Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 10 October 2020. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening.
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Oil and natural gas prices jump as Hurricane Delta shuts down Gulf production
Oil prices rose for the 2nd week in 6 this week, as a strike in Norway threatened that country’s oil output and as a major hurricane shut down US Gulf production…after falling 8% to $37.05 a barrel last week on an increase of coronavirus cases globally and Trump’s positive test, the contract price of US light sweet crude for November delivery opened 5 cents lower on Monday but quickly rallied more than 6%, driven by the announcement that Trump would be discharged from the hospital later that day, and settled with a gain of $2.17, or 5.9%, at $39.22 per barrel, supported by hopes for a new stimulus package and by an escalating oil workers’ strike in Norway over pay…oil prices continued higher on Tuesday amid the supply disruptions in Norway, a new hurricane in the Gulf and Trump’s return to the White House and finished $1.45 higher at $40.67 a barrel, but slipped in post-settlement trading after Trump said he was instructing his team not to negotiate a new stimulus package until after the election…oil prices then opened 2% lower on Wednesday and traded in a narrow range before closing down 72 cents at $39.95 a barrel, after the EIA reported a slightly larger-than-expected build in U.S. commercial crude inventories…but the November oil contract price opened higher and rallied again on Thursday as the impact of higher US crude inventories was negated by draws in product inventories and escalating supply disruptions in Norway and the Gulf of Mexico, and prices went on to settle $1.24 or 3.1% higher at $41.19 a barrel, the higherst close in nearly 5 weeks, as hurricane Delta forced the shut-in of more than 90% of Gulf crude oil output…after opening higher, oil slipped more than 1% on Friday, after Norwegian oil firms struck a wage bargain with labour unions on Friday, ending the 10-day strike that had threatened to cut the country’s oil and gas output by close to 25%, with US crude falling 59 cents to $40.60 a barrel….even so, the U.S. benchmark crude price advanced more than 9% this week on the supply disruptions from Hurricane Delta, and on optimism for a U.S. stimulus deal…
Natural gas prices also rose this week, as exports rose and Hurricane Delta shut in Gulf production…after falling 13.1% to $2.438 per mmBTU last week on an increase in gas output and a forecast for reduced demand, the contract price of natural gas for November delivery opened higher on Monday and jumped 17.7 cents, or over 7%, as LNG exports rose and traders worried production would be shut in again with another hurricane expected in the Gulf of Mexico…natural gas prices then gave up half of those gains on Tuesday, falling 9.5 cents to $2.520 per mmBTU as forecasts indicated milder weather and lower demand over the next two weeks than had been previously expected…but most of that loss was regained on Wednesday when gas rose 8.6 cents to $2.606 per mmBTU as producers shut Gulf of Mexico wells ahead of Hurricane Delta and as forecasts were revised to show larger-than-expected demand over the next two weeks…natural gas prices then inched up 2.1 cents on Thursday as the natural gas storage report was in line with the increase that analysts had forecast, and then jumped 11.4 cents or 4.3% cents to $2.741 per mmBTU on Friday as Gulf Coast producers shut wells ahead of Hurricane Delta and on forecasts for colder weather and higher demand in mid October than was previously indicated…that left prices 12.4% higher on the week and at their highest since last November, although we should note that wintertime natural gas contracts almost always trade at higher prices than those during the rest of the year..
The natural gas storage report from the EIA for the week ending October 2nd indicated that the quantity of natural gas held in underground storage in the US increased by 75 billion cubic feet to 3,831 billion cubic feet by the end of the week, which left our gas supplies 444 billion cubic feet, or 13.1% greater than the 3,285 billion cubic feet that were in storage on October 2nd of last year, and 394 billion cubic feet, or 11.5% above the five-year average of 3,437 billion cubic feet of natural gas that have been in storage as of the 2nd of October in recent years….the 75 billion cubic feet that were added to US natural gas storage this week was a bit more than the forecast for a 71 billion cubic foot increase from an S&P Global Platts’ survey of analysts, but it was below the average of 86 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years, and it was much lower than the 102 billion cubic feet that was added to natural gas storage during the corresponding week of 2019…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending October 2nd showed that due to an increase in our oil imports and an increase in our oil production, we managed to add a bit of oil to our stored commercial supplies for the 2nd time in the past eleven weeks and for the twenty-fourth time in thirty-eight weeks…our imports of crude oil rose by an average of 610,000 barrels per day to an average of 5,732,000 barrels per day, after falling by an average of 45,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 853,000 barrels per day to an average of 2,659,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,073,000 barrels of per day during the week ending October 2nd, 1,463,000 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 reportedly 300,000 barrels per day higher 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 14,073,000 barrels per day during this reporting week…
US oil refineries reported they were processing 13,853,000 barrels of crude per day during the week ending October 2nd, 184,000 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 total of 92,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 312,000 barrels per day more than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-312,000) 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 that there must be an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…moreover, since last week’s fudge factor was +819,000 barrels per day, indicating a week over week difference of 1,131,000 barrels per day in the line 13 balance sheet adjustment, the difference between those errors means any week over week comparisons of oil supply and demand figures reported here are nonsense…however, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 5,258,000 barrels per day last week, which was still 18.9% less than the 6,486,000 barrel per day average that we were importing over the same four-week period last year….the 92,000 barrel per day net withdrawal from our total crude inventories was as 72,000 barrels per day were being added to our commercially available stocks of crude oil and 164,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial supplies….this week’s crude oil production was reported to be 300,000 barrels per day higher at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states rose by 200,000 barrels per day to 10,500,000 barrels per day, and because a 16,000 barrels per day increase to 459,000 barrels per day in Alaska’s oil production added another 100,000 barrels per day to the rounded national total (EIA math)….last year’s US crude oil production for the week ending October 4th was rounded to 12,600,000 barrels per day, so this reporting week’s rounded oil production figure was 12.7% 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 77.1% of their capacity while using 13,853,000 barrels of crude per day during the week ending October 2nd, up from 75.8% of capacity during the prior week, but excluding the 2005 and 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years…hence, the 13,853,000 barrels per day of oil that were refined this week were 11.5% fewer barrels than the 15,656,000 barrels of crude that were being processed daily during the week ending October 4th of last year, when US refineries were operating at 85.7% of capacity….
wWh the increase in the amount of oil being refined, gasoline output from our refineries was much higher, increasing by 630,000 barrels per day to 9,522,000 barrels per day during the week ending October 2nd, after our refineries’ gasoline output had decreased by 423,000 barrels per day over the prior week (when refinery throughput had increased by 300,000 barrels per day)…but since our gasoline production is still recovering from a multi-year low in the wake of this Spring’s covid lockdown, this week’s gasoline output was still 5.1% less than the 10,081,000 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 174,000 barrels per day to 4,532,000 barrels per day, after our distillates output had decreased by 112,000 barrels per day to a three year low of 4,358,000 barrels per day over the prior week…even after this week’s increase in distillates output, our distillates’ production was 6.3% less than the 4,835,000 barrels of distillates per day that were being produced during the week ending October 4th, 2019….
Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 11th time in 14 weeks and for the 26th time in 36 weeks, falling by 1,435,000 barrels to 226,747,000 barrels during the week ending October 2nd, after our gasoline supplies had increased by 683,000 barrels over the prior week…our gasoline supplies decreased this week because the amount of gasoline supplied to US markets increased by 367,000 barrels per day to 8,896,000 barrels per day, and because our exports of gasoline rose by 235,000 barrels per day to 903,000 barrels per day, while our imports of gasoline rose by 117,000 barrels per day to 849,000 barrels per day…after the gasoline inventory drawdowns of recent weeks, our gasoline supplies were 0.9% lower than last October 4th’s gasoline inventories of 228,763,000 barrels, but still close to the five year average of our gasoline supplies for this time of the year…
With our distillates production still near a three year low, our supplies of distillate fuels decreased for the 9th time in 27 weeks and for the 30th time in 52 weeks, falling by 962,000 barrels to 171,796,000 barrels during the week ending October 2nd, after our distillates supplies had decreased by 3,184,000 barrels during the prior week….our distillates supplies fell by less this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 213,000 barrels per day to 3,868,000 barrels per day, because our exports of distillates fell by 268,000 barrels per day to 1,031,000 barrels per day, while our imports of distillates rose by 89,000 barrels per day to 230,000 barrels per day….but even after this week’s inventory decrease, our distillate supplies at the end of the week were still 34.9% above the 127,324,000 barrels of distillates that we had in storage on October 4th, 2019, and about 23% above the five year average of distillates stocks for this time of the year…
Finally, with the increase in our oil imports and the increase in our oil production, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) rose for the 7th time in the past seventeen weeks and for the 35th time in the past year, increasing by 501,000 barrels, from 492,426,000 barrels on September 25th to 492,927,000 barrels on October 2nd…after that increase, our commercial crude oil inventories were around 12% above the five-year average of crude oil supplies for this time of year, and about 49% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the fourth weekend of September, 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 over the past two years, except for during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of October 2nd were 15.8% above the 425,569,000 barrels of oil we had in commercial storage on October 4th of 2019, 20.2% more than the 409,951,000 barrels of oil that we had in storage on October 5th of 2018, and 6.6% above the 462,216,000 barrels of oil we had in commercial storage on September 29th of 2017…
This Week’s Rig Count
The US rig count rose for the 4th week in a row during the week ending October 9th, but for just the 6th time in the past 31 weeks, and hence it is still down by 66.1% over that thirty week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 3 to 269 rigs this past week, which was still down by 587 rigs from the 856 rigs that were in use as of the October 11th report of 2019, and was also 135 fewer rigs than the all time low prior to this year, and 1,660 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….
