Oil, Gas, And Fracking News Reads: 12July 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 11 July 2020. Part 2 is available here.

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

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Low prices appear to be driving drillers to abandon horizontal drilling for cheaper vertical wells

US oil prices were little changed this week, as better than expected economic reports were offset by the threat of rising coronavirus cases….after rising 5% to $40.65 a barrel last week on improving economic data and on falling US crude inventories, the contract price of US light sweet crude for August delivery opened lower on Monday on concerns that a spike in coronavirus cases could curb US oil demand, but steadied on reports that U.S. services industry activity had rebounded sharply in June and that China’s capital markets were attracting money to end the session just 2 cents lower at $40.63 a barrel…the same dynamic played out in oil markets Tuesday, with prices falling as oil traders eyed rising coronavirus cases but steadying as improving economic data overshadowed the coronavirus worries, as August oil ended down a penny at $40.62 a barrel…a larger than expected build in US crude inventories hit prices early Wednesday, but prices recovered and ended 28 cents higher at $40.90 because the EIA report also showed rising demand for and falling inventories of gasoline…but oil prices tanked on Thursday after Wednesday’s coronavirus data showed the largest increase in US cases ever reported by any country in a single day, renewing fears that new lockdowns would again sink fuel consumption, as oil prices settled $1.28 lower at $39.62 a barrel…August oil then opened lower on Friday and fell more than $1 on ongoing virus fears, but prices got a late boost after the International Energy Agency bumped up its 2020 forecast for global oil demand, and the ensuing rally carried the August contract to a 93 cent gain on the day, settling at $40.55 a barrel…nonetheless, oil prices still ended with a 0.3% loss on the week as the risk of spiking coronavirus counts outweighed the bevy of better economic news…

On the other hand, natural gas prices ended the week modestly higher, as forecasts through the end of July called for much warmer than normal temperatures….after rising 12.3% to $1.734 per mmBTU on rising air conditioning demand last week, the contract price of natural gas for August delivery jumped to a five-week high on Monday on forecasts calling for hotter weather and higher air conditioning demand than had previously been expected, with natural gas prices settling 9.6 cents higher at $1.830 per mmBTU…with July heating up at a record pace, front month contract prices rose another 4.6 cents on Tuesday after an unplanned pipeline shutdown in West Virginia, but then fell back 5.2 cents on Wednesday on a continued drop in LNG exports and a smaller than expected drop in output due to unplanned pipeline work…natural gas prices fell another 4.5 cents along with the oil price drop on Thursday on worries about ongoing coronavirus demand destruction, despite a bullish gas storage report that was in line with expectations…natural gas prices then regained 2.6 cents on Friday on forecasts hotter-than-normal weather through late July to end the week at $1.805 per mmBTU, an increase of 4.1% over the week…

The natural gas storage report from the EIA for the week ending July 3rd indicated that the quantity of natural gas held in underground storage in the US rose by 56 billion cubic feet to 3,133 billion cubic feet by the end of the week, which left our gas supplies 685 billion cubic feet, or 28.0% greater than the 2,448 billion cubic feet that were in storage on July 3rd of last year, and 454 billion cubic feet, or 16.9% above the five-year average of 2,679 billion cubic feet of natural gas that has been in storage as of the 3rd of July in recent years….the 56 billion cubic feet that were added to US natural gas storage this week was in line with the average increase of 55 billion forecast by analysts polled by S&P Global Platts, but it was less than the 92 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, and was also less than the average of 68 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending July 3rd indicated that because of a big jump in our oil imports and a sizable drop in our oil exports, we were left with quie a bit of surplus oil to add to our stored commercial supplies of crude oil for the 4th week of the past five, and for the 31st time in the past forty-three weeks….our imports of crude oil rose by an average of 1,425,000 barrels per day to an average of 7,394,000 barrels per day, after falling by an average of 571,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 705,000 barrels per day to an average of 2,387,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,007,000 barrels of per day during the week ending July 3rd, 2,130,000 more 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 unchanged at 11,000,000 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 16,007,000 barrels per day during this reporting week..

US oil refineries reported they were processing 14,347,000 barrels of crude per day during the week ending July 3rd, 315,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 895,000 barrels of oil per day were being added to the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 765,000 barrels per day more than what was added to storage plus 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 (-765,000) 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 fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…however, since the media usually treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as 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 6,636,000 barrels per day last week, which was still 8.5% less than the 7,253,000 barrel per day average that we were importing over the same four-week period last year….the 895,000 barrel per day net addition to our total crude inventories included 87,000 barrels per day that were added to our Strategic Petroleum Reserve, and 808,000 barrels per day that were being added to our commercially available stocks of crude oil…this week’s crude oil production was reported to be unchanged at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,600,000 barrels per day, while a 36,000 barrel per day increase in Alaska’s oil production to 399,000 barrels per day had no impact on the rounded national total….last year’s US crude oil production for the week ending July 5th was rounded to 12,300,000 barrels per day, so this reporting week’s rounded oil production figure was about 10.7% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 77.5% of their capacity while using 14,347,000 barrels of crude per day during the week ending July 3rd, up from 75.5% of capacity during the prior week, but excluding the 2005 & 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years…hence, the 14,347,000 barrels per day of oil that were refined this week were still 17.7% fewer barrels than the 17,438,000 barrels of crude that were being processed daily during the week ending July 5th, 2019, when US refineries were operating at 94.7% of capacity….

With the increase in the amount of oil being refined, gasoline output from our refineries was also higher, increasing by 140,000 barrels per day to 8,045,000 barrels per day during the week ending July 3rd, after our refineries’ gasoline output had increased by 111,000 barrels per day over the prior week… however, since our gasoline production is still recovering from a multi-year low, this week’s gasoline output was still 13.2% lower than the 10,418,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 122,000 barrels per day to 4,756,000 barrels per day, after our distillates output had increased by 63,000 barrels per day over the prior week…but even after this week’s increase in distillates output, our distillates’ production was still 11.2% less than the 5,358,000 barrels of distillates per day that were being produced during the week ending July 5th, 2019….

Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 7th time in 11 weeks and for the 15th time in 23 weeks, falling by 4,839,000 barrels to 251,682,000 barrels during the week ending July 3rd, after our gasoline supplies had increased by 1,199,000 barrels over the prior week…our gasoline supplies decreased this week because the amount of gasoline supplied to US markets increased by 205,000 barrels per day to 8,766,000 barrels per day, and because our imports of gasoline fell by 282,000 barrels per day to 729,000 barrels per day while our exports of gasoline rose 41,000 barrels per day to 524,000 barrels per day….but even after this week’s inventory decrease, our gasoline supplies were still 9.8% higher than last July 5th’s gasoline inventories of 229,187,000 barrels, and roughly 8% above the five year average of our gasoline supplies for this time of the year…

With the increase in our distillates production, our supplies of distillate fuels increased for the twelfth time in 25 weeks and for the 17th time in 40 weeks, rising by 3,135,000 barrels to 177,262,000 barrels during the week ending July 3rd, after our distillates supplies had decreased by 593,000 barrels over 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 759,000 barrels per day to 3,019,000 barrels per day, even as our exports of distillates rose by 294,000 barrels per day to 1,360,000 barrels per day while our imports of distillates fell by 63,000 barrels per day to 72,000 barrels per day….after this week’s inventory increase, our distillate supplies at the end of the week were 35.8% above the 130,517,000 barrels of distillates that we had stored on July 5th, 2019, and about 27% above the five year average of distillates stocks for this time of the year…

Finally, with the jump in our oil imports and the decrease in our oil exports, our commercial supplies of crude oil in storage rose for the 20th time in twenty-four weeks and for the 35th time in the past 52 weeks, increasing by 5,654,000 barrels, from 533,527,000 barrels on June 26th to 539,181,000 barrels on July 3rd…after that increase, our our commercial crude oil inventories were around 18% above the five-year average of crude oil supplies for this time of year, and 58.5% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the first weekend of July, 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 have generally been rising since September of 2018, except for during last summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of July 3rd were 17.5% above the 458,992,000 barrels of oil we had in commercial storage on July 5th of 2019, 33.0% above the 405,248,000 barrels of oil that we had in storage on July 6th of 2018, and 8.8% above the 495,350,000 barrels of oil we had in commercial storage on July 7th of 2017…

Moreover, with the big jump in our crude inventories and the increase in our distillate fuel supplies, the total of our commercial oil supplies and the commercial stockpiles of all the refined product made from oil have again increased by 9,841,000 barrels this week to yet another record high of 1,461,620,000 barrels, 12.5% more than the 1,298,926,000 barrel total of the same week a year ago…

This Week’s Rig Count

The US rig count fell for the 18th week in a row during the week ending July 10th, leaving the rig count down by 67.5% over that eighteen week period…(note that this week’s report covers 8 days after last week’s was released on Thursday ahead of the July 4th weekend)…Baker Hughes reported that the total count of rotary rigs running in the US decreased by 5 rigs to 258 rigs this past week, which again was the fewest active rigs in Baker Hughes records going back to 1940 and 146 fewer rigs than the all time low prior to this year, and was also down by 700 rigs from the 958 rigs that were in use as of the July 12th report of 2019, and 1,671 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….

The number of rigs drilling for oil decreased by 4 rigs to 181 oil rigs this week, after falling by 3 oil rigs the prior week, leaving oil rig activity at its lowest since June 5th, 2009, which was also 603 fewer oil rigs than were running a year ago, and less than an eighth 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 fell by 1 rig to 75 natural gas rigs, which matches the least natural gas rigs running in at least 80 years, and was down by 97 natural gas rigs from the 172 natural gas rigs that were drilling a year ago, and was 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 on the big island of Hawaii, and one in Sonoma County, California… a year ago, there were no such “miscellaneous” rigs deployed…

The Gulf of Mexico rig count was unchanged at 12 rigs this week, with 10 of those rigs drilling for oil in Louisiana’s offshore waters and two of them drilling for oil offshore from Texas…that was 14 fewer rigs than the 26 rigs drilling in the Gulf a year ago, when 24 rigs were drilling offshore from Louisiana and two rigs were operating in Texas waters…meanwhile, there are no rigs operating off other US shores at this time, nor were there a year ago, so the Gulf of Mexico rig count is equal to the national offshore rig count, just as it has been since the onset of last winter…

The count of active horizontal drilling rigs decreased by 6 rigs to 220 horizontal rigs this week, which was the fewest horizontal rigs active since December 9th, 2005, and hence is a new 14 1/2 year low for horizontal drilling…it was also 611 fewer horizontal rigs than the 831 horizontal rigs that were in use in the US on July 12th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…meanwhile, the directional rig count was down by one to 19 directional rigs this week, and those were also down by 51 from the 70 directional rigs that were operating during the same week of last year…on the other hand, the vertical rig count rose by 2 rigs to 19 vertical rigs this week, but those were also still down by 38 from the 57 vertical rigs that were in use on July 12th of 2019….

