natural gas prices fall by most in 8 years, maybe most ever; SPR at an 18 1/2 year low; 22 week low in gasoline demand

natural gas prices fall by the most in almost 8 years, maybe ​by the most ever; Strategic Petroleum Reserve ​is ​at an 18 1/2 year low; gasoline supplies rose by most in 22 weeks on a 22 week low in demand

oil prices fell for the sixth consecutive week​ this week​, as OPEC decided to increase production even as a Omicron surge loomed...after falling 10.4% to $68.15 a barrel last week after the discovery of a new Covid variant sent global markets tumbling, the contract price for US light sweet crude for January delivery opened 2% higher on Monday on bargain hunting by oil traders returning to the market following "black Friday's" 13% plunge, and rallied more than 5% to trade as high as $72.93​,​ before paring the day's gains to settle $1.80 higher at $69.95 a barrel, as traders turned their focus to the upcoming meeting among OPEC and Russia-led partners, and the possible delay of their planned production increase in light of renewed travel resections tied to the emergence omicron variant of ​Covid....but oil prices tumbled nearly 5 percent on Tuesday after Moderna’s ​CEO cast doubt on the efficacy of COVID-19 vaccines against the Omicron variant, spooking financial markets and adding to worries about oil demand, as oil ​settled $3.77 lower at $66.18 a barrel, thus ending November 20.8% lower, the biggest monthly drop in prices since March 2020....oil prices jumped more than 4% ahead of the OPEC meeting early Wednesday on speculation the producer's group might pause their supply hikes, but pared a portion of the gains late morning Wednesday after an inventory report from the EIA showed domestic crude oil production jumped to an 18-month high, and gasoline and distillate fuels supplies registered large builds, only to completely reverse the morning rally to fall 5% and settle 61 cents lower at $65.57 per barrel​,​ after the CDC announced the first US case of Omicron...oil prices whipsawed between 5% lower and 3% higher on Thursday, as traders reassessed near-term supply fundamentals after OPEC+ unexpectedly decided to proceed with a 400,000-barrel-per-day (bpd) production increase, a move that ​was expected to exacerbate a buildup in global oil inventories, and settled 93 cents higher at $66.50 a barrel, even as the alliance said in a statement that "the meeting remains in session," ​suggesting they c​ould "make immediate adjustments" should the current market conditions shift... oil prices continued higher early Friday, rising as much as 4% at one point, after the OPEC+ alliance said it could immediately revisit that 400,000 bpd increase if demand suffers in coming weeks, but again reversed and gave back all its gains, closing 24 cents lower at $66.26 a barrel, as a weaker-than-expected US jobs report and ​the ​rapidly spreading omicron variant added uncertainty to demand outlooks, and thus closed down for the sixth straight week, the longest stretch of weekly declines since 2018, and 2.8% lower than last Friday's close...

t​o illustrate how oil prices ran up to a 7 year high of $83.83 on October ​25th only to tumble back to a three month low this week, we'll include a graph below showing the trajectory of oil prices over the past 6 months..

The above is a screenshot of the current contract's interactive oil price chart from barchart.com, which i have set to show ​daily oil prices ​for the January 2022 oil contract over the past 6 months....th​at​ same chart can be reset to show prices of front month or individual monthly oil contracts over time periods ranging from 1 day to 30 years, as the menu bar on the top indicates, and also to show oil prices by the minute, hour, day, week or month for each...each bar in the graph above represents the range of oil prices for ​one day, with days when prices rose indicated in green, with th​at ​day's ​opening price at the bottom of the bar and the​ day's​ closing price at the top, ​while ​days when prices fell ​are ​indicated in red, with the opening price at the top of the bar and the closing price at the bottom​...the small barely visible sticks above or below each monthly bar represent the extent of the price change above or below the opening and closing price during the ​day in question....​ ​likewise, the bars across the bottom show trading volume for the ​January oil contract for the ​days in question, again with up ​days indicated by green bars and down ​days indicated in red....​espectially noteworthy on the graph above is the 13.1% drop in prices on Friday of last week,​ the largest daily drop since April 2020 (when oil prices ​fell below $0)​, when global markets tanked with the discovery of the new Covid strain...​

meanwhile, ​this week's ​natural gas prices fell by the most in nearly 8 years ​due to a forecast​ for a​ warm December, increasing expectations that gas supplies would ​remain adequate for the rest of winter​....after the contract price of natural gas for December delivery rose 7.5% to expire at $5.447 per mmBTU last week on higher domestic heating demand and record global gas prices, this week's natural gas trading started with the contract price of natural gas for January delivery plummeting 62.3 cents or 11.4% to $4.854 per mmBTU, as forecasts shifted warmer through the middle of December, allaying concern about tight domestic supplies amid a global shortage of the fuel...natural gas prices continued tumbling Tuesday, shedding another 28.7 cents or nearly 6%​,​ to settle at a 3 month low of $4.567 per mmBTU, as traders looked past robust demand for U.S. exports and fixated on exceptionally light domestic heating demand expectations heading well into December, as natural gas contracts ended November down more than 15%, the biggest monthly percentage loss since January 2020....natural gas prices were down almost 7% again on Wednesday in falling 30.9 cents to ​another ​3 month low ​at $4.258 per mmBTU, on ongoing forecasts for mild winter weather, record gas production, and ample amounts of gas in storage, and then gave up early gains to fall another 20.2 cents, or 4.7% to ​$​4.056​ ​per mmBTU on Thurday, after the latest government storage data failed to generate any buzz in the market...natural gas prices finally managed to gain 7.6 cents or nearly 2% on Friday, on forecasts for slighly cooler weather, rising LNG exports and a small decline in output to finish the week at $4.132 per mmBTU, still down 24% from the prior week and the biggest weekly decline since February 2014...

​you'll note that i cited Reuters for that "biggest weekly decline since February 2014"; curious to see what happened back then, i brought up an interactive natural gas price graph, set it to show weekly prices changes, and scrolled back over recent natural gas​ ​price history​ to see what might have happened at that time....as it turned out, there was no weekly price decline of this week's magnitude shown during February 2014​; the worst down ​week that month was the week of February 24, when natural gas prices opened at $5.089 and closed at $4.609, and the week over week change was minus 40.3 cents...earlier that month, during the week ending February 3rd, 2014, there was more volatility, with a 99.8 cent difference between the high and low price, but at the end of the week prices were only down 16.8 cents...so whatever Reuters was looking at there, i didn't see it...in fact, i think this week's drop was the greatest on record, but that's a conclusion i've arrived at by manually searching for big price changes, which could be prone to error...

i'll include a natural price graph price graph here and describe the method i've used, in case anyone else wants to give it a shot...:

The above graph is a screenshot of the ​current ​interactive natural gas price chart from barchart.com, which i have set to show front month natural gas prices ​weekly over the past 20 years, which means you're seeing the range of natural gas prices over that time as they were quoted daily by the media...​again, ​this same chart can be reset to show prices of front month or individual monthly natural gas contracts over time periods ranging from 1 day to 30 years, as the menu bar on the top indicates, and also to show natural gas prices by the minute, hour, day, week or month for each...each bar in the graph above represents the range of natural gas prices for a single week, with weeks when prices rose indicated in green, and weeks when prices fell indicated in red, with the small barely visible sticks above or below each​ weekly bar representing the extent of the price change above or below the opening and closing price for the week​ ​in question....likewise, the bars across the bottom show trading volume for the weeks in question, again with up weeks indicated by green bars and down weeks indicated in red...

​you can see that on the 5 year graph above​, this week's $1.345, or 24% drop in natural gas prices shows up as a large red bar, clearly the largest red bar on the graph, hence telling us that this week's price drop was the largest over the 5 year span of the graph...the only other weekly red bar that's close is that of December 10, 2018, when natural gas prices opened at $4.590 and closed at $3.827, prices one can get directly from this interactive graph by hovering one's cursor over the date in question...thus it's just a simple matter of scrolling back through the prior years on the graph looking for a red bar the size of this week's and checking the data....so i went back past 10 years and found nothing close to a 24% drop; moreover, i didnt see a weekly drop in natural gas prices of any magnitude ultil after the 2008 price spike...while there were a couple occasions that year when nominal prices fell a bit more than this week's $1.345, that was when natural gas prices were over $10, so the percentage drop back then was much less than this week, not any more than 16%...