The number of rigs drilling for oil increased by 4 rigs to 189 oil rigs this week, after increasing by 6 oil rigs the prior week, still leaving us with 519 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 decreased by one to 73 natural gas rigs, which was also down by 70 natural gas rigs from the 143 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico…a year ago, there only one such “miscellaneous” rig deployed…
The Gulf of Mexico rig count remained unchanged at 14 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and two drilling for oil offshore from Texas…that was 9 fewer Gulf rigs than the 23 rigs drilling in the Gulf a year ago, when all 23 Gulf rigs were drilling offshore from Louisiana…while there are no rigs operating off of other US shores at this time, a year ago there was also a rig deployed offshore from Alaska, so this week’s national offshore count is down by 10 from the national offshore rig count of 24 a year ago…also note that in addition to those rigs offshore, a rig continues to drill through an inland body of water in St Mary County, Louisiana this week, while a year ago there were no rigs drilling on inland waters..
The count of active horizontal drilling rigs was up by 4 to 233 horizontal rigs this week, which was still 517 fewer horizontal rigs than the 750 horizontal rigs that were in use in the US on October 4th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was unchanged at 21 directional rigs this week, and those were down by 34 from the 55 directional rigs that were operating during the same week of last year….on the other hand, the vertical rig count was down by one to 15 vertical rigs this week, and those were down by 36 from the 51 vertical rigs that were in use on October 4th of 2019….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of October 9th, the second column shows the change in the number of working rigs between last week’s count (October 2nd) and this week’s (October 9th) count, the third column shows last week’s October 2nd active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 11th of October, 2019…
Once again, there were very few changes this week, with only five rig additions and two removals nationally….by checking the rig counts in the Texas part of Permian basin, we find that one rig was added in Texas Oil District 7C, which roughly aligns with the southern part of the Permian Midland, while 1 rig was pulled out of Texas Oil District 8A, which corresponds to the northern Permian Midland, thus leaving the rig count in the Texas Permian unchanged….since the national Permian basin rig count was up by one, that means that the rig that was added in New Mexico must have been set up to drill in the far western Permian Delaware, in order to balance the overall rig count on that basin…elsewhere in Texas, one rig was added in Texas Oil District 2, which accounts for the rig added in the Eagle Ford, and two more rigs were added in Texas Oil District 3, one in Washington county, and another in Brazoria county, both of which were horizontal rigs targeting an “other” formation, ie, not the Eagle Ford…other than those, the only other rig change nationally was the natural gas rig that was removed from Pennsylvania’s Marcellus….
Columbia Gas fined $156,000 for Leach Xpress violations – TC Energy’s Columbia Gas Transmission LLC has agreed to pay $156,000 to the Pennsylvania Department of Environmental Protection for pipeline sedimentation and erosion violations in southwest Pennsylvania, Kallanish Energy reports.The violations occurred from June 6, 2017, to Nov. 8, 2019, during construction of the Leach Xpress natural gas pipeline in Greene County.The company and the DEP have agreed to a consent order and agreement.DEP reported numerous violations on a 28.3-acre site in Richhill Township.Erosion and sedimentation discharges from the pipeline construction entered two streams and a damaged a wetland, DEP said.The company was cited for failing to implement best management practices to minimize erosion, failing to implement the erosion plan in its permits, failing to stabilize area where the soil had been disturbed, failing to comply with permit conditio0ns and failing to perform work according to specifications in its permits, it said.Not all the problems have been corrected by the company, the state agency said.It issued two compliance orders to Columbia Gas Transmission.It must also reimburse the Greene County Conservation District $1,126 for costs incurred.
Center Twp. reflects on explosion as Revolution Pipeline construction resumes – Karen Gdula, a retired MSA project manager, grew up on Ivy Lane. When Energy Transfer’s Revolution Pipeline exploded in the early hours of Sept. 10, 2018, the fire’s roar was so loud emergency dispatchers could hardly hear calls for help. “My immediate words to my husband were ‘get dressed, get your meds, we’re going to evacuate,'” Gdula said. “The house shook, and the flames were as high as the pine trees.” Barbara Goblick, who lives near Gdula on Ivy Lane, was making coffee just before 5 a.m. that day. She quickly dialed 911 as her house violently rattled. Emergency responders received as many as 800 calls that morning; residents reported possible plane crashes, tanker truck explosions and meteors as they grappled with what could have caused a fireball so large. “The dispatcher said, ‘What was that noise?’ and I told him it was the fire,” Goblick said. “And I think that’s when it got real for him. Not that he didn’t believe us, but it was the sound of it. Some neighbors said they could feel the heat. I don’t remember feeling any heat, but every time I think about it, I hear the sound.” Police and firefighters from multiple departments spent 14 to 18 hours assisting Ivy Lane homeowners, rerouting traffic and clearing debris. Goblick’s mother was so startled by the explosion that her legs knocked together and bruised her knees. Another Ivy Lane neighbor was in hospice and on oxygen, causing confusion for first responders. “She could have died that day,” Gdula said. Now, as Energy Transfer resumes Revolution Pipeline construction near the explosion site two years later, Ivy Lane residents are prepared for the worst, but hoping for the best. Just one week after the Revolution Pipeline became active in Beaver County, it burst into flames in a valley near Ivy Lane following heavy rainfall and a subsequent landslide. The blast torched multiple acres of forested areas, destroyed a single-family home, forced the evacuation of nearby residents and caused six high-voltage electric transmission towers to collapse. An investigation found a subsidiary of Dallas-based Energy Transfer had not stabilized a number of areas along the pipeline to prevent landslides. Pennsylvania’s Department of Environmental Protectionlater fined Energy Transfer $30.6 million in civil penalties related to the incident, essentially authorizing the company to resume construction. The 40-mile gathering line travels across Butler, Beaver and Washington counties to feed natural gas liquids from western Pennsylvania into the company’s larger statewide lines.
GRID: Natural gas projects at risk in 4 states, report warns — Wednesday, October 7, 2020 — An oversupply of natural gas in the nation’s largest regional grid operator’s portfolio could pose substantial risks for its customers and investors, according to a new report.
Coal, nuclear retirements in US Midwest might boost gas-fired power demand | S&P Global Platts – As natural gas storage surpasses five-year maximum levels in the US Midwest, a swath of coal and nuclear power plant retirements look to boost gas’ share of generation winter over winter, helping balance a towering inventory despite higher hub prices in the region. About 70 MWh of coal-fired capacity has retired since last winter with another 173 MWh offline by the end of this upcoming winter in the Midcontinent Independent System Operator and Southwest Power Pool, according to S&P Global Platts Analytics. This pales in comparison though to the 619 MWh of nuclear generated capacity lost this year. Overall, these losses should provide more opportunity for gas-fired generation in the region. Last winter power burn exceeded expectations thanks to low cash prices. Chicago averaged just $1.90/MMBtu last winter, down from an average of $3.00/MMBtu the past five years. This incentivized greater coal-to-gas switching and boosted power burn in the Midwest to 3.8 Bcf/d. This winter, Platts Analytics expects stronger prices to weaken power burn by a sizable 595 MMcf/d from last winter in the region. However, these winter-over-winter losses could be mitigated in part by the retirement at the Duane Arnold Energy Center in Iowa. Duane Arnold was Iowa’s only nuclear power plant and ran from 1975 to August 2020. The plant was scheduled to retire at the end of October, but the plant could not restart after heavy El Derecho rains in early August, pushing the retirement earlier than expected. The nuclear plant had a nameplate capacity of 619 MWh. US Energy Information Administration data, however, showed the plant averaged 445 MWh in the winter of 2019 and 2020 and hit as high as 456 MWh in January 2020. This lost generation could help boost power burn by 85 MMcf/d if gas fills in for all of the lost nuke output. The region has also seen smaller coal retirements with 129 MWh lost with the JB Sims and TES Filer City Stations in Michigan during the first half of the year. The loss of another 173 MWh is expected with the closure of the Dallman coal-fired power plant in Illinois later this year. Last winter both ran below their nameplate capacity, with JB Sims averaging 22 MWh out of its 68MWh capacity, TES Filer City at 34 MWh of 61 MWH, and Dallman at 81 MWh of 173 MWh. While these plants present a combined 302 MWh of nameplate capacity, only 138 MW was utilized last winter. The lost coal-fired capacity could boost power burn by 26 MMcf/d. Platts Analytics forecasts power burn to decline this year from last assuming normal temperatures and stronger prices. The EIA, however, estimates 22% of the Midwest primarily heat their home with electricity while 20% also use it as a secondary heating source. The loss of generation from coal and nuclear retirements this winter will therefore provide a substantial upward risk to Platts Analytics winter power burn forecast. The region also has a surplus of gas in storage to draw upon, with levels towering above the five-year maximum since August. Cooler winter-over-winter temperatures would only further boost power demand, exacerbating the effects of these retirements. The National Weather Service forecasts Midwest temperatures to be slightly cooler than normal for winter 2020-21.
