Oil, Gas, And Fracking News Reads: 13September 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 12 September 2020. Part 2 is available here.

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

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US fields the lowest percentage of horizontal rigs and the highest percentage of vertical rigs in 3 years; distillates’ output at a 3 year low

US oil prices fell for a second straight week this week after the Saudis & Emirates marked down their prices on oil exports to Asia and domestic crude supplies increased…after falling more than 7% to $39.77 a barrel in the first drop in five weeks on fears of a slowing recovery last week, the contract price of US light sweet crude for October delivery opened lower in New York trading on Tuesday and quickly tanked, reflecting a drop of more than 1.5% in overseas markets Monday after Saudi Arabia had made the deepest price cuts for crude supplies to Asia in five months over the holiday weekend…Tuesday’s oil price continued lower to settle down $3.01, or 7.6%, at $36.76 a barrel, the lowest price since June, as equities also sold off amid growing demand concerns as Covid-19 continued to spread worldwide…oil prices recovered part of that loss Wednesday, rising $1.29, or 3.5%, to settle at $38.05 a barrel as the flurry of Tuesday’s panic-stricken trading was absorbed and the market rebalanced, leading to a rebound…but the rebound was short-lived as oil prices opened lower Thursday after the API had reported an increase in US oil supplies and then continued falling when that surprise increase was confirmed by the EIA to settle down at 75 cents as $37.30 a barrel, as some traders interpreted those rising oil supplies as a sign of falling demand…October oil then traded in a narrow range on Friday and finished 3 cents higher at $37.33 a barrel, but still posted its second straight weekly decline, down 6.1% from last Friday’s close, as crude stockpiles rose around the world and fuel demand failed to rebound to pre-coronavirus levels…

Natural gas prices also finished lower for a second straight week on an early cold weather outbreak and rising gas supplies…after falling 2.6% to $2.588 per mmBTU last week on cooler temperatures and reduced demand, the contract price of natural gas for October delivery opened lower on Tuesday and tumbled along with oil prices on Covid19 related demand fears, finishing down 18.8 cents or 7% at $2.40 per mmBTU on an increase in gas output and forecasts for cooler weather and lower demand in late September, despite a post-Laura rebound in LNG exports and record pipeline exports to Mexico…with the same dynamic remaining in play, natural gas prices steadied and closed six-tenths of a cent higher on Wednesday, but then fell 8.3 cents to a four week low of $2.323 per mmBTU on Thursday on forecasts for cooler weather and less air conditioning demand next week than had been expected, following an EIA report on gas supplies showing that storage was filling quickly as cooler temperatures swept over swaths of the Lower 48….with unseasonable cold in place in the the mountains and plains, natural gas prices fell another 5.4 cents to a fresh four week low of $2.269 per mmBTU on Friday, thus ending the week about 12% lower, in their biggest weekly decline since March…

The natural gas storage report from the EIA for the week ending September 4th indicated that the quantity of natural gas held in underground storage in the US increased by 70 billion cubic feet to 3,525 billion cubic feet by the end of the week, which left our gas supplies 528 billion cubic feet, or 17.6% greater than the 2,997 billion cubic feet that were in storage on September 4th of last year, and 409 billion cubic feet, or 13.1% above the five-year average of 3,116 billion cubic feet of natural gas that have been in storage as of the 4th of September in recent years….the 70 billion cubic feet that were added to US natural gas storage this week were more than the forecast of a 64 billion cubic foot increase from an S&P Global Platts” survey of analysts, but it was still less than the 80 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, while it was in line with the average of 68 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years..

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending September 4th showed that because our oil production and our oil imports partially recovered from hurricane Laura while our refinery throughput did not, we had surplus oil to add to our stored supplies for the first time in seven weeks and for the 6th time in the past fourteen weeks…our imports of crude oil rose by an average of 523,000 barrels per day to an average of 5,423,000 barrels per day, after falling by an average of 1,016,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 58,000 barrels per day to an average of 2,944,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,479,000 barrels of per day during the week ending September 4th, 581,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly 300,000 barrels per day higher at 10,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 12,479,000 barrels per day during this reporting week…

US oil refineries reported they were processing 12,779,000 barrels of crude per day during the week ending September 4th, 1,089,000 fewer barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 247,000 barrels of oil per day were being added to the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 547,000 barrels per day less than what was added to storage plus what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+547,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must be an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…but since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry… (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 5,492,000 barrels per day last week, which was 18.1% less than the 6,6694,000 barrel per day average that we were importing over the same four-week period last year….the rounded 247,000 barrel per day net addition to our total crude inventories was as 290,000 barrels per day were being added to our commercially available stocks of crude oil while 44,000 barrels per day were being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is also being leased for commercial use, so by rights the recent SPR additions and withdrawals should be included in our commercial supplies….this week’s crude oil production was reported to be 300,000 barrels per day higher at 10.000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states rose by 300,000 barrels per day to 9,500,000 barrels per day, while Alaska’s oil production fell by 5,000 barrrels per day to 459,000 barrels per day but still added 500,000 barrels per day to the rounded national total….last year’s US crude oil production for the week ending September 6th was rounded to 12,400,000 barrels per day, so this reporting week’s rounded oil production figure was 19.4% below that of a year ago, yet still 18.6% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 71.8% of their capacity while using 12,779,000 barrels of crude per day during the week ending September 4th, down from 76.7% of capacity during the prior week, and excluding the 2005 and 2008 hurricane-related refinery interruptions, one of the lowest refinery utilization rates of the last thirty years…hence, the 12,779,000 barrels per day of oil that were refined this week were 27.0% fewer barrels than the 17,495,000 barrels of crude that were being processed daily during the week ending September 6th of last year, when US refineries were operating at 95.1% of capacity….

With the big drop in the amount of oil being refined, gasoline output from our refineries was also much lower, decreasing by 604,000 barrels per day to 8,930,000 barrels per day during the week ending September 4th, after our refineries’ gasoline output had increased by 16,000 barrels per day over the prior week…and since our gasoline production is still recovering from a multi-year low in the wake of this Spring’s covid lockdown, this week’s gasoline output was 13.8% less than the 10,360,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 381,000 barrels per day to a three year low of 4,398,000 barrels per day, after our distillates output had decreased by 343,000 barrels per day over the prior week…and after this week’s big decrease in distillates output, our distillates’ production was 17.7% less than the 5,341,000 barrels of distillates per day that were being produced during the week ending September 6th, 2019….

Along with the big decrease in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 8th time in 10 weeks and for the 23rd time in 32 weeks, falling by 2,954,000 barrels to 231,905,000 barrels during the week ending September 4th, after our gasoline supplies had decreased by 4,320,000 barrels over the prior week…our gasoline supplies decreased by less this week even with the drop in production because the amount of gasoline supplied to US markets decreased by 396,000 barrels per day to 8,390,000 barrels per day, while our imports of gasoline fell by 3,000 barrels per day to 574,000 barrels per day and while our exports of gasoline rose by 140,000 barrels per day to 709,000 barrels per day….but even after the large gasoline inventory drawdowns of recent weeks, our gasoline supplies were still 1.3% higher than last September 6th’s gasoline inventories of 228,904,000 barrels, and roughly 3% above the five year average of our gasoline supplies for this time of the year…

Meanwhile, with the big drop in our distillates production, our supplies of distillate fuels decreased for the sixth time in 23 weeks and for the 27th time in 48 weeks, falling by 1,675,000 barrels to 177,195,000 barrels during the week ending September 4th, after our distillates supplies had also decreased by 1,675,000 barrels during the prior week….our distillates supplies fell again this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 205,000 barrels per day to 3,713,000 barrels per day, and even as our exports of distillates fell by 182,000 barrels per day to 1,084,000 barrels per day, while our imports of distillates fell by 6,000 barrels per day to 160,000 barrels per day…but even after this week’s inventory decrease, our distillate supplies at the end of the week were still 29.1% above the 136,226,000 barrels of distillates that we had in storage on September 6th, 2019, and about 20% above the five year average of distillates stocks for this time of the year…

Finally, with the rebound in our oilfiled production and the increase in our oil imports, our commercial supplies of crude oil in storage rose for the 23rd time in thirty-four weeks and for the 37th time in the past year, increasing by 2,033,000 barrels, from 498,401,000 barrels on August 28th to 500,434,000 barrels on September 4th…after that increase, our commercial crude oil inventories were still around 14% above the five-year average of crude oil supplies for this time of year, and almost 54% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the first weekend of September, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories have generally been rising over the past two years, except for during the past two summers, after generally falling over the year and a half prior to September of 2018, our crude oil supplies as of September 4th were 20.3% above the 416,068,000 barrels of oil we had in commercial storage on September 6th of 2019, 26.3% more than the 396,194,000 barrels of oil that we had in storage on September 7th of 2018, and 8.2% above the 462,353,000 barrels of oil we had in commercial storage on September 1st of 2017…

This Week’s Rig Count

The US rig count fell for the first time in four weeks during the week ending September 11th, and it is now down by 68.1% over the recent 27 week drilling pullback….Baker Hughes reported that the total count of rotary rigs running in the US fell by 2 to 254 rigs this past week, which was also down by 632 rigs from the 886 rigs that were in use as of the September 13th report of 2019…..that was also 150 fewer rigs than the all time low prior to this year, and 1,675 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….

The number of rigs drilling for oil decreased by 1 rig to 180 oil rigs this week, after increasing by 1 oil rig the prior week, leaving us with 553 fewer oil rigs than were running a year ago, and less than a eighth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations also decreased by one to 71 natural gas rigs, which was also down by 82 natural gas rigs from the 153 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico…a year ago, there were no such “miscellaneous” rigs deployed…

The Gulf of Mexico rig count remained at 15 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and three drilling for oil offshore from Texas…that was 10 fewer Gulf rigs than the 25 rigs drilling in the Gulf a year ago, when all 25 Gulf rigs were drilling offshore from Louisiana…while there are no rigs operating off of other US shores at this time, a year ago there was also a rig deployed offshore from Alaska, so this week’s national offshore count is down by 11 from the national offshore rig count of 26 a year ago…also note that in addition to those rigs offshore, a rig continues to drill through an inland body of water in St Mary County, Louisiana this week, while a year ago there were no rigs drilling in inland waters..

The count of active horizontal drilling rigs was down by 6 to 214 horizontal rigs this week, which was also 562 fewer horizontal rigs than the 776 horizontal rigs that were in use in the US on September 13th of last year, and less than a sixth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…on the other hand, the directional rig count was up by 1 to 21 directional rigs this week, but those were still down by 36 from the 57 directional rigs that were operating during the same week of last year….in addition, the vertical rig count rose by 3 to 19 vertical rigs this week, but those were still down by 34 from the 53 vertical rigs that were in use on September 13th of 2019….as of this week, 84.3% of all US drilling is being done by horizontal rigs, which is the lowest percentage horizontal rig deployment since September 8th, 2017….on the other hand, 7.5% of US drilling is now being done by vertical rigs, and that’s the highest percentage vertical rig deployment since the same date..

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 September 11th, the second column shows the change in the number of working rigs between last week’s count (September 4th) and this week’s (September 11th) count, the third column shows last week’s September 4th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running during the count before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 13th of September, 2019…

There were a few more changes this week than is evident from just looking at the above tables….checking the rig counts in the Texas part of Permian basin, we find that 5 rigs were added in Texas Oil District 8, which is the core Permian Delaware, while 4 rigs were pulled out of Texas Oil District 7C, which roughly aligns with the southern part of the Permian Midland, and another rig was pulled out of Texas Oil District 8A, which corresponds to the northern Permian Midland, thus leaving the Texas rig count in the Permian unchanged…since the national Permian basin rig count was down by one, that means that the rig that was pulled out of New Mexico must have been drilling in the far western Permian Delaware, to balance the national rig count on that basin…elsewhere in Texas, a rig was pulled out of Texas Oil District 6 near the Louisiana border, which thus accounts for the decrease in the Haynesville shale basin we see above…in addition to that natural gas rig removal from the Haynesville shale, two more natural gas rigs were also pulled out of West Virginia’s Marcellus this week, which you also see above…however, the national natural gas rig count was only down by one because a vertical rig was set up to drill for natural gas in a shallow formation in Kanawha county, West Virginia that was not targeting the Marcellus, and another rig targeting natural gas began drilling in Andrews County, Texas, one of the Texas Oil District 8 additions in the Permian basin we noted previously, and the only Permian rig targeting natural gas that is active at this time…

Ohio sees gas production drop, oil production increase – Natural gas production in Ohio in the first quarter of 2020 dropped by nearly 4.6%, while crude oil production increased by 16.0%, according to new data released by the Ohio Department of Natural Resources. Natural gas production dipped from 609,451,574 Mcf in 1Q 2019 to 581,634,083 Mcf in 1Q 2020, Kallanish Energy reports. Crude oil production jumped from 5,073,536 barrels of oil in 1Q 2019 to 5,887,0322 barrels in 1Q 2020. The data reflects production from the state’s horizontal shale wells, mostly in the Utica Shale in eastern Ohio. The state’s quarterly report lists 2,573 horizontal shale wells in Ohio, of which 2,509 reported oil or natural gas production in the quarter. The typical well produced 2,346 barrels of crude oil in the quarter and 231,919 Mcf of natural gas in that time period. Ohio law does not require the separate reporting of natural gas liquids or condensate. The oil and natural gas reporting totals include those commodities. The report is available at https://oilandgas.ohiodnr.gov/production.