The EIA's natural gas storage report for the week ending November 26th indicated that the amount of working natural gas held in underground storage in the US fell by 59 billion cubic feet to 3,564 billion cubic feet by the end of the week, which left our gas supplies 375 billion cubic feet, or 9.5% below the 3,939 billion cubic feet that were in storage on November 26th of last year, and 86 billion cubic feet, or 2.4% below the five-year average of 3,650 billion cubic feet of natural gas that have been in storage as of the 26th of November over the most recent years...the 59 billion cubic foot withdrawal from US natural gas working storage this week was in line with the average forecast for a 58 billion cubic foot withdrawal from Reuters, Bloomberg and Natural Gas Intelligence's surveys of analysts, but it dwarfed the 4 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2020, and ​was ​almost double the average withdrawal of 31 billion cubic feet of natural gas that have typically been pulled out natural gas storage during the same week over the past 5 years… 

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending November 26th showed that after a switch of “unaccounted for crude oil” from the supply side to the demand side, we needed to pull oil out of our stored commercial crude supplies for the third time in ten weeks and for the twenty-third time in the past thirty-five weeks….our imports of crude oil rose by an average of 168,000 barrels per day to an average of 6,604,000 barrels per day, after rising by an average of 245,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 99,000 barrels per day to an average of 2,704,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,900,000 barrels of per day during the week ending November 26th, 69,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly 100,000 barrels per day higher at 11,600,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 15,500,000 barrels per day during the cited reporting week…

Meanwhile, US oil refineries reported they were processing an average of 15,631,000 barrels of crude per day during the week ending November 26th, an average of 9,000 fewer barrels per day than the amount of oil they processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 408,000 barrels of oil per day were being pulled out the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 277,000 barrels per day more than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plunked a (-277,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed...and since last week’s EIA fudge factor was at (+220,000) barrels per day, that means there was a 497,000 barrel per day difference in the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are fairly useless...however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably 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)….

This week's 408,000 barrel per day net decrease in our crude oil inventories came as 130,000 barrels per day were pulled out of our commercially available stocks of crude oil, while 278,000 barrels per day of oil were pulled out of our Strategic Petroleum Reserve, possibly still part of an emergency loan of oil to Exxon in the wake of hurricane Ida...including the drawdowns from the Strategic Petroleum Reserve under such emergency programs, a total of 51,920,000 barrels per day have been removed from the Strategic Petroleum Reserve for a series of other "emergencies" over the past 16 months, and as a result the amount of oil in our Strategic Petroleum Reserve has fallen to an 18 1/2 year low of 602,556,000 barrels per day, as repeated tapping of our emergency supplies for political expediency or to “pay for” other programs have already drained those supplies over the past dozen years...with the BIden administration's announcement last week that another 50 million barrels of oil will be released to incentivize continued use of American gas guzzlers, we have initiated weekly coverage of the SPR storage status on this blog...

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,335,000 barrels per day last week, which was 18.5% more than the 5,345,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,600,000 barrels per day even though the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,100,000 barrels per day, because a 5,000 barrel per day increase in Alaska’s oil production to 454,000 barrels per day added 100,000 barrels per day to the reported rounded national production total (EIA mat​h​)​..​.US crude oil production had hit a pre-pandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was still 11.5% below that of our pre-pandemic production peak, but 37.6% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016...

US oil refineries were operating at 88.​8% of their capacity while using those 15,631,000 barrels of crude per day during the week ending November 26th, up from 88.6% of capacity the prior week, but still a bit below normal utilization for late-autumn refinery operations…the 15,631,000 barrels per day of oil that were refined this week were 11.6% more barrels than the 14,012,000 barrels of crude that were being processed daily during the pandemic impacted week ending November 27th of last year, but 6.9% less than the 16,798,000 barrels of crude that were being processed daily during the week ending November 29th, 2019, when US refineries were operating at what was then a close to normal 91.9% of capacity...

Even with the amount of oil being refined little changed this week, the gasoline output from our refineries was quite a bit lower, decreasing by 450,000 barrels per day to 9,649,000 barrels per day during the week ending November 26th, after our gasoline output had increased by 177,000 barrels per day over the prior week.…this week’s gasoline production was still 12.4% more than the 8,584,000 barrels of gasoline that were being produced daily over the same week of last year, but 2.9% less than the gasoline production of 9,941,000 barrels per day during the week ending November 29th, 2019….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 88,000 barrels per day to 4,872,000 barrels per day, after our distillates output had decreased by 58,000 barrels per day over the prior week…with that increase, our distillates output was 6.2% more than the 4,587,000 barrels of distillates that were being produced daily during the week ending November 27th, 2020, but 7.4% less than the 5,263,000 barrels of distillates that were being produced daily during the week ending November 29th, 2019..

Even with the big d​rop in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the first time in eight weeks, and for the thirteenth time in thirty-two weeks, rising by 4,029,000 to 215,422,000 barrels during the week ending November 26th, after our gasoline inventories had decreased by 603,000 barrels to a 48 month low over the prior week...our gasoline supplies increased this week because the amount of gasoline supplied to US users decreased by 538,000 barrels per day to ​a 22 week low of ​8,796,000 barrels per day, and because our imports of gasoline rose by 160,000 barrels per day to 643,000 barrels per day, while our exports of gasoline rose by 279,000 barrels per day to 887,000 barrels per day…even after this week’s big inventory increase, our gasoline supplies were 7.8% lower than last November 27th's gasoline inventories of 233,638,000 barrels, and about 5% below the five year average of our gasoline supplies for this time of the year…

With the increase in our distillates production, our supplies of distillate fuels increased for the third time in fourteen weeks and for the 11th time in 34 weeks, rising by 2,160,000 barrels to 123,877,000 barrels during the week ending November 26th, after our distillates supplies had decreased by 1,968,000 barrels to a 23 month low during the prior week….our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 182,000 barrels per day to 4,209,000 barrels per day, and because our exports of distillates fell by 419,000 barrels per day to 588,000 barrels per day​,​ while our imports of distillates fell by 98,000 barrels per day to 234,000 barrels per day....but after twenty-three inventory decreases over the past thirty-four weeks, our distillate supplies at the end of the week were 15.1% below the 145,870,000 barrels of distillates that we had in storage on November 27th, 2020, and about 9% below the five year average of distillates stocks for this time of the year…

Meanwhile, in addtion to this week's withdrawal of oil from our Strategic Petroleum Reserve, our commercial supplies of crude oil in storage also fell for the 17th time in the past twenty-seven-weeks and for the 33rd time in the past year, decreasing by 909,000 barrels over the week, from 434,020,000 barrels on November 19th to 433,111,000 barrels on November 26th, after our commercial crude supplies had increased by 1,017,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories slipped to around 6% below the most recent five-year average of crude oil supplies for this time of year, but were still 24.9% above the average of our crude oil stocks as of the last weekend of November over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring and remained elevated for most of the year after that, our commercial crude oil supplies as of this November 26th were 11.3% less than the 488,042,000 barrels of oil we had in commercial storage on November 27th of 2020, and are now 3.1% less than the 447,096,000 barrels of oil that we had in storage on November 29th of 2019, and 2.3% less than the 443,162,000 barrels of oil we had in commercial storage on November 30th of 2018…

Finally, with our inventory of crude oil and our supplies of all products made from oil all at or near multi year lows, we are continuing to track the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that total oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, rose by 2,319,000 barrels this week, from 1,822,392,000 barrels on November 19th to 1,824,711,000 barrels on November 26th, which is still the 2nd lowest level of total US inventories since January 23rd, 2015, just up fractionally from last week's a 82 month low...

This Week's Rig Count

The number of drilling rigs active in the US were unchanged in this week's report, which covers the nine days ending Friday, December 3rd, because last week's report was released 2 days early due to the Thanksgiving holiday....Baker Hughes reported that the total count of rotary rigs running in the US increased was unchanged at 569 rigs over that period, which was also 246 more rigs than the pandemic hit 323 rigs that were in use as of the December 4th report of 2020, but was also still 1,360 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….

