Oil, Gas, And Fracking News Reads: 01November 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 31 October 2020. Part 2 is available here.

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

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Distillates production at a 3 year low, distillates demand at a 36 week high, but distillate supplies still 33% above a year ago

Oil prices fell for a second straight week on surging coronavirus cases, postponing the prospect of a demand recovery…after falling 3.1% to $39.85 a barrel last week on rising fuel inventories and the likelihood of new coronavirus related lockdowns, the contract price of US light sweet crude for December delivery opened lower on Monday as surging coronavirus cases in the US and Europe raised worries about energy demand, and continued lower to end down at $1.29 at $38.56 a barrel on news that recovering Libyan oil production would reach 1 million barrels per day in four weeks, much sooner than most analysts had anticipated…but oil prices partly recovered on Tuesday, jumping 2% as Tropical Storm Zeta forced the shutdown of half of U.S. Gulf output, and finished $1.01 higher at $39.57 a barrel, even as surging coronavirus infections and rising Libyan output limited oil’s gains…however, oil prices were hammered overnight, accelerating lower after the API reported an unexpectedly large crude inventory build, and then opened more than 1% lower on Wednesday, and continued to drop further after the EIA confirmed the large inventory build that the API had reported, ending down $2.18 or 5% at a three week low of $37.39 a barrel, as surging coronavirus infections in the US and Europe were leading to renewed lockdowns, fanning fears that the unsteady economic recovery would further deteriorate…oil prices continued lower again on Thursday and were down another 7% at $34.92 a barrel early, but clawed back more that half of those losses to finish just $1.22 lower at $36.17 a barrel, still the lowest oil price settlement in nearly five months, as rising COVID-19 cases sparked tighter restrictions on activity in Europe and underlined worries about the outlook for a global economic recovery…oil prices fell further on Friday as rising COVID-19 cases in Europe and in the US heightened concerns over the outlook for fuel consumption, with December US crude finishing 38 cents lower to settle at $35.79 a barrel, thus finishng down 10.2% on the week and down more than 11% for October, the second monthly oil price drop in a row…

Natural gas prices finish higher for the fourth week in a row, as Hurricane Zeta shut in 45% of Gulf gas production while much less gas was added to storage than had been expected…after rising 7.1% to $2.971 per mmBTU last week on falling gas production and rising exports, the contract price of natural gas for November delivery opened lower Monday but rallied on forecasts for higher heating demand, and on concerns that Tropical Storm Zeta would move into the Gulf and disrupt production and settled 5.3 cents, or 1.8% higher at $3.024 per mmBTU….the November natural gas contract price gave up a half cent on Tuesday, with rising LNG exports and a drop in output weighed down by expectations that higher gas prices would cause power generators to burn more coal and less gas to produce electricity. and then fell 2.3 cents to expire at $2.996 per mmBTU on Wednesday, despite forecasts for colder weather and higher heating demand, as a 5% drop in crude futures weighed on all energy markets…meanwhile, the more actively traded contract for natural gas for December delivery, which had closed lower last week at $3.195 per mmBTU but had risen 5.8 cents on Monday again on Tuesday, road that same oil price slide to close 2.0 cents lower on Wednesday at $3.291 per mmBTU….with the December gas contract moving to the front of the board on Thursday, quoted natural gas prices plunged early to a $3.151 per mmBTU intraday low before screaming back to settle a penny higher at $3.301 per mmBTU, as a bullish EIA storage report erased earlier bearish weather outlooks…momentum from the Thurdsday rebound carried into Friday as natural gas prices rose another 5.3 cents to finish the week at a 21 month high of $3.354 pe rmmBTU, on rising LNG exports and a new outbreak of colder air...for the week, the quoted price of natural gas rose 12.9%, largely on the change of the front month contract from Novemer to December gas, while the December contract itself ended 5.0% higher than the prior week’s close…

The natural gas storage report from the EIA for the week ending October 23rd indicated that the quantity of natural gas held in underground storage in the US increased by 29 billion cubic feet to 3,955 billion cubic feet by the end of the week, which left our gas supplies 285 billion cubic feet, or 7.8% greater than the 3,670 billion cubic feet that were in storage on October 23rd of last year, and 289 billion cubic feet, or 7.9% above the five-year average of 3,666 billion cubic feet of natural gas that have been in storage as of the 23rd of October in recent years….the 29 billion cubic feet that were added to US natural gas storage this week was somewhat less than the forecast for a 37 billion cubic foot increase from an S&P Global Platts’ survey of analysts, and it was well below the average of 67 billion cubic feet of natural gas that are typically added to natural gas storage during the same week over the past 5 years, and it was also much lower than the 89 billion cubic feet that was added to natural gas storage during the corresponding week of 2019…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending October 23rd indicated that due to a big increase in our oil production and a increase in our oil imports, we had a surplus of oil to add to our stored commercial supplies for the 4th time in the past fourteen weeks and for the 25th time in forty-one weeks…our imports of crude oil rose by an average of 546,000 barrels per day to an average of 5,664,000 barrels per day, after falling by an average of 167,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 424,000 barrels per day to an average of 3,460,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,204,000 barrels of per day during the week ending October 23rd, 122,000 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 1,200,000 barrels per day higher at 10,100,000 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 13,304,000 barrels per day during this reporting week…

US oil refineries reported they were processing 13,388,000 barrels of crude per day during the week ending October 23rd, 363,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net total of 523,000 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 608,000 barrels per day less than what our oil refineries reported they used during the week plus what was added to storage…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+608,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…however, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as published, just as they’re watched & believed to be accurate by most everyone in the industry…(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 5,450,000 barrels per day last week, which was 13.1% less than the 6,268,000 barrel per day average that we were importing over the same four-week period last year….the 523,000 barrel per day net addition to our total crude inventories included 617,000 barrels per day that were added to our commercially available stocks of crude oil, which was partly offset by the 94,000 barrels per day that was being withdrawn from the oil supplies in our Strategic Petroleum Reserve, space in which is now being leased for commercial use, and hence the recent SPR additions and withdrawals should really be included in our commercial inventories….this week’s crude oil production was reported to be 1,200,000 barrels per day higher at 11,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states rebounded by 1,200,000 barrels per day to 10,600,000 barrels per day, while a 5,000 barrels per day increase to 469,000 barrels per day in Alaska’s oil production still added 500,000 more barrels per day to the rounded national total…last year’s US crude oil production for the week ending October 25th was rounded to 12,600,000 barrels per day, so this reporting week’s rounded oil production figure was 11.9% below that of a year ago, yet still 31.7% 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 74.6% of their capacity while using 13,388,000 barrels of crude per day during the week ending October 23rd, up from 72.9% of capacity during the prior week, but excluding the 2005 and 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the past thirty years…hence, the 13,388,000 barrels per day of oil that were refined this week were 16.3% fewer barrels than the 15,998,000 barrels of crude that were being processed daily during the week ending October 25th of last year, when US refineries were operating at 87.7% of capacity…

With the increase in the amount of oil being refined, gasoline output from our refineries was also higher, increasing by 162,000 barrels per day to 9,095,000 barrels per day during the week ending October 23rd, after our refineries’ gasoline output had decreased by 370,000 barrels per day over the prior week…but since our gasoline production is still recovering from a multi-year low in the wake of this Spring’s covid lockdown, this week’s gasoline output was still 10.7% less than the 10,184,000 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 5,000 barrels per day to a three year low of 4,126,000 barrels per day, after our distillates output had decreased by 138,000 barrels per day from the prior three year low over the prior week…and after this week’s decrease, our distillates’ production was 17.0% less than the 4,970,000 barrels of distillates per day that were being produced during the week ending October 25th, 2019…

Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the 13th time in 17 weeks and for the 28th time in 39 weeks, falling by 892,000 barrels to 226,124,000 barrels during the week ending October 23rd, after our gasoline supplies had increased by 1,895,000 barrels over the prior week…our gasoline supplies decreased this week because the amount of gasoline supplied to US markets increased by 256,000 barrels per day to 8,545,000 barrels per day, and because our imports of gasoline fell by 49,000 barrels per day to 460,000 barrels per day while our exports of gasoline fell by 169,000 barrels per day to 530,000 barrels per day…and despite the gasoline inventory drawdowns of recent weeks, our gasoline supplies were 2.8% higher than last October 25th’s gasoline inventories of 220,057,000 barrels, and about 3% above the five year average of our gasoline supplies for this time of the year…

With our distillates production again at another three year low, our supplies of distillate fuels decreased for the 6th week in a row, for 12th time in 30 weeks and for the 30th time in 52 weeks, falling by 3,832,000 barrels to 160,719,000 barrels during the week ending October 23rd, after our distillates supplies had decreased by 3,832,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 652,000 barrels per day to a 36 week high of 4,240,000 barrels per day, even as our exports of distillates fell by 372,000 barrels per day to 871,000 barrels per day, while our imports of distillates rose by 192,000 barrels per day to 344,000 barrels per day….but even after this week’s inventory decrease, our distillate supplies at the end of the week were still 33.1% above the 120,786,000 barrels of distillates that we had in storage on October 25th, 2019, and about 17% above the five year average of distillates stocks for this time of the year…

Finally, with the big increases in our oil imports and in our oil production, our commercial supplies of crude oil in storage (not including commercial oil in the SPR) rose for the 8th time in the past twenty weeks and for the 34th time in the past year, increasing by 4,320,000 barrels, from 88,107,000 barrels on October 16th to 92,427,000 barrels on October 23rd…after that increase, our commercial crude oil inventories were around 9% above the five-year average of crude oil supplies for this time of year, and about 44% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the last weekend of October, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had generally been rising over the past two years, except for recent weeks and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of October 23rd were 12.2% above the 438,853,000 barrels of oil we had in commercial storage on October 25th of 2019, 15.6% more than the 426,004,000 barrels of oil that we had in storage on October 26th of 2018, and 8.2% above the 454,906,000 barrels of oil we had in commercial storage on October 27th of 2017…

This Week’s Rig Count

The US rig count rose for the 7th week in a row during the week ending October 30th, but for just the 9th time in the past 34 weeks, and hence it is still down by 62.7% over that thirty-four week period….Baker Hughes reported that the total count of rotary rigs running in the US rose by 9 to 296 rigs this past week, which was still down by 526 rigs from the 822 rigs that were in use as of the November 1st report of 2019, and was also 108 fewer rigs than the all time low prior to this year, and 1,633 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….