Trump pounds fracking as a wedge issue in Pa. But if it’s not a top concern for voters, how much can it help? – Pennsylvania has emerged as one of the key swing states in the presidential election. And while natural gas drilling is near the bottom of a list of concerns for the state’s voters, fracking just keeps coming up.It got a surprising amount of air time during Wednesday’s vice presidential debate between Democratic Sen. Kamala Harris and Republican Vice President Mike Pence.”They want to abolish fossil fuels and ban fracking,” Pence said. “Joe Biden will not ban fracking, he’s been very clear about that,” countered Harris. In fact, Joe Biden can’t actually ban fracking, at least not in Pennsylvania. The technology that helped tap Pennsylvania’s deeply buried shale gas transformed some of the state’s quiet farm and forest communities over the past 12 years. It’s created good-paying jobs, and an influx of cash for people who lease their land to gas drillers. And that’s something President Trump likes to bring up, as at a recent rally at Harrisburg International Airport in Middletown. “You’re a big fracker,” Trump told the crowd. “It’s a big business here, 900,000 jobs.” Quick fact check here: That number is wrong. The state puts the figure at about 26,000 jobs in the oil and gas sector. That’s less than 1 percent of all jobs in the state. It doesn’t even make the state’s top 50 list of employment sectors. And even the industry claims a job figure of about 300,000, which is one-third of Trump’s number. On his trips to Pennsylvania, he’s repeatedly accused his Democratic opponent Joe Biden of wanting to ban fracking. “He wants to eradicate all the things that you’re doing, all the things that are bringing in so much money for your state, it’s a disgrace,” Trump told the crowd in Middletown. “Now he’s trying to say, well, I didn’t really mean that.” The Democratic party’s progressive wing has pushed for a ban on fracking because of the environmental damage drilling caused in some areas, including Pennsylvania. But a president cannot ban fracking on private land – only Congress can do that. And the vast majority of fracking in Pennsylvania takes place on private and state land. The state leases about 11 percent of its land – 251,233 acres – to gas drillers.What Biden says he wants to do – as part of his larger plan to tackle climate change – is stop leasing any new oil and gas rights on federal land. But Pennsylvania has very little federal land. The only place where federal leases exist are in the Allegheny National Forest, where there are three oil and gas leases that span about 855 acres.
Whistleblower claims Mariner East construction lacks proper safety measures related to sinkholes, subsidence | StateImpact Pennsylvania -A professional geologist who worked on the Mariner East pipeline project says pipeline builder Sunoco/Energy Transfer prevented him and other geologists from inspecting and reporting on dangerous subsidence, or sinkholes, during construction.The whistleblower says professional geologists were prevented from speaking to drillers, unable to gain access to drill sites, told to change the name from subsidence to “earth feature” in reports, and had their mandated reports to agencies like the Department of Environmental Protection edited and changed by non-geologists.He says the company had what they called a “limited disturbance policy” whereby geologists should only report subsidence issues within a specific area. Failing to follow the policy would risk termination.The claims are detailed in a notice of intent to sue Sunoco by the Clean Air Council. The legal notice was sent to the company on Tuesday. The whistleblower is not identified in the document. Tim Fitchett, staff attorney for Fairshake Environmental Legal Services, is representing Clean Air Council in the case. Fitchett said Sunoco fired the geologist after he reported a sinkhole in Chester County that lay outside the area defined by the company’s “limited disturbance policy.”Clean Air Council sued Sunoco in 2017, which resulted in a settlement agreement with the company and DEP.”Sunoco is so scared of what its scientists will find in investigating its pipeline construction that it’s muzzled them and doctored their reports,” said Joseph Minott, executive director and chief counsel of Clean Air Council.Sunoco’s erosion and sediment control permits issued by the Department of Environmental Protection require the company to report subsidence and stop work until a plan is created and approved by DEP. But Fitchett said the geologist witnessed examples where work stopped for about a week, the subsidence was “cursorily” monitored, and reports issued to DEP claimed no issues. At that point, work would restart at the site. Fitchett said the geologist saw issues similar to the kinds of subsidence that occurred in Beaver County at another Energy Transfer pipeline construction site, which led to an explosion in September 2018. No one was injured in the Revolution Pipeline incident, but it burned a house to the ground. Fitchett said the geologist decided to inform the Clean Air Council of his experiences due to safety concerns.
It Takes Two, Part 2 – U.S. Ethane Export Terminals, Throughputs, and Cargo Destinations | RBN Energy – Taken together, the ethane-related infrastructure projects developed in the U.S. over the past several years serve as a reliable feedstock-delivery network for a number of steam crackers in Europe, Asia, and Latin America. NGL pipelines transport y-grade to fractionation hubs, fractionators split the mixed NGLs into ethane and other “purity” products, ethane pipelines move the feedstock to export terminals fitted with the special storage and loading facilities that ethane requires, and a class of cryogenic ships – Very Large Ethane Carriers, or VLECs – sails ethane to mostly long-term customers in distant lands. The end results of all this development are virtual ethane pipelines between, say, the Marcellus/Utica and Scotland, or the Permian and India. Today, we continue our series on ethane exports with a look at the two existing export terminals, the ethane volumes they have been handling, and where all that ethane has been headed. As we said in Part 1, U.S. fractionators are now churning out record volumes of ethane, with the Energy Information Administration (EIA) last week reporting the highest production volume ever: 2.2 MMb/d for July 2020. We estimate that around a million additional barrels per day on average this year has been “rejected” into the natural gas stream at processing plants and sold (at the price of gas) for its Btu value (see Turnin’ Natgas into Gold). Most important to the export focus of this series, about 280 Mb/d, or 14% of total U.S. ethane production, has been sent to other countries so far in 2020. More than one-third of that 280 Mb/d is being piped to Canadian steam-cracker customers on either the Vantage, Mariner West, or Utopia pipelines. The rest is being loaded on VLECs or smaller ethane tankers and sent to crackers in a number of other countries, with the vast majority going to these seven: India, the UK, Norway, China, Mexico, Sweden, and Brazil. These export numbers represent a big change from just a few years ago. Ethane exports from the U.S. only started in 2014, when the Vantage and Mariner West pipelines to Canada came online. And it wasn’t until March 2016 when the first ethane was loaded onto ships for export, first from the Marcus Hook marine terminal near Philadelphia, and then from Morgan’s Point Ethane Export Terminal in the Houston area, which didn’t occur until September 2016 – barely four years ago. Before those terminals opened for business, nary a drop of ethane had ever moved via ship to ethylene crackers. Today, we discuss the Marcus Hook and Morgan’s Point export facilities, which so far account for all U.S. ethane exports by ship.
Shell says Pennsylvania ethane cracker about 70% complete (Reuters) – Royal Dutch Shell Plc said on Friday its multibillion-dollar petrochemical complex near Pittsburgh was about 70% complete and remains on track to enter service in the early 2020s.After temporarily suspending construction activities on the ethane cracker in March to limit the spread of coronavirus, Shell said it has been re-introducing workers at a measured pace – bringing the total number of workers on site to about 6,500.”As we safety ramp up to a pre-pandemic level of activity, the project remains on schedule to be completed sometime in the early 2020s,” Shell spokesman Curtis Smith said.