The number of rigs drilling for oil was unchanged at 467 oil rigs during this period, after they had increased by 6 oil rigs the prior week, but there are now 221 more oil rigs active now than were running a year ago, even as they still amount to just 29.0% of the high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was ​also ​unchanged at 102 natural gas rigs, which was still up by 27 natural gas rigs from the 75 natural gas rigs that were drilling during the same week a year ago, but still only 6.4% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….in addition, last year's rig count also included 3 rigs that Baker Hughes had classified as "miscellaneous', while there are no such "miscellaneous' rigs deployed this week...

The Gulf of Mexico rig count was down by 2 rigs to 13 rigs this week, with ​eleven of this week's Gulf rigs drilling for oil in Louisiana waters and two more drilling for oil in Alaminos Canyon, offshore from Texas...that equals the count of 13 rigs in the Gulf a year ago, when 1​2 Gulf rigs were drilling for oil offshore from Louisiana and one was deployed for oil in Texas waters…since there is now no drilling off our other coasts, nor was there a year ago, the Gulf rig count is equal to the national offshore totals..

In addition to those rigs offshore, we continue to have two water based rigs drilling inland; one is a directional rig targeting oil at a depth of over 15,000 feet, drilling from an inland body of water in Plaquemines Parish, Louisiana, near the mouth of the Mississippi, and the other is drilling for oil in the Galveston Bay area, and hence the inland waters rig count of two is up from one from a year ago..

The count of active horizontal drilling rigs was unchanged at 513 horizontal rigs this week, which was still 77.5% more than the 289 horizontal rigs that were in use in the US on December 4th of last year, but was 62.7% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014...however, the directional rig count was down by three to 31 directional rigs this week, but those were still up by 13 from the 18 directional rigs that were operating during the same week a year ago….on the other hand, the vertical rig count was up by 3 to 25 vertical rigs this week, and those were up by 9 from the 16 vertical rigs that were in use on December 4th of 2020….

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of December 3rd, the second column shows the change in the number of working rigs between last week’s count (November 24th) and this week’s (December 3rd) count, the third column shows last week’s November 24th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 4th of December, 2020...

this week saw a five rig increase in New Mexico, which was offset by rig decreases elsewhere...to determine what happened in New Mexico, we first check the Rigs by State file at Baker Hughes for changes in the Texas Permian basin...there we find that one rig was pulled out of Texas Oil District 8, which is the core Permian Delaware, and that another rig was pulled out of Texas Oil District 8A, which covers the northernmost Permian Midland, thus indicating an overall two rig decrease in the Texas Permian...since the national Permian rig count was up by 3, that means that all five rigs that were added in New Mexico had to have been set up in the westernmost reaches of the Permian Delaware, to account for the national Permian basin increase... elsewhere, the two rigs removed from Louisiana had been drilling in the state's offshore waters; counts in all other regions of Louisiana were unchanged...the rig that was pulled out of California came from a basin that Baker Hughes doesn't track, while the rig that was removed from Oklahoma's Cana Woodford had to have been offset by a rig addition elsewhere in the state, also in a basin that Baker Hughes doesn't track, for the state's rig count to remain unchanged..

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Ohio energy industry remains cautious despite high prices, rising demand - -- The future is currently looking bright for the energy industry in eastern Ohio as the price for gasoline and natural gas remains high around the country. "For gasoline, the price at the pump is the highest it has been since 2014, on average," said Mike Chadsey, director of public relations for the Ohio Oil and Gas Association. "We also know that natural gas prices are up, we also know that crude oil prices are up, and really one of the most fundamental reasons why is that energy demand is rising as we come out of the COVID lock-down of last year. "Demand is rising but the energy supply is not rising at the same rate. So that's kind of the squeeze right there." That has had a dramatic impact on the oil and gas industry in Ohio, but companies remain cautious. "We are seeing producers being very responsible with capital," Chadsey said. "It isn't the free-for-all that it was a couple of years ago in terms of drilling. "They're being mindful of that. We also don't know what tomorrow brings from the Biden administration in terms of methane taxes, climate change policy, so it's a little bit of wait and see. It's also fiscal responsibility, drilling within your means." The industry remains strong in the Buckeye State. There are around 10 to 12 drilling rigs operating in Ohio. For much of this year, there had only been three or four rigs, he said. Currently, there are 3,145 Utica Shale play wells in production in Ohio. And, according to JobsOhio, there are about 208,000 Ohioans employed in the oil and gas industry, more than the rest of the country combined. One of the biggest players in eastern Ohio is Ascent Resources, the largest producer of natural gas in Ohio. The Oklahoma City-based company has its local headquarters in Cambridge. It operates primarily in Belmont, Jefferson, Guernsey, Harrison and Noble counties. Chadsey said Ascent and other companies are focusing on Jefferson County because it's in the natural gas window. Prices are up, the infrastructure is in place and there's a big demand for natural gas as the country enters the winter heating season. The industry is also very active in Harrison and Carroll counties. Another player in the region is Encino Energy, a Houston, Texas, company with local offices in Stark County. “We have added another rig this year, but it’s important to note that we’ve had two rigs consistently running since our acquisition in 2018," said Jackie Stewart, director of external affairs for the company.

Turkish mining group picks region for new plant - When CS Global Group was looking around the United States to locate a plant, the Turkish manufacturer and distributor knew it wanted river and rail access. While it looked in other states, CS Global found what it was looking for along the Ohio River in Moundsville, West Virginia. Its product is barium sulfate, which is an ingredient in the fluids that are used to drill oil and natural gas wells. It’s also used in paint, fireworks, brake linings and X-ray imaging. Through one of its other subsidiaries, CS Global distributes barium sulfate and the CS Mining subsidiary creates the barite. The new plant in Moundsville will produce barium sulfate to be shipped to oil and gas drilling sites, particularly in Canada. CS Global announced in September it would invest nearly $10 million in the expansion, which will eventually employ 47 people and be open sometime in the first half of 2022.

13 New Shale Well Permits Issued for PA-OH-WV Nov 22-28 | Marcellus Drilling News - It seems as if Pennsylvania has been on a yo-yo lately. Three weeks ago PA issued just two permits to drill new shale wells. Two weeks ago PA issued 15 permits! And now, for last week (Nov. 22-28), PA flipped back to just two new permits again. What’s going on? Did the DEP take most of last week off for the Thanksgiving holiday? Perhaps. Ohio pulled our region’s bacon out of the fire by issuing 11 new permits last week for Utica shale wells. West Virginia drillers got skunked with zero new permits last week. All totaled there were just 13 new permits issued last week in the M-U, down from 32 the week before. (3 embedded tables)

State report shows strong natural gas production growth in 2021 - After a bruising year in 2020, natural gas production and prices in Pennsylvania are on the rise this year. The state’s Independent Fiscal Office’s latest Natural Gas Production report shows Pennsylvania drillers are producing more natural gas while slowing the rate at which they drill new wells. Using data from the Department of Environmental Protection, the IFO’s report shows the production rate grew by 6.8 percent from July to September, compared to the same period last year. The growth rate for new wells was flat. An uptick in production in Washington, Bradford, Lycoming and Wyoming counties made up more than 100 percent of the statewide increase. Through August of this year, the commonwealth had the strongest year-over-year growth of any top-five gas-producing state at 7.7 percent. Pennsylvania made up 18.7 percent of nationwide production through August. If that holds, it would be the state’s highest share on record. Related Content The number one producer, Texas, saw a 2.5 percent decrease in production this year. The IFO said Pennsylvania’s average gas prices have risen to their highest levels in several years to reach $3.54 per metric million British thermal units. That’s up 187 percent from the same time last year. The IFO said it’s due to the combination of weaker-than-usual supply growth and demand rebounding from closures related to the COVID-19 pandemic.