Drilling success in area only matter of time – Many of us remember the huge commitment BP, Consol, Halcon Energy and other big-name oil and gas companies made here in the form of mineral rights lease contracts with cash “signing bonuses” for many property owners in Trumbull, Mahoning and Columbiana counties.Hopes were high. Certainly, no big company like BP would invest here if it didn’t really believe it would pan out.The construction of pipelines began. Oil and gas industry suppliers began opening. Vallourec made a massive investment in a pipe factory near the Girard-Youngstown line. I researched the industry, learning about technology and “downstream” petro-chemical businesses that could develop here from byproducts of natural gas drilling. Months and even years later, drillers slowly pulled out of our area, explaining that the Utica shale play in this part of northeastern Ohio was simply too narrow or thin for their sometimes mile-long drill bits to maneuver.Most experts remained optimistic about the future, however, acknowledging that the oil and gas reserves indeed are here and that it’s only a matter of time – albeit years probably – until geologists perfect more advanced technology to access them.Last week, I was pleased to hear Steven Winberg, assistant secretary for Fossil Energy in the U.S. Department of Energy, talk about the drilling industry’s improving technology, the volume of resources and the potential to develop the petro-chemical industry that still exists here.He said, amazingly, if this region, including Appalachia, were an independent country, it would be the third largest natural gas producer on earth. Think about that.In respect to geology and thin shale formations, Winberg said developing technology in coming years will allow us to extract oil and natural gas from thinner formations. That will be possible due to artificial intelligence, high-performance computing and developing data with high-performance computers.It’s not going to happen tomorrow for northeast Ohio, Winberg said. But he is confident it’s going to happen. When it does, that will be a game-changer for our region and our economy.

Clock ticking on pipeline tax appeals – Time is almost up for two natural gas pipeline companies to appeal denials by the Ohio Department of Taxation for tax decreases they say are necessary due to cost overruns. Requests by both the NEXUS Gas Transmission and Rover pipelines for reductions in their public utility tax valuations were turned down by the state July 10. Both pipeline companies had argued in previous appeals that additional costs inflated the budgeted amounts of their projects in Ohio. Fulton County Auditor Brett Kolb previously reported that the NEXUS pipeline has appealed its value at approximately 40% of the original determination, and the Rover pipeline at approximately half of the original determination. Had their appeals been approved, pipeline revenue for county entities would have decreased from $6.7 million to $4.1 million for NEXUS and from $3.99 million to $2.28 million for Rover. Owned by DTE Energy and Canadian-based Enbridge Inc., NEXUS transports approximately 1.5 billion cubic feet of natural gas through 256 miles of 36-inch pipe. In Fulton County, it travels through Amboy, Fulton, and Swancreek townships.The original $2.2 billion cost of the project ballooned to $2.6 billion due to cost overruns that included an additional $120 million in scope reduction costs to decrease the pipeline size from 42 to 36 inches. NEXUS Gas Transmission has argued that Ohio’s tax commissioner should use the value estimated in the pipeline project’s appraisal as its true value. The company also argued that contractor costs and conditions and delays set forth by the Federal Energy Regulatory Commission helped caused the project’s cost overruns.The Ohio portion of the pipeline constitutes approximately 83% of its entire length. In a 30-page ruling, the Ohio Department of Taxation noted the Ohio Revised Code’s required use of the capitalized cost of taxable property reflects the pipeline’s true value.Rover pipeline owners Blackstone Group, Energy Transfer Partners, L.P., and Traverse Midstream Partners similarly argued that additional costs are responsible for significantly inflating a budgeted project cost of $4.2 billion to $6.2 billion. The company previously asked Ohio for a reduction in true value due to its additional costs for right of way acquisition and drawing costs, among other overruns. The ODT similarly denied the company’s appeal in a 20-page ruling.

State investigating whether injection well waste affecting drinking water – Brine, a waste byproduct produced in fracking, from an injection well in Washington County has migrated to gas-producing wells at least five miles away, the Ohio Department of Natural Resources reported Friday, and officials want to make sure it’s not getting into drinking water. While state officials said it’s unlikely, it’s possible the brine from the Class II Saltwater Injection Well, Redbird #4 in Dunham Township, could affect drinking water of those in the area. As of Friday, the state has not received any reports affecting human health or safety associated with any of the wells, officials said. Ohio Department of Natural Resources Director Mary Mertz said the state is in the process of hiring an expert to assess groundwater issues. “You can never be too careful. Science evolves. We’ll consult with some of the experts in the state like Ohio Environmental Protection Agency, Ohio Department of Health,” she said. “And we’ll bring someone on to just take a closer look at groundwater issues and confirm that there’s nothing to be concerned about.” If the groundwater does become contaminated, there would be no way to clean it, said Amy Townsend-Small, an associate professor of environmental science and geology at the University of Cincinnati who conducts research on fracking and its effects on groundwater. “That’s the biggest concern for people that live in shale gas producing areas,” she said. Abandoned wells could be source of the brine contaminating the water table, Townsend-Small said. “Abandoned wells are everywhere there. … And the state does not even know where they all are. So it’s a huge problem,” she said. The state released the report Friday “to make residents in the immediate area aware of our investigation and findings,” said ODNR spokeswoman Sarah Wickham. The state has already found 11 abandoned wells nearby, one of which contained the brine wastewater. “We’ve also compiled a list of all of the orphan and idle wells we can find in that two-mile radius. We’re analyzing each one of them to see would it make a difference if we take action?” Ohio has more than 200 injection wells that are full of ingredients that many companies don’t have to disclose citing trade secret protections. “The wastewater from that injection well, was apparently migrating to the surface through an idling or an orphan well. Otherwise they wouldn’t have been able to find it,” Townsend-Small said. “Ostensibly, they were pumping the water up (in the conventional gas wells.) Orphan/idle wells aren’t pumping, so it’s not active. The wastewater is very pressurized because they’re injecting such high volumes of it.” Much of the brine waste injected in Ohio’s injection wells comes not only from fracking sites in Ohio, but from other states, such as Pennsylvania. The state plans to add additional conditions to recently issued permits for injection wells in that area that will include additional monitoring and give the state the ability to halt operations if more fluid is migrating, Mertz said. There were also two pending permits that have since been put on hold.

Despite Historic Drop in Crude Oil, Pure Gas Plays Set to Rise – Appalachian and Haynesville basins well positioned for near-term growth – Enverus, the leading oil and gas SaaS and data analytics company, has released its latest FundamentalEdge report which reviews upstream and midstream activity in two active natural gas basins: the Appalachian, composed of the Marcellus and Utica shales in Pennsylvania and Ohio, and the Haynesville, in Louisiana and Texas.Along with the overall economy, the energy industry was drastically impacted by the COVID-19 pandemic. Operators were forced to readjust their 2020 plans as prices fell due to oversupply in the market. These revised 2020 activity plans called for reduced rig activity and reduced production outlooks from most operators, particularly those in oil-directed plays.The oversupply in the crude market and the subsequent price drop have lowered activity in crude-directed plays. While this activity reduction is needed to help balance the crude markets, associated gas in these areas will also be taken off the market as a result. To offset the drop in associated gas, dry gas plays will need to fill the gap – and this will require higher prices to incentivize production.”While the Saudi-Russian price spat earlier this year, followed by coronavirus pandemic, rocked crude oil demand, gas-reliant industries like heating and power weathered much better,” said Rob McBride, senior director of Strategic Analytics at Enverus.”For all that happened to oil, to some degree the inverse is true for natural gas, and that’s evident in the Appalachian and Haynesville basins,” McBride said. “Natural gas is well poised for the near future. Since the historic crash a few months ago, gas has slowly crept up, but drilling rigs haven’t yet followed suit.”Members of the media can download a preview of the full report or contact Jon Haubert to schedule an interview with one of Enverus’ expert analysts. Key Takeaways: Appalachian – Marcellus and Utica:

• In terms of production, the Marcellus and Utica plays have held strong through the pandemic. Production dropped at the start of the year, and then dropped further in May as wells were shut-in. However, volumes have recovered to levels higher than the start of 2020.
• While production in the Marcellus and Utica has battled through the pandemic, rigs have fallen as a result of COVID-19. That yields the question: How can production be up if new wells aren’t being drilled? The answer is DUCs. The DUC inventory in the Appalachian has been drastically decreased as operators have chosen to complete wells that have already been drilled in the past, as opposed to running rigs and drilling new wells.
• Rigs have fallen off in the Appalachian, but there are still rigs running and new wells being drilled. Production is expected to continue to climb in the Marcellus and Utica. The Mountain Valley Pipeline (MVP) is expected to come online in early 2021, which will add 2 Bcf/d of takeaway capacity to the region and send gas to the Transco Zone 5 region. Should MVP meet the same fate as the Atlantic Coast Pipeline, which was canceled in early July, pipeline bottlenecks could be seen in the region as early as mid-2021. Enverus does not expect this to happen

Enverus report sees signs of optimism for Marcellus, Utica in 2021 – Pittsburgh Business Times -Signs are increasing that the battered Appalachian natural gas industry is poised for a comeback next year, according to a new report.Enverus, a Texas-based analysis company, reported that the Marcellus and the Utica have been in a relatively decent position during 2020 despite the social and economic upheavals over Covid-19 and rock-bottom commodity pricing. The crash in oil prices and oversupply has led to a drop-off in the natural gas that was produced with the oil in the Permian Basin, which has been a thorn in the side of Marcellus and Utica shale producers for several years.Enverus’ FundamentalEdge report focuses on the Marcellus and Utica and another shale basin, the Haynesville in Louisiana and Texas, and said they’re likely to benefit as predicted from the falloff in so-called associated gas, which was available in high quanities and cheaply with the rise in oil in the Permian.With that extra supply greatly diminished, that has shone the light on the dry gas from the Marcellus, Utica and Haynesville at a time when demand is likely to go up, said Rob McBride, senior director of strategic analytics at Enverus.The reason for higher natural gas demand? Cooler weather that leads to higher demand for natural gas to heat homes and create electricity at gas-fired power plants.”It’s not surprising that the dry gas plays are the ones that now look attractive to come back,” McBride said. “At the end of the day, for natural gas, the seasonal demand going into winter, it’s going to be there.”The Covid-19 pandemic and a February price war between Saudi Arabia and Russia over oil prices crushed demand for months and with it, rig counts. Enverus counted 779 active rigs across the United States on March 1 and three months later only 277. That’s happened in the Marcellus and Utica as well, falling from 46 rigs across the three-state region to 26 at the end of last month. Not only were the number of new wells and capital spending on drilling drastically reduced – from an already low number due to the commodity prices – but existing production was also cut back by well shutins.McBride said that drillers have this year gone back to drilled but uncompleted wells – known in the industry as DUCs – to finish and replace lost production. That adds production but at a lower cost than it would be to drill and hydraulically fracture a new well. Two producers, Cabot Oil & Gas Corp. and Chesapeake Energy Corp., have all but eliminated their inventory of DUCs by completing 34 wells between the two companies. “They’re drawing down on their uncompleted inventory,” McBride said. “A lot of these players are trying to be strategic.”

Pa. shale gas permits decline YOY in August, despite EQT picking up its pace – After shutting in 1.4 Bcf/d of production volumes in May and pulling few permits for new wells over June and July, the largest U.S. natural gas producer, EQT Corp., is cranking up its machine to catch rising oil and gas prices this fall and winter, according to August shale gas permitting data from Pennsylvania’s Department of Environmental Protection. Pennsylvania issued 77 permits for shale gas wells in August, down 24% from the same month in 2019. Nearly half went to EQT, which pulled 38 permits compared to 12 in June and July combined. EQT’s August activity was focused on Greene and Washington counties south of Pittsburgh, according to DEP data as of Sept. 4. The increase in permitting activity is a sharp turn for the Appalachian driller. As recently as the company’s July 27 second-quarter earnings conference call, President and CEO Toby Rice told analysts that while EQT returned all of the gas it pulled from production in July, the company was ready to shut in gas in the fall if prices stayed low. Joining EQT in Greene County was CNX Resources Corp., which pulled eight permits in August, one more than in July. The state’s other big permit puller in August was New York gas company National Fuel Gas Co., which pulled eight permits to drill in north-central Cameron County, acreage that is prospective to both the Utica and Marcellus shales. The state’s four other large producers – Southwestern Energy Co., Cabot Oil & Gas Corp., Range Resources Corp. and Chesapeake Energy Corp. – accounted for only 10 permits in August, consistent with lower activity throughout the summer as commodity gas prices at the benchmark Henry Hub stayed below $2/MMBtu until starting to rise in August. Including EQT, the state’s top five gas producers accounted for 62% of the state’s August permitting activity, while publicly traded drillers accounted for 83% of activity. PennEnergy Resources LLC had seven of the 13 shale gas permits pulled by private drillers in August, according to DEP data. Backed by EnCap Investments LP, PennEnergy operates primarily in Butler County, north of Pittsburgh, on acreage acquired when Rex Energy Corp. went bankrupt in 2018.