Big Oil quietly built a plastics and chemicals empire worth billions. Now Exxon, Shell, and other giants are betting it will help save them in a future without gas-powered cars. – Most people are familiar with oil giants like Shell and Chevron, largely because they sell gasoline and diesel at stations across the country – fuel, after all, is the biggest market for oil companies. But there’s a large and growing part of Big Oil that’s less visible to the public: petrochemicals.Petrochemicals, or chemicals derived from petroleum, are absolutely everywhere.They’re used to make plastics, yes. But they’re also in laundry detergents and windshield wiper fluids. They’re in the blades of wind turbines. And they’re key ingredients in hand sanitizers and other products that have surged in demand during the pandemic. For years, petrochemicals have fueled Big Oil, and vice versa.From 2015 to 2018, for example, chemicals represented about a quarter of Exxon’s earnings, according to analysts at Morgan Stanley. That proportion has since fallen substantially, due to an industry-wide drop in margins, but the bank says profits are poised to recover as chemicals rebound from a pandemic-driven slump.”Exxon’s business is easily big enough to be a standalone company,” Sam Margolin, an analyst at Wolfe Research, said. “That should give you a sense of scale.”Now, petrochemicals look like an even better bet, as Big Oil faces an unprecedented challenge: Over the long term, demand for gas-powered cars, and the fuel that runs them, is set to weaken as more people opt for electric vehicles.In fact, by 2050, petrochemicals are projected to overtake the transportation sector as the largest driver of growth in oil demand, according to the International Energy Agency. So it’s no surprise that companies like Exxon, Shell, and Total have all been bulking up their chemical arms. That could be good for their bottom line, and even push them closer to their climate-change targets. But petrochemicals create another big problem – plastic waste. Chemicals were a smart bet well before the oil price downturn or electric car revolution, especially for companies experienced in turning oil and gas into other products.The market for chemicals is huge, worth more than a half a trillion dollars in the US alone, according to the American Chemistry Council. It’s also growing faster than global GDP, said Alan Gelder, an analyst at the research firm Wood Mackenzie.”What they’ve been doing over the last 40 years is effectively displacing other materials,” Gelder said of chemicals, which is why petrochemicals are growing at what he calls “GDP-plus.” A future with fewer gas-powered cars only makes chemicals more appealing to oil companies looking to keep growing. Thus, many of the integrated oil majors including Exxon, Shell, and French energy giant Total are doubling down on their chemical bets, even as they cut elsewhere to stay afloat in the wake of a pandemic-fueled collapse in oil prices. BP is the notable exception, having sold off its chemicals business earlier this year.”They all view petchems as among the fastest-growing product group within the hydrocarbon value chain,” Jason Gabelman, an energy analyst at Cowen, said. Exxon, which dominates the chemical space among majors, broke ground on four large projects in 2019. “We feel very well positioned in that business,” Neil Chapman, SVP of Exxon, told investors this summer.
State approves $56 million settlement with Columbia Gas for Merrimack Valley gas explosions – The Boston Globe – A settlement agreed upon in July that requires Columbia Gas of Massachusetts to pay $56 million for its role in the 2018 Merrimack Valley gas explosions was approved by the state Department of Public Utilities on Wednesday, officials said.The settlement also requires Columbia Gas to leave Massachusetts and transfer its assets to Eversource Energy, the department said in a statement.The agreement resolves the department’s investigation into the company’s pipeline safety compliance and emergency response related to the September 2018 explosions.
Weymouth officials, residents want to see gas company’s emergency plan – – Officials are pushing to get more information on the emergency response plan for the newly-completed natural gas compressor station on the banks of the Fore River following two incidents at the facility in less than three weeks that caused emergency releases of gas. Alice Arena, president of the Fore River Residents Against the Compressor Station, went before town council at its virtual meeting this week regarding safety, risk and evacuation planning at the compressor station, which is close by the MWRA sewage pumping station, Fore River Bridge, numerous industrial facilities and hundreds of homes. Arena said Enbridge, the energy company that owns the compressor station, is required to have an emergency plan, yet has released no information on how it will build and maintain communications with local first responders, make personnel, equipment, tools and materials available during an emergency, evacuate residents and other factors. “It is simply unacceptable that this compressor station has received its final operating permit from the Federal Energy Regulatory Commission, but we still have no safety and evacuation plan available to the vulnerable residents and no risk assessment was ever done by federal or state agencies,” Arena said.
‘Less-than-ideal bedfellows’: Mountain Valley Pipeline payout prompts criticism – Maury Johnson has been tangling with a long, skinny, unwelcome intruder – the Mountain Valley Pipeline – on his West Virginia homestead for close to six years. He and his rural neighbors figured the Appalachian Trail Conservancy would continue to back them as they strategized to prevent the long-delayed, contentious natural gas pipeline from being buried along 303 miles of sensitive West Virginia and Virginia habitat. So, Johnson was crestfallen when he learned in mid-August that the nonprofit Conservancy had signed a $19.5 million “voluntary stewardship agreement” with the handful of companies building the pipeline. A Conservancy staffer delivered the news via telephone minutes before a press release landed in his inbox. “It shocked me so much that I almost fell to the floor,” said the 60-year-old retired farmer and former teacher from Monroe County. “At first, I wanted to drop my membership in the Conservancy. But then I thought, wait a minute, membership gives me power because they have to be responsive to members.” The Conservancy, founded in 1925, is the guardian of the storied footpath that stretches 2,193 miles from Georgia to Maine. Its charge, the Appalachian National Scenic Trail, is a unit of the National Park Service. Johnson convinced his anti-pipeline colleagues to hold off on a protest at the Conservancy headquarters in Harpers Ferry, West Virginia, until he composed a letter to Sandi Marra, the president and CEO of the nonprofit, and checked in with other allies. “I didn’t want to be confrontational with Sandi,” he said, adding that other Conservancy staffers had reassured him that anti-pipeline efforts would not be ignored just because of the pact. Johnson is upset enough that the Mountain Valley Pipeline is slated to be buried under a lengthy section of his 150-acre farm. But he’s also heartsick because his once-pristine view of Peters Mountain is now of chain-sawed trees. That’s about 11 miles from his home and where the pipeline will likely cross under the Appalachian Trail in the Jefferson National Forest on the Monroe County, West Virginia-Giles County, Virginia border.
Stream-Crossing Permits Bring New Court Challenges as MVP Awaits Construction Restart – In keeping with an extensive history of persistent legal opposition to Mountain Valley Pipeline LLC (MVP), environmental groups have asked a federal appeals court to stay recently updated waterbody-crossing permits for the 303-mile, 2 million Dth/d natural gas conduit. In petitions filed Monday with the U.S. Court of Appeals for the Fourth Circuit, a coalition of plaintiffs including the Sierra Club has asked the court to put a hold on MVP’s Nationwide Permit 12 (NWP 12) approvals, issued by the Huntington, WV, and Norfolk, VA, districts of the U.S. Army Corps of Engineers. The groups have asked the Fourth Circuit to issue a stay while the court reviews the approvals, arguing that the Army Corps has failed to meet standards laid out in the federal Endangered Species Act and that the NWP 12 issued by the Huntington District “relies on unlawful modifications.” The groups claimed that “MVP’s haste” to restore its federal permits and complete construction on the project “necessitates this stay motion.”The NWP 12 approvals are among a number of federal permits that have come under scrutiny since MVP secured its FERC certificate in 2017, with opposition groups scoring key legal victories that have stalled construction progress on the pipeline. After securing a number of updated and reissued permits in recent weeks, including a new Endangered Species Act review conducted by the U.S. Fish and Wildlife Service, MVP has been seeking the Federal Energy Regulatory Commission’s blessing to resume construction activities. The operator has pointed to adverse impacts on landowners and the environment from temporary stabilization on unfinished stretches of the pipeline, which is designed to transport Marcellus and Utica shale gas from West Virginia to an interconnect with the Transcontinental Gas Pipe Line in Virginia. MVP has sought to further bolster its case to resume construction by pointing to a draft supplemental environmental impact statement the U.S. Forest Service recently completed for the project. MVP has also received a right-of-way permit from the National Park Service to cross the Blue Ridge Parkway, the operator said in a FERC filing late last week. Genscape Inc. analyst Colette Breshears said in a note to clients Tuesday that the firm anticipates MVP entering full service in March 2021.However, “delays to some of these permits will be consequential, especially the NWP 12 permits,” Breshears said. “Despite their issuance and MVP’s renewed request to construct, these permits aren’t a foregone conclusion” amid the renewed legal opposition.A previously raised issue concerning river crossings in West Virginia “may haunt the project again,” the analyst said.