Pennsylvania Natural Gas Production Continues Growing at Pre-Pandemic Levels - Pennsylvania’s unconventional natural gas production grew at pre-pandemic rates through the first nine months of the year as prices and demand rebounded, according to the state’s Independent Fiscal Office (IFO). The IFO said unconventional production came in at 1.884 Tcf in 3Q2021, or 6.8% higher than the year-ago period, resembling the strong rates of the first and second quarters. Appalachian producers made price-related curtailments throughout 2020 as they grappled with low demand in the United States and across the world that helped to force production down across the country. As Covid-19 restrictions have eased and lower supplies have squeezed the market, producers in Pennsylvania have slowly brought back volumes throughout the year. Through August, data from the U.S. Energy Information Administration (EIA) cited by the IFO shows that Pennsylvania had the strongest year/year production growth rate of any of the nation’s top producing states at 7.7%.While the market has improved, oil and gas producers continue to exercise capital discipline that has curbed natural gas output in places like Texas and Oklahoma, according to EIA data cited by IFO. Meanwhile, volumes in other top-producing states grew at rates closer to 2% through the first eight months of the year, the IFO said. The IFO said Henry Hub prices averaged $4.28/MMBtu in 3Q2021, up 120% from the year-ago period, when Pennsylvania’s unconventional production grew at the lowest annual growth rate on record. The IFO also said spot prices in Pennsylvania jumped 187% year/year in the third quarter to average $3.54/MMBtu. Prices are forecast to stay high through the winter and into early next year as storage levels aren’t as strong as they have been in years past and global demand for liquefied natural gas remains strong amid a supply shortage.The IFO noted that there were 10,665 producing horizontal wells in the state during the third quarter, up 5.4% from the year-ago period. Horizontal wells account for about 99% of the state’s unconventional production, while vertical wells drilled to unconventional formations make up a marginal share.Growth in producing wells in the state has largely dropped over the last 16 quarters and hit its lowest rate earlier this year. Decelerating growth in producing wells, IFO said, is due to less drilling activity and older wells being shut-in or plugged.

Natural gas industry seeking students - Lackawanna College School of Petroleum and Natural Gas is one of only three of its kind in the whole country, and it is looking for new students. Later this week, Northern Tier Industry & Education Consortium, a non-profit that works to bridge the gap for students between school and the workforce, is hosting an open house at the college’s brand new facility in Tunkhannock. “The jobs are here. They’re not going anywhere, and you don’t need a 4-year degree to be able to work in the gas industry,” said Debbie Tierney, NTIEC. And that is why the program needed to expand. Lackawanna College School of Petroleum and Natural Gas just opened its new facility in August. The program can now accept 60 students. That is twice as many as before. The school has a nearly 100% job placement rate. “This program in 2 years, it’s a life-changer. It makes dreams come true. I’ve seen all of the students come through this program, and it’s just very rewarding, and I just want to get the word out,” said Sue Gumble, Program Director for Lackawanna College School of Petroleum and Natural Gas. High school students from any district in the area are invited to attend the Open House on Wednesday evening. Students can sit in on classes and talk to teachers. “They’ll also be able to talk to current students and past students. So they’re not going to hear it just from us of what a great program this is. They’re actually going to be able to talk to the people who came here, have graduated from here, and who are working locally in the industry,” Tierney said.

Marcellus shale natural gas driller proposes compressor station in Upper Burrell - Olympus Energy is seeking state approval to develop a Marcellus shale natural gas compressor station in Upper Burrell, off White Cloud Road on undeveloped industrial property owned by Arconic. Olympus Energy of Canonsburg has three well pads to tap natural gas in the Marcellus shale rock formation approved by the township and state Department of Environmental Protection in various stages of development. The compressor station, known as the Rogers compressor, is proposed near the Calliope well pad site, also off White Cloud Road. The proposed station is strategically located to maintain the pressure and flow of the natural gas to take it to the market, said Kimberly Price, Olympus spokeswoman. The company has applications pending with the DEP, including one for an air permit, she said. Next steps would include submitting plans to township officials. “Throughout this process, Olympus will also be working to address the questions and concerns of nearby residents,” she said. The planning commission will review the proposal and make recommendations to township supervisors, who will have final say on approval, township Solicitor Steve Yakopec said. Residents such as Dan Myers want to learn more. “How much noise will the compressor station make? This is a noise that won’t be going away,” Myers said. He also wants to know more about the facility’s emissions.

Danskammer power plant appeals DEC’s denial of permit - Danskammer Energy on Wednesday announced it is appealing the denial of its air permit to build and operate a new natural gas-fired power plant and generation facility near Newburgh, calling the decision “unjustified.” The New York State Department of Environmental Conservation (DEC) on Oct. 27 struck down the proposed Danskammer project in mid-Hudson Valley, saying the project did not comply with the state’s new climate law. The decision marked a precedent-setting moment in the implementation of the state’s Climate Leadership and Community Protection Act (CLCPA), which passed in 2019 and calls for sharp reductions in the use of fossil fuels, such as the natural gas that would power the Danskammer facility.The DEC also denied a permit for Astoria Gas Turbine Power in Queens. The two proposed plants would “interfere with the statewide greenhouse gas emissions limits established in the Climate Act,” said DEC Commissioner Basil Seggos in a statement on Oct. 27.“We believe DEC is holding Danskammer to standards that don’t even exist because the Climate Action Council has yet to issue guidance on what it means to be consistent with the State’s new climate law,” said Bill Reid, CEO of Danskammer Energy LLC, in a press release.The energy company had been seeking authorization to construct a new power generation facility near the Town of Newburgh in Orange County and submitted its application to the DEC in December 2019.

New York Utilities Polarize Over Push to Ban Natural Gas - A top provider of natural gas to New York City is quietly supporting a fight to ban gas hookups in new buildings. Con Edison sells both gas and electricity in New York, where it is counting on higher electric demand in winter months as it backs activists’ efforts to eliminate fossil fuels in new housing and commercial developments. The investor-owned utility has lobbied the City Council to pass Bill 2317, which would prohibit developers from piping oil or gas into new construction projects or major renovations as soon as this year.“They’re putting down some specific industry lies,” said Pete Sikora, a climate campaigner who has led activist efforts to decarbonize buildings. “It’s very, very useful.”The stance pits ConEd against national lobbyists for the oil industry, and against local real estate interests fighting to slow the phaseout of gas.“It’s becoming a common pattern,” said Leah Stokes, an environmental policy professor at University of California, Santa Barbara who testified at a recent hearing on the ban. “Combined gas and electric utilities have been realizing that electrification is an opportunity.”Not all energy companies are convinced. All-gas utilities are resisting efforts to phase out the fuel, and in some states are trying to head them off.The city’s other main gas provider, National Grid, has opposed the ban, though in what activists say is a break with more aggressive past tactics, its criticism has been comparatively muted.

North American Pipeline Project Roundup: November/December 2021 - Project Roundup is a monthly feature that summarizes the contracts awarded for pipeline projects in North America. The following oil and gas pipeline contracts have been announced. Projects are in order of most recent approximate starting date. All listings are for 2021 unless noted. (excerpts from list of ~ 2 dozen)

• InterCon Construction Inc. was awarded a contract by Apex Pipeline Services Inc. to install approximately 1,100 ft of 24-in. pipeline via horizontal directional drilling in Tyler County, West Virginia.
• InterCon Construction Inc. was awarded a contract by C.J. Hughes Construction/Mountaineer Gas to install approximately 500 ft of 12-in. pipeline in Berkely County, West Virginia.
• Minnesota Limited LLC was awarded a contract by Dakota Carrier Network to install approximately 2,500 ft of 8-in. pipeline in Cass County, North Dakota. .
• U.S. Pipeline Inc. was awarded a contract by Williams – Transcontinental Gas Co. for various anomaly investigations in York County, Pennsylvania. Headquarters
• Dun Transportation & Stringing Inc. was awarded a contract by H&S Constructors Inc. for a project to load, haul, and string approximately 8 miles of 16-in. pipe in Eddy County, New Mexico.
• Apex Pipeline Services was awarded a contract by TC Energy for the abandonment of approximately 500 ft of pipeline and building demolition in Jackson County, Ohio.
• InfraSource Construction Inc. was awarded a contract by Washington Gas & Light for the abandonment of approximately 1,600 ft of various size pipelines from 4 to 26 in. and a regulator station, install 70 ft of 30-in. and 30 ft of 24-in. pipeline, three 24-in. pipeline stoppers 10 2-in. drill nipples and three gauge line risers replacements in Montgomery and Prince Georges counties, Maryland, and Washington, D.C.
• Minnesota Limited LLC was awarded a project contract by CenterPoint Energy for a 10- and 6-in. launcher barrel installation in Piqua County, Ohio. Headquarters is Piqua, Ohio. .

