,000 barrels per day to an average of 5,254,000 barrels per day, after rising by an average of 470,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 17,000 barrels per day to an average of 2,748,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,506,000 barrels of per day during the week ending November 13th, 228,000 fewer barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells was reportedly 400,000 barrels per day higher at 10,900,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 13,406,000 barrels per day during this reporting week...
meanwhile, US oil refineries reported they were processing 13,841,000 barrels of crude per day during the week ending November 13th, 395,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net of 52,000 barrels of oil per day were being added to the supplies of oil stored in the US....so based on that reported & estimated data, this week's crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 488,000 barrels per day less than what our oil refineries reported they used during the week plus what was added to storage....to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+488,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures we have just transcribed.....however, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we'll continue to report them as published, just as they're watched & believed to be accurate by most everyone in the industry...(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 rose to an average of 5,361,000 barrels per day last week, which was still 12.5% less than the 6,124,000 barrel per day average that we were importing over the same four-week period last year....the 52,000 barrel per day net addition to our total crude inventories was as 110,000 barrels per day were added to our commercially available stocks of crude oil, which was partly offset by the 58,000 barrels per day that was being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial inventories.....this week's crude oil production was reported to be 400,000 barrels per day higher at 10,900,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 400,000 barrels per day higher at 10,400,000 barrels per day, while a 5,000 barrels per day decrease to 514,000 barrels per day in Alaska's oil production still added the same rounded 500,000 barrels per day to the rounded national total...last year's US crude oil production for the week ending November 15th was rounded to 12,800,000 barrels per day, so this reporting week's rounded oil production figure was 14.8% below that of a year ago, yet still 29.3% 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...
meanwhile, US oil refineries were operating at 77.4% of their capacity while using 13,841,000 barrels of crude per day during the week ending November 13th, up from 74.5% of capacity during the prior week, but excluding the 2005 and 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the past thirty years...hence, the 13,841,000 barrels per day of oil that were refined this week were 15.8% fewer barrels than the 16,435,000 barrels of crude that were being processed daily during the week ending November 15th of last year, when US refineries were operating at 89.5% of capacity...
even with the increase in the amount of oil being refined, gasoline output from our refineries was quite a bit lower, decreasing by 255,000 barrels per day to 9,064,000 barrels per day during the week ending November 13th, after our refineries' gasoline output had increased by 247,000 barrels per day over the prior week...and since our gasoline production is still recovering from a multi-year low in the wake of this Spring's covid lockdown, this week's gasoline output was also 9.0% less than the 10,053,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) increased by 38,000 barrels per day to 4,237,000 barrels per day, after our distillates output had decreased by 38,000 barrels per day over the prior week....but since it's still near a three year low, our distillates' production was 16.6% less than the 5,124,000 barrels of distillates per day that were being produced during the week ending November 15th, 2019...
even with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 6th time in 20 weeks and for the 13th time in 42 weeks, rising by 2,611,000 barrels to 227,967,000 barrels during the week ending November 13th, after our gasoline supplies had decreased by 2,309,000 barrels over the prior week...our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 504,000 barrels per day to 8,2582,000 barrels per day, and because our imports of gasoline rose by 80,000 barrels per day to 530,000 barrels per day, while our exports of gasoline fell by 20,000 barrels per day to 690,000 barrels per day....so despite the gasoline inventory drawdowns of recent weeks, our gasoline supplies were still 3.2% higher than last November 15th's gasoline inventories of 220,846,000 barrels, and about 4% above the five year average of our gasoline supplies for this time of the year...
meanwhile, with our distillates production remaining well below normal for this time of year, our supplies of distillate fuels decreased for the 9th week in a row, for the 15th time in 33 weeks and for the 31st time in 52 weeks, falling by 5,216,000 barrels to 144,073,000 barrels during the week ending November 13th, after our distillates supplies had decreased by 5,355,000 barrels during the prior week....our distillates supplies fell again this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 171,000 barrels per day to 4,225,000 barrels per day, while our imports of distillates rose by 154,000 barrels per day to 285,000 barrels per day, and while our exports of distillates rose by 1,000 barrels per day to 1,080,000 barrels per day....but even after this week's inventory decrease, our distillate supplies at the end of the week were still 24.5% above the 115,681,000 barrels of distillates that we had in storage on November 15th, 2019, and about 11% above the five year average of distillates stocks for this time of the year...
finally, with the increase in our refinery throughput equalled by the increase in our field production, our commercial supplies of crude oil in storage (not including the commercial oil in the SPR) rose for the 10th time in the past twenty-three weeks and for the 33rd time in the past year, increasing by 769,000 barrels, from 488,706,000 barrels on November 6th to 489,475,000 barrels on November 13th....after that modest increase, our commercial crude oil inventories were still around 6% above the five-year average of crude oil supplies for this time of year, and about 43% above the prior 5 year (2010 - 2014) average of our crude oil stocks after two weeks of of November, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for this autumn and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of November 13th were 8.7% above the 450,380,000 barrels of oil we had in commercial storage on November 15th of 2019, 9.5% more than the 446,908,000 barrels of oil that we had in storage on November 16th of 2018, and 7.1% above the 457,142,000 barrels of oil we had in commercial storage on November 17th of 2017...
This Week's Rig Count This Week's Rig Count
the US rig count fell for the 1st time in ten weeks during the week ending November 20th, but for the 23rd time in the past 36 weeks, and hence it is down by 60.4% over that thirty-six week period....Baker Hughes reported that the total count of rotary rigs running in the US fell by 2 to 310 rigs this past week, which was also down by 493 rigs from the 803 rigs that were in use as of the November 22nd report of 2019, and was also 94 fewer rigs than the all time low prior to this year, and 1,619 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....
The number of rigs drilling for oil decreased by 5 rigs to 231 oil rigs this week, after increasing by 10 oil rigs the prior week, leaving us with 440 fewer oil rigs than were running a year ago, and less than a sixth of 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 3 to 76 natural gas rigs, which was still down by 53 natural gas rigs from the 129 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil & gas, three rigs classified as 'miscellaneous' continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico...a year ago, there were no such "miscellaneous" rigs deployed...
The Gulf of Mexico rig count was down by one to 12 rigs this week, with 11 of those rigs drilling for oil in Louisiana's offshore waters and one drilling for oil offshore from Texas...that was 10 fewer Gulf rigs than the 22 rigs drilling in the Gulf a year ago, when all 22 Gulf rigs were drilling offshore from Louisiana...since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week's national offshore rig figure are equal to the Gulf rig counts....meanwhile, in addition to those rigs offshore, two rigs continue to drill through inland bodies of water this week, one in St Mary's county in southern Louisiana and the other in Chambers County, Texas, just east of Houston, while a year ago there were no such rigs drilling on US inland waters..
The count of active horizontal drilling rigs was up by 5 to 272 horizontal rigs this week, which was still 427 fewer horizontal rigs than the 702 horizontal rigs that were in use in the US on November 15th of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014....on the other hand, the directional rig count was down by three to 20 directional rigs this week, and those were also down by 34 from the 54 directional rigs that were operating during the same week of last year....at the same time, the vertical rig count was down by four to 18 vertical rigs this week, and those were also down by 32 from the 50 vertical rigs that were in use on November 15th of 2019....
The details on this week's changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes...the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that 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 November 20th, the second column shows the change in the number of working rigs between last week's count (November 13th) and this week's (November 20th) count, the third column shows last week's November 13th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count before the same 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 22nd of November, 2019...
it doesn't look like there were many changes this week, but we know there had to be, with the directional and vertical rig removals we've noted, which wouldn't show up in the horizontally accessed basins shown here....checking first for the details on the Permian basin in Texas, we find that one rig was added in Texas Oil District 7C, which roughly corresponds to the southern part of the Permian Midland, while a rig was pulled out of Texas Oil District 8A, which corresponds to the northern Permian Midland, which thus means that Permian rigs in Texas were on net unchanged...since the Permian basin rig count was up by two rigs nationally, that means that the two rigs that were added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national increase...elsewhere in Texas, we find that one rig was pulled out of Texas Oil District 1, and another rig was pulled out of Texas Oil District 2, both of which seem to have come from basins that Baker Hughes doesn't track, while a rig was added in Texas Oil District 6, which accounts for one of the Haynesville natural gas rig additions...the other Haynesville additions came in northern Louisiana, and as a rig in Texas Oil District 6 was either switched with one targetting the Haynesville, or reassigned to the Haynesville from previously being marked as an "other"...meanwhile Louisiana's rig count remained unchanged as a Gulf rig was removed from the state's waters at the same time...elsewhere, the rig removals from the Cana Woodford account for the Oklahoma reductition, while the rig that was removed from the Williston basin came out of Montana, as the rig count in North Dakota remained unchanged...
DUC well report for October
Monday of this past week saw the release of the EIA's Drilling Productivity Report for November, which includes the EIA's October data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions....that report showed a decrease in uncompleted wells nationally for the 16th time in the past twenty months in October, as completions of drilled wells and drilling of new wells both remained subued....for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 86 wells, falling from 7,644 DUC wells in September to 7,558 DUC wells in October, which was also 7.3% fewer DUCs than the 8,156 wells that had been drilled but remained uncompleted as of the end of October of a year ago...this month's DUC decrease occurred as 316 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during October, up from the 294 wells that were drilled in September, while 402 wells were completed and brought into production by fracking, up from the 394 completions seen in September, but down by 69.2% from the 1,307 completions seen in October of last year....at the October completion rate, the 7,558 drilled but uncompleted wells left at the end of the month represents a 18.8 month backlog of wells that have been drilled but are not yet fracked, down from the 20.4 month DUC well backlog of a month ago, with the understanding that this normally indicative backlog ratio is being skewed by near record low completions...
both oil producing regions and natural gas producing regions saw DUC well decreases in October, with no basins reporting a DUC increase...the number of uncompleted wells remaining in Oklahoma's Anadarko decreased by 22, falling from 683 at the end of September to 661 DUC wells at the end of October, as just 13 wells were drilled into the Anadarko basin during October, while 35 Anadarko wells were being fracked....at the same time, DUCs in the Permian basin of west Texas and New Mexico decreased by 15, from 3,580 DUC wells at the end of September to 3,565 DUCs at the end of October, as 141 new wells were drilled into the Permian, while 156 wells in the region were completed...in addition, DUC wells in the Eagle Ford of south Texas decreased by 13, from 1,152 DUC wells at the end of September to 1,139 DUCs at the end of October, as 24 wells were drilled in the Eagle Ford during October, while 37 already drilled Eagle Ford wells were completed... there was also a decrease of 13 DUC wells in the Bakken of North Dakota, where DUC wells fell from 864 at the end of September to 851 DUCs at the end of October, as 19 wells were drilled into the Bakken in October, while 32 of the drilled wells in that basin were being fracked... meanwhile, the drilled but uncompleted well count in the Niobrara chalk of the Rockies' front range fell by 12 to 461, as 22 new Niobrara wells were drilled in October while 34 already drilled Niobrara wells were being fracked...
among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 10 wells, from 571 DUCs at the end of September to 561 DUCs at the end of October, as 61 wells were drilled into the Marcellus and Utica shales during the month, while 71 of the already drilled wells in the region were fracked....at the same time, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory decrease by 1 to 320, as 36 wells were drilled into the Haynesville during October, while 37 of the already drilled Haynesville wells were fracked during the same period....thus, for the month of October, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 75 wells to 6,677 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 11 wells to 881 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas...
++++++++++++++++++++++++++++++++++++
State investigating whether injection well waste affecting drinking water - The Columbus Dispatch - Brine, a waste byproduct produced in fracking, from an injection well in Washington County has migrated to gas-producing wells at least five miles away, the Ohio Department of Natural Resources reported Friday, and officials want to make sure it’s not getting into drinking water.While state officials said it’s unlikely, it’s possible the brine from the Class II Saltwater Injection Well, Redbird #4 in Dunham Township, could affect drinking water of those in the area. As of Friday, the state has not received any reports affecting human health or safety associated with any of the wells, officials said. Ohio Department of Natural Resources Director Mary Mertz said the state is in the process of hiring an expert to assess groundwater issues. If the groundwater does become contaminated, there would be no way to clean it, said Amy Townsend-Small, an associate professor of environmental science and geology at the University of Cincinnati who conducts research on fracking and its effects on groundwater. “That’s the biggest concern for people that live in shale gas producing areas,” she said. Abandoned wells could be source of the brine contaminating the water table, Townsend-Small said.“Abandoned wells are everywhere there. ... And the state does not even know where they all are. So it's a huge problem,” she said. Ohio has more than 200 injection wells that are full of ingredients that many companies don’t have to disclose citing trade secret protections. “The wastewater from that injection well, was apparently migrating to the surface through an idle or an orphan well. Otherwise they wouldn't have been able to find it,” Townsend-Small said. “Ostensibly, they were pumping the water up (in the conventional gas wells.) Orphan/idle wells aren't pumping, so it's not active. The wastewater is very pressurized because they're injecting such high volumes of it.” Much of the brine waste injected in Ohio’s injection wells comes not only from fracking sites in Ohio, but from other states, such as Pennsylvania. The issue was first reported late in 2019 when three owners of oil and gas production wells reported to ODNR an increase brine during the extraction process of 28 production oil and gas wells. When operations ceased in December 2019 when the issue was reported, a total of 4.2 million barrels of brine had been injected in the Ohio shale layer since the well originally came online in November 2018, according to the report by Resource Services International, a Colorado-based petroleum engineering firm hired by the state to conduct an assessment of the issue. The injection well has since been drilled deeper and began re-operating in June.
Utica Shale Stalwart Gulfport Energy Files for Bankruptcy - Gulfport Energy Corp. filed for Chapter 11 bankruptcy protection Friday, becoming the latest exploration and production (E&P) company this year to succumb to low commodity prices made worse by the Covid-19 pandemic. The company said it has the support of 95% of its revolving credit facility lenders and other creditors holding over two-thirds of its senior unsecured bonds for a restructuring plan that would wipe out $1.25 billion of debt. The company has shut in production, cut spending significantly and sold noncore assets in recent years to help reduce debt, but CEO David Wood, who took over in 2018 and reshaped the management team, said the company’s “large legacy debt burden” and its “legacy firm transportation commitments created a balance sheet and cost structure that was unsustainable in the current market environment.” The company has more than $2 billion of total debt on its books. Wood said management would focus on “rapidly” delevering once the company emerges from bankruptcy with a “much-improved cost structure driven by reduced legacy firm transport commitments and costs.” As part of the plan, Gulfport said it would issue $550 million of new senior unsecured notes to existing unsecured creditors. The company plans to continue operating as normal and has secured $262.5 million of debtor-in-possession financing to help fund its business. The company has also landed a commitment from existing lenders to provide $580 million in financing when it emerges from bankruptcy. Gulfport revealed in a regulatory filing last month that it was in discussions with its lenders about filing bankruptcy. The company also received a delisting notice from Nasdaq in September. A major player in Ohio’s Utica Shale, where it holds more than 200,000 net acres and produces about 1 Bcfe/d of oil and gas, the company spent $1.85 billion on a deal that closed in 2017 to enter the South Central Oklahoma Oil Province, aka the SCOOP. It ultimately planned to focus more time and money on the play for its liquids-rich volumes, but the transition never really occurred as operators have had difficulties developing the assets. In the second quarter, the SCOOP accounted for only 300 MMcfe/d of the company’s 1.03 Bcfe/d total. The natural gas-rich Utica Shale accounted for the rest.
Complaints aired on Mariner East Pipeline - An East Wheatfield Township property owner said Tuesday that the Mariner East pipeline that was built through his property just north of Seward has caused some major problems. “We have had nothing but grief from Sunoco and its subcontractors,” Patrick Robinson said in a summary during a 90-minute “Virtual People’s Hearing” Monday night, giving residents from across the state the opportunity to share their stories of the impact from the Mariner East pipeline project. It is a $2.5 billion project that was built across 17 counties beginning in 2014, as an expansion of the original Mariner East project linking Marcellus and Utica shale natural gas extraction sites in western Pennsylvania with a Sunoco’s processing and distribution center in Marcus Hook, Delaware County. In Indiana County the project comes through Burrell, West Wheatfield and East Wheatfield townships. “We lived in this house for 17 years and always had a lot of good drinking water,” Robinson told the forum, which was being recorded by organizers to present to Gov. Tom Wolf and other state officials. “We lost most of our drinking water within a day of them digging the pipeline across the hollow.” The forum was hosted by the HaltMarinerNow Coalition, an alliance of groups aiming to educate the public and increase pressure on Wolf and the Public Utility Commission to halt the pipeline project. Robinson said there have been landslides on his property, and a holding pond built in the middle of his property “now actually floods the rest of my commercial property.” He focused on how the pipeline crew treated his drinking well and his property, recalling crews doing “everything from them urinating and defecating on the road in front of my house to threatening me with bodily harm out on the street, in the local towns and on the property.” Robinson said the well never did recover pre-construction quality or quantity, showing pictures of blackened water he said came from his faucets. He also said the water drawn from that well “tears up the pump.”