FERC study finds no risk from protective coating of Mountain Valley Pipeline – Segments of steel pipe stockpiled along the path of a natural gas pipeline, exposed to the elements for two years while lawsuits delayed construction, pose no risk to the surrounding air, soil or water, a federal agency has concluded.In a report released Thursday, the Federal Energy Regulatory Commission addressed concerns that have been raised about the Mountain Valley Pipeline.An epoxy coating applied to protect the pipe from corrosion may have released toxins in two ways, the theory goes: into the air after it degenerates from sitting too long in the sun, and into groundwater after the 42-inch diameter pipe is assembled and buried.But after more than a year of study, FERC found no basis for the fears about Mountain Valley or the Atlantic Coast Pipeline, a similar project that collapsed in July under the weight of multiple legal challenges.The report cites the conclusion of ToxStrategies, a consulting firm hired by Atlantic Coast, that there should be “no impact on human health or the environment from the chalky residue” that forms on the pipes after prolonged exposure to sunlight. After getting the report last year, FERC requested more information, including an assessment of pipeline storage yards. A revised study dated Aug. 27 reached the same conclusion as the first.
Video Conversation: Pipeline Opponents Discuss Lessons Learned – ‘You Can’t Give Up’ – Daily Yonder — At the height of the summer as the Covid-19 pandemic continued to spread throughout the U.S. – particularly in rural areas – and as protests demanding racial justice continue in cities and towns, several oil and gas infrastructure projects were either cancelled or hit major stumbling blocks. On July 5, Dominion Energy cancelled the Atlantic Coast Pipeline, a 600-mile natural gas project the utility proposed to build from West Virginia to North Carolina. A day later, a court ordered the Dakota Access Pipeline to halt operations. On the same day, the U.S. Supreme Court upheld a decision to suspend construction on parts of the Keystone XL pipeline. A permit for the Mountain Valley Pipeline Southgate extension was rejected by North Carolina regulators.The decisions will have a significant impact on movements around public health, anti-racism, and environmental conservation. Oil and natural gas pipelines are typically proposed in rural areas, in communities that are low-wealth and have a history of extraction or other industrial and polluting facilities. They are often routed through communities where Black, Latino, and Indigenous people live. These projects have been in the works for years, with varying degrees of success: The Dakota Access Pipeline already had oil flowing through it; less than 10% of the Atlantic Coast Pipeline was in the ground. The projects, touted as economic silver bullets for rural places by developers, have divided communities, churches, neighborhoods, and families. Those opposing them have spent years working to stop them, writing op-eds for newspapers, filing lawsuits, organizing protests and meetings and fundraisers. Some people camped out in trees for weeks on end. Others trained themselves on how to monitor construction to ensure any environmental damage was reported. Southerly and the Rural Assembly wanted to know about this work: the successes, concerns, and challenges, how these folks have organized against pipeline projects they say are dangerous and unnecessary. We wanted to learn about the mistakes they made, the lessons they’ve learned, and the small and large victories they have celebrated. In late summer, I spoke to Belinda Joyner, an activist in Northampton County, North Carolina, who fought the Atlantic Coast Pipeline; Becky Crabtree, a retired teacher and activist in West Virginia who protested the Mountain Valley Pipeline; and Greg Buppert, senior attorney for the Southern Environmental Law Center, which had multiple lawsuits against the Atlantic Coast Pipeline. We talked about their efforts to oppose fossil-fuel pipelines and what they would tell other folks in rural communities where industrial projects are proposed.
Additional clean up needed at oil spill on WK Parkway – The clean up from a crude oil spill occurring Friday, Sept. 25, on the Western Kentucky Parkway, will continue through Thursday, Oct. 8. The clean up began Monday, Oct. 5.The work zone is eastbound between Central City and the Muhlenberg/Ohio County line. Signage will be in place to alert motorists of the work on the parkway. Motorists can expect an eastbound, right lane restriction while this work is addressed at mile marker 63.8. The work is scheduled for completion Thursday afternoon.
12 million cubic feet of natural gas released after rupture near Florida’s Turnpike – Contact 5 is learning new details about a natural gas line that ruptured late last month next to Florida’s Turnpike near Lake Worth Road. More than a week and a half after the incident, there is still no word on the cause of the failure. According to a federal incident report, Florida Gas Transmission reported that the rupture of the 18-inch transmission pipeline released 12 million cubic feet of natural gas into the air. Security cameras at a nearby business caught the moment the line ruptured. The incident closed the turnpike for hours and led to a shelter in place and evacuations. A U.S. Department of Transportation incident report located by Contact 5 shows a minor natural gas leak not far from the site in 2012. According to the report, in that incident, only 6,000 standard cubic feet of gas released.
Natural gas production, consumption hit record highs in 2019 – US natural gas production, consumption and gross exports rose to record levels in 2019, according to the U.S. Energy Information Administration (EIA). Data recently released in EIA’s Natural Gas Annual shows dry natural gas production rose by 10% to a record-high average of 93.1 billion cubic feet per day in 2019. U.S. natural gas consumption increased by 3%, and the increase could be attributed to the greater use of natural gas in the electric power sector. Natural gas gross exports rose 29% to 12.8 billion cubic feet per day. The electric power sector consumed 7% more natural gas in 2019 than in 2018. Electric power sector consumption increased because of favorable natural gas prices and ongoing coal plant retirements. Natural gas consumption in all other sectors was flat. The volume of natural gas exports in pipelines and as liquefied natural gas (LNG) rose for the fifth consecutive year to an average of 12.8 billion cubic feet per day in 2019. U.S. LNG exports contributed to the majority of the increase. The United States exported more natural gas than it imported in 2019, and net natural gas exports were an average of 5.2 billion cubic feet per day. In 2019, the United States also exported more natural gas by pipeline than it imported for the first time since at least 1985, and this could be attributed to an increase in pipeline capacity to send natural gas to Canada and Mexico. In 2019, dry natural gas production rose by 10%, or by 8.7 billion cubic feet per day, to a record of 93.1 billion cubic feet per day. The increase was the second-largest volumetric increase since at least 1930 and second only to the increase in 2018. Texas and Pennsylvania produce the most natural gas in the United States, and they had the largest increases in natural gas production in 2019. In Texas, dry natural gas production rose 15%, from 19.3 billion cubic feet per day in 2018 to 22.2 billion cubic feet per day in 2019. In Pennsylvania, the production rose 10%, from 16.9 billion cubic feet per day in 2018 to 18.6 billion cubic feet per day in 2019. In Wyoming, natural gas production declined 11%, from 4.3 billion cubic feet per day in 2018 to 3.9 billion cubic feet per day in 2019. The decrease was the largest year-over-year decline of any state last year.
U.S. natgas rises to 5-week high on higher LNG exports, hurricane worries (Reuters) – U.S. natural gas futures jumped over 7% to a five-week high on Monday as liquefied natural gas (LNG) exports rise and worries production could be shut in again later this week with another hurricane expected in the Gulf of Mexico. Tropical Storm Delta is expected to strengthen into a hurricane before slamming into the Gulf Coast between Louisiana and Florida on Friday. Front-month gas futures rose 17.7 cents, or 7.3%, to settle at $2.615 per million British thermal units, its highest close since Aug. 31. Despite the rise in the futures, spot gas prices for Monday fell to their lowest in years in several regions of the United States and Canada as mild weather and coronavirus demand destruction cut usage of the fuel for heating and industrial purposes. Gas speculators, meanwhile, boosted their net long positions on the New York Mercantile and Intercontinental Exchanges last week for a second week in three on expectations energy demand will rise as the economy rebounds once state governments lift more coronavirus-linked lockdowns. Data provider Refinitiv said output in the Lower 48 U.S. states averaged 86.8 billion cubic feet per day (bcfd) so far in October, down from a four-month low of 87.2 bcfd in September. Those production declines come as low prices earlier in the year due to coronavirus demand destruction caused energy firms to shut wells and cut back on new drilling so much that output from new wells no longer offsets existing well declines. With milder weather coming, Refinitiv projected demand, including exports, would slip from 86.8 bcfd this week to 86.4 bcfd next week. That, however, was higher than Refinitiv’s forecasts on Friday. The amount of gas flowing to LNG export plants averaged 7.1 bcfd so far in October, up from 5.7 bcfd in September as vessels started returning to Cameron in Louisiana.