The number of rigs drilling for oil increased by 10 rigs to 221 oil rigs this week, after increasing by 6 oil rigs the prior week, still leaving us with 470 fewer oil rigs than were running a year ago, and less than a seventh of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations decreased by one to 72 natural gas rigs, which was also down by 58 natural gas rigs from the 130 natural gas rigs that were drilling a year ago, and was also less than a twentieth of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Sonoma County, California, and one in the Permian basin in Eddy County, New Mexico…a year ago, there only one such “miscellaneous” rig deployed…

The Gulf of Mexico rig count remained at 13 rigs this week, with 12 of those rigs drilling for oil in Louisiana’s offshore waters and one drilling for oil offshore from Texas…that was 8 fewer Gulf rigs than the 21 rigs drilling in the Gulf a year ago, when all 21 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 9 from the national offshore rig count of 22 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 was also a rig drilling on southern Louisiana inland waters..

The count of active horizontal drilling rigs was up by 9 to 254 horizontal rigs this week, which was still 463 fewer horizontal rigs than the 717 horizontal rigs that were in use in the US on November 1st of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was up by one to 22 directional rigs this week, but those were down by 31 from the 53 directional rigs that were operating during the same week of last year….on the other hand, the vertical rig count was was down by one to 20 vertical rigs this week, and those were also down by 32 from the 52 vertical rigs that were in use on November 1st of 2019….

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of October 30th, the second column shows the change in the number of working rigs between last week’s count (October 23rd) and this week’s (October 30th) count, the third column shows last week’s October 23rd 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 1st of November, 2019…

As you can see, most of this week’s activity was concentrated in Texas, and then in the Permian basin, mostly in that state…checking for the details on the Permian in Texas, we find that five rigs were added in Texas Oil District 8, which roughly aligns with the Permian Delaware, another rig was added in Texas Oil District 8A, which corresponds to the northern Permian Midland, and another rig was added in Texas Oil District 7C, which corresponds to the southern Permian Midland, which together means that the Texas Permian saw a net seven rig increase…since the Permian basin rig count was up by 9 rig nationally, that means that the two rigs that were added in New Mexico must have been added in the farthest west reaches of the Permian Delaware, to account for the national increase…elsewhere in Texas, we find that one rig was added in Texas Oil District 1, which would account for the Eagle Ford shale increase and also bring our Texas rig count increase up to the 8 rigs shown in the table…the other changes shown above are all in Oklahoma; an oil rig was added was added in the Cana Woodford, which now has 8 oil rigs, while the last natural gas rig remaining in the Arkoma Woodford was pullled out at the same time…since the overall Oklahoma count was down by one, we have to assume there was also another oil rig removed from a basin not tracked by Baker Hughes in another part of that state…meanwhile, there is no indication of activity elsewhere, in any other basins or states that we haven’t mentioned…

Chevron to Divest Shale Assets in $735MM Deal — EQT Corp. agreed to buy Chevron Corp.’s Appalachian shale assets for $735 million as the biggest producer of U.S. natural gas takes advantage of an industry slump to expand. The transaction is expected to close by the end of the year, EQT said in a statement on Tuesday. Chevron has been trying to unload its Appalachian gas holdings since late 2019, when it recorded an $11 billion writedown for that asset and others amid a swelling domestic gas glut and cratering prices for the furnace and power-plant fuel. The acquisition is the latest in a string of recent deals where shale drillers are seeking to add scale to cope with a plunge in commodity prices that has left much of the industry unprofitable. “This acquisition is a natural bolt-on extension of EQT’s dominant position in the core of the southwest Marcellus and supplements our already impressive asset base,” EQT Chief Executive Officer Toby Rice said in the statement. The Chevron assets include about 100 work-in-progress wells, with a net production capacity of 450 million cubic feet a day, EQT said. It will also give the shale explorer a 31% ownership interest in pipeline company Laurel Mountain Midstream. EQT indicated it may fund the deal with cash on hand, a revolving credit facility or a separately disclosed issuance of up to 23 million common shares. EQT fell in after-hours trading, dropping 3% to $15.67 at 7:59 p.m. in New York. Chevron fell 0.6%. EQT has also made a proposal to acquire rival CNX Resources Corp., people familiar with the matter told Bloomberg News last week. No final decision had been made and EQT could opt to not proceed with a potential deal, they said. CNX fell 1.6% after the arrangement with Chevron was announced. EQT already is the largest supplier of U.S. gas, producing 44% more than its nearest competitor, Exxon Mobil Corp., according to figures compiled by the Natural Gas Supply Association. EQT pumped about 4 billion cubic feet a day as of the first quarter.

EQT to grow even bigger with $735 million deal for Chevron assets – EQT Corp. announced on Tuesday that it is buying Chevron’s Appalachian assets for $735 million in a deal that will make the largest natural gas producer in the country an even bigger force. Downtown-based EQT called the move “low risk” and a “strategic step,” having foreshadowed the industry’s consolidation during its earnings call last week. Chevron’s more than 500 producing wells that are part of the sales agreement, signed last week, will add about 11% to EQT’s production. The sale would also come with coveted infrastructure: two water pipelines that can handle fresh and produced water, a centralized water handling facility in West Virginia, and an interest in a natural gas gathering pipeline system operated by Williams Companies. These assets, which make it possible for wells to operate and for companies that operate them to sell their gas to the market, are increasingly important for drillers to control. EQT is raising money to partially fund the deal by issuing up to 23 million shares of its stock. The rest will come from cash and its revolving credit facility. The company also plans to sell up to $350 million in senior notes. In its stock offering, EQT said it expects the deal to close late in the fourth quarter. Chevron put its position in this region up for sale in December after several years of waning interest in Appalachia. It entered the area in 2011 with a $4.3 billion acquisition of Atlas Energy Inc. At one point, the California-based energy giant planned to build a regional headquarters here and even bought land in Moon to do so. But its Appalachian aspirations began to dim around 2014 as natural gas prices settled into a stubborn valley. In December, after writing down the value of its Appalachian assets by billions of dollars, Chevron said it was marketing nearly 900,000 acres in the region. The deal with EQT includes 335,000 Marcellus shale acres, 37% of which are in what EQT believes to be the core area of the play. It also comes with 400,000 undeveloped acres in the Utica shale. EQT’s CEO Toby Rice said in a statement that when the deal closes, the assets will be “in the right hands.”

Adelphia Gateway Natural Gas Pipeline Begins Construction in Eastern Pennsylvania – Natural Gas Intelligence -Given clearance by FERC and state regulators, Adelphia Gateway LLC has started pre-construction on its brownfield natural gas pipeline expansion project in eastern Pennsylvania. Backed by New Jersey Resources Corp., the Adelphia project proposes converting part of an existing oil pipeline to natural gas to serve customers in the Greater Philadelphia area. Adelphia, which received authorization earlier this month to start Phase I of construction, told the Federal Energy Regulatory Commission last week that work had begun. The pipeline is slated to begin service next year. “The project continues to work closely with local stakeholders and governments as activity gets underway,” the developer said this week. “Adelphia Gateway will conduct additional outreach to inform residents and businesses of construction activities in their areas.”Phase 1 includes construction in parts of Delaware, Chester, Bucks and Montgomery counties and includes converting a 50-mile segment of an existing 84-mile oil pipeline to deliver natural gas. The northern 34-mile segment of the pipeline, running from western Bucks County to the Martins Creek terminal in Northampton County, has delivered natural gas since 1996.Adelphia President Ginger Richman said the developer expects to “bring natural gas resources to families and businesses in the Greater Philadelphia area and play a role in getting the region’s economy back up and running.”Adelphia secured a certificate from FERC by a 2-1 vote in late 2019. The project recently received permits from the Pennsylvania Department of Environmental Protection that were needed to start construction.

PBF Energy to shut fuel-producing units at Paulsboro, New Jersey refinery: letter (Reuters) – PBF Energy will shut most refining units at its Paulsboro, New Jersey, refinery, the company’s chief executive said in a letter to employees on Wednesday that cited the impact of the coronavirus pandemic on fuel demand. The company will cut 250 jobs at the refinery, which will now only produce partially refined feedstocks that will be sent to PBF’s nearby Delaware City, Delaware, refinery, CEO Tom Nimbley said in the letter, which was seen by Reuters. “PBF Energy, along with the entire oil industry, has been significantly, unexpectedly, and negatively impacted from the wellhead to the pump by the COVID-19 pandemic, primarily through demand destruction for transportation fuels related to lockdowns that throttled back the economy,” Nimbley said in the letter. It was sent to employees after the market close on Wednesday. PBF was not immediately available for comment. In a 2019 press release, PBF said it had 489 full-time workers at the refinery.