With low prices for oil & natural gas, it appears there has been an ongoing shift from the complex and expensive horizontal drilling technique to the simpler and cheaper conventional vertical drilling…recall that in the Dallas Fed energy survey of a couple months ago, of the 157 oil executives responding, none could profitably drill a new horizontal well in any US shale basin at an oil price below $30 a barrel, but at least one company thought they could profit even with oil as low as $15 a barrel by drilling a vertical well….on June 5th, there were 253 horizontal rigs, 24 directional rigs, and 7 vertical rigs deployed; but as we have just reported, by July 10th, horizontal rigs had fallen by 33 to 220 rigs, directional rigs had fallen by 5 to 19 rigs, but vertical rig activity had increased by 12 rigs to 19 vertical rigs…my sense is that some of this switch is taking place in the Permian basin, as horizontal rigs are being shut down in Permian Delaware, while vertical rigs are starting up in the Permian Midland, but to establish the degree to which that is happening, one would have to locate each of the individual well records on the North America Rotary Rig Count Pivot Table, and i haven’t yet had the patience for that tedious endeavor…

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 July 10th, the second column shows the change in the number of working rigs between last week’s count (July 2nd) and this week’s (July 10th) count, the third column shows last week’s July 2nd active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running 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 12th of July, 2019…

Again there were few changes in drilling activity this week, with just a handful of rig removals and only two additions, which suggests that prices have risen high enough that drillers are no longer anxious to shut down money-losing operations, but not high enough to encourage the addition of new rigs to the field…checking the rig counts in the Texas part of Permian basin, we find that one rig was shut down in Texas Oil District 8, or the core Permian Delaware, and one rig was shut down in Texas Oil District 7C or the southern Permian Midland…since the overall Permian basin rig count was down by just 1 rig nationally, that means that the rig that was added in New Mexico would have been drilling in the western Permian Delaware, to offset the Texas decrease…elsewhere in Texas, there were two rigs shut down in Texas Oil District 2, another rig shut down in Texas Oil District 3, while a new rig was added in Texas Oil District 4, all of which most likely would represent changes in activity in the Eagle Ford shale, which stretches in a relatively narrow band through the southeastern part of the state and touches on all three of those Oil Districts…in addition, a rig was shut down in Texas Oil District 9, which would account for the rig reduction in the Barnett shale in the area around Dallas-Ft Worth….that rig stacked in the Barnett shale had been targeting natural gas, as was the rig that was shut down in West Virginia’s Marcellus, while at the same time a rig began drilling for natural gas in a basin not tracked separately by Baker Hughes, thus netting out to this week’s one natural gas rig decrease nationally…

Frac-Sand Supplier Covia Files for Bankruptcy – Frac-sand supplier Covia Holdings Corp. has filed for bankruptcy as part of a plan to cut more than $1 billion in debt and shed its railcar leases after taking a beating from the economic disruption sparked by the coronavirus pandemic and lower energy prices. The Independence, Ohio, company filed for chapter 11 protection in the U.S. Bankruptcy Court in Houston late Monday after reaching a restructuring support agreement with a group of holders of a majority of its secured debt.

Companies Cancel Atlantic Coast Pipeline After Years of Delays – The Wall Street Journal – The builders of the Atlantic Coast Pipeline are pulling the plug on the project as companies continue to meet mounting environmental opposition to new fossil-fuel conduits. Duke Energy Corp. and Dominion Energy Inc. said Sunday they were abandoning the proposed $8 billion pipeline – which aimed to carry natural gas 600 miles through West Virginia, Virginia and North Carolina and underneath the Appalachian Trail – citing continued regulatory delays and uncertainty, even after a favorable Supreme Court ruling last month.Dominion said it was selling the rest of its natural-gas transmission and storage network to Warren Buffett’s Berkshire Hathaway Inc. for $9.7 billion including debt. The deal includes a 25% stake in the Cove Point liquefied natural gas export facility in Maryland, of which Dominion will remain the largest owner. “This announcement reflects the increasing legal uncertainty that overhangs large-scale energy and industrial infrastructure development in the United States,” Dominion and Duke said in a joint statement. “Until these issues are resolved, the ability to satisfy the country’s energy needs will be significantly challenged.”Utilities and pipeline companies have been trying to expand U.S. pipeline networks for more than a decade to take advantage of the bounty of oil and gas unlocked by the fracking boom. But many of the projects have encountered intense opposition from landowners, Native American groups and environmental activists concerned about climate change who want to keep fossil fuels in the ground. The Trump administration has sought to make it easier for companies to build pipelines and other energy infrastructure, but the effort has failed to fast-track projects amid continued legal and regulatory challenges by opponents. Dominion and Duke had first proposed building the Atlantic Coast Pipeline in 2014. It repeatedly faced legal challenges from environmentalists, Native American groups and others. Its costs had swelled to $8 billion before the companies decided to abort the plan. “Duke and Dominion did not decide to cancel the Atlantic Coast Pipeline – the people and frontline organizations that led this fight for years forced them into walking away,” said Michael Brune, the executive director of the Sierra Club. The companies had scored a significant victory last month when the Supreme Court ruled that it could cut under the historic Appalachian Trail, which runs from Georgia to Maine. The court overturned a lower-court ruling that found the U.S. Forest Service didn’t have the authority to grant a special-use permit that allowed for the development of that segment. However, Duke and Dominion said Sunday that the ruling wasn’t enough to mitigate an “unacceptable layer of uncertainty and anticipated delays” for the project. They cited a Montana court ruling last month that threw another roadblock in the path of the Keystone XL Pipeline as an example of the continued challenges such projects face. That ruling, which related to a federal permit program for oil and gas pipelines, had the potential to also further delay the Atlantic Coast Pipeline, the companies said. The companies involved had together invested about $3.4 billion in the pipeline to date.

Atlantic Coast Pipeline Canceled Following Years of Legal Challenges — The Atlantic Coast Pipeline (ACP), which would have carried fracked natural gas through 600 miles of West Virginia, Virginia and North Carolina, will never be completed. Pipeline owners Dominion and Duke Energy announced Sunday they were cancelling the fossil fuel project due to mounting delays and uncertainty. They said the many legal challenges to the project had driven up the projected costs by almost half, from $4.5 to $5 billion when it was first announced in 2014 to $8 billion according to the most recent estimate. Environmental and community groups, who have long opposed the project on climate, conservation and racial justice grounds, welcomed the news. “If anyone still had questions about whether or not the era of fracked gas was over, this should answer them,”Sierra Club Executive Director Michael Brune said in a statement emailed to EcoWatch. “Today is a historic victory for clean water, the climate, public health, and our communities. Duke and Dominion did not decide to cancel the Atlantic Coast Pipeline – the people and frontline organizations that led this fight for years forced them into walking away. Today’s victory reinforces that united communities are more powerful than the polluting corporations that put profits over our health and future.” The utilities’ announcement comes a little less than three weeks after the pipeline scored an important legal victory when the Supreme Court ruled that it could pass beneath the Appalachian Trail. But environmental groups at the time pointed out that the project still needed eight other permits. Early this year, a federal court vacated a permit the pipeline needed to build a natural gas compressor station in Union Hill, a historic Black community in Virginia, after community members successfully argued that it would disproportionately harm the health of the mainly African American residents who lived nearby. Courts have also tossed permits over the pipeline’s plans to cut a visible scar through the forest as it crosses beneath the Blue Ridge Parkway, its crossing of more than 1,500 streams and rivers in West Virginia and its impact on endangered species like the Indiana bat and Madison cave isopod, Sierra Magazine pointed out in 2019. “All of the ACP’s problems are entirely self-inflicted,” Greg Buppert, a senior attorney for the Southern Environmental Law Center, told Sierra Magazine at the time. “It was never a good idea to build this pipeline through two national forests, a national park, across the Appalachian Trail, and through the steepest mountains in West Virginia.”

Warren Buffett’s Berkshire buys Dominion Energy natural gas assets in $10 billion deal – Warren Buffett’s Berkshire Hathaway is finally pulling the trigger. The conglomerate is spending $4 billion to buy the natural gas transmission and storage assets of Dominion Energy. Including the assumption of debt, the deal totals almost $10 billion. It’s Berkshire’s first major purchase since the coronavirus pandemic and subsequent market collapse in March. At his annual shareholder meeting in May, Buffett revealed that Berkshire had built up a record $137 billion cash hoard as financial markets tanked and that he hadn’t seen many favorable deals, despite the stock market’s swoon. “We have not done anything because we don’t see anything that attractive to do,” Buffett said at the time, suggesting that the quick actions taken by the Federal Reserve this year meant companies could get more access to financing in the public markets than they could during the financial crisis in 2008 and 2009. “If we really liked what we were seeing, we would do it, and that will happen someday,” Buffett said in May. For Dominion, the move is part of its transition to a pure-play regulated utility company that focuses on clean energy production from wind, solar and natural gas. Following the sale, Dominion expects that 90% of its future operating earnings will come from its utility companies that provide energy to more than 7 million customers in states like Virginia, North and South Carolina, Ohio and Utah. Dominion also announced that it is cancelling its Atlantic Coast Pipeline project with Duke Energy. The $8 billion project has faced increasing regulatory scrutiny and delays that have ballooned projected costs and raised doubts about its economic feasibility. With the purchase, Berkshire Hathaway Energy will carry 18% of all interstate natural gas transmission in the United States, up from 8% currently. Under the deal, Berkshire Hathaway Energy will acquire 100% of Dominion Energy Transmission, Questar Pipeline and Carolina Gas Transmission and 50% of Iroquois Gas Transmission System. Berkshire will also acquire 25% of Cove Point LNG, an export-import and storage facility for liquefied natural gas, one of just six in the U.S.

