Oil, Gas, And Fracking News Reads: 06December 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 05 December 2020. Part 2 is available here.

This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.

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Smallest late November gas draw since 2001; gasoline demand at 24 week low; distillate imports at a 10 year high

Oil prices rose for the 5th week in a row this week after OPEC and other producers cobbled together a compromise on early 2021 oil output cuts after a week of internecine conflict…after rising 7.3% to $45.53 a barrel last week on the belief that one or more of the new vaccines would soon end the pandemic, the contract price of US light sweet crude for January delivery opened lower on Monday on reports of dissatisfaction and fatigue within the OPEC+, oil producers cartel and remained weak ahead of their Tuesday meeting to settle 19 cents lower $45.34 a barrel, following comments that Iraq, Nigeria, the Emirates and Kazakhstan were opposed to the 3 month production cut extension being pushed by the Saudis….oil prices slid further on Tuesday after a Bloomberg report that the Wednesday OPEC meeting had been “rescheduled to Dec 3 as more talks are needed.” and ended down 79 cents at $44.55 a barrel, after a headline that Saudi Arabia was mulling quitting it’s role as co-chair of OPEC and the Joint Ministerial Monitoring Committee…however, oil prices rose on Wednesday as Britain’s approval of a COVID-19 vaccine boosted hopes for a demand recovery and extended their gains on headlines that OPEC+ was making headway towards a deal to finish 73 cents higher at $45.28 a barrel as key OPEC partners worked quietly behind the scenes to repair the damage and resolve the dispute between the Saudis and the Emirates…however, oil prices fell again early on Thursday as Saudi Arabia and Russia locked horns over the need to extend record production cuts set in place in the first wave of the pandemic, but returned to the plus side after OPEC and the other producers agreed on a compromise deal to gradually ease output curbs beginning early next year and finished 36 cents higher $45.64 a barrel…oil continued rising on OPEC deal optimism early Friday and closed up 62 cents at a nine month high of $46.26 a barrel as expectations of a U.S. economic stimulus package and a vaccine for the coronavirus overrode rising supply and record COVID-19 deaths, and thus managed hold on to post a 1.6% gain for the week and log its fifth straight weekly increase ..

On the other hand, natural gas prices fell this week after the EIA reported the smallest late November draw from inventories in nineteen years…after rising 2.6% to $2.843 per mmBTU last week on record LNG exports and vaccine optimism, the contract price of natural gas for January delivery rose 3.9 cents on Monday as more intense winter weather loomed and forecasters predicted colder temperatures and greater heating demand over the first half of December…prices were little changed on Tuesday, finishing at $2.880 per mmBTU, as a report that average natural gas output in the Lower 48 rose to a seven-month high offset record LNG exports, but then fell 10 cents to $2.780 per mmBTU on Wednesday as a balmy turn in the December weather outlook quickly sent prices crashing…natural gas prices then tumbled 27.3 cents, or nearly 10% on the milder weather on Thursday to settle at $2.507 per mmBTU after the EIA reported that users pulled just 1 billion cubic feet of gas from storage during the warmer-than-normal week ended Nov. 27th, the smallest late November draw since 2001…natural gas prices regained their footing on Friday even as weather models continued to add warmth to the outlook, as traders trying to pick a “capitulation bottom” bought back in and pushed prices back up 6.8 cents to finish at $2.575 per mmBTU…but despite that modest Friday recovery, natural gas prices still lost 9.4% on the week, with the January natural gas contract approaching a 9 month low…

The natural gas storage report from the EIA for the week ending November 27th indicated that the quantity of natural gas held in underground storage in the US decreased by 1 billion cubic feet to 3,939 billion cubic feet by the end of the week, which left our gas supplies 343 billion cubic feet, or 9.5% higher than the 3,596 billion cubic feet that were in storage on November 27th of last year, and 290 billion cubic feet, or 7.9% above the five-year average of 3,649 billion cubic feet of natural gas that have been in storage as of the 27th of November in recent years….the billion cubic feet that were drawn out of US natural gas storage this week was less than the average forecast from an S&P Global Platts survey of analysts who expected a 13 billion cubic foot withdrawal, and was also much less that the average withdrawal of 41 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 21 billion cubic feet withdrawal from natural gas storage seen during the corresponding week of 2019….

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 27th indicated that because of the largest increase in our oil exports since early March, we had to withdraw oil from our stored commercial supplies for the 13th time in the past nineteen weeks and for the 19th time in the past forty-six weeks….our imports of crude oil rose by an average of 171,000 barrels per day to an average of 5,399,000 barrels per day, after falling by an average of 26,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 625,000 barrels per day to an average of 3,456,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 1,943,000 barrels of per day during the week ending November 27th, 454,000 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 100,000 barrels per day higher at 11,100,000 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 13,043,000 barrels per day during this reporting week…

US oil refineries reported they were processing 14,012,000 barrels of crude per day during the week ending November 27th, 251,000 fewer 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 total of 97,000 barrels of oil per day were being pulled out of 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, from storage, and from oilfield production was 872,000 barrels per day less than what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+872,000) 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 that 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 5,345,000 barrels per day last week, which was still 10.5% less than the 5,975,000 barrel per day average that we were importing over the same four-week period last year….the 97,000 barrel per day net withdrawal from our total crude inventories was due to a 97,000 barrels per day withdrawal from our commercially available stocks of crude oil, while the oil supplies in our Strategic Petroleum Reserve remained unchanged…..this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 10,600,000 barrels per day, while a 12,000 barrels per day increase to 507,000 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 29th was rounded to 12,900,000 barrels per day, so this reporting week’s rounded oil production figure was 14.0% below that of a year ago, yet still 31.7% 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 78.2% of their capacity while using 14,012,000 barrels of crude per day during the week ending November 27th, down from 78.7% of capacity during the prior week, and excluding the 2005, 2008, and 2017 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the past twenty-eight years…hence, the 14,012,000 barrels per day of oil that were refined this week were 16.6% fewer barrels than the 16,798,000 barrels of crude that were being processed daily during the week ending November 29th of last year, when US refineries were operating at 91.9% of capacity…

With the decrease in the amount of oil being refined, gasoline output from our refineries was again lower, decreasing by 266,000 barrels per day to 8,584,000 barrels per day during the week ending November 27th, after our refineries’ gasoline output had decreased by 214,000 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 13.7% less than the 9,941,000 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) decreased by 21,000 barrels per day to 4,587,000 barrels per day, after our distillates output had increased by 333,000 barrels per day over the prior week….and since it’s also just coming off a three year low, our distillates’ production was still 12.8% less than the 5,263,000 barrels of distillates per day that were being produced during the week ending November 29th, 2019…

Even with the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 8th time in 22 weeks and for the 15th time in 44 weeks, rising by 3,491,000 barrels to 233,638,000 barrels during the week ending November 27th, after our gasoline inventories had increased by 2,180,000 barrels over the prior week…our gasoline supplies increased by more this week because the amount of gasoline supplied to US markets decreased by 156,000 barrels per day to 7,973,000 barrels per day, and because our imports of gasoline rose by 81,000 barrels per day to 522,000 barrels per day, while our exports of gasoline fell by 71,000 barrels per day to 689,000 barrels per day….with now three increases in a row, our gasoline supplies were 1.9% higher than last November 29th’s gasoline inventories of 229,363,000 barrels, and about 4% above the five year average of our gasoline supplies for this time of the year…

Also, even with the decrease in our distillates production, our supplies of distillate fuels increased for the first time in 11 weeks, for the 19th time in 35 weeks and for the 22nd time in the past year, rising by 3,238,000 barrels to 145,870,000 barrels during the week ending November 27th, after our distillates supplies had decreased by 1.441,000 barrels during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 386,000 barrels per day to 3,789,000 barrels per day, and because our imports of distillates rose by 428,000 barrels per day to a ten+ year high of 614,000 barrels per day, while our exports of distillates rose by 124,000 barrels per day to 949,000 barrels per day….after this week’s inventory increase, our distillate supplies at the end of the week were 22.1% above the 119,469,000 barrels of distillates that we had in storage on November 29th, 2019, and about 8% above the five year average of distillates stocks for this time of the year…

Finally, with that big increase in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil in the SPR) fell for the 15th time in the past twenty-five weeks and for the 20th time in the past year, decreasing by 679,000 barrels, from 488,721,000 barrels on November 20th to 488,042,000 barrels on November 27th…after that modest decrease, our commercial crude oil inventories were nearly 7% 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 three 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 27th were 9.2% above the 447,096,000 barrels of oil we had in commercial storage on November 29th of 2019, 10.1% more than the 443,162,000 barrels of oil that we had in storage on November 23rd of 2018, and 8.9% above the 448,103,000 barrels of oil we had in commercial storage on December 1st of 2017…

This Week’s Rig Count

Note: since last week’s rig count was released on Wednesday ahead of the Thanksgiving holiday, this week’s release covers the 9 days to Friday…given that, the US rig count rose for the 11th time in twelve weeks during the period ending December 4th, but for just the 13th time in the past 38 weeks, and hence it is still down by 59.2% over that thirty-eight week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 3 to 323 rigs this past week, which was still by down 476 rigs from the 799 rigs that were in use as of the December 6th report of 2019, and was also 81 fewer rigs than the all time low prior to this year, and 1,606 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 increased by 5 rigs to 246 oil rigs this week, after rising by 10 oil rigs the prior week, leaving us with 417 fewer oil rigs than were running a year ago, and still 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 decreased by 2 to 75 natural gas rigs, which was also down by 58 natural gas rigs from the 133 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, two rigs classified as ‘miscellaneous’ continued to drill this week; one in Lake County, California, and one in the Permian basin in Eddy County, New Mexico…a year ago, there were three such “miscellaneous” rigs deployed…

The Gulf of Mexico rig count increased by 1 rig to 13 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas…that was 9 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….however, in addition to those rigs offshore, two rigs continue to drill through inland bodies of water this week, one in St Mary 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 6 to 289 horizontal rigs this week, which was still 406 fewer horizontal rigs than the 695 horizontal rigs that were in use in the US on December 6th of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the vertical rig count was up by one to 16 vertical rigs this week, but those were still down by 36 from the 52 vertical rigs that were operating during the same week of last year….on the other hand, the directional rig count was down by 4 to 18 directional rigs this week, and those were also down by 34 from the 52 directional rigs that were in use on December 6th 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 December 4th, the second column shows the change in the number of working rigs between last week’s count (November 25th) and this week’s (December 4th) count, the third column shows last week’s November 25th 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 6th of December, 2019…