Pin Oak Midstream Acquires Assets from Laurel Mountain Midstream in NW Pennsylvania –Pin Oak Midstream, a wholly owned subsidiary of Pin Oak Energy Partners LLC, announces the closing of a transaction with Laurel Mountain Midstream LLC (“LMM”), a joint venture between Williams Laurel Mountain, LLC and Chevron Northeast Upstream LLC, to acquire LMM’s Jackson Center assets. Jackson Center includes over 1,050 miles of natural gas gathering pipelines and five (5) gathering compressor stations with a gathering capacity of over 50 MMcf/d and multiple interstate pipeline interconnects (both National Fuel Gas and Tennessee Gas Pipeline) with total interconnect capacities of almost 100 MMcf/d. The transaction adds to Pin Oak Midstream’s growing asset base within the Appalachian Basin. Brent Breon, President of Pin Oak Midstream LLC and Chief Commercial Officer of Pin Oak Energy Partners LLC, stated, “These assets in Mercer, Lawrence, and Crawford counties of Pennsylvania are a great fit to our expanding footprint and further bolster the Company’s midstream assets in the oil and wet gas windows of the Utica play in northwestern Pennsylvania. The Jackson Center assets currently gather conventional and unconventional gas from third party operators in the area and will allow Pin Oak Energy to connect and produce Utica wells currently waiting on pipelines. Additionally, Pin Oak remains committed to our ongoing efforts of executing our growth strategy through acquisitions even during these difficult times.” Pin Oak Midstream’s Appalachian Basin position consists of nearly 1,200 miles of pipeline assets; 13 interstate pipeline interconnections; gathering, processing and transportation dedications on more than 150,000 dedicated net deep acres (Marcellus and Utica) and current flowing volumes more than 15 MMcf/d.

Frack Check: Trump inflates Pennsylvania fracking job figures by 3500 percent – PGH City Paper Yesterday, President Donald Trump held a campaign rally in Latrobe, Pa., just an hour east of Pittsburgh. There, he lobbed many insults and made many false claims, but arguably none more egregious than one about jobs inPennsylvania’s natural-gas, aka fracking, industry. According to WESA editor Chris Potter, Trump claimed during his speech that there are currently 940,000 natural-gas jobs in Pennsylvania. A gross exaggeration. According to multiple analysis and data from state and federal labor departments, there are around 26,000 jobs in Pennsylvania’s oil and gas industries. Trump inflated the amount of fracking jobs in Pennsylvania by more than 3500%. According to a March analysis of federal employment data by environmental group Food & Water Watch, there were approximately 636,000 jobs directly related to oil and natural gas extraction from 2016-2018 nationally. In Pennsylvania, there were 26,000 jobs in these industries during this time span. Since 2018, the fracking industry has struggled, as gas prices remain low. In the Pittsburgh region, hundreds of jobs have been lost, and large fracking companies are divesting from the area. Other analysis corroborate these figures. According to the Pennsylvania Department of Labor and Industry, there are between 20,000 to 50,000 jobs in, and supported by, the state’s fracking industry. According to the Bureau of Labor Statistics, in 2017, there were about 967,000 total jobs in the oil and gas and supported industries throughout America. But nothing close to those figures when just counting Pennsylvania jobs. In fact, it is hard to find job figures as high as Trump is claiming in any Pennsylvania sector. Only jobs in “Trade, Transportation, and Utilities” and “Education and Health Services” have figures over 940,000 jobs in the commonwealth. Conservatives and fracking boosters have been known to exaggerate the number of jobs in the natural-gas sector. Local congressional candidate Sean Parnell (R-Ohio Township) claimed in March that “over 100,000 oil and gas jobs in Western PA would vanish” under a plan proposed by Biden that would ban new permits for oil and gas drilling on federal land and off-shore. (Only about 2% of Pennsylvania is comprised of federal land.)Obviously, with only about 26,000 fracking-related jobs in the entire state, this is impossible.

Judge declines to toss charges against pipeline constables – The two state constables arrested last summer on charges of improperly using their official positions while working as private security guards along the controversial Mariner East Pipeline project will have to face trial on those charges after their attempt to have the cases against them thrown out failed. Common Pleas Judge Jeffrey Sommer denied the move by constables Kareem Johnson of Coatesville and Michael Robel of Northumberlnd County to have bribery and conflict of interest charge against them dismissed because they claimed that no actual crimes had been committed when they began working as security guards along the pipeline construction area in West Whiteland. The pair contended that there is no law against constables working for private companies such as the Sunoco Pipeline firm, Energy Transfers Partners, outside the judicial system, and that neither man represented that they were working for any court while they patrolled the pipeline in West Whiteland, as the law prohibits. Although Sommers ruled against them, he did so not on the merits of their claims but because of rules of criminal procedure in Pennsylvania that he agreed did not allow such a pre-trial move. The judge accepted the position of Deputy District Attorney Thomas Ost-Prisco, who argued the case on Monday, that Johnson and Robel had given up their right to argue the quality of evidence against them at this stage in the process because they had waived their right to challenge the case at a preliminary hearing. The pair’s trial is currently scheduled for Sept. 29. However, because of restrictions on criminal trials put in place by the courts due to the corona virus earlier this year, it is uncertain when any trial would be held. Both men remain free on bail, and continue to work as constables. They were arrested in August 2019 when Chester County Detective Ben Martin filed criminal complaints against them after witnessing them working as guards along the controversial pipeline project in West Whiteland, allegedly using their official badges and positions as state officials in doing so.

Pennsylvania DEP Orders Sunoco to Reroute Mariner East II Pipeline After Chester County Spill – – A natural gas liquids pipeline under construction in Pennsylvania will be rerouted after thousands of gallons of industrial waste spilled into a creek last month. The state Department of Environmental Protection ordered Sunoco to reroute the Mariner East II pipeline and divert it around the Marsh Creek Lake and wetlands, a DEP news release says.In August, more than 8,100 gallons of drilling fluid spilled into a tributary of the lake before flowing into the lake itself. 33 acres of the lake were closed off from boating and other recreational uses after the spill. Sunoco has proposed adjusting the pipeline route so it would cross under the Pennsylvania Turnpike and Conestoga Road.Secretary Patrick McDonnell of the DEP called the spill “yet another instance where Sunoco has blatantly disregarded the citizens and resources of Chester County with careless actions while installing the Mariner East II Pipeline.””We will not stand for more of the same,” McDonnell added in the news statement. “An alternate route must be used. The department is holding Sunoco responsible for its unlawful actions and demanding a proper cleanup.”The department says Sunoco hasn’t turned over plans on how it will remediate the impacts of drilling fluid spills and sinkholes. The company told the state that spills are “readily contained and cleaned up with minimal affect to natural resources.”

Pa. shale gas permits decline YOY in August, despite EQT picking up its pace – After shutting in 1.4 Bcf/d of production volumes in May and pulling few permits for new wells over June and July, the largest U.S. natural gas producer, EQT Corp., is cranking up its machine to catch rising oil and gas prices this fall and winter, according to August shale gas permitting data from Pennsylvania’s Department of Environmental Protection. Pennsylvania issued 77 permits for shale gas wells in August, down 24% from the same month in 2019. Nearly half went to EQT, which pulled 38 permits compared to 12 in June and July combined. EQT’s August activity was focused on Greene and Washington counties south of Pittsburgh, according to DEP data as of Sept. 4. The increase in permitting activity is a sharp turn for the Appalachian driller. As recently as the company’s July 27 second-quarter earnings conference call, President and CEO Toby Rice told analysts that while EQT returned all of the gas it pulled from production in July, the company was ready to shut in gas in the fall if prices stayed low. Joining EQT in Greene County was CNX Resources Corp., which pulled eight permits in August, one more than in July. The state’s other big permit puller in August was New York gas company National Fuel Gas Co., which pulled eight permits to drill in north-central Cameron County, acreage that is prospective to both the Utica and Marcellus shales. The state’s four other large producers – Southwestern Energy Co., Cabot Oil & Gas Corp., Range Resources Corp. and Chesapeake Energy Corp. – accounted for only 10 permits in August, consistent with lower activity throughout the summer as commodity gas prices at the benchmark Henry Hub stayed below $2/MMBtu until starting to rise in August. Including EQT, the state’s top five gas producers accounted for 62% of the state’s August permitting activity, while publicly traded drillers accounted for 83% of activity. PennEnergy Resources LLC had seven of the 13 shale gas permits pulled by private drillers in August, according to DEP data. Backed by EnCap Investments LP, PennEnergy operates primarily in Butler County, north of Pittsburgh, on acreage acquired when Rex Energy Corp. went bankrupt in 2018.

Joseph Otis Minott: EPA’s methane rollback is bad for Pa., nation | Pittsburgh Post-Gazette — On Aug. 13, U.S. Environmental Protection Agency Administrator and former coal lobbyist Andrew Wheeler stopped in Pittsburgh to announce the finalization of another dangerous regulatory rollback. Amid the global pandemic and over 1,000 Americans dying every day from acute respiratory disease, EPA gutted commonsense air pollution standards that protect the public from methane leaks from fracked gas infrastructure. These methane controls, known as the 2016 New Source Performance Standards for the Oil and Natural Gas Industry (2016 NSPS), have been successfully implemented for years. They have already helped prevent hundreds of thousands of tons of industrial methane leaks. Methane, the primary component of fracked gas, is an extremely potent climate pollutant, up to 87 times as efficient at trapping atmospheric heat as carbon dioxide in the first 20 years after its release. Methane is responsible for roughly a quarter of the warming we’ve already experienced. The oil and gas sector is the nation’s largest industrial emitter of methane, and Pennsylvania is the second-largest fracked gas producing state in the country. The commonwealth has tens of thousands of oil and gas wells that emit over 1.1 million tons of methane pollution every year. Pennsylvania has already begun to experience vast and devastating impacts from climate change: higher temperatures, changes in precipitation and frequent extreme weather events, including large storms, flooding, heat waves, heavier snowfalls and periods of drought. This rollback represents terrible public policy, and the approach is particularly nonsensical because EPA identifies no practical or administrative problems in enforcing the 2016 NSPS. It identifies no burden whatsoever to industry in continuing to comply with these rules. It is simply mindless deregulation. Leading oil and gas operators do not even support it! Exxon, BP and Shell have all publicly supported the 2016 NSPS and opposed this dangerous rollback. The consequences would be severe: hundreds of thousands of oil and gas sources nationwide – including many here in Pennsylvania – will be allowed to continue pumping methane (and other harmful pollutants) into the atmosphere every year. Even EPA’s own analysis estimates this rollback will result in an additional 370,000 tons of dangerous methane emissions just over the next five years. This proposal runs directly counter to EPA’s obligations under the Clean Air Act and the enormous factual record demonstrating serious public health harms caused by pollutants from fracked gas infrastructure.

Cleanup of oil spill continues on Buffalo River – The Coast Guard and state Department of Environmental Conservation are investigating an oil spill discovered on the Buffalo River about a month ago near the former ExxonMobil refinery site on Elk Street. The release of oil was first reported Aug. 7 as a sheen on the Buffalo River near Babcock Street, prompting the start of an investigation. Although it’s not known when the release began, a statement from the DEC said the amount of oil varies day by day but is generally considered to be two to five gallons, with most of it contained and recovered through mitigation efforts. The property is owned by Elk Street Commerce Park. ExxonMobil, the former owner, is under an agreement with the DEC to investigate and remediate Buffalo River sediments adjacent to its former refinery. The cleanup is being led by LaBella Associates, a Rochester-based environmental consultant. Kayakers and boaters are advised to avoid the northern half of the Buffalo River near the spill. A boom has been placed around the site to capture the petroleum discharge. An analysis indicated degraded light fuel and lubricating oil are entering the Buffalo River near a combined sewer overflow pipe located at the foot of Babcock Street.