Opponents: Pipeline’s defeat ‘a testament to perseverance’ (AP) – Richard Averitt and his wife have spent six years and more than six figures fighting to keep the Atlantic Coast Pipeline off their picturesque central Virginia property. In all that time, Averitt said he couldn’t recall meeting a single person who thought they would succeed. The massive interstate natural gas pipeline designed to start in West Virginia and run at least through Virginia and North Carolina was being developed by some of the country’s biggest and most politically powerful energy companies with support of lawmakers and governors from both parties, labor unions and the Trump administration. But on Sunday, Duke Energy and Dominion Energy announced they had pulled the plug on the $8 billion project, citing uncertainties about costs, permitting and litigation. Environmental advocates and other opponents of the ACP called the decision to scrap the project a historic David-beats-Goliath win that – along with a recent blow to the Keystone XL oil sands pipeline – marks a turning point in the climate fight, illustrating the time has passed for energy companies to invest in massive fossil fuel infrastructure projects.”The Atlantic Coast Pipeline was an anvil that would have stymied investment in renewable energy for decades, harmed vulnerable communities, and crushed mountainsides,” Greg Buppert, a senior attorney at the Southern Environmental Law Center, which for the past six years has represented conservation groups opposing the project, said in a statement. Prominent conservation groups including the Sierra Club, the Natural Resources Defense Council and SELC did fight the pipeline, but the effort also included smaller, grassroots organizations, including more than 50 in Virginia and West Virginia that banded together to form the Allegheny-Blue Ridge Alliance. Getting the project built would have involved tree removal and blasting and leveling some ridgetops as the pipe, 42 inches (1 meter) in diameter for much of its path, crossed mountains, hundreds of water bodies and other sensitive terrain and burrowed underneath the Appalachian Trail.Dominion and Duke said in their announcement that a key reason they were abandoning the pipeline was a decision by a Montana judge in a case over the Keystone XL that would potentially keep the ACP tied up in court too.In the Keystone case, an April ruling from a federal judge dealing with a type of permit used to approve oil and gas pipelines and other utility work through wetlands and streams had threatened to delay not just that project but more than 70 other pipelines across the U.S. and add as much as $2 billion in costs, according to industry representatives.

Atlantic Coast Pipeline: why it took so long to defeat. -The Atlantic Coast Pipeline was a planned underground highway of natural gas, meant to cover 600 miles across the South. Activists were hugely worried about the environmental impact of the pipeline, so their strategy was to block every attempt to get it built. They tried to keep pipelines away from the Appalachian Trail. They argued that construction of the pipeline put endangered species at risk. They filed lawsuits. All this work slowed the pipeline down, but what no one was expecting was what happened this weekend: After six years of legal fights, Duke Energy and Dominion Energy, the companies behind this pipeline, announced that thewhole thing was canceled. How did this victory happen? And can it be replicated?On Wednesday’s episode of What Next, I spoke with Lyndsey Gilpin, the founder and editor in chief of Southerly, a media organization covering ecology, justice, and culture in the South, about the people who dedicated years to successfully busting the Atlantic Coast Pipeline. Our conversation has been edited and condensed for clarity.

Duke Energy, Dominion likely began to consider abandoning Atlantic Coast Pipeline last year – Charlotte Business Journal – Back in November, Duke Energy announced a $2.5 billion stock sale that allowed it “to absorb a wide range of outcomes associated” with the Atlantic Coast Pipeline. Turns out that amount covers the charge Duke expects to take against earnings for abandoning the project.

What sank the Atlantic Coast Pipeline? It wasn’t just environmentalism. – In a year of turmoil, the news that Dominion Energy and Duke Energy had decided to pull the plug on the pipeline still managed to be a bombshell. The companies had poured billions into the effort, which was only about 6 percent complete. They had just won a victory at the U.S. Supreme Court, which had declared the pipeline could pass beneath the Appalachian Trail. So what happened? Dominion attributed the pipeline’s demise to “ongoing delays and increasing cost uncertainty which threaten the economic viability of the project.” In particular, the utility pointed a finger at a string of legal challenges to federal and state permits the pipeline had received and then subsequently saw yanked. The delays had been extremely costly: since the initial $4.5 to $5 billion estimate, the price tag had risen to $8 billion. “To state the obvious, permitting for investment in gas transmission and storage has become increasingly litigious, uncertain and costly,” Farrell told investors on a Monday call. “This trend, though deeply concerning for our country’s economic growth and energy security, is a new reality.” President Donald Trump’s administration, which had argued on behalf of Dominion before the Supreme Court in February, blamed what U.S. Secretary of Energy Dan Brouillette on Sunday called “the well-funded, obstructionist environmental lobby,” an accusation picked up by industry groups like the U.S. Energy Association, which called out “environmental lobbyists with a myopic view and an ideology-driven agenda.” But seeing the ACP’s defeat merely as proof that natural gas pipeline projects are increasingly litigious and difficult to build “really ignores the fact that the problems with this project were self-inflicted,” said Southern Environmental Law Center attorney Greg Buppert, who has represented project opponents in numerous cases, including the Cowpasture case that went to the Supreme Court.”There were always different choices that the company could have made. … Those are decisions that have consequences,” he said.

NATURAL GAS: With Atlantic Coast dead, is this pipeline next? — The death of the long-embattled Atlantic Coast pipeline has energized environmental and public health groups looking to bring down other major oil and gas projects. For many in the Appalachian region, that means the 300-mile Mountain Valley pipeline, which is being built to move natural gas from northwestern West Virginia to southern Virginia and has faced similar backlash from local community groups. But the project’s developer, EQM Midstream Partners LP, insists the pipeline is on track to come online next year, and some analysts say the demise of the Atlantic Coast line could actually boost Mountain Valley’s prospects. Dominion Energy Inc. and Duke Energy Corp. axed the Atlantic Coast natural gas transmission pipeline Sunday, citing ongoing delays and concerns over the $8 billion project’s economic viability (Energywire, July 5). “It is a somewhat positive development for Mountain Valley because the Appalachian region is still a prolific gas-producing basin,” said Sreedhar Kona, a senior oil and gas analyst with Moody’s Investors Service. “There is gas that needs to get out, and now there is one less pipeline that can carry it.” Joe Dawley, a partner at Earth & Water Law who helped lead the push on the Mountain Valley pipeline project as a top attorney for natural gas producer EQT Corp., echoed this sentiment. He said that without the Atlantic Coast pipeline, Mountain Valley will have access to dedicated federal resources.”There are limited agency resources, so one less large project on their plate is beneficial to Mountain Valley,” he said. “But at the same time, the environmental scrutiny will be higher.”Indeed, environmental groups have found recent success by dragging fossil fuel projects through litigation battles. Lawyers with the Southern Environmental Law Center succeeded in getting the 4th U.S. Circuit Court of Appeals to stall the Atlantic Coast pipeline by arguing the permitting process was hurried and flawed (Energywire, July 7).

PIPELINES: Court urged to keep door shut on FERC delay tactic — Friday, July 10, 2020 — Environmentalist groups are asking a federal court to remain firm in its watershed decision to bar the Federal Energy Regulatory Commission from stalling challenges to pipeline projects, despite the agency’s request for more time.

Natural gas pipeline developers aim to differentiate from Atlantic Coast and avoid its fate –Duke Energy and Dominion Energy’s joint announcement canceling the Atlantic Coast Pipeline (ACP) natural gas project has spurred other natural gas pipeline developers to project confidence in their projects and differentiate themselves from ACP.”The industry is rightfully scared that the status quo is changing… and it’s therefore unsurprising that companies would be eager to find ways to distinguish themselves from Atlantic Coast,” Gillian Giannetti, an attorney in the Sustainable FERC Project at the Natural Resources Defense Council, told Utility Dive. “Whether that turns out to be appropriate remains to be seen.”Similar to ACP, the Mountain Valley Pipeline (MVP) project is crossing the Appalachian Trail and developers continue to pursue permitting for the project. They were quick to issue a statement on Sunday setting their project apart from ACP.”From the beginning, ACP and Mountain Valley Pipeline (MVP) have been very different projects, as evidenced by the fact that total project work for MVP is roughly 92% complete,” they said.Mountain Valley is owned by Equitrans Midstream, NextEra Energy, Consolidated Edison, AltaGas and RGC Resources. The pipeline is set to enter into service early next year and its capacity “has been fully subscribed since the onset of the project,” to deliver natural gas in the mid-Atlantic and Southeastern U.S.Reuters reported on Tuesday that analysts foresee how the proposed Southgate extension of the MVP project into North Carolina could gain traction due to the region’s growing energy demand in the wake of the ACP cancellation. But MVP has also run into challenges. FERC ordered a halt to construction in October along the entire route while the federal government studies MVP’s potential impacts on endangered species. But developers say the project remains on track. “As the MVP project team continues to work through and resolve the outstanding regulatory permits, the project’s current construction plan incorporates sufficient tie-in work and activity that will allow for construction to progress into the early winter, provided MVP receives its Biological Opinion in July and the FERC lifts the stop work order, all of which keeps MVP on track to meet its targeted early 2021 in-service date,” according to Natalie Cox, Equitrans spokesperson. But environmental groups maintain that MVP could face a similar fate to ACP. Another project, the PennEast Pipeline, also highlighted that it’s “unrelated” to ACP, according to spokesperson Patricia Kornick. The developers are pursuing a decision from the Supreme Court, which requested input from the U.S. Solicitor General on a permitting issue, which has caused environmental groups to compare the two projects.