As you can tell, this week’s changes are more widespread than in recent weeks, when much of the activity had been centered around Texas…checking for the details on the Permian basin in Texas, we find that two rigs were added in Texas Oil District 8, which corresponds to the core Permian Delaware, while other Texas Permian basin districts were unchanged, which thus means that Permian rigs in Texas were up by a total of two…since the Permian basin rig count was up by three rigs nationally, that means that the rig that was added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national Permian increase…elsewhere, the 2 rigs added in Colorado were most likely in the Denver-Julesburg Niobrara chalk, while the rig removed from Wyoming probably came from a basin that Baker Hughes does not track, as did the rig removed from California, which had only directional and vertical rigs running in Kern and Los Angeles counties as of a week ago…also note that the rig added in Louisiana was the oil rig that was added offshore from the state…for natural gas rigs, we have the addition of 2 rigs targeting gas in West Virginia’s Marcellus, while 4 natural gas rigs were removed from Pennsylvania’s Marcellus at the same time, & hence the Marcellus was down by 2 rigs….the Pennsylania rig count is only down by three, however, because a natural gas rig targeting the Utica was added in Beaver county PA at the same time, at a depth that Baker Hughes say is less than 10,000 feet, which is a good trick if they can pull it off…meanwhile, the national natural gas rig count was still down by two because the only natural gas rig that had been drilling in the Eagle Ford of southeastern Texas was shut down this week, while an oil rig targetting the Eagle Ford started up at the same time…

Owners of closed Weathersfield injection well win supreme court case – The Ohio Supreme Court has ruled in favor of a company that has been trying to restart an oil and gas drilling waste disposal well since it was shut down after a 2014 earthquake in Weathersfield.In a 5 to 1 decision, the justices ruled Wednesday on a case brought by American Water Management Services, which claims the Ohio Division of Oil and Gas imposed unreasonable restrictions, prohibiting them from putting it’s well #2 back in service along State Route 169.AWMS was ordered to stop pumping brine into both of its injection wells at the site following a 2.1 magnitude earthquake on August 31, 2014. Injection wells are drilled to hold waste liquids collected during the gas and oil exploration process known as “fracking”. The division allowed operations to resume at a shallower well but kept the second well-closed due to concerns over public safety. In addition to citing the earthquake at the Weathersfield location, state officials cited other seismic activity at two other well operations in the Valley. In support of its decision to keep the well closed, the division noted there were 12 earthquake events between March 2011 to Dec 2011, including a 4.0 magnitude tremor at the Northstar injection well in Youngstown and a 3.0 magnitude earthquake on March 14, 2014, at the Hilcorp wells in Poland. Both the Hilcorp and Northstar wells have since ceased operations. The division cited a study that the Weathersfield well is located near a fault that is like the fault associated with the seismic activity of the Northstar well.In its ruling sending the case back to the 11th District Court of Appeals, the Supreme Court note that AWMS tried on two separate occasions to give the state a plan to restart the well, but was either ignored of rebuffed. The justices concluded that AWMS was justified in pursuing compensation for the investment lost over the years, due to what AWMS believes was the state essentially “taking” their property during the well’s shutdown. AWMS has estimated a loss of more than $20 million because of the closing of the well. The appellate court has been ordered to reconsider the economic impact of the well closing, and whether the state’s suspension of AWMS’s operations constituted a “total taking” by depriving AWMS of all economically beneficial use of the well.

Wolf vetoes conventional oil, natural gas legislation – Gov. Tom Wolf recently vetoed bipartisan legislation that was designed to help strengthen the future of Pennsylvania’s 160-year-old conventional oil and natural gas industry as well as its workforce. Senate Bill 790 would have enacted the Conventional Oil and Gas Wells Act to govern and regulate the conventional, shallow-well oil and gas industry and end unfair industry regulations set by the state’s Department of Environmental Protection (DEP) under Act 13 of 2012, which are supposed to address more impactful unconventional natural gas drilling activities. “There are major differences between unconventional deep-well drilling and conventional, shallow-well drilling … differences that this administration continues to ignore because it doesn’t fit their narrative,” state Rep. Martin Causer (R-Turtlepoint) said on Nov. 25. “The industry is struggling immensely, and a significant cause of that struggle is the lack of understanding and purposeful misrepresentation of how our conventional oil and gas operations work in a safe and environmentally conscious manner.” The legislation passed the House in May with a vote of 109-93. The Senate passed the bill in October 2019 with a vote of 26-23. Following the return of the House amended version, the Senate passed the legislation in November with a vote of 29-19. In his veto statement, Wolf noted that he did not believe the legislation addressed the distinct challenges within the conventional oil and natural gas industry in a manner that would adequately protect the environment or public health and safety. He also stated that the bill would “contribute to a legacy of environmental degradation.”

Pa. DEP advancing new rules for conventional oil wells after veto of industry-backed bill – The Pennsylvania Department of Environmental Protection is pushing ahead to strengthen regulations specific to the state’s conventional oil and gas industry. But first it is trying to win back the industry’s confidence. Proposed updates to the rules have stagnated for more than a year while the industry sought to craft a new – and, in some respects, weaker – law tailored to its operations. That attempt foundered last week when Gov. Tom Wolf vetoed Senate Bill 790, saying it “would contribute to a legacy of environmental degradation.” While the bill aimed to address distinct challenges faced by the conventional oil and gas industry, whose operations are smaller and less expensive than Marcellus and Utica shale drillers’, it also would have rolled back protections for drinking water supplies and public resources, allowed more spills to go unreported and avoided erosion permitting requirements, Mr. Wolf wrote. The governor’s veto was no surprise. Mr. Wolf, a Democrat, vowed to do so in January, when the bill was last amended. The bill passed by the Republican-led House in May and Senate in November contained the same provisions Mr. Wolf and DEP objected to at the start of the year. Still, with the veto fresh in mind, leaders of conventional oil and gas companies, trade groups and their allies in the Legislature called DEP out as untrustworthy on Thursday during an industry-led advisory committee meeting held by video conference. The primary items on the agenda were two sets of rules for waste management and above-ground activities at conventional oil and gas sites that DEP wants to update through its authority under Pennsylvania’s existing environmental laws. “DEP has now chosen to flex their muscles and teach us all a lesson,” said David Clark, president of the Pennsylvania Grade Crude Oil Coalition. “Ramming the most punitive set of regulations on this industry to date, during the worst commodity collapse in 20 years, is appalling.”

Families and advocates criticize Pa.’s fracking health studies – Two state-funded studies to determine whether fracking had anything to do with a group of childhood cancer cases in southwestern Pennsylvania are receiving criticism from advocates for affected families. Gov. Wolf announced the studies last year after pressure from families of cancer patients in Washington County. The state says it will be partnering with an academic institution to conduct the studies, but has not announced which one. But at a recent online ‘town hall’ on the topic, advocates for the families of some of children and young adults who have been diagnosed with Ewing sarcoma, a rare cancer, say they are being cut out of the process of constructing the studies. The department rejected their request to establish a “process overview panel” that would consist of community members and public health experts to advise scientists on how to conduct the studies, said Laura Dagley, a nurse and medical advocacy coordinator with Physicians for Social Responsibility, an environmental health group working with the families. “It would not only provide crucial insight and expertise to the department in the execution of these studies, but we hoped it would go a long way towards building and maintaining trust with the community,” Dagley said. Dagley said the Department of Health officials rejected another request to examine radioactivity in fracking waste as part of the study. “We were told … that the studies were funded at the request of the community to focus on unconventional oil and gas activity, not radioactive waste streams,” Dagley said. “This statement from the Department of Health, it shows a complete lack of understanding of … not only what the community is asking for, (but) a lack of understanding of the radioactivity that is present in oil and gas operations.”Drill cuttings and liquid waste from oil and gas can contain high levels of naturally-occuring radioactive materials, like radium. High levels of radium have been detected in leachate, or runoff, from landfills that accept drill cuttings in Pennsylvania. And scientists recently found airborne radioactivity levels werehigher downwind of fracking sites. Dozens of children and young adults have been diagnosed with Ewing sarcoma and other forms of cancer in a four-county area outside Pittsburgh, where energy companies have drilled more than 3,500 wells since 2008. The cases were first reported by the Pittsburgh Post-Gazette.

Federal agency refuses to extend construction deadline for National Fuel pipeline — National Fuel was premature in requesting an extension of its deadline to complete a new $500 million pipeline to carry natural gas from northern Pennsylvania to Canada through Western New York. The Federal Energy Regulatory Commission on Tuesday rejected the request from National Fuel and its Empire Pipeline subsidiary to push the construction deadline for the Northern Access pipeline from February 2022 to December 2024. Although FERC said it was too soon for the company to ask for such an extension, it rejected National Fuel’s Oct. 16 request “without prejudice,” meaning the company is free to ask again when the question is more timely. “We remain fully committed to this project and, as indicated in the FERC comments, we are able to file again,” National Fuel spokeswoman Karen L. Merkel said. “We’re glad they denied it,” said Diana Strablow, vice chairwoman of the Sierra Club’s Niagara Group. The seven-page FERC ruling noted that 64 comments, all negative, were received during a 15-day public comment period. “I think they had an impact,” Strablow said. The state Department of Environmental Conservation has tried to block the pipeline project by refusing to grant a water quality permit that would allow the 24-inch-wide pipeline to cross 192 streams in Allegany, Cattaraugus and Erie counties. National Fuel has won every lawsuit over the pipeline so far, winning eminent domain rights to take land along the route, overcoming a Pendleton law that would have impeded the construction of two gas compressors in that Niagara County town, and defeating the DEC over its refusal to grant the stream crossing permit. One last lawsuit over the latter issue remains pending before the U.S. Second Circuit Court of Appeals in New York City. In its FERC request, National Fuel referred to the delays caused by litigation as a reason for seeking an extension of the construction deadline. It would have been the second extension. FERC’s original approval for the project in February 2017 gave the company two years to complete it, but in January 2019, FERC granted a three-year extension. Strablow said the project has been pending for so long – it was first announced in 2013 – that National Fuel ought to be required to complete a new environmental impact study. “New York’s climate laws have changed,” Strablow said. “Right now, under the Climate Leadership and Community Protection Act, New York is laying out the implementation plans to transition our state off of fossil fuels. There will be no market for new gas in New York State.” The 97-mile pipeline would carry fracked gas from McKean County, Pa., to connect to an existing Canadian pipeline beneath the Niagara River at Chippawa, Ont.

de Blasio calls for end of Brooklyn natural gas pipeline – Mayor de Blasio has come out against a controversial project to create a natural gas pipeline in northern Brooklyn. “Climate change is an existential threat to our city and we must transition quickly to clean energy,” he said in a Thursday statement. “I am voicing my opposition to National Grid’s North Brooklyn Pipeline because we cannot justify the environmental impacts on the largely Black and Brown residents of Brooklyn associated with an unnecessary pipeline expansion. “Racial and environmental justice go hand-in-hand, and National Grid has failed to clearly demonstrate that this pipeline is needed to keep New Yorkers warm and safe,” Hizzoner concluded. “I am calling on them to withdraw this project immediately.” National Grid broke ground on the project in 2018 and has faced protests from activists and some lawmakers since. The seven-mile pipeline would bring natural gas from Pennsylvania and run from Brownsville, Bedford-Stuyvesant, Bushwick and East Williamsburg to National Grid’s Maspeth Ave. depot. A number of blocks in those areas have already been torn up to make way for the project, according to reports.