Shale continues to benefit US plastics firms in Appalachia region – Eagle Manufacturing Co., a maker of plastic safety products in Wellsburg, W.Va., was struggling with foreign competition in the early 2000s but was able to turn things around when shale gas and oil provided low energy costs and low-priced plastic resins as resin makers expanded. “It was tough to compete,” former Eagle President and CEO Joe Eddy said Oct. 22 during the 2020 Global Plastics Summit. “The country lost a lot of jobs, but we decided to stay instead of moving our production to China. “We didn’t move, and now we’re more profitable than ever. We’re more cost-effective and competitive, and China’s labor rates are increasing,” he said. Eagle was acquired in early 2018 by Justrite Manufacturing, with Eddy retiring in early 2019. He said shale continues to hold a lot of promise for manufacturing in the Ohio, Pennsylvania and West Virginia area. “A manufacturer can build a plant in the midst of the largest market on top of feedstock and in a low-cost energy area,” Eddy added. “The main thing is offering reduced energy costs and raw material costs to plastics processors.” The Appalachia region of those three states has benefited from development of the Marcellus and Utica shale fields. The combination of horizontal drilling and hydraulic fracturing (fracking) has allowed the development of feedstocks that previously couldn’t be reached. As a result of shale development, the U.S. now is producing more energy than it did in the 1970s, according to Jerry James, president of energy firm Artex Oil Co. of Marietta, Ohio, and co-founder of Shale Crescent USA, an organization that’s been promoting the region. “Wind and solar only make electricity, but [shale oil and gas] makes 5,000 products,” he said.

Big Oil’s hopes are pinned on plastics. It won’t end well. – Vox – The fossil fuel industry has not been doing well lately. Even before the Covid-19 pandemic hit, growth in global demand had slowed to 1 percent annually. Now, lockdowns and distancing to stop the spread of the coronavirus have decimated the industry. The International Energy Agency (IEA) recently released projections of rapid short-term decline in global demand, to the tune of 9 percent for oil, 8 percent for coal, and 5 percent for gas. Depending on how long and severe the economic crisis proves to be, it will take years for demand to recover. Indeed, with electric vehicles cutting into oil demand by the end of the decade, it may never fully recover. Industry analysts like Carbon Tracker’s Kingsmill Bond are speculating that 2019 may turn out to be the peak of fossil fuel demand, and historically, in other industries, a peak in demand “tends to mark the beginning of a period of low prices and poor returns,” says Bond. But the industry has a response to this dire forecast, and it can be summarized in one word: plastics. Overall, plastics represent a fairly small sliver of oil demand. Annually, the world consumes around 4,500 million tonnes (mt) of oil but only around 1,000mt of petrochemicals (oil and natural gas used to make chemical products), and of that 1,000mt, only about 350mt are plastics. (A tonne is a metric ton, about 1.1 US tons.)Nonetheless, plastics are commonly projected to be the biggest source of new demand for oil over coming decades – in some projections, the only real source. It is these projections that the industry is using to justify billions in new projects, as oil companies across the world shift investment toward petrochemicals. And Big Oil is working its hardest to make the projections come true: The New York Times recently ran an investigative piece revealing the industry’s plans to push more plastic, and plastic waste, into Kenya. Plastics are the thin reed upon which the industry is placing all its hopes.But a new report released in September by Carbon Tracker throws a big bucket of cold water on these hopes. It argues that, far from a reliable source of growth, plastics are uniquely vulnerable to disruption. They are coming under increasing scrutiny and regulation across the world. Huge consumer product companies like Unilever are phasing them out. And the public is turning against them.If existing solutions are fully implemented, growth in plastics could fall to zero. And if that happens, then there is no remaining source of net oil demand growth and 2019 will almost certainly prove to be the year of peak fossil fuels.

Plastic Continues to Capture Share of the US Pipe Market – US demand for pipe is forecast to reach $47.4 billion in 2024, with a particularly strong market performance expected for plastic pipe, as materials such as PVC and HDPE continue to gain share over other material types like metal in many applications due to such benefits as:

• corrosion resistance – key for such applications as sewers and buried pipe applications with acidic soils
• flexibility, which is important for trenchless installation
• low cost per linear foot due to their light weight

In addition, pipe replacement projects are expected to benefit suppliers of plastic pipe. Many communities are facing the replacement of aging water and sewer infrastructure, resulting in good growth for these sizable end markets for PVC and HDPE pipe.Plastic pipe demand is forecast to rise 3.5% per year through 2024, a faster rate than expected for overall pipe demand. Advances will be driven by increased water and sewer supply construction spending as urgency to update outdated infrastructure in the US continues to grow.Federal spending is expected to constitute a significant driver of growth in these applications, especially as local and state government face budget shortfalls due to the negative economic impact of COVID-19.One commonality between major water, sewer, and oil and gas transmission projects is pipeline size.Where plastic pipelines are replacing older infrastructure, these new plastic pipes are almost universally of a larger diameter than the ones they are replacing. As US water, sewer, and energy needs grow, so too does the diameter of pipes required to handle these needs adequately.As a result, the average diameter of plastic pipes is increasing, which will support growth in weight and value terms through 2024 and beyond.

Oil spill cleanup of Delaware Bay Coastline Intensifies Today With Additional Resources Deployed – The Department of Natural Resources and Environmental Control and U.S. Coast Guard continued Thursday and Friday to spearhead a cleanup operation for the oil spill that has deposited blobs of oil called tar balls and oiled debris this week over a stretch of Delaware coastline extending from the upper Delaware Bay to the tip of the Atlantic Ocean. The cleanup operation intensified this morning with additional resources deployed by state and federal agencies and non-profit organizations. More than 125 environmental professionals from DNREC, the Delaware Department of Transportation (DelDOT), the Coast Guard and its environmental contractor, and the Delaware Bay and River Cooperative are expected to be engaged Friday in removing oil found littering beaches and rafting around debris offshore. The Delaware Bay and River Cooperative, a non-profit funded by industry in the event of an oil spill, dispatched an oil skimming vessel to remove oily debris seen Thursday afloat in the Bay. Tri-State Bird Rescue of Newark continued to play a key role in the cleanup coalition, investigating reports of wildlife impacted by oil and treating captured sea gulls and other wildlife that has been oiled in the water. “We continue to mobilize our expert resources as the tides spread oil from the beaches back into the water and back on the beach,” said DNREC Secretary Shawn Garvin. “We are combing the beaches and, shovel by shovel, removing the tar balls and contaminated sand.” The crews are manually removing oil patties and tar balls are being found on various locations along the coast. Approximately 21 tons of oily sand and debris, filling 1 1/2 dumpsters, was removed from the affected areas as of 7 p.m. Thursday. “We are grateful for our interagency collaboration with DelDOT and for the help from the Delaware Bay and River Cooperative enabling us take the cleanup onto the water,” Secretary Garvin said. The city of Lewes Thursday closed its beaches temporarily due to oil that had come ashore and posed a threat to people and pets alike who visit them. DNREC closed the 4-wheel drive surf fishing crossing at Delaware Beach Plum Island Preserve, overseen by Delaware State Parks, so cleanup operations will not be hampered by vehicles tracking oil onto the sand. While the oil spill cleanup continues, the Coast Guard and DNREC strongly advise the public not to handle any oily product found or attempt to assist affected wildlife along the shore, but to report these findings to DNREC’s environmental hotline at 800-662-8802 so the situations can be addressed by hazmat-trained professionals.

Oil Spill Off Delaware Coast Affecting Less Than 1% Of Ocean City Beach Area, Officials Say – Cleanup efforts continued on the Delmarva Peninsula Tuesday more than a week after oil blobs first started washing ashore in the Delaware Bay. So far, roughly 55 tons of debris have been cleared. Still, currents continue to carry the oil south, with remnants now washing ashore in Ocean City, Maryland. “Over the course of the next four or five days, we’re going to have some issues,” Ocean City Mayor Rick Meehan said. “The good news is it affects less than 1% of the actual beach area.” Ocean City, Maryland Officials Monitoring Oil Spill Affecting Delaware Beaches Meehan said it’s a situation officials are closely monitoring. “The good news is if there is good news in something like this, is there are no toxic properties evident at this time, there are no harmful vapors and really isn’t any health hazard,” the mayor said. As for the environmental impact, Meehan said an upward of 66 birds have had some sort of interaction with the oil blobs, but in most cases, the birds were still able to fly. “We don’t see any real environmental issue at this time,” Meehan said. “But that’s why there’s such an extensive cleanup effort.” The cause of the spill is still unknown. The Coast Guard continues to investigate. “We are looking at all vessels that were in the area from a period of time before and even a period of time up to [the oil blobs] coming ashore,” Lieutenant Commander Coast Guard Frederick Pugh said.

Cleanup of oil spill from unknown source stretches into Ocean City – Cleanup of an oil spill from an unidentified source continues, extending into Ocean City, Maryland. The Maryland Department of the Environment has joined efforts to clean up oil and oil-drenched debris that has been washing ashore in Delaware and now Maryland since Oct. 19. Maryland’s department will work with the Delaware Department of Natural Resources under the guidance of the U.S. Coast Guard to help with the cleanup. The spilled oil has been washing ashore with high tide in “tar balls,” which range from coin- to pancake-sized, along with debris that has been drenched in oil. As of Tuesday, more than 65 tons of oil-covered sand and debris had been removed from Delaware beaches. Though many birds and fish have migrated from the area for the season, the Coast Guard said there have been reports of birds covered in oil. They have worked to clean the exposed birds and said that there did not appear to be any lasting impact on the animals. The spill prompted the closure of several beaches in Delaware and Maryland. Dewey Beach, Bethany Beach and Lewes have all closed their beaches as the cleanup efforts continue. “We’re not sure how long oily debris will continue to wash up with the tide,” said Shawn Garvin, secretary of the Delaware Department of Natural Resources, who was on scene surveying oil on the Delaware beaches on Wednesday. “Unfortunately, oil can be very persistent in the marine environment, but our environmental professionals are persistent, too,” Garvin said. “They’re out there, working up and down the coastline, getting it out of the sand as much as possible.” On Tuesday, a large beach cleanup was organized on South Bethany ahead of the arrival of the U.S. Army Corps of Engineers, who will begin a beach replenishment operation.

