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...
meanwhile, 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....
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...
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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.
GOP Proposes Letting Fossil Fuel Firms Sue Sick Workers Seeking Compensation -Alexis Goldstein - Fossil fuel firms have long argued that addressing climate change will kill jobs — but the main entities killing oil and gas jobs lately have been fossil fuel firms.Rather than save jobs, oil firms have lined executive pockets just before declaring bankruptcy, and announced layoffs rather than cut into shareholder profits. Some oil workers are even dying on the job — and instead of increasing safety and transparency, oil companies have pushed Congress to make it impossible for workers and families to sue if they get sick due to unsafe conditions.We have seen this pattern before with the coal industry, which has long fought efforts to fund benefits to workers who contracted “black lung” in mines. Now, it’s oil and gas firms that are putting profits ahead of the lives of their own workers.The response of fossil fuel firms and the Trump administration alike to the potentially lethal working conditions for oil and gas workers has been to bury the data and prevent workers from suing. Fossil fuel giants like ConocoPhillips and Exxon lobbied Congress to grant them legal immunity should their workers get sick, as documented by Friends of the Earth. The liability shield proposed by Senate Republicans even allows firms to sue their own workers should they try and seek recompense if they get sick.
Crude oil pipeline expansion in Texas is canceled – Midstream operator Enterprise Products Partners LP on Wednesday announced it was scrapping its Midland to ECHO 4 pipeline expansion project in Texa, Kallanish Energy reports. The project was designed to move 450,000 barrels per day from the Permian Basin of West Texas and New Mexico to the Gulf Coast. The expansion project would have linked Midland in West Texas with Enterprise’s ECHO terminal in Houston, Texas. The cancellation comes as crude oil producers in North American have slashed production due to low prices and that has reduced demand for new pipeline capacity. Enterprise Products Partners said it has amended some contracts with customers to allow them to transport crude oil in its existing pipelines in the near term while extending the overall duration of the agreements. Last April, the company had pushed back the completion date for the project by six months to the second half of 2021, as part of a $2.1 billion cut to its 2020 budget. The company said the cancellation will reduce growth capital in 2020-2022 by about $800 million. The decision will also result in a $45 million impairment charge to third quarter 2020 earnings later this year, it said.
Oil Companies Rely On Controversial Firm To Rebut Colorado Health Study - One day after Colorado health officials briefed a state rulemaking panel on the potential health risks posed by oil and gas drilling, industry groups brought in an expert of their own to downplay the state's findings — and her comments were blunt. "My expert conclusion is that there's no credible, causal evidence that current setback distances need to be extended in order to minimize adverse health impacts," Tami McMullin, who previously served as a state toxicologist, told members of the Colorado Oil and Gas Conservation Commission in a Sept. 4 hearing.Since 2018, McMullin has worked as a senior toxicologist for the Center for Toxicology and Environmental Health, an Arkansas-based consulting firm with a long history of working closely with the fossil fuel industry — and an equally long history of controversy during which its work has drawn conflict-of-interest accusations.McMullin's comments to the COGCC came on behalf of the Colorado Oil and Gas Association ahead of a pivotal decision by the commission on whether, and by how much, to extend mandatory "setback" distances between occupied buildings and new wells. Industry groups are staunchly opposed to increased setbacks, and testimony submitted to state regulators in advance of the rulemaking included a private study "prepared for" COGA by McMullin and other CTEH researchers to help bolster their case.
Advocates: 2020 presidential election presents clear choice on energy for Colorado, US --The outcome of the presidential election will have a big impact on the energy front in Colorado a nd other oil- and gas-producing states.If U.S. voters decide to stay the course, the current push for energy dominance through increased drilling will continue. If they elect a new president, the challenger has pledged to end new drilling on public lands and move toward a carbon-free future.Whoever wins Nov. 3, any executive-branch attempts to change existing policy are likely to face legal challenges.Democratic challenger Joe Biden has vowed to immediately start addressing climate change if elected. The former vice president has a $2 trillion plan that includes expanding clean-energy jobs and greatly reducing fossil fuel emissions.President Donald Trump, who was officially nominated in late August as the GOP presidential candidate, has targeted oil and gas regulations he sees as burdensome to the industry.“There couldn’t be a more clear divide between the two perspectives about American energy production, particularly coal, oil and natural gas,” said Thomas Pyle, president of the American Energy Alliance, an advocacy organization that has endorsed Trump.President Donald Trump, third from left, with Energy Secretary Rick Perry, left, Shell Oil company President Gretchen Watkins, second from left, and Shell Pennsylvania Vice President Hilary Mercer, fourth from left, tour the Shell Pennsylvania Petrochemicals Complex in Monaca, Pa., on Aug. 13, 2019.A new poll released by the American Petroleum Institute-Colorado found that 57% of Colorado voters would be more likely to vote for a candidate who supports providing access to oil and gas produced in the United States. Still, given Colorado’s changing demographics, most political experts don’t expect Trump to win here. The president lost Colorado by 6 points in 2016, and a recent poll by Morning Consult — the same firm that did the API poll — showed Biden leading Trump 52% to 39% in Colorado. The two campaigns fundamentally differ on their stances toward drilling on federally managed lands. Roughly 36% of Colorado is federal land, and the state is the seventh-biggest energy producer in the country.Colorado is also considered a leader on renewable energy, with Gov. Jared Polis and legislators setting goals to cut greenhouse gas emissions and get to a 100% carbon-free electric grid.
More than 40 groups call for coronavirus protections for oil and gas workers - A coalition of more than 40 organizations is urging the federal government to take steps to protect workers at oil and gas facilities, as well as the communities surrounding the sites, from the coronavirus. In a letter to the Interior Department, Bureau of Safety and Environmental Enforcement (BSEE), Coast Guard and Occupational Safety and Health Administration (OSHA), the groups specifically call for monthly public reporting on COVID-19 testing and infection rates at oil and gas facilities. The coalition, which includes a number of environmental groups, also called for requiring companies operating the facilities to put forth coronavirus response plans and for the government to monitor and report on the implementation of these plains. The groups additionally asked OSHA to presume that some exposures are “work related” when reporting work-related illnesses. “The offshore oil industry presents a high risk for oil workers, as oil rig employees spend shifts working on site, sleeping and eating in tight quarters,” the groups wrote. “Onshore oil and gas workers, particularly those living in ‘man camps’ are also at risk from close contact on the job and in quarters.” “It is incumbent on federal regulators to investigate whether oil and gas operators are sanitizing workspaces, evacuating workplaces when necessary and adopting strict safety protocols such as temperature checks and frequent COVID-19 testing,” they added. Reports have shown that some oil and gas workers in the U.S. have tested positive for the virus. Meanwhile, other countries have seen significant impacts, including Mexico, whose state owned oil company has seen more than 200 employee deaths. The industry has also been hit by sinking prices because of a drop in demand linked to the pandemic. Asked for comment, Coast Guard spokesperson Brittany Panetta pointed The Hill to a March guidance issued by a regional office that has jurisdiction over the Gulf of Mexico coastline. The guidance states that operators "shall develop and be prepared to execute plans to evacuate offshore personnel exhibiting COVID-19 symptoms, and have them tested." It says they are "reminded to report the illness...or death to their respective Coast Guard Sector Command Center." OSHA and Interior, which oversees BSEE, didn’t immediately respond to The Hill’s request for comment.
Oil wells along Fort Berthold boundary subject of potential tax changes - More changes could be on the horizon regarding the way oil taxes are divvied up between the Three Affiliated Tribes and the state of North Dakota, as the tribe seeks revenue from all wells that straddle the boundary of the Fort Berthold Indian Reservation. Tribal Chairman Mark Fox, who has pushed to address this matter in the past, raised it again at a Friday meeting of the Tribal Taxation Committee at the state Capitol in Bismarck. At issue are 132 wells that begin outside the reservation and extend horizontally across the border. The tribe does not collect any tax revenue on those wells, as the money goes to the state. For wells that begin on the reservation and then cross the border, both the tribe and state share in tax revenue. Fox would like to see the tribe collect taxes from all wells at the border, not just the ones that begin on Fort Berthold. He told committee members, which include state lawmakers and the governor, that the issue is a matter of “realizing revenue for our government, just like you do for the wells that go both ways.” “The longer we wait, the more we lose,” Fox said. “That’s really a strong concern that we’ve got, that this needs to be resolved ASAP.” For wells that begin on the reservation and cross the boundary, the proportion of tax revenue that goes to the tribe and the state depends on whether the well passes trust or fee land. Trust land is held by the federal government in trust for the benefit of the tribe, and fee land refers to private land within a reservation. A major tax agreement struck in 2019 changed the percentage of taxes allocated for new wells drilled on Fort Berthold, depending on which type of land the well crosses. As committee members discussed the issue Friday, a potential solution emerged in which the tribe collects taxes on all wells that cross the border, but possibly not on the portion of a well that extends outside the reservation. Fox acknowledged that a solution might involve a “give and take,” in which the tribe loses some tax money collected on wells that reach land outside the boundary. He indicated that the tribe is researching how this matter is handled on oil-rich Indian reservations in other states. He said he would also like to see data showing how much money went to the state, historically, that could have gone to the tribe had an agreement been reached earlier allowing the tribe to share in tax revenue from wells that begin off the reservation.