Battleground State Poll Shows Voters Are Strongly Supportive of Oil and Natural Gas Development – The Heartland Institute – A new poll from the American Petroleum Institute (API) shows voters in energy-producing swing states support increasing access to oil and natural gas and the candidates who support those industries. The poll of more than 8,600 registered voters in 12 states – Arizona,Colorado, Florida, Georgia, Iowa, Michigan, Minnesota, Nevada, New Mexico,Ohio, Pennsylvania, and Texas – was conducted by Morning Consult and found 64 percent of voters would “be more likely to vote for a candidate who supports policies that ensure consumers have access to natural gas and oil produced in the U.S.” Further, 82 percent of voters in these states say “natural gas and oil provide value to their lives,” while 73 percent believe oil and natural gas will be “a significant part of America’s energy needs” in 2040. And while 76 percent of respondents admit that the COVID-19 pandemic has significantly hurt their state’s economy, 63 percent said they expect the oil and natural gas industries to play an “important role” in any economic recovery.What’s more, 93 percent responded that it was important for the United States to not be reliant on other countries for oil, while 92 percent believe it is important to keep energy and gasoline prices affordable.

Gibbstown LNG Terminal Could Be Decided This Week Plans to build New Jersey’s first liquefied natural gas export terminal may get a final vote from the Delaware River Basin Commission this week, prompting a flurry of last-minute protests by opponents including environmentalists and public-health advocates. The interstate water regulator has left open the possibility that its governing body will vote on whether to approve the construction of a dock for LNG tankers on the Delaware River at Gibbstown in Gloucester County, and dredging of the river, even though the matter is not on the formal agenda for the Sept. 10 business meeting. “An action could occur, but it would be at the commissioners’ discretion,” said Kate Schmidt, a spokeswoman for the DRBC, referring to representatives of the governors of New Jersey, New York, Pennsylvania and Delaware plus the U.S. Army Corps of Engineers, which represents the federal government on the commission’s governing body. The commission approved the project in June 2019 but then suspended its decision and agreed to hold a quasi-judicial hearing in May this year to hear the arguments of Delaware Riverkeeper Network (DRN), an environmental group, about why the dock should not be built. DRN and other critics are urging the commission to reject a recommendation to approve from an officer who presided over the hearing when friends and foes made their arguments over the project. The hearing officer, John Kelly, said in a report issued in July that he had heard no evidence to indicate that the commission should change its previous approval for the project, which would build a second dock for LNG tankers – “Dock 2” – at the planned Gibbstown Logistics Center. The center is being built on a former DuPont site where explosives were made. Kelly said the evidence presented by Delaware Riverkeeper Network and its witnesses had failed to meet their burden of proving that the dock should not be built. “It is recommended that the Dock 2 Docket should remain as previously approved by the commission,” Kelly said in the 102-page report.

Delaware River Basin Commission suspends approval of natural gas terminal – The Delaware River Basin Commission (DRBC) on Thursday, September 10 voted to hold off on either approving or denying the permit for the proposed Gibbstown Liquefied Natural Gas (LNG) export terminal in New Jersey. The commission’s decision temporarily prevents the limited liability company Delaware River Partners from constructing New Jersey’s first liquefied natural gas export terminal. Completion of the terminal would allow fracked gas from Pennsylvania’s Marcellus Shale, to be transported to a processing facility on the Susquehanna River, and finally hauled as liquefied methane to the Gibbstown, NJ. The DRBC originally approved the project in June of last year, however, was challenged by the Delaware Riverkeeper Network, an environmental advocacy group, which argued during an eight-day hearing last May that the dock presented health, safety and environmental risks. “The process of the appeal was concluded very recently, less than 2 weeks ago, and requires a vote by the commissioners about whether to reaffirm the original approval, which is what prompted the vote today,” according to a statement from the Riverkeeper. “The voluminous record produced during the appeal process, the full year of legal filings, the eight-day adjudicatory hearing and the fact that legal submittals were made as recently as last week, were cited as the reason for the delay in the decision about the fate of the project.” Representatives from New York, New Jersey and Delaware voted to abey approval, Pennsylvania abstained and the federal representative from the Army Corps of Engineers voted no. The representatives from New York and Delaware noted that they wanted to wait on approving construction until after the Riverkeeper’s administrative appeal is resolved, but that this decision is “not intended to signal how the appeal will be resolved.”

Brooke County commissioners concerned about power plant loan guarantee provision – While the West Virginia Economic Development Authority is expected today to consider a loan guarantee for the proposed Brooke County Power Plant, Brooke County Commissioners said Tuesday they are concerned about a provision that may be included with it.The commissioners said they have learned that Gov. Jim Justice’s office has asked for the Energy Solutions Consortium, the company building the plant, to formally agree to use some percentage of natural gas from West Virginia for the gas-fired plant.A website for the project states it will draw gas from existing pipelines. Equitrans, a Canonsburg, Pa.-based company, has announced plans to build a 16.7-mile pipeline from the Rover pipeline in western Pennsylvania to serve the plant.Once completed, the facility is expected to expected to consume $177.5 million in natural gas per year.Commissioner A.J. Thomas said he’s concerned the provision will deter its developers and others who may consider building in the state.He said the state Development Authority has written to ESC indicating its intention of supporting a $5.6 million loan guarantee for the project, a move he sees as an effort to calm prospective investors in the plant.The state board had been slated in August to consider the guarantee, which would involve the state in repaying the loan should the plant’s developers be unable to. But the board dropped it from its agenda after Gov. Jim Justice raised questions about the project. Some have argued Justice was swayed by interests who see the plant as a threat to the coal industry.

Development board approves loan guarantee for Brooke County Power plant – The West Virginia Economic Development Authority on Wednesday unanimously approved a $5.5 million loan guarantee for the proposed Brooke County Power plant project. The authority’s approval checked one of the final boxes the project needed before construction can begin, which the original proposal projected would be in 2022. A swarm of uncertainty surrounded the vote Wednesday. The authority was set to vote for approval of the loan guarantee during its Aug. 20 board meeting, but the item was pulled from the agenda without explanation and a clear reason was never given. Members of the trades union, oil and gas industry and public, lawmakers and county commissioners were afraid that $5,518,865 was going to derail the entire near-billion-dollar project. The coal industry tanked West Virginia’s first attempt to build the state’s first natural gas-fired power plant nearly four years ago, and some stakeholders said they feared it was going to happen again. Many of these stakeholders spoke in support Wednesday during the meeting’s public comment period. No members of the public spoke against the project. The board went into executive session for nearly an hour to discuss the project before returning for a vote. Authority board member Joe Eddy offered one amendment to the loan guarantee that altered one of the stipulations Gov. Jim Justice asked the authority to review, that the natural gas powering the plant must be from West Virginia. The project’s site, in Colliers, Brooke County, sits just miles from the border with Pennsylvania. The developer’s plan is to connect the plant to the existing Rover Pipeline in Pennsylvania, because there is no pipeline in West Virginia that can reach Colliers.

Trump Administration seeks to relax oil drilling rules through U.S. Forest Service rule change –(WOWK) – A new rule proposed by the U.S Forest Service has conservationists saying the Trump Administration wants to relax oil and gas drilling rules on Forest Service lands.There are currently 5,490 federal oil and gas leases covering about 4.2 million acres – or 2 % – of national forest system lands.The West Virginia Rivers Coalition does not want the Monongahela Forest with its many headwaters to be one of them.”It’s important for us to protect these headwaters which in turn protect not only drinking water and surface water for our state but also the region,” said Dr. Sarah Cross with the coalition.Although there are currently no active gas and oil wells in the Monongahela Forest, they say the plan, proposed on September 1st, could lead to this.”When it comes to this proposed rule, it would make it a lot easier to implement oil and gas drilling on our national forest service lands it would also reduce the public input on the process,” said Cross.Charlie Burd, the executive director of the Independent Oil and Gas Association of West Virginia says the rule is only streamlining the process.”They’re just really proposing to clarify all the processes that the Bureau of Land Management and others have in place,” he said.”It pretty clearly states that it doesn’t relieve the oil and gas operator from any responsibility to protect the land and the resources and the environment.”But Cross says up to a million gallons of water are used in hydraulic fracking. “There would be a lot more soil erosion, roads cut into our national forests, but also we’re very concerned about that much water being taken out of our streams then after the fracking process takes place you have a tremendous amount of water that has to be hauled out,” she said. The Forest Service is taking public comment on the rule proposal until November 2nd.

Mountain Valley Pipeline construction won’t jeopardize protected species, federal review says — Construction of the Mountain Valley Pipeline, should it continue, is not likely to jeopardize five endangered or threatened species of fish, bats and plants, a long-awaited federal authorization has concluded. The U.S. Fish and Wildlife Service on Friday issued a revised biological opinion, which was essentially a rewrite of its finding in 2017. After a legal ch allenge was filed by Wild Virginia and six other environmental groups last August, a federal appeals court stayed the original opinion. The Federal Energy Regulatory Commission then issued a stop-work order in October. Following a nearly year-long reconsideration, the Fish and Wildlife Service released a 226-page opinion that found the massive project – which has run into repeated problems with erosion on steep mountain slopes – would not jeopardize protected species. The finding applies to the Roanoke logperch, the candy darter – a second kind of fish that has been added to the endangered species list since 2017 – the Indiana bat, the northern long-eared bat and the Virginia spiraea, a flowering shrub native to southern Appalachia. With the renewed permit in hand, Mountain Valley says it will resume work once the stop-work order is lifted. “We look forward to resolving the few remaining permitting issues, resuming forward construction, and completing the MVP project in early 2021.” However, new legal challenges are likely for any authorizations given to the controversial 303-mile pipeline, which will transport natural gas at high pressure from the Marcellus and Utica shale formations to markets in the Mid-Atlantic and Southeastern parts of the country. “This dirty, dangerous fracked gas project is years behind schedule, billions of dollars over budget, and was sued by the Commonwealth of Virginia for violating common sense environmental protections hundreds of times,” Joan Walker of the Sierra Club said in a statement. “MVP has shown they can’t be trusted to build this pipeline anyway,” she said, “and they should wise up and walk away from this risky bet like Duke and Dominion did with the ACP [Atlantic Coast Pipeline].” Before completing the $5.7 billion project, Mountain Valley still must obtain a renewed permit from the U.S. Army Corps of Engineers for the pipeline to burrow under nearly 1,000 streams and wetlands. Permission from the U.S. Forest Service is also required before the pipe can pass through about 3.5 miles of the Jefferson National Forest. The permits were set aside after environmental groups filed legal challenges in the 4th U.S. Circuit Court of Appeals. As a result, construction has been delayed by about two years, while costs rose by nearly $2 billion.

MVP One Step Closer to Resuming Construction After New Fish and Wildlife Permits -Crossing one of the items off Mountain Valley Pipeline LLC’s (MVP) regulatory checklist, the U.S. Fish and Wildlife Service (USFWS) has issued a new Endangered Species Act review of the 2 million Dth/d, 303-mile Appalachian natural gas conduit. Late last week, the USFWS notified FERC that it had finished drafting an up-to-date Biological Opinion (BiOp) and Incidental Take Statement (ITS) for the pipeline, part of federal requirements to review potential impacts to protected species from project construction. The newly issued opinion takes into account “new data” and ensures “that we continue using the best available scientific and commercial information,” the USFWS wrote in a memo to the Federal Energy Regulatory Commission. MVP first received a BiOp and ITS in 2017 as part of the FERC certification process. However, the BiOp and ITS came under the scrutiny of the U.S. Court of Appeals for the Fourth Circuit, leading to a work stoppage last year while the USFWS reinitiated its consultation process and worked on reissuing the approvals. With the new USFWS permits in hand MVP has cleared “a key hurdle” in its efforts to place the 42-inch diameter pipeline into service, according to analysts at ClearView Energy Partners LLC. ClearView analysts said in a note to clients that they expect MVP to seek FERC approval to resume construction. The memo from USFWS “specifically states that this document replaces the BiOp and ITS issued in 2017,” the ClearView analysts wrote. “Therefore the Fourth Circuit order suspending the 2017 permits becomes irrelevant as FERC would be authorizing Mountain Valley to resume work on the basis of the new permits.” The delays over the USFWS permits are part of a series of regulatory hurdles MVP has faced in its effort to construct a route for Marcellus and Utica shale gas to travel southeast out of West Virginia to an interconnect with the Transcontinental Gas Pipe Line in southwestern Virginia.