Weymouth compressor station to come back online starting Dec. 4 – Crews will soon begin the process of bringing the recently-constructed natural gas compressor back online after two emergency shutdowns at the plant in September prompted federal regulators to halt operations. Max Bergeron, a spokesman for the Canadian company that built the compressor station, said in an email Tuesday that the process of putting the station back in service will start Dec. 4 with oversight from the Pipeline and Hazardous Materials Safety Administration. Bergeron said the process will require the controlled venting of natural gas to remove any air in the piping before the facility is pressurized with natural gas. He said the process is expected to take a few days, and neighbors, first responders and state and local officials have been notified. Bergeron said venting of natural gas may occur intermittently between 7 a.m. and 7 p.m. from Dec. 4 to 11. “The controlled venting of natural gas is a safe and routine procedure, and the gas which is vented will naturally dissipate. Algonquin Gas Transmission representatives will be on site during this work, and monitors that constantly measure the levels of natural gas will be used,” Bergeron said. “We are committed to being good neighbors and operating the compressor station safely and responsibly.” The controversial compressor station is part of Enbridge’s Atlantic Bridge project, which expands the company’s natural gas pipelines from New Jersey into Canada. It has been a point of contention for years among community members, who say it presents serious health and safety problems.

Scuttle N.J. LNG site before Trump rides approval into sunset – In Gloucester County’s Greenwich Township, New Fortress Energy is proposing to build a massive new liquefied natural gas (LNG) terminal, which would create an array of public health and safety risks. To get gas that was fracked in Pennsylvania to the port terminal in Gibbstown, New Fortress plans to use either a fleet of rail cars untested for LNG transport, or rely on hundreds of trucks traveling to and from the site daily. Either scheme could endanger millions of residents along a nearly 200-mile transportation route. The volatile, super-cooled, liquified gas would be loaded onto tankers traveling near Philadelphia International Airport and under the Delaware Memorial Bridge. The threat of a leak or fire represents a potentially deadly risk, especially if the LNG turns into vapor. Even a small ignition source could create a huge fire. Despite these obvious dangers, New Fortress received a special, first-of-its-kind permit from the Trump administration to ship LNG to the site by rail. The special permit has, thus far, evaded the federal oversight normally required for these projects – including an assessment of its cumulative environmental and public safety impacts. The terminal project, known overall as the Gibbstown Logistics Center, could creep one step closer to reality at a Dec. 9 meeting of the Delaware River Basin Commission, the multi-state agency that is tasked with protecting this vital waterway. The commission has been asked to grant a permit for a dock needed to load the gas onto ships for export. The DRBC vote could be the last chance for the Trump administration – the federal government has one seat on the commission – to greenlight this exploitative gas export scheme. While fossil-fuel boosters talk about how drilling gives us a chance to achieve “energy independence,” fracking has already produced a surplus of natural gas, leaving a debt-ridden industry desperately seeking ways to stay afloat. The gas shipped from South Jersey would be exported to other countries, which is all part of New Fortress’ global business model. The company already has a terminal in Florida to send fracked gas to the Caribbean, and has received criticism over a pending contract to supply the fuel to a power authority in Puerto Rico.

Fate of the Mountain Valley Pipeline? -It wasn’t that long ago that Virginia was slated for not one, but two, new natural gas pipelines. Dominion Energy recently scrapped its plan for the Atlantic Coast Pipeline, citing high costs and a pivot to more renewable energy in its portfolio. And that has people wondering about the fate of the Mountain Valley Pipeline as construction delays mount and costs rise.The pandemic has cut demand for energy and led to lower prices. But utilities and private energy companies take the long view. These projects are years in the planning and not easy to alter, for a myriad of reasons, once the ball is rolling.”A lot of money has been spent on this one, ” says Roger Conrad, an energy industry analyst in northern Virginia. He says it wasn’t clear, in Mountain Valley Pipeline’s most recent earnings call, exactly how close to completion it is. “But, previously we’d heard numbers like 93%, complete, implying that all they had to do is just overcome a couple of additional regulatory hurdles, procedural things, and then they could get this thing completed.”But obstacles remain, from stream crossing permits in limbo to tenacious tree sitters protesting the pipeline in one small section of its path in Montgomery County. And perhaps the biggest hurdle of all: The mounting financial costs as time goes by.Conrad says he thinks it’s “kind of extraordinary” that the company did announce it’s expected costs for completion.”A lot of people would be familiar with these figures already: They increased the mid-point of what they thought their costs would be. But they also are now talking about a 2021 startup date, which of course is pretty amorphous as well.”The initial plan had completion by the end of 2018, at a cost of around $3 billion. The new estimate is $5.8 to $6 billion.Conrads sees “a lot of uncertainty, the longer it takes to get the work completed and the pipeline open. The lesson has been pretty clear that, (the uncertainty reduces odds that (the Mountain Valley Pipeline) actually does, eventually operate.” More confident that the pipeline will go into service as planned is the Independent Oil and Gas Association of West Virginia. Executive Director, Charlie Burd, said in a statement: “The importance of the MVP to West Virginia, in terms of infrastructure investment, jobs, tax revenues generated at local county and state level, cannot be overestimated.”Conrad also believes there will be a strong market for gas from the Mountain Valley Pipeline; plenty of buyers, at potentially lower than normal cost.But there’s been a shift in the wind on energy production during the time it’s taken to build the MVP”That of course, is the electric industry itself. Every year, the Edison Electric Institute has an annual meeting where they get together, it’s for financial analysts to interact. But what you hear there is, the emphasis on ‘energy transition,’ which means more renewables and (ESG) Environmental Social Governance. These are things you didn’t hear about at all just a few years ago but now that the industry has made a full pivot in that direction.”

Federal appeals court explains stay of Mountain Valley Pipeline waterbody construction | News | herald-dispatch.com – The 4th U.S. Circuit Court of Appeals issued an opinion Tuesday explaining a stay of construction of the Mountain Valley Pipeline across about 1,000 waterbodies in West Virginia and Virginia that it granted last month, stating the U.S. Army Corps of Engineers’ approval of water permitting for the project was likely illegal.The court’s Nov. 9 stay will remain in effect until it decides whether to overturn water permitting from the U.S. Army Corps of Engineers for the project, designed to be a 303-mile natural gas pipeline system traveling from Northwestern West Virginia to Southern Virginia crossing Wetzel, Harrison, Doddridge, Lewis, Braxton, Webster, Nicholas, Greenbrier, Fayette, Summers and Monroe counties in the Mountain State.Environmental groups, including the Sierra Club, the West Virginia Rivers Coalition and the West Virginia Highlands Conservancy, challenged the corps’ September re-issuance of Nationwide Permit 12 approval. The 4th Circuit had, in 2018, vacated a previous version of the NWP 12 verification issued by the Corps of Engineers’ Huntington District the previous year.But the court said the environmental groups were unlikely to succeed in their challenges of the corps issuance of the 2017 NWP 12 because it probably lacks jurisdiction to consider the challenge.Under NWP 12, projects do not need separate permits for individual waterbodies. By operating under that federal permit, the MVP would not have to go through the more time-consuming process of obtaining individual permits for specific projects under the Clean Water Act.In its opinion, the court highlighted what it viewed as the West Virginia Department of Environmental Protection’s lack of authority to walk back a water permitting condition it adopted.The DEP imposed a special condition as part of its 2017 certification of NWP 12 stipulating that individual state water quality certification is required for pipelines equal to or greater than 36 inches in diameter or pipelines that cross a river regulated by the federal Rivers and Harbors Act of 1899. The MVP is greater than 36 inches in diameter and is designed to run through three such rivers: the Elk, the Gauley and the Greenbrier.The DEP later purported to waive its requirement that the pipeline obtain an individual water quality certification, but the court ruled the DEP had to engage in proper notice and comment procedures before it could waive the requirement and vacated the Huntington District verification for that reason.

Virginia Lawmaker Coordinated Support for Mountain Valley Pipeline With Project’s Lobbyist – — A Virginia state lawmaker coordinated with an energy lobbyist to support a controversial gas pipeline, the Energy and Policy Institute has found. Delegate Les Adams, a Republican representing Henry and Pittsylvania Counties, coordinated his official letter to the federal government with an oil and gas lobbyist who works for the pipeline’s proponent. In September, Adams wrote a letter to the Federal Energy Regulatory Commission (FERC) in support of Mountain Valley Pipeline’s request for an extension of the project’s in-service date. FERC approved the 300-mile pipeline in 2017, but its completion has stalled due to legal battles, as well as ongoing opposition from landowners and environmental activists. The pipeline is a joint venture of energy and utility companies, including Equitrans, NextEra, Con Edison, WGL Midstream, and RGC Midstream. If completed, it will bring fracked gas from West Virginia to southern Virginia. The letter Adams submitted to FERC, which has been reviewed by the Energy and Policy Institute, shows that he carbon copied Maurice Royster. Royster is a veteran Tennessee-based fossil fuel lobbyist who is registered in Virginia to lobby for Equitrans, the main stakeholder in the pipeline. In a phone conversation with the Energy and Policy Institute, Royster acknowledged he discussed the matter with Adams. “You know, I probably talked to him,” Royster said, adding that he’s spoken to a number of Virginia state lawmakers during the comment period as part of his advocacy for the pipeline. Asked if he provided Adams with a template letter, Royster said he did not. Delegate Adams did not respond to a request for comment.

Eastern Shore gas pipeline project gets key environmental approval from Maryland’s Board of Public Works – Baltimore Sun — The Maryland Board of Public Works voted Wednesday to approve a key environmental license for an Eastern Shore pipeline project that would extend natural gas service to Somerset County – particularly to the University of Maryland Eastern Shore and the Eastern Correctional Institute.The nearly 7-mile buried pipeline has received fierce opposition from environmentalists, who say constructing it would mean disregarding the state’s commitment to renewable energy. Local advocates, meanwhile, argue that Somerset County, one of the state’s poorest, deserves access to natural gas infrastructure so it can attract meaningful economic development. Further, they say natural gas would mean greener energy for both the university and prison, which currently use dirtier fuels like propane.

January Natural Gas Futures Climb as Winter Weather Moves in and Cash Prices Jump – The January Nymex contract rose 3.9 cents day/day to settle at $2.882/MMBtu after taking over as the prompt month following the Thanksgiving holiday. February advanced 3.3 cents to $2.865. NGI’s Spot Gas National Avg. soared 60.5 cents to $2.825 as temperatures were colder to start the week across the nation’s midsection following benign weather over the long holiday weekend. Chilly rains doused swaths of the East. For futures, Bespoke Weather Services said the potential for a winter freeze after a warm November appeared to be the leading “catalyst for the move higher” Monday. “The pattern depicted as we move toward the middle of the month is one that hints at drawing some stronger cold out of Canada into the U.S. pattern,” the forecaster said. “Any true cold could target the middle of the nation most, as the pattern shifts more toward a typical La Nina state.” EBW Analytics Group said that, “following exceedingly mild weather in mid-November and the Thanksgiving holiday,” even briefly cooler temperatures to start the week “may allow weather-driven demand this week to springboard 10.0 Bcf/d higher” week/week. Additionally, a “seasonal progression towards colder temperatures” before mid-December, could drive gas demand “another 8.5 Bcf/d higher next week.” Liquefied natural gas (LNG) volumes hung above 10 Bcf Monday, near an all-time high, while production levels were stable from the prior week. Genscape Inc. estimated LNG feed gas demand of 10.14 Bcf/d for Monday’s gas day, a 176 MMcf/d day/day increase to start the week. “Interstate pipeline feed gas nominations have averaged 9.40 Bcf/d over the past seven days,” Genscape analyst Allison Hurley said Monday. “Demand from facilities on the Gulf Coast accounted for 9.14 Bcf/d,” while the Cove Point and Elba Island LNG facilities “combined for the remaining 1 Bcf/d.” Amid the shift in weather, analysts are anticipating a second consecutive withdrawal with this week’s Energy Information Administration (EIA) storage report. Bespoke, for one, models a 25 Bcf pull from gas stockpiles for the week ended Nov. 27.