Bill heading to governor would relax environmental laws for conventional drillers -A bill to relax laws governing conventional oil and gas drillers is heading to the governor’s desk.Lawmakers passed the legislation this week, after it sat in the Senate for months. Conventional operators drill vertical wells that are shallower compared to unconventional operators, which use horizontal drilling and hydraulic fracturing to reach deeper deposits of oil and natural gas in rock formations like Pennsylvania’s Marcellus shale.The bill, sponsored by Senate President Pro Tempore Joe Scarnati (R-Jefferson), would set less rigorous environmental standards for conventional drillers than the ones for unconventional operators.Conventional drillers are generally smaller companies than unconventional drillers. In a 2016 bipartisan compromise, lawmakers and the Wolf Administration agreed the industries should be treated differently.This bill is an attempt to fulfill that agreement.But Gov. Tom Wolf’s office has previously said he would veto the bill, as it “poses an undeniable risk to the health and safety of our citizens, the environment, and our public resources.”The bill passed the House in May 109-93. It was amended in January to lower the reporting requirement for spills from five to two barrels of oil and from 15 to five barrels of brine, or wastewater. Spills under those amounts would not need to be reported to the state unless they endanger people downstream or could result in pollution or property damage.The amendment also removed a section that would have allowed drillers to use wastewater to suppress dust on roads.A 2018 Penn State study found that drilling wastewaters have salt, radioactivity, and other contaminant concentrations often many times above drinking water standards. It also found metals from the wastewater leach from roads when it rains, likely reaching ground and surface water. Republican lawmakers said the amendment was offered as a compromise to Democrats, to gain support for the bill and help conventional drillers.
NETL commits to prioritizing natural gas utilization in Appalachian region - National Energy Technology Laboratory (NETL) said it is committed to prioritizing natural gas utilization, leveraging its capabilities and expertise to identify more uses for natural gas and bring valuable products to market faster, cheaper, and with less environmental impact. Shale gas is used for heating and power production, while natural gas is heavily used as a feedstock to manufacture valuable chemicals within the chemical industry. “We strive to bring national focus and coordination to technology development associated with the conversion of natural gas to high-value commodities, ultimately strengthening our national economy and national security,” NETL Director Brian J. Anderson said on Monday. NETL is specifically focused on natural gas producers across Appalachia that are continuing to utilize the vast shale gas resources in the region. Prioritizing natural gas utilization is an important regional and national effort for NETL as it continues to work on developing solutions for U.S. energy challenges. “There are thousands petrochemical facilities across 13 key industry sectors within 300 miles of Pittsburgh that manufacture adhesives, paints, plastics and many other important products,” Anderson said. “Successfully developing our own regional natural gas processing and refining capabilities will enable a surge of new companies and jobs and enrich development of the workforce, particularly in economically depressed areas. Over the next decade, we are going to work hard to realize this goal through creating a Natural Gas Utilization Center of Excellence.” NETL has invested hundreds of millions of dollars in facilities, equipment and expertise necessary to develop technologies that would be too risky or far-term for private-sector investment alone, helping to bridge the gap between initial discoveries and full-scale commercialization in which funding or support often falls through.
Court Issues Emergency Order Blocking Mountain Valley Pipeline From Stream, Wetland Construction | WVPB --A federal appeals court has temporarily blocked developers of the Mountain Valley Pipeline from doing construction across streams and wetlands in southern West Virginia and Virginia.The emergency administrative stay was issued Friday by the U.S. Court of Appeals for the Fourth Circuit.Environmental groups led by the Sierra Club appealed to the court to stop river and stream crossings after the U.S. Army Corps of Engineers on Sept. 25 reissued the project’s permit that allows the 303-mile natural gas pipeline to cross nearly 1,000 waterways in the two states. The original approvals were tossed by a federal appeals court in 2018.Environmental groups asked the Corps to reconsider. When the agency upheld its permits, advocates filed a lawsuit with the Fourth Circuit asking the court to review. The emergency order will remain in place until the court considers the full motion to stay.Environmental groups, in briefs, cited an Aug. 4 earnings call during which pipeline developer Equitrans told its shareholders it would rush to complete stream crossings before the court could stop it.In its response, Mountain Valley Pipeline opposed the stay. Developers said it ultimately expected cases from the environmental groups to fail and said it reached out to the Sierra Club in an effort to discuss the river crossings of most concern.Mountain Valley Pipeline had previously agreed not to undertake any waterbody construction through Oct. 17.The Friday ruling by the court puts stream construction projects on hold. However, an Oct. 9 order by the Federal Energy Regulatory Commission partially lifted a stop-work order for the multi-billion dollar project on all but 25 miles of national forest land. The agency also extended the project’s for two years. Despite the court order, construction along the route may resume in other areas.
Tree sitters continue to block pipeline right-of-way, despite injunction ordering them to leave - (WDBJ) - Tree sitters continued to block the path of the Mountain Valley Pipeline In Montgomery County Monday, despite an injunction ordering them to leave. High above the hillside, three platforms swayed in the wind. Visitors could see at least one of them was occupied. On the ground, a makeshift barricade blocked the path to the tree sitters. And legal observers from the National Lawyers Guild watched for any activity. “We are here as a third party witness,” said one of the observers, “objectively working under an attorney just to document and observe how things go.” At the same time a group of pipeline opponents gathered along US 460 in a show of solidarity with the tree sitters. “The longer the sits hold out, and preserve that slope,” Amy Nelson told WDBJ7, “you know every day is a blessing as far as I’m concerned.” “I don’t agree with the judge’s ruling,” said another opponent identified as Molly, “but I’m out here to support the people who are still putting their lives on the line.” A spokesperson for the Mountain Valley Pipeline said safety is a primary concern, with a few opponents creating what she described as unnecessary risks for law enforcement, security personnel, project workers and opponents themselves. “We expect opponents to adhere to the law and vacate their positions along the right-of-way,” Natalie Cox wrote. By late afternoon, some equipment had arrived, and representatives of MVP and the sheriff’s office had reportedly made at least one pass through the area, but there was no effort to remove the tree sitters. So for now, the tree sitters, other pipeline opponents and the legal observers are playing a waiting game on Yellow Finch Lane.
Judge finds pipeline protesters in contempt for refusing to leave tree-sits— Two unidentified activists blocking construction of a natural gas pipeline from high in a white pine and a chestnut oak were found in contempt of court Thursday.Montgomery County Circuit Judge Robert Turk imposed a fine of $500 a day against each tree-sitter for as long as they remain on the tarp-covered wooden platforms that went up more than two years ago.Officials with the Mountain Valley Pipeline hope the tree-sitters will come down voluntarily to avoid the penalty.“Because these fines are prospective, Tree-sitter 1 and Tree-sitter 2 may avoid any liability for the fines by immediately vacating the MVP easements,” an order entered by Turk stated.Last week, Turk issued a temporary injunction ordering three tree-sitters to leave their stands, which are about 50 feet off the ground on a steep wooded slope near Elliston. The tree-sits have prevented Mountain Valley from cutting trees for a small segment of its 303-mile pipeline.One of the tree stands is currently unoccupied, according to testimony Thursday during a court hearing that was not attended by the tree-sitters or anyone associated with them.Turk noted that under the injunction, the protesters remain subject to removal by sheriff’s deputies. The order does not say when, or if, that may happen. “It was our hope that the tree-sitters would choose to leave on their own to avoid unnecessary confrontations,” Montgomery County Sheriff Hank Partin said in a statement released after the hearing. “However, we will ensure the court order is enforced in due time.”Partin said the office is making plans “to ensure we have all the necessary resources available, so the situation can be resolved quickly and in a safe manner for all the parties involved.” In the past, authorities have used a mechanized lift to reach and remove protesters who chained themselves to excavators and other high perches in the pipeline’s right of way. That could be complicated by the steep terrain on which the tree-sits are located off Yellow Finch Lane. After Turk issued his order Thursday, it was read aloud by sheriff’s deputies who stood at the base of the two occupied trees. A short time later, there had been no response from above. The protesters are not likely to surrender, one of them indicated in a message posted to the Facebook page of Appalachians Against Pipelines, a group that has chronicled the tree-sits since they went up Sept. 5, 2018.
US court allows Equitrans to keep building Mountain Valley natgas pipe (Reuters) - The U.S. Fourth Circuit Court of Appeals rejected a motion to stay a permit for the $5.8-$6.0 billion Mountain Valley natural gas pipeline from West Virginia to Virginia. Analysts said that court decision on Wednesday - not to stay the pipeline's Biological Opinion - increases the odds Equitrans Midstream Corp can put the long-delayed project into service in the second half of 2021. The Biological Opinion from the U.S. Fish and Wildlife Service allows construction in areas inhabited by endangered and threatened species. Mountain Valley is one of several oil and gas pipelines delayed by regulatory and legal fights with environmental andlocal groups that found problems with permits issued bythe Trump administration. When Equitrans started construction in February 2018, it estimated Mountain Valley would cost about $3.5 billion and be completed by the end of 2018. The 303-mile (487.6 km) pipeline was designed to deliver 2 billion cubic feet per day of gas from the Marcellus and Utica shale in Pennsylvania, Ohio and West Virginia to consumers in the Mid Atlantic and Southeast. One billion cubic feet is enough to supply about 5 million U.S. homes for a day Analysts said denial of the stay allows Equitrans to continue construction in areas other than the 25-mile (40-km)exclusion zone surrounding the Jefferson National Forest while the court considers the merits of appeals against the Biological Opinion. Analysts at Height Capital Markets said the U.S. Federal Energy Regulatory Commission may decide soon to reduce that exclusion zone to 7.7 miles. Height Capital Markets also said Mountain Valley must begin applying for an individual stream crossing permit in case it loses an ongoing lawsuit against its Nationwide Permit or President-elect Joe Biden's administration remands the permit, both of which seem probable. The Nationwide Permit from the U.S. Army Corps of Engineers allows the project to cross waterbodies. "We continue to have high conviction that the project will be completed, though the Biden administration could delay the ultimate in-service date to 2022,"
US natural gas futures fall on milder weather - - US natural gas futures dropped 10% to a near one-month low on Monday on forecasts for milder weather resulting in lower heating demand and a steady rise in output. Front-month gas futures fell 29.8 cents, or 9.9%, to settle at $2.697 per million British thermal units. The contract touched its lowest since Oct. 19 at $2.682 earlier in the session. “Natural gas futures are lower this morning as supply held steady over the weekend and weather model outlook is showing a forecast that is warmer-than-normal over the next two to three weeks,” said Robert DiDona of Energy Ventures Analysis. “This warmer weather outlook has negatively impacted weather-related demand which will loosen the end of season storage forecast,” DiDona added. Data provider Refinitiv estimated 259 heating degree days (HDDs) over the next two weeks in the Lower 48 US states, well below the 30-year average of 318. HDDs measure the number of degrees a day’s average temperature is below 65 degrees Fahrenheit (18 Celsius) and are used to estimate demand to heat homes and businesses. Refinitiv predicted demand, including exports, would rise to an average of 104.8 billion cubic feet per day (bcfd) this week from 98.1 bcfd in the prior week. Gas production in the Lower 48 averaged 89.4 billion cubic feet per day (bcfd) so far in November, up from a five-month low of 87.4 bcfd in October. That, however, was still well below the all-time monthly high of 95.4 bcfd in November 2019. “Adding to bearish pressures has been a lift in production of late that has been combining with a quicker-than-expected rebound in the rig counts to exert additional psychological bearish price pressure,” advisory firm Ritterbusch and Associates said in a note. The amount of gas flowing to US LNG export plants has averaged 10.1 bcfd so far in November, up from a five-month high of 7.7 bcfd in October. That puts exports on track to rise for a fourth month in a row as rising global gas prices prompt buyers to purchase more US gas.
Momentum Eludes December Natural Gas Futures as Production Rises, Domestic Demand Tapers - Natural gas futures on Tuesday traded sideways as markets weighed modest weather-driven demand and rising production against continued strength in exports. The December Nymex contract flipped between slight gains and losses throughout much of Tuesday’s session and ultimately settled at $2.692/MMBtu, down a half-cent day/day. January fell 2.0 cents to $2.844. A day earlier, the prompt month dropped nearly 30 cents, wiping out gains made the previous week. Amid mild fall temperatures, NGI’s Spot Gas National Avg. declined 8.5 cents to $2.545. Liquefied natural gas (LNG) volumes have hovered near or above 10 Bcf in November – around record levels – and have kept supply/demand balances tight. Still, production this week has ticked up to a recent high at the same time that the weather is expected to prove unseasonably warm into early December. “Production is hovering around the 90 Bcf/d mark for the first time since the end of April,” Genscape Inc. analyst Joe Bernardi said Tuesday. He noted that associated gas production dropped last spring as the pandemic took hold and oil prices plunged, bringing total Lower 48 gas output below the 90 Bcf/d threshold at the time. “It hasn’t yet returned above that 90 Bcf/d level, but the recent five-day average (subject as always to revisions) is hovering at 89.6 Bcf/d,” the analyst said. “Northeast production has rebounded significantly over the last several weeks, fueling the gains.” Forecasts are calling for little near-term help from weather on the demand side, with mild temperatures throughout the southern half of the country and chilly but above-average conditions in many areas of the northern United States over the next three weeks. “The overall pattern still looks very hostile toward any cold and continues to point toward warm to very warm risks as we move into the early part of December,” Bespoke Weather Services said. Increased storage levels are also weighing on prices. The U.S. Energy Information Administration (EIA) last week reported an 8 Bcf injection into storage for the week ending Nov. 6. The increase boosted inventories to 3,927 Bcf, ahead of the five-year average of 3,751 Bcf. Preliminary forecasts point to another increase for the week ended Nov. 13.
US working natural gas volumes in underground storage increase by 31 Bcf: EIA | S&P Global Platts — US natural gas stocks posted a sizable injection last week at a time when the Lower 48 traditionally switches to net draws, while the remaining NYMEX Henry Hub winter strip tumbled 18 cents following the report. Storage inventories increased by 31 Bcf to 3.958 Tcf for the week ended Nov. 13, the US Energy Information Administration reported the morning of Nov. 19. The injection proved much more than an S&P Global Platts' survey of analysts calling for a 22 Bcf build. Responses to the survey ranged for an addition of 11 Bcf to 30 Bcf. The build was very bearish compared to the 66 Bcf draw reported during the same week last year as well as the five-year average withdrawal of 24 Bcf, according to EIA data. It also marked the second-consecutive week the EIA number surpassed market expectations. US supply and demand balances were considerably looser, featuring demand losses of 4.0 Bcf/d week over week, according to S&P Global Platts Analytics. Weaker consumption was the result of very mild temperatures driving residential and commercial space heating down by 4.7 Bcf/d. The soft demand resulted in some temporary production curtailments in the Northeast, as cash prices traded below $1.00/MMBtu. Storage volumes now stand 293 Bcf, or 8%, more than the year-ago level of 3.665 Tcf and 231 Bcf, or 6.2%, more than the five-year average of 3.727 Tcf. The injection season has now extended one week further than usual. The NYMEX Henry Hub December contract tumbled 14 cents to $2.574/MMBtu in trading following the release of the weekly storage report at 10:30 am ET. The remaining winter strip, January through March, lost 14 cents to average $2.67/MMBtu, a decline of more than 40 cents from one week prior. Natural gas prices saw immense selling pressure this week, with winter 2020-21 prices off more than 30% relative to its year-to-date high established late last month. The sizeable declines have been driven by very mild realized and expected temperatures, with weather models forecasting mild temperatures to persist into December, according to Platts Analytics. Further stoking bearish sentiment is production, which in recent days has eclipsed 90 Bcf/d for the first time since the spring. Higher output is largely the result of Northeast and Haynesville producers ramping up production ahead of the winter. Platts Analytics' supply and demand model currently forecasts a 27 Bcf withdrawal for the week-ending Nov. 20, which would grow the surplus versus the five-year average by 10 Bcf as the heating season kicks off one week later than normal. Cooler, but still milder-than-normal temperatures, has boosted residential and commercial demand by 9.7 Bcf/d week over week.