River partners remove 19th century oil pipeline from Musconetcong River -Remnants of nine old oil pipelines have been removed from the Wild and Scenic Musconetcong River. The completion was announced on Thursday, Nov. 18, according to a joint statement from The National Park Service (NPS), the Chevron Environmental Management Company (Chevron), the Musconetcong River Management Council (MRMC), and theMusconetcong Watershed Association (MWA).Investigating complaints of pipelines protruding from the river bottom, the MWA and the NPS found that in low flows, the pipelines could come into contact with the bottoms of canoes and kayaks. Working with Chevron, it was determined the pipelines were no longer in use and had been filled with cement and capped. The pipelines, some dating back to the 1880s, are believed to be some of the oldest petroleum pipelines in the United States. While the pipelines posed no pollution threat to the river, they remained a navigational impediment for paddlers.“The National Park Service Wild and Scenic Rivers program seeks to protect and enhance river resources across the nation,” said NPS River Manager Paul Kenney. “We appreciate the work of our river partners to help improve the recreational and ecological quality of the Wild and Scenic Musconetcong River and are excited for the paddling community to enjoy this exceptional river without these obstacles.”

If the gasholder building comes down, unknown pollution might rise up - Fans of Concord’s gasholder builder want to save the historic structure because of how it looks above the ground, but there’s an underground reason to keep it intact, as well. In one talk James Wieck of GZA GeoEnvironmental discussed ongoing efforts to preserve the 1888 gasholder, including monitoring subsurface pollution that was left behind by a century of processing coal to create a flammable gas, which was used for building heat in Concord before natural gas pipelines arrived in 1952. The round brick building that held this gas has been empty for years and is in danger of falling apart. The main pollution problem goes by the inelegant acronym DNAPL. This stands for dense nonaqueous phase liquids, in this case tar-like byproducts of coal processing that seeped into the ground during decades of storage and handling, threatening groundwater. Most of the toxins were dug up and removed from the 2.4-acre site decades ago. But material had already oozed underground beyond the property boundaries, mostly to the east and south toward the Merrimack River, although it does not appear to be spreading any longer. A series of monitoring wells have been dug to keep track of the spread and two wells are removing material that is found, he said. “It’s under 10 gallons over the course of a year – not much.” The monitoring will continue until the New Hampshire groundwater quality standards are met, and tar will be recovered as long as it is present in the wells where it is being recovered. As for the gasholder building itself, however, there’s more uncertainty. The building held manufactured coal gas under a floating cap that is 88 feet in diameter and weighs many tons. The gas was pumped in from the manufacturing building and held there, trapped between the cap and water, until it was used by downtown buildings for heat. The cap rose and sank depending on how much gas was stored at the time. Its weight provided pressure that sent the gas through pipelines to customers. The gasholder’s historic importance comes from the fact that the cap and associated machinery is still intact. Many other gasholder buildings exist around the country, including a small one at St. Paul’s School, but this appears unique in still having all its machinery.

Air pollution impacts of Mountain Valley Pipeline extension compressor station to be considered at public meetings -- Lambert Compressor Station would worsen air quality issues in communities of colorThe Virginia Air Pollution Control Board will meet December 2 and 3 in Chatham, VA to consider an air quality permit for a proposed compressor station needed to extend the controversial Mountain Valley Pipeline into North Carolina. The Board will hear limited public comment on Thursday afternoon and Friday morning.If built, the Lambert Compressor Station in Pittsylvania County, Virginia would pump fracked gas into the Southgate extension of the Mountain Valley Pipeline, which has drawn growing grassroots opposition from environmental justice advocates, like the NAACP. Environmental reviews found building the compressor station would mean higher levels of carbon monoxide, sulfur dioxide, particulate matter, formaldehyde and other volatile organic compounds. These substances are known to contribute to asthma and other respiratory problems, heart disease, cancer, and other health problems for community members living near them. Mountain Valley Pipeline took a narrow view of the impacts of this pollution and failed to account for impacts to people of color and/or low income families living near the proposed station.Environmental concerns have already led the North Carolina Department of Environmental Quality to twice deny a water permit for the proposed 74-mile Southgate project. The Southgate project is still without this crucial permit, which is necessary for any construction to begin. The MVP mainline is billions of dollars over budget, three years behind schedule, and has racked up more than $2 million in fines for water quality-related violations in Virginia and West Virginia.

Chatham residents and others to speak against Lambert Compressor Station at air board hearing – Appalachian Voices -Beginning on Dec. 2 at 1 p.m., the State Air Pollution Control Board will consider an air quality permit for the Lambert Compressor Station proposed for Pittsylvania County at a thrice-delayed public hearing in Chatham, Virginia. The hearing will continue on Dec. 3 at 9:30 a.m.The Lambert Compressor Station would be the only compressor station for MVP Southgate, a proposed 73-mile extension of the unfinished 303-mile fracked-gas Mountain Valley Pipeline. It would be the third compressor station located on Transco Road.Compressor stations, which help maintain pressure and flow of the natural gas in pipelines, can be significant sources of pollution, emitting carbon monoxide, nitrogen oxides, fine particulate matter, sulfur dioxides and volatile organic compounds, among other harmful substances.“Why us? Why in our backyard? Why in the Banister District in Chatham in Pittsylvania County?” asked Elizabeth Jones, who chairs the environmental justice committee of the Pittsylvania County Branch of the NAACP, during an online meeting in August. “It’s because there is very little resistance. … This is an environmental justice issue.”Jones noted that Banister District is predominantly African-American. She lives on a farm near the site of the proposed compressor station with her husband Anderson, who spoke during the meeting about the farm that’s been in his family for 98 years. “The Jones family farm is one of the beautiful areas in Chatham,” he said. “We used to have cows, hogs, chickens. We had fruit trees. We had a wonderful farm and the land was very fertile. The pipelines have come in and destroyed the beautiful landscape. You just need to look at what they have done to it.” Only people who submitted public comments during the original comment period earlier this year will be allowed to speak at the public hearing. “Our members and others from Southern Virginia are facing a 300-mile, 6-hour round trip, and a 1- or 2-night stay in order to attend the meeting,” wrote President Anita Royston in a letter to DEQ. “Given the current set-up, we can only speak — and listen — if we make the trip.”

Bill blocking NC governments from banning natgas heads to governor’s desk - North Carolina came closer Monday to joining 20 other states around the country in passing legislation that will prevent local governments from banning the use of energy sources, like natural gas, in new construction or renovations. House Bill 220 would formally prevent local governments in North Carolina from banning natural gas in new or renovated buildings. No local governments in North Carolina have moved to ban the use of natural gas in construction, and environmental groups called for Gov. Roy Cooper to veto the legislation moments after the House voted to concur. The bill also includes a provision exempting design or vulnerability information about infrastructure, such as electric facilities, water treatment and water outfalls, from public record. Monday, Sen. Paul Newton told the Senate Rules Committee that HB 220 is in response to legislation passed by some local governments in California and other parts of the country that banned natural gas or propane as part of an effort to electrify homes and buildings. “The primary purpose of this bill is to reaffirm that we make energy policy at the state level. Local government units do not,” Newton, a Cabarrus County Republican, said Monday during the Senate Rules Committee. The N.C. Senate voted 29 to 17 in favor of a revised version of HB 220 on Monday, followed by the House voting 56 to 47 to concur. Next, it will head to Cooper’s desk.