Winter Severity Doubts Add to Wild US Gas Price Swings — Rollercoaster moves in the U.S. natural gas market over the past few weeks are underscoring traders’ uncertainty about whether a frigid winter, muted output and rebounding demand will send prices rocketing higher in the coming months. Gas futures settled more than 7% higher on Monday, mimicking gains in oil and equities. But just two weeks ago, prices posted their biggest one-day loss in almost two years. Historical volatility has surged to levels not seen since late 2018, and implied volatility, a measure of how dramatic price swings may be going forward, is the highest in data going back to 2010. Bullish bets on U.S. gas have soared as traders wager on lackluster production and surging demand heading into winter. Liquefied natural gas exports are rising as consumption recovers from pandemic-driven lockdowns, and as terminals restart after storm-related outages and maintenance. Meanwhile, shale output remains subdued as drillers heed investor calls for financial restraint after this year’s oil-price crash. Outsize moves in risk assets amid geopolitical turmoil have magnified the volatility in gas, while a hyperactive hurricane season has disrupted offshore production and LNG exports and triggered blackouts that curtailed gas demand for power generation. “You’ve had a volatile market, but this is the icing on the cake,” said Bob Yawger, director of the futures division at Mizuho Securities USA Inc. “Guys were stepping in to pick at the bottom.” But as is often the case with the gas market, it all hinges on the weather. Though a La Nina pattern has emerged, which could lead to a chilly winter in the northern U.S., brutally cold conditions are far from certain. A mild December, January and February would limit gas demand for heating and curb withdrawals from underground storage, leaving the market oversupplied heading into spring. Almost half of respondents in a Bloomberg News survey of traders and analysts late last month said winter prices could rise higher than $3 per million British thermal units, perhaps testing $4 or more, a level not seen for years. Hedge funds are the most bullish on gas prices since 2017. Gas futures jumped 17.7 cents to $2.615 in New York on Monday, the biggest gainer among major commodities. Shares of gas producers including Southwestern Energy Co. also climbed. With temperatures not expected to be cooler until late October, EBW AnalyticsGroup CEO Andy Weissman said gas traders are closely watching the recovery process of Cameron LNG, a Sempra Energy-owned export terminal in Louisiana that’s restarting after shutting due to Hurricane Laura in late August. If cold weather doesn’t materialize, money managers will jettison their bullish positions, leading prices to plummet.
U.S. natgas drops 3% on mild forecasts, LNG export hurricane worries – (Reuters) – U.S. natural gas futures fell over 3% on Tuesday on forecasts for milder weather and lower demand over the next two weeks than previously expected and worries Hurricane Delta could disrupt liquefied natural gas (LNG) exports. That price decline came despite a rise in LNG exports so far this week and a drop in output as producers shut Gulf of Mexico wells ahead of the storm. Delta is expected to slam into the Gulf Coast between Texas and Florida as a major hurricane on Friday. Front-month gas futures fell 9.5 cents, or 3.6%, to settle at $2.520 per million British thermal units. Earlier in the day, the contract was on track for its highest close since November. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to drop from 86.9 billion cubic feet per day (bcfd) on Monday to 84.2 bcfd on Tuesday, its lowest since August 2018 as Gulf Coast producers shut-in wells. That data is preliminary and subject to change later in the day. The U.S. Bureau of Safety and Environmental Enforcement (BSEE) said energy firms have already shut-in about 0.2 bcfd, or 9%, of offshore gas production in the Gulf of Mexico. With milder weather coming, Refinitiv projected demand, including exports, would slip from 86.0 bcfd this week to 85.8 bcfd next week. That was lower than Refinitiv’s forecasts on Monday. The amount of gas flowing to LNG export plants has averaged 7.0 bcfd so far in October, up from 5.7 bcfd in September, as vessels started returning to Cameron in Louisiana. Traders noted Cove Point in Maryland was expected to exit its maintenance outage next week.
U.S. natgas futures rise as producers shut wells ahead of Hurricane Delta | Reuters(Reuters) – U.S. natural gas futures gained over 3% on Wednesday as producers shut Gulf of Mexico wells ahead of Hurricane Delta and on forecasts for larger-than-expected demand over the next two weeks. Prices rose despite worries Delta could cut liquefied natural gas (LNG) exports as happened with Hurricane Laura in late August. Actual gas flows to LNG export plants, however, were at their highest since April. Delta is expected to slam into Louisiana as a major hurricane on Friday. Front-month gas futures rose 8.6 cents, or 3.4%, to settle at $2.606 per million British thermal units. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to drop from a four-month low of 84.8 billion cubic feet per day (bcfd) on Tuesday to a 26-month low of 83.3 bcfd on Wednesday as Gulf Coast producers shut wells. That data is preliminary and subject to change later in the day. The U.S. Bureau of Safety and Environmental Enforcement said energy firms shut in 1.3 bcfd, or 49%, of offshore Gulf of Mexico gas production. With milder weather coming, Refinitiv projected demand, including exports, would slip from 87.0 bcfd this week to 86.8 bcfd next week. That, however, was higher than Refinitiv’s forecasts on Tuesday. The amount of gas flowing to LNG export plants averaged 7.2 bcfd so far in October, up from 5.7 bcfd in September. That was on track to rise for a third month in a row for the first time since hitting a record 8.7 bcfd in February as higher global gas prices in recent months have prompted buyers to reverse some cargo cancellations.
US working natural gas volumes in underground storage rise by 75 Bcf: EIA | S&P Global Platts – US working natural gas inventories rose by 75 Bcf last week while an approaching hurricane in the Gulf of Mexico douses LNG export demand in the South-Central storage region. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up US gas in storage increased 75 Bcf to reach 3.831 Tcf for the week ended Oct. 2, Energy Information Administration data showed Oct. 8. The injection was above an S&P Global Platts’ survey of analysts that called for a 71 Bcf build. Responses to the survey ranged from an injection of 62 Bcf to 86 Bcf. The injection measured less than the 102 Bcf build reported during the same week last year as well as the five-year average gain of 86, according to EIA data. Storage volumes now stand 444 Bcf, or 13%, above the year-ago level of 3.285 Tcf and 394 Bcf, or 11.5%, above the five-year average of 3.351 Tcf. Stock levels for the Continental US were 128 Bcf higher than the previous five-year maximum for this calendar week. Nearly half of those extra volumes were stored in the South-Central region’s salt dome facilities, which are 58 Bcf higher than the five-year maximums. NYMEX Henry Hub futures prices were muted the morning of Oct. 8, with November rising 1 cent to $2.62/MMBtu, while the balance of winter was trading about 1 cent lower. After a rocky month of trading, winter strip prices were roughly equal to where they were a month ago, with the strip priced at $3.09 after briefly dropping as low as $2.93 last weekend. S&P Global Platts Analytics’ supply and demand model currently forecasts a 37 Bcf injection for the week ending Oct. 9. This would lower the surplus to the five-year average by 50 Bcf. Markets have tightened for the week ending Oct. 9, with the week in progress seeing fundamentals trending more than 4 Bcf/d tighter compared with the week prior. Total supplies week have averaged about 300 MMcf/d lower, after a nearly 1 Bcf/d combined drop in onshore and offshore production was supported, in part, by a 700 MMcf/d increase in net Canadian imports. Downstream, residential and commercial demand has made a strong showing, up nearly 3 Bcf/d week on week, while LNG feedgas demand has ticked up another 700 MMcf/d, helping drive a combined 3.9 Bcf/d increase in total US demand. Injections tightened in response to the rapid intensification of Hurricane Delta from a Tropical Storm to a Category 4 hurricane Oct. 6. Despite the calm start to the week, the South-Central region finishes as the primary driver of weaker US-level injections, with the salt domes alone accounting for nearly half of the week-on-week change.
U.S. natgas up to highest since August as Hurricane Delta shuts output | è·¯é€ (Reuters) – U.S. natural gas futures edged up on Thursday to their highest since August, as the Gulf of Mexico braced for Hurricane Delta’s arrival and the market focused more on production declines than on lower gas flows to the region’s liquefied natural gas (LNG) export plants. Delta was expected to slam into Louisiana on Friday with winds over 100 miles per hour (161 kph). Traders noted that prices fell early in the session, then turned positive following a report showing an expected, below-normal storage build last week that keeps inventories on track to reach a record high by the end of October. The U.S. Energy Information Administration said utilities injected 75 billion cubic feet (bcf) of gas into storage in the week ended Oct. 2. That is in line with the 73-bcf build analysts forecast in a Reuters poll and compares with an increase of 102 bcf during the same week last year and a five-year (2015-19) average build of 86 bcf. Front-month gas futures rose 2.1 cents, or 0.8%, to settle at $2.627 per million British thermal units, their highest since Aug. 31. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to drop from a 26-month low of 84.1 billion cubic feet per day (bcfd) on Wednesday to a preliminary 83.3 bcfd on Thursday as Gulf Coast producers shut wells. The U.S. Bureau of Safety and Environmental Enforcement said energy firms shut 1.7 bcfd, or 62%, of offshore Gulf of Mexico gas production. In Louisiana, Cameron LNG said it would shut its LNG export plant, while Cheniere Energy Inc reduced gas flows to its Sabine Pass facility but planned to keep it operating with a small “ride-out” crew. With LNG exports declining, Refinitiv projected demand would slip from 86.9 bcfd this week to 85.5 bcfd next week.