Natural Gas Bull Case Starts to Unravel on Demand-Killing Warmth - Winter hasn’t begun yet, but the bullish trade in U.S. natural gas is already starting to fall apart. Gas futures tumbled Thursday as U.S. forecasts shifted warmer through early December, leaving bullish traders flat-footed after the previous day’s modest gain stoked speculation that the recent rout had run out of steam. Government data showed an unusually big gain in stockpiles for this time of year, adding to a glut of the fuel in underground storage. Traders had been betting big on higher gas prices this winter, with hedge funds’ bullish wagers climbing to the highest in more than six years last month. Shale producers have curbed output on lower oil prices, while gas exports to Mexico and overseas buyers soared to a record. But with frigid weather failing to show up in the forecasts, cracks are emerging in the bullish thesis. One sign of growing bearishness is the March-April gas spread, known as the widowmaker for its volatility. The premium for March prices versus April has narrowed to a record low for the 2021 contracts, suggesting that traders are increasingly skeptical about the prospect of tight supplies this winter. Traders were caught in a “bull trap” overnight, with futures rising in the very early hours of the U.S. trading day before plunging as the milder forecasts emerged, said John Kilduff, founding partner at Again Capital, a New York-based hedge fund. “We really needed the weather,” Kilduff said. “All the other supporting elements were there: LNG, exports to Mexico. The kindling was all there. But the weather was the missing element.” But with winter still ahead, it’s too early for bulls to throw in the towel completely. Record exports and muted production are leaving prices primed to rocket higher at the first sign of extreme cold. “The market remains under-supplied and higher prices will be a concern when weather takes a more bullish turn,”
LNG Demand Not Enough to Stop Natural Gas Forward Price ‘Meltdown’ - A balmy weather outlook that was seen potentially extending through the first third of December weighed heavily on natural gas market sentiment during the Nov. 12-18 period, sending forward prices crashing down by an average of 36.0 cents, according to NGI’s Forward Look. Similar to the prior week, the steepest losses occurred in Appalachia. However, this time, the declines extended farther downstream into the Northeast, where warm conditions were on track to expand late this week. Transco Zone 6 non-NY December prices dropped 50.0 cents from Nov. 12-18 to reach $2.358, while the balance of winter (December-March) fell 42.0 cents to $3.210, Forward Look data show. Prices for next summer (April-March) slid 17.0 cents to $2.180, and the winter 2021-2022 strip slipped 14.0 cents to $3.770. Farther upstream, Dominion South December was down 61.0 cents to $1.415, the balance of winter was down 42.0 cents to $1.890, next summer was down 17.0 cents to $2.020 and winter 2021-2022 was down 22.0 cents to $2.080. The deep nosedive in forward markets occurred on the heels of a similarly sharp decline along the Nymex gas futures curve. Benchmark Henry Hub December futures plunged 27.0 cents to $2.712, and the balance of winter tumbled 24 cents to $2.784. Unlike last week when the biggest action was limited to the winter months, this week’s double-digit decreases spilled over into next summer and the winter of 2021-2022 as well. The recent losses are attributable to warmer-than-normal weather forecast shifts and a collapsing winter contract risk premium, according to EBW Analytics Group. Technical trades further helped drive the extent of losses early this week, which far outpaced the rate of fundamental weakening. The weakness along the Nymex curve and across forward markets comes despite steadily strong export demand. NGI data showed feed gas deliveries to U.S. liquefied natural gas (LNG) terminals climbing to 10.68 Bcf last Friday (Nov. 13) and Saturday but then falling below 10 Bcf on Sunday and Monday after some equipment issues at the Freeport LNG terminal. Feed gas flows quickly recovered, though, and by Thursday were back at 10.26 Bcf.
US natgas futures rise over 2pc on cooler forecasts in early December -US natural gas futures rose over 2% on Friday, buoyed by record-high liquefied natural gas (LNG) exports and forecasts for cooler weather and higher heating demand in early December. The price increase came despite a mostly steady rise in output this month. Front-month gas futures rose 5.8 cents, or 2.2%, to settle at $2.650 per million British thermal units. On Thursday, the contract marked its lowest close since Oct. 6. For the week, the front-month was down about 11% after rising almost 4% last week. Data provider Refinitiv said output in the Lower 48 US states averaged 89.8 billion cubic feet per day (bcfd) so far in November, up from a five-month low of 87.4 bcfd in October. That, however, was still well below the all-time monthly high of 95.4 bcfd in November 2019. Traders said some of that output increase was due to higher oil prices. Oil futures have risen about 17% so far this month on expectations of a rebound in global energy demand and economic activity as promising coronavirus vaccines are being developed. Higher oil prices over the last few months have encouraged energy firms to drill for more crude. Those oil wells also produce a lot of associated gas. Refinitiv projected demand, including exports, would drop from 103.3 bcfd this week to 99.5 bcfd next week as the weather turns unseasonably warm before jumping to 109.6 bcfd in two weeks with a drop in temperatures. The amount of gas flowing to US LNG export plants has averaged 10.0 bcfd so far in November, up from a five-month high of 7.7 bcfd in October, as rising prices in Europe and Asia in recent months have prompted global buyers to purchase more US gas.
Two Professors Faced Years of Harassment for Defying the Fossil Fuel Industry. Now, They Are Reframing the Discussion Around Fracking | The Cornell Daily Sun - “I do rule out banning fracking, because the answer we need, we need other industries to transition to, ultimately, a completely zero emissions by 2025,” said President-elect Joe Biden in the final presidential debate. President Donald Trump stated that he would protect fracking in the interest of maintaining low prices for energy and preserving American jobs. A failing that underscored both sides of the debate on fracking is a fundamental misunderstanding of what fracking is and the role it plays in the fossil fuel industry, according to Prof. Anthony Ingraffea, civil and environmental engineering. “Why are we talking about fracking in 2020? Clearly, there’s something wrong here,” Ingraffea said. “Something doesn’t jive, and what’s wrong is that there is profoundly universal misuse of the word fracking.”“The problem is in the early 2000s, the oil and gas industry discovered an entirely new way of getting a huge oil and gas resource to market,” Ingraffea said. Conventional natural gas reserves contain methane that naturally broke free from shale over the course of millions of years, but the practice of extracting natural gas directly from shale was not commercially available until 15 years ago, according to Prof. Robert Howarth, ecology and evolutionary biology. Tapping into these reserves opened up a Pandora’s box of effects on local communities, contaminating local water sources and releasing emissions that contribute to poorer air quality and worsening the greenhouse effect. On top of the direct environmental effects of this unconventional drilling, the expansion of obtainable oil and gas kept the price of fossil fuels low, making them more economically desirable than renewable alternatives like wind and solar, and subsequently extending the lifetime of the fossil fuel industry while stalling the transition to renewable energy sources. “[Unconventional drilling] suppressed, or pushed down, what we should have been elevating — which is capital investment and renewable energy,” Ingraffea said. “The oil and gas industry was saying, ‘Look, we just elongated the fossil fuel industry by 30 years, we made the United States energy dominant’ … The market response to that is, ‘Well, then we don’t need wind and solar and hydro, because there’s this cheaper alternative called shale gas.’” Throughout the past 40 years, fossil fuel companies have used their monetary and political sway to postpone the transition to other sources of energy — spreading misinformation on oil and gas emissions’ connection to climate change and lobbying for subsidies. Ingraffea and Howarth are no strangers to this political and economic arm of the fossil fuel industry.
Environmental groups fight Eastern Shore natural gas pipeline project ahead of key vote - As a natural gas pipeline proposed for Maryland’s Eastern Shore continues to move through the state’s regulatory approval process, environmental activists vowed to continue their fight to stop a line they say would encourage more fracking and harm communities. The energy company Chesapeake Utilities Co. wants to extend a natural gas pipeline from Delaware through Wicomico County and into Somerset County. Advertisement The $34 million project would add seven miles on new gas pipeline in those counties. The project received a key approval last week when the state Department of the Environment signed off on its tidal wetlands licenses. The licenses could go before the Board of Public Works as early as next month — either together or separately. After the board rules on the tidal wetlands licenses, MDE will issue its review of the non-wetlands related pieces of the project, said MDE spokesman Mark Shaffer. Proponents say the pipeline would bring much-needed natural gas to key institutions in Somerset, namely the University of Maryland Eastern Shore and the Eastern Correctional Institution, and attract more businesses to the area. But environmentalists argue the state is ignoring its commitment to renewable energy and brushing aside the pipeline’s potential impact on the low-income communities it would pass through. They’re urging Gov. Larry Hogan, Comptroller Peter Franchot and Treasurer Nancy Kopp to vote against the pipeline, which could open the door for the state to consider other, greener ways of meeting the area’s energy needs.
Oil spill cleanup operations suspended along Del., Md. beaches -- – The Unified Command, comprised of the U.S. Coast Guard and Delaware Department of Natural Resources and Environmental Control suspended operations along the shores of Delaware on Friday. We’re told cleanup crews are prepared to respond to any further oiling, and shoreline monitoring will still take place. The month-long, multi-agency response to oil patties began on October 19th, after reports of oil patties impacting the Delaware Shoreline from Fowler Beach, downward along the Delaware Bay coast to the state’s Atlantic Ocean beaches from Cape Henlopen to Fenwick Island and to Assateague State Park in Maryland. Officials say 85 tons of oily sand and debris were removed over the course of three weeks. The origin of the spill remains unknown, but it is still under active investigation by the U.S. Coast Guard and the Marine Safety Lab in New London, Connecticut. The public is asked to report any sizeable sightings of oil, oily debris, or oiled wildlife to DNREC at 800-662-8802.
Virginia Natural Gas infrastructure expansion to be scaled back amid plant financing troubles - Plans for one of two controversial new natural gas plants planned to be built in Charles City County appear to be faltering, according to a letter sent by Virginia Natural Gas to state regulators Friday. In the filing by McGuireWoods attorney Lisa Crabtree, Virginia Natural Gas informed the State Corporation Commission that it would not meet three criteria set by regulators as a condition for their approval of a gas infrastructure expansion by the mandated Dec. 31 deadline. All three conditions are related to plans for the development of a 1,060 megawatt combined-cycle natural gas plant in Charles City. The project, known as C4GT, is being developed by Michigan-based Novi Energy to sell power into the regional grid. A second natural gas plant, Chickahominy Power Station, is also being planned by another independent developer, Balico, LLC, a mile away from the C4GT site. While the commission closely vets plans for new generating facilities built by electric utilities — which are paid for by everyone in the utility’s territory — they give less scrutiny to projects developed by independent power producers like NOVI Energy and Balico, where financial risks are borne by project backers instead of ratepayers. In such cases, regulators focus primarily on whether the facility will have any “adverse effect” on electric reliability or be “otherwise contrary to the public interest.” These non-utility developers are “not required to establish that the Facility is required by the public convenience and necessity as a condition of approval,” as State Corporation Commission Hearing Examiner Ann Berkebile wrote in a report on C4GT in 2017. But while the company had little trouble getting approval from the State Corporation Commission for construction, securing a natural gas supply has proved a struggle. C4GT has sought to obtain its supply from Virginia Natural Gas, which proposed a $345 million suite of new pipeline sections, a new compressor station and other upgrades called the Header Improvement Project. As a publicly regulated utility with captive ratepayers, though, Virginia Natural Gas has to meet a higher bar in justifying why its customers should pay for projects. And despite assertions that the Header Improvement Project is needed to improve reliability as well as to provide gas to two other companies, Columbia Gas of Virginia and Dominion Energy subsidiary Virginia Power Services Energy, regulators have expressed skepticism. “The Project is not needed without C4GT,” the State Corporation Commission wrote on June 26 in a ruling that made its approval of the Header Improvement Project contingent on C4GT proving its financial viability. “Put simply,” the commissioners wrote later in their order, “if C4GT is built, we find that the Project is needed. If C4GT is not built, the project is not needed.”
To Protect the Great Lakes, Michigan Governor Moves to Shut Down Pipeline - Environmental and Indigenous activists celebrated Friday after Democratic Michigan Gov. Gretchen Whitmer took action to shut down the decades-old Enbridge Line 5 oil and natural gas pipelines that run under the Straits of Mackinac, narrow waterways that connect Lake Huron and Lake Michigan—two of the Great Lakes. Citing the threat to the Great Lakes as well as “persistent and incurable violations” by Enbridge, Whitmer and Michigan Department of Natural Resources (DNR) Director Dan Eichinger informed the Canadian fossil fuel giant that a 1953 easement allowing it to operate the pipelines is being revoked and terminated. The move, which Michigan Attorney General Dana Nessel asked the Ingham County Circuit Court to validate, gives Enbridge until May 2021 to stop operating the twin pipelines, “allowing for an orderly transition that protects Michigan’s energy needs over the coming months,”according to a statement from the governor’s office. The Great Lakes collectively contain about a fifth of the world’s surface fresh water. As Whitmer explained Friday, “Here in Michigan, the Great Lakes define our borders, but they also define who we are as people.” “Enbridge has routinely refused to take action to protect our Great Lakes and the millions of Americans who depend on them for clean drinking water and good jobs,” the governor said. “They have repeatedly violated the terms of the 1953 easement by ignoring structural problems that put our Great Lakes and our families at risk.” “Most importantly, Enbridge has imposed on the people of Michigan an unacceptable risk of a catastrophic oil spill in the Great Lakes that could devastate our economy and way of life,” she added. “That’s why we’re taking action now, and why I will continue to hold accountable anyone who threatens our Great Lakes and fresh water.” MLive noted that the state attorney general’s new filing “is in addition toNessel’s lawsuit filed in 2019 seeking the shutdown of Line 5, which remains pending in the same court.” Nessel said Friday that Whitmer and Eichinger “are making another clear statement that Line 5 poses a great risk to our state, and it must be removed from our public waterways.”
Michigan Governor Moves to Prevent Great Lakes Oil Spill by Shutting Down Aging Pipeline -- Enbridge's aging Line 5 pipeline may finally be forced into retirement. Michigan Gov. Gretchen Whitmer and Michigan Department of Natural Resources Director Dan Eichinger informed Enbridge Friday that they were revoking the Canadian company's easement to run twin pipelinesunder the Straits of Mackinac, which divide Lakes Michigan and Huron, the Detroit Free Press reported. "Here in Michigan, the Great Lakes define our borders, but they also define who we are as people," Whitmer said in a statement reported by the Detroit Free Press. "Enbridge has routinely refused to take action to protect our Great Lakes and the millions of Americans who depend on them for clean drinking water and good jobs." The Line 5 pipeline has carried fossil fuels beneath the Straits since 1953, when it was granted an easement to do so by the state of Michigan. It currently carries 23 million gallons of oil and gas each day through Michigan's Upper Peninsula, splits in two to transport it beneath the lakes and then carries it in another single pipeline through the Lower Peninsula into Ontario. Whitmer argued that Enbridge had violated the terms of the easement by ignoring structural problems that increased the risk of a devastating oil spill in the Lakes. For example, Enbridge was aware that a section of the underwater coating on the twin pipelines was damaged in 2014 but did not inform the state for three years. Whitmer is giving the company until May of 2021 to cease operations in the Straits. At the same time, Michigan Attorney General Dana Nessel filed a complaint in Ingham County Circuit Court asking the judge to uphold the governor's action, Michigan Live reported. Whitmer contends that the pipelines violate the "public trust" doctrine, which entrusts Michigan with protecting the bottom of the Great Lakes for its residents. "Transporting millions of gallons of petroleum products each day through two 67-year old pipelines that lie exposed in the Straits below uniquely vulnerable and busy shipping lanes presents an extraordinary, unreasonable threat to public rights because of the very real risk of further anchor strikes and other external impacts to the Pipelines, the inherent risks of pipeline operations, and the foreseeable, catastrophic effects if an oil spill occurs at the Straits," the notice she sent to the company read. Enbridge, however, countered that the pipelines remained safe. Alberta Premier Jason Kenney also opposed the move. "The impact of this would be devastating," Kenney said, as Global News reported. "It is the single largest supply of gasoline ultimately in southern Ontario, for aviation fuel out of the Detroit airport, for heating fuel in northern Michigan, for the refineries in northern Ohio that fuel much of the midwest U.S. economy, so this is a very very big deal." However, environmental groups, who have long raised alarms about the pipeline, praised Whitmer's decision. "Line 5 should have never been built in the first place," Mike Shriberg, regional executive director of theNational Wildlife Federation's Great Lakes Regional Center, told the Detroit Free Press. "Gov. Whitmer is now bravely, and correctly, standing up for the Great Lakes. This is a legacy-defining action by the governor. She is standing on the side not only of clean water, but clean energy and the jobs that go along with the transition to a renewable energy economy."
