Oil, Gas, And Fracking News Read 21March 2021 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 20 March 2021. Part 2 is available here.

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

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Oil drops most in 5 months; DUC backlog rises to 14.7 months as completions fall for the first time in 9 months

Oil prices tumbled by the most in 5 months this week on rising tension between Biden and Putin, and on a new wave of Covid infections across Europe…after slipping 0.7% to $65.61 a barrel last week in an inevitable correction of an 80% runup over 18 weeks, the contract price of US light sweet crude for April delivery opened slightly lower on Monday as the dollar strengthened and weighed on commodities priced in the currency, then rallied into positive territory by midday on strong Chinese economic news and ongoing supply restraint from major oil producers before fading to close 22 cents lower at $65.39 a barrel, pressured by expectations that ongoing damage from the freeze off in Texas would continue to boost crude inventories….oil prices continued lower on Tuesday as traders awaited signs of further recovery in consumption and closed down 59 cents at $64.80 a barrel as Germany, France and other European states suspended the use of the AstraZeneca coronavirus vaccine, threatening the recovery of fuel demand…oil prices jumped back above $65 late Tuesday after the API reported that US crude inventories had unexpectedly dropped, but fell back after the market opened on Wednesday and settled 20 cents lower at $64.80 a barrel after government data showed a weekly build in crude, gasoline and distillate supplies…oil prices opened lower on Thursday and tumbled throughout the day to a 10% loss by midafternoon on concern over rising tensions between the U.S. and Russia and a slowdown in the European vaccine rollout, but recovered to post just a 7% loss at $60.00 a barrel, still the steepest drop in 6 months, with a sharp rise in the value of the dollar after a Fed meeting where no action was taken also driving the selloff…however, oil prices rebounded after opening lower again on Friday after investment banks from Goldman Sachs to Morgan Stanley said the Thursday sell-off was excessive and offered an opportunity to buy, and rallied to close $1.42 or 2.4% higher at $61.42 a barrel, on reports of an attack on an oil facility in Saudi Arabia, but still finished the week 6.4% lower, oil’s worst week since October, as a new wave of coronavirus infections across Europe dampened hopes that fuel demand would recover anytime soon…

Natural gas prices also fell this week, albeit not as precipitously, as weather forecasts suggested little demand for heating thru the remainder of the season…after falling 3.7% to $2.600 per mmBTU last week as the weather continued to moderate with the end of the heating season approaching, the contract price of natural gas for April delivery opened more than 4 cents lower on Monday and tumbled to an 11.6 cent loss at $2.484 per mmBTU as forecasts called for spring weather and less heating needs over the remainder of this month and into April…gas prices recovered 7.8 cents of that loss on Tuesday, as signs of sustained strength in LNG demand offset forecasts for mild weather and light heating demand, but fell back 3.4 cents to $2.528 per mmBTU on Wednesday as traders mulled forecasts for mild spring weather and expectations for only a modest storage withdrawal report the next day….natural gas prices fell another 4.7 cents to $2.481 per mmBTU on Thursday – the 10th decline in 12 trading sessions – after a bearish storage report and forecasts that indicated further moderating heating demand…however, gas prices reversed the slide on Friday as LNG output reached record levels, and a brightening economic outlook offset festering worry about weak weather-driven demand and gas prices settled 5.4 cents higher at $2.535 per mmBTU, but still finished 2.5% lower on the week…

The natural gas storage report from the EIA for the week ending March 12th indicated that the amount of natural gas held in underground storage in the US fell by 11 billion cubic feet to 1,782 billion cubic feet by the end of the week, which left our gas supplies 253 billion cubic feet, or 12.4% below the 2,035 billion cubic feet that were in storage on March 12th of last year, and 93 billion cubic feet, or 5.0% below the five-year average of 1,875 billion cubic feet of natural gas that have been in storage as of the 12th of March in recent years….the 11 billion cubic feet that were drawn out of US natural gas storage this week was less than the average forecast of a 17 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, and was also less than 15 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, and far less than the average withdrawal of 59 billion cubic feet of natural gas that have typically been pulled out of 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 March 12th indicated that even after another big increase in our oil refining and a decrease in our oil imports, we still had a modest surplus of oil left to add to our stored commercial crude supplies, which increased for the 4th week in a row and for the 12th time in the past thirty-four weeks….our imports of crude oil fell by an average of 332,000 barrels per day to an average of 5,323,000 barrels per day, after falling by an average of 636,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 113,000 barrels per day to 2,520,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,803,000 barrels of per day during the week ending March 12th, 219,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was unchanged at 10,900,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 13,703,000 barrels per day during this reporting week…

US oil refineries reported they were processing 13,433,000 barrels of crude per day during the week ending March 12th, 1,123,000 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 342,000 barrels of oil per day were being added to the supplies of oil stored in the US….totalling those amounts, 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 72,000 barrels per day less than what 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 plugged a (+72,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there was a small error or errors in this week’s oil supply & demand figures we have just transcribed….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,467,000 barrels per day last week, which was 13.9% less than the 6,351,000 barrel per day average that we were importing over the same four-week period last year…..the 342,000 barrel per day addition to our total crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported to be unchanged at 10,900,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,400,000 barrels per day, while a 1,000 barrel per day decrease to 460,000 barrels per day in Alaska’s oil production had no impact on the rounded national total….last year’s US crude oil production for the week ending March 13th was rounded to 13,100,000 barrels per day, so this reporting week’s rounded oil production figure was 16.8% below that of a year ago, yet still 29.3% above the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

US oil refineries were operating at 76.1% of their capacity while using those 13,433,000 barrels of crude per day during the week ending March 12th, up from 69.0% of capacity during the prior week, but except for the pandemic impacted months of 2020, still one of the lowest refinery utilization rates of the last 30 years…hence, the 13,433,000 barrels per day of oil that were refined this week were still 15.1% fewer barrels than the 15,820,000 barrels of crude that were being processed daily during the week ending March 13th of last year, when US refineries were operating at a seasonal low 86.4% of capacity…

Even with the jump in the amount of oil being refined, the gasoline output from our refineries was lower for the 11th time in 18 weeks, decreasing by 128,000 barrels per day to 8,877,000 barrels per day during the week ending March 12th, after our gasoline output had increased by 704,000 barrels per day over the prior week…with our gasoline production remaining depressed, this week’s gasoline output was still 11.0% lower than the 9,974,000 barrels of gasoline that were being produced daily over the same week of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 524,000 barrels per day to 4,228,000 barrels per day, after our distillates output had increased by 806,000 barrels per day from a twenty-six year low of 2,898,000 barrels per day over the prior week…but even after that two week rebound in our distillates’ production, this week’s output was still 9.8% less than the 4,686,000 barrels of distillates that were being produced daily during the week ending March 13th, 2020…

Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the thirteenth time in eighteen weeks, and for 17th time in 35 weeks, rising by 472,000 barrels to 232,075,000 barrels during the week ending March 12th, after our gasoline inventories had decreased by a record 25,493,000 barrels over the prior two weeks...our gasoline supplies managed to increase this week despite the production drop because the amount of gasoline supplied to US users decreased by 284,000 barrels per day to 8,442,000 barrels per day, and because our imports of gasoline rose by 333,000 barrels per day to 910,000 barrels per day, and because our exports of gasoline fell by 97,000 barrels per day to 580,000 barrels per day…even after this week’s inventory increase, our gasoline supplies were 3.6% lower than last March 13th’s gasoline inventories of 240,819,000 barrels, and about 4% below the five year average of our gasoline supplies for this time of the year…

Meanwhile, with modest recovery in our distillates production, our supplies of distillate fuels increased for the 1st time in 8 weeks and for the 9th time in twenty nine-weeks, rising by 255,000 barrels to 137,747,000 barrels during the week ending March 12th, after our distillates supplies had decreased by 5,504,000 barrels during the prior week….our distillates supplies also rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 459,000 barrels per day to 4,028,000 barrels per day, while our exports of distillates rose by 213,000 barrels per day to 688,000 barrels per day, and while our imports of distillates rose by 52,000 barrels per day to 524,000 barrels per day…and after this week’s inventory increase, our distillate supplies at the end of the week were 10.1% above the 125,120,000 barrels of distillates that we had in storage on March 13th, 2020, even as they remained about 2% below the five year average of distillates stocks for this time of the year…

Finally, even with the recovery in our refinery throughput and the decrease in oil imports, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) ended the week higher for the seventh time in the past eightteen weeks and for the 29th time in the past year, increasing by 2,369,000 barrels, from 498,403,000 barrels on March 5th to 500,799,000 barrels on March 12th, after our commercial oil inventories had increased by a record 35,361,000 barrels over the prior two weeks…after this week’s modest increase, our commercial crude oil inventories remained 6% above the most recent five-year average of crude oil supplies for this time of year, and were still 49.6% above the 5 year average of our crude oil stocks as of the second week of March at the beginning of the decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the spring lockdowns of last year, after generally rising over the prior two years except for during the 10 weeks prior to the Texas freeze and 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 March 12th were 10.4% more than the 453,737,000 barrels of oil we had in commercial storage on March 13th of 2020, 14.0% more than the 439,483,000 barrels of oil that we had in storage on March 15th of 2019, and also 16.2% more than the 430,928,000 barrels of oil we had in commercial storage on March 9th of 2018…

This Week’s Rig Count

The US rig count rose for the 24th time over the past 27 weeks during the week ending March 19th, but it still remains down by 46.8% from what it was a year ago….Baker Hughes reported that the total count of rotary rigs running in the US was up by 9 to 411 rigs this past week, which was still down by 361 rigs from the 772 rigs that were in use as of the March 20th report of 2020, and was 1,518 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 9 rigs to 318 oil rigs this week, after falling by 1 oil rig the prior week, still leaving us with 346 fewer oil rigs than were running a year ago, and less than a fifth 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 was unchanged at 92 natural gas rigs for the 4th week in row, which was still down by 14 natural gas rigs from the 106 natural gas rigs that were drilling a year ago, and just 5.7% 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 or gas, one rig classified as ‘miscellaneous’ continued to drill in Lake County, California this week, while a year ago there were two such “miscellaneous” rigs deployed…

The Gulf of Mexico rig count was unchanged at 13 rigs this week, with 11 of those rigs drilling for oil in Louisiana’s offshore waters and 2 drilling for oil in Alaminos Canyon offshore from Texas…that was 6 fewer Gulf of Mexico rigs than the 19 rigs drilling in the Gulf a year ago, when 17 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the West Delta field offshore from Louisiana, and one rig was drilling for oil offshore from Texas…since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig counts….

The count of active horizontal drilling rigs was up by 10 to 372 horizontal rigs this week, which was still down by 324 rigs from the 696 horizontal rigs that were in use in the US on March 20th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the directional rig count was down by 1 rigs to 14 directional rigs this week, and those were also down by 35 from the 49 directional rigs that were operating during the same week a year ago….meanwhile, the vertical rig count was unchanged at 25 vertical rigs this week, and those were down by 2 from the 27 vertical rigs that were in use on March 6th of 2020….

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 March 19th, the second column shows the change in the number of working rigs between last week’s count (March 12th) and this week’s (March 19th) count, the third column shows last week’s March 12th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday 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 20th of March, 2020..