Land Board again pushes back gas royalty payment deadline - The North Dakota Board of University and School Lands voted Wednesday to further push back the deadline dozens of oil patch companies face to pay the state for deductions taken from natural gas royalties.If a company wants to avoid penalties and owe just minimal interest, they must now pay by April 30, 2021. The money originally was due this past springuntil the Land Board voted to delay the deadline until Sept. 30 amid the oil downturn brought on during the coronavirus pandemic.Following a North Dakota Supreme Court ruling last year favorable to the state, officials estimated the state is owed tens of millions of dollars from companies that applied deductions for royalties stemming from mineral development on state-owned land. Royalty money collected by the state benefits education and public institutions. Gov. Doug Burgum suggested delaying the payment deadline againat the last Land Board meeting in August amid ongoing challenges facing the oil industry as low demand keeps oil prices down. Some oil producers are undergoing bankruptcy proceedings, and they face uncertainty over the Dakota Access Pipeline, he said Wednesday. A federal judge ordered the pipeline to stop operating this summer and although a higher court overruled that decision, litigation is ongoing. There also is uncertainty surrounding potential changes to the quality of natural gas accepted onto the Northern Border Pipeline, a major exporter for Bakken gas, Burgum said."Things are perhaps not better; they may be worse than they were last spring," he said.The Land Board voted unanimously to extend the deadline again following Wednesday's discussion, which took place in part during a closed session as the matter involves litigation.
PIPELINES: Tribes renew push to shutter Dakota Access -- Wednesday, September 9, 2020 -- Native American tribes opposing the Dakota Access pipeline are making a second bid for a federal court to shut down the crude oil pipeline.
Alaska Native tribes and 15 U.S. states file suits to stop oil drilling in Arctic refuge - Anchorage Daily News - Three Alaska tribal entities on Wednesday sued the Trump administration to stop the federal government’s first-ever oil and gas lease sale in the coastal plain of the Arctic National Wildlife Refuge. The Neets’aii Gwich’in tribes of Venetie and Arctic Village named Interior Secretary David Bernhardt and several federal agencies in the suit, filed in federal district court in Alaska. The Native Village of Venetie Tribal Government, the Arctic Village Council and the Venetie Village Council, represented by the Native American Rights Fund, filed the lawsuit to protect important traditional resources there, such as the caribou that are sought after by subsistence hunters. They challenge Bernhardt’s signing last month that finalized a plan that puts all available land, or 1.6 million acres in the coastal plain, on the table for possible leasing after Congress in 2017 agreed to open the area to drilling.
Washington leads suit against Arctic Refuge drilling -Washington will lead a coalition of 15 states challenging the Trump administration’s decision to open the Arctic National Wildlife Refuge for oil and natural gas production. State Attorney General Bob Ferguson said Wednesday a federal lawsuit filed in Alaska contends the decision to drill on the Coastal Plain violates federal laws, including the Administrative Procedures Act, which has been a basis of other successful suits he has filed. It also claims the decision violates the National Environmental Protection Act with a flawed environmental review. Opening the refuge to drilling is the latest example of president Donald Trump’s “assault on our environment,” Ferguson said. It would harm Washington by exacerbating the effects of climate change and devastate birds that migrate through the state, the lawsuit contends. Washington would also be impacted by refining the oil extracted in the refuge, increasing the risk of spills and potential worker hazards, it adds. Trump and his administration “unlawfully cut corners in their haste to allow drilling in this pristine, untamed wildlife refuge to oil and gas development,” Ferguson said in a news release announcing the lawsuit. An indigenous people’s community on the Coastal Plain also has filed suit against the plans to open the area to drilling. Interior Secretary David Berhardt announced in mid August the administration would open all 1.5 million acres of the Coastal Plain to oil and gas leasing, calling it “a new chapter in energy independence” and a way to generate thousands of jobs. Congress had mandated the leases, he said.
The Upcoming Release of Crude Oil from the Strategic Petroleum Reserve |- As the year 2020 wears on, it seems that every month brings a new surprise. In August, in addition to the ongoing pandemic and protests, a major hurricane was added to the mix. What comes next is anybody’s guess. A zombie apocalypse? An alien invasion? At this point, the possibilities seem boundless. And the energy industry has been no stranger to this year’s turmoil, what with COVID-related demand destruction, an oil-price collapse, and production shut-ins. Amidst the chaos, the Department of Energy (DOE) announced that for the first time, private-sector energy companies would be allowed to store crude oil in the U.S.’s Strategic Petroleum Reserve (SPR), which resulted in the leasing of 23 MMbbl of capacity. Recently, those volumes have begun to be drawn back out. Today, we examine the factors influencing movements of crude oil into and out of the U.S. SPR. April was quite a month for crude oil, complete with the price of WTI dropping to unprecedented levels — even going negative for a day, as we discussed in One Way Out. Even before the bottom fell out though, in early April, the DOE was scrambling to cope with the fallout of the OPEC+ price war and rapidly deteriorating global crude demand due to COVID (see Things That Matter). In an attempt to stymie further price shocks and stabilize the market by absorbing some of the oil glut, the Trump administration directed the Secretary of Energy, Dan Brouilette, to fill up the SPR. To comply, the DOE announced on April 2 that it would lease up to 30 MMbbl of crude storage space in the SPR to private energy companies for the first time. It was a stunning decision to many in the industry; however, given the abundance of unceasing surprises which have occurred this year, this action was quite fitting with the what’s-next uncertainty that has ensued in 2020. The U.S. SPR is the largest emergency stockpile of crude oil in the world, with an authorized capacity of 714 MMbbl. It was established in the mid-1970s in response to the 1973 oil crisis to mitigate domestic supply disruptions. In the past few decades, it has been used to store crude for a rainy day — that is, to help deal with unpredictable events such as embargoes or devastating hurricanes that interrupt supply. There are currently four storage sites in operation. Moving from west to east in the map in Figure 1 below, they are:
Never Say Goodbye, Part 3 - Will Rebounding Canadian Crude Production Fill Up Pipelines? -Western Canadian producers have been deeply impacted by lower crude oil prices and the demand-destroying effects of COVID-19. This past spring, oil production in the vast region dropped by an estimated 940 Mb/d, or as much as 20% from the record highs earlier this year. Taking that much production offline helped in at least one sense: it eased long-standing constraints on takeaway pipelines like Enbridge’s Canadian Mainline, TC Energy’s Keystone Pipeline, and the government of Canada’s Trans Mountain Pipeline. Production has been rebounding this summer, however, and there are indications that pipeline constraints may be returning and apportionment of uncommitted space on some pipes may again become a persistent issue. Today, we continue a review of production and takeaway capacity in Alberta and its provincial neighbors with a look at apportionment trends on the biggest pipelines. As we explained in Part 1 of this series, oil producers in Western Canada responded to sharply lower oil prices and lower demand by reducing production by 940 Mb/d between February and the peak of the cutbacks in May. Three-quarters of the cuts occurred in Alberta’s oil sands in response to single-digit pricing for the heavy oil price benchmark of Western Canadian Select (WCS) during April. However, WCS prices recovered steadily through May and June, and have since been holding steady between $30/bbl and $35/bbl (all in U.S. dollars). As a result, production has begun to recover: we estimate that about half of the 940 Mb/d supply reduction had been restarted by early July, and there are indications that production has continued to rise as the summer wears on. In Part 2, we discussed how the sudden shifts in Western Canadian oil production have been affecting the region’s takeaway pipelines. It’s no secret that, despite the midstream sector’s best efforts to bring new pipeline capacity online, midstreamers failed to keep pace with production growth in the oil sands and other production areas through much of the 2010s. (See The Shape I’m In, How Long, and Canadian Pipedream for details.) The end result — at least until the production slowdown this spring — has been too many barrels competing for too little pipeline space.
Ukraine gas company to add Rick Perry pick to board – The Ukraine state-owned natural gas company caught up in President Donald Trump’s impeachment investigation has appointed a U.S. businessman pushed by former Energy Secretary Rick Perry to its board, two people with direct knowledge of the decision told POLITICO on Thursday.Houston-based oil and gas executive Robert Bensh is set join the board of Naftogaz, pending final paperwork, the two people said, adding that his appointment has drawn opposition from some other board members. They said the move has led at least one of them, Amos Hochstein, to prepare to resign.m The Ukraine government informed Naftogaz last week that it had approved Bensh, two people with knowledge said. The appointment adds to questions about Perry’s role in Ukrainian energy politics and whether the former Texas governor had pressured the government there to buy U.S. energy supplies to win favor with the Trump administration. Perry, as first reported by POLITICO, had originally pushed Naftogaz to accept Bensh and another Perry associate, Texas oil and gas executive with ties to Ukraine, Michael Bleyzer, onto its board.
Rick Perry’s Ukrainian Dream —Rick Perry came to Washington looking for a deal, and less than two months into his tenure as energy secretary, he found a hot prospect. It was April 19, 2017, and Perry, the former Texas governor, failed presidential candidate and contestant on “Dancing With the Stars,” was sitting in his office on Independence Avenue with two influential Ukrainians. “He said, ‘Look, I’m a new guy, I’m a deal-maker, I’m a Texan,’” recalls one of them, Yuriy Vitrenko, then Ukraine’s chief energy negotiator. “We’re ready to do deals,” he remembers Perry saying. The deals they discussed that day became central to Ukraine’s complex relationship with the Trump administration, a relationship that culminated in December with the House vote to impeach President Donald Trump. Perry was a leading figure in the impeachment inquiry last fall. He was among the officials, known as the “three amigos,” who ran a shadow foreign policy in Ukraine on Trump’s behalf. Their aim, according to the findings of the impeachment inquiry in the House, was to embarrass Trump’s main political rival, Joe Biden. Alongside this political mission, Perry and his staff at the Energy Department worked to advance energy deals that were potentially worth billions of dollars to Perry’s friends and political donors, a six-month investigation by reporters from Time, WNYC and ProPublica shows. Two of these deals seemed set to benefit Energy Transfer, the Texas company on whose board Perry served immediately before and after his stint in Washington. The biggest was worth an estimated $20 billion, according to U.S. and Ukrainian energy executives involved in negotiating them. If this long-discussed deal succeeds, Perry himself could stand to benefit: In March, three months after leaving government, he owned Energy Transfer shares currently worth around $800,000, according to his most recent filing with the Securities and Exchange Commission. Perry appears to have stayed on the right side of the law in pursuing the Ukraine ventures. Federal prosecutors in the Southern District of New York, or SDNY, questioned at least four people about the deals over the past year, according to five people who are familiar with the conversations and discussed them with our reporting team on the condition of anonymity. “As far back as last year, they were already interested in events that had taken place in Ukraine around Rick Perry,” including allegations that Perry “was trying to get deals for his buddies,” says one of the people who spoke to the Manhattan prosecutors. Perry is not a target of their investigation, according to two sources familiar with the probes. But two ethics experts say Perry’s efforts were violations of federal regulations. Administration officials are not allowed to participate in matters directly relating to companies on whose board they have recently served. Other experts say Perry and his aides may have broken a federal rule that prohibits officials from advocating for companies that have not been vetted by the Commerce Department. “Even if it skirts the criminal statute, it’s still unethical,” says Richard Painter, the top ethics lawyer in the White House of President George W. Bush, with whom we shared our findings.