PennEast Pipeline partners still determined to build $1 billion pipeline project – PennEast Pipeline partner companies remain committed to their pipeline project as they await a decision by the U.S. Supreme Court on whether the high court will hear its appeal, which could decide the projects fate. The appeal centers around a 2019 Third Circuit Court of Appeals decision denying the condemning of 42 parcels of New Jersey state-owned land for its $1 billion pipeline project. Before the high court makes its decision, Supreme Court justices had asked for the U.S. Solicitor General to file a brief expressing the Trump Administration’s views on the issue at hand on June 29, according to the U.S. Supreme Court docket for the petition. PennEast’s spokesperson Patricia Kornick said partner companies are pleased that the U.S. Supreme Court requested the views of the solicitor general regarding the issues presented in the company’s petition. “Eighteen business, labor and consumer advocacy organizations filing amicus briefs in support of the PennEast petition demonstrate the importance of reversing the Third Circuit’s decision.” The construction of the 116-mile long natural gas pipeline is a $1 billion project from Pennsylvania into New Jersey. If the pipeline project were to be constructed, its construction would occur in the Hopewell area, while the New Jersey leg of the pipeline accounts for about one-third of the total project. “PennEast remains hopeful that the U.S. Supreme Court will grant the petition and put an end to the ‘profoundly adverse impacts … on the development of the nation’s interstate natural gas transportation system’ that FERC has explained the Third Circuit’s decision is having,” Kornick said. The recent abandonment by Duke Energy and Dominion Energy of their own $8 billion pipeline project (Atlantic Coast pipeline) from West Virginia to North Carolina will not have any impact on future decisions by PennEast partner companies on PennEast’s own project, according to Kornick. In November, the company made the decision to appeal its federal appeals case to the U.S. Supreme Court. The decision came in light of a November ruling by Third Circuit Court of Appeals, denying PennEast’s request to rehear a case concerning the condemning of 42 parcels of New Jersey state-owned land for PennEast’s pipeline project. Due to that denial and opinion by the third circuit, the New Jersey Department of Environmental Protection also denied the company’s Freshwater Wetlands Permit application siting that PennEast’s application could not be “administratively complete” because of the circuit’s decision.

Controversial $180M pipeline that ruined a N.J. house has key permit suspended – The future of a controversial natural gas pipeline running through the Pinelands is in doubt after work on the project caused a house to be condemned last month. On Wednesday, the New Jersey Department of Environmental Protection suspended a key permit for construction of the Southern Reliability Link pipeline. The permit allowed for horizontal direction drilling (HDD) at specific points along the pipeline route. As long as the permit remains suspended, no such drilling is allowed for the project. The $180 million pipeline, which is being constructed by New Jersey Natural Gas, would carry natural gas 30 miles underground through Burlington, Monmouth and Ocean counties. The goal of the new pipeline is to provide more resilience to the areas natural gas supply in case of disaster, according to the utility. Environmental groups and opponents of the pipeline have long maintained there is no proof that such added resilience is necessary. Instead, they argue that the pipeline is a way to boost natural gas capacity as the fracking-driven natural gas boom in Pennsylvania’s Marcellus Shale region continues, and that the pipeline poses a threat to environmental health. HDD uses drilling fluid to bore horizontally through the ground, rather having workers dig a trench. If something goes wrong, that drilling fluid can force its way back to the surface and cause a spill known as an “inadvertent return.” In its letter to NJNG, the DEP said that three recent drilling-related spills had caused the SRL pipeline project to pollute sensitive environments like freshwater wetlands and headwater streams, thus violating the conditions of the permits. The DEP did not immediately respond to NJ Advance Media’s request for comment. Kevin Roberts, a spokesman for NJNG, said in a statement that the utility is working with authorities while HDD work for the pipeline remains suspended. Roberts added that NJNG still expects the SRL pipeline to be in service in 2021.

Are gas royalty owners buyers or sellers? In a court fight over royalties, the answer to that question could make all the difference to landowners – When natural gas drillers started rolling into Pennsylvania during the shale boom over a decade ago, some landowners got their hopes up. “Depending on the amount of acreage you had, people had big expectations and small expectations,” said Jackie Root, a consultant and membership director of the Pennsylvania Oil and Gas Landowner Alliance. Some farmers who leased their mineral rights were able to pay cash for new equipment or barns. Some landowners got enough money to put their kids through college. But for many, those expectations never materialized. “It’s like they’re led up to the river and then actually can’t get in there to drink,” Root said. Some say the drillers aren’t paying them what they’re owed. Many have joined class action lawsuits in an attempt to recover their losses. Some have reached settlements with companies, while others are still waiting on a final decision. Under the direction of former Gov. Tom Corbett and state Sen. Gene Yaw (R-Lycoming), then-Attorney General Kathleen Kane started investigating one driller, Chesapeake Energy, in early 2014. Her office filed a lawsuit in late 2015,alleging the company deceived landowners into leasing their mineral rights. The office said the case could affect more than 4,000 Pennsylvania landowners who signed leases with Chesapeake. Now, after years of delays, a case in Pennsylvania’s Supreme Court could determine whether the AG’s case can go forward. At the heart of that case is who is protected by the state’s Unfair Trade Practices and Consumer Protection Law. A decision siding with the AG would allow the case to finally be argued in Bradford County Court, where it originated. If they win there, royalty owners could have another tool when disputing contracts and payments with gas companies. Landowners hope that tool will ultimately help them get paid what they claim they’re owed.

U.S. natgas jumps to 5-week high on hot weather, rising cooling demand (Reuters) – U.S. natural gas futures jumped to a five-week high on Monday on forecasts calling for warmer weather and higher air conditioning demand over the next two weeks than previously expected. That price move comes despite rising output, coronavirus demand destruction, swelling stockpiles and a collapse in liquefied natural gas (LNG) exports to their lowest since 2018. Front-month gas futures rose 9.6 cents, or 5.5%, to settle at $1.830 per million British thermal units. That is their highest close since May 29 and is up almost 30% from a near 25-year low of $1.432 hit about a week ago. Looking ahead, futures for the balance of 2020 and calendar 2021 were trading about 22% and 43% over the front-month, respectively, on hopes the economy and energy demand will rebound as state governments lift coronavirus-linked lockdowns. Refinitiv said production in the Lower 48 U.S. states averaged 88.7 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June compared with an all-time monthly high of 95.4 bcfd in November. As the weather heats up, Refinitiv forecasts U.S. demand, including exports, would rise from 89.0 bcfd this week to 92.6 bcfd next week. That is higher than its forecasts on Thursday before the long U.S. July Fourth holiday weekend. Pipeline gas flowing to U.S. LNG export plants averaged just 3.2 bcfd (33% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record high of 8.7 bcfd in February. Utilization was about 90% in 2019. U.S. pipeline exports, meanwhile, were mixed. Refinitiv said pipeline exports to Canada averaged 2.4 bcfd so far in July, up from 2.3 bcfd in June but still well below the all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico, however, averaged 5.2 bcfd so far this month, down from 5.4 bcfd in June and a record 5.6 bcfd in March.

U.S. natgas output drops by record amount after West Virginia pipe shuts – U.S. natural gas production was on track to drop by a record amount on Tuesday to its lowest since September 2018 due in part to unplanned work on TC Energy Corp’s Mountaineer Xpress pipeline in West Virginia, according to Refinitiv data.Preliminary pipeline flow data showed U.S. output was expected to drop by 4.2 billion cubic feet per day (bcfd) to 84.6 bcfd on Tuesday. One billion cubic feet is enough gas to supply about 5 million U.S. homes for a day. If correct, that would be the biggest daily decline on record, according to Refinitiv data going back to 2011. Traders, however, noted pipeline flows are measured several times a day and the data is subject to change. Analysts said work on the 2.6-bcfd Mountaineer Xpress was expected to reduce output in West Virginia by around 2.0 bcfd, so the rest of the nation’s production declines were scattered among several other states and not necessarily related to Mountaineer. TC Energy’s Columbia Gas Transmission (TCO) unit, which operates the Mountaineer pipe, said on its website that it declared a force majeure effective for the evening cycle on Tuesday, July 7, due to unplanned maintenance. That work requires a pressure reduction south of the Mount Olive compressor station. The company did not say when the pipe would return to full service. Officials at TC Energy were not immediately available for comment. Despite the output decline on Tuesday, Refinitiv said production in the Lower 48 U.S. states has averaged 88.1 bcfd so far in July.

NYMEX prompt hits two-month high as force majeure cuts Appalachian production | S&P Global Platts -NYMEX Henry Hub prompt-month prices surged to a two-month high in July 7 trading after a force majeure on Columbia Gas’ Mountaineer XPress Pipeline cut Appalachian gas production by over 2.2 Bcf/d, amid no announced timeline for a return to service on the impacted segment. After trading into the low $1.90s, the August contract settled July 7 at $1.88/MMBtu – up more than 20 cents since the start of the month to its highest closing price since early May. In the cash market, Henry Hub gas rose about 4 cents on the day to $1.74/MMBtu, preliminary settlement data from S&P Global Platts showed. In Appalachia, gas production dropped on July 7 by over 2.2 Bcf on the day to an estimated 29.8 Bcf, its lowest in 14 months, amid concentrated declines in the West Virginia wet and South Pennsylvania dry windows, data compiled by S&P Global Platts Analytics showed. While upstream receipts are likely to be revised higher as rerouted production becomes visible, a return to prior 30-day output levels in Appalachia, around 31.6 Bcf/d, could be limited by existing flow restrictions on other regional pipes, including Texas Eastern Transmission, and by elevated storage levels. In a critical notice updated July 7, Columbia Gas said that unplanned maintenance on a segment of its Mountaineer XPress Pipeline near Leach, Kentucky would a require a temporary pressure reduction, dropping capacity on the line to 100 MMcf/d, down from its nameplate 2 Bcf/d. According to the updated posting, the pressure reduction will remain in effect until further notice. Flows along the affected segment of Mountaineer XPress dropped to 100 MMcf/d July 7, down from a prior 30-day average at 1.9 Bcf/d. In West Virginia, evening cycle production receipts dropped roughly 1.6 Bcf on the day, while receipts in southern Pennsylvania were down by over 400 MMcf/d. Appalachian market At Appalachia’s benchmark Dominion South hub, stranded production overwhelmed local demand, driving cash prices down about 16 cents on the day to a preliminary settlement at $1.33/MMBtu. According to Platts Analytics, Tennessee Gas Pipeline has the most spare-capacity among alternate interstate pipes exiting the Appalachian Basin, with roughly 500 MMcf/d available. With capacity on Texas Eastern Transmission limited by its own ongoing pressure reduction near the Owingsville compressor station in Kentucky, the pipeline is current flowing nearly full around 1.4 Bcf/d.