US natgas little changed as lower demand offsets record LNG exports – US natural gas futures held steady on Tuesday as forecasts for lower demand over the next two weeks offset an increase in liquefied natural gas (LNG) exports to a fresh record high. Front-month gas futures fell 0.2 cents, or 0.1%, to settle at $2.880 per million British thermal units. Data provider Refinitiv said average output in the Lower 48 US states rose to a seven-month high of 91.0 billion cubic feet per day (bcfd) in November, up from 87.8 bcfd in October. Traders said some of that output increase was due to higher oil prices. Oil futures gained about 27% in November on expectations global energy demand and economic activity would rebound in 2021 once coronavirus vaccines become widely available. Rising oil prices over the last few months encouraged energy firms to drill for more crude. Those oil wells also produce a lot of associated gas. With a seasonal cooling of the weather, Refinitiv projected demand, including exports, would rise from 112.9 bcfd this week to 115.6 bcfd next week. But that was lower than Refinitiv forecast on Monday. The amount of gas flowing to US LNG export plants averaged a record 9.9 bcfd in November, up from 7.7 bcfd in October, as rising prices in Europe and Asia in recent months prompted global buyers to purchase more US gas. That tops the 9.8-bcfd US LNG export capacity and the prior all-time monthly high of 8.7 bcfd in February, which was before buyers started canceling cargoes due to coronavirus demand destruction. LNG plants can pull in a little more gas than they can export since they use some of the fuel to run the facility. In addition, the third liquefaction train at Cheniere Energy Inc’s Corpus Christi plant in Texas is pulling in gas as it prepares to enter commercial service.

US working natural gas volumes in underground storage fall 1 Bcf: EIA | S&P Global Platts – US natural gas in storage fell only 1 Bcf during the week that featured the Thanksgiving holiday in the US, drawing down Henry Hub futures further, but withdrawals should return to more normal levels in the weeks ahead on the back of cooler weather. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Storage inventories dipped to 3.939 Tcf for the week ended Nov. 27, the US Energy Information Administration reported the morning of Dec. 3. The withdrawal was less than an S&P Global Platts’ survey of analysts calling for a 13 Bcf pull. Responses to the survey ranged from a 4 Bcf injection to a 23 Bcf withdrawal. The build was also well below the 21 Bcf draw reported during the same week a year ago as well as the five-year average withdrawal of 41 Bcf, according to EIA data. Mild temperatures interacted with the demand-draining Thanksgiving holiday weekend. As a result, total demand dropped 1.4 Bcf/d week on week, with residential-commercial making up most of that decline, according to Platts Analytics. Total supply did not follow demand lower, increasing the implied looseness observed in the EIA report. Domestic production rose 1.1 Bcf/d, led by the Northeast, Southeast, and Texas. Storage volumes now stand 343 Bcf, or 11.5%, above the year-ago level of 3.596 Tcf and 290 Bcf, or 8%, above the five-year average of 3.649 Tcf. Gas prices tumbled this week, with the prompt-month January contract leading the dive. Entering the report, the January contract was off more than 8% day on day – down to a multi-month low near $2.54/MMBtu and marking a near $1.00/MMBtu contraction in price over the past month as very mild temperatures in November and concerns over the weather in December have sparked a massive liquidation in speculative length, according to Platts Analytics. After the report was issued at 10:30 am ET, prices pared some of the declines, rising near $2.57/MMBtu as some market participants feared an injection would be reported. Nevertheless, with the January contract now trading at a discount to the February contract and peak summer months, the winter premium has now completely vanished. Platts Analytics’ supply and demand model currently forecasts an 85 Bcf withdrawal for the week ending Dec. 4, which would shrink the surplus versus the five-year average by 24 Bcf as cooler weather spikes US-level demand week on week. Colder weather and a return from the Thanksgiving holiday pushed demand up 9 Bcf/d on the week. The following week’s draw should near triple digits if weather forecasts hold true.

US natural gas futures drop on milder weather – US natural gas futures dropped almost 10% to an eight-week low on Thursday on forecasts for milder weather in mid-December than previously expected and a smaller-than-expected storage draw last week. The price plunge came despite record liquefied natural gas (LNG) exports. The US Energy Information Administration (EIA) said US utilities pulled just 1 billion cubic feet (bcf) of gas from storage during the warmer-than-normal week ended Nov. 27. That was less than the 12-bcf decline analysts forecast in a Reuters poll and compares with a decrease of 22 bcf during the same week last year and a five-year (2015-19) average withdrawal of 41 bcf. “Today’s warm shift in weather forecasts and an exceedingly bearish, marginal storage withdrawal may be the final nail in the coffin for the 2020-21 winter trade,” said Daniel Myers, market analyst at Gelber & Associates in Houston. Front-month gas futures for January delivery fell 27.3 cents, or 9.8%, to settle at $2.507 per million British thermal units, their lowest close since Oct. 2 and their biggest daily percentage drop since November 16. That price collapse put futures for February over January for the first time since the contracts started trading in 2009. Refinitiv said output in the Lower 48 US states averaged 91.0 billion cubic feet per day (bcfd) so far in December, flat with November’s seven-month high but well below the all-time monthly high of 95.4 bcfd in November 2019.

Natural Gas Longs Scurry for Exits, Send Forward Prices Crashing Lower – Natural Gas Intelligence – Wrapping up one of the warmest Novembers in U.S. history, natural gas winter forward prices plunged during the Nov. 25-Dec. 2 period as the weather outlook for December grew milder, according to NGI’s Forward Look. January prices averaged 18.0 cents lower over the period, which included the extended Thanksgiving holiday, while the balance of winter (January-March) tumbled an average 16.0 cents. Losses extended through the rest of the curve but were less pronounced, with the summer 2021 strip (April-October) falling 6.0 cents on average and the winter 2021-2022 sliding 7.0 cents on average, Forward Look data showed. At the heart of the retreat is an increasingly warm outlook for December. The coming two-week span is generally forecast for moderate temperatures across much of the country. There were hopes of a mid-month cold front, however, Wednesday’s weather models lessened those chances and subsequent runs deteriorated the outlook even further. Even with other more supportive factors weighing on the market, the balmy turn in the December outlook quickly sent futures prices crashing. The January Nymex settled Wednesday at $2.780, off 10 cents day/day and off 18 cents from Nov. 25. A fair price prior to Wednesday’s midday weather model runs was “easily $3.00,” according to Lovern, but the market could never get there. That fight got a little tougher on Thursday when the Energy Information Administration (EIA) reported a measly 1 Bcf withdrawal from storage inventories for the week ending Nov. 27, which was more than 10 Bcf lower than consensus. The reference period included the Thanksgiving holiday, which always makes estimating the storage change a bit more difficult. But it also factored in millions of people staying home for the holidays and strong global gas demand in key U.S. export markets. Lovern said the EIA’s 1 Bcf draw is “very weak, even factoring in the holiday.” Participants on The Desk’s online chat Enelyst noted the EIA figure indicates the market is nowhere close to tight.. Ahead of Thursday’s EIA report, consensus had built around a draw in the mid- to high teens Bcf range. The EIA’s 1 Bcf draw compares with a 22 Bcf pull last year and the five-year 41 Bcf average draw. Broken down by region, the Midwest reported an 11 Bcf withdrawal from storage, while the Mountain and Pacific regions each notched a 2 Bcf decline in inventories, according to EIA. The East reported no change in stocks, and the South Central added a whopping 14 Bcf. This included 12 Bcf into salt facilities and 2 Bcf into nonsalts. Total working gas in storage as of Nov. 27 stood at 3,939 Bcf, which is 343 Bcf higher than year-ago levels and 290 Bcf above the five-year average, EIA said.

Natural Gas Futures Regain Pulse Following Massacre, but Weather Looks ‘Increasingly Unfriendly’ -After Thursday’s bloodbath, natural gas futures rebounded a bit on Friday even as weather models continued to add warmth to the December outlook. The January Nymex gas futures contract finished the week at $2.575/MMBtu, up 6.8 cents day/day. February picked up 7.1 cents to reach $2.586. Spot gas prices were mixed, with the most notable changes occurring in the Northeast ahead of a quick-moving cold blast. NGI’s Spot Gas National Avg. picked up 5.5 cents to $2.530. Natural gas traders waking up Friday morning may have had their heads still spinning from Thursday’s dizzying tumble in the futures markets. The prompt month was down nearly 20 cents soon after the open in what EBW Analytics Group characterized as “panic-selling” after the latest weather models trended even warmer for December. January went on to settle at $2.507. Friday’s action was a bit less volatile. After the carnage of the last two days, Bespoke Weather Services said it may become popular to try to determine if it was a “capitulation bottom,” but picking tops and bottoms in any market is “inherently very difficult.” While Thursday’s move was clearly about much more than weather, the moves in the weather pattern were looking “increasingly unfriendly” to bulls yet again, Bespoke said, as the positive Eastern Pacific Oscillation’s return increased the risk for more demand losses to come. The increasingly mild December forecast doesn’t bode well for plump storage inventories that have struggled to shed some of the weight amassed during the summer. After an early start to the traditional withdrawal season, the market since then has recorded a couple of weeks with little change in stocks and some weeks with injections. On Thursday, the Energy Information Administration (EIA) reported a meager 1 Bcf draw from inventories for the week ending Nov. 27, which included Thanksgiving. While a small draw was to be expected given the holiday week, the 1 Bcf pull was more than 10 Bcf lower than the consensus draw. Compared to degree days and normal seasonality, including around 14 Bcf of holiday impact, the reported withdrawal appeared loose versus the prior five-year average by around 0.5 Bcf/d, according to Genscape Inc.