Mexico Is Cutting Pemex’s Oil Output Forecast in Latest Setback - Mexico is cutting its 2021 forecast for oil production at Petroleos Mexicanos by 8.4% as the state producer struggles under a $107 billion debt load and the impact of the deadly coronavirus. The country’s Finance Ministry lowered its preliminary estimate for output next year to 1.857 million barrels a day, down from 2.027 million in an April forecast, according to a draft of next year’s budget proposal obtained by Bloomberg News. Pemex, as the company is also known, has been hit hard by Covid-related deaths among its workers at a time when the oil-market crash only made the ambitions of Mexican President Andres Manuel Lopez Obrador to increase production more difficult. Even the revised output number looks “optimistic,” said [one analyst]. “It seems that they have not learned,” he said, predicting that Pemex will fail to meet the lower target. The Finance Ministry estimates oil prices will average $42.10 a barrel next year, up from a preliminary forecast of $30 a barrel at the start of April. The numbers are part of a budget proposal that would increase Pemex’s spending by just 0.6% next year, to 544.6 billion pesos ($25 billion).
Mexico to present projects open to private capital as it moves to undo energy reform | S&P Global Platts — Mexico will present a set of infrastructure projects in the energy sector where private companies will be invited to participate, while it prepares to undo the energy reform conducted by the previous administration. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Mexico will announce a set of infrastructure projects before Sept. 15, when Mexicans celebrate Independence Day, President Andres Manuel Lopez Obrador said Sept. 7. The joint plan between the government and the private industry to reactivate the economy had originally been announced in November. According to a presentation filtered to the press, which presumably originated in the office of the presidency, the government's announcement will consist of 168 projects worth roughly $44.4 billion where the private industry will provide over 50% of equity. The announcement comes at a time when lawmakers from the president's party prepare to discuss a series of changes to the constitution that would effectively undo the energy reform carried out by former President Enrique Pena, which opened up the sector to private investment after over seven decades of monopoly. Senators from Morena, the party formed by the president and which currently has majority in both Houses of Congress, will discuss modifications to undo the 2013 energy reform, according to the party's legislative agenda for the next period, which began on Sept. 1 ends in January. The plan includes changes to Mexico's Hydrocarbon's law, Pemex's internal rules, the law of the energy regulators and the law for hydrocarbon revenues, the agenda shows. The main goal of the modification is to strengthen Pemex and CFE, the state hydrocarbon and power companies, respectively, for them to become economic engines for the country, the president has repeatedly said. The energy reform allowed private companies to participate in all areas of the energy sector for the first time in over 70 years and attracted over $200 billion in committed investments, including power generation and oil exploration. Lopez Obrador has touted with the idea of modifying the constitution to undo the energy reform for many years and even used it as a presidential campaign promise. Yet since he took office in December 2018, he promised to wait until his third year in office to do so. Sources have told Platts in recent months they see limits to the changes the current administration can make, because modifying many laws is a complex political process that needs coordination and therefore many of them expected the changes next year, after next year's elections, which could add strength to the president's party. In July, Mexico will renovate the lower House of Congress as well as 13 out of the 32 governorships in the biggest election process in modern history. Sources have also said undoing the reform is hard because many of the rules of the market are also included in the recently signed United States-Mexico-Canada Agreement.
Mexico Shuts The Door To Foreign Oil Companies -There will be no new exploration and production contracts on the table for private or foreign companies in Mexico under a government plan set to be made public soon.“We don’t expect that there will be anything new in exploration and extraction in this infrastructure plan,” the head of Mexico’s oil industry association AMEXHI toldReuters in an interview.The infrastructure plan is the Mexican government’s attempt to stimulate economic growth, but according to AMEXHI’s head, Merlin Cochran, it will not involve a focus on the energy industry in the form of new projects. New joint ventures for Pemex are also unlikely, Cochran told Reuters.Earlier this week, it emerged that Mexico might have to cut its production target for 2021 as total output continued to fall steadily. President Andres Manuel Lopez Obrador has ambitious plans for reversing this fall, but this plan relies exclusively on state player Pemex, and the company has probably the highest debt pile in the oil industry, despite government efforts to help it prop up its finances. This has made the target of 2 million bpd even harder to achieve.According to government plans, Pemex was supposed to boost oil production by about half a million barrels in 2021. Instead, in July production fell to 1.54 million bpd because of a sharp drop in the output from Pemex’s largest offshore field, Maloob. Output from Maloob fell by more than 30 percent on the year. This meant Pemex’s total for July fell to a record low. Earlier this year, there were media reports that the Mexican state company would farm out some production to foreign companies. The head of the National Hydrocarbons Commission, the state industry regulator, said he expected farm-out deals to be announced soon. However, this has not happened to date even though, according to NHC’s Rogelio Hernandez, Pemex was actively looking for partners.
PdV sees no spill risk from floating storage vessel - The Venezuela-flagged floating storage tanker Nabarima is in sound operating condition and poses no risk of an oil spill, according to PetroSucre, an offshore joint venture controlled by Venezuelan state-owned PdV.The Nabarima, a small VLCC built in 2005, has been moored for a decade at the offshore Corocoro field in eastern Venezuela's Paria Gulf where it is used to store PetroSucre's production of 23°API crude. The joint venture's operations have been suspended since last year, leaving the storage unit at close to its full capacity of about 1.2mn bl."Representatives of the National Aquatics Institute (INEA) have boarded (the Nabarima) on different occasions to certify its optimum conditions," PetroSucre said in a 5 September statement. The last such visit was on 16 August, the company noted.PetroSucre workers reported early last week that the vessel was listing because of water flooding in the engine room and nearby compartments.Italy's Eni, which holds a 26pc stake in PetroSucre, said later in the week that the vessel had been stabilized, but the crude aboard would be transferredinto another tanker, once the US provided a "green light" to ensure sanctions compliance.PetroSucre dismissed complaints by workers on and off the unit as false information intended to hurt Venezuela's national oil industry and justify US sanctions.
Total to drop control of sensitive offshore Brazilian exploration blocks - — Total has decided to resign its operatorship of five exploration blocks, in the environmentally sensitive the Foz do Amazonas Basin, 120 km offshore Brazil, the French oil major said Sept. 7. Total said it notified its partners BP and state-run Petrobras of its decision on Aug. 19 of blocks FZA-M-57, FZA-M-86, FZA-M-88, FZA-M-125 and FZA-M-127. No reason was given for the decision but exploration projects in Foz do Amazonas have been facing strong resistance from environmental groups following the discovery of a previously unknown coral reef in the turbid waters of the Amazon River delta. Total has been looking to drill seven exploration well on the acreage in the area in a long-running struggle to secure approval from Brazilian federal environmental regulator IBAMA. Total first started licensing the exploration drilling project in 2014. The move also comes amid rising public sensitivity over new oil exploration. BP last month pledged to undertake no new oil exploration in new countries as part of its transition to cleaner energy. Total said it now has six months to appoint a new operator for the blocks, which it was awarded in 2013. Until then, Total said it has a duty to continue monitoring all regulatory processes on behalf of its partners Petrobras and BP. Total's portfolio in Brazil currently includes 24 blocks, with 10 operated. In 2019, its production in the country averaged 16,000 b/d.
Tanker Delfi causes oil spill again - The work on raising and stabilizing the Delfi tanker (owned by Mister Drake PC) that sank near Odesa again caused an oil spill. "The leakage of oil products occurred due to the fact that the vessel continues to be raised and stabilized. The State Environmental Inspectorate will be able to calculate losses for environmental damage only after the Delfi tanker is finally removed from the Black Sea," head of the State Environmental Inspection Andriy Maliovany wrote on Facebook on Friday. According to him, on Thursday, the State Environmental Inspection of Odesa region, examining the water area near the sunken ship, noticed spots and a gray slick of silvery color with a total area of 70 sq. m. Laboratory studies have shown an excess of normalized values of maximum permissible concentrations in water by 5.8 times. To promptly eliminate pollution, representatives of Odesa branch of the Ukrainian Sea Ports Authority carried out urgent work near the flooded tanker using a sorbent. As reported, the specialists of Cranship LLC on August 26, 2020 put the Delfi tanker sunken near Odesa beach on an even keel. In November 2019, the tanker Delfi under the flag of Moldova sank in the Odesa Gulf.
Huge anti-govt demonstrations held across Mauritius in wake of botched oil spill response — -- Tens of thousands of Mauritians took to the streets of the capital to call for the resignation of Prime Minister Pravind Jugnauth and his cabinet for their botched handling of an oil spill which threatens the country’s economy. An estimated 75,000 people took to the streets of the capital Saint Louis over the weekend, the country’s largest anti-government protests in decades, following a slow and lackluster response to an oil spill in early August. The Japanese bulk carrier MV Wakashio struck a reef in southeast Mauritius and spilled roughly 1,000 tons of oil into the pristine Indian Ocean waters offshore the island. A 15 kilometer (9 mile) stretch of the coastline is now stained with oil as volunteers attempt to halt the spread of the slick. Environmental volunteers have erected makeshift oil barriers to stem the spread while experts from Japan and Britain are investigating the extent of the spill and its potential impact on the local flora and fauna, which include major mangrove forests filled with endangered species of animal. Meanwhile, some 34 melon-headed whales were found dead or seriously ill near the spill while the carcasses of roughly 40 dolphins are being examined for traces of oil in their system which may have contributed to their sudden and untimely deaths.