RI regulators approve natural gas rate hikes but push off bill impacts – State regulators have approved increases in natural gas rates proposed by National Grid, but, citing the continuing economic distress caused by the coronavirus crisis, they made the highly unusual decision to defer half of the bill impacts on ratepayers. “The COVID crisis and all its impacts have really clobbered Rhode Island,” Ronald Gerwatowski, chairman of the Rhode Island Public Utilities Commission, said at a virtual meeting on Wednesday. “It’s a once-in-a-hundred-year crisis. I think this reality needs to be confronted.” The decision to defer some of the costs for gas used for heating and cooking comes after the commission approved an electric rate increase in September that was also requested by National Grid, the state’s dominant energy utility. At that time, commission members considered pushing off part of the burden, but decided against it because of uncertainty surrounding the pandemic and how long it would continue. However in the past weeks since the electric case was decided, infections have spiked and Gov. Gina Raimondo has spoken of possibly tightening restrictions once more. With the commission’s vote, instead of paying an additional $97 over the 12-month period starting Sunday, the typical homeowner will pay about $48. For qualifying low-income customers, the annual increase will be about $35. The monthly increases work out to $6.87 and $4.82, respectively, and come on top of an $11 increase in the monthly electric bill for the typical household. (The electric increase will remain in effect until March 31, when rates will likely come down, while the new gas rates will stay in place until Oct. 31, 2021.) By deferring collections for half of the $30.7-million increase that they approved for National Grid’s gas business, commission members didn’t reduce the amount that customers will ultimately pay. In fact, because the deferred costs will collect interest, ratepayers will end up paying more when the bill comes due.

Healey wades into debate over Weymouth gas compressor station – Responding to a cadre of South Shore lawmakers who had asked her to intervene and address what they described as potential regulatory and civil rights violations impacting environmental justice communities, Attorney General Maura Healey said last week that her office will keep a close eye on a natural gas compressor station in Weymouth and is open to collaborating with lawmakers to change the permitting process for future projects. Last month, South Shore lawmakers who have long opposed the Weymouth project wrote to Healey with complaints that project operators and state agencies failed to provide sufficient notice to residents, particularly those in designated environmental justice communities, ahead of several important hearings and public comment periods.”In response to your concerns about public notices to environmental justice communities near the project, my team asked MassDEP to closely examine past public involvement practices with the facility and encouraged the agency to explore additional options for improvements going forward, including ensuring community responsive translation,” Healey wrote in her letter last week. “Public involvement by all communities, but especially environmental justice communities, is equally important. We understand that MassDEP intends to speak again with community leaders to solicit further feedback on what additional steps the agency could include in the current public involvement plan related to cleanup at the site to address any ongoing concerns.”Healey has previously called for Massachusetts to steer away from expanding natural gas infrastructure but has not vocally and directly opposed the compressor station that Enbridge sought and now controls in Weymouth. In her letter, however, Healey said she is “deeply concerned about the recent emergency natural gas releases at the facility,” and that her office has been in touch with federal regulators to discuss the issue.

Another lawsuit filed against bogged-down Mountain Valley Pipeline – Two endangered species of fish – the Roanoke logperch and the candy darter – could be pushed closer to extinction if a natural gas pipeline is allowed to invade their waters, according to a legal challenge filed Tuesday. A coalition of environmental groups asked a federal appeals court to review a biological opinion from the U.S. Fish and Wildlife Service, which found last month that construction of the Mountain Valley Pipeline is not likely to jeopardize protected fish, bats and mussels. It was the latest in a string of lawsuits that have long delayed work on the 303-mile pipeline. Also on Tuesday, the Sierra Club and 10 other environmental and conservation groups asked the Fish and Wildlife Service to stay its approval, one of several needed for the project to move forward. In a letter seeking the stay, the groups contend that the biological opinion failed to adequately consider how fish would be affected by increased sedimentation caused by the steel pipe crossing hundreds of streams, or how the Indiana and northern long-eared bats would survive the clearing of forests they inhabit. “These imperiled species are highly vulnerable to precisely the impacts that the Project would inflict,” Elly Benson, a senior attorney with the Sierra Club, wrote in the letter. Work on the controversial pipeline was put on hold a year ago, after the same environmental groups filed a legal challenge to Fish and Wildlife’s first biological opinion, issued in 2017. After a nearly year-long review, the agency last month issued its second approval – which was again challenged Tuesday. Benson’s letter asked the agency to act on its request for a stay “as soon as possible,” as construction crews begin to mobilize along the pipeline’s route from northern West Virginia, through Southwest Virginia, to connect with an existing pipeline near the North Carolina line. A spokeswoman for the Fish and Wildlife Service would only say that the request and court papers were under review.

Environmental Justice Advocates Sound Alarm Over Eastern Shore Pipeline – Maryland Matters – The proposed Eastern Shore Pipeline Project, which would bring fracked natural gas from Delaware into Somerset County, runs primarily through low-income communities of color, a recent analysis by the Chesapeake Climate Action Network found. Out of the 40 census blocks surrounding the proposed pipeline route through Maryland, only four were not identified as potential environmental justice populations. There are especially large majority minority and low-income populations concentrated around Salisbury in Wicomico County, where the proposed pipeline project would begin. The study also found a large census tract with over 70% minority population and 24% of low-income residents adjacent to the proposed pipeline in Somerset County. The natural gas pipeline already exists in in Delaware and Wicomico County in Maryland, but this project would extend it from Wicomico to Somerset County, one of three counties in Maryland that do not have access to natural gas and have missed economic opportunities because of it, according to Daniel K. Thompson, executive director of the Somerset County Economic Development Commission. With an unemployment rate at 9.1% and the highest poverty rate in the state at 23.4%, Somerset County would greatly benefit from access to natural gas, as it would provide additional tax revenue, decrease local businesses’ energy costs and help create more jobs, Thompson said. Mountaire Farms, the chicken processing company that is waiting to invest an additional $5 million and add five to seven new jobs, as well as Somerset Crossing, a development project in Princess Anne that will create 75-100 new jobs, will benefit immediately after natural gas is made available in Somerset County, Thompson said. “Somerset County has many challenges such as high unemployment, high poverty rates, high energy cost, etc. Therefore, why should one of the most challenged counties in Maryland not have access to natural gas, when other counties enjoy the benefits?” he said. Environmentalists argue that expanding gas infrastructure is short-sighted, as companies like the Chesapeake Energy Corporation (not affiliated with Chesapeake Utilities Corporation, the pipeline company) filed for bankruptcy this summer and many more are expected to do so by the end of next year. Rather, electrifying buildings is a lower cost alternative compared to gas and leads to lower energy bills in the long-run, according to Energy and Environmental Economics, Inc., an energy consulting firm.

Federal regulators order Atlantic Coast Pipeline to provide a plan for project wind-down, restoration – Almost four months after the cancellation of the Atlantic Coast Pipeline, federal regulators have ordered the project developers to provide a plan for what they intend to do with the facilities and the lands where the natural gas pipeline was supposed to be built. The order from the Federal Energy Regulatory Commission applies to both the Atlantic Coast Pipeline and the Supply Header Project, a roughly 38-mile pipeline that was expected to connect the ACP with existing pipelines in Ohio and Pennsylvania. “In order for us to determine if additional commission authorizations are required in conjunction with cancellations, we will need more detail about your plans regarding the authorized facilities,” wrote Rich McGuire, director of FERC’s Division of Gas Environment and Engineering, in an Oct. 27 letter to Dominion Energy Transmission, Inc., the majority owner of the project. FERC has asked that the plan be filed within 60 days. Among the requested information is a schedule for final arrangements regarding the project’s different phases and restoration activities related to them, a description of how areas where construction has begun but no pipe has been installed will be restored and “a plan for the long-term restoration of disturbed rights-of-way.”The company will also be required to provide an update on the status of its discussions with affected landowners, including “preferences regarding treatment of pipeline segments that have already been installed,” “preferences for removal of felled trees that have not been cleared” and “preferences on how disturbed areas would be restored, depending on their land use type.” The cancellation of the planned 604-mile pipeline left in limbo many landowners who had granted easements for the project, whether willingly or not. Atlantic Coast Pipeline signed a range of easements with landowners along the project’s path. While some included clauses terminating the easement if the pipeline wasn’t built within a certain period of time or imposing other restrictive terms, others granted the developers broader rights on a permanent basis. Asked about how Dominion intends to approach easements that remain in force and whether it plans to relinquish those easements, Dominion spokesperson Aaron Ruby said in an email the company “will work with each landowner whose property has been disturbed to develop a plan for the right of way on their property” and will “evaluate each easement agreement on a case-by-case basis in consultation with each landowner.” “Our goal is to close out the project as efficiently as possible and with minimal environmental disturbance,” he wrote.