Time Runs Out for a U.S.-Canada Oil Pipeline - The New York Times - Gov. Gretchen Whitmer of Michigan said the state would shut down a line between her state and Ontario that has been operating since the 1950s. In an unusual move, Gov. Gretchen Whitmer of Michigan, citing environmental concerns, is shutting down an underwater pipeline that carries oil to refineries in her state and Canada. Pipeline operations normally fall under federal jurisdiction. Governor Whitmer, a Democrat, is acting under the state’s public trust doctrine, which requires state authorities to protect the Great Lakes. The pipeline in question, known as Line 5, has been in operation since the 1950s. The decision, announced on Friday, requires the pipeline operator Enbridge to cease operations on a specific section of Line 5 by May 2021, but it will have the effect of curtailing the entire pipeline, which runs between Superior, Wis., and Sarnia, Ontario. “Enbridge has routinely refused to take action to protect our Great Lakes and the millions of Americans who depend on them for clean drinking water and good jobs,” Governor Whitmer said in a statement. Under the terms of an agreement with the state, Enbridge is required to maintain a multilayered coating on the pipeline to protect it from corrosion and to ensure that the pipeline has physical supports that are no more than 75 feet apart. The Michigan authorities found that the company had violated those terms and also failed to adequately protect the pipeline from damage from boat anchors. While the line moves a relatively small quantity of oil — about 540,000 barrels of light crude oil and liquid natural gas each day, compared with national average consumption of 20 million barrels of crude oil per day — environmentalists applauded the move. While it was not clear that the legal strategy could easily be applied to other pipelines, they also said it was significant in that it focused on an older pipeline rather than a new project. “I think this Line 5 decision is going to spark some interest in existing pipelines,” said Jared Margolis, a senior attorney with the Center for Biological Diversity. “I think, at some point, we do need to turn to pipelines that are in the ground that are dangerous, that are posing a serious risk.” Governor Whitmer’s action will revoke the 1953 easement that allows Enbridge to operate pipelines through the Straits of Mackinac, a narrow waterway that connects Lake Michigan and Lake Huron. A spokesman for Enbridge said the decision could have “devastating” economic consequences. “Enbridge remains confident that Line 5 continues to operate safely and that there is no credible basis for terminating the 1953 easement allowing the Dual Line 5 Pipelines to cross the Straits of Mackinac,” the spokesman, Michael Barnes, said. “Line 5 is an essential source of energy for not only Michigan but for the entire region including Wisconsin, Indiana, Ohio, Pennsylvania, Ontario, and Quebec.”
Canadian officials oppose Whitmer plan to shut down Line 5 in Straits - Gov. Gretchen Whitmer's announcement Friday that she will revoke the 1953 easement allowing the controversial Line 5 twin oil and gas pipelines to continue operation on the Straits of Mackinac lake bottom isn't winning her fans among Canadian officials.The premier of the oil-rich Canadian province of Alberta, and an Ontario oil minister, both panned Whitmer's shutdown plan for what they consider a vital lifeline for one of Canada's most important commodities."The impact of this would be devastating," Alberta Premier Jason Kenney told "The Roy Green Show," a nationally syndicated news radio show and podcast based in Montreal. The 67-year-old Line 5, operated by Calgary-based oil transportation giant Enbridge, moves oil that primarily originates in the Alberta oil fields of western Canada. Some 23 million gallons of oil and natural gas liquids per day are transported by Line 5 east through the Upper Peninsula, splitting into twin underwater pipelines through the straits, before returning to a single transmission pipeline through the Lower Peninsula that runs south to Sarnia, Ontario."It is the single largest supply for gasoline, ultimately, in southern Ontario; for aviation fuel out of the Detroit airport; for heating fuel in northern Michigan; for the refineries in northern Ohio that fuel much of the Midwest U.S. economy," Kenney said. "So this is a very, very big deal."The Alberta premier noted that Line 5 has operated safely, "without a significant environmental incident for 60 years," and called the effort to shut it down "part of the broader campaign to land-lock Canadian energy." He said he visited Michigan last year and attempted to meet with Whitmer, a Democrat, but it didn't happen."She refused; she wouldn't see me," he said. "She couldn't find the time, I guess, on the schedule."
Alberta premier and Enbridge respond to Michigan seeking shut down of Line 5 pipeline -- Alberta Premier Jason Kenney calls an attempt by the Michigan government to shutdown the Enbridge Line 5 pipeline very concerning and a continued effort to landlock Canadian energy. “The impact of this would be devastating,” Kenney said. “It is the single largest supply of gasoline ultimately in southern Ontario, for aviation fuel out of the Detroit airport, for heating fuel in northern Michigan, for the refineries in northern Ohio that fuel much of the midwest U.S. economy, so this is a very very big deal.” Kenney made the comments on The Roy Green Show Sunday. On Friday, Michigan Gov. Gretchen Whitmer took legal action to shut down the pipeline. Her office also notified Enbridge it was revoking an easement granted in 1953 to extend a 6.4-kilometre section of the pipeline through the Straits of Mackinac in Michigan. In the letter to Enbridge, the government’s legal counsel said its decision was based on “a violation of the public trust doctrine” and “a longstanding, persistent pattern of noncompliance with easement conditions and the standard of due care.” “Enbridge has routinely refused to take action to protect our Great Lakes and the millions of Americans who depend on them for clean drinking water and good jobs,” Whitmer said in a statement. “They have repeatedly violated the terms of the 1953 Easement by ignoring structural problems that put our Great Lakes and our families at risk. “Most importantly, Enbridge has imposed on the people of Michigan an unacceptable risk of a catastrophic oil spill in the Great Lakes that could devastate our economy and way of life. That’s why we’re taking action now, and why I will continue to hold accountable anyone who threatens our Great Lakes and fresh water.” Enbridge said it is confident Line 5 continues to operate safely and “there is no credible basis for terminating” the easement. The move escalates a multiyear battle over Line 5, which is part of Enbridge’s Lakehead network of pipelines that carries oil from western Canada to refineries in the U.S. and Ontario. The pipeline carries about 87 million litres of oil and natural gas liquids daily between Superior, Wisc., and Sarnia, Ont. Kenney said the pipeline has transported Alberta oil without a “significant environment incident for 60 years.” The Alberta premier said he traveled to Michigan last year to meet with Whitmer but “she refused.” “She couldn’t see me; she couldn’t find time I guess on the schedule. But I did meet the governor of Ohio who strongly supports the continued operation of Line 5 and Premier (Doug) Ford because he understands it would be devastating to the Ontario economy,” Kenney said.
Experts: Whitmer has upper hand in Line 5 case, but May shutdown is uncertain Michigan Gov. Gretchen Whitmer has a strong case against Enbridge Energy, but that doesn’t necessarily mean the oil will stop flowing through Line 5 anytime soon. That’s the conclusion of legal experts who spoke to Bridge Michigan about the hurdles Whitmer must clear to make good on her announcement that the Canadian petroleum company has 180 days from last Friday to permanently cease operating its 67-year-old pipeline at the bottom of the Straits of Mackinac. It could be months or years before Michiganders know for sure when or whether Enbridge must decommission Line 5, legal experts told Bridge, as the state and Enbridge fight a legal battle that many expect to reach the Michigan Supreme Court. Along the way, they said, the case is likely to raise broad questions about Michigan law that could impact Michigan’s ability to regulate a host of environmental concerns in the Great Lakes and influence other pipeline disputes across the nation. A successful case could be nationally significant, said Michael Blumm, the Jeffrey Bain Faculty Scholar and Professor of Law at Lewis & Clark Law School and an expert in the legal doctrine Whitmer used to justify its shutdown, by “showing other states what’s possible.” Whitmer’s shutdown order follows years of debate about how best to reduce the risk of an oil spill from Line 5, a pipeline that transports up to 540,000 barrels of petroleum products daily across the Straits as it travels from Wisconsin to Ontario. After campaigning for office on a promise to shut down the pipeline, Whitmer ordered the Michigan Department of Natural Resources to review Enbridge’s compliance with a 1953 state easement that allowed Enbridge to operate in the Straits. On Friday, Whitmer and Dan Eichinger, director of the Michigan Department of Natural Resources, notified Enbridge that the results of that review have convinced them to revoke Enbridge’s rights to operate in the Straits. Their rationale was twofold: Michigan should never have granted the easement in the first place, Whitmer and Eichinger wrote, because allowing Enbridge to transport oil through the Straits poses a spill risk that “cannot be reconciled with the public’s right in the Great Lakes and the state’s duty to protect them.”
Grön Fuels proposes to build $9.2B biorefinery in Louisiana - On Nov. 10, Louisiana Gov. John Bel Edwards and Fidelis Infrastructure co-founders Daniel J. Shapiro and Bengt Jarlsjo announced their portfolio company Grön Fuels LLC is studying the feasibility of a renewable fuel complex at the Port of Greater Baton Rouge. With expansions and associated projects, the complex could involve up to $9.2 billion of total investment over several phases. A final investment decision is expected in 2021, which will determine the final cost of the project’s first phase. Through all phases and associated projects, the complex would create an estimated 1,025 new direct jobs, with an average annual salary of $98,595, plus benefits. Louisiana Economic Development estimates the project and subsequent phases would result in up to 4,560 new indirect jobs, for a total of 5,585 new jobs for the Capital Region. “This renewable fuel production facility will help to secure Louisiana’s place as a leader in environmentally friendly energy production,” Edwards said. “Growing global demand for renewable transportation fuels creates a significant growth opportunity for our state. Once again, Louisiana’s port, rail and pipeline infrastructure and other logistical advantages are making possible an important industrial complex that will deliver many quality jobs for our skilled workforce. We look forward to the final investment decision for Grön Fuels to launch this innovative project at the Port of Greater Baton Rouge.” The project would be built in stages over nine years at a site leased from the port on the west bank of the Mississippi River, near Port Allen. The first phase of construction would involve a capital investment of over $1.25 billion and create 340 new direct jobs by 2024. The base project is expected to produce up to 60,000 barrels per day of low-carbon renewable diesel, with an option to produce renewable jet fuel utilizing non-fossil feedstocks, including soybean oil, corn oil and animal fats. Upon completion of all phases – potentially by 2030 – the site would be one of the largest renewable fuel complexes in the world.
Venture Global delays financial decision on Plaquemines LNG until 2021 - Venture Global LNG has quietly pushed back the timeline for when the company would make its final investment decision on its second liquefied natural gas export terminal in Louisiana. Venture Global LNG previously anticipated making a financial decision by the end of 2020 about whether to build an $8.5 billion LNG export terminal known as Plaquemines LNG. That has been delayed until mid-2021, according to its website. The facility would export up to 20 million tons of LNG each year. The Arlington, Virginia-based business already signed a 20-year deal to sell 1 million tons of its LNG to French utility Électricité de France S.A. in February. The Polish Oil and Gas Co. agreed to buy 2.5 million tons of LNG from the Plaquemines terminal. The company declined comment about its plans. Reuters news reporters first noticed the website had changed. The Plaquemine LNG project, which sits on a 630-acre site about 20 miles south of New Orleans, has been navigating the federal regulatory process to export LNG and securing local permits. The company anticipated it would begin early construction this year. It's not the first time the Plaquemines project has been delayed. Back in 2016 the company anticipated it would begin construction by 2018 and start selling LNG by 2022. It expects to hire 250 workers at the terminal, and is projected to support up to 2,200 construction jobs. Researchers at LSU have forecast that about half of the LNG export terminals projected to be built along the Gulf Coast would fall through — up from about one-third last year. Venture Global LNG has two other LNG export terminals in the works in Louisiana, one of which is under construction in Cameron Parish and was in the path of Hurricane Laura in August and the other known as Delta LNG, for which a final investment decision has not been reached. The company began construction in mid-2019 on it $4.5 billion Cameron Parish Calcasieu Pass LNG terminal, a 10 million ton per year facility. In 2014, the company had predicted its Cameron Parish site would already be exporting LNG by 2019. In mid-November Venture Global's contractor delivered its first two liquefaction units to the Calcasieu Parish site two months ahead of schedule. It had minimal damage from Hurricane Laura and is expected to begin operations in 2022. The Delta LNG facility in Plaquemines Parish could cost another $8.5 billion and would also export about 20 million tons of LNG per year, but is not epected to be operational until 2024. The company said that the first phase of Delta LNG would begin in 2024 and second phase in 2025. The export facilities are feeding off an abundance of natural gas being produced from U.S. shale formations around the country that are being tapped with advanced drilling technology.
Closure of Louisiana’s Shell Convent Refinery will impact 1,100 jobs and create economic hardship - On November 5, oil giant Shell announced that it will be shutting down the Convent Refinery in Saint James Parish, Louisiana, after failing to find a buyer for the massive complex. The refinery is located on 4,400 acres of land between Ascension and St. James parishes and is expected to begin the shutdown process starting in mid-November. As of now Shell is continuing to seek a buyer for the idled refinery, which can process up to 240,000 barrels of crude oil a day and employs over 1,100 workers, including 400 contract workers, making the operation a key part of the local economy. The news of the closure comes after a $500 million investment in 2015 by the previous owner of the refinery, Motiva, to connect the Convent Refinery to the Norco Refinery down river by a pipeline, integrating their productive capacities and creating the Louisiana Refining System. After sharp contractions in the demand for oil due to the impact of the COVID-19 pandemic on energy use by both private business and individuals, Shell has decided that the refinery is no longer financially viable. Shell spokesperson Curtis Smith stated in the announcement: “Despite efforts to sell the asset, a viable buyer was never identified. After looking at all aspects of our business, including financial performance, we made the difficult decision to shut down the site.” Though the decision was sparked by the pandemic, Shell and other oil companies have long been preparing for large-scale restructuring measures. In fact, Shell is planning on consolidating its assets into just six energy and chemical parks internationally. Other refineries under review for potential sale or closure include Puget Sound, Washington, and Mobile, Alabama, along with others in Canada and Denmark. The fate of those refineries has not been decided yet, according to the company. The international scope of such restructuring measures means they will impact workers all across the globe. The turn by Shell toward consolidating its business, as well as to focus on the integration of its remaining assets to allow the production of more chemically based products such as biofuel, hydrogen and synthetic fuels, is due to major changes in the financial viability of shale well drilling. The overall decline in the productivity of shale, as well as the future focus on lower carbon sources of energy, means the continued reliance on financialization to fuel the industry’s rapid growth is no longer feasible.
The Worst May Be Over for Louisiana's Oil & Gas Industry: LSU Report - The worst is likely over for Louisiana’s struggling oil-and-gas sector, though employment is unlikely to rebound to levels seen before the 2015 crash or even to pre-COVID-19 levels, according to a new report. The LSU Center for Energy Studies projects Louisiana will regain about 2,600 jobs in the upstream oil and gas extraction and services sectors by the end of next year relative to the low point in September. Louisiana refining and chemical manufacturing employment is expected to increase by about 300 jobs by the end of 2021, or about a 0.8% increase. The authors of the center’s 2021 Gulf Coast Energy Outlook, LSU CES director and professor David Dismukes and associate professor Greg Upton, assume that presumptive President-elect Joe Biden’s campaign proposal to ban new oil and gas permitting on public lands and waters is not implemented anytime soon. They also assume that trade talks with China will not deteriorate, leading to new tariffs, and that the COVID-19 pandemic is brought under control. “Embedded in this outlook is the assumption that COVID-19 will gradually subside, and that a second wave of shutdowns will be avoided,” the authors say. “Yet, within days of sending this [report] off to print, the likelihood of a second wave of infections and associated reduced economic activity has increased substantially.” Other factors to watch include a potential re-engagement with Iran, which could add to the global oil supply, and industry efforts to reduce carbon emissions. Ironically, regulatory changes that make it harder to develop oil-and-gas resources could benefit certain sectors of the industry by increasing prices for fossil fuels.
Oil industry and Edwards at odds over vetoed tax break - Oil interests are criticizing Gov. John Bel Edwards' decision to veto a tax break he says was unlikely to deliver the jobs the industry and its supporters suggested. House Bill 29, passed by the Legislature during a special session last month, would have cost the state about $38 million over five years, officials said. It would have cut the taxes companies for drilling new wells or bringing old ones back into production. “This legislation would have stimulated some critically needed economic activity in our state, and while it did not pass, we remain hopeful and optimistic,” Mike Moncla, interim president of the Louisiana Oil & Gas Association, said in a news release Tuesday. “We believe Gov. Edwards gave strong consideration to the merits of the issue, and it is our job over the next few months to illustrate to the governor, the Department of Natural Resources and key legislators why this bill is so important.” In his veto message, issued last week, Edwards questioned the job claims. "During a legislative session wrought with limited access for the public to meaningfully comment on bills, proponents of this new exemption averred that the exemption would increase oil production and create jobs," Edwards wrote. "Yet no legitimate evidence or testimony supports this assertion, other than the testimony of those with a vested interest through enactment of a new exemption." The bill also included no requirement that drilling operators who benefit from the tax break employ Louisiana residents. "Further, any potential benefits of this legislation must be balanced against the resulting 38-million-dollar hole left in the state's budget for the current and next four fiscal years," Edwards said. The governor also noted that the bill was one of several introduced during a special session legislative leaders had claimed they convened to deal with COVID-19 response and hurricane recovery. "There will be a fiscal session of the Legislature in the spring of 2021 where this plan and other tax measures can be fully debated and considered," Edwards wrote. "I look forward to continuing discussions with industry representatives about ways that we can continue to make Louisiana competitive for our oil and gas partners."