Mauritius oil spill ship operator to pay $9.4 million- The Japanese operator of a ship that leaked oil off the Mauritius coast pledged Friday to pay at least $9.4 million to help restore areas affected by the spill. Mitsui OSK Lines said in a statement that it planned "to contribute a total fund of about one billion Japanese yen over several years to support measures" to restore the marine environment. The measures include running mangrove and coral protection projects in partnership with experts and local NGOs, and setting up an environment recovery fund, it said. The company operates the MV Wakashio, which ran aground on July 25 off the coast of Mauritius, carrying 4,000 tonnes of fuel that began seeping into the island nation's pristine, coral-filled waters. After the boat split in two, the larger piece was towed out to sea and sunk, but the smaller section remains stranded on the reef. More than 1,000 tonnes of oil is believed to have leaked from the ship, with the rest siphoned out before it spilled. The oil has affected mangroved areas that are complicated to clean. Both the operator and the vessel's owner Nagashiki Shipping have apologised for the spill. Nagashiki last month pledged to "sincerely" respond to requests for compensation. It was not immediately clear if the funds promised by Mitsui would satisfy demands from the Mauritius government for compensation from the companies for "all losses and damages" caused by the spill and clean-up costs. Japan's Foreign Minister Toshimitsu Motegi said last week the country would continue supporting recovery efforts. The accident is still under investigation by Mauritian authorities. Japan's Kyodo News said last month the ship's crew had steered it close to shore because they wanted to find a mobile signal so they could contact family and ask about the coronavirus situation at home. It cited an unnamed judicial source, who also said an alcohol-fuelled birthday party had been held on board before the accident, though it was not clear if on-duty crew participated.
No real danger of oil spill from burning oil Tanker, Sri Lanka Navy Says - There is no real risk of a spill from a fully loaded supertanker that caught fire off the east coast of Sri Lanka, a senior official in the Indian Ocean nation's navy said on Friday. The fire that broke out in the engine room of the New Diamond on Thursday morning had spread to the bridge of the ship, carrying about 2 million barrels of oil, though it has not reached the cargo area, the Sri Lankan navy said. Director-General of Operations Rear-Admiral Y N Jayarathna told reporters it was the navy’s view that there was no real danger of a spill, because the fire on the ship has been contained in the rear section of the vessel. "The live flames have now died down and there is only white smoke emanating from the vessel," he told a televised press conference. A navy spokesman, Captain Indika de Silva, said there were 23 crew on board, one of whom is presumed dead. The rest have been taken off the ship by the Sri Lankan navy, with one injured crew member flown to the capital Colombo for treatment. Three tug boats, five Sri Lankan navy ships as well as two craft from the Russian navy and three from the Indian navy have been assisting in an operation to fight the fire and tow the ship away from the coast, after it began drifting towards land. At present the vessel is being held by the salvage team in deep sea 35 kms (21.7 miles) east of the Sri Lankan town of Pottuvil, de Silva said. Initially, the ship was stranded 38 kms (24 miles) east of the town of Thirukovil, but drifted within 25 kms of the coast after being abandoned. Authorities were now towing it eastward, away from the coast, de Silva said.
Oil spill fears dissipate as fire almost doused on Sri Lankan coast - The fears of an oil spill due to a fire in a crude laden vessel off the Sri Lankan coast appears to have dissipated with the authorities on Sunday saying here that the blaze has almost been doused.While intense fire-fighting efforts taken up by the Indian Coast Guard and Sri Lankan Air Force and Navy since September 3 had led to localisation of the fire in the ship, a defence release said no oil spill has been reported.“Fire appears to be doused and no flame and smoke is visible.Situation is being monitored for further action,” the release said, adding that the inertness of cargo was being maintained.The ship’s storage area, which has about three lakh tonnes of crude oil, is reported to be safe.The Panama registered MT (Motor Tanker) New Diamond, a Greek owned vessel and under charter by Indian Oil Corporation was carrying 2,70,000 tonnes of crude oil from Kuwait to India’s Paradip port when its engine room caught fire off Sangamankanda’s coast in Lanka’s eastern district of Ampara.Indian Coast Guard (ICG) and Sri Lankan ships, fast patrol vessels and tugs have been deployed in the fire fighting exercise.The oil tanker, which was taken to safe waters, is being held by a tug about 42 miles from the nearest coast for preventing drifting of the ship and to facilitate fire fighting.The various assets deployed are equipped with fire extinguishers like Dry Chemical Power and Aqueous Film- Forming Foam Concentrates besides Oil Spill Dispersants and oil skimmers to handle the situation in the event of an oil slick.
Fire Breaks Out Again on Stricken Supertanker Offshore Sri Lanka Firefighters are again battling flames aboard a fully loaded oil supertanker off Sri Lanka, the island's nation's navy said on Monday, four days after fire first broke out on the New Diamond."Fresh flames have risen in the funnel section of the MT New Diamond Supertanker and firefighters are battling the fire using foam to contain the blaze," said the Navy spokesman Captain Indika de Silva, adding that the fire had not reached the oil cargo of around 2 million barrels.A fire first broke out last Thursday in the engine room and spread to the bridge of the very large crude carrier, chartered by Indian Oil Corp for importing oil from Kuwait. That blaze was doused on Sunday.Tugs had been spraying water onto the ship on Monday to keep the metal cool, but high winds ignited the flames once again, de Silva said."We are spraying water on to the ship to keep it cool as there are several small fires still burning," he said.Several tugboats surrounding the Very Large Crude Carrier (VLCC) are keeping it about 30 nautical miles, or about 58 km, east of Sangaman point - Sri Lanka’s easternmost point in the Ampara district.The supertanker is adrift and has to be held in position by the tugboats.Salvage operations are expected to begin shortly, but "the ship will be allowed to be moved out of Sri Lankan waters only with our permission", de Silva said.
Sri Lanka towing stricken ship to deep sea, douses another fire (Reuters) - The Sri Lankan navy towed a stricken supertanker away from the Indian Ocean island’s east coast on Wednesday, while an Indian Coast Guard plane sprayed chemical dispersants on a long oil slick that trailed in its wake. A fire broke out in the engine room of the Greek-owned New Diamond tanker last Thursday. The blaze was believed to have been doused on Sunday but reignited a day later. Laden with 2 million barrels of crude oil, there are fears that the accident could cause an environmental disaster, but so far the slicks have resulted from escaping marine fuel oil rather than leaking crude. “This morning when we started moving the ship we noticed another slick trailing behind. It was about 1-2 nautical miles (1.8-3.6 kilometers), longer than the previous slick,” said Indika de Silva, spokesman for Sri Lankan Navy. The first slick, spotted on Tuesday, had been around a kilometer long. The slick, comprising marine fuel and residue from the fire, has been sprayed with chemical dispersants from a Dornier aircraft deployed by the Indian Coast Guard, de Silva said. Three members of a salvage team boarded the tanker on Wednesday to assess the damage, while a naval tug towed the vessel 41 nautical miles (76 kms) off Sri Lanka’s east coast. Greece-based Porto Emporios Shipping Inc is the registered owner of the 20-year old Panama-flagged very large crude carrier New Diamond, according to Refinitiv data. New Shipping Ltd is the manger of the vessel. There was no immediate comment from either company. Legal action would be filed against the owner under Sri Lankan laws protecting the marine ecosystem, Jagath Gunesekara, deputy general manager of the Marine Environment Protection Authority (MEPA) said. “We are deciding whether to claim criminal liability or civil liability or both,” Gunesekara said. Sri Lanka has deployed scientists and experts from MEPA, with one team examining the area around the ship and another surveying coastal areas for signs of pollution. “I have been informed there was some marine life, like turtles, closer to the incident, so this oil spill would have definitely damaged these species,” MEPA chairwoman Dharshani Lahandapura told Reuters.
Diesel fuel found in ocean near Sri Lanka oil tanker fire - An Indian coast guard aircraft sprayed a special chemical on a patch of diesel fuel near a large oil tanker off Sri Lanka's coast where firefighters are battling a new blaze that broke out two days after an earlier fire was extinguished, the navy said. The MT New Diamond is carrying nearly 2 million barrels of crude oil and officials have warned of possible massive environmental damage to Sri Lanka's coast if the ship leaks or explodes. Navy spokesman Capt. Indika de Silva said the new fire started Monday evening and reached the magnitude of the previous blaze. Firefighters have contained it but it is still burning, he said. High winds, extreme temperatures on the ship and sparks reignited it, the navy said, adding that so far there is no risk of a crude oil leak or of the fire spreading into the oil storage area. The navy said the initial fire began in an engine room boiler and did not spread to the oil storage area. However, it said "a diesel patch" had been spotted in the ocean about one kilometer (0.6 mile) from the ship. The patch is likely to be diesel fuel from the ship, it said. The ship has about 1,700 tons of diesel fuel to power its engines. An Indian coast guard aircraft sprayed a chemical on the patch to minimize damage to the marine environment, the navy said. Ships and helicopters from Sri Lanka and neighboring India are taking part in the firefighting efforts. The initial fire killed one Filipino crew member and injured another, but 21 other crew members escaped uninjured. Twenty were taken to the southern port city of Galle on Tuesday, while the captain remained on a ship near the tanker to help firefighting efforts, de Silva said. The tanker is about 30 nautical miles (55 kilometers) off the coast, the navy said.