After several weeks of Permian basin oil rigs moving from New Mexico to Texas, this week it appears they were moving in the opposite direction….checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that there were 2 rigs pulled out of Texas Oil District 8, which corresponds to the core Permian Delaware, while one rig was pulled out of Texas Oil District 7B, which includes the easternmost extent of the Permian Midland basin, which together means there was a net decrease of 3 rigs in the Texas Permian….however, since the national Permian rig count was up by 4, that means that the 7 rigs that were added in New Mexico must have been set up in the farthest west reaches of the Permian Delaware, to balance the national Permian total….elsewhere in Texas, there were 2 rigs added in Texas Oil District 1, another rig added in Texas Oil District 3, and yet another rig added in Texas Oil District 4, any three of which could account for the three rig increase in the Eagle Ford shale, which stretches in a narrow band through the southeast part of the state…at the same time, there were also 2 rigs pulled out of Texas Oil District 6, which had been drilling for natural gas in the western part of the Haynesville shale…the Haynesville shale shows no net change, however, because two natural gas rigs were set up to target that formation in northwestern Louisiana at the same time…other than that, the only other change evident this week was the oil rig that was pulled out of North Dakota’s Williston basin at the same time…

DUC well report for February

Monday of this past week saw the release of the EIA’s Drilling Productivity Report for March, which includes the EIA’s February data for drilled but uncompleted oil and gas wells in the 7 most productive shale regions….that data showed a decrease in uncompleted wells nationally for the 9th month in a row, as both completions of drilled wells and drilling of new wells both decreased and remained far below the pre-pandemic levels, with wells drilled down for the first time since July and completions down for the first time since May….for the 7 sedimentary regions covered by this report, the total count of DUC wells decreased by 102 wells, falling from 7,188 DUC wells in January to 7,086 DUC wells in February, which was also 15.9% fewer DUCs than the 8,426 wells that had been drilled but remained uncompleted as of the end of February of a year ago…this month’s DUC decrease occurred as 380 wells were drilled in the 7 regions that this report covers (representing 87% of all U.S. onshore drilling operations) during February, down from the 417 wells that were drilled in January, while 482 wells were completed and brought into production by fracking, down from the 606 completions seen in January, and down by more than half from the 1,137 completions seen in February of last year….at the February completion rate, the 7,086 drilled but uncompleted wells left at the end of the month represents a 14.7 month backlog of wells that have been drilled but are not yet fracked, up from the 12.5 month DUC well backlog of a month ago, with the understanding that this normally indicative backlog ratio is being skewed by a completion rate that is now one-third of the previous norm…

Both oil producing regions and natural gas producing regions saw DUC well decreases in February, as only the Haynesville shale reported a single DUC increase…the number of uncompleted wells remaining in the Niobrara chalk of the Rockies’ front range fell by 30, decreasing from 503 at the end of January to 467 DUC wells at the end of February, as 39 wells were drilled into the Niobrara chalk during February, while 69 Niobrara wells were being fracked….in addition, DUCs in the Eagle Ford of south Texas decreased by 22, from 1,033 DUC wells at the end of January to 1,011 DUCs at the end of February, as 35 wells were drilled in the Eagle Ford during February, while 57 already drilled Eagle Ford wells were completed…there was also a decrease of 22 DUC wells in the Bakken of North Dakota, where DUC wells fell from 702 at the end of January to 680 DUCs at the end of February, as 17 wells were drilled into the Bakken during February, while 39 of the drilled wells in that basin were being fracked…at the same time, the number of uncompleted wells remaining in Oklahoma’s Anadarko decreased by 13, falling from 764 at the end of January to 751 DUC wells at the end of February, as 18 wells were drilled into the Anadarko basin during February, while 31 Anadarko wells were being fracked….meanwhile, DUC wells in the Permian basin of west Texas and New Mexico decreased by 2, from 3,275 DUC wells at the end of January to 3,273 DUCs at the end of February, as 167 new wells were drilled into the Permian, while 169 wells in the region were completed…

Among the natural gas producing regions, the drilled but uncompleted well count in the Appalachian region, which includes the Utica shale, fell by 14 wells, from 564 DUCs at the end of December to 550 DUCs at the end of February, as 66 wells were drilled into the Marcellus and Utica shales during the month, while 80 of the already drilled wells in the region were fracked….however, the natural gas producing Haynesville shale of the northern Louisiana-Texas border region saw their uncompleted well inventory increase by 1 to 314, as 38 wells were drilled into the Haynesville during February, while just 37 of the already drilled Haynesville wells were fracked during the same period….thus, for the month of February, DUCs in the five major oil-producing basins tracked by this report (ie., the Anadarko, Bakken, Niobrara, Permian, and Eagle Ford) decreased by a total of 89 wells to 6,222 wells, while the uncompleted well count in the natural gas basins (the Marcellus, Utica, and the Haynesville) decreased by 13 wells to 864 wells, although as this report notes, once into production, more than half the wells drilled nationally will produce both oil and gas…

Federal judge orders no new fracking in Wayne National Forest – Farm and Dairy – A federal judge blocked new oil and gas development in Ohio’s only national forest.The decision comes after a ruling last year found the Bureau of Land Management and U.S. Forest Service failed to adequately consider the environmental impacts hydraulic fracturing could have on Wayne National Forest.The U.S. District Court of the Southern District of Ohioordered a review of U.S. Bureau of Land Management’s 2016 environmental assessment and the U.S. Forest Service’s consent to lease that gave the OK to lease the federal lands.Pending review, the order also prohibits new leases in Wayne National Forest, prohibits new drilling permits and surface disturbance on existing leases and halts water withdrawal from the Little Muskingum River for any drilling that’s already occurring.Judge Michael Watson said in his opinion that the Bureau of Land Management and Forest Service failed to take the requisite “hard look” at the impacts of fracking in the Wayne, including impacts to air quality, surface area disturbance and cumulative impacts on the Indiana Bat and Little Muskingum River. Environmental groups sued the Forest Service and Bureau of Land Management in May 2017 over plans to permit fracking in the Wayne.The Ohio Environmental Club, Sierra Club, Heartwood and Center for Biological Diversity argued that the federal agencies relied on outdated information and ignored “significant environmental threats” before opening the Wayne’s 40,000-acre Marietta unit to unconventional gas development in October 2016. The Wayne National Forest is Ohio’s only national forest. It’s split into three non-contiguous sections. The Marietta unit is the eastern most section and consists of more than 268,000 acres of private and federal lands. There are already about 1,200 active vertical wells in the entire forest.The Bureau of Land Management sold 679 acres in Monroe and Washington counties in its first lease auction in December 2016 and another 1,147 acres in a second auction in March 2017.

Ohio lawmakers seek to limit local authority over fossil-fuel use – Ohio Republican lawmakers are again looking to hamstring local governments’ ability to pass pro-environmental ordinances — this time, by cutting off potential attempts by communities to rein in the use of fossil fuels.Twin bills introduced in the Ohio House and Senate would, if passed, prevent local governments from limiting residents’ use of natural gas. A third bill, introduced in the House, would prevent local bans on oil or gas pipelines, as well as restrictions on the use of any fossil fuel for electricity generation.Environmental activists in Ohio and other states who feel stymied by GOP-dominated state legislatures have increasingly turned to local governments to pass a wish-list of initiatives that promote green energy and cut carbon emissions.Republican lawmakers, who oppose such efforts for both ideological and practical reasons, have increasingly focused on heading them off. Last fall, Gov. Mike DeWine signed a bill imposing a one-year moratorium on local bans of plastic bags.The bills to block limits on natural gas use, House Bill 201 and Senate Bill 127, will ensure residents have access to a reliable source of heat in the winter, said state Rep. Jason Stephens, a Lawrence County Republican who introduced the House version.Stephens said while he hasn’t heard of any Ohio cities restricting natural gas use, dozens of cities on the East and West Coasts have voted to ban natural-gas hookups for new buildings to reduce emissions that cause global warming.Bills similar to Stephens’ prohibiting such bans have already been passed in Arizona, Tennessee, Oklahoma and Louisiana.Stephens, who chairs the Ohio House Energy and Natural Resources Committee, said people he talked to from the natural gas industry indicated this was “a big concern” for them. Given Ohio’s significant natural gas reserves, Stephens said, “It only makes sense to me that if we have that abundant source of energy, that we make sure that we are allowed to use it and we don’t restrain folks who want access to it.”

Ohio legislation would stop towns from banning natural gas – Three bills recently introduced to the Ohio legislature seek to stop local governments from limiting the use of certain types of energy.House Bill 201 and Senate Bill 127 would prevent local governments from limiting the use of natural gas.The House version was introduced by Rep. Jason Stephens, R-Kitts Hill. It was sent to the House Energy and Natural Resources Committee, which Stephens chairs, on March 16. The Senate version, introduced by Sens. Michael Rulli, R-Salem, and George Lang, R-West Chester, was sent to the committee on March 17.Similar legislation has popped up in Indiana, Iowa, Kansas and other states this year. Tennessee, Oklahoma, Arizona and Louisiana enacted laws in 2020 prohibiting bans on natural gas.It all stems from moves on the West Coast to prohibit or limit the use of natural gas in new buildings.It started in Berkley, California. The city council there passed the nation’s first ban on natural gas hookups in new buildings in 2019. Since then dozens of other cities, mostly in California, have passed similar restrictions. Most recently, Seattle enacted legislation to ban natural gas in new buildings in early February.While he hasn’t heard of any Ohio cities considering such an action, Stephens told Farm and Dairy that he thought it best to address the issue before it became an issue. Before becoming a state representative in 2019, Stephens worked in local government for 20 years. He’s seen how a village or city can make decisions seemingly on a whim.If someone does not want natural gas coming to their house, “just take the meter out,” Stephens said. There’s no reason to eliminate the choice for others who do want to use gas to heat their homes or power their stoves.“It just made sense to me that if people have access to natural gas, if they like it, they should continue to have access to it without a government at any level saying they can’t,” Stephens told Farm and Dairy.Another similar piece of legislation, House Bill 192, would prohibit local governments from prohibiting energy generation from fossil fuels. The bill would also prohibit local governments from banning the construction or use of oil and gas pipelines. Sponsor Rep. Al Cutrona, R-Canfield, said in a press release that the purpose of the bill is to prevent possible rate increases.“Ohioans should not be penalized with increased rates if their local government passes new restrictions that so drastically impact utilities’ energy generation practices,” he said in the release.

When A Gas Plant Moves Next Door – WOSU – Kevin and Marlene Young built their house in the country, so they had space for horses. “I was raised around horses, and that’s my love,” Marlene said. With names like Buckeye Blast and Creekside Pete, their horses aren’t just pets. They built a half mile track to train them as racehorses. Their horses have won tens of thousands of dollars in prize money. Surrounded mostly by farmland here in Guernsey County, Ohio, 65 miles west of the Pennsylvania border, they have space to grow grass for hay. The Youngs also built their home into something of a tourist business. When a scenic railroad started running on the train tracks along their property, it would stop here. They opened an antique shop, and even hosted weddings in the outdoor setting. “We’re getting ready to retire. I thought we had it handled,” Marlene said. Visiting them now, things don’t seem handled. Big trucks drive past the house throughout the day. The farm field next door has become an industrial construction site. The air is often filled with dust – there’s a thick layer of it on their new truck. Some nights, bright construction lights shine through their windows. “I mean, come on man, that’s unbelievable,” Marlene said. In the summer of 2019, Caithness Energy started building one of the largest natural gas power plants of its kind in the nation. Thanks to fracking, cheap natural gas is replacing coal to generate electricity. According to the U.S. Energy Information Administration, this site is one of 30 natural gas-fired generators planned in Ohio and Pennsylvania. EIA expects 231 new utility-scale natural gas generators to be built in the U.S. by 2024. There’s already a pipeline that will run natural gas from the region to this site. Once constructed, the Guernsey Power Station will generate 1,875 megawatts, enough power the company says for 1.5 million homes. But the Youngs don’t want to live next door to it. Like others who live nearby, they say the construction has caused cracks in their walls. Before it was a farm field, the site was a coal mine. To stabilize it, Caithness got a permit from the Ohio EPA to drill about a thousand holes in the ground and fill them with cement grout. The land was also known to flood, so the company is moving dirt in some spots to raise it 20 feet. But Kevin said when it rains, water now runs off, flooding his property.“This way, I’m taking all the water,” he said. “It’s like a lake.” In November, Ohio EPA issued two notices of violation to Gemma Power Systems, the company building the plant for Caithness, for problems with erosion and sediment running off the property. But much damage has already been done. One of their horses got startled by the construction equipment just over the fence, and injured itself. “And she was laid up for a month, and we had to dress this leg every day,” Kevin explained.Between incidents like that, and the dusty air, the Youngs have stopped training their horses, sometimes even putting them on respirators.