Gulf of Mexico oil drilling interest remains low despite recent uptick -- Oil industry interests expressed optimism after Wednesday's Gulf of Mexico lease sale attracted more winning bids than the last one. Companies submitted $121 million in high bids, up from the $98 million the federal government received in March, when the COVID-19 pandemic sparked a global decline in demand for oil and gas. "Today’s lease sale shows industry interest remains strong in the Gulf of Mexico despite the challenges of an uncertain economic environment, and this basin will continue to be an important player in providing energy for America,” Tyler Gray, president of the Louisiana Mid-Continent Oil and Gas Association, said in a prepared statement. Nonetheless, the 23 companies submitting bids sought drilling rights on less than 1% of the more than 79 million acres offered, according to the federal Bureau of Ocean Energy Management. Total winning bids were also down from the $159 million received in August 2019. On Wednesday, companies submitted 105 bids on 98 tracts, a tiny fraction of the nearly 15,000 tracts offered. Results have been similar for the past several lease sales as the pandemic, global production wars and an inland shale boom helped make the Gulf less attractive to drillers. The downturn has cost Houma-Thibodaux's oil-based economy thousands of jobs. Analysts had expressed skepticism that Wednesday's lease sale would attract any significant increase in drilling interest. "At a time of fiscal austerity forced by lower oil demand, ample global supply and the next lease sale likely to occur just a few months from now in March 2021, many observers are betting on lower participation in the Nov. 18 auction," S&P Global Platts, an energy consulting and analytics firm, said Monday. Oil company budgets are limited, and many operators already have leases in reserve, The latest lease sale was the last for the Trump administration, which has touted itself as a friend of the oil industry and a catalyst for American energy dominance. Industry executives and others have expressed concern about Democratic President-elect Joe Biden's campaign pledge to ban new drilling permits on federal land and in federal waters, including the Gulf.
Oxy Taking ‘Contrarian Approach’ to Net-Zero Emissions by Developing Oil Resources, Reusing CO2 --Houston-based Occidental Petroleum Corp. is aiming for net-zero carbon emissions, but rather than investing in renewables, it plans to capture and then reuse the carbon from its global oil developments, CEO Vicki Hollub said Tuesday. During a third quarter conference call, Hollub and the executive team offered details about the sweeping strategy to boost oil production while working toward a goal of net-zero carbon dioxide (CO2) emissions. The plan is to be emissions free in the direct operations by 2040, with emissions from other sources, including by customers down to zero by 2050.The European majors, all of which aim to be emission free in 30 years or less, are charting growth in renewables and alternative fuels to reduce their carbon footprints. Oxy, as it is better known, has a simpler approach, said Hollub.“We are doing a contrarian approach in that we believe that using our core competence of CO2-enhanced oil recovery expertise is the best way to go, rather than trying to go learn a new business.” Enhanced oil recovery, aka EOR, is “going to be a huge industry going forward,” she said. “Globally, there’s only 40 million metric tons of CO2 per year that’s sequestered or used.” CFO Rob Peterson told investors that “Oxy’s approach to this is we also believe that fossil fuels have a role in the energy portfolio of the world long term. And this is a way to take the carbon footprint of those fossil fuels, keep them part of the portfolio, and still generate a low-neutral, even negative-carbon fossil fuel molecule.” Oxy’s U.S. portfolio extends across the Permian, Denver-Julesburg (DJ) and Powder River basins, and into the deepwater Gulf of Mexico. It also has an extensive base of oil-rich development overseas. To date it is the only U.S.-based producer aiming to be net-zero for both direct and indirect (customer) emissions. Houston-based ConocoPhillips recently set a goal to be emissions-free for its direct operations, and many U.S. energy operators, including utilities, also are aiming to be emission-free.Oxy may have a step up on almost everybody. And it’s willing to share the technology, Hollub said.First up is a massive direct air capture (DAC) project in the works for the Permian under the purview of Oxy Low Carbon Ventures LLC (OLCV). OLCV in August partnered with private equity firm Rusheen Capital to create 1PointFive to advance financing and develop the long-awaited Permian project using DAC technology created by Carbon Engineering Ltd. Emissions from Oxy’s oil production are to be stored and then reused in the EOR operations to draw more resources from old wells.
Gulfport Energy Corp. files for bankruptcy protection in Houston with $2.5B in debt - Oklahoma City-based Gulfport Energy Corp. is the latest out-of-town energy company to bring billions of dollars of debt to Houston's bankruptcy court. Gulfport and 10 affiliated companies filed Chapter 11 petitions with the U.S. Bankruptcy Court for the Southern District of Texas on Nov. 13. The main petition lists nearly $2.38 billion of assets and $2.52 billion of debt as of Sept. 30. The company has between 10,000 and 25,000 creditors. Gulfport is an independent natural gas and oil exploration and production company and one of the largest producers of natural gas in the contiguous United States, according to the company. It holds significant acreage positions in the Utica Shale of Eastern Ohio and the SCOOP Woodford and SCOOP Springer plays in Oklahoma, plus noncore assets. The bankruptcy filing comes after Gulfport took several steps in 2020 to improve its balance sheet and preserve liquidity amid decreased demand for oil and natural gas due to the Covid-19 pandemic. Although those steps helped, "continued macro headwinds, including the depressed state of energy capital markets and the extraordinarily low commodity price environments, present significant risks to the company's ability to fund its operations going forward," the earnings report states. Additionally, Gulfport's borrowing base under its revolving credit facility was reduced for the second time during 2020 on Oct. 8, dropping from $700 million to $580 million. On Oct. 15, Gulfport elected not to make a $17.4 million interest payment on its 6% senior unsecured notes maturing 2024. On Nov. 2, the company skipped a $10.8 million interest payment on its 6.625% senior unsecured notes maturing 2023. The company had a 30-day grace period for both payments and said it was continuing "constructive discussions with its lenders and certain other stakeholders regarding a potential comprehensive financial restructuring," according to filings with the U.S. Securities and Exchange Commission. Late last year, the New York Times reported that Gulfport was among several gas-focused companies that would need to refinance billions of dollars of debt between 2021 and 2023. “If low natural gas prices persist beyond 2020,” said a Moody’s Investor Service report, per the Times, “companies may need to reduce debt to maintain compliance with financial covenants or amend covenant levels.” Gulfport reported total revenue of nearly $136.18 million in the third quarter of 2020, a 60% drop from nearly $341.75 million in the third quarter of 2019. However, the company's net loss of $380.96 million, or $2.37 per share, was less than its Q3 2019 net loss of $484.8 million, or $3.04 per share.
Oklahoma Natural Gas Producer Enters Restructuring - Oklahoma City-based Gulfport Energy plans to shed nearly $1.25 billion in debt as it enters a court-supervised Chapter 11 bankruptcy process, according to a company statement on 14 November. Gulfport operates in the Oklahoma’s SCOOP and Ohio’s Utica Shale and as of the second quarter of this year was operating a single rig in each play. The company formed a new executive team in 2019 which was tasked with trimming costs and improving cash flow. However, Gulfport’s large debt load combined with long-term pipeline contracts meant it was on an unsustainable footing given current natural gas prices, ultimately driving its decision to enter bankruptcy, David Wood, president and CEO of Gulfport, said in the announcement. “We expect to exit the Chapter 11 process with leverage below two times and rapidly delever thereafter due to a much-improved cost structure driven by reduced legacy firm transport commitments and costs,” he added. A prepackaged restructuring agreement was reached with most of the natural gas producer’s credit lenders and senior noteholders. The restructuring package includes more than $262 million in debtor-in-possession financing from existing credit lenders, $105 million that will be dispersed imminently, pending court approval. After exiting bankruptcy, the company also expects to have access to $580 million in new financing available. The agreement also notes that common shareholders may see their equity cancelled during the process. Gulfport was founded in 1997 and acquired its current unconventional positions after 2012. The company also owns a 22% nonoperating interest in noncore assets operated by Oklahoma City-based Mammoth Energy and a 25% stake in Canadian operator Grizzly Oil Sands.
Minnesota Pollution Control Agency advisers quit over pipeline permit - A citizen advisory group at the Minnesota Pollution Control Agency (MPCA) has collapsed following the regulator’s decision to issue a water-quality permit to Enbridge Energy for its Line 3 oil pipeline cutting through Minnesota. The bulk of the agency’s Environmental Justice Advisory Group has resigned in protest over the permitting decision, saying in a letter Tuesday to MPCA Commissioner Laura Bishop that “we cannot continue to legitimize and provide cover for the MPCA’s war on Black and brown people.” A dozen of the board’s 17 members signed the letter, which called the water-quality permit the “final straw” in a series of MPCA actions that they said sidelined the advisory group. Among those resigning is Winona LaDuke, a member of the White Earth Band of Ojibwe and executive director of Honor the Earth who strongly opposes the pipeline. In an interview, LaDuke called the decision “a slap in the face.” “The people who are most impacted are Indigenous people, and for seven years we have tried to make the system work,” she said. “If the MPCA actually valued Indigenous people and environmental justice they would not have issued that permit.” LaDuke called her four years on the advisory group “a waste of time.” Commissioner Bishop issued a statement praising the board for making a “significant” difference at the state agency. “I recognize the disappointment of some advisory group members regarding the Line 3 decision,” Bishop said. “The MPCA will continue to eliminate and reverse environmental and health inequities and disparities in overburdened communities and ensure engagement remains at the forefront of our decisionmaking.” The environmental justice advisory group was created in 2016 by former MPCA Commissioner John Linc Stine, with unpaid members appointed by the commissioner. Many members work for advocacy groups or nonprofits. The group currently meets with the commissioner every other month for about 1 ½ hours, it said.
Enbridge Line 3 Construction Blocked by Protesters in Northern Minnesota — Early this morning, two people locked themselves to equipment used for Enbridge’s Line 3 tar sands oil pipeline in northern Minnesota. The action was organized by the Giniw Collective and comes days after various permits were granted in the state of Minnesota, pushing the highly controversial pipeline closer to construction. “Gov. Walz said we need to act boldly on climate,” Tara Houska (Ojibwe), founder of the Giniw Collective, told Native News Online. “Then he approved the largest tar sands infrastructure project in North America through Anishinaabe territory.” “Having grown up on occupied Anishinaabe and Dakota land, I feel a responsibility to defend that land and the rights of the people who have a relationship to it,” Mira Grinsfelder, 24 of Saint Paul, Minn., said in a statement prior to locking herself up to Enbridge equipment. “If the US government won’t defend Anishinaabe treaty rights, we will. If the Minnesota government won’t protect the water, we will,” added Grinsfelder. Native News Online reported on Thursday, Nov. 12, the Minnesota Department of Natural Resources and the Minnesota Pollution Control Agency (MPCA) approved various permits for Enbridge’s Line 3. The result brought hundreds of people in protest at the Governor’s Mansion on Saturday, clashing with a pro-Trump rally with people voicing they support pipelines.Yesterday, Minnesota Public Radio (MPR) News reported that 12 out of 17 MPCA advisory group members resigned in protest over the approval of MPCA Commissioner Laura Bishop approval for a key water permit that pushes Line 3 closer to construction. White Earth tribal member and former Green Party Vice-Presidential candidate Winona LaDuke is one of the twelve that resigned. “We cannot continue to legitimize and provide cover for the MPCA's war on black and brown people," their resignation letter stated. Enbridge’s Line 3 is the largest project in the company’s history and would be one of the largest crude oil pipelines in the continent, according to a statement on the company’s website. Line 3 is expected to transport up to 760,000 barrels a day through northern Minnesota, passing through treaty lands of several Ojibwe bands.
Corps, Users and Opponents Take Sides on Project Permit Makeover - Slammed by a federal court in April over lack of environmental protection in its blanket water-crossing construction permit for the Keystone XL oil pipeline, the U.S. Army Corps of Engineers is closing in on key changes to its Nationwide Permit program. With public comment ended Nov. 16, the Corps is weighing revisions that would affect Keystone XL and other projects. The proposal should streamline the permitting process for the controversial Nationwide Permit-12, a target of fossil fuel project opponents, and help permits withstand new lawsuits, says Sarah Soard, a Burns & McDonnell environmental services manager.But in yet another legal tussle over a pipeline using that permit, known as NWP-12—a Richmond, Va., U.S. appeals court said Nov. 18 that the $6-billion Mountain Valley natural gas line could continue clearing, grading, and other earth-disturbing construction—rejecting opponents' call for an emergency halt until it rules on a broader permit challenge.Even so, the same court did halt in a separate Nov. 9 decision, any water-crossing work under its NWP-12 permit on the 303-mile line in Virginia and West Virginia, pending the bigger final ruling next year. The much-challenged project, already about two years behind schedule, is further pushed back until late 2021, its builder has said. In a statement, a project spokeswoman said the Nov. 18 decision to allow some work "is evidence that [the project] has taken the right steps to ensure that its planned construction activities will continue in a manner that best protects the environment."The Corps has 52 NWPs based on project type. NWP-12 allows dredge-and-fill work and building structures in, over or under water bodies for most oil, gas, electric transmission, water/wastewater, cable and other projects. Project activity with minimal site disturbance can get an NWP permit for the entire work scope rather than approvals for each crossing. NWP process time averaged 45 days, compared to 264 days for an individual permit, said the Corps. It generally updates NWPs every five years. Current rules expire on March 2022 but it is unclear if the proposed changes would go into effect before then, possibly even by year end. With NWP-12 permits for oil and gas pipelines targeted, the Corps has proposed that the permit be limited to those projects. The agency would create separate NWPs for electric and telecom transmission, utility water and wastewater lines, and for water reuse and reclamation plant work. Other proposed NWP changes include permits required for road access to land-based renewable projects or utility substations, raising the size cap on hydropower projects covered, and lowering limits for stream-bed losses in those NWPs that now have them. The proposal adds a required preconstruction notification to build energy pipelines longer than 250 miles, but removes many utility project notification “triggers” the Corps now mandates. The agency would also close a loophole for projects with more than one NWP whose requirements differ, and increase the size of “minor dredging.” A federal district court in Montana had struck down the NWP-12—initially invalidating it nationwide—but later narrowed its ruling to oil and gas lines only. The U.S. Supreme Court then stayed that revised decision, except for Keystone XL, until a San Francisco appeals court case ruling, which is expected next year or possibly later.
Colorado Agency Mistakenly Sends Email To Oil & Gas Companies Calling Them Derogatory Names, Including ‘Snake Oil Inc’ – CBS Denver – The Colorado Oil and Gas Conservation Commission is apologizing after sending an inappropriate email ridiculing the very companies it regulates. CBS4 has learned that staff members at COGCC were testing a new e-filing system when they inadvertently sent an email to hundreds of oil and gas workers across the state. The email called the companies they work for names that you don’t expect from people who are supposed to be fair and unbiased. The email arrived early Sunday morning with a list of oil and gas companies that had upcoming hearings. The names of the companies included “Snake Oil Inc.,” it’s law firm “Blah Blah Blah” and its cause or case number “666” — a designation for the devil. Other names included “Acme Company,” “Bad Oil and Gas,” “Really Rich,” “Here We Go Again,” and “The Lorax” — a Dr. Seuss character that warns about environmental destruction. “As our entire economy is struggling, that they have time to make jokes and horrible comments about the hard working women and men in our industry, it’s just sad,” said Chelsie Miera, who represents oil and gas companies on the Western Slope. She says if state employees thought it was a joke, operators and workers don’t find it funny. The email comes in the middle of hearings to overhaul the regulatory framework for industry. “There’s been no acknowledgement that this even happening in those meetings,” said Miera. A follow up message said only that “the emails were sent in error.” Miera says she’s concerned that they came from people who control the fate of the industry.
Utah lawmakers push to block cities from banning natural gas - Some California cites have enacted rules that prohibit new homes from connecting to natural gas, a fossil fuel whose emissions contribute to climate change. That won’t happen in Utah under a bill that a legislative committee advanced Tuesday on a straight party-line vote. “We should have customer choice when it comes to energy," bill sponsor Rep. Stephen Handy, R-Layton, told the Public Utilities, Energy, and Technology Interim Committee. “As policymakers, we should allow for customer choice, whatever the market dictates, whatever that is. We shouldn’t prohibit customer choice.” But Democratic committee members failed to see the point of the bill since no Utah city has proposed restricting utility customers' access to natural gas, although Handy contended “there are conversations.” “I worry that when we start getting into this prohibition language, it really hamstrings municipalities from exploring any sort of innovative policy,” said Sen. Derek Kitchen, D-Salt Lake City. “I just think that it’s a very heavy-handed approach for the state of Utah when we haven’t even seen any negative consequences.” Titled “Utility Permitting Amendments,” the bill simply states “a municipality [or county] may not enact an ordinance, a resolution, or a policy that prohibits, or has the effect of prohibiting, the connection or reconnection of a utility service to a customer based upon the type or source of energy to be delivered to the customer.” By a 12-4 vote, the committee advanced the measure for consideration in the upcoming legislative session.