U.S. natgas climbs to 2-month high on hot weather, pipe shutdown – (Reuters) – U.S. natural gas futures rose to a two-month high on Tuesday with output on track to fall by a record amount after a pipe shutdown in West Virginia and on forecasts confirming Monday’s hot weather outlook that will keep air conditioners humming for the next two weeks. The price rise comes despite coronavirus demand destruction, stockpiles swelling toward record highs, and a collapse in liquefied natural gas (LNG) exports to their lowest levels since 2018. Front-month gas futures rose 4.6 cents, or 2.5%, to settle at $1.876 per million British thermal units. That is the highest price since May 7 and up 31% from a near 25-year low of $1.432 hit about a week ago. Looking ahead, futures for the balance of 2020 and calendar 2021 were trading about 19% and 37%, respectively, over the front-month, on hopes the economy will rebound and energy demand will increase as state governments lift coronavirus-linked lockdowns. U.S. gas production was on track to drop by a record amount on Tuesday to its lowest level since September 2018 due in part to unplanned work on TC Energy Corp’s Mountaineer Xpress pipeline in West Virginia. Overall, however, Refinitiv said production in the Lower 48 U.S. states averaged 88.1 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June compared with an all-time monthly high of 95.4 bcfd in November. As the weather heats up, Refinitiv forecasts U.S. demand, including exports, will rise from 88.8 bcfd this week to 91.9 bcfd next week. That is a little lower than its forecasts on Monday.

U.S. natgas slides on smaller than expected output drop, less cooling demand –(Reuters) – U.S. natural gas futures slipped on Wednesday from a two-month high in the prior session on a forecast small decline in cooling demand next week, a continued drop in liquefied natural gas (LNG) exports and a smaller than expected drop in output due to unplanned pipeline work. Front-month gas futures fell 5.2 cents, or 2.8%, to settle at $1.824 per million British thermal units. On Tuesday, the contract closed at its highest since May 7. Looking ahead, futures for the balance of 2020 and calendar 2021 were trading about 22% and 43%, respectively, over the front-month, on hopes energy demand will rise. Refinitiv said production in the Lower 48 U.S. states averaged 88.2 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November. U.S. gas production on Wednesday was on track to drop to its lowest since mid June following revisions of pipeline flows on Tuesday due to unplanned work on TC Energy Corp’s Mountaineer Xpress pipeline in West Virginia that will continue through at least July 13. On Tuesday, early pipeline flow data showed output was expected to drop by a record 4.2 bcfd. In reality, however, output fell by just 1.9 bcfd, which is still high but only the most in a day since May 1. As the weather heats up, Refinitiv forecasts U.S. demand, including exports, will rise from 89.1 bcfd this week to 91.0 bcfd next week. The outlook for next week is a little lower than Refinitiv expected on Tuesday. Pipeline gas flowing to U.S. LNG export plants averaged just 3.1 bcfd (32% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record high of 8.7 bcfd in February. Utilization was about 90% in 2019.

US working natural gas volume in underground storage rises by 56 Bcf: EIA | S&P Global Platts – US natural gas in storage rose 56 Bcf in the week ended July 3, according to Energy Information Administration data released July 9, as electric generation boosted demand and the Henry Hub prompt-month contract continues to inch closer to the $2/MMBtu mark. The estimated 56 Bcf build, to total underground gas storage stocks of 3.133 Tcf, was slightly above consensus expectations of an S&P Global Platts’ survey of analysts, which called for a 55 Bcf build. Responses to the survey ranged from an injection of 42 Bcf to one of 65 Bcf. The injection was smaller than the 83 Bcf build reported during the corresponding week in 2019 and the five-year average increase of 68 Bcf, according to EIA data. Summer heat intensified across the US Midwest and Southeast in the week that ended July 3, pushing estimated nationwide power burn to a year-to-date high of 39.9 Bcf/d, according to S&P Global Platts Analytics. Meanwhile, after bottoming out at 3.8 Bcf/d two weeks ago, LNG feedgas deliveries held above 4 Bcf/d for the second week in a row, helping trim the 18% inventory surplus that will weigh on Henry Hub prices through the end of injection season in October. Storage volumes now stand 685 Bcf, or 28%, above the year-ago level of 2.448 Tcf and 454 Bcf, or 17%, above the five-year average of 2.679 Tcf. Platts Analytics’ supply and demand model currently expects a 52 Bcf injection for the week ending July 10, which would be 11 Bcf below the five-year average, as supply-and-demand fundamentals draw tighter. Gas-fired power demand continues to ratchet up deeper into the US cooling season. Year-to-date power burn has been impressive from the perspective of electricity demand, which was relatively lackluster because of a mild winter, followed immediately by the suppressive impact of coronavirus and efforts to mitigate its spread. However, corresponding pressure to gas prices has provided gas-fired generation the ability to increase market share and dominate the supply stack, displacing an enormous amount of coal-fired generation, according to Platts Analytics. Through June, electricity demand across the continental US averaged 4% lower year on year, while gas-fired generation managed to increase 7% in the same period. Gas prices at Henry Hub averaged 90 cents/MMBtu lower through the first half of 2020, which facilitated nearly 30% year-on-year declines in coal-fired generation.

U.S. natgas futures fall with crude prices after storage report – (Reuters) – U.S. natural gas futures fell over 2% on Thursday, following a 3% decline in crude futures related to worries about ongoing coronavirus demand destruction despite a report showing a smaller-than-usual weekly gas storage build that was in line with estimates. That price drop also came as gas output slowly rises and liquefied natural gas (LNG) exports slowly fall, despite forecasts for hot weather and high air conditioning demand over the next two weeks. The U.S. Energy Information Administration (EIA) said U.S. utilities injected 56 billion cubic feet (bcf) of gas into storage during the week ended July 3. That is close to the 58-bcf build analysts forecast in a Reuters poll and compares with an increase of 83 bcf during the same week last year and a five-year (2015-19) average build of 68 bcf for the period. Front-month gas futures fell 4.5 cents, or 2.5%, to settle at $1.779 per million British thermal units. Refinitiv said production in the Lower 48 U.S. states averaged 88.1 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November.

U.S. natgas futures rise as hot weather boosts air conditioning demand –(Reuters) – U.S. natural gas futures climbed on Friday on forecasts hotter-than-normal weather will keep air conditioners humming through late July. The higher price move comes despite a slow increase in output and a drop in liquefied natural gas (LNG) exports to their lowest since early 2018. Front-month gas futures rose 2.6 cents, or 1.5%, to settle at $1.805 per million British thermal units. For the week, the contract gained about 4%, putting it up for a second week in a row after soaring 16% last week. Traders predicted that Tropical Storm Fay, which is heading for the New York City area, would likely have little impact on gas demand. Refinitiv said production in the Lower 48 U.S. states averaged 88.1 billion cubic feet per day (bcfd) so far in July, up from a 20-month low of 87.0 bcfd in June but still well below the all-time monthly high of 95.4 bcfd in November. As the weather heats up, Refinitiv forecast U.S. demand, including exports, will rise from 89.3 bcfd this week to 91.4 bcfd next week and 93.3 bcfd in two weeks. Pipeline gas flowing to U.S. LNG export plants averaged just 3.1 bcfd (32% utilization) so far in July, down from a 20-month low of 4.1 bcfd in June and a record high of 8.7 bcfd in February. Utilization was about 90% in 2019. Flows to Freeport LNG in Texas fell to zero for a fourth day in a row the first time since July 2019 when its first liquefaction train was still in test mode. Refinitiv said pipeline exports to Canada averaged 2.4 bcfd so far in July, up from 2.3 bcfd in June but still below the all-time monthly high of 3.5 bcfd in December. Pipeline exports to Mexico averaged 5.4 bcfd for a second month in a row, which is down from a record 5.6 bcfd in March.

Anti-Line 5 activists buoyed by national pipeline victories ⋆ Indigenous activists and environmentalists scored two major victories over pipeline companies this week in quick succession. On Sunday, two major energy companies in Virginia and North Carolina announced that permitting delays, economic concerns and legal challenges have caused them to pull the plug on a $8 billion natural gas pipeline. The Atlantic Coast pipeline would have traveled under the Appalachian Trail. Only a day later, a federal judge ruled that the controversial Dakota Access Pipeline (DAPL) will be shut down for a thorough environmental review – possibly for years – and must be emptied of oil by early August. Could a few significant wins for water defenders also spell trouble for Enbridge, the Canadian oil company facing criticism and lawsuits over its Line 5 oil pipeline under the Straits of Mackinac? Enbridge, in addition to being the largest pipeline company in North America, is also a partial owner of the DAPL. The 27.6% stake it holds in the Bakken Pipeline System housing the DAPL translates to an investment of $1.5 billion. Enbridge finalized that investment in 2016 – the same year that protests against the DAPL surged and led to violent clashes between indigenous people and law enforcement in North Dakota. The Line 5 dual pipeline has transported oil across the Straits bottomlands for nearly 70 years. A 1953 easement with the state of Michigan allows Enbridge to operate under the choppy waters connecting Lake Michigan and Lake Huron. Sean McBrearty, campaign coordinator for the anti-Line 5 Oil & Water Don’t Mix coalition, said Monday’s DAPL court order was a “monumental victory” for North Dakota’s Standing Rock Sioux Tribe. “Across the country, courts and government agencies are beginning to realize that environmental protections must be enforced to protect residents and our natural resources from the devastating impacts of further fossil fuel development,” McBrearty said.