Rebuttal: Oil and gas industry are good for Ohio communities despite report – — From the car dealers selling vehicles so quickly they can barely keep up with demand, to the construction crews who are as busy as they have ever been, area businesses in Ohio’s shale country are thriving thanks to the investments and economic activity being generated by the oil and gas industry. As commissioners from these counties, we see how the industry is benefitting our communities and constituents every day. That is why we were stunned to see a recent article in The Dispatch argue that the oil and gas industry has not been an economically uplifting force in our communities.The February article, “Report: Ohio fracking counties saw declines in jobs, population and income,” blatantly distorted and misrepresented facts while detailing a report by theOhio River Valley Institute, an organization of radical activists whose main purpose is to promote renewable energy sources.The facts are that the oil and gas industry has invested more than $60 billion in Ohio to support upstream activities such as drilling, extraction and leasing since 2011. That number comes from a report out of Cleveland State University which was commissioned by JobsOhio. That same report showed that from July 2019 to December 2019, the industry invested more than $400 million in Belmont County alone. Let that sink in, $400 million in one county in just six months. In that same time period the industry invested $206,280,000 in Harrison County and $168,480,000 in Guernsey County. The report also indicates that the industry has provided more than $1 billion to build and repair roads since 2011. The numbers are clear, the oil and gas industry is an economic engine in eastern Ohio. The shale boom has made our communities more prosperous than they have ever been, and you don’t have to take our word for it. We invite anyone who wants to see for themselves to visit our counties and spend some time speaking to the locals.

FERC, in signal on pipeline compliance, takes action on Rover, Midship – The Federal Energy Regulatory Commission took two steps March 18 that its new chairman said should send a “clear message” to natural gas pipeline companies that the commission will “not look the other way” when companies fail to meet responsibilities. The commission ordered Energy Transfer Partners and Rover Pipeline to show why they should not pay a proposed $20.2 million civil penalty in relation to allegations of misleading FERC about the destruction of an Ohio farmhouse during the application process for the 3.25 Bcf/d, 711-mile Rover project (IN19-4). FERC also directed Cheniere Energy’s Midship Pipeline to remedy outstanding restoration issues on certain tracts of land and encouraged the company to enter dispute resolution to help address remaining damage that occurred during construction, according to FERC Chairman Richard Glick. The 199.7-mile, 1.4 Bc/d pipeline project, designed to move gas to the US Gulf Coast and Southeast markets from Oklahoma ‘s Anadarko Basin, has faced concerns from landowners about outstanding impacts to properties following construction (CP17-458, CP19-17). Glick called attention to both actions at the start of FERC’s March 18 open meeting.”I think it is important to remind pipeline developers that when they apply for a certificate of public convenience and necessity that they must be truthful, and that when they receive a certificate, which conditions the right to build and operate the pipeline with a requirement of the developer repairing the damage it creates during construction, that they need to take that responsibility seriously.” “This commission is not going to look the other way,” he added. In his view, FERC has several options and “revocation of the certificate itself, must be on the table” for projects that fail to meet responsibilities.During a press briefing with reporters, Glick underscored his view that “we need to send a clear message to certificate holders” that when they agree to a duty of candor or to act in an environmentally sound manner, “you mean that and we’re not going to look the other way.”The commission voted 5-0 to issue the show cause order in relation to Rover and gave the company 30 days to respond to the enforcement staff report.

Ascent Resources to Curb Utica Spending, Stay Disciplined in 2021 – Ascent Resources Utica Holdings LLC, Ohio’s largest oil and natural gas producer, plans to cut spending this year and hold production flat to 2020 levels as the industry continues to take a more conservative financial approach. The Ohio pure-play has issued 2021 capital guidance at a range of $550-600 million and intends to maintain production at 2 Bcfe/d. Ascent spent $657 million last year and produced just over 1.9 Bcfe/d after curtailing 40 Bcfe of volumes, as other operators did when commodity prices were hit by the Covid-19 outbreak.The company intends to run up to four operated rigs this year on its acreage in the southeast part of the state. It plans to spud up to 65 wells and turn up to 70 to sales.Ascent, which is privately owned, is forecasting up to $150 million of free cash flow (FCF) this year based on current market conditions. The company reported $114 million of FCF for full-year 2020.“Ascent has successfully delivered on its operational and financial objectives in 2020,” CEO Jeff Fisher said. He added that the company was able to navigate through the challenging year by “staying disciplined, leveraging our operational capabilities and improving our balance sheet.” Ascent is also the nation’s eighth largest natural gas producer. The company holds 340,000 net acres in Ohio that came together after the late Aubrey McClendon was ousted from the helm of former Utica Shale heavyweight, Chesapeake Energy Corp., and founded Ascent’s predecessor before it was spun-off and became independent.Ascent produced nearly 1.9 Bcfe/d in the fourth quarter, which included the impact of 9 Bcfe of curtailments. Ascent produced 2.3 Bcfe/d in 4Q2019. Fourth quarter net income was $169 million, compared to net income of $65.3 million in the year-ago period. The company reported a net loss of $590 million for the full year, including a $100 million impairment on unproved oil and gas properties. That’s compared with 2019 net income of $466 million. Last year’s average realized prices, including the impact of derivatives, were $2.71/Mcfe, down from $3.02 in 2019.

Why Frack Wastewater Injected Underground Doesn’t Always Stay There — Salty wastewater produced by fracking for oil and gas has to go somewhere. Often, it’sinjected into disposal wells deep underground. But sometimes that wastewater can find its way back to the surface and cause environmental problems. How? We turned to three experts to find out.

Pennsylvania lawmakers urge Gov. Wolf to protect residents following EHN fracking investigation – EHN -On the heels of an Environmental Health News (EHN) study, 35 members of the Pennsylvania House and Senate have issued a public letter calling on state Governor Tom Wolf to take “immediate action in response to the ongoing harm” from fracking.The letter, led by State Senator Katie Muth and State Representatives Sara Innamorato, points to a study recently published by EHN that found evidence of exposure to harmful chemicals in families living near fracking wells.”Recent studies, such as the multifamily investigation published by the Environmental Health News, highlight the true risk so many Pennsylvania families face due to toxic and radioactive contamination caused by fracking,” said Senator Muth in a statement.The two-year investigation, which is documented in a four-part series, found alarming evidence of toxic industrial chemicals linked to fracking in the urine of families living nearby, in addition to finding harmful chemicals like benzene, toluene, and naphthalene in the families’ air and drinking water. Several children in the study had biomarkers for exposure to cancer-causing chemicals in their bodies at levels that exceed those seen in the average adult cigarette smoker.The study, led by EHN reporter Kristina Marusic, is the first time families in western Pennsylvania have been tested for exposure to chemicals emitted from fracking operations – and only the second study nationwide to examine such impacts from oil and gas drilling.”The initial outcomes are alarming in terms of the effects on the long-term health and safety of these residents,” the lawmakers wrote. “This study adds to an ever-growing mountain of evidence comprising more than ten years of epidemiological studies from across the United States that demonstrate a connection between a person’s proximity to shale gas development and a host of negative human health conditions, significant ecological impacts, and dire economic projections for the affected individuals.”The letter urges Governor Wolf to use the same biomonitoring techniques employed inEHN’s investigation to conduct similar testing on a wider scale, and points out that last month the commissioners of the Delaware River Basin Commission, including Gov. Wolf, banned fracking in the Delaware River Basin, which includes parts of eastern Pennsylvania.

Advocacy group says Shell’s Falcon Pipeline under investigation for safety issues -Shell’s controversial multistate pipeline is under investigation by several state and federal agencies for issues that an environmental advocacy group said poses serious threats to public safety, workers and natural resources. FracTracker Alliance, a nonprofit that focuses on the oil-and-gas industry, obtained documents that indicate an investigation into safety matters with the Shell Falcon Pipeline involving the Pennsylvania Department of Environmental Protection, the state Attorney General, the Pipeline Hazardous Materials Safety Administration and the U.S. Environmental Protection Agency. According to a release, the investigation focuses on potential “noncompliance with construction and public safety requirements and alleged cover-up of incidents that could put the public at risk.”A Shell Pipeline spokesman said that government and regulatory agencies have provided oversight throughout the construction process. “It’s our view we have demonstrated an unwavering commitment to safe construction and operations through the robust design and installation of the Falcon Pipeline,” a spokesman said. “Construction and inspection procedures related to Falcon meet or exceed all safety standards and requirements.”The 97.5-mile pipeline system will pass through Ohio, West Virginia and Pennsylvania to deliver ethane to Shell Chemicals’ petrochemical plant in Potter Township. Installation of the pipeline is complete and has been connected on the supply ends and to the cracker plant. While there is no ethane product in the pipeline at this time, Shell officials expect it to become an active pipeline at some time in the next two months. A spokesman said officials do not expect final commissioning of the pipeline until sometime in 2022.Falcon has come under fire for potential impacts to the Ambridge reservoir and other major drinking water sources in the region. The pipeline was installed between 4,100 and 5,1000 feet east of the reservoir and crosses 61 feet below the water authorities’ raw water line, which connects the reservoir to a treatment plant. The route, in total, runs between two dozen towns in Pennsylvania and three bodies of water in the Ambridge reservoir watershed alone.