U.S. natgas hits near 2-yr high on higher demand view, storm threat (Reuters) – U.S. natural gas futures climbed to their highest in nearly two years on Monday on forecasts for higher heating demand and concerns that Tropical Storm Zeta aiming at the U.S. Gulf Coast could disrupt production. Front-month gas futures rose 5.3 cents, or 1.8%, to settle at $3.024 per million British thermal units (mmBtu). Prices earlier rose to their highest since Jan. 25, 2019 at $3.080 per mmBtu. “We are seeing some very cold weather temperatures that will be coming across in the next week, so we are going to see some very strong demand,” said Phil Flynn, a senior analyst at Price Futures Group in Chicago. Data provider Refinitiv predicted 212 heating degree days (HDDs) over the next two weeks in the Lower 48 U.S. states, higher than the 30-year normal of 204 HDDs. HDDs measure the number of degrees a day’s average temperature is below 65 Fahrenheit (18 Celsius) and are used to estimate demand to heat homes and businesses. Refinitiv projected average demand would jump from 97 bcfd this week to 97.4 bcfd next week. Concerns that Tropical Storm Zeta, which was poised to turn into a hurricane as it approached the Gulf of Mexico, would disrupt oil and gas production, was also fuelling price gains, Flynn said. Zeta has already forced the closure of 16% of crude oil and 6% of natural gas production, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) said. Chevron Corp has evacuated staff from its U.S. Gulf of Mexico offshore facilities, while BP Plc and Equinor ASA withdrew workers and shut in offshore production ahead of the storm. U.S. output in the Lower 48 U.S. states was at 87.6 billion cubic feet per day (bcfd) on Sunday, Refinitiv said.

US natural gas holds near 21-month high – US natural gas futures held near a 21-month high on Tuesday on rising liquefied natural gas (LNG) exports and a drop in output as another storm targets the Gulf Coast. Traders noted the front-month was weighed down by expectations higher prices in November will cause power generators to burn more coal and less gas to produce electricity. On their second to last day as the front-month, gas futures for November delivery fell 0.5 cent, or 0.2%, to settle at $3.019 per million British thermal units (mmBtu). On Monday, the contract closed at its highest since January 2019. December futures, which will soon be the front-month, meanwhile, gained about six cents to settle at $3.31 per mmBtu, which would also be the highest close since January 2019. Data provider Refinitiv said output in the Lower 48 US states was on track to drop to 85.8 billion cubic feet per day (bcfd) on Tuesday, down about 2.9 bcfd over the last five days as Gulf Coast producers shut wells before Tropical Storm Zeta strengthens into a hurricane and hits eastern Louisiana on Wednesday. The US Bureau of Safety and Environmental Enforcement said energy firms have already shut in about 1.5 bcfd, or 55%, of offshore gas production in the Gulf of Mexico.

U.S. natgas futures slip from 21-month high as drop in crude prices weigh – U.S. natural gas futures slipped on Wednesday from a 21-month high earlier in the week as a 5% drop in crude futures weighed on all energy markets. That price dip came despite forecasts for colder weather and higher heating demand over the next two weeks, rising liquefied natural gas (LNG) exports, and a drop in output as producers shut wells ahead of Hurricane Zeta, which is expected to smash into eastern Louisiana later Wednesday. On their last day as the front-month, gas futures for November delivery fell 2.3 cents, or 0.8%, to settle at $2.996 per million British thermal units (mmBtu). On Monday, the contract closed at its highest since January 2019. December futures, which will soon be the front-month, meanwhile, lost about two cents to close at $3.29 per mmBtu, which would also be the highest since January 2019. Oil prices fell over 5% as surging coronavirus infections in the United States and Europe raised the specter of renewed lockdowns. Data provider Refinitiv said output in the Lower 48 U.S. states dropped to 84.8 billion cubic feet per day (bcfd) on Tuesday, down 3.8 bcfd over the last five days as Gulf Coast producers shut wells for Zeta. U.S. regulators said energy firms shut about 1.5 bcfd, or 55%, of offshore Gulf of Mexico gas production. With colder weather coming, Refinitiv projected demand, including exports, would rise from an average of 97.7 bcfd this week to 98.2 bcfd next week. The amount of gas flowing to LNG export plants averaged 7.4 bcfd so far in October. That would be the most in a month since April and puts exports on track to rise for a third month in a row for the first time since February, when feedgas hit a record 8.7 bcfd as rising global gas prices prompted buyers to purchase more U.S. gas.

November Natural Gas Falls Short of $3 Mark as Cold Seen Moderating; Cash Strengthens — Natural gas traders on Wednesday struggled with which side of the $3.00/MMBtu mark the prompt-month futures contract should roll off the board. With an uncertain weather outlook weighing heavily on the market, the November Nymex contract expired 2.3 cents lower at $2.996. December, which moves to the front of the curve on Thursday, fell 2.0 cents to $3.291. Spot gas prices were mixed as chilly air intensified across the country’s midsection. NGI’s Spot Gas National Avg. climbed 8.5 cents to $3.025. With weather becoming increasingly important given the fast approaching start of winter for the gas markets, the current cold blast was propping up demand as far south as Texas. Bespoke Weather Services said the morning forecast changes were mixed, but slightly colder overall. A “sneaky” trough swinging through the East early next week continued to move colder, although the warming in the wake of this feature is strong, according to the forecaster. This would lead to warmer changes in all of the eastern half of the nation in the back half of next week. “The crucial part of the forecast remains what comes as we move toward the middle third of November,” Bespoke said. There are signs of colder weather, which was reflected again in the midday weather models, but they are likely to be limited to the western half of the country, at least initially, according to the firm. Currently, below normal gas-weighted degree days are seen at the end of the 15-day outlook, but models are to be heavily scrutinized in case the western cold is able to spread eastward toward mid-month. “Confidence is below average for now,” Bespoke said. On the supply front, more offshore production was being shut-in as Category 2 Hurricane Zeta moved her way through the Gulf of Mexico (GOM).In the 4 p.m. CT update, the National Hurricane Center said Zeta was making landfall in southeastern Louisiana packing maximum sustained winds of 110 mph. On the forecast track, the storm was projected to make a second landfall along the Mississippi coast Wednesday evening, then move across the southeastern and eastern United States on Thursday.Before noon Wednesday, more than 66% of the oil and about 45% of the natural gas produced in the GOM had been shut-in, according to the Bureau of Safety and Environmental Enforcement. Personnel had been evacuated from three nondynamically positioned rigs, and six dynamically positioned rigs had been moved out of the storm’s projected path.

US working natural gas volumes in underground storage rise by 29 Bcf: EIA – US natural gas storage volumes expanded well below market expectations last week, while a net withdrawal is anticipated for the week in progress, kicking off the heating season two weeks earlier than last year.Storage inventories increased by 29 Bcf to 3.955 Tcf for the week ended Oct. 23, the US Energy Information Administration reported the morning of Oct. 29. The injection was less than an S&P Global Platts’ survey of analysts calling for a 37 Bcf build. Responses to the survey ranged from an injection of 32 Bcf to 53 Bcf. The injection measured much less than the 89 Bcf build reported during the same week last year as well as the five-year average gain of 67 Bcf, according to EIA data. Storage volumes now stand 285 Bcf, or 8%, more than the year-ago level of 3.670 Tcf and 289 Bcf, or 8%, more than the five-year average of 3.666 Tcf. The NYMEX Henry Hub December contract shed 7 cents to $3.21/MMBtu in trading following the release of the weekly storage report at 10:30 am ET. However, those declines shifted during the afternoon, with the prompt month back to $3.29/MMBtu. S&P Global Platts Analytics’ supply and demand model currently forecasts a 29 Bcf withdrawal for the week ending Oct. 30. The net withdrawal looks to occur two weeks earlier than the first draw last year as the surplus to the five-year average would shrink by a sizable 81 Bcf. The first pull of the year typically occurs during the first full week of November, according to EIA historical data. Hurricane Zeta smashed into Louisiana on Oct. 28, making it the fifth storm to strike the state this year. It crippled offshore production in the Gulf of Mexico. Offshore output declined from 2.2 Bcf/d on Oct. 22 to 1 Bcf/d by Oct. 27 in anticipation of the storm. It fell to 294 MMcf/d in the storm’s wake on Oct. 29. Zeta is weaker than the three major hurricanes that have pummeled the US Gulf Coast over the last two months during this historic season. Based on the initial offshore declines, the storm is likely to have a primarily bullish effect on prices at Henry Hub, according to Platts Analytics. Zeta set a record as the 11th named storm to make landfall in the Lower 48 in a single season. It is also the 27th named storm of the year, already tying the record-setting 2005, but with a full month remaining in the hurricane season. The sudden supply losses come just as the US begins to see the first signs of winter demand, easing the massive supply overhang that has built up through most of the summer. Colder weather across much of the country has increased residential and commercial demand by 7.4 Bcf/d for the week in progress.