Equitrans on track to finish Mountain Valley natgas pipe in early 2021(Reuters) – U.S. pipeline company Equitrans Midstream Corp said on Tuesday it remains on track to complete the $5.4-$5.7 billion Mountain Valley natural gas pipeline from West Virginia to Virginia early next year. That comment follows a decision by the U.S. Fish and Wildlife Service (FWS) to issue a new Biological Opinion on Sept. 4, which the project needs to resume construction. Mountain Valley is one of several U.S. oil and gas pipelines delayed by regulatory and legal fights with environmental and local groups that found problems with federal permits issued by the Trump administration. In February 2018 when Equitrans started construction of the 303-mile (488-km) pipeline designed to deliver 2 billion cubic feet per day of gas from the Marcellus and Utica shale, it estimated Mountain Valley would cost about $3.5 billion and be completed by the end of 2018. “We look forward to resolving the few remaining permitting issues, resuming forward construction,” Equitrans said. Equitrans has said it expects to receive new approvals soon from the U.S. Federal Energy Regulatory Commission (FERC) and the U.S. Army Corps of Engineers that will enable it to finish building the last 8% of the project. Analysts at Height Capital Markets said they expect FERC will lift its stop-work order in “coming days” and the Army Corps will reauthorize the project’s Nationwide Permit 12 to allow stream crossing “shortly thereafter.” “We expect environmentalists and other opponents will challenge each of these permit decisions … within 1-2 weeks of issuance,” Height Capital Markets said, noting “FERC and FWS have had nearly a year to review the permit, so it should be relatively insulated from legal challenges.” Other projects similarly held up include TC Energy Corp’s $8 billion Keystone XL and Energy Transfer LP’s Dakota Access crude pipelines, which are still involved in court battles.

Second defendant in Franklin County pipeline protest is fined | Crime News – A Massachusetts woman charged last year at the scene of a Franklin County protest against the Mountain Valley Pipeline has resolved her case with a fine.Melissa Dubois, 28, of Worcester appeared at a plea hearing Wednesday in Franklin County General District Court and was found guilty of trespassing. A related charge of tampering with a vehicle was dropped through her agreement with prosecutors.Dubois was ordered to pay a $100 fine plus $152 in court costs, according to Franklin County Assistant Commonwealth’s Attorney Ashley Neese.The exact details of what led to Dubois’ arrest were not immediately available, but she was charged Aug. 15, 2019, at the same time protester Amory Lei Zhou-Kourvo, 21, of Ann Arbor, Michigan, locked himself to pipeline construction equipment for a little over four hours.Zhou-Kourvo faced the same charges as Dubois but pleaded guilty in June to tampering with a vehicle and paid $189 in fines and court costs. Although he served nine days in jail after he was taken into custody, Neese said records indicate Dubois bonded out the day of her arrest. Dubois’ lawyer, Sandra Freeman, a Denver attorney who has worked from Blacksburg representing pipeline protesters, did not respond to a request for comment and additional information Thursday.

In Virginia battleground, natural gas pipeline projects face reversals – In Virginia, the future of natural gas depends on a highly volatile present. Since June, one pipeline project has shut down, two others suddenly find themselves on shaky footing and the natural gas industry as a whole continues to reel from a series of setbacks, including the bankruptcy of one of its largest firms. Utility giants Dominion Energy and Duke Energy shocked environmentalists in early July when they abruptly canceled the highly contentious Atlantic Coast Pipeline. The ACP was a massive $5.5 billion effort announced in 2014 to convey fracked natural gas 600 miles from West Virginia’s bountiful shale fields through central Virginia and into North Carolina. The utilities had acquired easements along most of the route and had already laid more than 30 miles of pipe in West Virginia. In Virginia, they had clear-cut trees, but hadn’t yet dug trenches or installed pipe. From the start, the ACP battled stiff legal challenges – largely based on natural resources, public health and environmental justice concerns – that swelled the project’s estimated cost to $8 billion. Ultimately, Dominion and Duke decided that ongoing delays, ballooning costs and persistent legal fights were just too much.The demise of the Atlantic Coast Pipeline eliminated a potential competitor for a different pipeline. “It has to work in favor of Mountain Valley Pipeline,” said Sreedhar Kona, a senior oil and gas analyst with Moody’s Investors Service. “That is, if MVP gets completed.” In August, the North Carolina Department of Environmental Quality rejected a key water-quality permit for the pipeline’s extension into the central portion of that state. The primary section of the pipeline will travel more than 300 miles from northwestern West Virginia to southern Virginia. Though outside the Bay watershed, the project has raised regional concerns over supporting the conveyance of gas harvested through the controversial technique of hydraulic fracturing, or fracking. “Resistance to this project is statewide,” Sims said.The pipeline’s developers were fined more than $2 million last year for environmental violations, and work has been largely halted since October 2019 while the U.S. Fish and Wildlife Service decided whether the project violates the Endangered Species Act. In southeastern Virginia, another pipeline is fighting its own headwinds. The $346 million Header Improvement Project would add 24 miles of 30-inch pipe along segments of an existing route from Prince William County in Northern Virginia south to the city of Chesapeake. It would build two huge gas plants in Charles City County, expand a compressor station in Caroline County and build two more stations in Prince William and Chesapeake. But the Virginia State Corporation Commission has declined to approve the project until its developer meets certain conditions. That company, Virginia Natural Gas, must show by the end of the year that it has firm financing to build the C4GT gas plant, which the HIP’s new pipeline would service. It must show it can recover the costs of the project during the period of its contract with C4GT and agree to a strict cap on costs to its customers.

Bleicher and Rubin: Lessons for Corporate Leaders from the Death of the Atlantic Coast Pipeline | Columnists – In July, after “almost six years of effort” and “billions of dollars,” Dominion Energy and Duke Energy abandoned their joint effort to build the Atlantic Coast Pipeline (ACP). Dominion CEO Thomas Farrell II said the decision reflects “the increasing legal uncertainty” for large pipelines even after the ACP’s recent victory at the United States Supreme Court. Farrell pointed to a Montana District Court decision throwing out water crossing permits issued by the U.S. Army Corps of Engineers, just the latest case in the continuing legal conflict between pipeline proponents and grassroots opposition. It seems more likely that Dominion finally recognized that the pipeline would soon be a worthless “stranded asset.” Consider the evidence: Warren Buffett’s Berkshire Hathaway just purchased Dominion’s natural gas transmission business, but wouldn’t take the ACP at any price. Why was the ACP such a fiasco? Because Dominion’s corporate leadership ignored the transformation of the business landscape by public dissatisfaction with government’s and industry’s failure to address climate disruption, destruction of natural habitat, and racial, economic, and environmental injustice. Its ACP demise announcement still asserts an inevitable future for “environmentally superior, lower cost natural gas-fired generation” and “widespread growing demand for residential, commercial, defense, and industrial applications of low-cost and low-emitting natural gas.” In 2020, those claims are manifestly incorrect. Natural gas is composed predominately from methane, a heat-trapping greenhouse gas 30 times more potent than carbon dioxide. New technology makes solar and wind electricity environmentally superior and more economical than natural gas. Residential and office building designers are phasing out natural gas. Heavy industry looks to reducing carbon emissions from making steel and cement. The Defense Department is pursuing efforts to reduce fossil fuels in its operations. Dominion’s indifference to the natural environment as it pushed the ACP provoked opposition everywhere. Dominion began buying and clearing forestland and farms even while other essential permits were still pending, using “quick take” laws to seize land from local landowners. Its operations fragmented pristine forests, ravaged prime farmland, and bulldozed sensitive and endangered species habitats – cleaving steep slopes, damaging waterways, and dramatically increasing landslide and water quality risks.Dominion’s obvious disregard for the environment and property rights led to fierce, well-organized, and highly visible opposition in rural Virginia, with irate environmentalists joining forces with community members outraged by the forcible taking of property and racial injustice. In the wake of the pipeline’s demise, questions of restitution to landowners and ecosystems loom large.

Weymouth compressor station starts testing – – The controversial natural gas compressor station in Weymouth has begun testing this week and, in the process, releasing natural gas into the atmosphere.The station, on the banks of the Fore River, is being built by Enbridge, a Canadian-based multinational energy transportation company. The compressor station is part of Enbridge’s Atlantic Bridge project, which would expand the company’s natural gas pipelines from New Jersey into Canada.The testing began on Tuesday and will run through Oct. 1. In addition to testing for leaks and calibrating piping, the station will complete an emergency shutdown test on Saturday. Enbridge said they will be venting the natural gas through a charcoal trailer to help reduce its characteristic smell. In order to test operation of the facility’s pipes, it has to purge air from the pipes using pressurized natural gas.”The testing activities will include occasional controlled venting of natural gas, testing the Emergency Shutdown System which is one of the many safety features designed to support safe operations, and testing and calibrating the turbine and other equipment and systems,” said Enbridge spokesman Max Bergeron in a statement. “These testing activities are a routine part of ensuring a newly-constructed compressor station is fit for service, and we are proceeding with health and safety as our priority.” Bergeron said during the testing of the emergency shutdown system, “there may be noise produced, similar to the sound of a jet engine, for a duration of several minutes on one or two occasions.”

U.S. natgas futures drop 7% with fall in crude prices, rising output (Reuters) – U.S. natural gas futures fell over 7% on Tuesday along with a similar drop in crude prices with an increase in gas output and forecasts for cooler weather and lower demand in late September. That gas price decline came despite a daily increase in liquefied natural gas (LNG) exports following hurricane shutdowns in late August and record sales to Mexico. Front-month gas futures fell 18.8 cents, or 7.3%, to settle at a two-week low of $2.400 per million British thermal units. That was the contract’s biggest one-day decline since early May, leaving the front-month down 13% from an eight-month high of $2.743 on Aug. 28. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to rise to 88.0 billion cubic feet per day (bcfd) in September, up from a three-month low of 87.6 bcfd in August. That is well below November’s all-time monthly high of 95.4 bcfd. With exports rising and temperatures expected to remain warmer-than-normal through mid September, Refinitiv projected U.S. demand, including exports, would rise from an average of 84.0 bcfd this week to 85.0 bcfd next week. That is higher than Refinitiv’s forecasts on Friday before the long U.S. Labor Day weekend. In late September, however, demand is expected to decline as air conditioning use drops as the weather cools. The amount of gas flowing to U.S. LNG export terminals was on track to rise over 1.0 bcfd to 5.0 bcfd on Tuesday, the biggest one-day gain since March, as Cheniere Energy Inc’s Sabine Pass plant in Louisiana continues to ramp up after shutting for Hurricane Laura. Pipeline exports to Mexico were on track to rise to 6.2 bcfd in September, topping August’s 5.9-bcfd record high.

U.S. natgas little changed as rising output offsets jump in LNG exports (Reuters) – U.S. natural gas futures held steady on Wednesday as rising production and forecasts for lower air conditioning demand in late September offset a jump in liquefied natural gas exports and record sales to Mexico. After dropping over 7% on Tuesday, front-month gas futures rose 0.6 cents, or 0.3%, to settle at $2.406 per million British thermal units on Wednesday. Data provider Refinitiv said output in the Lower 48 U.S. states was on track to rise to 87.9 billion cubic feet per day (bcfd) in September, up from a three-month low of 87.6 bcfd in August. That, however, was still well below November’s all-time monthly high of 95.4 bcfd. With exports rising and expectations for warm weather through mid September, Refinitiv projected U.S. demand would rise from an average of 84.0 bcfd this week to 85.8 bcfd next week. That is higher than Tuesday’s forecast. In late September, however, demand is expected to decline as air conditioning use drops with the weather forecast to turn seasonably cooler. The amount of gas flowing to U.S. LNG export terminals soared by a record 1.8 bcfd on Tuesday as Cheniere Energy Inc’s Sabine Pass plant in Louisiana continues to ramp up after shutting in late August for Hurricane Laura. Average flows so far in September were 4.1 bcfd. That puts gas piped to LNG plants on track to rise for a second month in a row in September for the first time since February when average flows hit a record 8.7 bcfd. Coronavirus demand destruction caused U.S. LNG exports to drop every month from March to July when flows to plants fell to a 21-month low of just 3.3 bcfd as buyers canceled cargoes. U.S. pipeline exports to Mexico, meanwhile, were on track to rise to 6.1 bcfd in September, which would top August’s 5.9-bcfd record.