Tests show west leg of Line 5 pipeline isn’t damaged – A court-ordered investigation on one of the dual Line 5 oil pipeline’s underwater segments found no indication of metal loss or deformation on an area of interest, according to court documents obtained by the Advance. Canadian oil company Enbridge had restarted the west leg of Line 5, which runs under the Straits of Mackinac, on July 1 under orders from circuit court Judge James Jamo. Jamo had requested that an in-line inspection (ILI) be completed on a 50-square-inch area toward the middle of the pipeline and that Enbridge provide those results to the state within seven days. The west segment remains in operation while the east segment remains shut down. “The inspection results conclude that there are zero metal loss and zero dent anomalies in this area. These results are consistent with past ILI inspection results and demonstrate the pipeline is safe and fit for continued operation,” Enbridge’s notice of the west line investigation report reads. Enbridge spokesperson Ryan Duffy said the test “reconfirms that the west leg of the pipeline is safe to operate” and emphasized that the state of Michigan will continue to be advised of further investigations. Enbridge has not been able to conclude definitively what caused the damage to either line, but says the discolored patch and disturbed aquatic biota on the west line’s area of interest was likely caused by a thin, lightweight cable being dragged perpendicular across it by a boat. Sean McBrearty, campaign coordinator to the anti-Line 5 Oil & Water Don’t Mix coalition, said in a statement Thursday afternoon that the July 1 investigation results should not reassure Michiganders about the pipeline’s risk to the Great Lakes. “While Enbridge wants us to be reassured by a report they issued today on the damage to one of two Line 5 pipelines, this is just another finger holding back a breach in the proverbial overflowing dam,” McBrearty said. “Only luck is keeping Michigan and the Great Lakes being hit with a catastrophic Line 5 rupture. ” … Michigan shouldn’t be relying on Enbridge to keep the Great Lakes safe. The fact that Gov. Whitmer is content with simply keeping a finger poised to plug the next immediate Line 5 threat is disappointing and unacceptable. The solution is obvious: we need all hands on deck to shut down Line 5 and that includes Michigan’s governor,” McBrearty continued.*

Natural gas pipeline from Wicomico to Somerset County, public comment open – – A natural gas pipeline is proposed to be built on the Eastern Shore by the end of 2021. Many are voicing their support and citing economic growth but environmentalists aren’t too happy with the project. The Maryland Department of Environment held the first public hearing on this proposal on Tuesday night. Lawmakers say this has been in the works for more than two decades. Supporters say this will entice more businesses to set up shop in Somerset County as well as benefit the University of Maryland Eastern Shore and Eastern Correctional Institution. However, critics say there are safer alternatives that won’t put residents’ health at risk. “It’s either the pipeline or nothing. But my perspective is that there are choices,” says Susan Olsen with the Lower Eastern Shore Group of the Sierra Club. Residents and officials are making their voices heard about an almost 18-mile long proposed natural gas pipeline extension, stretching the Del-Mar Energy Pathway Project from Wicomico County to Somerset County. “We want a clean environment. We want a sustainable environment. We also need a sustainable economic future,” says Jim Mathias, the director of government relations for the University of Maryland Eastern Shore. According to proposals, 91 percent of the pipeline would be under existing roadways like Route 13 but it would also cross some areas with water to reach Princess Anne and Westover. Environmental groups are concerned about this project because these pipes can leak which some research links to health issues including cancer. “I don’t think we have to go to fracked gas. It’s too dangerous,” says Olsen. Officials say this change would make Somerset County more attractive to new businesses and offer a cheaper more eco-friendly alternative to places that currently use diesel fuel including the University of Maryland Eastern Shore and Eastern Correctional Institution. “The conversion to natural gas would reduce CO2 emissions at ECI by 64 percent and reduce CO2 emissions at UMES by 23 percent,” says Maryland Senator Mary Beth Carozza.

Shell is testing the market to sell its Convent refinery, Sorrento salt cavern and more – Shell is testing the market to potentially sell its Convent refinery and various facilities associated with the site. A potential sale of the Convent refinery, located midway between Baton Rouge and New Orleans, also would include its products truck terminal, marine docks, the Sorrento salt cavern for liquefied petroleum gas storage, and rights for its Bengal Pipeline. “We have informed staff and local community leaders that we are assessing market interest for the potential divestment of the Shell Convent refinery in Louisiana,” spokesman Curtis Smith said. He said the process could take several months. The plan is consistent with a mid-2019 announcement that the company plans to narrow its ownership to a smaller, optimal core set of “uniquely positioned refineries by 2025.” The remaining core sites will be ones more closely integrated with Shell trading hubs and able to produce more chemicals and related products expected to be resilient in a low-carbon future. “It’s important to keep in mind this process may or may not result in a finalized sale,” Smith said. He said the U.S. Gulf Coast will remain a key region for Shell through its integrated manufacturing sites, Gulf of Mexico oil and gas operations, midstream infrastructure assets, branded gasoline outlets and hub offices in Houston and New Orleans. The refinery is located on a 4,400-acre site that straddles Ascension and St. James parishes and employs 700 Shell workers and 400 contract workers. The processing equipment is located in St. James Parish and occupies about 900 acres, according to the company’s website, with a capacity to process 240,000 barrels of crude oil per day. The refinery produces various grades of gasoline; jet fuel; diesel fuel and heating oil; propane and butane for residential and industrial use; and oil for tankers, power generation and locomotives. The facility has access to multiple major crude oil and product pipelines, which ship gasoline, diesel, kerosene and jet fuel. The site’s location on the Mississippi River allows shipping and receiving petroleum products aboard ocean-going vessels. The refinery uses two docks along 6,000 feet of Mississippi River access.

Dakota Access Pipeline Shutdown Will Not Affect Bayou Bridge Pipeline, Says Company That Owns Both – The temporary closure of the Dakota Access Pipeline will not affect Louisiana’s Bayou Bridge Pipeline, according to the company that owns both.”The Bayou Bridge Pipeline is an extension of a pre-existing network of infrastructure that has already been in place for years,” Energy Transfer spokesperson Lisa Coleman said in an email Tuesday morning. “The pipeline is fully permitted and will remain in operation.”On Monday, a federal judge ordered the Dakota Access Pipeline to be shut down and drained of oil while an environmental impact statement was completed by the Army Corps of Engineers. It’s the latest development in a multi-year fight that involved high-profile Standing Rock protests in North Dakota in 2016.The Obama Administration denied permits for the pipeline in 2016, but the Trump Administration quickly reversed that decision once he took office in 2017. It was completed in 2017.In Monday’s ruling, U.S. District Judge James Boasberg decided that the permits issued by the Army Corps of Engineers violated federal environmental law, that the Corps needs to amend its environmental assessment, and that the pipeline should cease operations while that takes place.Energy Transfer disagreed with the judge’s ruling. In a statement, the company said it believes Boasberg “exceeded his authority in ordering the shutdown of the Dakota Access Pipeline, which has been safely operating for more than three years.” Coleman said the company is “looking into all options available to us to keep the Dakota Access Pipeline operating.” Bayou Bridge also faced resistance to its construction, albeit with a much lower profile compared to the Dakota Access. Over a span of many months in 2018, landowners and protesters attempted to block its construction both on the ground and in the courts.That included several arrests in 2018, including a few made that Septemberunder a then-new Louisiana law that made trespassing on pipeline property a felony, rather than just a misdemeanor. Construction stopped briefly in September 2018 when a landowner accused the company of illegally trespassing, but resumed shortly thereafter. In December 2018, a Louisiana judge ruled that the company had indeed trespassed, but was allowed to exercise eminent domain over the property. The Bayou Bridge Pipeline ultimately went into service in March of 2019.

US Oil Exports Can Compete at $30 Break-Even –The near-term economic shock of the coronavirus, or COVID-19 pandemic has been profound, and as a domino effect the price of the global economy’s poster commodity – crude oil – has taken a hammering. Largely predictable range-bound oil price oscillation seen for much of 2019, gave way in February 2020 to extreme volatility as soon as the human cost and economic upheaval caused by the virus in China, its point of origination, became clear. Subsequent collapse of OPEC+ on March 6 and sparring between Saudi Arabia and Russia, coupled with the global spread of the virus, then created a supply glut as well as a demand crisis in tandem. As oil threatened to slide below $20, OPEC scrambled back to the negotiating table and brokered a 9.7 million barrels per day (bpd) production cut effective May 1. But the deal came too late to save April and was too little for May. That’s because all of the big five crude oil-consuming nations – U.S., China, India, Japan and South Korea – were experiencing lockdowns. Around the world, aviation, services and manufacturing sectors were seen taking the biggest hit. That meant paper traders were left dangling West Texas Intermediate (WTI) May contracts due for expiry on April 21, and their attempts at dumping a day before saw U.S. oil prices enter a negative patch for the first time in trading history closing at -$37.63 per barrel. That situational aberration aside, some semblance of normalcy is returning. While it is premature to assume the only way is up, major crude markets are limping back to heath. The westward spread of the virus has meant East Asian markets have been among the first to come out of the pandemic and are looking to step up economic activity. Such a scenario augurs well for U.S. exporters still left in the game, given that 2019 offered ample proof of incremental volumes of the country’s light sweet crude heading to Asia in general and East Asia in particular. According to Energy Information Administration (EIA), May 2019 saw more than half of 3 million bpd in exported American barrels going to Asia.

North American Oil And Gas Companies Continue To Go Bankrupt At $40 Oil –The rash of oil and gas bankruptcies in North America is set to continue for the remainder of 2020, a report by Haynes and Boone cited by Reuters shows. After the coronavirus pandemic and oil price war set in at the end of the first quarter, the second quarter began with a wave of bankruptcies in the oil and gas sector in North America, according to the report. There have been more than 18 producer bankruptcies in Q2 alone, according to Haynes and Boone – it is the highest quarterly figure since 2016 during the previous oil price crash. So far this year, 41 oil producers and oilfield service firms have sought bankruptcy protection. Even without the coronavirus pandemic or the oil price war, the flurry of bankruptcies were to be expected, with companies holding junk-rated bonds defaulting on interest payments at record levels even in 2019, with more distressed companies in the energy sector than in any other, Michael Bradley, energy strategist with Tudor, Pickering, Holt said at the end of last year. Of course, these distressed companies were all holding out hope that oil prices would recover in 2020. Nothing could have been further from how this year is playing out. This year has seen Chesapeake Energy, Diamond Offshore Drilling, Whiting Petroleum, And even while prices have rebounded, the $40 per barrel oil price right now will not be sufficient to stave off doom for the debt-laden shale producer, Haynes and Boone said. $40 oil will not be enough for shale companies to make good on their hefty debt obligations. Rystad Energy in April warned that as many as 530 U.S. oil companies could file for bankruptcy protection if oil had stayed at $20 per barrel.