Falcon Pipeline, which provides natural gas to Shell cracker plant, under investigation for possible corrosion – PGH City Paper -Last year, a natural gas pipeline being constructed through Southwestern Pennsylvania garnered the attention of Pennsylvania’s Department of Environmental Protection, who then notified federal agencies in charge of regulating pipelines and other environmental concerns. In a February 2020 letter to the federal Pipeline and Hazardous Materials Safety Administration, Pa. Department of Environmental Protection Secretary Patrick McDonnell wrote that issues “pose a possible threat of product release, landslide, or even explosion.” According to the Pittsburgh Post-Gazette, McDonnell mentioned witnesses with “first-hand knowledge of bad corrosion coatings, falsification of records and reports, retaliatory firings and other actions by Shell,” who owns the Falcon Pipeline. This led PHMSA to conduct an investigation into the pipeline, which is currently ongoing. The Falcon Pipeline will run 98 miles through Southwestern Pennsylvania, West Virginia, and Ohio and will deliver ethane to the cracker plant in Beaver County, which will refine the natural gas liquid into plastic pellets. When completed, oil giant Shell will run both the Falcon Pipeline and the cracker plant. The investigation is focused on possible noncompliance of public safety requirements during construction of the pipeline and an alleged cover up of incidents that could put the public at risk, according to the FracTracker Alliance, an advocacy organization that obtained documents in connection to the investigation. FracTracker Alliance is particularly concerned with allegations of corrosion of the Falcon Pipelines, as corrosion failure is the second leading cause of incidents occurring on pipelines. “Residents of the Ohio River Valley know too well the serious and life-threatening impacts that have come from rushed pipeline construction in the wake of the fracking buildout,” says Erica Jackson of FracTracker Alliance in a press release. “We hope that regulators will take all necessary action to protect public welfare and bring justice for workers who may have been unfairly terminated.” A spokesperson for Shell confirmed to the Post-Gazette that federal officials conducted audits of the Falcon Pipeline and said PHMSA officials “found no issues with installed coatings.” Shell said it also completed inspection of all the welds as an effort to prevent corrosion, and installed more emergency shutoff valves than necessary and buried the pipeline deeper than and used a thicker pipe than federally mandated.

Federal, state agencies probing Shell’s Falcon ethane pipeline after whistleblowers’ allegations – Early last year, Penn­syl­va­nia’s top en­vi­ron­men­tal of­fi­cial tried to raise an alarm at the high­est level of the fed­eral agency re­spon­si­ble for pipe­line safety. “I write to you re­gard­ing a very se­ri­ous pub­lic safety mat­ter for Penn­syl­va­nia,” the let­ter from Patrick McDon­nell, sec­re­tary of Penn­syl­va­nia’s Depart­ment of En­vi­ron­men­tal Pro­tec­tion, be­gan.The DEP, he said, had cred­i­ble in­for­ma­tion that some sec­tions of Shell Pipe­line’s Fal­con proj­ect “may have been con­structed with de­fec­tive cor­ro­sion coat­ing pro­tec­tion.” He also men­tioned wit­nesses with “first-hand knowl­edge of bad cor­ro­sion coat­ings, fal­si­fi­ca­tion of records and re­ports, re­tal­ia­tory fir­ings and other ac­tions by Shell.”A coat­ing pro­tects the metal pipe­line from be­ing ex­posed to el­e­ments that can cause it to cor­rode. Cor­ro­sion doesn’t typ­i­cally oc­cur early in the pipe­line’s life, but is a lead­ing cause of rup­tures in older pipe­lines. “These are very se­ri­ous al­le­ga­tions, they de­serve thor­ough in­ves­ti­ga­tion and ap­pro­pri­ate res­o­lu­tion,” Mr. McDon­nell stressed to Howard El­li­ott, ad­min­is­tra­tor of the Pipe­line and Hazard­ous Ma­teri­als Safety Ad­min­is­tra­tion. It was, in fact, PHMSA that re­ceived in­tel­li­gence from a whis­tle­blower in early 2019 with con­cerns about how the proj­ect was be­ing han­dled. The fed­eral agency over­sees the in­stal­la­tion and op­er­a­tion of pipe­lines, not en­vi­ron­men­tal mat­ters. So when it came across con­cerns of po­ten­tial un­der­re­p­ort­ing of drill­ing mud spills on the pipe­line, PHMSA sent that in­for­ma­tion to the DEP.For months, the two agen­cies ex­changed in­for­ma­tion. The DEP, alarmed about what it was find­ing, had also started to loop in in­ves­ti­ga­tors from the Penn­syl­va­nia at­tor­ney gen­eral’s of­fice. It briefed of­fi­cials at the U.S. En­vi­ron­men­tal Pro­tec­tion Agency and made con­tact with the U.S. Oc­cu­pa­tional Safety and Health Ad­min­is­tra­tion, which was also con­tacted by a whis­tle­blower on the Fal­con proj­ect.As late as Jan­u­ary 2020, DEP in­ves­ti­ga­tors were email­ing with the head of safety at PHMSA about the Fal­con pipe­line, while at the same time send­ing the lan­guage of Mr. McDon­nell’s let­ter to PHMSA’s head to var­i­ous DEP law­yers for re­view. mWhat Mr. McDon­nell was say­ing – that a PHMSA in­quiry into po­ten­tial cor­ro­sion de­fects was “in­com­plete” and urg­ing the agency to take a more se­ri­ous look at the is­sue, while es­sen­tially copy­ing its su­pe­ri­ors on the note – was a se­ri­ous ac­tion.PHMSA con­firmed that its in­ves­ti­ga­tion into the proj­ect was on­go­ing. “We looked into the con­cerns raised by the DEP but the re­sults are not yet avail­able,” the agency said. A spokes­man for Shell Pipe­line said PHMSA of­fi­cials “con­ducted three on-site au­dits of the Fal­con Pipe­line and found no is­sues with in­stalled coat­ings.”The com­pany also listed steps it took to pre­vent cor­ro­sion. Since the pipe­line was in­stalled, Shell said, it had com­pleted “100% post-in­stal­la­tion in­spec­tions of all welds,” pres­sure-tested the pipe­line and con­ducted an in­line in­spec­tion, the re­sults of which were shared with PHMSA. Lit­tle is known about the scope of the DEP’s find­ings. Mr. McDon­nell’s let­ter to PHMSA was one of a hand­ful of doc­u­ments that sur­faced af­ter the en­vi­ron­men­tal ad­vo­cacy group FracTracker Al­liance re­quested pub­lic records re­lated to the agency’s in­ves­ti­ga­tion. A log of 111 doc­u­ments that were not re­leased, how­ever, sug­gests the DEP was in con­tact with at least two con­fi­den­tial in­for­mants, had ac­cess to pho­tos and notes from the pipe­line job, and fol­lowed up with other agen­cies to see how their in­ves­ti­ga­tions were pro­gress­ing. Within its own ju­ris­dic­tion, the DEP is­sued sev­eral no­tices of vi­o­la­tion to Shell Pipe­line.

Whistleblower Claims Dangerous Defects in Pipeline for Shell’s Pennsylvania Plastics Plant –A whistleblower has alleged that the Falcon pipeline – a 98-mile-long fossil fuel pipeline that will soon feed Shell’s massive plastics manufacturing site under construction in western Pennsylvania – was built with defective protection against corrosion. That’s according to public records obtained by the nonprofit FracTracker Alliance and which reveal that state regulators complained last year that federal authorities had failed to adequately investigate the reports of defects.In that letter, dated February 26, 2020, obtained by FracTracker via a right-to-know request, Patrick McDonnell, secretary of the Pennsylvania Department of Environmental Protection, wrote to the nation’s top pipeline safety regulator describing “a very serious public safety matter for Pennsylvania.”“The Pennsylvania Department of Environmental Protection (PA DEP) has received what appears to be credible information that sections of Shell’s Falcon Pipeline project in western PA, developed for the transportation of ethane liquid, may have been constructed with defective corrosion coating protection,” McDonnell wrote, adding that PA DEP had obtained and sent federal pipeline regulators additional information “which appears to corroborate the whistleblower’s original allegations.”The letter appears to be the first public reference to allegations that the Falcon pipeline’s corrosion protection may be faulty. FracTracker also obtained a log of over a hundred emails and documents apparently related to one or more informants on Falcon, largely involving discussions between attorneys with the PA DEP and other state and federal agencies. The state declined to provide FracTracker with the documents listed in that log, though it did provide a summary of the contents of each communication and indicate who was involved, in some cases providing full names of state officials, in others listing a “Confidential Informant.”The February 2020 letter outlines serious concern among state regulators. “While PA DEP does not regulate the construction, maintenance or operation of the pipeline itself, our staff was alarmed by the whistleblower’s allegations,” McDonnell wrote, “and concerned for the safety of people living along the pathway of the Falcon Pipeline.” The letter asserts that federal authorities had done an inadequate job of responding to the whistleblower’s allegations, despite the dangers posed when anti-corrosion coatings on pipelines fail. “Corroded pipes pose a possible threat of product release, landslide, or even explosion,” McDonnell added. But, he went on, the federal Pipeline and Hazardous Materials Safety Agency (PHMSA) conducted only a “brief inquiry in 2019″ that reported finding no coating problems. “PA DEP believes PHMSA’s initial inquiry was incomplete,” McDonnell continued, “and has referred the matter to other authorities for investigation of the safety of the corrosion protection on the Falcon Pipeline.”

Shell says cracker plant will begin operations in 2022 – The long-awaited and highly polarizing cracker plant will be fully operational in 2022. Shell Pennsylvania Chemicals, owner-operator of the massive facility in Beaver County, made that announcement on Tuesday. That was the first time the company targeted a launch date more specific than “the early 2020s.” Plastics manufacturing will be the hallmark of a facility that is under construction along a 340-acre tract in Potter Township, located below Interstate 376 and along the banks of the Ohio River. And plastics manufacturing is why this is a polarizing endeavor, one that is opposed by a number of environmental support groups, which are concerned about potential impacts from the operation. Ethane, sourced from natural gas in the Marcellus and Utica shale plays, will be converted to polyethylene pellets, a feedstock for plastics production. This $6 to $10 billion project has been in the works for almost a decade. Shell initiated discussions about building a cracker in the Beaver Valley in mid-2012, and did not make a final decision to invest in this until June 2016. Route 18 had to be partially rerouted near the site and the property, once home to a zinc plant, required remediation. Construction on the plant itself did not begin until November 2017. An estimated 7,000 workers have toiled there over the past 3½ years, some of whom endured a monthslong shutdown beginning last spring because of COVID-19. The facility reopened later in the year. When operational, the facility will be the first cracker operation in the United States, outside of the Gulf Coast, in 20-plus years.

Environmental danger lurks beneath – Mountaineer NGL Storage plans to store 3 million barrels of highly toxic and flammable fracked-gas liquids next to, or under, the Ohio River in caverns created by three salt wells, each using 1.7 million gallons of fresh water daily.Ten percent of the resulting 30-million barrels of super-saline water would be kept for cavern pressurization. This polluted water is to be held in a huge pond below the Ohio River high water mark in Monroe County, OH, upon abandoned mines and mine entrances. With such unstable footing the pond could fail contaminating drinking water for five-million people.On the 200-acre site are also adjacent fracked wells and gas pipelines. Such infrastructure near large gas impoundments has touched off disasters elsewhere.However, even after six environmental organizations successfully sued the Ohio Department of Natural Resources for issuing the well permits without the required public notice, public comment, draft permit or a fact sheet, Mountaineer is continuing its risky plan.Meanwhile, local facilities that separate liquids from the gas reduce pressure by flaring. Along with chemicals known to cause asthma, heart damage and immune disorders, this flaring emits cancer-causing radioactivity.These risks are unjustifiable. A March, 2020, institute for Energy Economics and Financial Analysis report concludes that a plastics-production complex, supplied by the gas-liquids storage, is not economically feasible–even without considering clean-up and health care costs. And according to industry which reliably overstates benefits, the storage project will provide only 15 temporary jobs. Nevertheless, proponents – industry and politicians – expect that this storage hub will retrieve fracking from insolvency by supporting plastics production. If the hub indeed saves Appalachian fracking we are in deep trouble both globally and locally. Fracking is currently a principal source of atmospheric methane, an exceptionally powerful greenhouse gas. In West Virginia, this new extreme-extraction method is poisoning billions of gallons of water yearly, destroying aquifers. It is also radioactive in all parts, emits highly toxic air pollution, and is eliminating an increasingly valuable asset, our wild mountain beauty.