US working natural gas volumes in underground storage rise by 70 Bcf: EIA | S&P Global Platts – US natural gas volumes in storage increased roughly in line with the five-year average last week, prompting a dip across the board in Henry Hub futures, as similar additions loom for the weeks ahead. Storage inventories increased by 70 Bcf to 3.525 Tcf for the week ended Sept. 4, the US Energy Information Administration reported the morning of Sept. 10. The injection was more than an S&P Global Platts’ survey of analysts calling for a 64 Bcf build. Responses to the survey ranged from an injection of 54 Bcf to 72 Bcf. The injection measured less than the 80 Bcf build reported during the same week last year but just above the five-year average gain of 68 Bcf, according to EIA data. Storage volumes now stand 528 Bcf, or 17.6%, more than the year-ago level of 2.997 Tcf and 409 Bcf, or 13%, more than the five-year average of 3.116 Tcf. The last remaining summer contract this year, October, has come under downward pressure in the last two weeks as supplies continue to rise amid flagging demand. The October NYMEX Henry Hub contract was trading around $2.39/MMBtu following the release. This represents a drop of nearly 20 cents from where it closed last Friday, and more than 30 cents lower than the peak of $2.71 it hit on Aug. 27. The winter strip, November through March, has traded relatively steady around the $3.20/MMBtu level in the last several weeks but dipped slightly during Sept. 10 trading to $3.17/MMBtu. The injection doubled the 35 Bcf injection estimate reported by the EIA for the week ended Aug. 28. Total supplies came in 800 MMcf/d lower on the week at an average 90.1 Bcf/d. After accounting for offsetting movements between onshore and offshore production volumes, the supply decline was driven by a 900 MMcf/d drop in net Canadian imports, according to Platts Analytics. Total demand suffered sharper losses, with the gas-fired power sector shedding an average of 5 Bcf/d from the week earlier. S&P Global Platts Analytics’ supply and demand model currently forecasts a 61 Bcf injection for the week ending Sept. 11. This would lower the surplus to the five-year average by 16 Bcf as about nine net weekly injections remain before the flip to the winter withdrawal season. Offshore production and LNG feedgas continue to make steady gains from the losses related to Hurricane Laura. However, cooler weather and falling power burn were the main factors contributing to bearish sample injections in the US Gulf Coast this week.

Record Southeast gas storage levels hit pause on rally in Henry Hub forwards | S&P Global Platts – Gas storage levels in the US Southeast are setting record highs recently as continued weakness in LNG feedgas demand and a rapid rebound in offshore production leave the region awash in supply. On Sept. 10, Southeast inventories were estimated at 585 Bcf – their highest on record for the third consecutive day, data compiled by S&P Global Platts Analytics shows. Within the US Energy Information Administration’s South Central region, which includes Texas but omits states along the southeastern seaboard, storage inventories were estimated Sept. 10 at 1.24 Tcf as of the week prior – just 130 Bcf below their own record-high level recorded in November 2016. As many Gulf Coast and Southeast storage caverns test their capacity limits, forwards markets at the Henry Hub are taking notice, pausing the rally in balance-of-year gas prices. On Sept. 9, fourth-quarter strip prices at the benchmark hub pulled back to an average $2.84, down from an annual high in early September at $2.95/MMBtu, S&P Global Platts’ most recently published M2MS forwards data shows. Elevated storage levels in the Southeast and flagging bullish sentiment in the forwards market come as US LNG feedgas demand remains well below pre-pandemic highs recorded in the first quarter. On Sept. 10, total US feedgas demand was estimated at 6.8 Bcf/d, its highest since early May, but still significantly below late-March highs at over 9.6 Bcf/d, Platts Analytics data showed. Heading into October, gas demand at export terminals in the Southeast and Texas should continue rising as cargo cancellations for the month dwindle to fewer than 10, according to prior reporting by S&P Global Platts. Still, over the past two weeks, total US feedgas demand, most of which is concentrated along the Gulf Coast, has averaged only about 4.1 Bcf/d as it comes under pressure from an estimated 26 cargo cancellations this month and from recent terminal shut-ins caused by Hurricane Laura. As the Gulf Coast region continues to recover from the storm, offshore production has also rebounded quickly, pushing additional supply onshore at a time when the region least needs it. On Sept. 10, output from the Gulf of Mexico edged up to an estimated 2.46 Bcf/d, now roughly at par to its pre-storm level, data from Platts Analytics showed.

U.S. natgas falls to 4-week low on cooler forecasts, normal storage build (Reuters) – U.S. natural gas futures fell on Thursday to a four-week low on forecasts for cooler weather and less air conditioning demand next week than previously expected. That decline came despite a continued increase in liquefied natural gas exports, record sales to Mexico and a report showing an expected, near-normal storage build last week. The U.S. Energy Information Administration (EIA) said U.S. utilities injected 70 billion cubic feet (bcf) of gas into storage in the week ended Sept. 4. That was close to the 68-bcf build analysts forecast in a Reuters poll and compares with an increase of 80 bcf during the same week last year and a five-year (2015-19) average build of 68 bcf. Front-month gas futures fell 8.3 cents, or 3.4%, to settle at $2.323 per million British thermal units, their lowest close since Aug. 13. That is down 15% from an eight-month high of $2.743 on Aug. 28. Even though the weather is expected to turn cooler in mid-September, Refinitiv projected U.S. demand would rise to an average of 85.4 billion cubic feet per day (bcfd) next week, from 84.0 bcfd this week, due to an increase in exports. That forecast, however, is lower than Refinitiv’s projection on Wednesday. The amount of gas flowing to U.S. LNG export terminals was on track to rise for a second month in a row in September for the first time since February as Cheniere Energy Inc’s Sabine Pass plant in Louisiana ramps up after shutting in late August for Hurricane Laura. Coronavirus demand destruction caused U.S. LNG exports to drop every month from March to July when flows to plants fell to a 21-month low of 3.3 bcfd as buyers canceled cargoes. U.S. pipeline exports to Mexico, meanwhile, were on track to rise to 6.1 bcfd in September, which would top August’s 5.9-bcfd record.

U.S. natgas futures fall to fresh 4-week low on cooler forecasts (Reuters) – U.S. natural gas futures fell more than 2% to a fresh four-week low on Friday on forecasts for cooler weather and lower air-conditioning demand over the next two weeks than previously expected. That price decline came despite a continued increase in liquefied natural gas (LNG) exports and record sales to Mexico. Front-month gas futures fell 5.4 cents, or 2.3%, to settle at $2.269 per million British thermal units, their lowest close since Aug. 13 for a second day in a row. For the week, the front-month dropped about 12% in its biggest weekly decline since March. Data provider Refinitiv projected demand in the Lower 48 U.S. states would rise from an average of 84.0 billion cubic feet per day (bcfd) this week to 84.9 bcfd next week as exports increase, before slipping to 83.6 bcfd in two weeks due to a seasonal cooling of the weather. Those forecasts are lower than Refinitiv’s projections on Thursday. The amount of gas flowing to U.S. LNG export plants was on track to average 4.5 bcfd in September. That is the most in a month since May and is up for a second month in a row for the first time since hitting a record high of 8.7 bcfd in February. That LNG-export gain comes as Cheniere Energy Inc’s Sabine Pass in Louisiana keeps ramping up after shutting in late August for Hurricane Laura and as global gas prices rise, making U.S. gas more attractive in Europe and Asia following months of U.S. cargo cancellations due to coronavirus demand destruction. Cameron LNG’s export plant in Louisiana, however, has remained shut since Aug. 27 when Laura struck the southwestern Louisiana coast. U.S. pipeline exports to Mexico, meanwhile, were on track to rise to 6.1 bcfd in September, which would top August’s record 5.9 bcfd.

Lower natural gas demand for US Midwest this winter looks to offset supply losses | S&P Global Platts – Elevated natural gas storage volumes and lower demand looks to offset decreased supply flowing into the US Midwest this winter, but Chicago prices could strengthen if the region pulls more gas from the Southeast to mitigate supply losses. Total Midwest supply is expected to fall in winter 2020-21 from the previous winter on declining Bakken Shale production and lower inflows. Total production in the region last winter averaged 2.3 Bcf/d, but should fall to 2 Bcf/d this coming winter, according to S&P Global Platts Analytics. While Bakken production has recovered much since March’s price collapse, production is still expected to be 257 MMcf/d below winter 2019-20 levels, at 1.8 Bcf/d. Additionally, lower production in surrounding regions has reduced supply to the Upper Midwest. Of particular note is Oklahoma’s SCOOP/STACK play, where production has not rebounded as initially expected after 2020’s price and production plummet. Production is expected to average 5.9 Bcf/d, down 1.8 Bcf/d from last winter. Rockies production is expected to decline 1.3 Bcf/d year on year this winter to 7.7 Bcf/d. This is forecast to reduce inflows from the Rockies to the Midwest by 439 MMcf/d to 1 Bcf/d. Total inflows from the SCOOP/STACK, Rockies, Northeast and Western Canada are therefore expected to decline by a total of 1.8 Bcf/d this winter from last. Outflows to East Canada are expected to decline 750 MMcf/d, partially offsetting lower supply from surrounding regions. Net flows to the Midwest should falter to 10.9 Bcf/d from 12.2 Bcf/d last winter, according to Platts Analytics. Lower demand should help mitigate some of this supply loss. Total demand is forecast to average 17.9 Bcf/d this winter, down 522 MMcf/d year on year. While residential and commercial demand is expected to pick up from last winter by 153 MMcf/d, gas-fired power generation is expected to decline by 421 MMcf/d. Industrial demand is also expected to decline by 243 MMcf/d. The Midwest region can also rely more heavily on storage to resolve supply loss. With 924 Bcf in storage, working gas volumes stand 12% above the year-ago level as well as the five-year average at this time of the year, according to the US Energy Information Administration. If stocks in the region build at the five-year average rate, storage will peak at 1.136 Tcf, which is only 18 Bcf less than the all-time high set in 2016.

PAC challenging SC’s Graham over offshore drilling stance (AP) – Offshore drilling, an issue that has created some bipartisan unity in South Carolina among opponents who argue such expansion would mar the state’s pristine coastline, is surfacing in a political action committee’s effort to oust U.S. Sen. Lindsey Graham. As the state’s beaches teem with visitors on Labor Day, Lindsey Must Go PAC is flying a plane up and down the South Carolina coast, with a trailing banner reading “L. Graham Will Drill 4 Oil Here.” Officials with the PAC say the plane expenditure and an accompanying digital ad decrying Graham’s support for drilling expansion legislation and alleged ties to the oil industry, are part of a six-figure buy over the next two weeks, now that the campaign has entered its final two months and voters are starting to tune in. “Graham has been all over the map on drilling. His position shifts as quickly as the tide shifts,” Jimmy Williams, a consultant who works with the PAC, told The Associated Press. “Jaime Harrison has had one position on drilling: Hell no.” Harrison is the Democratic opponent for Graham’s seat. “This false attack is an attempt to distract the people of South Carolina from Jaime Harrison’s record as a high-paid, liberal lobbyist for BP, the company responsible for the largest oil spill in U.S. history,” said Graham campaign spokesman T.W. Arrighi. “Harrison’s environmental record can be summed up in two words – dirty and oily.” Harrison, an associate chairman with the Democratic National Committee, lobbied for BP in 2010 while employed by the Podesta Group, according to filings with the Center for Responsive Politics.

Trump pauses oil drilling off SC, Georgia, Florida after years of support – President Donald Trump announced on Tuesday an oil drilling moratorium off the coasts of South Carolina, Georgia and Florida, a reversal after stripping a drilling ban put in place by his predecessor. Trump signed an order in an afternoon event that he said would lengthen a drilling moratorium on the west coast of Florida and expand it to the Atlantic coasts of all three states. The text of the order says that it takes effect on July 1, 2022, and applies for the following 10 years, but it’s unclear what that means in South Carolina before that date.Like all presidential orders, it could be changed under a new president.”This protects your beautiful Gulf and your beautiful ocean, and it will for a long time to come,” the president said at the event, adding that the country had found a way to produce enough energy by other means, including hydraulic fracking for natural gas. Environmental advocates, however, are not taking Trump’s announcement at face value. “We’ll be looking for specific actions, in court or in federal agencies, to show that this is more than words,” said Alan Hancock of the Coastal Conservation League. Trump made his announcement in Florida, a battleground state for the presidential election where public opinion is staunchly against drilling. Floridians passed a constitutional amendment in 2018 banning rigs in state waters. An existing federal moratorium along its Gulf Coast was set to expire in 2022, and Trump expanded that prohibition with his Tuesday action. In South Carolina, 56 percent of the state opposes offshore drilling, according to a 2019 Winthrop University poll. Much of that opposition is focused at the coast, where businesses depend on natural beauty to bring tourists, and the memory of the 2010 Deepwater Horizon oil spill in the Gulf of Mexico looms large.

Trump expands ban on new Florida offshore drilling sites – President Donald Trump brushed back critics of his record on the environment in the crucial swing state of Florida Tuesday during a visit to Palm Beach County by signing a presidential order that extends and expands a ban on drilling off the state’s coastline. The order – which Trump signed atop a stage not far from the mouth of the Loxahatchee River – extends by 10 years the life of a moratorium that prohibited drilling in federal waters off Florida’s Gulf Coast until 2022. He said it also expanded the ban to include the Atlantic Coast off Florida, Georgia and South Carolina. “Thanks to my administration’s pro-American energy policies, we can take this step and the next step while remaining the No. 1 producer of oil and natural gas anywhere in the world,” Trump said, appearing at the Jupiter Inlet Lighthouse and Museum. But even before Trump made the announcement, Democrats began criticizing his motives and warning that executive orders can be easily overturned. In a video conference with reporters Tuesday morning, Congresswoman Lois Frankel, D-West Palm Beach, said the expected Trump order banning drilling was a self-serving campaign ploy. “He obviously knows it’s a politically devastating issue to support drilling off of Florida,” she said. “You can not believe anything he says.” The order also drew criticism from the National Oceanic Industries Association, the offshore drilling industry’s lobbying arm. “Our preference should always be to produce homegrown American energy, instead of deferring future production to countries like Russia and Iran,” the association said in a statement.