Georgia environmental regulators propose $3 million fine for Golden Ray pollution - The state’s Environmental Protection Division is proposing a $3 million fine against a South Korean logistics company for polluting the sea and salt marshes on the Georgia coast after the Golden Ray car carrier capsized in St. Simons Sound on Sept. 8, 2019.State environmental regulators are accepting public comments until Dec. 23 on their proposed consent order to penalize Hyundai Glovis Co. for discharging pollutants and debris without a permit in one of the largest maritime disasters in American history.The $3 million fine would be a relatively small price compared to the cost of the snakebit shipwreck cleanup project, where estimates of the tab that will be footed by the company and insurer are in the $1 billion range. Environmentalists said Monday that the punishment from the fine is not nearly as significant as holding the company accountable for damages.The approval order also says that the company will have to follow an approved Environmental Assessment and Response Plan after the Coast Guard-led incident response finishes the shipwreck response and overseeing pollution control. If Hyundai submits a plan that wins EDP approval for another environmental project, its fine could be reduced.Susan Inman, of the Brunswick-based environmental group One Hundred Miles, said the ship’s oil leaks can have some lasting effects on estuaries and waterways in the area.Although the Golden Ray has been removed from the water, there is still oil that seeps to the surface as debris is removed from the water, Inman said.

Georgia Proposed $3 Million Pollution Fine for Golden Ray’s Operators - A month after the removal of the last section of the Golden Ray wreck and with debris removal efforts expected to wind down in St. Simmons Sound, Georgia environmental officials have moved to implement a fine for the environmental damage caused by the Ro-Ro that rolled over after departing the port of Brunswick, Georgia. The state’s environmental authority posted notice of the proposed enforcement action published on November 23 with a one-month comment period. The action proposes a $3 million settlement to be paid by Hyundai Glovis, operators of the Golden Ray at the time of the accident. Georgia’s Environmental Protection Division alleges that pollutants, debris, and petroleum products were discharged from the Golden Ray into waters beginning on September 8, 2019, through the effective date of this consent order. “Upon the termination of the Unified Command incident response, the respondent shall implement the approved Environmental Assessment and Response Plan,” according to the notice. Within one year of the execution of this consent order, Hyundai Glovis must pay a civil penalty or elect to submit a plan for a proposed supplemental environmental project. If they elect to propose further remediation efforts, the company might obtain a reduction in the civil penalty. Following the accident, response teams sought to mitigate oil leaks from the vessel. The Unified Command strung a barrier around the site and developed teams to mitigate further oil leaks from the vessel during the salvage operations. The team reported that they expected additional oil leaks during the removal operations as well as regular monitoring and removing various debris that washed up during the operations. The last significant oil leak happed at the end of July into early August 2021 as the operation went to remove one of the last sections of the vessel. Both during the weight shedding process and then when they began to raise section six fuel oil leaked into the water and was able to escape the protective barrier. Teams worked to contain the spill and clean reside from the shoreline. In early August, the salvage team located and capped a vent pipe which they said was the source of the most significant leak since the salvage operation had begun.

Students, residents protest natural gas plant on University of Florida’s campus - Protesters are opposing a natural gas plant that may be coming to the University of Florida’s campus. “Don’t pass gas,” protesters chanted. Their mission was to bring awareness and get the UF board of trustees to postpone building the plant until lawmakers allow more solar energy at UF. The steam plant would help heat and cool buildings on campus. “But as far as the repercussions of it, obviously natural gas is not a sustainable resource,” organizer Mackenzie Griffin said. “It produces carbon emissions which contribute to global warming which takes away from our future as students here. We have a long future ahead of us and we want to keep it nice and beautiful.” Grace Lear said she believes students were in the dark about the plant. “Just from a student perspective, we would just like more transparency from UF at this point. They kind of hid this from us for a very long time and planned it during the pandemic which as students we all weren’t here so they were kind of suppressing our voices and there’s been all kinds of issues going around.” The board of trustees is set to discuss whether they’ll move forward with the plant this Thursday and Friday.

‘Don’t pass gas’: Students, residents protest natural gas plant on University of Florida’s campus --- Protesters are opposing a natural gas plant that may be coming to the University of Florida’s campus. “Don’t pass gas,” protesters chanted. Their mission was to bring awareness and get the UF board of trustees to postpone building the plant until lawmakers allow more solar energy at UF. The steam plant would help heat and cool buildings on campus. “But as far as the repercussions of it, obviously natural gas is not a sustainable resource,” organizer Mackenzie Griffin said. “It produces carbon emissions which contribute to global warming which takes away from our future as students here. We have a long future ahead of us and we want to keep it nice and beautiful.” Grace Lear said she believes students were in the dark about the plant. “Just from a student perspective, we would just like more transparency from UF at this point. They kind of hid this from us for a very long time and planned it during the pandemic which as students we all weren’t here so they were kind of suppressing our voices and there’s been all kinds of issues going around.” The board of trustees is set to discuss whether they’ll move forward with the plant this Thursday and Friday.

The Spire STL natural gas pipeline and the new challenge to already-built assets. --Determining whether to approve plans for interstate natural gas pipeline projects has never been an easy task for the Federal Energy Regulatory Commission. There are so many things to consider, chief among them the need for the pipeline, impacts on the environment and landowners along the route, and what it all means for gas customers. But as complicated as the decision-making process may be, at least pipeline developers, gas producers, and customers knew that once a new pipeline was approved by FERC, permitted, built, and put into service that the matter was closed — that is, the pipeline was here to stay. Now, in the wake of a groundbreaking court ruling on a new gas pipeline near St. Louis, things are not so certain. As it turns out, we’re intimately familiar with the matter, having just made the case that the 65-mile Spire STL Pipeline is an important addition to the regional pipeline network that provides supply diversity, improved reliability, and access to lower-cost gas. In today’s RBN blog, we consider the evolution of FERC regulation of gas pipelines and the new uncertainty that all affected parties face.

Cost of natural gas to double this winter for Spire customers -Spire customers in Joplin and elsewhere in Southwest Missouri will pay twice as much for natural gas this winter. That doesn’t mean their bill will double, because the cost of the gas is only part of the bill, along with other customer charges, but it is the largest part of the bill — between 50% and 55%, according to regulators — and customers should still expect increases in their monthly bills, said Jason Merrill, spokesman for Spire. The change means an increase of about $24.36 per month, or 41.5%, for the typical natural gas residential customer, defined as someone an average of 60 to 65 ccf per month. A ccf is a hundred cubic feet of natural gas and a unit to measure usage. The Missouri Public Service Commission this week approved the increase, which takes effect Tuesday. “The gas is a straight pass through; it is not something we profit off of. The cost of natural gas has gone up throughout the Midwest and Missouri is no different. ... What we pay for the gas is what a customer pays for the gas,” Merrill said.

Longmeadow Select Board questions Eversource on pipeline project – The Longmeadow Select Board put representatives from Eversource through extensive questioning about the pipeline project that has been proposed to run through Longmeadow. During a three-hour public meeting on Nov. 15, Eversource answered many questions, but the Select Board and residents expressed several concerns that went unaddressed. The meeting began with a presentation from Joseph Mitchell, a human relations specialist at Eversource, on the proposed pipeline project. “It is our goal to do as much outreach as possible to have the community aware of our proposed project We want to receive their feedback,” Mitchell said. He explained that greater Springfield receives its gas from a 70-year-old pipeline that joins with a Tennessee Gas pipeline in Agawam, runs under Memorial Bridge into Springfield and to a point-of-delivery (POD) station on Bliss Street. If anything were to happen to that line, Mitchell said, 40,000 customers east of the Connecticut River, and potentially 18,000 on the west side, would be without gas. Mitchell said gas outages last much longer than electrical outages and it could be between one and two months for complete service restoration. He painted a picture of families without heat in the winter, frozen pipes, water damage to homes and businesses and the disruption of workers needing to enter people’s homes to restore their gas service. “We want to bring a second independent source to supply our customers,” Mitchell told the Select Board and residents watching the meeting. The new line, which he emphasized was for reliability and not new customers, would branch off an existing Tennessee Gas line running west to east in Longmeadow near the Connecticut border and feed a new POD to be built on land at the Longmeadow Country Club. From there, a 16-inch pipeline would run along one of four routes.