Natrona Trump administration must weigh climate change when leasing land to oil and gas, court rules --A federal judge admonished the Trump administration yet again in a court opinion on Friday for failing to adequately assess how leasing public land to oil and gas developers could negatively affect the climate. The U.S. District Court for the District of Columbia ruled the Bureau of Land Management neglected to properly weigh the impacts of climate change when conducting its environmental review tied to 304,000 acres of leased land in Wyoming. In the decision rendered Friday, U.S. District Judge Rudolph Contreras called on federal regulators to conduct its environmental analysis again before drilling could be occur. According to the judge, the BLM’s analysis once again fell short and did not comply with the National Environmental Policy Act when it leased public land in Wyoming to oil and gas developers. The judge moved to enjoin, or block, drilling applications from being approved on 282 lease parcels of federal land, an area amounting to 303,995 acres in Wyoming. This isn’t the first time the court has struck down the Trump administration’s environmental analysis related to leasing public land for oil and gas development. In 2016, two non-profit organizations, WildEarth Guardians and Physicians for Social Responsibility, filed the lawsuit against the BLM. In March 2019, the court sided with the plaintiffs and concluded the BLM had not fully considered the cumulative impacts of climate change before leasing the land to energy companies. The judge ordered the agency to conduct additional analysis before development could move forward. After the BLM submitted the supplemental environmental reviews, the agency was met with yet another challenge from the same pair of nonprofit groups. WildEarth Guardians and Physicians for Social Responsibility called the BLM’s new analysis “error-riddled,” “arbitrary” and “capricious.” The federal court agreed on Friday, calling the BLM’s additional analysis “a sloppy and rushed process.”
Oil and gas production rising in North Dakota, but future is murky - North Dakota posted a solid hike in petroleum output in September, while the industry now races to start new wells before pro-oil President Donald Trump leaves office.Still, the oil and gas outlook in North Dakota — and the rest of the U.S. — is murky as oil prices remain depressed and COVID-19 continues to sap the economy.“September production was up 5% on the oil side — good news there,” Lynn Helms, director of North Dakota’s Department of Mineral Resources told reporters Tuesday. But “this might be as good as it gets for a while.”North Dakota, the nation’s second-largest oil and gas producer, churned out 1.22 million barrels of oil per day in September, up from 1.17 million the previous month. Natural gas production jumped 7% during the same time.North Dakota’s oil output hit a seven-year low in May of 858,400 barrels per day before rallying over the summer.The recovery, though, was driven by the reopening of wells that had been shut-in during the spring when oil hit historic low prices. It has now largely played out, Helms said.For production to keep rising, oil companies must frack new wells to compensate for old wells petering out. But oil prices are too low to spur such activity anytime soon.In August and September, North Dakota saw a steady rise in permits for new wells, and drilling activity — while still historically low — hasn’t fallen off. The trend has continued since.“That is attributed to [concerns] over changing federal policy,” not economics, Helms said.President-elect Joe Biden has proposed banning oil and gas drilling on federal lands. Almost one-quarter of North Dakota’s oil lands could be “severely impacted” by a federal drilling moratorium, Helms said.Hence, the rush to get new permits and drill new wells on federal land. However, even after a well is drilled, oil producers aren’t likely to turn on the spigot until oil prices rise appreciably.And Helms noted that federal energy forecasters don’t see oil demand returning to 2019 levels until 2022.
Living Near Drilling Is Deadly. Why Don’t California Lawmakers Care? - The New York Times – video - California famously prides itself on environmental leadership — but what about when its lawmakers overlook problems in their own constituents’ backyards? It’s still legal to drill for oil there right next to schools and hospitals — despite well documented health risks to anyone nearby. In the video op-ed above, Josiah Edwards explains what it was like to grow up breathing in the toxic chemicals expelled by drilling. He traces the asthma that plagues his entire family to decades of redlining in Los Angeles County, which consigned Black and brown communities like theirs to live next to active oil wells. Even today, politicians keep rejecting legislation that would help protect Californians from these poisonous emissions. You may not have an oil drill in your backyard now, but if you live in California, there’s nothing stopping one from moving in tomorrow.
Trump administration pushes to sell Alaska oil leases pre-Biden inauguration - The White House will be sending out a call for nominations in coming days, according to a spokeswoman for the U.S. Bureau of Land Management in Anchorage, Alaska. The call is a request to energy companies on what specific land areas should be offered for sale. That would start the clock on a 60-day period before sales could take place in ANWR, where drilling had been banned for decades before a Republican-led tax legislation signed in 2017 removed that ban. Biden opposes drilling in ANWR, while lawmakers in Alaska have long pushed to open up the ecologically sensitive area for oil and gas exploration. “Development in ANWR is long overdue and will create good-paying jobs and provide a new revenue stream for the state - which is why a majority of Alaskans support it,” said Frank Macchiarola, senior vice president of policy, economics and regulatory affairs at the American Petroleum Institute, an industry group. Following a 30-day period after the call for nominations, the government would have to issue a notice for an impending sale of leases. Thirty days after that, the sale would take place, just before Biden’s inauguration on Jan. 20. Alaska produces roughly 500,000 barrels per day of crude oil, far below its peak of 2 million bpd in the late 1980s. “This lease sale is one more box the Trump administration is trying to check off for its oil industry allies before vacating the White House in January,” said Adam Kolton, executive director at the Alaska Wilderness League, which opposes drilling in ANWR. The White House finalized a plan to allow drilling earlier this year. The 19 million acre (7.7 million hectares) refuge is home to Native tribes and wildlife populations including caribou and polar bears. In recent months, several big U.S. banks have said they would not finance oil and gas projects in the Arctic region. “This administration has consistently ignored our voices and dismissed our concerns. Our food security, our land and our way of life is on the verge of being destroyed,” said Bernadette Demientieff, executive director of the Gwich’in Steering Committee. The Gwich’in tribe lives in scattered villages in the reserve and across the national border in Canada.
Trump Rushes To Sell Oil Drilling Leases in Arctic National Wildlife Refuge -- The lame duck Trump administration is making a rushed last-minute push to sell leases to oil companies in the long-protected Arctic National Wildlife Refuge before Inauguration Day, numerous outlets reported.On Monday, the Interior Department issued a "call for nominations" asking oil companies to request specific parcels of land to be made available for drilling. Completing the lease sales before President-elect Joe Biden takes office on Jan. 20. would make it harder, though not necessarily impossible, for the Biden administration to prevent oil drilling in ANWR."Any company thinking about participating in this corrupt process should know that they will have to answer to the Gwich'in people and the millions of Americans who stand with us," said Bernadette Demientieff, executive director of the Gwich'in Steering Committee, in a statement. Despite the Trump administration's efforts, oil companies may still struggle to drill in ANWR, given substantial logistical costs and recent moves by major financiers to stop funding drilling there.As reported by The Washington Post: It's unclear if drillers will even want to take on the legal, political and engineering challenges of extracting oil and gas from the pristine, frozen landscape. Some major banks have already announced they will not fund oil and gas activities in the Arctic in response to environmental pressure.But in other cases, the Biden administration will have to go through an entirely new process all over again to stop the Trump rules from taking effect. That could potentially siphon time and energy away from other environmental protection efforts — including heading off the disastrous rise in temperatures because of global warming.For a deeper dive:For a deeper dive: NPR, The New York Times, Politico Pro, The Hill, Axios, The Washington Post
Trump Plan to Sell Arctic Oil Leases Will Face Challenges -New York Times - If lease sales happen in the final days of the Trump administration, they may face disputes in court or could be reversed by the Biden administration.Even if in its waning days the Trump administration succeeds inselling oil and gas leases in the Arctic National Wildlife Refuge in Alaska, the leases may never be issued, legal and other experts said Tuesday.The leases would face strong and likely insurmountable headwinds from two directions: the incoming Biden administration and the courts, they said.Under new leadership, several federal agencies could reject the leases, which even if purchased at an auction a few days before Inauguration Day would be subject to review, a process that usually takes several months.Mr. Biden vowed during the campaign to oppose oil and gas development in the refuge, a vast expanse of virtually untouched land in northeast Alaska that is home to polar bears, caribou and other wildlife. “President-elect Biden has made it clear that protecting the Arctic refuge from drilling is important to him,” said Brook Brisson, a senior staff attorney with Trustees for Alaska, a nonprofit public-interest law firm. “We trust that means his administration will use its executive authority to do just that.”But if for some reason after those reviews the new administration did not reject the leases, they could also be overturned in court. There are already four lawsuits against the Trump administration’s actions relating to oil and gas development in the refuge, including one filed by Ms. Brisson’s group on behalf of Alaska Native and environmental organizations. “Whoever wins these leases will walk into a minefield of litigation,” . With the publishing of a “call for nominations” in the Federal Register on Tuesday, the Bureau of Land Management officially initiated the lease-sale program for the refuge. The document seeks comment from oil companies and other parties as to their interest in leasing specific parts of the refuge’s coastal plain, which covers 1.5 million acres along the Arctic Ocean.The area is thought to overlie reserves containing billions of gallons of oil. For decades it was protected by law from drilling, but it was opened to potential development in 2017 by the administration and the Republican-led Congress. The decision to start the lease-sale program was hailed by oil industry groups and by members of Alaska’s Congressional delegation, who have long pursued drilling in the refuge for the jobs and revenue it could bring. The Interior Department, which includes the Bureau of Land Management, said it had “taken a significant step in meeting our obligations by determining where and under what conditions the oil and gas development program will occur.”
Big oil and gas have a lot invested in Trump’s attack on the election system --Calmer heads may yet talk Donald Trump down from caps-locked denial to lower-case concession, but the longer the defeated presidentflirts with a coup, the more the oil and gas industry must take a share of the blame. Fossil-fuel firms are among the biggest donors to the defeated US president and the Republican party leaders who have endorsed his legal challenge to overturn the election result. They also have the most to lose if Joe Biden carries out his campaign promise to rejoin the Paris climate agreement and enact a $2tn Green New Deal that would make wind, solar and other clean technologies far cheaper than petroleum. Trump’s presidency was made possible by the rise of a far-right wing in the Republican party characterised by white supremacist messaging and fossil-fuel funding. Oil and gas companies, led by Energy Transfer Equity, Koch Industries and Chevron, give about 80% of their political donations to Republican and conservative candidates. The biggest beneficiary by far is Donald Trump, who directly received more than $2m from this sector in the past year, not including money funnelled through secretive political action committees. High on the list are other supporters of his attempt to overturn the ballot box in the courtroom, such as Mitch McConnell, with $490,000, and Graham, with $143,000. Trump’s refusal to concede can be dismissed as the tantrum of a sore loser. But his support from prominent Republicans resembles a more serious attempt to hold back history: in particular, the two intertwined trends – climate and race – that drove Biden to victory. Climate campaigns are increasingly intertwined with social justice movements. The tighter they bind, the more powerful they become. This is the alliance that pushed Biden to victory. In the future it is likely to strengthen as demographic trends advance and fossil fuel dependency retreats. This may be why some Republicans are so spooked that they are toying with rejecting democracy outright. Lindsey Graham, the Senate Judiciary Committee chair who was re-elected as senator for South Carolina, has made little secret of why he believes Trump’s challenge is an existential political issue for his party. “If Republicans don’t challenge and change the US election system, there will never be another Republican president elected again,” he told Fox News. In a subsequent interview, he clarified this. “If we don’t do something about voting by mail, we are going to lose the ability to elect a Republican in this country.” Of course, it is not the postal votes he fears, but who is making them and why. The massive Covid-driven increase in mail-in votes is likely to have helped to enfranchise many black and indigenous people who were previously excluded by voter-suppression tactics. This, and the dynamism of black women activists such as Stacey Abrams, appears to have been decisive in the democratic victory in Georgia and could yet end the Republicans long control of the Senate, depending on the result of a run-off vote in January.
Oil and gas lobbyists optimistic about 2021 - Energy and business lobbyists are shifting focus to influencing an administration that isn’t President Donald Trump’s, and some see the potential for a divided Congress to benefit industry even with voters concerned about climate change. The Texas Energy Museum hosted a virtual symposium Thursday that featured expert analysis of energy markets and policy goals from one of the top political advisers for the U.S. Chamber of Commerce and the executive director of the American Petroleum Institute. Speakers addressed the biggest challenges and next steps for the energy sector but mostly painted a rosy picture for the oil and gas industry moving forward into the next presidential administration. Mike Sommers, chief executive of the American Petroleum Institute (API), said it became clear on Nov. 7 — the day statistical projections for President-elect Joe Biden’s electoral college votes exceeded 270 — that there would be a new presidential administration to deal with, but the Election Day outcomes for industry were more complicated than one man. “When you dig deeply into the House and Senate results, this election was actually an overwhelming victory for U.S. energy leadership and the millions of jobs and economic benefits our industry provides,” he said. API is one of the largest energy associations in the nation, made up of more than 600 companies in both the oil and gas sectors. It also helps establish industry standards and practices for a wide swath of the industry. Based on the House races that have been called so far and the leanings of outcomes in races yet to be called, lobbyists are preparing for Democrats to have one of the smallest majority margins in the chamber since 2000.
Coast Guard works to contain oil leaking from boat in lagoon - The U.S. Coast Guard is working to clean up oil leaking from an abandoned tugboat in Krause Lagoon on St. Croix’s south shore. The owner of St. Croix Renaissance Group made a report on Nov. 12 and placed a containment boom around the partially sunken Cape Lookout, Coast Guard spokesman Ricardo Castrodad told The Daily News on Tuesday. While at least some of the oil was not captured by the boom, that initial containment effort likely kept the vast majority of oil from drifting throughout the lagoon, and crews started work Tuesday to capture and dispose of the oil, Castrodad said. “While the maximum potential discharge based on the size of the vessel fuel and lube oil tanks is approximately 48,000 gallons of fuel and 2,000 gallons of lube oil. It is unknown how full both tanks are at this time,” according to information from a Coast Guard news release. “At this time, approximately 85% of the discharged oil remains contained within the absorbent and containment boom that is surrounding the vessel, while the remaining material remains within an area that extends approximately 50 yards from the vessel.” “Due to the immediate pollution threat this vessel represents to the environment and surrounding area, the Coast Guard is working to open the Oil Spill Liability Trust Fund to hire an Oil Spill Removal Organization to conduct clean-up operations,” Lt. Cmdr. Alberto Martinez, Sector San Juan Incident Management Division chief, said in a statement. Castrodad said that has happened and a crew was dispatched Tuesday to clean up the site. The 97-foot tugboat “remains tied to a concrete platform at the facility partially sunk with its bow sticking out of the water,” according to the news release, and Castrodad said it’s unclear when exactly the vessel was abandoned. Castrodad said while the tugboat’s owners are ultimately responsible for the vessel’s maintenance and the spill, the priority now is to clean up the environmental hazard, and then the Coast Guard will continue working to identify the responsible individuals.
US Coast Guard manages oil cleanup from Sunken tugboat - The US Coast Guard responded to reports of an abandoned tugboat that was sinking in the harbor of an industrial park on the island of St. Croix in the US Virgin Islands. Coast Guard pollution teams are monitoring cleanup operations to recover discharged oil from the sunken vessel. The incident began on November 12 when the owner/operator of the business park, St. Croix Renaissance Group, reported to the Coast Guard that the abandoned tugboat Cape Lookout was sinking at Krause Lagoon on St. Croix. Coast Guard personnel from the Resident Inspections Office St. Croix, working in coordination with the Sector San Juan Incident Management Division, responded to the scene. The Coast Guard found that the tugboat, which remained tied to a concrete platform at the facility, had partially sunk with its bow sticking out of the water Oil was leaking from the 97-foot tugboat. Based on the size of the vessel, the Coast Guard estimated that the maximum potential discharge was approximately 48,000 gallons of fuel and 2,000 gallons of lube oil. However, it was not known how full the fuel and lube oil tanks were at the time the vessel sunk. An oil containment boom was placed around the vessel and according to the Coast Guard, approximately 85 percent of the discharged oil remains contained within the absorbent and containment boom that is surrounding the vessel. The remaining material remains within an area that extends approximately 50 yards from the vessel the Coast Guard estimated. The Coast Guard assisted in establishing a liability trust fund to hire an oil spill removal organization to conduct cleanup operations. “The National Response Corporation in the US Virgin Islands has been hired as the oil spill removal organization that will be conducting oil recovery and cleanup operations for the Cape Lookout,” said Lt. Cory Woods, Coast Guard Resident Inspection Office St. Croix supervisor. “Our primary objective is to remove this pollution threat and help the affected area and environment return to its pristine state as soon as possible.” Since oil recovery operations began, cleanup crews have recovered approximately 1,500 gallons of oily water of the material discharged from the vessel using an oil waste vacuum truck and oil skimmers to recover the oil from the water. Also, a new containment and absorbent boom was placed around the vessel to keep the discharged oil contained and facilitate its recovery.