Pennsylvania and methane: Why cutting emissions is critical for health – Methane, a greenhouse gas 84 times more potent than carbon dioxide in the near term, heats the planet at an accelerated rate. This warming contributes to the formation of ground-level ozone, or smog, that is harmful to our environment and human health. Research by the Appalachian Mountain Club shows that hikers and outdoor enthusiasts are especially vulnerable because ozone often accumulates at high elevations such as mountain summits, where air pollution transported by wind can build up. Also, hikers breathe in air more deeply, thereby increasing their exposure. Think about it: Who among us hasn’t at some point gotten winded while hiking or biking? What was the air quality like on that day? Of even greater concern is the next generation of hikers who are being exposed to poor air quality. Pennsylvania already has the third highest rate of childhood asthma in the nation, turning an afternoon ramble on the storied Appalachian Trail just west of the Lehigh Valley into a struggle for far too many children. This is not the future they deserve. Again, methane contributes to warming and increased smog. Sites in natural gas drilling regions emit air toxics, ozone precursors, as well as climate-disrupting methane. Air pollution travels, so pollution generated in these regions can easWe believe it’s critical to protect our natural resources and ensure that the outdoors can be enjoyed by all – these spaces are centrally important to the lives of many, especially right now. Key to that, as outlined in our climate and energy policy, is the understanding that natural gas’s benefits are undermined if the industry is not appropriately regulated. Recent studies show that emissions of methane – essentially natural gas – – are consistently being under-reported to the state of Pennsylvania and actually exceed over 1.1 million tons. That’s especially concerning given that the actual emissions and leaks from oil and gas infrastructure carry double the climate impact of all the cars on Pennsylvania’s roads combined.

Survey seeks Columbia Gas disaster victim input – The state wants to hear from residents and businesspeople impacted by the Sept. 13, 2018 gas disaster in the Merrimack Valley. Feedback through an online survey is now needed so state officials can develop and implement energy efficiency programs in Lawrence, Andover and North Andover, which were directly affected by the gas disaster. “We want the residents to drive this bus as much as we can. The decisions will be rooted in the priorities of the communities,” “We really see ourselves as caretakers. It’s not our money. It’s the Merrimack Valley’s money. We want it spent the way folks in the Merrimack Valley want it spent,” Last summer, Columbia Gas, the natural gas provider at the time of the disaster, reached a $56 million agreement with the state for its role in the gas explosions and fires. As a result of the fires and explosions caused by overpressurized pipelines operated by Columbia Gas, Leonel Rondon, 18, of Lawrence, was killed, three firefighters and 19 civilians were hurt, and damages are estimated at $1 billion. About 50,000 people were forced to evacuate and the severity of the damage depended on the age of appliances. Five homes were destroyed and 131 properties damaged, according to findings by the National Transportation Safety Board. The $56 million was earmarked for debt relief for gas bills for thousands of low-income gas customers, as well as to enable clean energy and energy efficient efforts in homes and buildings in the three communities.

Gas utilities seek to scale back engineering rules – – Gas companies are trying to water down proposed regulations that would require certified engineers sign off on construction work. The state Department of Utilities is considering rules to require the utilities to get a review and a stamp from a professional engineer for “complex projects” that pose a risk to public safety. The rules stem from a 2018 law signed by Gov. Charlie Baker in response to the Merrimack Valley gas disaster. But gas companies have complained that the scope of the proposed regulations will make them too costly, and that they are unnecessary. A group of utilities, including National Grid and Eversource, submitted a litany of proposed changes seeking to limit the kinds of projects that would have to be reviewed. “Routine, low-risk, non-complex work, such as the installation of service lines that do not involve two or more tie-ins, bypass of a distribution line to supply service or changes to system operating pressures, do not need a (professional engineer’s) stamp,” the utilities wrote to regulators. “And using resources on those types of simple tasks will be wasteful and costly without achieving any incremental public safety benefit.” Tom Kiley, president and CEO of the Northeast Gas Association, noted that a lack of qualified natural gas engineers could prevent cities and towns from moving ahead with projects, which he argues would jeopardize public safety. “The current pool of qualified engineers will not be sufficient to handle the workload,” he wrote to regulators. “This could lead to work delays and stoppages.” Meanwhile, engineering trade groups point out the new regulations won’t be a panacea in preventing future disasters.

Water utilities, state environmental regulators wary of bill that would relax oil and gas tank oversight –The West Virginia Department of Environmental Protection’s deputy secretary told state lawmakers earlier this month the department did not support a proposed bill that would relax oversight of certain oil and gas tanks located near public water intakes.Scott Mandirola explained to the House Health and Human Resources Committee that efforts to prevent drinking water contamination from oil and gas tanks would not be as effective without the tank oversight that House Bill 2598 would erase.Mandirola said 887 tanks would no longer be regulated under the Aboveground Storage Tank Act as of last month if House Bill 2598 became law, according to Department of Environmental Protection data. The DEP currently must inspect tanks within zones of critical concern at least once every three years; the state defines a zone of critical concern as consisting of a five-hour water-travel time in streams to a water intake.Current law also requires tank operators to submit spill prevention response plans, as well as registration and certified inspection of such tanks.But Mandirola estimated about 38 tanks would be inspected once a year based on current data, a scenario in which all 887 would be inspected about once every 23 years.The numbers don’t add up,” Mandirola said.The Health and Human Resources Committee disagreed.“The DEP through their testimony gave a lot of assumptions on several things,” Delegate Vernon Criss, R-Wood, said.With the full House of Delegates passing the regulatory rollback last week after the Health and Human Resources Committee signed off on the bill, the concerns about future relaxed tank oversight that Criss dismissed as assumptions are deep-seated among not only state environmental and health regulators, but water utilities. “We don’t support that,” said Todd Grinstead, executive director of the West Virginia Rural Water Association, a statewide group of nearly 300 water and wastewater systems. “Obviously, our main concern is protecting the source water for the water treatment plant, and I just think anytime you deregulate a tank of that size in a zone of critical concern, that’s a little bit of a concern for us.” The Morgantown Utility Board also disapproves of the bill. “At Morgantown Utility Board, our mission is the safeguarding of public health,” Chris Dale, the board’s communications director, wrote in an email. “Therefore, we oppose HB 2598 and any bill that loosens regulatory requirements protecting our raw water resources.”

Proposed pipeline extension into North Carolina gains new life in court – A proposed extension of the Mountain Valley Pipeline from Virginia into North Carolina has gained new life in an ongoing court battle. The Roanoke Times reported Thursday that the 4th U.S. Circuit Court of Appeals threw out a decision by North Carolina’s Department of Environmental Quality.The appeals court ruled that the state agency did not properly explain the reasons why it had denied a water quality certification for that portion of the natural gas pipeline. The portion is called MVP Southgate. And it would start at the main pipeline’s terminus in Virginia’s Pittsylvania County and run for 75 miles into North Carolina.The federal appeals court ordered North Carolina regulators to address why certification was denied outright instead of giving it conditional approval. The court also asked the regulators to address inconsistent statements about the project’s impact on bodies of water. The main portion of the pipeline would run for 300 miles in West Virginia and southwest Virginia. North Carolina’s denial was based in large part on uncertainty over whether the mainstem of the pipeline would ever be completed. At the time, the project was lacking three sets of federal permits following legal challenges by legal groups. But Mountain Valley has since regained two of the three permits for its main pipeline. And it says it’s proceeding with plans for the extension.

North Carolina Regulators Fail to Adequately Explain MVP Southgate Denial, Court Rules – North Carolina’s Department of Environmental Quality (DEQ) did not adequately explain its decision to deny a water quality certificate for Mountain Valley Pipeline LLC’s (MVP) Southgate expansion project, a federal appeals court has ruled. The U.S. Court of Appeals for the Fourth Circuit in a ruling handed down late last week granted a petition filed by MVP seeking to vacate the DEQ’s decision last August to deny state certification for the project. MVP’s Southgate project would consist of 75 miles of 16-inch and 24-inch diameter line to extend the original 303-mile, 2 million Dth/d mainline project’s reach into North Carolina. At the time, the DEQ predicated its decision to deny the certification, required under Section 401 of the Clean Water Act, on uncertainty surrounding the mainline project’s completion given multiple legal and regulatory setbacks.However, the Fourth Circuit said the DEQ “failed to explain why it chose to deny certification instead of conditioning certification upon the Mainline Project receiving its permits.” The court ordered the state’s environmental regulator to revisit its decision and explain its rationale.Still, the ruling may provide only limited relief to MVP, which has dealt with adverse decisions from the Fourth Circuit previously. The court appeared to take issue only with the DEQ’s explanation of its decision and not the decision itself, finding that DEQ’s “denial is consistent with the state’s regulations and the Clean Water Act.”Meanwhile, MVP continues to work toward completion of its mainline, recently disclosing a new strategy to obtain waterbody crossing permits needed to wrap up construction on the oft-delayed project.MVP is designed to transport Marcellus and Utica shale gas from West Virginia into Virginia. The Southgate extension would receive gas from MVP in Virginia and transport it to new delivery points in Rockingham and Alamance counties, NC.

Gas pipeline moves to condemn Piedmont properties, but gas might never flow – The company behind a controversial proposed natural-gas pipeline has filed dozens of federal lawsuits against local landowners, even though there are serious doubts it will ever carry gas.“There’s so many ifs with this project that it should not be difficult for a federal judge in Greensboro, North Carolina, to say, ‘What’s the hurry here?’” said Chuck Lollar, an eminent-domain lawyer in Norfolk, Va., representing a number of landowners trying to keep the Mountain Valley Pipeline (MVP) from getting easements across their properties. The MVP Southgate would carry Marcellus and Utica Shale gas from the MVP terminus in Pittsylvania County, Va., to the Dominion Energy distribution system south of Graham. The collaboration of five energy companies behind the project filed more than 35 condemnation suits in the U.S. District Court for the Middle District of North Carolina in January against more than 100 landowners in North Carolina including 38 in Alamance County, according to a letter District 63 state Rep. Ricky Hurtado wrote to the Federal Energy Regulatory Commission last month.Many of those property owners would lose up to 3 acres, according to court filings. Others could lose up to 10 acres, according to Hurtado. Federal law, Lollar said, gives natural gas companies a lot of power to take land through eminent domain once they have failed to get it through negotiation or contract. And for its part, MVP Southgate says it has taken the time and effort to work with landowners. “In November 2018, Mountain Valley initiated negotiations with landowners to obtain the required rights of way,” according to a company email to the Times-News. “To date, Mountain Valley has successfully negotiated easements through mutual agreement for almost 75 percent of the affected parcels along the entire route.”Many of those landowners are fighting that condemnation using some of the same arguments pipeline opponents have brought out since the MVP project started.“(T)here presently exists access to an ample supply and capacity to meet existing and future demands in natural gas in North Carolina and Southern Virginia, and the Extension Pipeline then is not a public necessity,” according to the response filed on behalf of a Rockingham County landowner. Lollar said the rationale for the pipeline is serving the domestic market, but fracking has turned the United States from a net importer to an exporter, and the goal of these pipelines is to export liquefied natural gas not to serve American’s needs.

‘Lipstick on a pig.’ Landowners skewer FERC — Thursday, March 18, 2021 — Landowners in the path of natural gas pipelines slammed the Federal Energy Regulatory Commission yesterday for its handling of their complaints.