State extends Enbridge Line 5 tunnel application review to January – The Michigan Department of Environment, Great Lakes, and Energy (EGLE) is extending its review of Enbridge Energy’s permit applications to build a utility tunnel and house a new section of the controversial Line 5 oil pipeline under the bedrock of the Straits of Mackinac. The department now plans to issue a decision in January 2021. Scott Dean, spokesman for EGLE, said the department has to review close to 2,800 comments submitted to the department, along with around 400 comments given verbally during public meetings. “EGLE is still carefully considering the thousands of public comments on these applications in addition to the report we received in November from the State Historic Preservation Office,” Dean said. “Given the significant amount of public participation and state agency input related to these permit applications, we thought it reasonable to request an extension from the applicant and they agreed.” Enbridge has agreed to the extension despite ongoing battles with the state over the use of the current 67-year-old line that carries oil and natural gas liquids from Wisconsin to Ontario, across both Michigan peninsulas, with part going through the Straits of Mackinac. Gov. Gretchen Whitmer recently ordered Enbridge to shut down Line 5. She said the Canadian company has violated its 1953 easement multiple times, and that the state has a duty to protect the Great Lakes. Whitmer has given Enbridge until May 2021 to shut it down – well before the proposed tunnel would be finished.In turn, Enbridge sued the state, accusing Whitmer of violating the U.S. Constitution by revoking the easement, and asking a federal judge to block the order.The tunnel project was started in 2018 when Republican Rick Snyder was governor. It has been a point of contention for Whitmer and Attorney General Dana Nessel’s administrations, with Nessel involved in an ongoing lawsuit to overturn the tunnel agreement.Enbridge has a sea of permits to collect before it can begin the project. EGLE is debating whether to grant a National Pollutant Discharge Elimination System Wastewater permit. The company needs the permit for the construction and post-construction phases of the project because of water being taken out of and going into the Straits as a result of the tunnel.Enbridge has also requested a permit from EGLE involving the impact on potential wetlands.There is also Enbridge’s permit request with the Michigan Public Service Commission (MPSC). The MPSC will consider Enbridge’s request to “site” the line, meaning it needs permission to replace and relocate the portion of Line 5 that runs under the Straits. The MPSC permit is expected to be ruled on in the summer of 2021.

Once-Ignored Promises to Tribes Could Change the Environmental Landscape – Last month, Michigan officials announced plans to shut down a controversial oil pipeline that runs below the Great Lakes at the Straits of Mackinac. Governor Gretchen Whitmer and Attorney General Dana Nessel, both Democrats, cited several reasons for the decision, including one that got the attention of tribal leaders in Michigan who have been fighting the pipeline for years. In the shutdown order, Whitmer referenced an 1836 treaty in which tribal nations ceded more than a third of the territory that would become Michigan in exchange for the right to hunt and fish on the land in perpetuity. An oil spill from the pipeline would destroy the state’s ability to honor that right, Whitmer said. Federal and state officials signed nearly 400 treaties with tribal nations in the 18th and 19th centuries. Threatened by genocidal violence, the tribes signed away much of their land. But they secured promises that they could continue to hunt, fish and gather wild food on the territory they were giving up. Many treaties also include cash payments, mineral rights and promises of health care and education. For the most part, the U.S. has ignored its obligations. Game wardens have targeted and arrested tribal members seeking to exercise their hunting and fishing rights. Governments and private interests have logged and developed on hunting grounds, blocked and polluted waterways with dams and destroyed vast beds of wild rice. If Native treaty rights had been honored, the natural landscape of the U.S. might look very different today. In recent years, some courts, political leaders and regulators have decided it’s time to start honoring those treaty obligations. Some legal experts think that asserting these rights could prevent – or even reverse – environmental degradation. . “It is always a struggle to get state governments to recognize the existence of our treaties, our rights and their responsibilities to not impair those rights,” Bryan Newland, chair of the Bay Mills Indian Community in Michigan’s Upper Peninsula, said . “It’s not enough to recognize our right to harvest. State governments have a responsibility to stop harming and degrading this fishery. This was a big step in tribal-state relations.” Attorney Bill Rastetter, who represents the Grand Traverse Band of Ottawa and Chippewa Indians, another Michigan tribe, said tribal members invoking a treaty can make a stronger legal claim than non-Native citizens raising the same issue as an environmental complaint. “With environmental claims, there is sometimes a balancing test that’s applied between the potential harm and potential good,” said Rastetter, who has been part of efforts opposing the pipeline in Michigan. “But when you’re dealing with the diminishment of a right reserved by tribes, there ought not to be that balancing test.” Still, tribes have mostly used treaty rights claims to play defense against new infringements by developers and polluters. Some tribal members say new treaty violations are surfacing faster than old ones are being corrected. Some legal experts are also wary about making sweeping treaty assertions, for fear that coming up short could set a dangerous precedent. “There’s been an effort to try to be careful about what you give a court the chance to decide,” Rastetter said. “If they decide against you, you might not get another bite at the apple. We have to not just have a claim, but we have to go through the pragmatic analysis of how it may work out.”

Enbridge sues Michigan over Line 5 shutdown order — Enbridge Energy is suing the State of Michigan in federal court in hopes of thwarting Michigan Gov. Gretchen Whitmer’s quest to shut down the Line 5 petroleum pipeline.The Canadian company’s filing in the U.S. District Court for the Western District of Michigan seeks an injunction against Whitmer’s shutdown orders. The suit repeats a familiar argument the company has made in past disputes with the state: that federal regulators with the U.S. Pipeline and Hazardous Materials Safety Administration are in charge of pipeline safety, not the state of Michigan. As a result, Enbridge argues, Michigan has no authority to shut down Line 5 over alleged safety concerns.”The attempt to shut down Line 5 interferes with the comprehensive federal regulation of pipeline safety and burdens interstate and foreign commerce in clear violation of federal law and the US Constitution,” an announcement from the company states. In its filing, the company argued Michigan’s shutdown order interferes with federal authority in a way that “would create a disturbing precedent” and encourage “copycat” actions in other states.The move follows Whitmer’s Nov. 13 announcement that she has ordered Enbridge to shut down the pipeline running across the bottom of the Straits of Mackinac by May for fear that its continued operation would pose an unacceptable oil spill risk in the Great Lakes. Whitmer ordered the shutdown after a state Department of Natural Resources review concluded Enbridge has violated the terms of the state easement that grants the company permission to operate Line 5 in the lake bottom of the Straits. The DNR review also concluded the easement should never have been granted, because allowing Line 5 to operate in the straits violates the public’s overriding interest in protecting the Great Lakes. As a result, Whitmer notified Enbridge that the state is revoking and terminating the easement. In conjunction with Whitmer’s order, Michigan Attorney General Dana Nessel sued Enbridge in Ingham County Circuit Court, seeking legal reinforcement of Whitmer’s decision. With Tuesday’s filing, Enbridge also filed paperwork seeking to remove the state’s Ingham County lawsuit to federal court. A spokesman for Nessel’s office said only that state lawyers have not yet had a chance to review the filing. “Once we do, we will discuss it with our clients and determine the appropriate next steps,”

Michigan Express Pipeline project aims to secure propane supply -A Plan B for Michigan’s propane supply scene is the top priority of a new energy and renewables infrastructure company called Silver Wolf Midstream. Niel Rootare, a business development executive with a career focus in energy, formed Silver Wolf Midstream earlier this year with the goal of acquiring and repurposing a natural gas pipeline in Michigan for propane supply and distribution throughout much of the state. “This project was begging to get done somehow,” Rootare says. “The truth is, there was not going to be a viable propane pipeline solution if it had to be built new.” Instead, Silver Wolf Midstream is in the final stages of securing an existing 225-mile, 8-in. coated steel line, which it’s naming the Michigan Express Pipeline. Shell Oil Co. had built the natural gas pipeline in 1974 to transport ethane, Rootare explains, but market demand for ethane in the area waned in recent years due to new product sources coming online, including in the Marcellus and Utica shale regions of Ohio and Pennsylvania. With Michigan among the largest propane-consuming states in the U.S. and with ongoing governmental threats to Enbridge’s Line 5 natural gas liquids and light crude oil pipeline that has run under the Straits of Mackinac since 1953, Rootare saw the need to enhance propane’s distribution channels locally. “The Line 5 discussion created this anxiety and question around propane security and supply in the state of Michigan,” Rootare says. “What’s our Plan B? I can talk about Plan B, and that’s what I think this is. It’s highlighted the need for a project like this to come to fruition.” Once it closes on the pipeline acquisition, expected before year’s end, Silver Wolf Midstream looks to undertake the capital expenditures portion of the project. The effort includes the installation of pumping stations and additional terminal locations before the company begins to flow propane in the third quarter of 2021, Rootare says. The Michigan Express Pipeline will feature three locations where trucks can load propane: an existing terminal in Kalkaska, at the northern end of the pipeline, and additional terminals are planned in Nelson and Farwell, in the center of the state. “They were strategically placed based on consumption models for the market and accessibility for trucks,” Rootare says. Once online, the pipeline will have a volume capacity of 500,000 gallons per day in the first year, with expectations for growth, Rootare says. He also estimates the pipeline will supply 65 million gallons of propane to the market in that first year.

Comin’ to America, Part 3 – PADD 2 Refineries Continue a Years-Long Shift to Canadian Crude | RBN Energy — Fifteen years ago, just before the dawn of the Shale Era, more than 1.8 MMb/d of Gulf Coast and imported crude oil was being piped and barged north from PADD 3 to refineries in the Midwest. By 2019, those northbound flows had fallen by half, to less than 930 Mb/d, and in the first nine months of this year they averaged only 550 Mb/d. Refineries in PADD 2, many now equipped with cokers and other hardware that enables them to break down heavy, sour crude into valuable refined products, have replaced those barrels – and more – with piped- and railed-in imports of favorably priced crude from Western Canada, including a lot of dilbit and railbit from Alberta’s oil sands. Today, we discuss the evolution of feedstock supply to the Midwest refinery sector. This is the third episode in our series on the changing face of U.S. crude oil imports in each of the five PADDs. InPart 1, we said that the Shale Revolution, combined with the development of the oil sands and other hydrocarbon resources in Western Canada, led to a dramatic decline in U.S. oil receipts from OPEC countries in particular and, to a lesser extent, from non-OPEC countries (other than Canada), and a big increase in imports from Canada. In 2005, the U.S. imported an average of 4.8 MMb/d from OPEC, 1.6 MMb/d from Canada, and 3.7 MMb/d from other non-OPEC countries, including 1.6 MMb/d from Mexico, according to the Energy Information Administration (EIA). By last year, imports from OPEC had decreased by almost 70%, to 1.5 MMb/d, while imports from Canada had increased by more than 135% to 3.8 MMb/d. Imports from other non-OPEC countries, in turn, had fallen by almost 60% to 1.5 MMb/d, and imports from Mexico – a subset of the non-OPEC countries – had plummeted by more than 60%, to about 600 Mb/d. In Part 2, we zeroed in on PADD 1, which is quirky from a refining perspective in that it produces virtually no oil (about 70 Mb/d, on average, so far in 2020, much of it superlight oil or condensate), and that nearly all of the oil refined there – domestic or imported – needs to be delivered by railroad tank cars or ships. We noted that refinery demand for oil in PADD 1 averaged around 1.1 MMb/d for most of the past decade, but has plummeted by half (to less than 600 Mb/d) due to a combination of the June 2019 closure of the 335-Mb/d Philadelphia Energy Solutions (PES) refinery (after an explosion and fire) and the demand-destroying effects of COVID-19. As for PADD 1’s sources of oil supply, that jumped around through the 2010s, from almost 100% imports in 2010-12 to a mix of imports and railed-in Bakken crude in 2013-15, then back to a preponderance of imports in the latter years of the decade – all in an effort to maximize the refiners’ profitability. East Coast refineries generally lack the sophisticated, complex equipment to break down heavy crude slates into refined products, but the situation is quite different in PADD 2, whose oil imports, refineries, and crude slates are the focus of today’s blog.