Oil Supertanker Windfall Disappears -- Just six months ago, oil supertankers experienced a windfall as the pandemic slashed demand for crude and traders raced to book vessels to store the resulting glut. Now that season of good fortune for those ships has all but vanished. The tankers, which can haul 2 million barrels of oil across the world’s oceans, are now earning just $6,103 a day on the benchmark route from the Middle East to China, Baltic Exchange data show. That’s the lowest since May 2018. Back in March, they could make $250,000 a day on the same journey. The boom-to-bust comes as the recovery in oil demand stutters and the OPEC+ alliance continues to curb output, reducing the need for tankers. At the same time, China, the world’s largest crude importer, has slowed its purchases following a buying binge when oil was cheap. “The demand that was pushed forward is now not showing up anywhere in the market,” said Peter Sand, chief shipping analyst at industry group BIMCO. “There’s still a little bit of floating storage around, and that storage is easing mostly,” weighing on rates, he said. To help improve rates in the short-term, vessels can slow down in order to limit availability. Renewed interest from traders to store oil at sea on a temporary basis could also provide a boost. Shipowners usually prefer the former when rates are low so that they can capitalize on any future improvement in earnings. For now though, the outlook doesn’t look much better. More ships are starting to come available as congestion begins to ease at China’s ports following the buying spree earlier in the year, “The return of vessels from floating storage and reduced port congestion is putting pressure on rates,” the analysts said. “We expect an improvement of crude oil trade will have to wait until oil stock levels have come down before OPEC+ opens its tap.”
Russia must regain — and increase — its oil market share when demand returns, energy minister says - Russia and other major oil producers must regain, and even increase, their share of the oil market once demand returns, Russia's energy minister has said. "When demand begins to return to pre-crisis levels, it will be extremely important for Russia, like other oil-producing countries, to regain market share as soon as possible and, possibly, even increase it in the face of reduced competition between producers," Russia's Energy Minister Alexander Novak said in an article published in the ministry's in-house magazine Tuesday. OPEC, Russia and other non-OPEC producers — a group known collectively as OPEC+ — are currently cutting output by 7.7 million barrels per day (bpd) until December. The energy alliance agreed to impose the production cuts in response to lower demand due to the coronavirus pandemic and the global economic downturn. From January 2021, the cuts are expected to taper further to amount to 5.8 million bpd, with these expected to last until April 2022. Producers aim to rebalance supply and demand in the unstable market, and to support oil prices. Russia and other major oil producers have found themselves ceding market share to U.S. shale producers in recent years, with the U.S. becoming the largest oil producer in the world in 2018. Wary of the damage that lower output is doing to its own oil industry, both to producers and its oilfield services sector, the Russian government is looking to support the sector and could launch a scheme to encourage (and offer tax incentives) to oil companies to drill several thousand oil wells with the idea being that the wells are left unfinished but can quickly be put into use after the OPEC+ deal ends in 2022. Novak said that "work is underway to create conditions for the formation of a stock of unfinished wells" but did not specify if the scheme had been approved by the government. Such a scheme is designed to support Russia's oilfield services industry that focuses on services related to oil and gas exploration as well as the construction and maintenance of oil wells, for example. The industry employs 300,000 people in Russia, Novak said, and a lack of investment in the domestic industry could lead to mass redundancies, and it losing more market share to foreign companies.
Why Opec needs a plan to balance near-term prices against long-term market share - - It is easy to talk about when things return to normal. For the world oil market, there may be no such return. With demand still struggling, Opec needs a plan to balance short-term prices against long-term market share by the time its monitoring committee next meets on September 17.Various Covid-19 vaccines may be on the way, but doubts remain over the reliability of testing and their eventual efficacy.Meanwhile, the virus remains frustratingly resilient despite a fall in death rates. The growing rate of infections in India, Indonesia and Iraq appears unstoppable while Australia, Germany, Italy, Spain, Britain and, especially, France have registered a resurgence of cases after having managed to keep things under control.However, the US, Brazil and Iran were never really on top of the pandemic.Efforts to reopen schools and universities in many countries have led to a surge in new cases. Most office work continues remotely or at limited occupancy. As the US holiday season ebbs, these factors are causing a renewed slowdown in petrol demand. Air passenger travel is severely depressed, with continued confusion over regulations and the unpredictable appearance of quarantines and travel bans.Blanket lockdowns in most places will probably not return but rolling closures and depressed social and public activities continue. As companies run out of cash, temporary job losses become permanent and as government financial support winds down, many countries may now be entering a more conventional, shallower but still painful recession.China’s imports have been strong, although lower in July and August compared with the record hit in June, helping to support the market. But it is questionable how long this will continue as the country clears a backlog of deliveries bought when prices were weaker. Last month, the number of active US rigs began to increase after hitting its lowest level since 1940. The temporary shut-ins because of Hurricane Laura should shortly be reversed. Still, there is insufficient drilling to compensate for the fast declines in existing shale wells and the fall in US output will probably not be halted until next year, and until prices are above $50 per barrel.This points to the danger for Opec+ in assuming the pandemic is an aberration and that current policy only has to be maintained temporarily. To be fair to the group, it has laid out a path for sizeable but diminishing cuts of 5.8 million bpd against its baseline through next year and up to April 2022.
Oil Prices Face a Chill Autumn Wind - As the summer driving season fades in the rearview mirror, oil markets are taking on a distinctly chilly air.The recovery in demand has officially stalled, just as the OPEC+ countries are starting to taper their record output cuts. With spare capacity rife throughout the supply chain and huge stockpiles of crude and refined products, it may be some while yet before oil prices resume their upward path.After a strong initial rebound from the depths of the pandemic-induced slump, the comeback in demand slowed dramatically, as I’ve written hereand here. This is most obvious in those countries that publish detailed data at high frequency, such as the U.S., the U.K. and some other European nations.U.S. oil demand recovery has ground to a halt at around 85% of last year's level That oil demand in India remains muted is particularly bad news for those wishing oil prices higher. Before Covid-19 struck, it had joined China as one of the major centers of growth in liquid fuel consumption. Sales of transport fuels by the country’s three biggest fuel retailers — Indian Oil Corp., Bharat Petroleum Corp. and Hindustan Petroleum Corp. — were still down year-on-year by more than 20% in July and August. The one potential bright spot is China, which may yet prove a lifeline for the flagging demand. July’s apparent oil use in the world’s biggest importer was up by a whopping 19.5% year on year, according to Bloomberg calculations on data from the nation’s Customs General Administration. Air travel in the country’s vast domestic market is picking up. Passenger numbers for China’s biggest airlines — Air China Ltd., China Eastern Airlines Corp. and China Southern Airlines Co. — were up by about 25%month on month in July. Travel analytics company ForwardKeys predicts air travel in China will fully recover this month. But China’s already got plenty of oil on hand. It took advantage of rock-bottom prices in March and April to make purchases, leaving the country’s stockpiles brimming, both on land and in tankers anchored off its coast. The volume in so-called floating storage is coming down, but there are still some 50 million barrels of crude that have been in tankers off China’s Shandong province for more than 15 days, according to London-based consultants Energy Aspects. When it comes to getting oil out of the ground, the spare capacity may be even bigger. While U.S. shale oil production may never recover fully to its pre-virus peak, there is still plenty of room for output to pick up from current depressed levels. In the seven shale basins covered by the Energy Information Administration’s Drilling Productivity Report, there were still more than 7,600 drilled but uncompleted wells at the end of July, a number that has barely changed since February. That may reflect a lack of activity in the shale patch, but the wells provide a buffer from when demand picks up to the point that drilling crews return to the Permian and other shale basins.
IEA sees oil market stuck between no major slowdown but stalled recovery - (Reuters) - The global economy is likely not headed for any major slowdown due to COVID-19 but piled-up storage and uncertainty over China’s oil demand cloud oil markets’ recovery, an official with International Energy Agency (IEA) said. Keisuke Sadamori, IEA director for energy markets and security, told Reuters the outlook for oil was in the midst of either a second wave or a steady first wave of the coronavirus. “There is an enormous amount of uncertainty, but we don’t expect any additional serious slowdown in the coming months.” “Even though (the market is) not expecting real robust growth coming back soon, the view on demand is more stable compared with three months ago,” he said in an interview. Crude prices LCOc1 CLc1 plunged in spring to historic lows as the pandemic’s lockdowns crushed demand, and have pared losses but remained stuck near $40 a barrel. The IEA cut its 2020 oil demand forecast in its monthly report on Aug. 13, warning that reduced air travel would lower global oil demand by 8.1 million barrels per day (bpd). The Paris-based agency downgraded its outlook for the first time in three months, as the epidemic continues to wreak economic pain and job losses worldwide. With Brent crude registering its first weekly loss since June on Friday, markets have grown increasingly nervous over demand, poor refining margins and slow economic growth, reducing incentives to draw crude and products from abundant stocks. “It doesn’t seem like a massive stock draw seems to be happening yet,” Sadamori said. “We are not seeing a robust pickup in refining activity, and jet fuel is the big problem,” he added. China, the world’s largest crude importer, emerged from an economic lockdown sooner than other major economies and used its financial muscle to make record oil imports in recent months, a rare bright spot amid global demand destruction. But geopolitical tensions could call into doubt “to what extent it can be sustainable and last long”, Sadamori said. “There are so many uncertainties with regard to the Chinese economy and their relationship with key industrialized countries, with the U.S. and these days, even Europe. It’s not such an optimistic situation - that casts some shadow over the growth outlook”.