Judge in SC wants explanation of Trump’s contradictory orders on offshore oil drilling – A federal judge wants to know how President Donald Trump’s order banning oil drilling off South Carolina affects five companies trying to search for fuels off the state’s coast. The answer could spell the end to a lawsuit that was put in motion, in part, by the president trying to open offshore exploration along the U.S. south Atlantic coast three years ago. Separately, an exploration company told the federal government last week it was no longer trying to search in the Atlantic. The lawsuit includes two consolidated cases, though both ask the judge to strike down federal permits for companies that search for oil. One suit was filed by nine environmental groups, and one was filed by 16 cities and towns around the state, along with the S.C. Small Business Chamber of Commerce. U.S. District Judge Richard Gergel asked the federal government to explain how Trump’s most recent move on Tuesday relates to a 2017 executive order directing federal agencies to “encourage energy exploration and production,” including in the federal waters off of South Carolina. The government has 10 days to respond. “The Government has disclosed no purpose for the proposed seismic testing other than to facilitate oil and gas development off the East Coast of the United States,” Gergel wrote. A spokeswoman for the federal fisheries agency being sued in the case declined to comment on the litigation. On Tuesday, the president moved in the opposite direction, saying he was putting the waters around Florida, Georgia and South Carolina under a drilling moratorium. His official memorandum says the ban will start in 2022 and end in 2032. Five companies had already received the first needed permit to do seismic air blasting, however, with pending applications for the second and final one. One of them, Texas-based WesternGeco, was further behind in the permitting process but told the Bureau of Ocean and Energy Management on Sept. 4 that it was withdrawing its application entirely, according to a letter the company wrote.

NC excluded from Trump moratorium on offshore drilling – President Donald Trump signed an executive order Tuesday in Florida imposing a 10-year moratorium on offshore drilling in waters from Florida to South Carolina, leaving North Carolina open to potential activity. Under the order, leases of areas along the coasts of Florida, Georgia and South Carolina for the purposes of offshore exploration or development are prohibited between July 1, 2022, and June 30, 2032. What is not clear is why the order omits North Carolina and Virginia, where residents have been vocally opposed to offshore drilling, often citing the potential impact to fisheries and coastal tourism. Sierra Weaver, a senior attorney in the Southern Environmental Law Center’s Chapel Hill office, said, “There has been no explanation for why to stop at the South Carolina line, and based on what we know, there is no basis for that decision at all. We all know there is every bit as much worth protecting here in North Carolina as below.” This week’s executive order is raising alarms among North Carolina environmental groups and the coastal communities that have almost unanimously stood in opposition to any proposal that would see exploration. The issue has largely been dormant since a March 2019 court decision. Erin Carey, the director of coastal programs for the Sierra Club’s North Carolina chapter, said, “I am very concerned, our allies are very concerned because we thought maybe we had a stay until after the (November 2020) election. … I think that this is definitely a signal that they’re still thinking about the plan, they’re still considering where they’re going to open and that political favors are not out of the question.”

Company seeking to conduct offshore seismic testing for oil and gas withdraws application – In a surprise move, the company that was seeking to conduct a seismic survey off the coast of North Carolina and other states for potential oil and natural gas appears to have decided to call it quits. WesternGeco, LLC. sent a letter to federal officials on September 4, withdrawing their application submitted in 2014. “The application requested authorization to conduct a geophysical survey on the Atlantic Outer Continental Shelf,” said Adil Mukhitov, vice president with WesternGeco in a one paragraph letter to the U.S. Bureau of Ocean Energy Management. “BOEM has not yet granted or denied the application. Please consider the application withdrawn,” Mukhitov said. This comes two weeks after Governor Roy Cooper announced the state would appeal the decision in June by the U.S. Secretary of Commerce to override North Carolina’s objection to WesternGeco’s plan for offshore seismic testing. Opponents to offshore testing and drilling expressed cautious optimism. “This move is certainly gratifying, and adds to the feeling that the wheels may be coming off the grand Atlantic drilling plan – which just means we opponents need to redouble our efforts,” said Nags Head Mayor Ben Cahoon. “It’s not over until it’s over!”

Oil pollutes Chattahoochee River after fire at Smyrna power plant – Something between hundreds and thousands of gallons of oil were discharged into the Chattahoochee River as a result of the explosion and fire at a Smyrna power plant last weekend.The Chattahoochee Riverkeeper organization said on Facebook that as many as 1,000-4,000 gallons of oil were discharged into the waterway during the incident at Georgia Power’s Plant McDonough-Atkinson on Sunday, as firefighters fought the blaze.The group shared with 11Alive a U.S. Environmental Protection Agency Emergency Operations Center spot report from which it got the estimate. That report was published Tuesday morning.Georgia Power however contended it was a much lower figure, saying that, “our calculations indicate very conservatively that approximately 250 gallons of oil entered the river.” 11Alive has reached out to the Georgia Department of Natural Resources and U.S. EPA to try and confirm an updated figure. Power transformers often have oil present for internal cooling and insulation purposes. A Cobb County Fire spokesman confirmed the oil present in the transformer was released and caught fire in the explosion and washed into the river through the firefighting efforts. Georgia Power said “most of the oil in the transformer was contained onsite.” Georgia Environmental Protection Division and United States Environmental Protection Agency were on scene, and downstream drinking water plant operators were notified,” the Chattahoochee Riverkeeper group wrote on Facebook. “Some firefighting chemicals, which included foam suppression product that was used due to the nature of the oil being on fire, also washed into the river. Georgia Power said that “comprehensive response activities began immediately once the fire was extinguished” and “the company aggressively began working to assess, limit and remove this oil from the river.”

‘It was a huge explosion:’ Gas line rupture sparks massive fire in Sanford – A massive fire erupted early Thursday in Sanford when a gas line ruptured, prompting officials to evacuate more than 800 nearby homes. The fire broke out around 1 a.m. near Michigan Avenue and Oregon Street, west of I-4 near the St. Johns River. A ball of smoke and flames shot 200 feet into the sky for nearly two hours, with News 6 viewers saying they could see flames and smoke from miles away. Fire officials said they received so many calls about the fire that they had difficulty pinpointing the exact source of the blaze. Crews discovered the ruptured 12-inch gas line in a remote area near the Black Bear Wilderness Area. Seminole County officials said went to restore service at 10 p.m. on Thursday. The Florida Gas Transmission vented the line that was damaged. Officials said only air will be vented, not gas. This caused a loud hissing sound for approximately 30 minutes, according to officials.Multiple people called 911 to report the blast.”I don’t know if it’s a house on fire. It was a huge explosion,” one woman said.She told the operator she looked from her backyard and all she could see was flames.Another woman described the fire as a “massive blaze.”” “You can’t miss it, it’s over the treeline,” she said. Florida Public Utilities Co. said the incident involved an interstate pipeline not owned by the company caused FPU to lose its natural gas feed service to customers in parts of Seminole County.”Areas impacted included Sanford, Longwood, Lake Mary, and Winter Springs. FPU had to proactively interrupt service to some sections of its system to ensure system integrity.

Hurricane hit oil storage site, but no shortages expected (AP) – Hurricane Laura caused significant damage at a site holding about 30% of the nation’s store of emergency crude oil, but three other sites still have plenty of petroleum, U.S. Energy Secretary Dan Brouillette said Wednesday. The damaged Strategic Petroleum Reserve site in West Hackberry, Louisiana, holds nearly 8.2 billion gallons (31 billion liters) of crude oil in 21 huge caverns deep underground. Brouillette did not specify the exact nature of the damage or say how much it would cost to fix it, but said he planned to tour it later Wednesday. More than any worries about damage to the federal repository, “My concern is with the people who work at that site” because so many homes were damaged and destroyed, Brouillette said during a livestreamed news conference with Louisiana Gov. John Bel Edwards. “Restoring power is our top concern right now,” Edwards said. He noted that 90% of Calcasieu Parish, the most populous parish in the southwest Louisiana area where the storm slammed ashore, remains without power. Brouillette also said that because the COVID-19 pandemic has reduced demand for oil and gas so much, there is no shortage of gasoline, jet fuel and other refined products, even though two large refineries in the Lake Charles area haven’t been able to reopen since the hurricane. Citgo and Phillips 66 have large refineries in the area; a third, run by Calcasieu Refining, is much smaller. Edwards and Brouillette spoke after a closed roundtable discussion with the owners of the large Lake Charles refineries and officials from the Port of Lake Charles, utility companies and three state agencies. Edwards said that one of those refineries shut down for the second time in 76 years. “But because they shut down the way they did, they did not suffer catastrophic damage,” he said. Brouillette said some refineries expect to resume operation as soon as power has returned. “We are still weeks away from total restoration,” Edwards said. He said the big problem is that Laura damaged or destroyed 1,000 or more power transmission towers. “These are very, very difficult things to replace,” he said.

Hurricane Laura’s Aftermath: Miles of Oil Sheen in Louisiana’s Wetlands | DeSmog – (photos) Almost a week after Hurricane Laura struck Louisiana’s coast, which is studded with oil and gas industry pipes, tanks, wells, and rigs, I photographed from the sky oil sheen along at least 20 miles of marsh and bayous that absorbed the full strength of the storm. Scientists say warmer ocean waters due to human-caused climate change is making hurricanes like Laura stronger and causing them to intensify more rapidly; Hurricane Laura spun up to a Category 4 storm in just 24 hours. For miles along the western Louisiana coastline near the Texas border, I spotted large swathes of land and water that appeared coated with oil, visible as the floodwaters receded between the small communities of Grand Chenier and Cameron. On September 2 and 3, I also documented oil sheen in waterways along the bayous from Cameron north to the city of Lake Charles and as far east as New Iberia, roughly 130 miles west of New Orleans.How much oil did Hurricane Laura’s impact cause to spill with its powerful winds, rain, and storm surge? While the storm made landfall on August 27, Louisiana Department of Natural Resources (DNR) spokesman Patrick Courreges told DeSmog it is still too early to assess the storm’s damage. “We are just 10 days out,” Courreges said by phone on September 8.NOLA.com reported on August 27 that federal and state emergency responders would focus first on search-and-rescue operations before eventually pursuing oil spill inspections and possible cleanups.While the hurricane’s storm surge was not as high as initially predicted, its coastal flooding and 150 mile-per-hour winds still left a trail of devastation. Given the more than 1,400 oil wells in Hurricane Laura’s path, I was not surprised to find slicks of oil along the coast after the storm. However, the vast area of coastline now shimmering with oil and crumpled metal was a reminder of what any strong storm can do when it collides with the area of the Gulf Coast dotted with oil and gas production sites. Louisiana has to worry not only about its active oil and gas wells, but also its thousands of orphaned wells, which are no longer in production and have been abandoned by their former owners. On September 2, I shot photos of some of the damage left in Laura’s wake for the Louisiana Environmental Action Network(LEAN), a nonprofit environmental advocacy group. The next day, David Levy, owner of Petrotechnologies and founder of the Free Iberian Press, took me on a flight to shoot impacts to the coast for DeSmog, covering some of the same ground.

Oil and gas companies try again for federal court venue – Oil and gas companies are asking a federal appeals court to reconsider its decision that parish lawsuits alleging damage of coastal wetlands should be heard in state court. A three-judge panel of the New Orleans-based U.S. Court of Appeals for the Fifth Circuit in August unanimously rejected the companies’ argument that the case belongs in federal court. The defendants are asking the panel and the court as a whole to review that decision. In 2013, local governments in Louisiana’s coastal region filed lawsuits against more than 200 oil and gas companies, seeking compensation for damage they say the companies caused to the region’s wetlands. The companies say they followed their permits and the law as it stood at the time. The Fifth Circuit panel’s ruling last month only applied directly to lawsuits by Plaquemines and Cameron parishes, though it could have broader implications given the similarities shared by the various lawsuits, experts say. The decision focused on an expert report Plaquemines Parish produced in 2018 that notes some of the alleged damage dates back to World War II. At the time, the companies argue, they were under strict wartime regulation and essentially were acting as agents of the federal government. That raises a federal issue, which means the cases should be heard in federal court, they say.