Another Pipeline Hits Regulator Roadblock – Virginia Natural Gas had hoped to expand its network to supply a power plant in Charles City County, southeast of Richmond, – a plant that has not yet been built. Chesapeake Bay Foundation lawyer Taylor Lilley argued against the project. “Virginia Natural Gas was proposing a 6-part project. It was going to include three segments of pipeline adding up to about 24.1 miles total and then three compressor stations – the construction of two new ones and the expansion of an existing one.” She told the State Corporation Commission that the project would threaten 153 acres of wetlands and 313 acres of forest. The utility could apply again for a Certificate of Public Convenience and Necessity, but Lilley says making its case will be even more difficult. “They are going to be doing that in a much different regulatory landscape than they were when they first submitted this application. Virginia now has an environmental justice act, the Clean Economy Act and a new energy plan, all of which are very black and white about how the Commonwealth feels about environmental justice, its role in decisionmaking, and also the future that the Commonwealth sees as far as its energy portfolio. Quite frankly, it doesn’t seem to include infrastructure like Virginia Natural Gas’s Header Improvement Project.” The Chesapeake Bay Foundation also argued that the pipeline expansion would put an undue burden on low income communities already stuck with a landfill and two compressor stations by further polluting the air in the city of Chesapeake, Prince William, Fauquier, Caroline, Hanover, Henrico, New Kent and Charles City Counties.

Piedmont halts north Greenville gas pipeline plans after outcry, will assess other routes — When Matt Craft found out that a proposed Piedmont Natural Gas pipeline wanted an easement across the back half of his five acres in the Travelers Rest area, he vowed to fight. The company wanted at least a 50-foot right of way and told him his long driveway could also be an access road to the pipeline if it were built. That would have put a pipeline near his son’s tree fort and made the back half of his land unusable for building, an idea he and his wife had kicked around. So he and his neighbors started to organize. They saw it as a David vs. Goliath matchup of a few dozen landowners against Duke Energy, a multibillion-dollar utility company that owns Piedmont Natural Gas. So when Craft got a call the day after Thanksgiving from Brooks Smith, another landowner, telling him she received a letter from Piedmont Natural Gas informing her the company would not use her 18-acre homestead for the pipeline, he jumped in his truck and drove straight to his mailbox. He ripped open an envelope and found he won, too. Piedmont had reconsidered and wouldn’t use his property. “I almost started crying,” Craft said. It was a spark of good news in an otherwise difficult year, he said. In all, more than 30 property owners along a proposed route for a new 10- to 14-mile natural gas transmission pipeline have received letters from Piedmont that the company determined their land was no longer being considered for the new line. Those receiving letters included landowners at each proposed terminus of the project, meaning the company has canceled the Beaverdam Creek route from Taylors to Travelers Rest. .

Deepwater crude oil export project looks to build offshore Louisiana; feds seek public input – Dallas-based Energy Transfer LP is seeking to replace an existing offshore natural gas platform and build a crude oil export project in the Gulf of Mexico 99 miles offshore from Cameron Parish in southwest Louisiana. The Maritime Administration, in coordination with the U.S. Coast Guard, is holding two virtual public meetings for Cameron Parish residents from 6 p.m. to 8 p.m. Wednesday and Thursday and created a website for more information while it prepares an environmental impact report. Energy Transfer, which already has plans for Lake Charles LNG, a liquefied natural gas export terminal in Calcasieu Parish, hopes to begin construction on the oil export platform during the fourth quarter of 2021 and begin commercial service by third-quarter 2023, according to its application. The Maritime Administration is considering issuing a license to the business for its deepwater port, which could load up to 80,000 barrels of crude oil every hour onto very large oil carriers too large to visit onshore ports. The maximum capacity would be 2 million barrels per day. The facility would be a competitor to the Louisiana Offshore Oil Port, which was built in the late 1970s as an import facility about 20 miles offshore from Port Fourchon, then retrofitted for exports. The import facility is collectively owned and operated by Marathon, Shell and Valero. The oil port stands in 110 feet of water and has 60 million barrels of crude oil storage capacity inside underground caverns that are naturally occurring salt domes. The oil port can export up to 1.2 million barrels of crude oil each day. Energy Transfer, the parent company of Sunoco, is expected to transfer crude oil from a Sunoco storage terminal in Texas to its new subsidiary Blue Marlin Offshore Port LLC’s deepwater platform. The company expects to export both light- and heavy-grade crudes. Energy Transfer already operates the largest above-ground crude oil storage facility in the U.S. in Nederland, Texas, which is the destination for long-haul pipelines from Bakken and Permian shale plays.

Proximity to Texas oil refineries increases cancer risk, study finds – HoustonChronicle.comA multi-year study completed by local researchers found that Texans who live nearest to oil refineries are at significantly higher risk of getting cancer.The study, recently published in the Journal of the National Cancer Institute, was conducted by a team of physicians, scientists, and students at the University of Texas Medical Branch at Galveston. The researchers used Texas Cancer Registry and Census data from 2001 through 2014, to compare rates of cancer of people within 30 miles of 28 active Texas oil refineries.The study found a clear correlation between distance from an oil refinery and rate of all cancer types. Of the more than 800,000 cancer patients living in Texas during that period, 34 percent lived in close proximity to an oil refinery. Patients living within 10 miles of refineries were most likely to have an advanced cancer diagnosis, compared to those who lived 21 to 30 miles away.Previous studies across the globe have shown that toxins associated with oil-refinery processes pose a high risk of cancer to nearby residents. Cancer-causing pollutants most commonly associated with refineries include benzene, toluene, ethylbenzene and xylene compounds. As oil production in the United States has soared – 18.8 million barrels per day – and with Texas as the country’s leading producer, public health concerns have been raised on behalf of those living and working near oil refineries. One of the co-authors of the study, Stephen Williams, chief of urology at the medical branch and a professor of urology and radiology at UTMB, hoped the findings would leverage a collaborative effort with some of the state’s oil refineries to determine causes of illnesses among their employees. The team of researchers plans to apply for a grant from the Cancer Prevention Research Institute of Texas to further investigate their findings. “There have been studies that have been done, particularly by the individual oil refineries themselves with their own employees, and there are data to suggest increased cancer among those particular individuals when they compare to the general population,” Williams said. “But these have either been done not recently, and then (it) also begs the question of whether or not they would allow investigators such as ourselves to look into this a little bit further.”

Tellurian withdraws U.S. application to build Permian natgas pipeline (Reuters) – U.S. liquefied natural gas (LNG) developer Tellurian Inc told federal energy regulators on Tuesday it wants to withdraw its application to build the Permian Global Access natural gas pipeline in Texas and Louisiana. The filing with the U.S. Federal Energy Regulatory Commission (FERC) comes a day after Tellurian said its President and Chief Executive Meg Gentle will leave the company. In what has been a tough year for the LNG industry after coronavirus demand destruction caused global energy prices to collapse, Tellurian said in the filing that “current market conditions do not support the economic thresholds to pursue the (Permian pipe) further at this time.” Tellurian said it “continues to believe that in time the proposed project will provide significant benefits” and it will host a new open season “in the event market conditions rebound and the market needs an additional transportation solution.” The 625-mile (1,005-km) Permian pipeline was designed to transport up to 2.3 billion cubic feet per day (bcfd) of gas from the Permian shale in West Texas and eastern New Mexico to southwest Louisiana near where Tellurian wants to build the Driftwood LNG export plant. In addition to the Permian pipe, Tellurian has also proposed to build the 4.0-bcfd Driftwood, 2.0-bcfd Haynesville Global Access and 2.0-bcfd Delhi Connector gas pipelines in Louisiana. The company has estimated the Permian pipe would have cost about $4.2 billion, Driftwood about $2.3 billion and Haynesville and Delhi around $1.4 billion each. In the past, Tellurian estimated the Driftwood project would cost about $27.5 billion and include the pipelines, the 3.6-bcfd LNG export plant, and gas production and other assets. But in August, the company reduced the cost of the first phase of the project by deferring most of the pipelines and including liquefaction trains capable of producing around 2 bcfd of LNG.

US oil, gas rig count rises 1 to 396 as adds in domestic plays slow: Enverus – – The US oil and gas total rig count rose by one in the week ending Dec. 2 to 396, rig data provider Enverus said, with totals reaching close to half the pre-pandemic levels of early March and more than 40% higher than it was in the July trough.The net one-rig add came from the natural gas side, as gas rigs rose by five to 110, while oil rigs fell by four to 286.The slight week-on-week rise showed a slowing of recent drilling activity, as the count has risen in recent months often by double-digits per week, with upstream operators attempting to shore up falling production from activity cutbacks earlier in the year when the pandemic caused a massive plunge in oil prices.The total US rig count is inching closer to 50% of mid-March levels following recent weekly gains, Platts Analytics noted in a Nov. 30 Spotlight report.Mid-March 2020 was the start of the large weekly tumbles in domestic rig counts. From levels of 835 at the time, the rig count plummeted 67% in four months.Since the early July trough of 279, the rig count has gained 117 rigs.Although the rig count uptick appears to have quieted in advance of the December holiday season, activity could “pick back up after the new year and into February,” S&P Global Platts Analytics analyst Matt Andre said. Big US unconventional producer EOG Resources was the biggest mover this week, adding five rigs, Andre said.”Rigs in top gas plays have returned to about 90% of the mid-March count,” the Spotlight report said of plays such as the Marcellus Shale, the Haynesville Shale and the Utica Shale. “However, rigs in top oil basins, which experienced a sharper decline and slower recovery, remain at about 40% of mid-March levels.”Gas prices grew in the week ended Dec. 2, with Henry Hub prices averaging $2.79/MMBtu, up 55 cents, and Dominion South at $1.95/MMBtu, up 58 cents.Average horizontal rig activity, typically employing rigs in unconventional basins with more-productive wells, is now on pace to finish more than 25% higher quarter on quarter, investment bank Tudor Pickering Holt said.

Growth in Oil Drilling Spurs US Rig Count Higher; Natural Gas Rigs Decrease — Another week of growth in the oil patch lifted the U.S. rig count three units to 323 for the week ending Friday (Dec. 4), according to the latest figures published by oilfield services provider Baker Hughes Co. (BKR). The United States saw a net increase of five oil-directed rigs for the week, offsetting a decline of two natural gas-directed units. The combined U.S. tally ended the period nearly 500 rigs shy of the 799 active units in the year-ago period, according to the BKR numbers, which are based on data provided in part by Enverus Drillinginfo. Over the past three months, the U.S. count has risen by nearly 70 rigs, and oil-directed drilling has accounted for nearly all of that increase. The natural gas rig count has seen relatively little growth during that time frame. U.S. natural gas rigs stood at 72 in early September, versus 75 during the current week, BKR data show. Land drilling increased by two in the United States for the week, while one rig was added in the Gulf of Mexico. Horizontal rigs increased by six, along with the addition of one vertical unit. Those gains were partially offset by a net decrease of four directional rigs. The overall Canadian rig count was flat week/week, with a two-rig increase in oil rigs offsetting a two-rig decrease in natural gas rigs. The Canadian count finished the period 36 units behind its year-ago total of 138. The combined North American rig count ended the week at 425, versus 937 in the year-ago period. Among major plays, the Permian Basin led the way during the week, picking up three rigs to grow its total to 164, versus 400 a year ago. The Denver-Julesburg/Niobrara formation added two rigs for the week, while the Utica Shale added one. The Marcellus Shale posted a net decrease of two rigs week/week. Broken down by state, BKR recorded a three-rig decline in Pennsylvania, with California and Wyoming each dropping one rig from their respective totals. Texas, Colorado and West Virginia each saw a net increase of two rigs for the week, while Louisiana and New Mexico each added one.