Big trade houses see persisting oil stocks bubble - (Reuters) - Trading firms enjoyed an unprecedented boom in the first half of 2020 due to extreme volatility caused by the COVID-19 pandemic but the market’s direction now looks less certain due to high stocks and tepid demand recovery. “The market is more complex and nobody knows when demand will come back. Financial investors are piling into second half of 2021 or December 2021 (oil futures contracts) on the assumption demand will be back then,” Marco Dunand, chief executive of Mercuria Energy Trading, told Reuters. “Coming into the fourth quarter, the expectation was that we should be drawing 3 to 4 million barrels per day of crude and products from stocks but the market is not drawing that.” During the peak period of lockdowns in March and April, traders were forced to hastily store an additional 1 billion barrels of crude and refined products as oil demand cratered. Eventually, OPEC and other major producers announced record output cuts that helped oil prices rebound. Economic activity began picking up in June but the recovery has flatlined. Some possible COVID-19 vaccines are undergoing trials but meanwhile, countries have been forced to re-impose some restrictions to stop the spread of the virus. “We see people starting to do floating storage again ... It will be a problem at some point as we have a massive overhang,” Dunand said. “Crude and distillate stocks in particular are building ... It’s a bubble mess.”
Oil skids after Saudi price cuts, demand optimism fades - Oil prices dropped more than 1% on Monday after earlier hitting their lowest since July as Saudi Arabia made the deepest monthly price cuts for supply to Asia in five months while optimism about demand recovery cooled amid the coronavirus pandemic. Brent crude was at $42.21 a barrel, down 45 cents or 1.1% by 0439 GMT, after earlier sliding to $41.51, the lowest since July 30. U.S. West Texas Intermediate crude skidded 51 cents, or 1.3%, to $39.26 a barrel after earlier dropping to $38.55, the lowest since July 10. The world remains awash with crude and fuel despite supply cuts by the Organization of the Petroleum Exporting Countries (OPEC) and their allies, known as OPEC+, and government efforts to stimulate the global economy and oil demand. Refiners have reduced their fuel output as a result, causing oil producers such as Saudi Arabia to cut prices to offset the falling crude demand. "Sentiment has turned sour and there might be some selling pressure ahead," Howie Lee, an economist at Singapore's OCBC bank said. The Labor Day holiday on Monday marks the traditional end of the peak summer demand season in the United States and that renewed investors' focus on the current lackluster fuel demand in the world's biggest oil user. China, the world's biggest oil importer which has been supporting prices with record purchases, slowed their intake in August, according to customs data on Monday. "Abundant supplies, fears of loosening OPEC+ compliance, the end of the U.S. driving season and stale long positioning have all combined to erode confidence in oil," OANDA's senior market analyst Jeffrey Halley said in a note. The world's top oil exporter Saudi Arabia cut the October official selling price for Arab Light crude it sells to Asia by the most since May, indicating demand remains weak. Asia is Saudi Arabia's largest market by region. In August, the OPEC+ group eased production cuts to 7.7 million barrels per day after global oil prices improved from historic lows caused by the coronavirus pandemic cutting fuel demand.
Oil Down After Saudi Price Cuts - -- Oil extended its retreat below $40 a barrel after Saudi Arabia cut pricing for October crude sales as the summer driving season winds down with many countries still struggling to control the coronavirus. Futures in New York dropped 1.5% in Asian trading after Saudi Aramco reduced its key Arab Light grade by a larger-than-expected amount for shipments to Asia in a sign that fuel demand in the largest oil-importing region is wavering. The kingdom also lowered prices to the U.S. for the first time in six months. West Texas Intermediate, the American crude benchmark, fell 7.5% last week in its biggest loss since June amid nervousness over demand and a rout in stocks. While infection rates in the U.S. are slowing, the pandemic appears to be staging a comeback in parts of Europe and cases in India are still surging. After trading in a narrow range for the past three months, crude is off to a poor start in September amid a still-tepid demand backdrop and a continued increase in output from the OPEC+ alliance. Chinese crude imports fell for a second month in August, and the world’s biggest importer is expected to purchase much less in September and October than it did in May and June as independent refiners run out of quota after a buying binge earlier this year. A price correction is overdue and weakening margins for major fuels such as diesel may potentially become a concern, said Howie Lee, an economist at Oversea-Chinese Banking Corp. in Singapore. Any rally in prices will “face headwinds as long as crude oil inventories remain materially high,” he said. WTI for October delivery fell 1.5% to $39.19 a barrel on the New York Mercantile Exchange as of 7:48 a.m. in London after dropping 3.9% on Friday. It was down as much as 3.1% earlier on Monday. Brent for November settlement dropped 1.2% to $42.15 a barrel on the ICE Futures Europe exchange after declining 3.2% on Friday. Brent’s three-month timespread was $1.48 a barrel in contango - where prompt prices are cheaper than later-dated contracts -- compared with $1.09 in contango a week earlier. The change in the market structure of the global crude benchmark indicates concern about over-supply is increasing.
Oil prices fall as fuel demand concerns grow after end of U.S. summer driving season - Oil fell below $42 a barrel on Tuesday, its 5th session of decline, pressured by concerns that a recovery in demand could weaken as coronavirus infections flare up around the world. Coronavirus cases rose in 22 of the 50 U.S. states, a Reuters analysis showed on the Labor Day holiday weekend. New infections are also increasing in India and Britain. Brent crude fell $1.28, or 3.05%, to trade at $40.73 per barrel. West Texas Intermediate crude dropped $2.07, or 5.2%, to trade at $37.70 per barrel. On Monday, crude fell after Saudi Arabia's state oil company Aramco cut the October official selling prices for its Arab light oil, a sign demand may be stuttering. "The price weakness is continuing today," said Eugen Weinberg, analyst at Commerzbank. "We believe this is attributable first and foremost to demand concerns." Both oil benchmarks have dropped out of the ranges they were trading in throughout August. Brent has fallen more than 8% since the end of August. "The streak of losses is driven by a stalling crude demand outlook for the rest of the year," said Paola Rodriguez-Masiu, analyst at Rystad Energy. Still, oil has recovered from historic lows hit in April, thanks to a record supply cut by the Organization of the Petroleum Exporting Countries and allies, known as OPEC+. The producers are meeting on Sept. 17 to review the market. Crude has also found support from a weaker U.S. dollar, although the U.S. currency was up on Tuesday. The market could rally beyond $45 later this year, said Norbert Ruecker, head of economics at Swiss bank Julius Baer. "Fundamentally, things have not changed," he said. "Demand is recovering, supply remains constrained, and the storage overhang is slowly disappearing."
Oil drops more than 7% to multi-month low on demand fears - Oil prices tumbled to their lowest level since June on Tuesday amid growing demand concerns as Covid-19 continues to spread. West Texas Intermediate crude, the U.S. oil benchmark, slipped $3.01, or 7.6%, to settle at $36.76 per barrel. During the session WTI traded as low as $36.13, a price not seen since June 15. International benchmark Brent crude dipped more than 5.3% to settle at $39.78, also its lowest level since June. "Today's oil price move is a clear sign that the market now seriously worries about the future of oil demand," said Paola Rodriguez-Masiu, senior oil markets analyst at Rystad Energy. "The streak of losses is driven by a stalling crude demand outlook for the rest of the year, with rising cases of Covid-19 and the end of the summer driving season in the U.S., as well as Asian refineries putting on [the] breaks," she added. Since WTI plunged into negative territory in April for the first time on record, oil prices have staged a big comeback. WTI jumped nearly 90% in May, and has posted monthly gains ever since. The gains were, of course, on the back of record lows, but prices moved higher as international producers scaled back production in an effort to counteract the demand drop-off caused by the pandemic. But in recent sessions prices have begun to trend lower. WTI fell during Monday's session after registering a 7.45% loss in the prior week, snapping a four-week win streak and posting its worst weekly decline since June. Tuesday's move lower followed Saudi Aramco cutting its official selling prices for October, which RBC's Helima Croft said triggered new demand concerns. In a recent note to clients, Bank of America said that it will take three years for demand to recover from Covid-19, assuming there's a vaccine or cure. The firm believes peak oil will come as soon as 2030 due in part to electric car proliferation. Rising U.S.-China trade tensions, as well as production coming back online also pressured prices on Tuesday, as did a stronger U.S. dollar. "The market has its eye on the big picture: where and when we see demand normalize globally and what happens with both US production and OPEC+ agreement over the medium term,
Oil prices reverse some losses but demand concerns persist - Oil futures clawed back some of the losses they sustained in the previous session, but a rebound in COVID-19 cases in some countries undermined hopes for a steady recovery in global demand. Brent crude was up 44 cents, or 1.1%, at $40.22 a barrel after dropping more than 5% on Tuesday to fall below $40 a barrel for the first time since June. U.S. crude was up 50 cents, or 1.4%, at $37.26 a barrel, having fallen nearly 8% in the previous session. Both major oil benchmarks are trading close to three-month lows. The global health crisis continues to flare with coronavirus cases rising in India, Great Britain, Spain and several parts of the United States. The outbreaks are threatening to slow a global economic recovery and reduce demand for fuels from aviation gas to diesel. "Short-term oil market fundamentals look soft: the demand recovery is fragile, inventories and spare capacity are high, and refining margins are low," Morgan Stanley said. Yet, the bank raised its Brent price forecast slightly higher to $50 a barrel for the second half of 2021 with the dollar weakening and rising inflation expectations, it said. Record supply cuts by the Organization of the Petroleum Exporting Countries and allies, known as OPEC+ have helped support prices, but with grim economic figures being reported almost daily, the outlook for demand for oil remains bleak. China's factory gate prices fell for a seventh straight month in August although at the slowest annual pace since March, suggesting industries in the world's second-biggest economy continued their recovery from the coronavirus-induced downturn.