Mountain Valley Pipeline’s extension opposed by existing Transco pipeline- There’s new opposition to the Mountain Valley Pipeline, this time from a fellow natural gas pipeline..When Mountain Valley announced a 75-mile extension into North Carolina three years ago, its plan was to lay part of the buried pipeline next to the Transcontinental Pipeline, which has been in service since the 20th century.But in court documents filed Monday, attorneys for that pipeline wrote that “MVP’s proposed location is simply irresponsible.”Also known as Transco, the Oklahoma-based pipeline is fighting an attempt by Mountain Valley to use eminent domain to acquire easements on private property – some of it seized by Transco through the same controversial process years ago.In other words, Mountain Valley is attempting to take by eminent domain land that was taken by eminent domain.To build a second pipeline so close to the first “raises significant safety concerns for Transco and the general public,” according to responses to Mountain Valley’s legal actions filed in federal courts in Danville and Greensboro.Among the concerns cited: Mountain Valley’s extension, called MVP Southgate, could interfere with a cathodic protection system and possibly cause a leak to occur; restrict access needed by Transco to its pipeline; and endanger the older pipeline with heavy equipment and blasting during construction.Transco is asking federal judges in Virginia and North Carolina to deny Mountain Valley’s requests to acquire space in or along its easements.Mountain Valley has also filed eminent domain cases against the private owners of land crossed by Transco’s easements, which were acquired either voluntarily or through eminent domain decades ago.

U.S. natural gas consumption was lower in 2020 in all sectors except electric power – EIA – U.S. natural gas end-use deliveries in 2020 decreased in three out of four consuming sectors relative to 2019, according to the U.S. Energy Information Administration’s (EIA) Natural Gas Monthly. Despite mild winter weather and the economic effects of COVID-19, the second-highest annual amount of natural gas was delivered in the United States to end users in 2020, averaging 75.8 billion cubic feet per day (Bcf/d) for the year. The highest annual amount of natural gas consumption in the United States occurred in 2019, when end-use deliveries reached 77.6 Bcf/d.The electric power sector consumed the most natural gas of any sector – 31.7 Bcf/d in 2020, a 2% increase from the previous year. In 2020, natural gas prices were the lowest they had been in decades. Lower natural gas prices made natural gas more competitive in the electric power sector, especially compared with coal. Natural gas-fired electricity generation has been growing throughout the United States. Natural gas-fired generation replaced much of the lost generation from coal plant retirements in recent years, making natural gas the largest input fuel for power generation nationally. Natural gas accounted for nearly 40% of all power generation in 2020, accounting for more generation than coal and nuclear, the next two largest sources, combined.U.S. industrial consumption of natural gas decreased 2% in 2020. COVID-19-related closures and less demand reduced industrial consumption for much of the year. Industrial natural gas consumption has increased in 8 out of the past 10 years because of growth in dry natural gas production and relatively low natural gas prices.Weather patterns have been the primary drivers of residential and commercial natural gas consumption volumes in the United States. Economic patterns also affect U.S. commercial natural gas consumption. The winter months of 2020 (January – March 2020 and November – December 2020) were milder than the previous two winters in the United States, resulting in less heating demand. Natural gas consumption in the commercial sector, which includes restaurants, hotels, and schools, decreased by 11%.A small amount of end-use deliveries of natural gas go to the U.S. vehicle fuel sector, representing about 0.2% of total deliveries in 2020. In addition, a substantial volume of natural gas is consumed through producing, processing, and distributing natural gas. EIA considers these volumes as a component of total consumption, but they are not included in the end-use delivery sectors that EIA reports.

LNG Gains Prop Up April Natural Gas Futures; Cash Prices Drop – Natural gas futures on Tuesday found momentum as signs of sustained strength in liquefied natural gas (LNG) levels offset forecasts for mild weather and light heating demand. The April Nymex contract settled at $2.562/MMBtu, up 7.8 cents day/day. May gained 7.4 cents to $2.597. On Monday, the prompt month dropped 11.6 cents and fell to its lowest level since early January. Even with Tuesday’s gain, the April contract finished in the green only twice over the past 10 trading sessions. NGI’s Spot Gas National Avg., meanwhile, fell 14.5 cents to $2.410 on Tuesday. Cash prices were led lower by steep drops in the Northeast region. LNG export volumes topped 11 Bcf for the fourth time in five days, hitting 11.58 Bcf on Tuesday, according to NGI estimates. Analysts said Asian demand for U.S. supplies of the super-chilled fuel continue to prove strong, supporting a recovery to near record levels after delivery interruptions caused by the Texas deep freeze in February. “LNG feed gas has been strong,” NatGasWeather said. However, the firm said weather forecasts for the final third of March continued to show warmer temperatures and weakening demand for natural gas to run furnaces – the principal reason futures have struggled to get into positive territory this month. “The overnight data failed to trend any colder and remains quite bearish” from Sunday (March 21) through March 29, NatGasWeather said Tuesday. The data “maintained moderate demand early and late this week” but “exceptionally comfortable” temperatures “for the start of spring, with highs over most of the U.S. March 21-29 reaching the 50s to 80s.”

Weather Worry Weighs Down April Natural Gas Futures Natural gas futures dropped back into the red on Wednesday as traders mulled forecasts for mild spring weather and its dampening effect on demand along with polls that showed expectations for only a modest storage withdrawal. The April Nymex contract declined 3.4 cents day/day and settled at $2.528/MMBtu. May fell 4.2 cents to $2.555. The prompt month had gained 11.6 cents Tuesday, a rare advance in March, though analysts attributed that bounce in part to technically oversold conditions. Robust liquefied natural gas (LNG) levels – above 11 Bcf/d throughout this week, near records – also provided a boost. Still, light domestic demand, the key detriment to futures this month, re-emerged as an overriding concern Wednesday. The prompt finished in the red for the ninth time over the past 11 sessions. Weaker weather demand also kept next-day cash prices in check across much of the country. NGI’s Spot Gas National Avg. ticked up 3.0 cents to $2.440. “The pattern maintains its skew in the warmer direction rather solidly, thanks to warmer than normal conditions primarily from the Midwest to East, with the strongest anomalies coming this weekend into the first half of next week,” Bespoke Weather Services said of forecasts for the rest of this week and next. “This keeps March on pace to be quite warm…Outside of the two cold weeks in February, this warmer state has been very persistent, and we still believe this continues as we move into April,”

ANALYSIS: US natural gas storage volumes decline 11 Bcf as heating season winds down | S&P Global Platts – US natural gas storage volumes in the week ended March 12 decreased by 11 Bcf, to 1.782 Tcf, the US Energy Information Administration reported March 18, as heating season rapidly winds down and Henry Hub futures slide further. The withdrawal was weaker than the 17 Bcf draw expected by an S&P Global Platts’ survey of analysts. It was also less than the 15 Bcf draw reported during the same week last year as well as the five-year average withdrawal of 59 Bcf, according to EIA data. Strong injection activity in the South Central region’s salt dome facilities drove the bearish draw. South Central region salt dome inventories began February right around the five-year average, but after reporting the largest draw in the EIA’s historical data, the salts began to carve out a new five-year minimum. The last two weeks have demonstrated how flexible the salt facilities are, with activity turning to a net injection of 12 Bcf for the week ended March 5, and another 21 Bcf build for the week ended March 12, according to EIA data. The US averaged 3 degrees warmer than normal for the week ended March 12. Total demand dropped more than 6 Bcf/d, with residential and commercial falling by almost 5 Bcf/d, according to S&P Global Platts Analytics. Weaker weather-driven power loads and very strong wind output pushed gas burns down nearly 1.6 Bcf/d week over week too. Storage volumes now stand 253 Bcf, or 12.4%, less than the year-ago level of 2.035 Tcf and 93 Bcf, or 5%, less than the five-year average of 1.875 Tcf. The NYMEX Henry Hub April contract slipped 4 cents to $2.48/MMBtu in trading following the release of the weekly storage report, which represented a decline of 15 cents from the week prior. Platts Analytics’ supply and demand model currently forecasts a 32 Bcf withdrawal for the week ending March 19, which would measure 19 Bcf weaker than the five-year average, as the heating season enters its final weeks. Balances have tightened, with colder weather and stronger exports increasing the call on storage. Total demand has increased nearly 1.5 Bcf/d when compared to the prior week. Much of the gains were observed in LNG feedgas, which grew by 600 MMcf/d, as strong inflows into all the US facilities helped to push the weekly average north of 11 Bcf/d. An early forecast for the week ending March 26 points to an 8 Bcf pull. The first net addition to storage typically occurs in the week ending April 2. Ove the past five years, the injection season began with 1.8 Tcf in underground storage. If the current forecast for the next two storage weeks hold, the heating season will end with 1.742 Tcf in storage. The lingering impact of refinery and petrochemical outages along the US Gulf Coast from the February cold blast have delayed the recovery of industrial gas demand, contributing to a lower end-of-winter stock draw, with March storage likely to finish about 200 Bcf above the Platts Analytics’ base case forecast of 1.5 Tcf. These bearish headwinds have pushed the Henry Hub summer strip down to $2.60/MMBtu from $3.00/MMBtu last month, with risk prices could fall below $2.50/MMBtu.

Absent Expectations for Heating Demand, April Natural Gas Futures Fall – Natural Gas Intelligence – Natural gas futures fell further on Thursday – the 10th decline in the last 12 trading sessions – after a bearish storage report and forecasts that showed continued expectations for moderating heating demand. The April Nymex contract settled at $2.481/MMBtu, down 4.7 cents day/day. May lost 4.4 cents to $2.511. Diminished near-term weather demand also dragged cash prices lower. NGI’s Spot Gas National Avg. shed 1.0 cent to $2.430. Both the domestic and European weather models “held moderate demand late this week, then very light demand late this weekend through next week,” NatGasWeather said Thursday. For the final week of March, the firm added, “most of the U.S. will be mild to warm with highs of 40s to 60s” over the north “and 60s to 80s across the southern U.S. for light to very light national demand.” A third straight bearish storage report from the U.S. Energy Information Administration (EIA) punctuated concerns about waning demand during spring. The agency on Thursday reported a withdrawal of 11 Bcf from natural gas storage for the week ended March 12 – shy of market expectations and well off the five-year average withdrawal of 59 Bcf for the comparable week. “It was much warmer than normal over the northern and central U.S., while slightly cool over the West Coast and Southeast” during the report period, NatGasWeather said. Polls ahead of the report estimated a withdrawal in the range of 16-22 Bcf for the week. A Bloomberg survey found a median of 18 Bcf, while the median forecast in a Reuters poll landed at a pull of 16 Bcf. The Wall Street Journal’s weekly survey produced a 22 Bcf average decrease. NGI estimated a 14 Bcf pull for the latest week. The latest report marked the third-consecutive result that was bearish relative to expectations.