Natural Gas Futures Rise from Dead as EIA Storage Data Scares Bears – Natural gas traders waking up with any neck pain on Friday may have a case of whiplash after Thursday’s wild ride in the futures market. The December Nymex contract, on the first day in the prompt-month position, plunged early to a $3.151 intraday low before screaming back higher to settle at $3.301, up a penny on the day. January closed six-tenths of a cent higher at $3.417. The same could not be said for spot gas, which traded Thursday for gas delivery through Saturday. Small losses were seen across most of the country, but big gains on the East Coast lifted NGI‘s Spot Gas National Avg. up 1.5 cents to $3.040.In a battle between bearish weather outlooks and tighter supply/demand balances, the December Nymex gas futures contract made a big entrance on its first day at the front of the curve. The contract traded in a nearly 20-cent range before settling near the high end.The early losses largely were because of further confirmation that after next week’s cold blasts, a warmer regime would settle over the United States, particularly in the higher demand regions like the Northeast. The midday Global Forecast System trended even milder for the Nov. 8-12 period, according to NatGasWeather.Production also started to come back after Hurricane Zeta, a Category 2 storm, made landfall Wednesday afternoon near Cocodrie, LA, about 75 miles southwest of New Orleans. Genscape Inc. said Thursday’s top-day estimates showed U.S. production up 1.4 Bcf/d to 84.9 Bcf/d. Analyst Josh Garcia noted that Wednesday’s production levels were already down day/day but then suffered a 1.7 Bcf/d downward revision to finish at 83.5 Bcf/d.”This is a drop of 3.2 Bcf/d day/day from Oct. 26’s production number of 86.7 Bcf/d,” Garcia said. In addition to Gulf of Mexico shut-ins, including about 45% of natural gas, Genscape estimated output declines this week in Texas, the Midcontinent and the New Mexico portion of the Permian. Gains on Thursday were centered in Texas (up 587 MMcf/d) and in the Permian New Mexico (up 787 MMcf/d), according to Garcia.”Gulf production is still depressed due to the hurricane, sitting at 148 MMcf/d” Thursday, he said. “One place where production has not been hampered is the East, where it has been rising since early October due to stronger local economics.”Genscape estimated East region production at 32.9 Bcf/d for Thursday, up from the month-to-date average of 31.9 Bcf/d.On the bullish side, the latest government storage inventory report surprised the market when it reported a much smaller-than-expected 29 Bcf injection. Ahead of the report, injection estimates ranged from 17 Bcf to 46 Bcf, though many surveys had reached a consensus of a build in the upper 30s Bcf.

Weekly Natural Gas Prices Spike as Chilly Air Intensifies, Zeta Strikes – In an abbreviated week of spot trading influenced by colder weather and yet another hurricane in the Gulf of Mexico (GOM), weekly cash prices surged. NGI‘s Weekly Spot Gas National Avg. for the Oct. 26-29 period jumped 59.5 cents to $3.000. This week’s average only includes trades conducted through Thursday, the cutoff for gas delivery through the end of October. Chilly air settled in across the country’s midsection, freezing the Upper Midwest and delivering below-average temperatures as far south as Texas. The cold blast boosted heating demand across large swaths of the Lower 48 and propped up spot gas prices. On the supply front, offshore production was shut-in as Category 2 Hurricane Zeta arrived in the GOM Wednesday. Zeta made landfall in southeastern Louisiana packing maximum sustained winds of 110 mph, before moving across the southeastern and eastern United States on Thursday. Ahead of its arrival, 45% of the natural gas produced in the GOM had been shut-in, according to the Bureau of Safety and Environmental Enforcement. The threat to supply provided additional cash price support. Weekly prices spiked in several regions, with hubs in Texas and the Northeast leading the way. El Paso Permian jumped $2.450 to average $2.535, whileWaha climbed $2.385 to $2.395. In the East, Algonquin Citygate advanced $2.335 to $4.275, and PNGTS bounced $1.700 to $5.000. NatGasWeather said new blasts of cold could support demand early in the first week of November. The Energy Information Administration said that U.S. stocks rose by 29 Bcf for the week ending Oct. 23. Markets had anticipated a larger build of as much as 46 Bcf. NGI had projected a 42 Bcf injection.Bespoke Weather Services said the 29 Bcf number suggested that recently higher prices were not yet curbing demand. Prices could climb higher in coming weeks if Mother Nature cooperates with further blasts of unseasonably cold air later in November.For the week covered by EIA’s latest storage report, strong liquified natural gas (LNG) levels, with feed gas deliveries above 8 Bcf, helped drive demand and keep injections low.Total working gas in storage for the week rose to 3,955 Bcf. That was 285 Bcf above year-earlier levels and 289 Bcf above the five-year average, according to EIA. A week earlier, the surpluses to the year-ago and five-year average were well above 300 Bcf.Analysts said that, in addition to weather, rising demand for U.S. LNG exports to fuel heating needs in Asia and Europe could help soak up supply and support prices moving into winter. LNG feed gas volumes inched up further early Friday after topping 9.5 Bcf/d a day earlier, led by rising output at Sabine Pass – 4.1 Bcf/d – according to EBW Analytics Group. Lifted by the LNG momentum, futures finished the week on a high note. The December Nymex contract gained 5.3 cents day/day and settled at $3.354/MMBtu. January advanced 5.2 cents to $3.469.

Opinion: Natural gas has less than a decade to figure out its carbon problem —Over the past decade, natural gas has been lauded as North America’s transition fuel – the abundant, cheaper, cleaner way to pivot from coal to a future of low-carbon fuels and renewables. By the end of 2019, natural gas’ share of the fuels used to generate electricity had grown to 38 percent, up from 24 percent in 2010. That replacement of coal with natural gas helped utilities reduce carbon emissions by 4.6 billion metric tons between 2010 and 2018, Oliver Wyman calculations show – a monumental achievement at a time when power consumption was increasing. Oliver Wyman, an international consulting firm, estimates that coal will be eliminated from the mix of fuels used in power generation by 2031 – at the latest. The problem for natural gas: Coal is now being replaced by even cleaner, and in recent years, cheaper, renewable energy. Once that transition from coal is complete, if not before, all eyes will turn to natural gas as it takes on the mantle of the biggest carbon emitter still in use in power generation. And the calls to eliminate natural gas – an agenda that is already being pushed by some – will intensify. When the per megawatt-hour lifetime cost of wind-generated electricity fell below the comparable cost of natural gas generation in 2019, these demands became achievable. The only hurdle left for renewables is creating enough storage for solar and wind energy, a necessity increasingly recognized by many producers and investors. While Oliver Wyman estimates that 2039 is the earliest comprehensive storage coverage for renewables can be developed, there could be enough storage by 2025 to start pushing natural gas out of the generation mix and into significant decline. By 2034, enough storage will likely have been built to allow utilities to rely almost entirely on renewables for power generation, except perhaps during extreme peaks in power usage, Oliver Wyman data show. The choices for natural gas Where does that leave natural gas? Natural gas and power generation are strongly linked. Natural gas is the largest fuel source for power generation, and power generation is also the largest use of natural gas, accounting for up to 62 percent of downstream gas use, according to the U.S. Energy Information Administration. If no action is taken to change natural gas’ current trajectory, renewables will dominate the generation mix across the United States and Canada by the end of the decade. This will narrow the share provided by natural gas to potentially less than 10 percent, according to our data. We estimate that such a dramatic reduction in natural gas’ share of the generation mix could cause the destruction of as much as $4.7 trillion of the industry’s value by 2050 – and that’s from well head to turbine. It shouldn’t be surprising as it’s a phenomenon already well underway in coal and beginning to be seen in oil assets.

DTE to spin off its natural gas pipeline, storage business – Detroit-based DTE Energy announced Tuesday that it plans to unload its natural gas pipeline and storage subsidiary, DTE Midstream, by spinning off the business to be its own publicly traded company. Midstream, which would keep its headquarters in Detroit, owns more than 2,300 miles of pipeline across the Midwest and Northeast and in Louisiana. DTE said the separation isn’t expected to have any “adverse impact” on DTE customers or customer rates. DTE bought much of the Midstream pipeline in 2016 and 2019 deals valued at $1.3 billion and $2.5 billion, respectively. The pipeline deals were described at the time as efforts to further diversify DTE’s business beyond electricity provision. When the Midstream transaction is done, DTE would get about 90% of its operating earnings from its core utility business versus 70% today. The transaction was hinted at earlier this month by Bloomberg News, which reported that other power companies have been retreating from the pipeline business after having bought natural gas infrastructure in past years in a search for growth. In a call Tuesday morning with Wall Street analysts, DTE executives said the Midstream spinoff will “unlock significant shareholder value.” Asked why the utility chose to make Midstream its own publicly trade company rather than simply sell the business to someone, DTE President and CEO Jerry Norcia said the spinoff strategy makes the most sense for shareholders. Under the Midstream separation plan, DTE shareholders will retain their current shares of DTE Energy stock and get a pro-rata dividend of shares of the new Midstream stock via a tax-free transaction.

Environmental groups react to state hiring outside expert to review Line 5 tunnel project – Environmental groups are responding to news that the state will retain an outside expert to review the Line 5 tunnel project. Last month, environmental groups and engineers raised concerns about the state’s ability to review Enbridge’s Line 5 tunnel project – worrying they didn’t employ experts who could provide an adequate review of the project. The Michigan Department of Environment, Great Lakes, and Energy has since announced it will retain an international civil engineering firm to provide a technical review. David Holtz is with Oil and Water Don’t Mix, an environmental group opposed to the tunnel project and continued operation of the Line 5 pipeline. “It’s a good step,” he said. “It’s a positive step potentially but it’s still an open question whether it will have any real meaning.” Holtz said it’s good the state is taking a review of the pipeline tunnel seriously – but it’s unclear how much the consultant’s analysis will factor into a decision on whether to greenlight the project. “It’s great that they hired consultants, engineers, to fill the gap in their own expertise,” he said. “But that doesn’t take away from the fact that their major responsibility is still to protect the Great Lakes. Every day that pipeline is there they are not doing it.’ The firm hired by the state to review the tunnel project did not respond to our request for comment. Separately, an Administrative law judge ruled last week that the Michigan Public Service Commission will have the authority to review the tunnel project, something Enbridge Energy, which owns the pipeline, had argued against.