Oil prices finish higher, but concerns remain over outlook for demand - Oil futures finished higher Wednesday, with U.S. prices reclaiming less than half of the more than 7% drop suffered in the previous session as worries over the demand outlook, driven by the pandemic, continued to limit crude’s upside potential. “The bounce in oil prices reflects the market recovering from the oversold positions” Tuesday, said Manish Raj, chief financial officer at Velandera Energy, “As the flurry of panic-stricken traders was absorbed,” the market was balanced today, leading to a rebound. However, “this week’s volatility is a reflection of substantial uncertainty in oil demand,” Raj told MarketWatch. “Whereas gasoline demand has staged a handsome V-shaped recovery world-wide, and particularly so in the U.S., distillate and jet fuel demand is elusive to say the least.” West Texas Intermediate crude for October delivery on the New York Mercantile Exchange rose $1.29, or 3.5%, to settle at $38.05 a barrel. November Brent crude, the global benchmark, rose $1.01, or 2.5%, to $40.79 a barrel on ICE Futures Europe. Weekly data on U.S. petroleum supplies will be released late Wednesday from the American Petroleum Institute and Thursday morning from the Energy Information Administration. The reports are each delayed by a day due to Monday’s Labor Day holiday. On average, the EIA is expected to report a decline of 500,000 barrels in crude supplies for the week ended Sept. 4, according to analysts polled by S&P Global Platts. Gasoline supplies are likely to have fallen by 2.5 million barrels, while distillates, which include heating oil, are expected to be up by 300,000 barrels, the survey showed.
Oil Inventories Rose by 2.9M Barrels Last Week: - U.S. oil stockpiles snapped six-straight weeks of declines on Wednesday at a time when the renewed spread of Covid-19 cases in some parts of the world threatens the demand outlook. U.S. crude inventories rose by 2.97 million barrels last week, according to an estimate released Tuesday by the American Petroleum Institute, after a draw of 6.36 million barrels the previous week. Crude Oil WTI Futures, the U.S. benchmark for oil, was up 2.64% after settling 3.5% higher at $38.05 a barrel on Wednesday. The surprise build comes a day ahead of the official government expected to show weekly U.S. crude supplies fell by 1.33 million barrels lasrt week.
WTI Holds Below $38 After Surprise Crude Build Raises Demand Fears - Oil prices are sliding once again this morning, with WTI unable to hold above $38 as concerns over rising American crude stockpiles pick up as global oil demand is expected to decline over 8 million barrels a day this year and likely won’t get back to 2019 levels before 2022, according to S&P Global Platts. At the same time, OPEC and its allies are unleashing crude back onto a market that’s still working through the inventory glut it built up earlier this year.“Uncertain oil-market fundamentals are holding prices back,” said Jens Pedersen, a senior analyst at Danske Bank. The “climb in U.S. crude stocks plays into the market worries over weak demand.” After last night's surprise build in crude stock s reported by API, all eyes are back on official data for signs of a growing glut. DOE:
- Crude +2.06mm (-806k exp)
- Cushing +1.838mm
- Gasoline-2.954mm
- Distillates -1.675mm
After 6 straight weeks of draws, US crude stocks built last week by over 2 million barrels US Crude Production barely bounced back after last week's storm-related shut-ins. WTI held below $38 on the official data... Finally, we note that Brent’s six-month timespread was $2.71 a barrel in contango - where prompt prices are cheaper than later-dated ones - compared with $1.97 at the end of August. The change in the market structure indicates growing concern about a glut and may also, together with falling tanker rates, incentivize floating storage.
Oil prices slip as growing stockpiles signal bumpy fuel demand recovery - Oil prices slid on Thursday after data showed U.S. crude stockpiles unexpectedly rose last week, stoking concern about a sluggish recovery in fuel demand as coronavirus cases continue to surge in many countries. U.S. West Texas Intermediate crude futures fell 49 cents, or 1.3%, to $37.57 a barrel, after climbing 3.5% on Wednesday. Brent crude futures dropped 37 cents, or 0.96% to $40.39 a barrel, after rising 2.5% on Wednesday. The oil market is under pressure on the prospect of both subdued demand and rising supply, ANZ analysts said in a note. The U.S. Energy Information Administration will release official weekly inventory data later on Thursday, a day later than normal following this week's U.S. Labor Day holiday. "(Refinery) maintenance season and a cautious approach from refiners should keep crude oil demand soft," the bank said, referring to regular scheduled outages at oil processing complexes. ANZ also said China's imports are likely to level off as 'teapot,' or independent refineries, reach their maximum annual crude import quotas. With coronavirus cases rising in several U.S. states, the country's crude stockpiles rose by 3 million barrels in the week to September 4, data from the American Petroleum Institute showed on Wednesday. That compared with analysts' forecasts of a draw of 1.4 million barrels. "If the EIA confirms a crude oil build later today, it would be the first U.S. stock build since mid-July," ING analysts said. The EIA already cut its 2020 world oil demand growth forecast by 210,000 barrels per day to 8.32 million bpd. In a further bearish sign, leading commodity traders are booking tankers to store crude oil and diesel on the water, with supply outpacing consumption, according to trading sources and shipping data. The rising stockpiles come ahead of a meeting on September 17 of the market monitoring panel of the Organization of the Petroleum Exporting Countries and allies including Russia, together known as OPEC+, which in August trimmed supply curbs from earlier this year on expectations demand would improve. "This issue will be front and center... next week, where we expect a strong statement that if markets continue to weaken, the producer group will be prepared to trim output further," Citi analysts said in a note.
It's Happening Again - Traders Store Oil At Sea As Recovery Falters - Crude prices slid Thursday as the stalled global economic recovery from the virus pandemic triggers a "second wave" of demand fears and sparks renewed interest in floating storage as the oil market flips bearish. Reuters said a "fresh build-up of global oil supplies, pushing traders including Trafigura to book tankers to store millions of barrels of crude oil and refined fuels at sea again."Floating storage, onboard crude tankers, comes as traditional onshore storage nears capacity as supply outpaces demand. Refinitiv vessel data shows trading house Trafigura has recently chartered at least five crude tankers, each capable of 2 million barrels of oil. The inventory build up, driving up demand for floating storage comes as OPEC+ recently trimmed supply curbs from earlier this year on expectations demand would improve. Though with the peak summer driving season in the US now over, demand woes and oversupplied markets are pressuring crude and crude product prices.Very large crude-oil carrier (VLCC) storage has started to rise once again. "Despite the recent slide in oil prices, we think that the OPEC+ leadership will continue to direct its efforts towards securing better compliance rather than pushing for deeper cuts at this stage," RBC analysts said.Another catalyst for the bearish tilt in crude markets is that China's oil imports are likely to subside as independent refineries have reached maximum annual oil import quotas.Reuters notes, in a separate report, that other top commodity traders are booking tankers to store crude products at sea, including diesel and gasoline. Refinitiv vessel data also shows Vitol, Litasco, and Glencor have been booking tankers in the last several days to store diesel for the next three months. "The market is soft and bearish, and floating storage is returning again," a market source told Reuters.
Oil prices slide near 2% after surprise U.S. crude stock build (Reuters) - Oil prices slid nearly 2% on Thursday after U.S. data showed a surprise build in crude stockpiles last week related in part to ongoing reductions at refineries along the Gulf of Mexico following Hurricane Laura. Brent futures fell 73 cents, or 1.8%, to settle at $40.06 a barrel, while U.S. West Texas Intermediate (WTI) crude fell 75 cents, or 2.0%, to settle at $37.30. After the market close, WTI briefly traded down over $1 a barrel and Brent was down as much as 99 cents. The U.S. Energy Information Administration (EIA) said crude inventories rose 2.0 million barrels last week. That confirmed the direction of the 3 million-barrel increase reported by the American Petroleum Institute (API), but was a surprise compared with the 1.3 million-barrel decrease that analysts forecast in a Reuters poll. “Today’s crude data looked bearish ... with about the only supportive element being the fact that the 2 (million-barrel) build was less than that indicated by the API,” said Jim Ritterbusch, president of Ritterbusch and Associates in Galena, Illinois, noting prices could fall further unless Gulf of Mexico refiners fully restart soon after shutting for Hurricane Laura. Brent and WTI futures dropped to their lowest since mid June earlier this week and have remained in oversold territory over the past several days. Brent’s Relative Strength Index (RSI) was under 30 for a fifth straight day for the first time since March. In China, Bank ANZ said oil imports were likely to level off as independent refineries reach their maximum quotas. In a further bearish sign, leading commodity traders were booking tankers to store crude oil and diesel. The rising stockpiles come ahead of a meeting on Sept. 17 of the market monitoring panel of the Organization of the Petroleum Exporting Countries (OPEC) and allies including Russia, a group known as OPEC+. “Despite the recent slide in oil prices, we think that the OPEC+ leadership will continue to direct its efforts towards securing better compliance rather than pushing for deeper cuts at this stage,” RBC analysts said.
Oil ekes out gain, but still posts second straight negative week - Oil prices edged higher on Friday as equities markets firmed, but crude remained on track for a second weekly drop as investors expected a global glut to persist if demand weakens further with rising COVID-19 cases in some countries. Brent crude rose 16 cents, or 0.4%, to $40.22 a barrel. U.S. crude settled 3 cents, or 0.08%, higher at $37.33. For the week, however, it declined more than 6%. Infections are growing faster in India than anywhere else, and the health ministry reported another record daily jump of 96,551 new cases on Friday, taking the official total to 4.5 million. U.S. stock markets rose, after a pullback in the previous session. Still, the three main U.S. stock indexes were also headed for a second straight weekly decline as recent economic indicators suggested a long and difficult recovery from the pandemic. "The financial markets are continuing to set the tone, including on the oil market ... fears about an oversupply have added to the general feeling of uncertainty," Commerzbank analysts said in a note. Also dampening the market mood, the U.S. Senate killed a Republican bill that would have provided around $300 billion in new coronavirus aid. In the United States, crude stockpiles rose last week, against expectations, as refineries slowly returned to operations after production sites were shut down due to storms in the Gulf of Mexico and the wider region. U.S. crude inventories rose 2 million barrels, compared with forecasts for a 1.3 million-barrel decrease in a Reuters poll. U.S. drillers also have started to slowly add oil and gas rigs after the rig count, an early indicator of future output, hit a record low of 244 in the week to Aug. 14. This week's data from Baker Hughes is due at 1 p.m.. In a further bearish sign, traders were starting to book tankers again to store crude oil and diesel, amid a stalled economic recovery as the COVID-19 pandemic continues. Increasing stockpiles are likely to be a subject at a meeting on Sept. 17 of the market monitoring panel of the Organization of the Petroleum Exporting Countries (OPEC) and allies including Russia. The group known as OPEC+ has been withholding supply to reduce stockpiles, but analysts say the meeting is likely to focus on compliance among members, rather than deeper cuts. Following Saudi Arabia, Kuwait also lowered its official selling price to Asia for October, to counter slower demand. "The decline is triggered by a series of unfortunate events: a surge in COVID-19 cases worldwide, the end of the peak summer driving season, the slowdown of the Chinese crude importing machine, and major producers trimming the OSPs to Asia as refinery margins worsen," Rystad Energy's senior oil markets analyst Paola Rodriguez-Masiu said.