April Natural Gas Futures Forge Ahead as LNG Volumes Reach Record Levels, Economy Musters Momentum – Natural gas futures on Friday edged higher as robust liquefied natural gas (LNG) levels and a brightening economic picture offset festering worry about weak weather-driven demand heading into the spring shoulder season. The April Nymex contract climbed 5.4 cents day/day and settled at $2.535/MMBtu. May rose in tandem, gaining 5.5 cents to $2.566. It marked the second time during the trading week the prompt month advanced, but only the third gain over the past 13 sessions as traders have fixated on waning heating demand and modest storage pulls. Forecasts for the week ahead called for generally mild conditions and modest demand for natural gas. The outlook remains “in a generally lower than normal demand state, heading into a time of year where demand is of course lower anyway,” Bespoke Weather Services said. As weather demand faded, NGI’s Spot Gas National Avg. fell 16.0 cents to $2.270. Asian demand for U.S. exports was strong throughout the winter and now, heading into spring, European demand is mounting as storage levels on the continent dwindled substantially in recent months. “Since Winter Storm Uri resulted in reduced outages and gas conservation for residential use in Texas, LNG demand has risen 10.0 Bcf/d in the past month,” Weissman said. “Further demand gains are possible – perhaps even eclipsing 12.0 Bcf/d if all terminals achieve maximum demonstrated demand levels at the same time. Gains in LNG feed gas and Gulf Coast industrial demand for natural gas this week may help offset declines in weather-driven demand, allowing small withdrawals to continue near term.”

US LNG feedgas demand sets another record as total approaches 12 Bcf/d | S&P Global Platts – US LNG feegas demand hit a new record March 19 as total deliveries approach 12 Bcf/d, S&P Global Platts Analytics data show. Capacity could rise come fall when Venture Global LNG’s Calcasieu Pass terminal in Louisiana – the seventh major US liquefaction facility – may be ready to ship its first cargo. Platts Analytics expects full dispatch economics out of the US to continue in the months ahead, due in part to supportive summer prices on the back of a tighter than expected winter, with greater room available in European storage for injections. Shipping costs are significantly cheaper than the start of the year, outweighing short-term swings in prices and demand. The 11.8 Bcf/d in total gas deliveries to existing US LNG export terminals topped the previous record of 11.65 Bcf/d set during the morning cycle March 17. Cheniere Energy’s two terminals – Sabine Pass in Louisiana and Corpus Christi Liquefaction in Texas – account for more than half of the total demand. The Platts JKM for May was assessed 14.4 cents/MMBtu lower at $6.550/MMBtu on March 19. JKM is the benchmark for spot-traded deliveries of LNG to Northeast Asia. While prices were lower day-on-day, netbacks remain high enough to incentivize robust shipments from the US. Asia Pacific freight was assessed at $30,000/day on March 18, compared with $45,000/day a month ago, and $165,000/day two months back, according to Platts data. Venture Global recently said in a US regulatory filing that it could ship its first cargo in late 2021, a year ahead of schedule. It also said the 23.4-mile TransCameron pipeline, which will connect to interstate pipelines and allow feedgas to reach the terminal, will begin service “very soon.” The developments would be bullish for US LNG feedgas demand. Venture Global provided the update in a filing to the Federal Energy Regulatory Commission requesting a waiver of certain rules on buy and sell transactions that would conceivably allow it to market upstream gas producers’ output directly to foreign buyers. Cheniere secured such agreements with two shale producers.

Asia became the main export destination for growing U.S. LNG exports in 2020 — U.S. exports of liquefied natural gas (LNG) continued to grow in 2020, averaging 6.5 billion cubic feet per day (Bcf/d) on an annual basis, according to the U.S. Energy Information Administration’s Natural Gas Monthly. LNG exports increased 1.5 Bcf/d, or 31%, compared with 2019 levels. U.S. LNG exports were relatively high from January through May. In the summer months, they declined to record lows following record declines in international natural gas and LNG prices. By October, U.S. LNG exports started to increase again, despite brief interruptions caused by Hurricanes Laura and Delta. In November and December 2020, U.S. LNG exports reached all-time highs. U.S. LNG was exported to 38 countries, a record number, and Asia overtook Europe to become the main export destination in 2020.LNG exports to Asia increased 67% in 2020 compared with 2019, accounting for almost half, or 3.1 Bcf/d, of all U.S. LNG exports. U.S. LNG exports to China averaged 0.6 Bcf/d in 2020 – after China lowered tariffs on imports of LNG from the United States from 25% to 10% – the largest increase by country. In 2019, when tariffs were at 25%, only two U.S. LNG cargoes were shipped to China. India increased imports of U.S. LNG by an average of 0.1 Bcf/d, especially in the spring and summer when LNG prices were at record lows. U.S. LNG exports to Japan grew by 0.2 Bcf/d, primarily in the fourth quarter of 2020 because of seasonal winter demand.U.S. LNG exports to Europe averaged 2.5 Bcf/d, an increase of 0.6 Bcf/d compared with 2019. Europe had been themain destination for U.S. LNG exports in 2019, accounting for 39% of U.S. LNG exports. In 2020, U.S. LNG exports to Turkey increased by 0.3 Bcf/d and to the United Kingdom, Spain, Greece, and Lithuania by 0.1 Bcf/d each. U.S. LNG exports to several countries in Latin America (Colombia, Chile, Argentina, Mexico) and the Middle East (Jordan and the United Arab Emirates) declined by a combined 0.5 Bcf/d in 2020 compared with 2019. U.S. LNG exports to Mexico declined by 0.3 Bcf/d because of COVID-19 mitigation efforts that reduced demand for natural gas. Growing U.S. exports by pipeline to Mexico also displaced more expensive LNG imports. In contrast, Brazil more than doubled its U.S. LNG imports – an average annual increase of 0.2 Bcf/d – as a result of drought conditions that limited hydroelectric power generation and increased demand for natural gas-fired power generation.

Wild Thing – Understanding the Volatile Relationship Between LNG and Global Gas Markets – To fully grasp just how much the U.S. LNG export market has changed in the past year, we have to go back about one year to March 2020, before the pandemic effects had set in. It may be hard to imagine those pre-COVID days now, so allow us to set the stage. The U.S. had just finished adding 25 MMtpa (3.34 Bcf/d) of liquefaction and export capacity over the course of 2019 and early 2020. Feedgas deliveries and LNG exports during this period were predictable for the most part, ramping up as the liquefaction trains were completed and then consistently operating near full utilization of capacity as the units were brought online and commercial contracts kicked in. So, in March of last year, feedgas demand was near what were then record highs, with little indication of volatility outside of routine maintenance events. It seemed like all LNG could do was grow – which was a story LNG developers were happy to promote.Then COVID-19 hit, decimating global demand, sending global gas prices to all-time lows and turning the economics for exporting U.S. LNG upside down for the first time since early 2016 when the first train at Cheniere Energy’s Sabine Pass terminal began exporting. We discussed the unraveling of the U.S. LNG export market that followed in a number of blogs last spring and summer, including Break It to Me Gently, Undone and LNG Interruption. The upshot is that offtakers of U.S. LNG began cancelling cargoes and, by summer, feedgas demand plummeted (dashed blue oval in Figure 1). Feedgas deliveries in July and August averaged just 3.66 Bcf/d, or about 40% of where they were in the first quarter of 2020 and just 42% of capacity at the time. Cancellations lessened by late summer as pandemic lockdowns eased, first in Asia and later Europe, and global prices improved. But just as U.S. LNG exports were poised to begin a recovery, a record-setting hurricane season wreaked havoc on the operations of Gulf Coast LNG terminals, particularly in Louisiana (see You Spin Me Round). Throughout the fall, nearly every U.S. LNG terminal faced some kind of outage, port closure, or shut-in for maintenance.

ENERGY POLICY: FERC makes major shift on pipeline CO2 emissions — Friday, March 19, 2021 — The Federal Energy Regulatory Commission assessed a natural gas pipeline project’s contribution to climate change for the first time yesterday as it shifted policy on renewables.Recent completions of natural gas pipeline projects increase transportation capacity – EIA -From November 2020 through January 2021, approximately 4.4 billion cubic feet per day (Bcf/d) of new natural gas pipeline capacity entered service, according to the U.S. Energy Information Administration’s (EIA) Natural Gas Pipeline Project Tracker. Four projects have recently been completed and entered service:

• Saginaw Trail Pipeline – Consumer Energy’s $610 million intrastate Saginaw Trail Pipeline entered service in late November 2020. The project replaced and expanded natural gas pipelines and infrastructure in Saginaw, Genesse, and Oakland Counties in Michigan, increasing natural gas capacity by 0.2 Bcf/d.
• Buckeye Xpress Project – Columbia Gas Transmission’s (CGT) 0.3 Bcf/d Buckeye Xpress Project began operations in December 2020. The $709 million project involved infrastructure improvements and replaced 66 miles of existing natural gas pipeline with more reliable 36-inch pipe in Ohio and West Virginia. The project increases transportation capacity out of the Appalachia Basin into CGT’s interconnection in Leach, Kentucky, and the TCO Pool in West Virginia.
• Permian Highway Pipeline – Kinder Morgan’s Permian Highway Pipeline (PHP) entered service in early January. The 430-mile pipeline brings 2.1 Bcf/d of additional natural gas capacity from the Waha Hub, located in West Texas near production activities in the Permian Basin, to Katy, Texas, near the Gulf Coast. It has additional connections to Mexico.
• Agua Blanca Expansion Project – Whitewater/MPLX’s Agua Blanca Expansion Project, which entered service in late January, connects to nearly 20 natural gas processing sites in the Delaware Basin. It transports an additional 1.8 Bcf/d of natural gas to the Waha Hub in West Texas. The project will also connect with the Whistler Pipeline, which is scheduled to be completed in the third quarter of 2021 and is expected to move 2.0 Bcf/d of natural gas from the Permian Basin to the Texas Gulf Coast.

In December, Tellurian withdrew its application to build the Permian Global Access Pipeline in Texas and Louisiana, effectively canceling the project. The proposed 2.0 Bcf/d project would have transported natural gas from the Permian Basin to a proposed liquefied natural gas (LNG) facility in Gillis, Louisiana. EIA’s Natural Gas Pipeline Project Tracker and the Liquids Pipeline Projects Database provide information about important natural gas and petroleum infrastructure in the United States. EIA updates its Natural Gas Pipeline Project Tracker quarterly, based on the best available information from pipeline company websites, trade press reports, and government documents. These data reflect reported plans. These resources are not forecasts and do not reflect EIA’s assumptions on the likelihood or timing of project completion.

Michigan GOP reps ask Biden to support Line 5 pipeline – – Michigan Republicans in Congress are urging President Joe Biden to oppose the closure of Line 5, warning of the potential consequences of shutting down the four-mile-long dual pipeline in the Straits of Mackinac. They recently wrote to Biden after he revoked the permit for the Keystone XL pipeline in his first week in office, citing “deep concerns” about the pressure to also shut down Enbridge Energy’s Line 5 over environmental concerns. Michigan Gov. Gretchen Whitmer has said she has revoked Enbridge’s easement for Line 5 in preparation for a May shutdown, but the issue will be decided in court.The dual pipeline that runs under the Straits of Mackinac is part of a longer line that transports oil and natural gas liquids from Canada through Wisconsin and Michigan into Sarnia, Ontario. The lawmakers in their letter said closing Line 5 would cost thousands of union jobs, close refineries and reduce energy supplies, including 15% of northwest’s Ohio’s fuel supply and 43% of southeastern Michigan’s supply.Line 5 also supplies 65% of the propane used in Northern Michigan and Upper Peninsula, the representatives said.