Caddo Commissioner Ken Epperson chipping away at oil, natural gas drilling noise issues— Oil and natural gas drilling issues persist in parts of Caddo Parish, despite residents’ complaints. Caddo Commissioner Ken Epperson has been chipping away at the drilling noises for years. In July, we told you how Pine Wave’s drilling well was affecting Twilight Meadows neighbors. Now, Goodrich Petroleum Corp. has opened a well about two miles down the road. “That is our major concern, that they want to drill in our communities,” said Glenn Moore, who lives right in front of the new well. He said they started drilling about two weeks ago. “I didn’t know they were putting a pad so close to us. I knew it was coming somewhere, but I didn’t know how close it was coming.” Since July, several residents have spoken at Caddo Commission meetings during the public comment period. “I’m a retired person. I don’t want to hear all that noise. I don’t want to breathe the dust that comes with it,” Moore said during a meeting held July 22. During a teleconference meeting earlier this year, parish Public Works Director Tim Weaver said the oil and natural gas industry is booming in Caddo. “Oil and gas is the strongest I’ve seen it in Caddo Parish since the Haynesville Shale.” Resident Murdis Dodd described the drilling, saying it was ”like an airplane is landing in my back yard.”

Exclusive: Arbor Gas CEO details Beaumont project --Now that Arbor Renewable Gas officially has announced its intentions to develop the Spindletop Plant in Beaumont, the company is shifting gears to focus on construction. The Beaumont Enterprise sat down with Arbor Gas CEO Tim Vail to discuss the coming $350 million investment, and breakdown why the company sees Southeast Texas as the perfect launching pad for high-level biofuels. Arbor Renewable Gas announced earlier this month that it was moving forward with its plans to build a renewable gasoline plant on a 53-acre industrial park property on Texas 347 at the border of Beaumont and Nederland. The company expects to start construction on its new Spindletop Plant by the first half of 2022, with completion estimated for late 2023. It’s not the first time Vail and most of his crew have worked on a project in Beaumont, as several of the key principals involved with Arbor Renewable Gas have experience with Beaumont’s Natgasoline methanol production facility.Vail said the group was already deeply familiar with the infrastructure assets available at the industrial site that would make an investment like the Spindletop Plant incredibly efficiency and cost-effective, but there also was something more attractive than good real estate.

In shadow of Texas gas drilling sites, health fears escalate — At a playground outside a North Texas day care, giggling preschoolers chase each other into a playhouse. Toddlers scoot by on tricycles. Just uphill, Total Energies is pumping for natural gas. The French energy giant wants to drill three new wells on the property next to Mother’s Heart Learning Center, which serves mainly Black and Latino children. The wells would lie about 600 feet from where the children play. The prospect is raising fears among families and the surrounding community. Living too close to drilling sites has been linked to a range of health risks from asthma to neurological and developmental disorders. And while some states require energy companies to drill farther from day cares and homes, Texas has made it difficult for localities to fight back. On Tuesday night, the Arlington City Council voted 5-4 to approve Total’s latest drilling request, with expected final approval in the weeks to come. Last year, the council denied Total’s request at a time when Black Lives Matter protests after George Floyd’s murder by police led many American communities to take a deeper look at racial disparities. But with some turnover on the City Council, many residents worried Total would succeed this time.“I’m trying to protect my little one,” said Guerda Philemond, whose 2-year-old daughter attends the day care. “There’s a lot of land, empty space they can drill. It doesn’t have to be in the back yard of a day care.” Total declined a request for an interview, but in a statement said it has operated near Mother’s Heart for more than a decade without any safety concerns expressed by the City of Arlington.The clash in Arlington comes as world leaders pledge to burn less fossil fuel and transition to cleaner energy. Yet the world’s reliance on natural gas is growing, not declining. As a result, there will likely be more drilling in Arlington and other communities. And children who spend time near drilling sites or natural gas distribution centers — in neighborhoods that critics call “sacrifice zones” — may face a growing risk of developing neurological or learning problems. Scientific studies have found that the public health risks associated with these sites include cancers, asthma, respiratory diseases, rashes, heart problems and mental health disorders.

More Permian Basin natural gas facilities to be expanded -A natural gas processing company based in Fort Worth, Texas sought to grow its presence in the Permian Basin, purchasing two facilities on either side of the region. Brazos Midstream announced it acquired the facilities from Diamondback Energy in the eastern Delaware sub-basin near the Texas-New Mexico border and in the Midland Basin further east into Texas. Subsidiary Brazos Delaware closed on its acquisition the Pecos Gathering System from Diamondback in Reeves County, Texas, per a Nov. 3 news release, while Brazos Midland announced it acquired the Mustang Springs Gas Gathering System in Martin County, Texas. Brazos already operated the Pecos system for Diamondback since 2017, but the acquisition augmented the company’s existing system by adding 150 miles of natural gas gathering pipelines and four associated compressor stations. The system was planned to be expanded, the release read, to continue meeting growing demand for gas producers in the area The Mustang Springs system was also planned to be expanded, read the release, as producers planned for growth in the basin. Brad Iles, Brazos chief executive officer said the move was intended to capitalize on continued and expected future growth in fossil fuel development in the Permian Basin, which spans southeast New Mexico and West Texas. The purchased infrastructure will augment Brazos’ portfolio of about 800 miles of natural gas and crude oil pipelines, about 460 million cubic feet of gas processing capacity and 75,000 barrels of crude oil storage capacity. “We are excited to announce both acquisitions and the expansion of our relationship with Diamondback, one of the Permian’s premier oil and gas operators,” Iles said. “The Pecos system is a perfect bolt-on acquisition for our existing Delaware Basin business and will allow Brazos to extend our reach to new producer customers.”

Shale Drillers to Lift USA Spending 19 Percent -Expenditures will rise to $83.4 billion in 2022, the highest since the Covid-19 pandemic emerged. U.S. shale oil producers will increase capital spending by nearly a fifth next year as they deploy more rigs and inflation bites, according to Rystad Energy AS. Expenditures will rise to $83.4 billion in 2022, the highest since the Covid-19 pandemic emerged in early 2020, with more than half of the increase due to “service price inflation,” the Oslo-based consultant said in a note Wednesday. That dollar amount still is about a third lower than forecast levels in 2019, indicating that companies are more disciplined about basing production decisions on near-term changes in crude prices. Closely held explorers have expanded drilling aggressively this year to take advantage of higher oil prices while their publicly-listed rivals resisted that urge and diverted cash to shareholders. In 2022, however, both groups will incur “significant” budget increases, the analysts wrote.

Oil industry to lose nearly half its workers -The oil and gas industry worldwide faces a talent gap as workers contemplate moving to renewables or leaving the energy industry altogether, a survey by recruitment firm Brunel and Oilandgasjobsearch.com, cited by Reuters, showed. More than half of workers in oil and gas, 56%, said they would look for employment opportunities in the renewables energy sector, according to the survey. Last year, that percentage was 38.8%, highlighting the shortages the oil industry is facing as it looks to hire again, after letting go in 2020 thousands of workers in oil and gas and related services in the supply chain. The survey also showed that 43% of workers want out of the energy sector within the next five years. As more workers look to move to renewables or to ditch the energy sector altogether, recruiters in the oil and gas business find attracting talent with the right skills increasingly difficult. Labor shortages have already become evident this year in the US shale patch and in the Canadian oil sands as demand recovers and companies put rigs back into operation. Despite the recent uptick in oil industry employment in the United States, short-term and permanent shifts in workers' negative perceptions of the sector have already started to create labor shortages. These shortages threaten to delay and even hinder the recovery of US oil production, analysts say. More and more workers are fed up with the boom-and-bust nature of the oil industry after two major oil price and drilling activity collapses in just five years. They vow they will never again be beholden to the volatile oil markets, and have quit the sector entirely after being let go in 2020.