U.S. natgas highest since November as hurricane shuts output, cold forecasts – (Reuters) – U.S. natural gas futures jumped to their highest since November on Friday as production fell to its lowest in over two years after Gulf Coast energy firms shut wells ahead of Hurricane Delta and on forecasts for colder weather and higher demand in mid October. That price increase came despite a drop in gas flows to liquefied natural gas (LNG) export plants as operators either shut or reduced their Louisiana facilities before Delta makes landfall. Delta was expected to slam into Southwest Louisiana near the Cameron LNG export plant later Friday. The storm has already caused about 12,000 power outages in Louisiana, according to local utilities. Front-month gas futures rose 11.4 cents, or 4.3%, to settle at $2.741 per million British thermal units, their highest close since Nov. 8. After rising 19% over the past two weeks, the front-month was up almost 13% this week. Data provider Refinitiv said output in the Lower 48 U.S. states would drop from a 26-month low of 84.0 billion cubic feet per day (bcfd) earlier this week to a preliminary 83.1 bcfd on Friday as Gulf Coast producers shut wells. The U.S. Bureau of Safety and Environmental Enforcement said energy firms shut 1.7 bcfd, or 62%, of offshore Gulf of Mexico gas production. In Louisiana, meanwhile, Cameron shut its LNG export plant on Thursday, while Cheniere Energy Inc reduced gas flows to its Sabine Pass facility from a five-month high of 4.0 bcfd earlier in the week to a preliminary 2.1 bcfd on Friday. Cheniere said it planned to keep Sabine operating with a small “ride-out” crew. Refinitiv projected demand would slip from 87.0 bcfd this week to 85.3 bcfd next week before jumping to 93.2 bcfd in two weeks as the weather turns colder and with LNG plants in Louisiana and Cove Point in Maryland expected to return.
Report questions feasibility of LNG industry – A new report released Monday questions not only the environmental impact, but also economic feasibility of the liquid natural gas industry based mostly on the U.S. Gulf Coast – including three proposed and existing facilities in Southeast Texas. In the report “Troubled Water for LNG,” the Environmental Integrity Project tracks the environmental toll of additional releases from LNG facilities and what it characterized as a volatile marketing that has led to 10 proposed projects being delayed by a year or indefinitely while still being approved by the federal government.Locally, the Golden Pass LNG and Port Arthur LNG projects – both planned for the Sabine Pass community of Port Arthur – were listed among six projects that have been delayed by at least a year since the COVID-19 pandemic took hold in the United States this spring. Authors of the report posited that such delays weren’t symptoms of the pandemic-related recession, but were the result of an already saturated market that was already becoming unattractive to investors as evidenced by some companies going more than three years after receiving air permits without making a final investment decision.
North American Pipeline Project Roundup: September/October 2020 – Project Roundup – Project Roundup is a monthly feature that summarizes the contracts awarded for pipeline projects in North America. The following oil and gas pipeline projects have been announced. Projects are in order of most recent approximate starting date. All projects are for 2020 unless noted. (dozens)
Pipeline Billionaire Steps Down— Kelcy Warren, the Dallas billionaire known for controversial pipelines and aggressive dealmaking, is stepping down as chief executive officer of Energy Transfer LP. But if the move is anything like those of fellow moguls in the pipeline industry, he isn’t going far. The company late Thursday named Chief Operating Officer Mackie McCrea and Chief Financial Officer Tom Long as co-CEOs. Warren, 64, will stay on as executive chairman and remains the top investor. He’ll also retain a majority stake in the so-called general partner that controls Energy Transfer’s board. Warren appears to be following a playbook employed by his billionaire rivals in the pipeline industry. Kinder Morgan Inc. founder Rich Kinder continues to serve as his company’s chairman despite relinquishing the CEO title in 2015, and Randa Duncan holds the same spot at Enterprise Products Partners LP after her father, the company’s founder, died in 2010. “Although I am stepping away from the day-to-day management of our business, I will continue to be intimately involved in the strategic growth of Energy Transfer,” said Warren, who has a net worth of about $3 billion, according to the Bloomberg Billionaires Index. Warren co-founded Energy Transfer in 1996 alongside Ray Davis, who now co-owns the Texas Rangers baseball team. Warren’s appetite for takeovers and his use of the tax-advantaged master limited partnership model allowed him to turn 200 miles of natural gas conduits into one of the biggest pipeline operations in the country. Those same characteristics have frequently earned him the ire of everyone from regulators to environmental groups to investors. Warren rose to national attention for his Dakota Access crude oil pipeline, which triggered months of on-the-ground protests after the Standing Rock Sioux Tribe objected to the path of the project in North Dakota. Even once Dakota Access faded from headlines after the project was fast-tracked by the Trump administration, Warren and Energy Transfer continued to attract scrutiny. When building the Rover natural gas pipeline, the company bulldozed an historic house in Ohio that it had told federal regulators it would use as office space. And Energy Transfer’s Mariner East natural gas liquids pipeline has been blamed for a series of sinkholes in Pennsylvania. Williams Deal Warren has taken a similarly pugnacious approach when it comes to dealmaking. Energy Transfer in 2016 backed out of a $36.6 billion deal with Williams Cos. that would have created the nation’s largest natural gas transporter. Two years later, Energy Transfer made a hostile, and unsuccessful, run at NuStar Energy LP. And despite all the acquisitions he’s managed to make, two dramatic oil-industry downturns have pushed down the value of Energy Transfer to less than $6 billion, from a peak of more than $35 billion in 2015.
Containership no longer leaking fuel in Bayonne terminal – A fuel oil leak from a containership at the Global Container Terminal in Bayonne has been stopped, the U.S. Coast Guard announced on Sept. 30. The container vessel YM Mandate is no longer leaking fuel oil from a crack in the hull. The ship is internally conducting a transfer of fuel oil from the affected tank. Fuel oil is being pumped from the affected tank to a barge alongside the vessel and will continue to be pumped until the affected tank is empty, and repairs to the hull can be made. All leaking product is currently contained within the boom and skimmer system. An oil containment boom, a temporary floating barrier, and absorbent pads have been deployed around the YM Mandate, according to the Coast Guard. Contracted skimming vessels have been working to remove oil from the water. A unified command consisting of the Coast Guard, New Jersey Department of Environmental Protection, and Gallagher Marine Systems, responded to the report of an oil leak in the water. The National Response Center contacted Coast Guard Sector New York watchstanders on Sept. 28, reporting a sheen near the vessel Yang Ming (YM) Mandate. The YM Mandate was built in 2010 and can hold 6,572 twenty-foot equivalent units (TEUs). Each storage container is 20 feet long, meaning the YM Mandate can carry approximately 6,572 storage containers. A Coast Guard Maritime Safety and Security Team (MSST) New York boat crew in the area reported a small crack in the ship’s hull, which was leaking fuel oil. Coast Guard investigators confirmed the leak. YM Mandate activated its Coast Guard-approved vessel response plan by making notifications and activating response resources. The affected tank has a capacity of 462,297 gallons. The amount of fuel oil leaked is not known at this time. The last time an oil spill occurred was in 2018. APM Terminal alerted the National Response Centre that fuel had spilled into Newark Bay while a ship was refueling pier-side at the terminal. While commercial cleanup crews used a boom to contain the fuel and recover it from the waterway, it’s not clear how much oil was spilled and how much was recovered.
Delta Threatens Louisiana Energy Hub Still Reeling from Laura — For six weeks, residents of the tiny bayou town of Cameron, Louisiana, have been plucking their wind-tossed belongings from swamps, ripping out soggy dry wall and attempting to piece their lives back together after being bowled over by Hurricane Laura. Now, with the waterfront town still in ruins, another storm is approaching. Hurricane Delta, which grew into a major Category 3 storm Thursday, is forecast to hit nearly the same spot as Laura. For Cameron, which sits 3 feet above sea level and has a population of 400, it would be a devastating one-two punch. “Debris is still everywhere,” said Tressie Smith, a Cameron native who lost her home and the seafood restaurant she owns in Laura. She’s evacuating to the Houston area to avoid Delta, forecast to make landfall Friday. Laura’s destruction has left the region — a hub for the oil, petrochemical and liquefied natural gas industries — fully exposed. Many people in Cameron and nearby Lake Charles work at refineries or on shrimping boats or offshore platforms. If the forecasts are right, they’ll soon be facing the rare and unfortunate fate of fending off one hurricane while still recovering from another. As of late Friday, Delta wasn’t forecast to be as strong as Laura, but even a weak storm can do more damage than usual when hitting so soon after another. A warmer-than-normal Atlantic and decreased wind shear have combined to spawn 25 named storms this year, the second most after 2005 when deadly Hurricane Katrina inundated New Orleans. Delta will be the record 10th tropical storm or hurricane to hit the U.S. in a year. “Lake Charles is still very much on its knees,” said Jim Serra, a long-time resident. Entergy Corp., which owns the local utility, didn’t fully restore power to the region until Oct. 1. On Wednesday, workers in Lake Charles were picking up debris and downed trees that have lined the streets since Laura so that they don’t become projectiles during Delta. Thousands of residents are living in temporary housing, including trailers and tents, after their homes were destroyed in Laura. Others are living in homes with tarps covering massive holes in their roofs.