U.S. offshore energy producers brace for Hurricane Zeta impact (Reuters) – Energy firms and ports along the U.S. Gulf Coast prepared on Tuesday for another test as Hurricane Zeta, the 11th hurricane of the season, entered the Gulf of Mexico. BP BP.L, Chevron CVX.N and Royal Dutch Shell RDSa.L, among others, evacuated 157 offshore facilities and sharply cut production from the offshore region. Pipeline operator Enbridge ENB.TO evacuated two platforms and removed workers from a Louisiana natural gas processing plant. Some oil producers were pulling staff for at least the sixth time since June, a process made more difficult by the COVID-19 pandemic with workers required to be tested for the virus before returning to work. Energy producers on Tuesday shut nearly half the region’s oil output, or 914,811 barrels per day (bpd), and 1.5 billion cubic feet per day, or more than half its natural gas output, the U.S. offshore energy regulator said. U.S. Gulf of Mexico offshore oil production accounts for about 17% of total U.S. crude oil output and 5% of total U.S. dry natural gas production. Zeta’s winds decreased to 65 miles per hour (100 kph) after sweeping across the Yucatan Peninsula early Tuesday but are forecast to restrengthen to 85 mph as its churns over the central Gulf of Mexico, the NHC said in a mid-day update. On Monday, it became the 11th hurricane of the Atlantic season, which on average has six. A hurricane watch was issued for parts of Louisiana to the Mississippi-Alabama border by the U.S. National Hurricane Center (NHC). Zeta could hit the U.S. coast on Wednesday at or near hurricane strength, the NHC said. Energy ports from Baton Rouge to Pascagoula were operating under advisories warning of the potential for gale force winds. A Louisiana deep water oil export port said it was implementing its inclement weather plan. U.S. crude futures gained 1.8% in Tuesday trading after falling more than 3% on Monday over fears of rising COVID-19 cases and increased crude supplies.

Zeta Almost Halves US GOM Oil Output – The Bureau of Safety and Environmental Enforcement (BSEE) estimates that around 49.45 percent of oil production and around 55.35 percent of natural gas production in the U.S. Gulf of Mexico (GOM) has been shut-in due to Tropical Storm Zeta. Personnel have been evacuated from a total of 154 production platforms in the region, which is equivalent to 23.95 percent of the 643 manned platforms in the area, the BSEE highlighted. Personnel are also said to have been evacuated from three non-dynamically positioned rigs in the U.S. GOM, which is equivalent to 30 percent of the ten rigs of this type currently operating in the region. A total of nine dynamically positioned rigs have moved out of the hurricane’s projected path as a precaution. This number represents 56.25 percent of the 16 dynamically positioned rigs currently operating in the U.S. GOM. In a statement posted on its Twitter page, the National Hurricane Center stated that a life-threatening storm surge is expected later today as the tropical storm impacts the Northern Gulf Coast. The BSEE reported on Tuesday that, as of Monday, just under 15 percent of oil production and six percent of gas production had been taken offline in the U.S. GOM due to Tropical Storm Zeta. In addition to Zeta, several storms have affected U.S. GOM production this year including Hurricane Delta, Hurricane Sally, Hurricane Laura and Tropical Storm Cristobal. The BSEE describes the Gulf of Mexico U.S. Outer Continental Shelf region as a “major focus” of the oil and gas industry. The organization says its GOM region staff oversee nearly 1,884 facilities and about 17,507 miles of active pipeline in the area. Since its establishment in 2011, the BSEE has been the lead federal agency charged with improving safety and ensuring environmental protection related to the offshore energy industry, primarily oil and natural gas, on the U.S. OCS, the organization’s website states.

Historic hurricane season wreaked havoc on offshore drillers – Offshore oil companies faced the most disruption from the 2020 hurricane season in over a decade, according to a new report. The 2020 Atlantic hurricane season, the second most active on record, forced offshore oil producers to curtail about 110,000 barrels per day. That’s the most since the 2008 hurricane season, which saw curtailments of nearly 140,000 barrels of oil a day. Before this year, hurricanes temporarily halted production on an average of about 20,000 barrels of oil per day, according to S&P Global Platts, an energy research firm. The report comes as Tropical Storm Zeta is barreling toward the U.S. Gulf Coast, expected to make landfall in Louisiana as a Category 1 or 2 hurricane on Wednesday afternoon. Offshore oil and gas operators have evacuated personnel from 154 platforms as of Tuesday, nearly a quarter of all the platforms in operation in the Gulf of Mexico, and shut in about half of the oil production from the Gulf, according to the Bureau of Safety and Environmental Enforcement. Zeta is the 27th named tropical storm this year, just shy of the 2005 Atlantic hurricane season that saw 28 named storms and production curtailments of 220,000 oil barrels per day. Meteorologists ran out of traditional names for hurricanes this year, turning to the Greek alphabet. This year’s particularly active hurricane season has wreaked havoc on offshore oil and gas companies, which must temporarily halt production, move rigs and secure platforms and evacuate workers via helicopter whenever a tropical storm approaches. Talos Energy said it has shut in production for 28 days in the third quarter because of Hurricanes Hanna, Laura, Marco, Sally and Beta. The Houston-based offshore producer during the fourth quarter shut in production during Hurricane Delta for a week, the company reported earlier this month. Talos CEO Tim Duncan said it saw an average of seven days of production downtime due to hurricanes over the past five years. “If you shut in production eight days a year because of hurricanes, that’s not a big deal,” Duncan said earlier this month. “If you do that for 30 days, that’s a bigger deal. It’s frustrating for us and it’s frustrating for our employees.” Offshore oil and gas companies may face more disruption to operations as climate change causes hurricanes to become more frequent and intense in the Gulf of Mexico. Texas Tech Climate Center scientists warned that hurricanes may become stronger and stall over land due to warmer air and ocean waters. Warming ocean temperatures increase the strength of hurricanes.

Much Too Much – Distillate Glut Challenges U.S. Refiners But Offers Contango Opportunity –For the past several months, U.S. refineries have been producing more distillate than demand warrants, resulting in a glut of distillate fuels, especially ultra-low-sulfur diesel and jet fuel. The disconnect between supply and demand has been particularly stark in the Gulf Coast region, where just a couple of weeks ago distillate stocks sat 39% above their 10-year average after coming perilously close to tank tops in August. The culprit, of course, is COVID-19, or more specifically the effects of the pandemic on air travel and the broader economy. Demand for motor gasoline rebounded more quickly than demand for ULSD and jet fuel, and refineries churned out more gasoline to keep up, but that results in more distillate too. Now, finally, there are signs that distillate stocks may be easing back down. Today, we discuss the build-up in ULSD and jet fuel stockpiles, the ways they might revert to the norm, and the potential for storing distillate now and selling it at a higher price later.This blog is based on research from Morningstar Commodities. A copy of the original report is available here. The collapse in crude oil prices earlier this year and COVID-19’s negative effects on demand for refined products put an unprecedented squeeze on U.S. refiners – a topic we first discussed back in March in Strange Brew. The net result was a miserable second quarter for the refining sector. As we said in Where Are You Going, not only did refiners produce less diesel, motor gasoline, and jet fuel in the April-through-June period than any quarter in recent memory, their refining margins were sharply lower than the historical range – a one-two punch that hit their bottom lines hard. Refiners’ troubles didn’t end there. Persistently high distillate inventories this year are compounding refiners’ woes by weighing on product prices and constraining processing levels. Total U.S. distillate stocks have been at or near record territory since April, according to weekly data from the Energy Information Administration (EIA), and only dropped below their seasonal 10-year high at the end of September. Total inventory of 172 MMbbl on October 2 was 44 MMbbl higher than this time last year, but down about 1 MMbbl per week from a peak of 180 MMbbl in early August. The 172 MMbbl in storage represented 48 days of supply based on implied demand of 3.6 MMb/d. Total U.S. working storage capacity for distillates is 218 MMbbl, according to an EIA survey from March 31, 2020, meaning that storage was 79% full as of October 2.

Louisiana Ballot Measure Could Slash Oil and Gas Property Taxes That the State Already Subsidizes – Lake Charles recently made national news on its own, as one of the first U.S. cities ever hit by back-to-back hurricanes just six weeks apart. Hurricane Laura’s sustained 150 mph winds left the city in ruins in late August, and residents had barely begun to clear those debris when Hurricane Delta dropped more than 15 inches of water on Lake Charles in early October. Lake Charles and other communities across Southwest Louisiana facing as much as $12 billion in hurricane damages to homes and businesses, and another $1.6 billion in agricultural and timber losses. So a new tax break for the state’s dominant oil and gas sector might not seem logical. But a measure on this year’s ballot could change the state constitution in a way that ultimately exempts the industry from property taxes in perpetuity. The measure, called Constitutional Amendment 5, would allow local governments to make deals with manufacturers for up-front property tax payments into municipal tax coffers, in return for waiving future payments on new or substantially enlarged manufacturing facilities, as long as a two-thirds supermajority of both houses of the state legislature approved the deal. If voters approve the measure, Louisiana’s $73 billion oil and natural gas industry, which the state has already blessed with substantial property tax subsidies, stands to save billions more.