Despite fear in Oklahoma, Biden likely won’t be ‘banning’ fracking – – President Donald Trump offered a warning to Oklahoma and other energy-rich states during the final months of his unsuccessful reelection bid. The president cautioned that if Joe Biden won, the new Democratic president would quickly take action on an aggressive climate-change agenda, specifically by banning fracking across the country, a move he said would eliminate thousands of oil and gas jobs. “Well, that means Texas is going to be one of the most unemployed states in our country,” the president said during a news conference in July. “That means Oklahoma, North Dakota, New Mexico are going to be a disaster.” Biden’s actual written energy plan, however, previews a much different agenda. Contrary to Trump’s claims, which have been rated as false by several fact-checkers, Biden does not plan a wholesale ban on old or new fracking. His climate strategy includes a proposal to only cease approving new oil and gas permits on federal lands. In Oklahoma, where less than 2% of the land is owned by the federal government, the effect of fulfilling the campaign promise would be far from the dire scenarios Trump suggested for the state’s oil and gas industry. Energy leaders and environmental activists say that although they see a Biden administration looking much different from its predecessor, they do not see a widespread ban on fracking anytime soon. Instead, experts are planning for a return – and in some cases, an expansion – of the Obama-era energy and climate strategy Trump has largely dismantled.

LAW: Energy industry braces for Biden-era court clashes — Monday, November 30, 2020 — As the official transition to the Biden administration begins, the energy industry is preparing for a new round of courtroom battles against the president-elect’s anticipated tightening of restrictions on U.S. fossil fuel development. Trade groups are watching carefully to gauge how far Biden is willing to go to regulate the energy sector and limit activities like hydraulic fracturing. Some organizations are already preparing to bring the new administration to court. “One thing that the industry learned during the Obama years was, they would sue on almost everything,” said James Coleman, a law professor at Southern Methodist University. Action on Biden’s campaign pledge to halt all new permits for fracking on public lands could trigger lawsuits, as could potential efforts to conduct programmatic analyses of federal energy development. Any bids by the incoming administration to halt lease sales or permitting approvals could also draw industry challenges. Just as environmental groups and blue states teamed up in court against the Trump administration, industry interests and red states are expected to tee off against Biden. Coleman said he expects to see some of the same collaborations between trade groups and Republican attorneys general who opposed high-profile, Obama-era regulations like the Clean Power Plan. Likely red-state challengers include oil-rich Texas and coal-rich West Virginia (Greenwire, Nov. 18). Proponents of fossil fuel development aren’t the only challengers that are likely to take on the Biden administration in court. Green energy groups, for example, may join forces with the natural gas industry to push for increased infrastructure development. “I think that a lot of the trade associations will stick together, even on things where they might not see completely eye to eye,” Coleman said.

Joe Biden: Pro-oil president? — — Joe Biden was accused during the presidential campaign of planning for the end of oil, but some analysts say the president-elect won’t hurt – and may actually help – the industry. The pandemic has forced dozens of oil and gas producers out of business and sparked a wave of cost-cutting, debt reduction and consolidation among surviving companies. That has added to industry warnings that a crackdown by Biden as president could interrupt energy production and spark a deep economic decline. “You’re talking big job losses, nearly a million jobs through the entire economy by 2022,” Dean Foreman, chief economist for the American Petroleum Institute, said in a panel last week hosted by the Dallas Federal Reserve Bank and Kansas City Federal Reserve Bank, speaking about Biden’s proposals. But others say the Biden administration may force the oil and gas sector to comply with investors’ increasingly climate-conscious demands and help it adapt and survive longer in a carbon-conscious world. The president-elect’s proposals on issues such as methane also could align the U.S. more with other countries, giving a potential boost to U.S. gas, analysts say. Biden’s energy plan touches on oil and gas development in several ways, perhaps most prominently by calling for an end to oil and gas leasing on public lands, which accounts for roughly a quarter of U.S. oil production depending on the year. Biden was accused of calling for a ban on hydraulic fracturing during the campaign, but he has not been firm on a fracking ban and denied any ban on private land. Biden also calls for modifying royalties to account for climate costs and ending fossil fuel subsidies. It’s unclear at this point how high a priority those policies are for Biden, considering some were not mentioned with other energy initiatives on his transition website. But the tightened regulatory approach could be beneficial to companies after the “Wild West mentality” of greater access to drilling rights across federal lands and reduced oversight on issues like methane pollution that characterized the Trump era, said Jen Snyder, director at Enverus, an energy data firm based in Austin, Texas. With the oil and gas industry facing a finite amount of time to be a prominent player in the energy mix, an improved relationship to the rest of society and state officials could be important and extend the industry’s viability, some argue, pointing to states like Colorado and California that have started a crackdown on the side effects of drilling.

Sen. Chuck Grassley proposes 50% hike in oil, gas royalties on federal lands – Sen. Chuck Grassley is calling for an end to an “outrageous giveaway” to oil and gas companies by raising the royalties they pay for oil and gas production on federal lands by 50 percent. The increase would end what the Iowa Republican calls an “unnecessary subsidy” to Big Oil by updating the royalties established in the century-old Mineral Leasing Act when automobiles had just started to replace the horse and buggy, and the oil industry relatively new. Grassley and New Mexico Democratic Sen. Tom Udall are proposing the Fair Returns for Public Lands Act. “As senators from different parties, we have our share of policy differences,” they wrote in a New York Times Op-Ed piece published Wednesday. “In this case, we agree that oil and gas companies should pay fair market value for the public resources they extract and sell. They aren’t doing that now – not even close – and the American public is the big loser.” However, Grassley said Wednesday it won’t be easy to win support for the measure even though it may seem like common-sense legislation. “Very difficult,” he told reporters, “unless you get it into something that deals with, let’s say, infrastructure, roads and highways, things of that nature.” Grassley, chairman of the Senate Finance Committee, has found bipartisan support for increasing the federal gas tax to raise $93 billion to fund a 2019 Senate Public Works and Environment Committee plan for transportation infrastructure. However, neither Senate Majority Leader Mitch McConnell nor Senate Minority Leader Chuck Schumer supports the measure. The federal per-gallon fuel tax, last raised in 1993, is 18.4 cents on gasoline and 24.4 on diesel. “So it would be difficult to get passed unless it was in a bigger package of things, to reach a compromise,” Grassley said. Nevertheless, Grassley called the proposal “more a matter of principle … a matter of consistency and fairness.” He’s proposing to increase the royalty for new leases on federal lands from 12.5 percent of the value extracted to 18.75 percent – the same as the royalty on offshore production. By comparison, the current royalty is half what Texas levies. The proposed increase would raise $200 million in federal revenue over the next 10 years as it is phased in, with an equivalent amount going to the states where the oil or gas is being extracted, according to the Congressional Budget Office.

Minnesota tribes file to halt pipeline approval due to virus (AP) – Two Native American tribes in northern Minnesota are asking state regulators to stop the imminent construction of Enbridge Energy’s Line 3 crude oil pipeline replacement, saying it would increase the risk of coronavirus infections spreading.The Red Lake and White Earth Bands of Chippewa filed a motion late Wednesday asking the Minnesota Public Utilities Commission to stay its approval of the $2.6 billion project. They argue construction would put locals at increased risk of coronavirus infections as workers move into the area.The bands and other pipeline opponents have sued and protested to try to block the project, and an appeal by the state Commerce Department is pending. They want the PUC to halt the project while that legal challenge plays out.The pipeline project took a step forward on Monday when the U.S. Army Corps of Engineers approved the final federal permit needed. The Public Utilities Commission has already approved the project several times, but still needs to give construction a final green light.Enbridge says the pipeline replacement will provide a safer way to transport the oil to Midwest refineries while creating 4,200 construction jobs and generating millions of dollars in local spending and tax revenues.Opponents say the project threatens spills in pristine waters where Native Americans harvest wild rice and that the Canadian tar sands oil it would carry would aggravate climate change.

Enbridge cleared to begin construction work on $2.6B pipeline across Minnesota – After six years of review, Enbridge is now poised to begin construction on its controversial $2.6 billion oil pipeline across northern Minnesota. The Minnesota Pollution Control Agency on Monday approved a construction stormwater permit – the last OK needed for workers to break ground on the Line 3 replacement pipeline that will run from the northwest corner of the state to a terminal in Superior, Wis. The agency issued waterway permits earlier this month for the project, which is a replacement for Enbridge’s existing 50-year-old Line 3 pipeline. The Army Corps of Engineers also recently issued a waterway permit, and the Minnesota Public Utilities Commission gave its final approvals. “Line 3 is poised to provide significant economic benefits for counties, small businesses, Native American communities, and union members – bringing 4,200 family-sustaining, mostly local construction jobs, millions of dollars in local spending and additional tax revenues at a time when northern Minnesota needs it most,” Enbridge said in a statement Monday. Unions and pipeline advocates cheered the news and said construction will benefit the state’s economy especially as the pandemic continues to keep folks out of work. “Even before the pandemic we were struggling with unemployment in northern Minnesota – now more than ever do we need the jobs,” said Joel Smith, the state president of Laborers’ International Union of North America. “Thousands of our friends and neighbors across Minnesota look forward to using their construction skills to protect our environment and communities by replacing an existing deteriorating pipeline.” Smith said he expects crews to start working in the coming days; Enbridge did not give a start date.

Construction on Enbridge pipeline begins as new lawsuit filed to delay $2.6B project –Less than a day after state regulators gave the final approval for Enbridge to start building a new $2.6 billion pipeline across northern Minnesota, the Canadian oil company got to work.The building began “across Minnesota,” Enbridge said, even as environmental and Indigenous groups launched another lawsuit seeking to stop construction.”We will continue to use every legal avenue available to stop the degradation of our waters for future generations to enjoy our treaty-protected resources on and off reservation,” White Earth Band of Ojibwe attorney Frank Bibeau said in a statement Tuesday.The suit challenges the construction stormwater permit issued by the Minnesota Pollution Control Agency and claims the MPCA gave “virtually no consideration of long-term impacts” to the climate or treaty rights.It joins several legal actions seeking to stop or at least stall construction of the 340-mile pipeline that would carry an average 760,000 barrels of oil per day between Alberta and the Enbridge terminal in Superior, Wis.Last week the Red Lake Band of Chippewa and the White Earth Band asked the Minnesota Public Utilities Commission to pause its approval of pipeline construction while the Minnesota Court of Appeals considers permit challenges.The PUC will consider that request at 10 a.m. Friday.”Some big questions need to be asked: What if the Appeals Court sides against Enbridge in the legal cases before it?” said Honor the Earth Executive Director Winona LaDuke in a statement Tuesday.Enbridge previously said in a statement that the bands’ petition “only seeks to delay” the new pipeline. “There is no legitimate basis for this filing. The Line 3 replacement project has passed every test.”