Heritage continues oil spill clean-up, air quality testing - The Heritage Petroleum Company Limited is continuing its clean-up efforts in response to the oil spill at the Godineau River, South Oropouche. The Company first received reports of the spill on Wednesday and initiated its response protocols. In an update on Friday, Heritage said it is committed to minimising the impact of the spill. According to the release, many of the people supporting the clean-up efforts live in the area with several fishermen utilising their boats in the process. Ambient air quality testing is ongoing as well as pipeline assessment and repairs along the 16” line. The release added that the relevant authorities are being regularly updated to ensure all operations are conducted in a safe, efficient, and timely manner. Furthermore, Heritage Petroleum once again reminded the public to avoid the affected area from La Fortune Pluck Road to the river’s mouth at Mosquito Creek since this may put them at unnecessary risk and hamper the clean-up activities.
Ban oil drilling in Bahamas - EDITOR, The Tribune:. Government enacted lockdowns during the COVID-19 pandemic have forced Bahamians to stay home, crushed the economy, and destroyed Bahamian businesses. Meanwhile, Bahamas Petroleum Company (BPC) – which is not Bahamian – has been allowed to forge ahead with its plans to drill for oil in The Bahamas. This blatant act of discrimination by the government against Bahamians is unconscionable and unacceptable. It is also a slap in the face by the government and BPC because oil drilling will not create significant jobs for Bahamians, and drilling is an assault on the precious ecosystem that our lives and countless other forms of life depend on. Numerous letters have been written to the media to express disapproval of drilling in The Bahamas. Requests have also been made to the Prime Minister to stop BPC from drilling. And the petition “Help Save The Bahamas From Oil Drilling” has gained international attention and support. Despite public outcry against BPC, top government officials who opposed drilling have been silent, and BPC representatives have tried to convince Bahamians that oil drilling is safe and great for The Bahamas. A lot has been written about the perceived benefits and the real risks of oil drilling in The Bahamas. So let’s discuss comments made by high-ranking politicians when they were not shy about voicing their opinions about drilling.
Sempra's Mexico LNG Plant -- Update -- November 17, 2020 --Just the other day, November 13, 2020: SRE: Mexico will give LNG conditional export permit -- Sempra Energy's local IEnova unit likely will receive an export permit for a proposed liquefied natural gas facility in northwest Mexico, as long as the company helps offset an oversupply of gas in the area, Mexican Pres. Lopez Obrador says.
- The President says he is inclined to approve the permit but stresses what he considers excess natural gas in the area around the northern Pacific coast, given that state-owned power company Comision Federal de Electricidad does not use the fuel to generate electricity.
- Lopez Obrador says supply contracts signed by the previous government obliged CFE to buy natural gas that is not needed.
- The comments appear to walk back the government's interest in requiring IEnova to build a second LNG export facility before approving the pending plant in Ensenada, which was reported in August.
Today: TechnipFMC wins $1-billion-plus contract for Sempra's Mexico LNG plant..
- TechnipFMC after-hours on news it received a notice to proceed for a major Engineering, Procurement and Construction contract by Sempra Energy and IENova at the Energía Costa Azul liquefied natural gas facility in Mexico; for TechnipFMC, a "major" contract exceeds $1B.
- The Costa Azul project, which won a final investment decision today, will add a natural gas liquefaction facility with nameplate capacity of 3.25M metric tons/year to the existing regasification terminal using a compact and high efficiency mid-scale LNG design.
- TechnipFMC has been involved in the project since 2017, including the delivery of the front end engineering design.
- Earlier this month, TechnipFMC reportedly was set to win a "huge" offshore engineering contract from Qatargas.
In its press release, Sempra refers to the Costa Azul (blue coast) project as a "landmark" project.
Australia LNG regas projects face scrutiny amid domestic gas policy changes -Australia's LNG regasification projects are facing scrutiny after a drilling moratorium in the state of Victoria was lifted earlier this year, and with more acreage recently opened up for exploration by the federal government to boost domestic energy security.The easing of upstream restrictions has made the race for LNG receiving terminals more competitive in South Australia and the eastern states of Victoria, Queensland and New South Wales, and not all the projects will make it to the finish line. But experts said there is still a strong case for some of the projects because of looming gas shortages, slow upstream progress and the terminals serving as an alternative to pipelines from gas-producing regions in the west. There has been limited progress in resolving medium and long-term east coast gas supply challenges, and by 2030 supply constraints will become increasingly evident with declining production offshore Victoria and no major gas discoveries, energy consultancy EnergyQuest said in an Oct. 16 report. "Any developments onshore Victoria or NSW will provide some supply increments but are unlikely to materially shift the long-term demand-supply imbalance," it said. "We expect one and possibly two of the Gladstone LNG trains to be closed as increased gas volumes are diverted from the LNG projects to the domestic market. The gap between demand and supply will also increasingly rely on LNG imports at international prices," the consultancy added.The Gladstone terminals in Queensland are the 9 million mt/year Origin-ConocoPhillips' Australia Pacific LNG, 7.8 million mt/year Santos-led Gladstone LNG and Shell's 8.5 million mt/year Queensland Curtis LNG. Actual output is below combined capacity of 25.3 million mt/year due to insufficient gas. Earlier this year, S&P Global Platts Analytics noted that individual issues had delayed final investment decision for each regas project.It said AGL's Crib Point LNG terminal faced environmental issues, EPIK's Newcastle project required an extensive and costly pipeline, and Australian Industrial Energy's Port Kembla FSRU struggled to find buyers as gas imports were only feasible during peak demand periods. On Oct. 20, AIE's Japanese shareholders sold their stakes to Squadron Energy. Victoria also has a second project, by Vitol-backed Viva Energy, near its Geelong refinery."Australian Industrial Energy's Port Kembla Gas Terminal is the only new project that can deliver substantial quantities of natural gas to market as early as 2022 and address the east coast's predicted short-term gas supply challenges," a spokesman for AIE told S&P Global Platts in early October. "The 14-16 month construction window is relatively short and the project will then have the capacity to supply more than 75% of NSW's gas needs," he said, adding that gas imports and domestic production can co-exist.
IMO and Arctic states slammed for endorsing continued Arctic pollution - The Clean Arctic Alliance today slammed the decision by the International Maritime Organization (IMO) to approve a ban ridden with of loopholes on the use and carriage of heavy fuel oil in the Arctic (HFO), saying that it would leave the Arctic, its Indigenous communities and its wildlife facing the risk of a HFO spill for another decade [1]. The ban was approved during a virtual meeting of the IMO’s Marine Environment Protection Committee (MEPC 75), despite widespread opposition from Indigenous groups, NGOs and in a statement release this week, the Catholic Church [2]. At the IMO’s PPR 7 subcommittee meeting in February 2020, the IMO agreed on the draft before sending it to MEPC. Following PPR7, the Clean Arctic Alliance called the inclusion of loopholes – in the form of exemptions and waivers – in the draft regulation “outrageous” as they mean a HFO ban would not come into effect until mid-2029. With the ban now scheduled to go forward for adoption at MEPC 76, the Clean Arctic Alliance – a coalition of 21 non-profit organisations, called for waivers to not be granted by Arctic coastal states and for the deadline beyond which exemptions would not apply to be brought forward. “By taking the decision to storm ahead with the approval of this outrageous ban, the IMO and its member states must take collective responsibility for failing to put in place true protection of the Arctic, Indigenous communities and wildlife from the threat of heavy fuel oil”, said Dr Sian Prior, Lead Advisor to the Clean Arctic Alliance. “In its current form, the ban will achieve only a minimal reduction in HFO use and carriage by ships in the Arctic in mid-2024, when it comes into effect. It is now crucial that Arctic coastal states do not resort to issuing waivers to their flagged vessels”. Heavy fuel oil is a dirty and polluting fossil fuel that powers shipping throughout the world’s oceans – accounting for 80% of marine fuel used worldwide. Around 80% of marine fuel currently carried in the Arctic is HFO; over half by vessels flagged to non-Arctic states – countries that have little if any connection to the Arctic. As Arctic heating drives sea ice melt and opens up Arctic waters further, even larger non-Arctic state-flagged vessels running on HFO are likely to divert to Arctic waters in search of shorter journey times. This, combined with an increase in Arctic state-flagged vessels targeting previously non-accessible resources, will greatly increase the risks of HFO spills in areas that are difficult to reach, and that lack any significant oil spill containment equipment.
Russia should get behind Arctic ban on dirty fuel - In recent years, Russia has emerged as a global leader in the production and transportation of liquefied natural gas (LNG). The projects are highly innovative, mighty impressive, and very expensive. However, Russia’s strides in switching to LNG in the Arctic will be hindered by their reliance on heavy fuel oil (HFO). HFO, known also as bunker fuel or mazut, is a thick, tar-like substance — a dangerous pollutant, packed full of contaminants. While much of the Russian business community seems to understand that it has no place in Arctic waters, the Russian government has spearheaded diplomatic efforts to water down a proposed international ban on the use of mazut in the Arctic. That could be a dangerous mistake. The Russian government, scientists, and civil society should take heed of these cues from some of the country’s largest businesses and support the transition away from mazut. Shipping along the Northern Sea Route — an Arctic passage which cuts naval journey times from Europe to Asia, but is only accessible in warmer summer months — is booming. Since 2017, volumes have gone up by more than 430%, eclipsing records set in the Soviet era. LNG already makes up most of the transported cargo volumes, but despite investments in gas infrastructure, Russia continues to rely on heavy fuel oil in the Arctic. In November 2019, then-Prime Minister Dmitry Medvedev called on the Murmansk Governor Andrey Chibis to find a “systematic solution” to the problem of growing expenses for heavy fuel oil — the issue of mazut had been elevated to the highest-levels of decision-making in the country. Russia’s business leaders understand that the future of mazut is kaput and are shifting their rubles to LNG.
Oil climbs higher on China, Japan rebound, hopes of OPEC+ supply curb - Oil prices climbed on Monday, recouping some losses from the previous session as hopes that OPEC+ will hold current output curbs offset concerns about weaker fuel demand due to rising Covid-19 cases and higher production from Libya. Figures showing a rebound in the world's second and third largest economies, China and Japan, also supported prices, along with data that Chinese refineries processed the most crude ever in October on a daily basis. Brent crude futures for January rose $1.70, or 3.97%, to trade at $44.48 per barrel, while U.S. West Texas Intermediate crude for December was up $1.61, or 4%, at $41.74 per barrel. "Fundamentally China's numbers do support why oil prices can keep at these levels," OCBC economist Howie Lee said. Both contracts gained more than 8% last week on hopes of a Covid-19 vaccine and that the Organization of the Petroleum Exporting Countries (OPEC) and their allies including Russia will maintain lower output next year to support prices. The group, also known as OPEC+, has been cutting production by about 7.7 million barrels per day, with a compliance rate seen at 101% in October, and had planned to increase output by 2 million bpd from January. OPEC+ is due to hold a ministerial committee meeting on Tuesday which could recommend changes to production quotas when all the ministers meet on Nov. 30 and Dec. 1. However, the speedy recovery of oil production in Libya, an OPEC member, back to above 1.2 million bpd presents a challenge to OPEC+ cuts, while a slowdown in traffic across Europe and the United States dampened fuel demand recovery hopes this winter. "European motorway traffic is down almost 50% in recent weeks in some countries (such as France) as lockdown measures are increased," ANZ analysts said. People movement on highways in the United States was also slowing based on vehicle mileage data despite authorities' reluctance to implement new restrictions, they added. While fuel demand is slowing, Baker Hughes' data showed that the U.S. oil and natural gas rig count rose last week to its highest since May as producers, spurred by higher crude prices, return to the wellpad. ANZ analysts expect the oil surplus to increase to between 1.5 million and 3 million bpd in the first half next year with a vaccine only boosting demand in the second half.
Oil futures finish sharply higher on vaccine news - Oil futures finished with a sharp gain on Monday as news of another promising vaccine helped to ease concerns about COVID-19 economic restrictions that could lead to lower energy demand. December West Texas Intermediate crude rose $1.21, or 3%, to settle at $41.34 a barrel on the New York Mercantile Exchange.
Oil prices edge higher ahead of OPEC+ meeting, vaccine hopes - Oil prices edged higher on Tuesday on expectations OPEC and its allies will extend oil production cuts for at least three months, while sentiment was bolstered by news of another promising coronavirus vaccine. Brent crude futures for January rose 26 cents, or 0.6%, to $44.08 a barrel by 0535 GMT and U.S. West Texas Intermediate crude for December added 18 cents, or 0.4%, to $41.52 a barrel. Equity markets rose on hopes of a quicker economic recovery after Moderna said its experimental Covid-19 vaccine was 94.5% effective in preventing infection based on interim late-state data. "Moderna's vaccine announcement had probably its largest effect on oil out of the main asset classes," said Jeffrey Halley, senior market analyst at OANDA, adding that positive vaccine news has "almost certainly put a long-term floor under oil prices." Moderna's results came after Pfizer reported last week that its vaccine was more than 90% effective. "If we judge economic recovery, particularly through the lens of oil markets ... with multiple high efficacy vaccines in the pipeline, there is good chance mobility will return close to pre-pandemic levels later in 2021," OPEC+, which groups the Organization of the Petroleum Exporting Countries (OPEC) and its allies, including Russia, is set to hold a ministerial committee meeting on Tuesday that could recommend changes to production quotas when all the ministers meet on Nov. 30 and Dec. 1. The group is leaning towards postponement of a planned January increase in oil output for at least three months to support prices as the Covid-19 pandemic continues its second wave, sources told Reuters on Monday. In the United States, oil output from shale formations in December is expected to decline to the lowest level since June, according to the Energy Information Administration. China's crude oil throughput in October rose to its highest-ever level, underpinning a fast demand recovery in the world's second largest oil consumer. "Oil demand in China is exceeding pre-COVID-19 levels which suggests oil demand is not permanently impaired," analysts from Bernstein Energy said. "This is in line with mobility data and supports the view that oil demand has not been structurally damaged by changes in behavior post COVID-19 for countries which emerged successfully from COVID-19."
Oil prices end mixed as traders weigh next move for OPEC+, upcoming EIA supply data - West Texas Intermediate crude for December delivery rose 9 cents, or 0.2%, to settle at $41.43 a barrel on the New York Mercantile Exchange. January Brent crude the global benchmark, fell by 7 cents, or 0.2%, at $43.75 a barrel on ICE Futures Europe. WTI jumped 3% and Brent rose more than 2% on Monday after Moderna Inc. announced its COVID-19 vaccine candidate was more than 94% effective in preventing infections. That came a week after Pfizer Inc. and BioNTech SE said their vaccine candidate was highly effective. The JMMC Tuesday also said it “welcomed the positive performance in the overall conformity level” for participating members and nonmembers of OPEC at 101% in October. Including voluntary adjustments to make up for past overproduction, those producers have cut global supply by about 1.6 billion barrels between May and October. The committee was expected to recommend delaying, by three to six months, a relaxation of output curbs set to take effect on Jan. 1, said analysts at UniCredit, in a note. OPEC+ is set to make a final decision at the Nov. 30 and Dec. 1 meetings. The failure to announce a recommendation was “surprising,” Marshall Steeves, energy markets analyst at IHS Markit, told MarketWatch. However, Arabic news and satellite TV channel Al Ekhbariya reported that OPEC+ unanimously agreed to an extension of output cuts by three months starting in January, according to translated tweet from the Saudi government owned network. “The global demand outlook remains precarious given the second wave of the pandemic and resulting lockdowns in Europe and the U.S.,” Steeves said. “This will likely remain the case through the first quarter of 2021 if not the second, thus OPEC+ needs to face the reality that demand for their oil will remain muted.” For now, “the oil market remains broadly rangebound between the pressure of travel restrictions and rising COVID cases, vs. supply constraints and optimism around vaccines,” he said. Traders also await weekly data on U.S. petroleum supplies due out from the American Petroleum Institute late Tuesday and Energy Information Administration early Wednesday. On average, analysts expect the EIA to report an increase of 100,000 barrels in domestic crude supplies for the week ended Nov. 13, according to a survey from S&P Global Platts. They also forecast a supply climb of 300,000 barrels for gasoline, but expect to see distillate stocks down by 1.8 million barrels for the week. .