Al Gore, Memphis activists rally against Byhalia Connection pipeline -Former Vice President Al Gore voiced his opposition to the Byhalia Connection and put Memphis elected officials on notice during a rally against the pipeline Sunday afternoon.A few hundred people were on hand for the event at Alonzo Weaver Park in South Memphis, which featured speeches from Gore, U.S. Rep. Steve Cohen, community activists and landowners that would be affected by the pipeline’s path.The proposed crude oil pipeline, a joint venture from Plains All American and Valero Energy, would span 49 miles. On its current route, it would be constructed through predominately Black communities in South Memphis and over a Memphis Light, Gas & Water wellfield drawing water from the Memphis Sands aquifer. Gore, an environmental activist and former member of Congress representing Tennessee, called the pipeline “a reckless, racist rip-off” in his speech. “They’re putting the risk on Memphis and they’ve taken the reward for themselves,” he said. “That is why it is a rip-off.”The pipeline would connect two existing pipelines, including the Diamond Pipeline that supplies the Valero Memphis Refinery with crude oil, which Plains says would make U.S. crude oil transportation more efficient. Construction is planned for later this year, with the pipeline coming into service nine months after.In a letter addressed to Memphis residents Saturday, Plains Vice President Roy Lamoreaux said the company has secured the necessary environmental permits from federal, state and local agencies to start construction. Cohen asked President Joe Biden in February to rescind a pipeline permit granted by the U.S. Army Corps of Engineers.The permit can be rejected or modified if the Biden administration asks the Corps of Engineers to do so, one of “several ways to stop this,” Gore said.Gore also pointed out two pipeline-related actions local officials could take this week. A Memphis City Council will consider an ordinance against the project Tuesday. The ordinance is sponsored by Councilman Edmund Ford, Sr. and Councilman Jeff Warren. A Shelby County Commission decision to sell county land for the pipeline has been delayed until Wednesday.“They can’t use eminent domain against Shelby County,” Gore said. “They need Shelby County to say ‘Yes, sir’ to the pipeline company.”Gore said if officials side with pipeline companies, voters can let their voices be heard at the next election.

Oil drilling platform construction begins in Apalachicola River basin -A Texas-based petroleum company has begun construction of two exploratory drilling platforms on land it’s leased in the Apalachicola River floodplain in rural Calhoun County, an area critical to the state’s water supply.The state Department of Environmental Protection (DEP) in December 2019 granted Cholla Petroleum of Dallas six permits to dig deep wells into the upper Floridan Aquifer, the principal source of drinking water for much of northern and central Florida.”Apalachicola Riverkeeper remains strongly opposed to these exploratory oil and gas wells as they pose significant ecological along with economic risk to the region,” said Georgia Ackerman, the group’s executive director. “We will continue to monitor the permit activities and address concerns with residents, local and state officials.” While environmental groups have asked the DEP to deny the permits, the Calhoun County Commission has expressed support for the project as went through the approval pipeline. Residents of Blountstown and other areas, however, have voiced concern over the project’s impact on the environment and the local economy. The exploratory drilling would punch into the Floridan aquifer, which environmentalists said could put the water supply for the Panhandle at risk of contamination. The permits do not authorize hydraulic fracking or commercial production, DEP spokeswoman Dee Ann Miller has said. A March 5 letter from Cholla Petroleum Vice President Mitch Myers to the DEP announced construction would begin on pads 1 and 3. The pads are within the Apalachicola River basin, close to flowing river waters during normal high flows, an article in the Apalachicola Riverkeeper blog said. “At those times, 95% of the Apalachicola River floodplain is connected aquatic habitat,” the organization said. “Moreover, during major flood events, the drilling pads would be surrounded by flowing water.”

Louisiana oil and gas industry in danger after President Biden cancels 80-million-acre oil lease sale – Louisiana officials say the state’s oil and gas industry is in danger. This comes after President Joe Biden cancelled a March oil lease sale in the Gulf of Mexico. Nearly 80 million acres of available leases would have been sold this week. The damage to Louisiana’s oil and gas companies started in January when President Biden signed an executive order banning all new oil and gas leases on public land and waters for 60 days. “Right now I think we’re still pretty much in the holding pattern. It was a 60-day ban, and he was going through relook at it, the president,” Louisiana Oil and Gas Association President Mike Moncla said. Moncla says their worst fear was that the president would extend that ban past 60 days. “Since that time, Governor Edwards has sent him a great letter letting him know exactly what that would mean to Louisiana, all of the economic and finances that come from our offshore work,” he said. He says as the 60-day ban comes closer to its end, President Biden isn’t easing restrictions. He’s enforcing new ones, cancelling the 80-million-acre Gulf of Mexico oil lease sale that was scheduled for March 17 in New Orleans. “It would kill our state. It would kill workers,” Moncla added. “It would kill jobs, and it would be a terrible thing.” Moncla says all they can do now is wait. “We’re hoping that Governor Edwards’ letter may have talked some sense into the president and that he won’t extend that 60 days,” he told News Ten. Moncla says the Gulf of Mexico supports 250,000 jobs between Louisaiana, Texas, and Mississippi and 98,000 Louisiana jobs offshore.

The future of Big Oil flaring in the Permian Basin and the climate challenge – When a raging snowstorm and frigid temperatures hit Texas last month, oil and gas behemoths responsible for producing and processing the lion share of the nation’s reserves, including Exxon, Occidental and Marathon Petroleum, shut down production at oil wells and refineries across the state. For many oil producers in the Permian Basin of West Texas and New Mexico, the shutdown put upstream and downstream operations in a squeeze. Downstream, multiple refining operations flared during shutdowns, releasing air pollutants from processing units. Upstream, as oil drilling came back online, there was risk of needing to flare or halt oil production in the field until the broader energy market, including refining and utility generation, stabilized. Indeed, satellite imagery showed increased flaring at oil and gas production sites in the Permian Basin did take place, according to the Environmental Defense Fund. But at Occidental, a choice was made to shut down some operations. “There were a couple of plants that had difficulty coming back online,” Occidental’s CEO Vicki Hollub said during a recent CNBC Evolve event focused on energy innovation. “We could have put our production back online and just flared the gas. We chose not to do that. We left the production shut down because we didn’t want to flare.” The decisions made during the Texas power crisis are part of a broader debate with the oil and gas industry over flaring, the process of releasing greenhouse gas emissions through burning, which has long been a controversial topic for environmental advocates and climate policy experts. The practice, which is commonly used by oil and gas companies to relieve the pressure that builds up during oil production, is responsible for releasing CO2 and methane into the atmosphere. The flaring issue is a global one. According to the World Bank Group, global gas flares burn approximately 140 billion cubic meters of natural gas every year, emitting more than 300 million tons of CO2. Hundreds of companies, governments and oil corporations around the world have signed onto the organization’s Zero Routine Flaring by 2030 Initiative, which aims to eliminate all routine flaring within the next decade. While flaring is often used in cases where there’s safety concerns or maintenance issues, routine flaring means the flaring of gas associated with oil production. Zubin Bamji, program manager of the World Bank’s Global Gas Flaring Reduction Partnership, said reducing gas flaring is attainable for many of these companies and is a “low-hanging fruit” among other methods to reduce emissions. Some experts say U.S. companies, specifically, need a more ambitious goal toward stopping routine flaring. The World Bank agreement focuses predominantly on reducing emissions in countries lacking the regulatory capacity and the infrastructure, but some experts say U.S. companies can accomplish the feat by 2025.

States looking to decarbonize may need to weigh their gas’s origin – study | S&P Global Market Intelligence – As U.S. states look to decarbonize, where they get their natural gas may be an important part of their emissions profiles, according to a recent study. Calculating the upstream greenhouse gas intensity of each state’s gas supplies, researchers at Georgia Tech’s School of Civil and Environmental Engineering found that gas consumed in 2018 in the Lower 48 had methane emissions profiles that ranged from 0.9% to 3.6% of the total gas withdrawn that supplied states’ consumption.”It really does make a difference where your natural gas is coming from and what that production leak rate is from your basin,” said Diana Burns, the study’s lead author who is pursuing a master’s degree in environmental engineering at Georgia Tech. “It can be high enough that it makes a big impact on greenhouse gas emissions.”Kansas, Arizona and New Mexico consumed natural gas that emitted over three times more methane during production than most Northeast states in 2018, the study found. Methane, the key component of natural gas, has a shorter atmospheric life than carbon dioxide but has a much stronger warming effect. As a result, researchers and environmentalists have pointed to methane emission reductions, particularly from the oil and gas industry, as an opportunity to help mitigate climate change in the near-term.As U.S. states look to decarbonize, where they get their natural gas may be an important part of their emissions profiles, according to a recent study.Calculating the upstream greenhouse gas intensity of each state’s gas supplies, researchers at Georgia Tech’s School of Civil and Environmental Engineering found that gas consumed in 2018 in the Lower 48 had methane emissions profiles that ranged from 0.9% to 3.6% of the total gas withdrawn that supplied states’ consumption.”It really does make a difference where your natural gas is coming from and what that production leak rate is from your basin,” said Diana Burns, the study’s lead author who is pursuing a master’s degree in environmental engineering at Georgia Tech. “It can be high enough that it makes a big impact on greenhouse gas emissions.”Kansas, Arizona and New Mexico consumed natural gas that emitted over three times more methane during production than most Northeast states in 2018, the study found. Methane, the key component of natural gas, has a shorter atmospheric life than carbon dioxide but has a much stronger warming effect. As a result, researchers and environmentalists have pointed to methane emission reductions, particularly from the oil and gas industry, as an opportunity to help mitigate climate change in the near-term.

Gasoline Demand Has Peaked, Global Forecaster Says – WSJ – The world’s thirst for gasoline isn’t likely to return to pre-pandemic levels, the International Energy Agency forecast, calling a peak for the fuel that has powered personal transportation for more than a century. The Paris-based energy watchdog, in its closely followed five-year forecast, said an accelerating global shift toward electric vehicles, along with increasing fuel efficiency among gasoline-powered fleets, will more than outweigh demand growth from developing countries. The forecast comes as auto makers have pivoted recently to boost their EV fleets, after years of industry skepticism about whether car buyers would ever embrace fully electric models. General Motors Co. said it would stop selling gas-powered vehicles by 2035. Volvo Cars of Sweden has said it would be all-electric by 2030. The shift toward electric vehicles has been driven by government regulation, hefty incentives in developed countries and broader consumer acceptance of the technology thanks in part to popular models like those sold by Tesla Inc. EVs still make up a small proportion of the world’s overall fleet, and auto makers say they expect to see growing demand for gas-burning internal combustion engines, particularly in the developing world, for years to come. The coronavirus pandemic has upended global fuel consumption, raising questions about whether it will change the world’s energy mix more generally in the years ahead. Energy watchers have long debated the timing of “peak oil,” a point at which demand for crude will start to wane. Amid the demand-crushing pandemic that started last year, some forecasters, including those at the Organization of the Petroleum Exporting Countries, have said that day might have already dawned in the developed world. The IEA said Wednesday that it foresees global crude demand recovering, reaching as much as 104 million barrels a day by 2026, up about 4% from 2019 levels, thanks to the developing world. Economic powerhouses such as China, India and other Asian countries would account for 90% of the net increase in oil demand over the coming five years, the agency said. But for the first time, the agency said it no longer forecasts a complete rebound in demand for gasoline – the product that for years underpinned the world’s thirst for crude. “We do not think gasoline consumption will come back to 2019 levels again,” said IEA Executive Director Fatih Birol. Global jet fuel demand, meanwhile, would fully return but at a slow pace and not before 2024, the agency said. U.S. air travel has been risingamid stabilizing or falling Covid-19 cases in many parts of the country and an accelerated vaccination drive. The Transportation Security Administration, which tracks how many U.S. travelers pass through airport security checkpoints, recorded 1.4 million passengers on Friday. That marked a one-year high but still less than half comparable numbers in 2019.

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