Doctors seek halt to Enbridge pipeline project because of COVID concerns – Health professionals and northern Minnesota residents pleaded with Gov. Tim Walz to halt construction of Enbridge’s controversial $2.6 billion oil pipeline, saying the project will draw thousands of out-of-state workers who could accelerate the spread of COVID-19. Health Professionals for a Healthy Climate, at an event with climate justice group MN350, held a socially distanced media event and rally Wednesday morning in front of the governor’s residence in St. Paul. Enbridge received a final permit from the Minnesota Pollution Control Agency on Monday, and on Tuesday started building the replacement for its deteriorating and aging Line 3. Speakers at the event said more than 4,000 Enbridge workers living and working in close quarters has the potential to develop into a superspreader event. They said if average Minnesotans and small businesses were being asked to limit their movements and even curtail holiday celebrations and travel, “big oil” could also do its part in stopping the virus’ spread across northern Minnesota. The 340-mile pipeline will cross northern Minnesota, connecting the oil fields in Alberta with Enbridge’s facility in Superior, Wis. “I am asking Gov. Walz to issue a stay on Line 3 construction as a COVID -19 mitigation measure,” said Dr. Vishnu Laalitha Surapaneni, a Twin Cities physician specializing in internal medicine who has been on the medical front lines battling COVID-19 since last spring. “These are perfect conditions for the virus to spread and harm us,” because some of the workforce will be from out of state and many will stay in hotels, she said.

Oakland bans natural gas in new residential and commercial buildings – The Oakland City Council voted unanimously Tuesday to ban natural gas in newly constructed apartment and commercial buildings. The measure requires all developers to design new residential and commercial buildings without natural gas. Developers can apply for waivers for “technology feasibility reasons” to avoid abiding by the new regulation. Existing buildings, additions and accessory dwelling units are not affected by the legislation. “Oakland’s national leadership to build cleaner, safer, and healthier cities for all families continues with this historic transition to all-electric buildings,” said Oakland Mayor Libby Schaaf in a statement. Councilman Dan Kalb, the lead author of the legislation, said Oakland can’t meet its climate goals without shifting away from natural gas use. In July, the City Council adopted the 2030 Equitable Climate Action Plan, which calls on the city to reduce greenhouse gas emissions to 56% below 2005 levels over the next 10 years. “State energy policies and lower prices of renewables mean that substituting natural gas with electricity is one of the quickest, safest, and least expensive pathways to eliminating greenhouse gas emissions from buildings,” Kalb said. “Additionally, reducing the reliance on gas systems will reduce the risk of fires, simplify building systems and maintenance, and improve indoor air quality.” Nearly a dozen people spoke in support of the restrictions during public comment. One Oakland resident called it a “common sense policy.” The vote comes more than a year after Berkeley became the first city in California to pass a natural gas ban – a move that is being challenged in the courts. Since Berkeley’s measure, nearly 40 cities have joined the effort with similar restrictions, including San Francisco, San Jose and Windsor.

San Jose bans natural gas in new commercial buildings – San Jose became the largest city in the country to ban natural gas in commercial buildings, but its plan to keep businesses running during a power outage was criticized by activists and lawmakers. The City Council voted 8-3 on Dec. 1 to approve the ban but in the wake of a public health crisis and not-so-distant memories of PG&E blackouts, lawmakers granted exceptions for hospitals, manufacturing plants, industrial facilities and energy storage companies, which use natural gas to provide a steady stream of fuel in case the grid goes dark. “The grid will shut down on us,” Mayor Sam Liccardo said. “We are going to have blackouts and when that does happen, it’s policies like this that will be the target of scorn. We need to be really clear that we are providing options for those who critically need them.” A handful of other California cities have banned natural gas, including Berkeley, Burlingame and Menlo Park. Oakland joined that list Tuesday night, banning it in newly-constructed apartment and commercial buildings.

Los Angeles Moves Closer to Forcing Oil & Gas Drillers Out of City (CN) – After a lengthy legal analysis and at least one threat of a lawsuit, Los Angeles will consider a ban on all oil drilling within the city limits. Environmental advocacy groups say the proposal – made during a committee meeting Tuesday – to consider a zoning update that would ban oil drilling is a big victory for people who live near drill sites and signals that LA is prepared to phase out fossil fuel use in the next few decades. “I think we all probably want to be on board with the idea of separating oil and gas production from human beings who are living their lives in neighborhoods,” said LA City Councilman Paul Krekorian, who asked the city attorney’s office to draft an zoning update on oil drilling. The road to that decision has been steeped in health issues for residents. For decades, residents in low-income communities exposed to harmful chemicals have demanded the city update zoning codes to address oil drill sites next to homes, schools, parks and churches. Problem oil operators have been allowed to renew their permits without much oversight by city officials according to environmental groups, leading to severe health issues for generations of Angelenos. LA is crisscrossed with active, abandoned and plugged wells. Among 26 oil and gas fields lie roughly 819 active, 296 idle, 3,181 plugged, and 933 buried wells according to the city. In 2017, the City Council asked for a report on updating those outdated zoning codes. This past summer, the city’s petroleum administrator recommended several avenues to reduce the toxic air that so many breathe, including a possible 600-foot setback or buffer around existing oil sites and a 1,500-foot buffer for any new drill sites. In such a densely populated city, buffers could mean the oil and gas operators would essentially be forced out of neighborhoods.

California- Increased criminal penalties for oil spill-related offenses Members are informed that the International Group (IG) clubs have considered the potential impact on cover for pollution risks of this new legislation. While having in mind the potential for substantial fines to be issued against a polluter, the IG clubs did not believe that it would be appropriate to seek to amend the existing limit of cover to respond to this significant, but nonetheless isolated, new piece of legislation. Any such amendment would in any event be impossible to achieve within the current confines of the global reinsurance markets if sufficient cover were to be required to respond in full to the maximum level of fines that might potentially be levied by Californian courts for accidental pollution. Members are however reminded that there is already cover of US$1 billion per ship per incident for oil pollution damage, which covers response costs and third party claims as well as fines where they fall under Club rules, and all limits of liability under OPA `90 regardless of ship type remain capable of cover well within this capacity. The Californian courts have substantial discretion to consider relevant aggravating and mitigating circumstances relating to a pollution incident when determining the amount of fines. These considerations include, among others, (1) the degree of culpability including the events leading up to the incident (2) prompt and accurate reporting; (3) effective response and clean-up efforts; (4) prompt and fair compensation to damaged parties; (5) remedial efforts towards natural resources; and finally, (6) the spilling party’s financial ability to pay.As to the latter, the legal advice received by the IG is that a court cannot impose a punishment, even if authorized by statute, that is so excessive as to be beyond the defendant’s ability to pay. The IG is also continuing to take active steps in conjunction with coalition partners to explore the possibility of addressing industry’s concerns arising from this new law, although it remains clear that any such steps will not affect the entry into force date of the new law in California.

When Can Pipelines Take Private Land? Jordan Cove LNG Project a Test for Eminent Domain – In 2005, Deb Evans and her husband Ron Schaaf bought a piece of property in Klamath County, Oregon, where they hoped to build a house and selectively harvest timber on the land. They saw it as a long-term investment. About a month after they closed on the property, they went to walk through portions of it where they considered building a home, but they noticed orange survey tape hanging from the trees. “We had no idea who had put it there or why,” Evans said. After calling around, they soon found out that a company wanted to build a liquefied natural gas (LNG) import terminal in Coos Bay on the Oregon coast, and run a natural gas pipeline to California – and Evans’ land was in the way. If the company’s plans worked out, the pipeline would travel right through their property. A decade and a half – and two White House administrations – later, there’s still no pipeline. But the project still looms over Evans and Schaaf, limping along in a zombie-like fashion. The Jordan Cove LNG project, now overseen by Canadian company Pembina, just won’t seem to die – even after it had been rejected by federal regulators twice and had key environmental permits denied. Now, in a final attempt to stop the pipeline that would supply the LNG terminal, local residents are suing to protect their property. Evans and a group of about two dozen landowners, represented by the Niskanen Center, a nonpartisan think tank based in Washington, D.C., are appealing the Trump administration’s approval of the pipeline (reversing an Obama-era rejection) in a case that will be heard by the D.C. Circuit Court of Appeals in 2021. The outcome could have far-reaching ramifications for how pipelines get built in the U.S., and how pipeline companies can use eminent domain to take private land.

Oneok seeks to expand capacity of natural gas liquids pipeline – Oneok seeks to expand the capacity of a natural gas liquids pipeline that connects to its Bear Creek gas processing plant near Halliday in Dunn County. The company wants to add two pump stations to boost horsepower along the Bear Creek NGL Pipeline, which currently carries up to 15,000 barrels per day from the plant to another pipeline in McKenzie County. The proposed stations would allow the line to transport up to 80,000 barrels per day. The company seeks a permit from the North Dakota Public Service Commission, as the two pump stations would fall outside the pipeline’s existing corridor. One of the new stations would be located on a 5-acre parcel of land leased by Oneok 8 miles southeast of Watford City. The other would be built on 7 acres of leased land 18 miles northwest of Killdeer, according to the application Oneok filed with the PSC earlier this year. The pipeline spans 38 miles and was built in 2016. Its maximum operating pressure would remain the same under the expansion, the company said in its application. Natural gas liquids, which are shipped through the pipeline, are isolated from raw natural gas at processing plants. They contain components of the gas such as ethane, butane and propane, which exist in liquid form under certain pressures and temperatures. The liquids would ultimately be shipped via Oneok’s Bakken and Elk Creek pipelines, which run from eastern Montana to Kansas, company spokesman Brad Borror said. The pipeline expansion is separate from a planned expansion of the Bear Creek processing plant, which was put on hold earlier this year due to changing market conditions and customer needs, he said. Many oil and gas projects have been halted or canceled in 2020 after the price of oil collapsed this spring in the early days of the coronavirus pandemic.

Oil field spill reported in Bowman County – An oil field spill occurred at a pipeline in Bowman County on Tuesday, according to the North Dakota Department of Environmental Quality.About 200 barrels or 8,400 gallons of “source water” leaked from the line, which is owned by Denbury Offshore. Some of the fluid spilled into pastureland at a site 8 miles southwest of Marmarth.Source water is fluid that is saltier than fresh water but not nearly as saturated with salt as what’s commonly known as “brine” or “produced water” in the oil fields. The water is pumped up to the earth’s surface from a shallow rock formation and then injected back down into a deeper formation to try to push more crude into old oil wells, said Karl Rockeman, director of the state Division of Water Quality.Denbury is involved in such enhanced oil recovery efforts in southwestern North Dakota. Environmental Quality said it is inspecting the site and will monitor cleanup.

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