WTI Slides After Bigger Than Expected Crude Build - Oil prices ended flat on the day, bouncing back above $41 (after weak retail sales) on the back of OPEC+ headlines: “All participating countries need to be vigilant, proactive and be prepared to act, when necessary, to the requirements of the market,” the panel said in its closing statement after Tuesday’s video conference.Saudi Energy Minister Prince Abdulaziz bin Salman said he could see a light at the end of the tunnel, but the market had some way to go before getting there (and we worry that is the oncoming train of global lockdowns crushing demand once again).“There is still a way to go before we reach the other side of the long-awaited pandemic tunnel,” Prince Abdulaziz said at the opening session of the OPEC+ Joint Ministerial Monitoring Committee’s virtual meeting.“The good news was counterbalanced by a surge in cases in the second wave of infections” and a rush of additional supply from Libya. But for now, the algos will focus on short-term inventories... API:
- Crude +4.174mm (+100k exp)
- Cushing +176k
- Gasoline +256k (+300k exp)
- Distillates -5.024mm (-1.8mm exp)
After the prior week's surprise crude build, analysts expected a very small rise in stocks in the last week (and a small build in gasoline stocks). However, crude stocks rose 4.174mm barrels (notably more than the 100k bump expected)... Graphics Source: Bloomberg “There’s the overhanging doom and gloom of a Covid resurgence and growing concerns about a long-term impact on jet fuel demand,” said Gary Cunningham, director of account management and research at Tradition Energy.“All of it is going to affect overall global consumer demand and that’s a big hit on the economy and a big hit on outlooks for petroleum demand.”WTI bounced back above $41 intraday, hovering around $41.40 ahead of the API print, and slipped lower after the data...
Oil falls as big build in U.S. crude stockpiles raises specter of supply glut - Oil mixed as hopes OPEC+ delays supply increase offset demand concerns Oil prices were mixed on Wednesday as a bigger-than-expected build in U.S. crude stocks and weaker U.S. retail sales stoked fears over fuel demand, although hopes that OPEC and its allies will delay a planned rise in oil output lent support. Brent crude futures for January rose 3 cents, or 0.1%, to $43.78 a barrel by 0430 GMT, while U.S. West Texas Intermediate crude for December eased 3 cents, or 0.1%, to $41.40 a barrel. The American Petroleum Institute (API) said on Tuesday that U.S. crude stockpiles rose by 4.2 million barrels last week, well above analysts' expectations in a Reuters poll for a build of 1.7 million barrels. "The API crude inventories rose much higher than expected, which added to pressure," Disappointing U.S. retail sales also raised concerns over weaker U.S. consumption in light of the Covid-19 resurgence,. U.S. retail sales increased less than expected in October, restrained by spiraling new Covid-19 infections and declining household income as millions of unemployed Americans lose government financial support. To tackle weaker energy demand amid a new wave of the Covid-19 pandemic, Saudi Arabia called on fellow members of the OPEC+ grouping – OPEC and other producers including Russia – to be flexible in responding to oil market needs as it builds the case for a tighter production policy in 2021. "Hopes that OPEC+ will keep existing cuts further into 2021, or even increase the cuts, underpinned prices," OPEC+ held a ministerial committee meeting on Tuesday that made no formal recommendation. The group will hold a full ministerial meeting on Nov. 30 and Dec. 1 to discuss policy. OPEC+ members are leaning towards delaying a previously agreed plan to boost output in January by 2 million barrels per day (bpd), or 2% of global demand, sources told Reuters early this week. Supporting the case for a tighter supply policy next year, OPEC and its allies have revised oil demand scenarios for 2021 with demand seen weaker than previously anticipated, a confidential document seen by Reuters shows.
Oil jumps to 11-week high on hope of OPEC+ supply increase delay - Oil prices firmed by more than 1% on Wednesday on hopes OPEC and its allies will delay a planned increase in oil output and after Pfizer said its COVID-19 vaccine was more effective than previously reported. Brent crude rose 70 cents, or 1.6%, to $44.45 a barrel, while U.S. West Texas Intermediate crude settled 39 cents higher at an 11-week high of $41.82 per barrel. Prices were also supported by a smaller-than-expected increase in U.S. crude stockpiles last week. Both contracts jumped by about $1 after Pfizer Inc said that final results from late-stage trial of its vaccine showed it was 95% effective. Last week it had put the efficacy at more than 90%. Moderna Inc on Monday said that preliminary data for its vaccine also showed it was almost 95% effective. "Oil prices today are modestly rising on hopes that OPEC+ will decide to postpone its planned production increase in January and on the latest vaccine euphoria," To tackle weaker energy demand amid a second wave of the pandemic, Saudi Arabia called on fellow members of the OPEC+ group to be flexible to meet market needs and to be ready to adjust their agreement on output cuts. OPEC+, comprising the Organization of the Petroleum Exporting Countries, Russia and other producers, met on Tuesday but made no formal recommendation. The group is due to discuss policy at a full ministerial meeting to be held on Nov. 30 and Dec. 1. Members of OPEC+ are leaning towards delaying the current plan to boost output in January by 2 million barrels per day (bpd), sources have said. They are considering a possible delay of three or six months. In the United States, crude inventories rose 768,000 barrels last week, compared with analyst expectations in a Reuters poll for a 1.7 million-barrel rise. Distillate stockpiles, which include diesel and heating oil, fell by 5.2 million barrels, far exceeding expectations. "There's concern about gasoline demand, but overall inventories, including diesel stocks, fell, giving credence to the efforts of OPEC+ and reduced overall crude production,"
Oil Prices Decline As Virus Restrictions Mount - -- Oil edged lower with growing virus restrictions and signs the labor-market recovery may be slowing in the U.S. dampens the near-term demand outlook. Futures fell as much as 1.8% in New York before closing little changed as the dollar erased gains late in the trading session, boosting the appeal for commodities priced in the currency. U.S. equities also staged a rally. Oil’s upward momentum seen earlier this week was zapped Thursday after U.S. jobless claims rose for the first time in five weeks, presenting yet another obstacle to a sustained rebound in consumption. With coronavirus cases rising across the U.S., many states are increasing restrictions, while the Centers for Disease Control and Prevention urged Americans not to travel for Thanksgiving.. “This is probably going to be a disappointing travel holiday coming up, and that’s going to weigh on demand.” Oil is still headed for a weekly gain after vaccine developments and signs of demand recovering in Asia boosted optimism over the outlook for consumption in the longer-term. However, as virus cases surge from the U.S. to Europe, the ongoing recovery in oil product global trade flows is slower than previously expected, according to Maersk Tankers Chief Executive Officer Christian M. Ingerslev. West Texas Intermediate for December delivery declined 8 cents to settle at $41.74 a barrel. Brent for January settlement fell 14 cents to end the session at $44.20 a barrel. The shaky demand picture poses a challenge to the Organization of Petroleum Exporting Countries and its allies as they struggle to manage the market. The United Arab Emirates tried to ease a spat with its OPEC+ partners on Thursday, after officials privately questioned the benefit of its membership of the group. The producer group is also dealing with the recent surge in Libyan oil output, which has surpassed 1.25 million barrels a day according to state-run National Oil Corp. Amid the rise in production, France’s Total SE is in talks to increase energy investment in the North African nation.
Oil rises about 1%, posts third week of gains on vaccine hopes - (Reuters) - Oil prices rose about 1% higher on Friday and posted a third consecutive weekly rise, buoyed by successful COVID-19 vaccine trials, while renewed lockdowns in several countries to limit the spread of the coronavirus capped gains. Brent crude futures rose 76 cents, or 1.7%, to settle at $44.96 a barrel. The more active U.S. West Texas Intermediate (WTI) January crude contract gained 52 cents, or 1.2% to $42.42 a barrel. The WTI contract for December, which expired on Friday, rose 41 cents, or 1%, to settle at $42.15 a barrel. Both benchmarks gained about 5% this week. Prospects for effective COVID-19 vaccines have bolstered oil markets this week. Pfizer Inc said it will apply to U.S. health regulators on Friday for emergency use authoritization of its vaccine, the first such application in a major step toward providing protection against the new coronavirus. “Despite the fact that in reality it will take time for a global vaccine campaign to be implemented, time during which oil demand will suffer, positive news are breaking daily about the vaccine deliveries,” said Bjornar Tonhaugen, Rystad Energy’s head of oil markets. Also boosting sentiment was hope that the Organization of the Petroleum Exporting Countries (OPEC), Russia and other producers will keep crude output in check. The group, known as OPEC+, were expected to delay a planned production increase. OPEC+, which meets on Nov. 30 and Dec. 1, is looking at options to delay by at least three months from January the tapering of their 7.7 million barrel per day (bpd) cuts by around 2 million bpd. “An assumed roll-over of current cuts by OPEC+ to Q1 2021 is probably in today’s price of $44 per barrel,” Nordic bank SEB said. Still, smaller Russian oil companies are planning to pump more crude this year despite the output deal as they have little leeway in managing the production of start-up fields, a group representing the producers said.
Aramco Plans U.S. Dollar Bond to Plug Funding Gap – WSJ —Saudi Aramco said Monday it aims to issue a U.S. dollar-denominated bond, as the cash-strapped oil giant cuts jobs, considers asset sales and reviews its expansion plans. Saudi Arabian Oil Co., as the company is officially called, is selling debt even as low oil prices hurt its ability to generate cash for its biggest shareholder, the Saudi government. It is seeking to meet a pledge made last year to pay $75 billion in annual dividends. Aramco in a statement said it hired Goldman Sachs Group Inc., Citigroup Inc., JPMorgan Chase & Co. and Morgan Stanley, among others, to arrange investor calls on Monday ahead of a debt sale. The oil company, which didn’t disclose pricing or how much it will raise, said it plans a multi-tranche bond offering with potential maturities of three, five, 10, 30 and 50 years. The bond issue is likely to raise billions of dollars, and the pricing and size would depend on market conditions, Aramco added. It could be well timed. Investors are hopeful of a global economic recovery after Pfizer Inc. last week said its coronavirus vaccine was 90% effective in trials. Oil prices have rallied since then. Aramco made its debut in the bond markets last year, raising $12 billion and giving global investors access to the world’s biggest oil company for the first time. The sale prospectus also opened the books on Aramco’s once-secretive financials, showing it was then the world’s most profitable company and whetting the appetite for equity investors ahead of last December’s share offering. The company announced the dividend commitment in a bid to lure investors to the initial public offering. But the pledge, combined with low oil prices caused by the pandemic, has forced a restructuring at Aramco and a scramble to raise cash. The IPO also failed to attract international buyers, many of whom were discouraged by what they perceived to be an expensive valuation. On top of raising debt, Aramco is now cutting jobs and reviewing plans to expand at home and abroad, The Wall Street Journal has reported. The company is also considering a sale-and-lease-back agreement for some of its pipeline assets in a deal that could also raise billions of dollars, according to people familiar with the deal. The plan, dubbed “Project Seek,” could involve Aramco selling a stake in its infrastructure to investors who would receive a regular payout from the company as it leases the asset, these people said. Aramco didn’t immediately respond to a request for comment on the project.
Yemeni officials repeat warnings over Safer oil tanker Iran-backed Houthi’s use of naval mines and bomb boats, and the group’s resistance to maintaining the Safer tanker are serious threatens to international maritime traffic and ecological life in the Red Sea, senior Yemeni officials warned on Monday. The officials repeated concerns about the collapse of the tanker, urging the international community to act now to avert a major disaster in the Red Sea. Yemeni Vice President Ali Mohsen Al-Ahmer said that the Yemeni government is still open to all peace initiatives, but the Houthi’s continuing use of land mines and their refusal to allow UN experts to visit the decaying tanker show that they are not serious about peace, state news agency SABA reported. During a meeting with Gov. of Hodeidah Al-Hassan Ali Taher, Al- Ahmer said that the Houthis pose an “increasing” threat to maritime navigation in the Red Sea through their mines and explosive-laden boats that target commercial ships. For months, Yemeni government officials and Western diplomats have pressured the Houthis to allow a team of UN experts access to the tanker to conduct vital maintenance, warning the rebels that they would be held responsible if the tanker crumbled and caused a predicted environmental and humanitarian catastrophe. Loaded with more than 1 million barrels of crude oil, the stranded ship off the western city of Hodeidah has decayed over the last five years due to lack of maintenance. Yemeni Minister of Planning and International Cooperation Dr. Najeeb Al-Ouj on Monday echoed the same concerns about the crumbling of the tanker and potential environmental disaster. SABA quoted the minister as saying that the international community has an “ethical and moral” responsibility to keep pressure on the Houthis until they allow UN experts to board the tanker and assess the damage.
Rockets Target US Embassy In Baghdad Just As Trump Ordered Troop Draw Down -- Coming less than within an hour of President Trump announcing his troop draw down order in Iraq and Afghanistan Tuesday afternoon, a hail of rockets fell near the US embassy in Baghdad. Local and regional reports say at least five rockets were fired on the fortified Green Zone in Iraq's capital and that four struck near the American compound. The US embassy's C-RAM system, or "Counter rocket, artillery, and mortar" defense weapon, was activated in response to the inbound rocket fire. The timing seems clearly intentional, given international headlines at that very moment circulated the US announced plans to reduce its troop levels in Iraq.Trump ordered the Pentagon to accelerate a drawdown of US troops in Afghanistan and Iraq to 2,500 , as the president works to deliver on his longtime pledge to exit from "endless wars" before he leaves office January 20. Current estimates put US troop levels in Iraq at over 3,000. In both Iraq and Afghanistan Trump's advisers have reportedly been urging the commander-in-chief to avoid pulling everyone out, reducing US presence down to 'zero'.
Shocking Images: Fleeing Armenians Burn Own Homes Rather Than Leave Them To Azerbaijan --The Russia-brokered peace deal signed last week between the leaders of Armenia and Azerbaijan at a moment Azerbaijan appeared to have the military upper-hand has held firmly as nearly 2,000 Russia peacekeeping troops are also on the ground in Nagorno-Karabakh.But it's come at a huge cost for the Armenian side in terms of possession of the disputed territory following six weeks of fierce fighting that has left thousands dead and wounded. As part of the truce terms Armenia and Nagorno-Karabakh must return the Armenian ethnic districts of Aghdam, Kalbajar and Lachin to Azerbaijan according to a timeline negotiated under the Russians. It's expected to be completed by December 1, with Armenian armed forces and what Azerbaijan has dubbed "illegal Armenian settlers" initially given just days to withdraw.However, in at least one district Baku has agreed to extend the date for complete handover: "Azerbaijan agreed to prolong the deadline for the withdrawal from Kalbacar of Armenian armed forces and of illegal Armenian settlers until November 25," the office of Azerbaijani President Ilham Aliyev told a news conference this weekend. But Aghdam, Kalbajar and Lachin districts will ultimately see all Armenians gone by Dec. 1, according to the terms.Over the days international media correspondents have observed Armenians living in the Kalbajar district setting fire to their homes as they flee, in order to prevent any Azeri from ever occupying them.The New York Times reported of the shocking scenes: The cars, trucks and vans jamming the mountain roads deep into the night on Saturday brimmed with all the possessions that the fleeing Armenians could rescue: upholstered furniture, livestock, glass doors.As they left, many set their homes on fire, enveloping their exodus in acrid smoke and illuminating it in an orange glow. Near some of the burning houses stood older ruins: the remains of homes abandoned a quarter-century ago, when Azerbaijanis fled and Armenians moved into the region.
Fighting erupts between Morocco and Polisario in Western Sahara - Fighting between Moroccan military forces and the Polisario Front (Popular Front for the Liberation of Saguia el-Hamra and Río de Oro) has broken out after Rabat sent troops to reopen a highway linking Morocco, the Western Sahara and Mauritania that was occupied by protesters. The fighting puts an end to a 1991 ceasefire, risking war between Morocco and Algeria in a region that is a powder keg after US and European imperialism started wars in Libya and Mali. For the past three weeks, dozens of Sahrawi protesters had blocked the Guerguerat border crossing, cutting trade and traffic between Morocco and Mauritania to the south. They were demanding Morocco close a road in the U.N.-patrolled buffer zone and calling for the release of political prisoners. Rabat reacted instead by deploying a brigade of 1,000 men accompanied by 200 vehicles to the region, violating the terms of the ceasefire. This deployment took place hours after US Major General Andrew Rohling met in Agadir with Lieutenant General Belkhir El Farouk, Commander of the Southern Zone of Morocco’s Royal Armed Forces, which includes occupied Western Sahara. They were to discuss preparations for next year’s African Lion military exercise, the largest training exercise involving US troops in Africa. “War has started, the Moroccan side has liquidated the ceasefire,” senior Polisario official Mohamed Salem Ould Salek told AFP. Sidi Omar, the Polisario Front’s representative to the U.N., said of Rabat’s action: “For us, it is an open war.” The Sahara Press Service claimed Polisario had launched attacks for five consecutive days against the Royal Moroccan Army in the Western Sahara, “causing loss of lives and equipment and disrupting its military plans.” In an official statement, King Mohammed VI warned that Morocco “remains firmly determined to react, with the greatest severity, and in self-defence, against any threat to its security.”
No comments:
Post a Comment