PANDEMIC: Texas drilling permits plunge 69% — Thursday, July 9, 2020 — The biggest oil-producing state in the country issued less than a third as many oil and gas drilling permits last month as it did in June 2019, another sign of the COVID-19 pandemic’s impacts on the energy industry.

‘We aren’t going away’: Oil drilling inside city limits remains thorny issue for many Texans – – An explosion jolted Jim and Mary Alice Estes awake early one morning last June as light from a nearby fireball danced on the walls of their home. The giant flare was from natural gas burning at an oil well being put into production a few hundred feet behind their property. A drilling rig had been parked behind their Bethel Springs Lane home for months, but nobody warned the couple or their neighbors in the Magnolia Creek subdivision that such startling production work would be taking place. Fearing something had gone wrong, they called 911. It was a rude awakening, literally, to a reality endured by thousands of city and suburban residents across Texas with oil and natural gas operations in their backyards.It came some five years after the passage of House Bill 40, a law that was supposed to sort out legal issues for drilling within city limits. Before oil and natural gas wells can be drilled within city limits, they require permits from both state and local officials. Supporters of House Bill 40 say the law settled what the state regulates and what cities control reaffirms. The bill reaffirmed the state’s authority to regulate the technical and underground aspects of an oil well while giving cities the authority to control surface activities such as traffic, noise and light, and requires wells to be a certain distance from homes and businesses. Critics, however, say the debate over distance requirements remains unsettled and that the law makes cities hostages to lawsuits, leaving them powerless to deny drilling permits. “That bill put profits over people and has made cities afraid to fight back,” Mary Alice Estes said. “None of the people who signed that bill would want to live in our house, on our street and experience what we experienced.” The vast majority of the state’s 438,000 oil and gas wells are in rural areas, but there are thousands in cities such as Fort Worth and Houston, in suburban communities and under entire towns in the Permian Basin, according to the Railroad Commission of Texas, the state agency that regulates the industry.Over the decades, oil companies have drilled hundreds of wells in areas that have been swallowed up by Houston as the city grew. An area across Loop 610 from NRG Stadium is surrounded by hundreds of wells. Many have been plugged, but other wells were drilled in South Houston, the Oates Prairie neighborhood in northeast Houston and near the Sam Houston Race Park off Windfern Road near Beltway 8 in northwest Houston. The Magnolia Creek subdivision in League City, about halfway between Houston and Galveston along I-45, has $350,000 homes, parks, trails and a golf course. It was built over former rice fields that contained decades-old drilling sites.

Ruling: Nearly half of Okla. under tribal control — Thursday, July 9, 2020 — Millions of acres in the eastern half of Oklahoma remain part of a Native American reservation for criminal law purposes, the Supreme Court said today in a sharply divided ruling that could have implications for oil and gas development in the state. This morning’s 5-4 decision put an end to a stalemate over whether 3 million acres of land, including part of the city of Tulsa, remained within the boundaries of Indian Country under an 1832 treaty struck with the Creek Nation after the U.S. government forced members of the tribe from their lands in Georgia and Alabama. The decision also recognized four other reservations in the state, bringing the total reservation land to 19 million acres. “Today we are asked whether the land these treaties promised remains an Indian reservation for purposes of federal criminal law,” Justice Neil Gorsuch, joined by the court’s four liberal justices, wrote for the majority. “Because Congress has not said otherwise, we hold the government to its word.” The case, McGirt v. Oklahoma, had drawn the attention of at least one oil and gas association, which warned of the potential consequences to energy development if the high court found that the lands were still under tribal control. Gorsuch today acknowledged the “potential for cost and conflict” as a result of the ruling but said the state and tribe are capable of reaching intergovernmental agreements. Chief Justice John Roberts, who penned the court’s dissenting opinion, also warned of the broad potential consequences of the ruling. He was joined by Justices Samuel Alito, Brett Kavanaugh and Clarence Thomas, except in one footnote of the opinion. Roberts argued that today’s decision would hobble the state’s ability to prosecute serious crimes and could lead to decades of convictions being thrown out. “On top of that, the Court has profoundly destabilized the governance of eastern Oklahoma,” the chief justice wrote. “The decision today creates significant uncertainty for the State’s continuing authority over any area that touches Indian affairs, ranging from zoning and taxation to family and environmental law.”

New Mexico fines oil and gas company DCP Midstream – A Denver-based oil and gas company was fined $5.3 million by the New Mexico Environment Department (NMED) for repeated violations of state air pollution standards dating back to 2017. DCP Midstream was issued a compliance by NMED on Tuesday for eight Permian Basin facilities in Eddy and Lea counties which had thousands of past violations between December 2017 and June 2019, per a news release from NMED. During that time, DCP submitted 367 excess emission reports for the eight facilities, totaling in more than 2.1 million pounds of pollutants, read the release. Aside from the civil financial penalty, NMED’s order also demanded that DCP immediately comply with all air permit limits and state and federal air quality laws. DCP Midstream spokesperson Sarah Sandberg said the company received NMED’s order and plants to respond to the allegations. She maintained that the emission releases “generally” related to equipment malfunctions and leaks and were excused from civil penalties under state law.

New Mexico again cites Kinder Morgan over 2018 gas spill cleanup in Anthony – . – Kinder Morgan was issued a formal notice of violation Tuesday by the New Mexico Environment Department’s Hazardous Waste Bureau over its cleanup of a 2018 oil spill in southern Dona Ana County. A gasoline pipeline operated by the company burst near Three Saints Road outside the city of Anthony. According to the bureau, more than 400,000 gallons of refined petroleum spilled, requiring solid waste cleanup of contaminated soil. That amount is higher than previously reported. Three families were evacuated and temporarily lodged at hotels, at the company’s expense. 54,600 gallons of gasoline were reported to have soaked into the Anthony Drain, a ditch within the Elephant Butte Irrigation District. In Tuesday’s notice, the bureau said Kinder Morgan violated New Mexico statutes by failing to test the contaminated soil for toxicity until after it moved the soil, allegedly stockpiling next to a ditch before moving it to another location. Because it was moved, the bureau said levels of benzene in the soil were reduced before it was measured, obscuring the extent of toxicity where the spill took place. “Kinder Morgan failed to make a hazardous waste determination at the point of generation, before an alteration of the waste occurred,” bureau chief Kevin Pierard wrote in the notice. “As a result, Kinder Morgan also failed to make an accurate determination as to whether the petroleum contaminated soil was a hazardous waste, a necessary step to ensure proper management of the waste stream.”

Judge Orders Dakota Access Pipeline to Shut Down – Owners of the Dakota Access Pipeline (DAPL) must halt operations while the government conducts a full-fledged analysis examining the risk DAPL poses to the Standing Rock Sioux Tribe, a federal judge ruled today. The court decision delivered a hard-fought victory to the Tribe, which has been engaged in a high-profile struggle against the Dakota Access Pipeline since 2016.The ruling ordering a shutdown of DAPL marks the final word of a March 25 decision by the same judge. That ruling found that the U.S. Army Corps of Engineers had violated the National Environmental Policy Act (NEPA) and glossed over the devastating consequences of a potential oil spill when it affirmed its 2016 decision to permit the pipeline. The court ordered the Corps to re-examine the risks of the pipeline and prepare a full environmental impact statement, but left open the question as to whether pipeline operations would be halted as a legal remedy pending further briefing. After carefully analyzing the seriousness of the government’s legal violations, and the potential impacts on the Tribe and third parties, today’s decision concluded that shutting down the pipeline was necessary.The shutdown will remain in place pending completion of a full environmental review, which normally takes several years, and the issuance of new permits. It may be up to a new administration to make final permitting decisions. “Today is a historic day for the Standing Rock Sioux Tribe and the many people who have supported us in the fight against the pipeline,” said Chairman Mike Faith of the Standing Rock Sioux Tribe. “This pipeline should have never been built here. We told them that from the beginning.””It took four long years, but today justice has been served at Standing Rock,” saidEarthjustice attorney Jan Hasselman, who represents the Tribe. “If the events of 2020 have taught us anything, it’s that health and justice must be prioritized early on in any decision-making process if we want to avoid a crisis later on. “

Dakota Access Oil Line to Be Shut by Court in Blow for Trump (2) -The Dakota Access pipeline must shut down by Aug. 5, a district court ruled Monday in a stunning defeat for the Trump administration and the oil industry. The decision, which shuts the pipeline during a court-ordered environmental review that’s expected to extend into 2021, is a momentous win for American Indian tribes that have opposed the Energy Transfer LP project for years. It comes just a day after Dominion Energy Inc. and Duke Energy Corp. scuttled another project, the Atlantic Coast natural gas pipeline, after years of legal delays.Environmentalists have increasingly used the courts to try to block additional investment in fossil fuel infrastructure while they push for a clean energy transition. Tribes, landowners, and other project opponents have also complained about local impacts from construction and potential spills on or near their land.The sophisticated legal onslaught has led to delays and disruptions for numerous other proposed and operational pipelines, including Keystone XL. But Monday’s court order, if upheld on appeal, marks the first time a major, in-service oil pipeline will be forced to shutter because of environmental concerns. The U.S. District Court for the District of Columbia said a crucial federal permit for Dakota Access fell too far short of National Environmental Policy Act requirements to allow the pipeline to continue operating while regulators conduct a broader analysis the court ordered in a previous decision. The ruling scraps a critical permit from the Army Corps of Engineers, and requires the pipeline to end its three-year run of delivering oil from North Dakota shale fields to an Illinois oil hub. Judge James E. Boasberg said Dakota Access must shut down the pipeline and empty it of oil by Aug. 5. “Today is a historic day for the Standing Rock Sioux Tribe and the many people who have supported us in the fight against the pipeline,” tribal Chairman Mike Faith said in a statement. “This pipeline should have never been built here. We told them that from the beginning.” The Army Corps referred questions about the ruling to the Justice Department, which didn’t immediately respond to requests for comment, including on whether it intends to appeal the ruling.