State pols support rescinding Columbia Gas emergency While state lawmakers from the Merrimack Valley cheered Gov. Charlie Baker’s recent decision to rescind the state of emergency due to the Columbia Gas disaster, they cautioned that the region remains scarred and still needs help. On Tuesday, the Baker-Polito Administration terminated the state of emergency — nearly two years after it was declared by Baker. On Sept. 13, 2018, overpressurized gas lines led to high pressure gas being injected into homes and businesses in Andover, North Andover and Lawrence. It led to fires, explosions, dozens of injuries and the death of Lawrence teen Leonel Rondon. The crisis resulted in the displacement of thousands of residents across the region, some who fled their homes on foot. Businesses in the impacted area were shut down for months as Columbia Gas replaced miles of gas pipeline and thousands of gas-powered furnaces, ovens, hot water heaters and other appliances. When it was safe to return, many residents lived for months in homes without working stoves, heat or hot water. The decision to rescind the state of emergency essentially hands responsibility for continued management of the incident to the Department of Public Utilities, or DPU, as it authorizes DPU chairman Matthew Nelson “to take any action necessary to ensure public safety and welfare and restore gas, electric, and water utility services,” according to a press release issued Tuesday by the Executive Office of Energy and Environmental Affairs.

New: Line 5 east leg not damaged, internal tests show ⋆ The eastern segment of the dual Line 5 oil pipeline in the Straits of Mackinac did not sustain damage during an incident that left an anchor support significantly bent, according to a court-ordered internal test. Canadian oil company Enbridge had been allowed to restart the east leg to complete an in-line inspection (ILI) on the segment on Aug. 24, thanks to a new amended temporary restraining order (TRO) ordered by Circuit Court Judge James Jamo. The east leg ILI was completed one day later. “The amended TRO allowed us to start the segment just to run the ILI. We submitted the results to PHMSA [Pipeline and Hazardous Materials Safety Administration] and they are reviewing them now. The results showed no dents and no metal loss,” Enbridge spokesperson Ryan Duffy said Friday. The same test had been performed on Line 5’s west segment in early July. Those results had also come back without any indication of pipeline damage. The west line has been in operation since then, but the east portion under the Straits of Mackinac remains shut down until further orders from the court. “PHMSA has reviewed those results and issued a letter today stating that it has no objection to Enbridge restarting the line. However, the pipeline cannot be restarted until the Court also approves. Our office’s review of the test results is ongoing,” said Ryan Jarvi, spokesperson for Attorney General Dana Nessel.

Enbridge just wants a permit. Michigan critics want to bring down Line 5 — Enbridge Energy had already won the blessing from Michigan’s Republican Legislature to build a tunnel beneath the Straits of Mackinac to keep oil flowing through Line 5, and survived a legal challenge that sought to unravel that plan. Now, a seemingly minor detail of the $500 million, multi-year tunnel project – getting a state commission’s permission to move a 4-mile segment of pipeline inside the tunnel – could give environmental activists and Native American tribes an opening to litigate broad objections to the pipeline and, they hope, shut it down completely. As the Michigan Public Service Commission begins a yearlong analysis of the relocation request, Line 5 opponents say they’re seeking a comprehensive review of the pipeline that has so far been missing from Michigan’s deliberations over the 67-year-old pipeline’s fate. “What we’re really discussing is allowing this pipeline to continue to exist for the next century.” Gravelle and other Line 5 opponents want the commission’s deliberations to include everything from Michigan’s long-term energy needs to climate impacts from continuing to transport fuel through Line 5, to safety and environmental concerns tied to the existing pipeline and the planned tunnel.Building the tunnel itself will be complicated and costly: Enbridge has estimated it will cost $500 million and take until 2024 to complete, although state regulators expect it to take significantly longer. Enbridge had hoped the process of moving the pipe inside the tunnel would be far easier. This spring, as Enbridge sought state permits for tunnel construction, it asked the Michigan Public Service Commission to agree that the company doesn’t need permission to move the pipeline inside the tunnel once it is built. The commission, which oversees the siting of pipelines within Michigan, rejected that argument. Instead, it launched a lengthy administrative review similar to a court proceeding, in which Enbridge and its opponents will litigate a key question the energy company thought it had moved past: Does Michigan need Line 5?

Judge- Enbridge can resume full operations on Michigan Line 5 pipeline – An Ingham County judge has given Enbridge Energy clearance to resume normal operations of Line 5 in the Straits of Mackinac, lifting a partial shutdown that had been in place for months after Enbridge discovered damage to an anchor support on the pipeline in June. Judge James Jamo approved the re-start in a revised restraining order issued Wednesday at Enbridge’s request. It came with the consent of state lawyers who had asked for the shutdown in the immediate wake of the damage, after federal regulators and an independent expert retained by the state concluded the pipeline was not structurally damaged. The order comes days after federal regulators with the federal Pipeline and Hazardous Materials Safety Administration, or PHMSA, notified Enbridge on Sept. 4 that the agency and outside experts had reviewed inspection records for the east leg and “did not identify any integrity issues” on the east leg, where an anchor support had been wrenched out of place. As a result, William Rush, PHMSA’s acting director for the region encompassing Michigan, wrote that federal regulators had “no objection” to the company resuming operations on the east leg. Enbridge spokesman Ryan Duffy said the company plans to resume petroleum transports in the east leg by Thursday afternoon. In reality, the reopening may mean little for Enbridge’s customers. Enbridge had previously told Bridge the partial shutdown did not impact its ability to deliver petroleum, because the company was able to meet existing demand using only the west leg of the dual-span line. Duffy said that remains true today. The news comes more than two months after Jamo ordered the pipeline shut down June 25, acting on a request from Michigan Attorney General Dana Nessel following revelations that an anchor support on the dual-span pipeline’s east leg had sustained damage from a then-unknown source. Enbridge and U.S. Coast Guard officials have since concluded that a contract vessel working for the company likely caused the damage. Nessel and other Line 5 opponents have long argued that the pipeline poses an unacceptable risk of an oil spill in the straits. Her temporary shutdown request is tied to a larger lawsuit in which she seeks to permanently shutter the pipeline by voiding the 1953 easement that gives Enbridge permission to operate Line 5 in the straits.

Coast Guard: Enbridge-contracted vessels likely responsible for scrapes to Line 5 – A U.S. Coast Guard official told environmental groups Friday that damage discovered to Line 5 earlier this year likely was caused by Enbridge-contracted vessels conducting work in the area to prepare for the construction of a utility tunnel. Enbridge earlier this year noted in a report that it had narrowed down to five the list of “small to moderately sized” vessels that could have dragged a cable in a north south direction over Line 5, scraped the east leg and damaged an anchor support. Four out of the five boats, Enbridge said at the time, had been contracted by the Canadian oil giant. Coast Guard Captain Anthony R. Jones of Port Sault Sainte Marie said his staff conducted its own review and came to similar conclusions. “I have concluded that the disturbances found by Enbridge Energy are reasonably attributed to incidental contact by cables or other equipment deployed or handled by vessels contracted by Enbridge to conduct work within the submerged pipeline area,” Jones wrote Friday. Enbridge Energy still is reviewing the incident and hasn’t reached a final determination about the cause, company spokesman Ryan Duffy said Tuesday. The company has implemented safety protocols to avoid vessel-induced damage to the line, including the identification of vessels traveling through the straits, patrol boats in the area, contact with at-risk vessels asking them to lift anchor or avoid crossing the straits, or a temporary shutdown of Line 5. “We have interviewed our own contractors working in the areas as part of our thorough investigation,” Duffy said. “As of now we can’t rule out their involvement.

EPA fines Michigan injection well owner $73K for ‘significant’ violations – Federal regulators plan to fine a northern Michigan oil and gas company $73,755 for keeping inaccurate records on injection well operation in four counties. Paxton Resources of Gaylord failed to properly monitor and report pressure on seven injection wells spread across Antrim, Alcona, Oscoda, and Otsego counties, according to a proposed U.S. Environmental Protection Agency (EPA) consent order. Form May 2014 to August 2016, Paxton failed to record and report weekly injection pressure, failed to monitor weekly annulus pressure and record accurate measurements, according to the proposed EPA order dated Aug. 27. Paxton also allowed an unauthorized employee to sign monitoring reports for four years, the EPA alleged. The EPA says those actions violate the Safe Drinking Water Act. In a public notice statement, the EPA called the alleged violations “significant” because accurate injection well pressure monitoring and reporting is “vital to protecting underground sources of drinking water” and ensuring wells “have mechanical integrity, are not leaking, and are being operated for the purposes for which they were permitted.” Class 2 wells inject brine from oil and gas production deep underground, either as wastewater disposal or to displace fossil fuels for extraction in the hydraulic fracturing, or fracking, process. Pressure monitoring helps detect leaks that could allow injected fluids to spurt back up the well casing and reach the level where groundwater is used for drinking. “Failing to take weekly annulus pressure measurements and submitting inaccurate reports were potentially serious impediments to the discovery of potential leaks and threats to underground drinking water sources,” the EPA wrote.

The Value of Human Life Must Have Priority in Oil & Gas Policies – When Texas Lieutenant Governor Dan Patrick said “There are things more important than living” about reopening businesses related to COVID-19, his comments quickly garnered national attention. Many people were shaken by the callous nature of the quote. However, Patrick was alluding to an often-taboo aspect of policy creation, the human cost of public policy. What made Patrick’s quote unique is that typically when talking about policy in this regard, politicians are not as forthcoming about the human collateral damage of their positions. For many who live near oil and gas operations, Patrick’s jarring comment betrays a mindset that feels tragically familiar. It is common to hear about how the benefits of relying on fossil fuels outweigh the risks posed by an inherently polluting form of energy. The part typically not said out loud is that “the risks” include health risks to real people – those who work for the industry who can be exposed to hazards with little or no protection as well as people who live close to, downwind, and downstream of wells, pipelines, processing plants, refineries, and more. Human life is often just another variable in a cost/benefit analysis. Texas lawmakers and oil and gas companies often tout the benefits of energy independence and free-market pursuit of a Texas-strong oil and gas industry. The implicit argument is that the people who become ill or die because of a polluter or a regulator’s actions (or lack thereof) are worth less than the upside benefits to the state and the nation. Energy independence is worth the rapid acceleration of climate change. Expanding a fossil fuel company’s profits is worth drilling next to a childcare center.Hearing a leader in Patrick’s position so casually put a value on human life can be disturbing, but it is clarifying. As a society, we are constantly evaluating the value of a human life when we make decisions on policies from the speed limit to acceptable side effects of medication. Many who live in the oil and gas “sacrifice zone” wonder how companies value a human life when they decide where to drill? How does the Texas Senate (of which Dan Patrick is the President) value a human life when they allocate money to the Texas Commission on Environmental Quality and the Texas Railroad Commission (the state agencies that oversee the oil and gas industry) for regulation, monitoring, and enforcement?

Big Fund Managers Urge Texas to Ban Most Flaring – — Investors managing more than $2 trillion are calling on Texas regulators to ban the routine burning of natural gas from shale fields, arguing that the energy industry hasn’t moved quickly enough to curb the controversial practice. AllianceBernstein, California State Teachers’ Retirement System and Legal & General Investment Management said they support eliminating gas flaring by 2025, according to a letter to the Texas Railroad Commission, which oversees oil and gas in the state. “Actions of leading operators demonstrate the financial and technical viability of ending routine flaring,” the fund managers said in the letter, which was seen by Bloomberg. “It is clear, however, that voluntary actions alone have been insufficient to eliminate routine flaring industry-wide.” Investors and environmentalists are increasingly drawing attention to flaring because of its wastefulness and contribution to climate change. Flaring is utilized around the world as a way to deal with gas that producers can’t — or don’t want to — transport or store. Much of what’s burned, especially in the shale fields of Texas, is so-called associated gas coming from oil wells. The sheer abundance of gas in the Permian Basin of West Texas and New Mexico means local prices for the fossil fuel are often so low that it’s cheaper for shale operators to burn it rather than pay for pipeline connections and storage. Last year the Permian flared enough gas to supply 5 million U.S. homes, according to Oslo-based Rystad Energy. The Texas Railroad Commission has come under attack for allowing companies to effectively flare at will over the past decade as shale production boomed and helped make the U.S. the world’s top oil producer. The commission allows companies to flare during the start-up of wells and during emergencies. It also issues waivers that can be utilized right through the early and most productive phase of a shale well’s operation. After more than a year of public pressure, the commission recently proposed requiring operators to provide information on why they need to flare, but it set no targets and resisted calls for an outright ban. Lower oil production due to the Covid-19 pandemic has meant flaring rates have dropped significantly this year, the commission said in a statement last month. “Strong and effective regulatory action — beyond initial steps to improve data gathering and transparency — is essential to build stakeholder confidence and solve this challenge across industry,” the investors said in the letter, which is part of the commission’s public consultation. LGIM, the U.K.’s biggest asset manager, oversees over 1.2 trillion pounds ($1.6 trillion). In May, LGIM said it would oppose the re-election of Darren Woods as Exxon Mobil Corp. chairman over what it called a lack of ambition on tackling climate change.

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