Complaint says Enbridge’s new $2.6 billion pipeline is no longer necessary – A Minnesota Indigenous environmental group told state utility regulators Tuesday that Enbridge has been adding considerable capacity to its existing oil pipelines in recent years, making the company’s controversial new $2.6 billion pipeline unnecessary. Honor the Earth, in a filing, asked the Minnesota Public Utilities Commission to investigate Enbridge’s capacity additions, saying the company made no mention of such moves during extensive hearings for the pipeline, a replacement for its deteriorating Line 3. “It is difficult to see how (the new Line 3) is in the public interest in light of the apparent fact that Enbridge has already achieved (the pipeline’s) capacity addition goals through other less impactful means,” Honor the Earth said in a PUC filing. Calgary-based Enbridge has been adding capacity to its “mainline” across Minnesota through various efficiency improvements. “There have been several initiatives that Enbridge has implemented in recent years to optimize its pipeline network to better meet customer demands,” the company said in a statement. “We’ve talked about these optimizations and efficiency-led capacity increases in a variety of public forums.” Tuesday’s PUC filing is the latest missive in the six-year battle over the new pipeline. The existing Line 3 is corroding and operating at only 51% of capacity. The PUC reapproved the $2.6 billion new Line 3 earlier this year, though Enbridge is still waiting on several other state and federal permits. A new Line 3 would add 375,000 barrels per day to Enbridge’s Minnesota oil flow. Before economic effects of the coronavirus pandemic shrunk oil demand earlier this year, the mainline was pumping 2.8 million barrels per day. The mainline’s volume is now down to just over 2.4 million barrels per day, about what was considered capacity during PUC hearings a few years ago over the new pipeline. Honor the Earth claims in its filing that Enbridge did not disclose to the PUC the roughly 400,000 barrels per day in capacity additions to the PUC. Enbridge said in its statement that the company has been “transparent” throughout the Line 3 review process. Honor the Earth in its filing also lodged a complaint about capacity expansion proposals on two of the six pipelines that currently run across northern Minnesota to the company’s terminal in Superior, Wis. Those proposals, for Line 4 and Line 67, are currently under review by Wisconsin natural resource regulators. Enbridge filings in Wisconsin indicate the company plans on boosting the two pipelines’ throughput to “maximum design capacity,” adding another 178,400 barrels per day in oil flowing across Minnesota to Superior. Honor the Earth in its complaint says Line 4 and Line 67 should be recertified in Minnesota if they are expanded.

US Oil’s Merger Mania Won’t End Well For Energy — The long-awaited shale patch consolidation has arrived, sparking another bout of merger mania in the energy industry. It’s reminiscent of the one in the late 1990s, just as the Internet bubble was exploding. But don’t expect the stocks to rally this time. Parallels between tech in the 1990s and today are common. But there’s been little mention of what the energy sector went through at the same time and how it suddenly looks so familiar. History’s repeating itself as it appears energy can’t attract investors — again. Then as now, the backdrop to energy’s M&A boom is a collapse in oil prices. The difference this time, however, is the deals are happening at a quarter of the traditional premiums. During this pandemic era, four deals have already emerged: Chevron’s takeover of Noble Energy, ConocoPhillips’s acquisition of Concho Resources, Pioneer Natural Resources’s purchase of Parsley Energy and Devon Energy’s merger with WPX Energy. This appears to be just the beginning as rumors circulate of more deals to come. The economy has structurally changed since 2000, which makes tech’s acceleration look real and lasting. That’s not so for the energy industry, which staged a comeback in the early part of the century as tech dropped. But this time around, the sector faces worsening supply dynamics and a demand hit from which it’s likely to take years to recover. Supply dynamics were not favorable even before the pandemic. The American shale boom and cheating on OPEC+ production quotas created an oversupplied oil market. Trade risk added to worries for shale producers, which were already treading water. Since 2017, the pain has become clearer. Oil rallies have seldom spilled over into energy stocks beyond a brief increase in valuations spurred by private equity in 2016. Add the impact of the U.S. presidential election, and the risks multiply. In the final presidential debate, Democratic challenger Joe Biden advocated for a transition from oil to renewable energy. A potential fracking ban on federal lands, which makes up parts of the crucial Permian basin, presents more danger. It’s worth noting that China, the second-largest oil consumer behind the U.S., is moving aggressively toward that green energy transition and is establishing itself as a leader in electrification. Oil prices have largely traded in a range for nearly five months. Seeing so much M&A activity at low premiums tells us that the industry expects stagnation to continue since drastic shifts in crude prices could endanger the deals. In the short-term, stimulus prospects and a Covid-19 vaccine will likely lift oil prices, accelerate the rotation into cyclicals and perhaps even sustain gains for a while. More deals also are likely, which could boost interest in the sector. But in the long-term, expect energy to revert back to its multi-year downtrend as investors keep buying growth, consolidation shrinks the industry and the rise of ESG investing weighs on oil stocks

Why is Michael Bloomberg giving $2.6 million to elect a railroad commissioner in Texas? -Oil and gas companies burn off billions of cubic feet of natural gas into the atmosphere every year in Texas alone. It’s both wasteful – the gas could be used to power the state’s populous cities many times over – and a major source of climate-warming pollution. Nevertheless, the Texas Railroad Commission, the state agency that regulates the industry, has largely sanctioned the practice, rubber-stamping applications from companies that want to engage in unlimited flaring.An under-the-radar election for one of the commission’s three seats could change all that. On November 3, Democrat Chrysta Castaneda will face off against Republican Jim Wright, a South Texas businessman who runs an oilfield waste and recycling company. The odds are stacked against Castaneda: She’s running for a position that a Democrat hasn’t won in three decades. But with Democrats suddenly polling competitively up and down the ballot in Texas – not to mention a recent$2.6 million donation Castaneda’s campaign received from former New York City mayor Michael Bloomberg – the oil and gas attorney from Dallas may have a fighting chance.If she wins, she may be in a position to get the commission to drastically reduce greenhouse gas emissions in some of the largest oilfields in the country. For this reason, she calls the race “the most important climate election in the nation.”

Environmental groups sue EPA over ‘failure’ on industrial flare rules – Ten environmental organizations, including Air Alliance Houston and Environment Texas, on Thursday filed a lawsuit against the Environmental Protection Agency, asserting that the agency has failed to bolster pollution rules for industrial sites. The suit claims that the EPA’s failure to update the standards for flaring, the practice of burning off excess gases to prevent more toxic pollution to escape, has increased emissions. The regulations target flaring at petrochemical facilities, gasoline terminals, natural gas processing plants, compressor stations and solid-waste landfills. The environmental groups say that operators don’t always conduct the practice correctly, leading to the release of gases that endanger public health and that contribute to climate change. “Time and time again, EPA has admitted that flares operating under these outdated standards can release many times more toxic air pollutants into local communities than estimated,” said Adam Kron, senior attorney for the Environmental Integrity Project, the leading plaintiff in the suit, in a statement. “This can cause serious harm to public health.” The lawsuit claims that the EPA doesn’t require operators to improve flaring procedures because the agency hasn’t updated two key flaring pollution controls in decades; the Clean Air Act requires the agency review the rules once every eight years. The Environmental Integrity Project argues that the rules for flaring procedures have shown that they’re not as effective as the EPA originally desired. For example, operators inject steam into flares to prevent smoking, but at times operators inject too much steam, which causes the flare to burn poorly and release toxic gases that should have been destroyed during combustion. A spokesperson for the EPA said the agency doesn’t comment on pending litigation.

Colorado moves to ban routine natural gas flaring at oil wells – – Colorado may eliminate the practice of routinely burning off excess natural gas at oil wells, and the industry mainly supports the idea. The Colorado Oil & Gas Conservation Commission proposes stopping permitted flaring of excess natural gas at wells and requiring companies to build gathering systems to capture the gas by early 2022. The percentage of gas flared in the state is second-lowest among major U.S. oil-producing states, according to the Colorado Oil & Gas Association. Major oil and gas producers told the COGCC they’ve invested in capturing the natural gas their oil wells produce, known as associated natural gas, instead of routinely burning it off. “We do not flare associated gas now and we will not flare associated gas in the future,” said Angela Zivkovich, health, safety and environment manager for Occidental Petroleum Corp. The Houston-based company (NYSE: OXY) is the largest oil and gas producer in the state. The COGCC commissioners have been taking testimony this week about flaring and other aspects of rule changes proposed as part of a larger overhaul of oil and gas regulation. The commission is slated to finalize flaring-related rule changes this week and then by mid-November formally vote on a broader package of rules changes. Smaller companies with oil wells outside the main oilfields of the Denver Julesburg Basin do flare excess gas. Oklahoma-based Sandridge Exploration & Production LLC, which operates oil wells in Jackson County in North Park, has burned off the majority of the natural gas its wells produce. It will have to build gathering systems unless the COGCC grants it a variance from the new rules. Flaring natural gas ballooned after 2009 as fracking and horizontal drilling drove a boom in oil well drilling in areas that didn’t have natural gas gathering infrastructure. Low natural gas prices that can make natural gas an unwanted byproduct of oil wells. Gas-gathering systems have mostly been built covering the Denver-Julesburg Basin, and natural gas flared as excess has become more rare. Routine flaring will go away entirely, but flaring will be allowed in emergencies, and some burning off of gas will be allowed. Nearly half the carbon dioxide produced by flaring at Colorado wells doesn’t come from burning off excess natural gas. It’s from enclosed burning of gas vapors produced by wells, according to a calculation of flaring data by the Audubon Society and wildlife group testifying at the hearing. They urged the COGCC to include enclosed combustion in the definition of flaring, saying it’s part of practices that produce the equivalent greenhouse gas pollution of 118,000 automobiles on Colorado roads.

INTERIOR: Grijalva warns ‘business as usual’ with Pendley risky — Monday, October 26, 2020 — House Natural Resources Chairman Raul Grijalva is urging the Interior Department to slow down and “determine the consequences” of a federal judge’s ruling striking down William Perry Pendley’s 424-day tenure leading the Bureau of Land Management.

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