Court orders Dakota crude pipeline shutdown, in win for Native American tribes in long-running saga – A federal court ruled Monday that the Dakota Access Pipeline must shut down within 30 days, by Aug. 5, according to a copy of the brief obtained by USA Today. The U.S. District Court for the District of Columbia scrapped a key permit from the Army Corps of Engineers, and ordered the pipeline to end its three-year run of delivering oil out of North Dakota’s Bakken shale basin to its endpoint in Illinois. The decision marked the end of a yearslong legal battle over the Energy Transfer Partners-owned pipeline’s environmental damage to the Missouri River. President Donald Trump granted the permit in 2017 over the objections of the Standing Rock Sioux Tribe and environmental activists, arguing oil spills could contaminate their water source and put their culture at risk. The court ruled the pipeline be shut down pending a full environmental review ordered previously. “The Corps had failed to produce an Environmental Impact Statement despite conditions that triggered such a requirement,” the court ruling said. “Although mindful of the disruption such a shutdown will cause, the Court now concludes that the answer is yes.” “Given the seriousness of the Corps’ NEPA error, the impossibility of a simple fix, the fact that Dakota Access did assume much of its economic risk knowingly, and the potential harm each day the pipeline operates, the Court is forced to conclude that the flow of oil must cease,” the ruling said. A spokesperson at Energy Transfer Partners told CNBC the pipeline is “the safest, most environmentally responsible method for moving North Dakota’s crude oil to refining markets around the country.” “Shutting down this critical piece of infrastructure would throw our country’s crude supply system out of balance, negatively impact several significant industries, inflict more damage on an already struggling economy, and jeopardize our national security,” the spokesperson said. “This was an ill-thought-out decision by the Court that should be quickly remedied.”

Dakota Access Pipeline Decision: The Standing Rock Generation Triumphs – The story of the Dakota Access Pipeline is as damning a tale as any told about the crooked dealings of the colonists and capitalists who swindled this continent away from its First Peoples. You’ve probably heard it already, but just in case, here’s the synopsis. An oil pipeline with close financial ties to Donald Trump – he was an investor, and Kelcy Warren, the CEO of Energy Transfer Partners, the company that operates the pipeline, is a donor – was rerouted from upstream of the predominantly white city of Bismarck, North Dakota downstream through the treaty lands and drinking supply of the Standing Rock Sioux Tribe. When the tribe protested, guards sicced dogs on activists. When people saw the images and descended on the reservation from far and wide to stand with Standing Rock, North Dakota Governor Jack Dalrymple called in the National Guard. Protesters, who took to calling themselves Water Protectors, squared off with law enforcement agents better armed than many militaries: riding in armored vehicles and brandishing all manner of lethal and non-lethal weapons – including, even, a surface-to-air missile launcher. At the protest encampments, TigerSwan, a private security firm employed by Energy Transfer Partners, deployed counterinsurgency tactics brought back from the battlefields of Iraq and Afghanistan. After months, President Barack Obama intervened, ordering an environmental review. But less than a week after his inauguration, President Trump reversed the decision with one of his first actions in office. Oil began flowing through the pipeline later that year. Adam Killsalive was on the front lines of much of this fight. When his friends confirmed the news – that a judge had, in fact, ordered the Dakota Access Pipeline to empty – his heart lifted. “What we did wasn’t for nothing,” he said. “But what still bothers me is that the people who built and approved this pipeline are being shown that it’s a bad idea, but still think they’re doing right.”

Judge declines to reverse Dakota Access Pipeline shutdown — A federal judge on Tuesday declined to reverse his decision ordering the Dakota Access Pipeline to be shut down. Obama appointee James Boasberg declined a request from Dakota Access LLC to immediately stay his Monday decision, but added that the court will “set a status hearing” on the matter when it receives certain documents from the company. Boasberg on Monday said that the pipeline had to temporarily shut down by Aug. 5 while the Army Corps of Engineers works to prepare an environmental impact statement for a rule relaxation granted to the project. In a filing after the decision, Dakota Access argued that his order should be halted because “the Court’s decision requires Dakota Access to begin shutting down a major interstate pipeline.” “As a result, Dakota Access would need to undertake a number of expensive steps before it is likely to have a ruling on the forthcoming stay motion,” the company said. However, tribes challenging the pipeline disagreed, saying in their own filing that the company did not do enough to show that the stay was unnecessary or try to work with the challengers to reach an agreement. The Standing Rock Sioux Tribe sued over the controversial pipeline, which crosses native lands and has drawn protesters from across the country, in 2016. Boasberg had previously ruled that the Army Corps of Engineers had violated environmental laws when it gave Dakota Access an easement to construct a segment of the pipeline. In ordering the shutdown, he wrote that the “seriousness of the Corps’ deficiencies outweighs the negative effects of halting the oil flow.”

North Dakota regulators say no to imposing oil production cuts – North Dakota regulators on Tuesday decided not to impose any mandatory production cuts on the oil industry, following the lead of Texas and Oklahoma, which both nixed similar proposals this year as oil prices plummeted amid the coronavirus pandemic.The unanimous decision by the North Dakota Industrial Commission to dismiss the matter comes after a lengthy hearing in May and extensive written comments, in which numerous oil producers and tribal mineral owners from the Fort Berthold Indian Reservation opposed the idea.”Let’s let the private sector hammer out some of these things and where government can assist and intervene we’ll do so, but it’s probably best if we don’t go down this road,” said Agriculture Commissioner Doug Goehring, who sits on the commission along with Gov. Doug Burgum and Attorney General Wayne Stenehjem.State regulators have instituted production cuts before, in the 1950s and 1960s during the early days of North Dakota’s oil industry. But the industry has grown much more complex since those days, State Mineral Resources Director Lynn Helms said. Nevertheless, regulators still have the authority to declare oil as a “waste” if prices get low, and in effect require that oil producers curtail their output.OPEC, for example, regularly imposes production cuts for member countries as a way to prop up oil prices when they fall.Many Bakken producers, as well as the North Dakota Petroleum Council, asked the state to let the market determine oil’s fate. The demand for oil dropped with the pandemic as people halted travel, causing oil prices to crash. Prices have increased slightly over the past few months to around $40 per barrel Tuesday, but that amount is still too low to prompt the restart of many idled oil wells and new drilling.Helms noted that even when the price of oil turned negative in futures markets one day in April, North Dakota did not receive any bills for oil produced from state-owned minerals, nor did the tax commissioner receive any filings related to the volatility, he said.

PIPELINES: Dakota Access NEPA ruling may end ‘build first’ strategy – This week’s court-ordered shutdown of the Dakota Access pipeline prompted the company behind the project yesterday to say it wouldn’t immediately comply with the court order. Experts watching the crossfire say the ruling serves as a stark warning for federal agencies.

Dakota pipeline still moving oil despite shutdown order – (AP) – The owner of the Dakota Access Pipeline continued to fill it with North Dakota crude oil on Wednesday and said it has no immediate plans to shut down the line, despite a federal judge’s order that it be stopped within 30 days for additional environmental review. Pipeline owner Energy Transfer asked the court Wednesday to halt the order, and is seeking an expedited appeal. “We are not shutting down the line immediately,” said Vicki Granado, who noted that the Texas-based company is still taking orders to move oil on the line in August. “We’re not saying we’re going to defy anything.” U.S. District Judge James Boasberg on Monday ordered the pipeline shuttered for an additional environmental assessment more than three years after it began pumping oil. “We don’t believe he has the authority to do this,” Granado said. Boasberg has given the company 30 days to empty the pipeline while the U.S. Army Corps of Engineers fulfills his demand to conduct a more extensive environmental review than the one that allowed the pipeline to start moving oil near the Standing Rock Indian Reservation. Boasberg cited the “potential harm” that the pipeline could cause before the Corps finishes its survey.

Company estimates shutting down Dakota Access Pipeline will take 3 months – The operator of the Dakota Access Pipeline estimates it will take three months to empty the pipe of oil and complete steps to preserve it for future use. The timeline of 86 to 101 days comes as part of the argument Energy Transfer made this week to a federal judge in an effort to halt an order to shut down the line by Aug. 5 — in about 30 days — for the duration of a lengthy environmental review. The company says the line must be filled with an inert gas, such as nitrogen, to keep the pipe from corroding if oil no longer flows through it. Energy Transfer outlined the process in a motion filed Wednesday evening in which it asked the judge to put the order on hold while it appeals the decision to a higher court. U.S. District Judge James Boasberg denied the company’s request Thursday, effectively putting it in the hands of a panel of judges on the U.S. Court of Appeals for the District of Columbia Circuit. Energy Transfer indicated to the judge that it wishes to make its case to the appellate court as soon as possible, according to court documents. A company executive wrote in a court filing made public Thursday that while the pipeline operator could turn off the equipment that causes oil to flow through the line by the judge’s deadline, “it is not physically possible to ’empty it of oil’ in the thirty days provided by the order.” The line must undergo a “purge-and-fill process” that involves draining segments of the line one at a time while the pipeline is operating to replace the oil with nitrogen, Vice President of Crude and Liquid Operations Todd Stamm wrote. An attorney for the Standing Rock Sioux Tribe and other Sioux tribes that have fought the pipeline in court for four years said in an interview Thursday that the tribes are not “overly worried” about the duration of the shutdown process. “If it takes longer than 30 days to drain the pipeline of oil, I don’t think that’s a major issue,” said Jan Hasselman, an attorney with Earthjustice who represents the tribes. Energy Transfer says the shutdown process involves “a number of expensive” steps. The company estimates it will cost $24 million to empty the line of oil and take steps to preserve the pipe. The company adds that to maintain the line, it will incur another $67.5-million expense each year the pipeline remains inoperable. Energy Transfer also discloses the revenue hit it anticipates during a shutdown, estimating it will lose out on at least $2.8 million every day the line sits idle. Hasselman acknowledged that there are costs associated with shutting down the line but said the company “has a history of wild exaggeration.”

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