Oil ends lower for second week as stockpiles rise, demand weakens - (Reuters) – Oil prices were little changed on Friday, but posted their second straight weekly loss as stockpiles rise around the world and fuel demand struggles to rebound to pre-coronavirus levels.Both Brent and U.S. crude lost about 6% on the week after a series of signals that showed markets still have an abundance of supply. Saudi Arabia and Kuwait cut official selling prices to Asia, U.S. stockpiles rose and traders are booking vessels for storage. Brent ended the session down 23 cents, or 0.6%, at $39.83 a barrel while U.S. crude settled up 3 cents at $37.33 a barrel.Coronavirus infections are growing in several countries, led by India, where the health ministry reported a record daily jump of 96,551 new cases on Friday, taking the official total to 4.5 million.U.S. stock markets ended lower for a second week following several economic indicators that suggest a long and difficult recovery from the pandemic.“The financial markets are continuing to set the tone, including on the oil market… fears about an oversupply have added to the general feeling of uncertainty,” Commerzbank analysts said in a note.In the United States, crude stockpiles rose 2 million barrels last week. Refineries slowly returned to operations after production sites were shut due to storms in the Gulf of Mexico. Traders are starting to book tankers again to store crude oil and diesel, another signal of oversupply amid a stalled economic recovery as the COVID-19 pandemic continues.For a graphic on Oil Product Floating Storage in Europe Oil Product Floating Storage in Europe: https://graphics.reuters.com/GLOBAL-OIL/nmovaqzkdva/chart.png The market monitoring committee Organization of the Petroleum Exporting Countries (OPEC) and allies including Russia, or OPEC+, will meet on Sept. 17 to consider how to deal with worldwide oversupply. The group reduced output in the spring to allow stockpiles to run down.In recent days, both Saudi Arabia and Kuwait lowered their official selling prices for crude to Asia for October, a signal of slower demand. Money managers cut their net long U.S. crude futures and options positions in the most recent week, a sign hedge fund managers expect further weakness in the oil markets.
Collapse in oil prices threatens social and political unrest in Middle East and North Africa - The collapse in oil prices earlier in the year, along with cuts in oil production and the world-wide recession following the COVID-19 pandemic, is having a devastating impact on economic and social conditions in the oil-producing countries of the Middle East and North Africa (MENA). The repercussions spread far beyond the oil producers’ borders. Oil prices, which started the year at around $60 a barrel—nearly half that of a decade ago—fell to $40 in March and plummeted into negative territory before rising again to around $40 a barrel in recent weeks. This year, oil revenues are expected to be around $300 billion, down from $575 billion in 2019 and more than $1 trillion in 2012. While oil production may just be profitable at $40 a barrel, none of the Arab states except Qatar can balance their budgets at this level. The worst affected, Algeria and Oman, need prices to rise to $157 and $87 a barrel, respectively. Even the largest oil producer, Saudi Arabia, which relies on oil for 70 percent of its budget, needs $80 a barrel to balance its books. In June, the International Monetary Fund estimated that the economies of the Gulf Cooperation Council (GCC) countries—Saudi Arabia, the United Arab Emirates (UAE), Kuwait, Bahrain, Oman and Qatar—would shrink by 7.6 percent this year, while Iraq’s economy is expected to contract by 7.5 percent and Iran’s by 6 percent, on top of a 7.6 percent decline in 2019 and 5.4 percent in 2018 due to Washington’s unilateral pull-out from the 2015 nuclear agreement. Since March, the Arab petro-states have slashed public expenditure—including the salaries of public sector workers, who form 90 percent of regular, full-time workers—raised sales taxes and petrol prices, all of which have fallen hardest on the poor. Subventions, which for the corporate sector have far exceeded any poverty relief measures, have been borrowed on the international money markets and are eating into foreign currency reserves. Even Saudi Arabia, which faces a budget deficit for 2020 equal to 16 percent of GDP, has only two years’ reserves left at current spending rates. More tax rises and privatisations are on the agenda, with its giant desalination plant, the world’s largest, up for sale.
Two decades of US “war on terror” responsible for displacing at least 37 million people and killing up to 12 million - A staggering new report coauthored by Professor David Vine at the Watson Institute at Brown University conservatively estimates that 37 million people, equivalent to the entire population of Canada, have been forced to flee their home country, or have become internally displaced within it by nearly two decades of unending US imperialist war. The analysis, published by the Costs of War Project, sought to quantify for the first time the number of people displaced by the United States military operations since President George W. Bush declared a “global war on terror” in September 2001 following the still unexplained attacks on the World Trade Center in New York City and the Pentagon.Professor Vine and his coauthors note that the 37 million estimated displaced is a “very conservative estimate,” with the real number of people displaced since September 2001, “closer to 48-59 million.” That is as much as, or more than, all of the displaced persons in World War II and therefore more than any other war in the last century. It is difficult to articulate the levels of misery, poverty, hardship, strife, pain and death visited upon entire societies and endured by millions of people. The latest Costs of War report focused on eight countries that have been subjected to major US military operations: Afghanistan, Pakistan, Yemen, Somalia, the Philippines, Iraq, Libya and Syria. The two countries with the highest number of displaced persons were Iraq and Syria, whose populations have suffered for decades under US-led regime-change operations and military occupations initiated by both Republican and Democratic administrations. The authors estimate that 9.2 million people in Iraq and 7.1 million in Syria have been displaced respectively, in both cases roughly 37 percent of the prewar population. The authors were careful to note that they only counted Syrian refugees and displaced persons post-2014, even though US-funded and supplied terrorist groups such as the Al Qaeda-affiliated Al Nusra Front, the Islamic State and other Islamist groupings began operations against the Syrian government as early as 2011. If the figures were to include the previous three years, the estimates exceed 11 million. Somalia, where US forces have been operating since 2002, has the highest percentage of displaced persons with 46 percent of the country or nearly 4.2 million people displaced. Throughout the “war on terror,” the authors estimate between 770,000 and 801,000 civilians and combatants on all sides have died in Afghanistan, Iraq, Syria, Pakistan and Yemen since US forces began military operations in those countries. The number of “indirect deaths,” that is, those who weren’t confirmed killed by military weaponry, but died due to lack of healthcare, infrastructure, or food as a result of US military operations, embargoes and blockades may exceed 3.1 million, although the authors noted that credible estimates range in excess of 12 million.
Trump's Iraq Troop Draw-Down To Begin This Month, Top General Announces --Previously the Trump administration said it would aim for a major troop reduction in Iraq by the time of the November election. It appears that promise — part of the Trump campaign's longtime pledge to "bring Americans home" from unnecessary "endless" foreign wars and occupations abroad — is on track to be delivered. Head of US CENTCOM, Marine Gen. Frank McKenzie, said while touring a US base in Iraq that troop numbers there will be cut down to 3,000 this month.Current American troops levels are at about 5,200 — though we should note the tens of thousands of US contractors and other privatized personnel that remain there.Gen. McKenzie underscored in statements that Washington feels confident that Iraqi forces are now trained to handle any threat from a potentially resurgent ISIS, now long driven underground."This reduced footprint allows us to continue advising and assisting our Iraqi partners in rooting out the final remnants of ISIS in Iraq and ensuring its enduring defeat," McKenzie said.US training of Iraqi military personnel had reportedly already been scaled back through the course of the coronavirus pandemic, given local as well as international lockdowns and travel restrictions. During a Labor Day news conference President Trump raised eyebrows in charging top Pentagon commanders of ultimately being beholden to defense contractors. Speaking of what sectors of the military are supportive of the Commander-in-Chief, Trump said Monday: “The top people in the Pentagon probably aren’t because they want to do nothing but fight wars so all of those wonderful companies that make the bombs and make the planes and make everything else stay happy.”
Turkey Escalates With Tanks & Armored Troop Carriers Deployed To Greek Border - Amid soaring Turkey-Greece tensions related to the eastern Mediterranean gas exploration spat, which has already resulted in rival fighter jets patrolling airspace off Cyprus, the Associated Press reports Ankara has deployed some 40 tanks and armored vehicles to the border with Greece. The AP/New York Times cites Turkish media reports on Saturday:Meanwhile, Turkish media reported that tanks were being moved towards the Greek border. The Cumhuriyet newspaper said 40 tanks were being transported from the Syrian border to Edirne in northwest Turkey and carried photographs of armored vehicles loaded on trucks.There was no immediate official confirmation of the deployment. Turkey deploys tanks to Greece border from Syrian border, Turkish private news agency İHA claims. Approximately 40 tanks. pic.twitter.com/nnDrEegXsj— Ragıp Soylu (@ragipsoylu) September 5, 2020 But confirmation has come after Turkish news agency İHA posted video showing APC armored troops carriers headed to the border point. However, tanks were not evident in the video of the large convoy on the Turkish highway, and the deployment could have been pre-planned, though will certainly be noticed and responded to by Athens. Meanwhile NATO leadership is attempting to mediate the inter-NATO member dispute, which could prove highly embarrassing, also given Russia is about to kick off naval war games around Cyprus, notably in the very disputed waters Turkey is claiming as its own.
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