92 Percent of US GOM Oil Production Shut-In – The Bureau of Safety and Environmental Enforcement (BSEE) estimates that approximately 91.53 percent of the oil production and around 61.82 percent of the gas production in the U.S. Gulf of Mexico has been shut-in in response to Hurricane Delta. Production percentages are calculated using information submitted by offshore operators in daily reports, the BSEE notes. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day, according to the BSEE, which said the shut-in production figures are estimates that it compares to historical production reports to ensure the estimates follow a logical pattern. Personnel have been evacuated from a total of 272 production platforms in the U.S. GOM, the BSEE highlighted, adding that this figure is equivalent to 42.3 percent of the 643 manned platforms in the region. Personnel have also been evacuated from seven non-dynamically positioned rigs, which is equivalent to 70 percent of the ten rigs of this type currently operating in the area. A total of 15 dynamically positioned rigs have moved off the location of the hurricane’s projected path as a precaution. This number represents 88.24 percent of the 17 dynamically positioned rigs currently operating in the region. “After the hurricane has passed, facilities will be inspected,” the BSEE said in a statement posted on its website. “Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online,” the BSEE added. The National Hurricane Center (NHC) has described Hurricane Delta as “major”. The hurricane is currently heading towards southwestern Louisiana and it expected to bring hurricane conditions and a life-threatening storm surge to portions of the northern gulf coast later today, according to the NHC.
Old wellsite spraying oil and natural gas after hit by logging equipment – Emergency responders were busy in far northwest Jasper County on Tuesday afternoon after logging equipment accidentally hit an old wellsite. It happened during the noon hour at the George W. Brown #2 well, located off of County Road 32 about a mile north of Recreational Road 255 in the Ebenezer Community. The Angelina River and Rayburn Fire Departments along with Jasper County deputies responded when it was reported that the well was spraying a blue-tinted mist into the air. A representative from the Texas Railroad Commission arrived at the scene and walked about 100 yards off the road to the well, where he said he determined that the well was spewing a combination of oil and natural gas. Although the gas had no smell, the odor of the crude oil was very obvious. Fortunately, a stiff northerly breeze on Tuesday was quickly blowing away the escaping natural gas. Jasper County Sheriff’s Department Chief Deputy Scotty Duncan was at the scene along with Lieutenant John Cooper and Deputy Chris Sherer. Duncan said they would remain on site until a work crew could arrive and repair the damage and stop the leak.
Texas oil well spewed pollution for 10 months, group says – An oil well site in the Permian Basin owned by a bankrupt shale producer has spewed polluting gases into the atmosphere for 10 months, despite being investigated by Texas regulators, according to an environmental group. Infrared video footage collected during multiple visits from November 2019 through September show “intense and significant” emissions from MDC Energy LLC’s Pick Pocket location in West Texas, Earthworks said in a letter to two state regulatory agencies on Thursday. The group called on the Texas Commission on Environmental Quality and the Texas Railroad Commission to rescind permits for MDC. “TCEQ and RRC must properly address these intense emissions including, but not limited to, volatile organic compounds (VOCs), methane, and hydrogen sulfide,” Sharon Wilson, Earthworks’ thermographer, wrote in the letter. TCEQ said in a statement that it would look into the issues raised in Wilson’s letter. An enforcement case for complaints raised about MDC’s operations “is currently under development and will include the assessment of an administrative penalty and corrective actions, as needed,” the agency said. The RRC didn’t immediately have comment. As the list of U.S. oil companies collapsing into bankruptcy grows, concerns are mounting about what happens to their wells if they’re unable to pay to maintain or properly plug them. Millions of wells have been left abandoned across the country, many of which have been found to leak methane. That’s drawn particular scrutiny because methane is a greenhouse gas that retains far more heat in the atmosphere upon its release than carbon dioxide. Texas has taken a friendly stance toward the shale industry. But, more recently, some of the industry’s biggest investors, and even some oil producers, have called for stricter regulations. Another major environmental concern is the widespread industry practice of flaring in which producers burn off excess natural gas. Recent surveys by the Environmental Defense Fund found flares in the Permian are frequently unlit or malfunctioning, meaning methane is being released directly into the air.
Oil Pipeline Operators Offer New Discounts as Demand Craters – U.S. oil pipeline operators are slashing fees to encourage customers in Texas to keep using their networks to ship barrels to the Gulf Coast as the pandemic wreaks havoc on profits.Kinder Morgan Inc. is offering discounts of about 50% on the Eagle Ford pipeline for some existing customers, according to people familiar with the matter. Magellan Midstream Partners LP is negotiating lower tariffs on the Permian’s BridgeTex system for certain users whose contracts are up for renewal at the end of 2020, they said. Energy Transfer LP plans a volume incentive program for those who qualify on its Permian Express 2 and 3 pipelines.The discounts reflect efforts by pipeline companies to combat sluggish oil consumption and a drilling slowdown in prolific regions such as the Permian Basin after they expanded capacity in recent years. Last month, Enterprise Products Partners LP shelved plans for a major crude pipeline which would have added 450,000 barrels a day of capacity to a system that carries oil from the Permian to the Gulf Coast.Kinder Morgan and Energy Transfer declined to comment. Magellan is always working with customers to meet their needs in any market environment, Bruce Heine, a company spokesman, said by email.The industry responded with similar discounts during previous slowdowns such as the 2014-2015 downturn, said Jon Sudduth, senior North American crude analyst at Energy Aspects in Houston. At that time, U.S. crude prices crashed after Saudi Arabia flooded the market in an attempt to kill off what the Kingdom saw as rising competition from booming North American shale fields.The lack of demand for pipeline capacity has reduced the premium for oil delivered to export hubs on the Gulf Coast to under $1 a barrel from around $3 a barrel at the start of the year. That’s not enough to cover transport costs for most Permian pipelines.While shippers regard tariffs as sunken costs, there are other variable charges, said Sudduth. “If the spread between Permian oil prices and those on the Gulf doesn’t cover the variable costs, it would mean losing not just on the cost of tariff, but those variable charges as well,” he said.
Simplifying the debate about routine flaring – There is broad and growing agreement that the practice of routinely flaring natural gas in Texas must quickly come to an end. The reason for this is obvious. Setting fire to natural gas produced at oil wells is a significant waste of resources and releases vast amounts of carbon dioxide, methane and other harmful pollution into the atmosphere.That’s why EDF and other environmental groups, investors, elected officials, communities and even some oil and gas companies are calling on the Texas Railroad Commission to end the practice as soon as possible. Sometimes discussions about routine flaring get bogged down in details, loopholes and special circumstances. But at its core, routine flaring and the need to end it are pretty simple.Routine flaring occurs when an operator is producing oil (or gas condensates) from a well without a use or destination for the associated natural gas that is produced.Because the oil and, sometimes, gas condensate, are more valuable, the operators may only want to capture those valuable products. Natural gas is less valuable, so many companies don’t want to capture it or don’t have an immediate plan to capture it. The simplest and cheapest solution is burning it. Routine flaring is, essentially, convenience flaring, and it has occurred across Texas during the shale boom. We don’t think flaring should be considered a free waste disposal solution. Before getting a drilling permit from RRC, operators should be required to submit a plan for how the natural gas they produce will be put to beneficial use and demonstrate that the plan will be in place before drilling begins. And for existing wells, the RRC should require a plan that expeditiously phases out routine flaring, ultimately resulting in the capture of the gas or a shutting in of the well.
Company wants to take Minnesota county’s frac sand ban to U.S. Supreme Court – A mining company plans to take its fight to overturn the Winona County ban on frac sand mining to the U.S. Supreme Court, a company spokesman said Tuesday. Minnesota Sands, which lost its case before the Minnesota Supreme Court in March, said the ban violates the U.S. Constitution. “We are hopeful the Court will decide to hear this case and overturn what we continue to believe is an ordinance that clearly interferes with interstate commerce and violates the Constitution’s Commerce Clause,” company president Rick Frick said in a statement. The southeast Minnesota county passed the ban in 2016 – the first in the state – after mining of the rich silica sand deposits there had begun. Frick sued the county in 2017. A district court upheld the ban, as did the Appeals Court in a 2-1 decision in 2018. In March, the seven-member state Supreme Court affirmed lower court rulings that let the ban stand, with two justices dissenting in full and one dissenting in part. The ban allows mining for construction sand, a cheaper and less-pure material used on roadways and for other commercial uses. Silica sand is 95% quartz and consists of round, extremely hard granules that prop open cracks in shale rock, allowing the extraction of oil, gas and natural gas liquids.
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