Don't Expect Oil and Gas to Drill Us Out of Crunch - Consumers are upset and businesses are beset by higher costs, but for all the sound and fury, the pandemic-fueled energy price spike may not signify a rebound for fossil fuel production either in the long or short run. “We’re undoubtedly in the middle of a big transition in the way that we power our country,” “There aren’t any coal plants being built anymore in the United States to generate electricity, and we’re starting to move more and more away from gas as utilities double down on solar and wind.” “The recent higher prices have not led to any new drilling in Arkansas,” or any renewed activities in oil or gas, he said. Fracking in Arkansas set off a decade-long boom, but it all went bust after gas prices plunged from near $13 per million British thermal units in June 2008 to $1.95 in April 2012. Prices had rebounded to $5.50 per million BTU by last week, but Bengal predicted it would take far higher prices to goose production in Arkansas’ Fayetteville Shale. The Economist also doesn’t expect Big Oil to ride to the rescue in the crunch. A few years ago, fossil fuel producers would have responded to the price surges by producing and investing more. “Not this time,” the magazine said. “Climate change has led to unprecedented pressure on oil and gas firms, especially European ones, to shift away from fossil fuels.” That dynamic has played out closer to home, Hooks said. “Utilities are starting to double down on solar and double down on wind, and it’s becoming an issue that transcends partisan politics. We’re seeing a lot of movement toward cleaner energy in red states and blue states, and that’s just a result of good economic decisions to benefit communities.” He noted that Entergy Arkansas had backed off plans to build a natural gas-burning electricity plant in resource plans submitted late last month to the Arkansas Public Service Commission, which regulates utilities. At the Sierra Club, where Hooks worked until this month, he and environmental allies worked hard to have Entergy reconsider. “Entergy envisioned the construction of another large natural gas plant in Arkansas, mentioning it in their 2018 plans and in the draft” of the proposal presented in October, Hooks said. “We really showed a lot of different economic scenarios, provided a lot of forecasting. As a result, they left major gas construction out of their plans for the foreseeable future, and really doubled down on renewables.” Public opinion and corporate governance demanding action against climate change helped set the stage, but the bottom line was, well, the bottom line.

CenterPoint Energy Hinges Future on Gas Expansion Despite Net-Zero Pledge --CenterPoint Energy billed itself as an industry leader when it pledged in September to reach net-zero emissions for its operations by 2035, but the investor-owned utility is planning a $1.7 billion gas pipeline expansion and fighting efforts to curb fossil fuel reliance at the local level.Shortly after unveiling a commitment to achieve net-zero emissions from CenterPoint’s direct operations during its 2021 Analyst Day, the utility’s executives at the same meeting told analyststhey expect to add 800 miles of new gas pipeline annually. The buildout is part of a $40 billion overall spending plan that sets aside at least $16 billion for gas investments over 10 years. View document or read text.In addition to expanding its pipeline network in Houston, Minneapolis, suburban Indianapolis and central Texas, executives said the utility plans to replace at least 900 miles of existing pipeline each year. While CenterPoint also expects to spend more than $23 billion to grow its electricity business, its overall vision remains underpinned by gas — its signature business line and a key driver of emissions and price volatility for customers. “We believe natural gas has an enduring future,” Scott Doyle, CenterPoint’s executive vice president for natural gas, told analysts shortly after other executives outlined the net-zero framework.CenterPoint previously said it expected to add 500,000 gas customers by 2030, bringing its total gas customers to 4.6 million. In their presentation to analysts, utility executives estimated a total number of gas customers closer to 4.7 million and projected that gas would account for roughly 40% of its rate base — or the part of its spending from which it can earn a profit — under its mammoth investment plan.

Natural gas plunges 11% as U.S. weather forecast stifles demand - -Natural gas futures plummeted 11% in the U.S. as forecasts shifted warmer through the middle of next month, allaying concern about tight domestic supplies amid a global shortage of the heating fuel. The expiration of the December contract last week amplified the market’s volatility. Prices closed 7.5% higher on Friday as traders rushed to close out bearish positions before the contract rolled off the board. Contracts for January delivery fell 62.3 cents to settle at $4.854 per million British thermal units in New York on Monday. Since late summer, volatility in gas prices has stayed well above the average for the past decade even after a drop from last month’s peak as traders try to gauge whether winter cold will strain inventories. Late-autumn cold in Europe and Asia has sparked fears that global gas shortages will worsen as nations struggle to refill stockpiles. But so far, there’s little sign of a similar situation developing in the U.S., even as shale producers keep a lid on output and the country’s exports of liquefied natural gas surge to a record. U.S. gas stockpiles are only 1.6% below normal for the time of year. The so-called widowmaker spread between March and April futures, essentially a bet on how tight inventories will be at the end of the northern hemisphere’s winter, shrank to 41.5 cents, the narrowest since June, after widening to $1.909 last month. Much of the U.S. should see milder-than-usual weather this week, with temperatures expected to peak in the 50s Fahrenheit in Minneapolis and Chicago, according to the Weather Channel. The western half of the country should continue to see above-normal temperatures at least through Dec. 13, private forecaster Commodity Weather Group said in a note to clients. “Particularly mild weather from Wednesday to Friday will decimate physical market demand and intensify downward pressure on Henry Hub spot prices,” EBW AnalyticsGroup said in a note to clients.

U.S. natural gas sinks, on track for worst month in three years -U.S. natural gas futures slid Tuesday to the lowest level in nearly three months as warmer-than-expected winter forecasts sent prices tumbling.The contract for January delivery fell as much as 7% to trade at $4.51 per million British thermal units (MMBtu), a price last seen on Sept. 1. The weakness builds on Monday's drop, which saw the contract settle 11.37% lower at $4.85 per MMBtu.Over the last two sessions, futures are down more than 17%."The weather outlook for the core heating demand months of the winter (December, January, February) suggests higher than normal temperatures in the major US demand centers," said David Givens, head of gas and power services for North America at Argus Media."This is purely a weather-driven downturn...[forecasts] currently indicate average to above-average temperatures across the U.S. That in turn has reduced the expected number of heating degree days weighing heavily on Henry Hub prices," added Campbell Faulkner, senior vice president and chief data analyst at OTC Global Holdings.The selling over the last two days comes after natural gas futures spiked 7% on Friday, despite oil falling 13% during the same session. The December contract expired on Friday so some of the activity could have been traders closing out positions. Natural gas is now down about 16% for the month, putting it on track for the worst month since December 2018. The contract is on track for a second month of declines.

January Natural Gas Prices Extend Losing Streak as Demand Fades - Natural gas futures tumbled further on Tuesday as traders looked past robust demand for U.S. exports and fixated on exceptionally light domestic weather demand expectations heading into December. The January Nymex contract dropped 28.7 cents day/day and settled at $4.567/MMBtu. February fell 26.2 cents to $4.506. The January contract, in its debut as the prompt month on Monday, plunged 62.3 cents. NGI’s Spot Gas National Avg. shed 49.0 cents to $4.465. “The likelihood of further declines later this week” for futures “remains elevated as daily demand plunges and the spot market weakens,” said EBW Analytics Group senior analyst Eli Rubin. The “dwindling of high-leverage winter price spike risks is causing natural gas prices to nosedive.” NatGasWeather said Tuesday forecasts pointed to increasing warmth expectations for the first half of December, with milder adjustments spread across the 15-day projection period. “The overnight data remained exceptionally bearish the rest of this work week and again Dec. 9-15 as most of the U.S. experiences temperatures 10-30 degrees warmer than normal,” the firm said. “…What also makes the overnight data bearish is that the end of the 15-day forecast was again quite warm with the upper pattern, suggesting bearish weather headwinds in the 10-15 day period will carry over to forecast days 16-20.” Widespread cold, the forecaster added, may not arrive in the Lower 48 until the final week of December. At the same time, production hovered around 97 Bcf/d over the past week, according to Bloomberg estimates, putting output on par with 2021 highs. Meanwhile, the Omicron coronavirus variant’s shadow “is growing darker” after Moderna Inc.’s chief executive said existing vaccines could prove less effective combating it than previous strains of the virus, Energy markets traders “will also wait for hints from other vaccine makers, and if more voices reinforce Moderna’s efficacy concerns, further price downside can be expected,” Should the new variant necessitate business and travel restrictions, they could slow economic activity and impact energy needs.

U.S. natgas drops nearly 7% to 3-month low on mild weather forecasts (Reuters) - U.S. natural gas futures dropped almost 7% on Wednesday to a three-month low on forecasts for mild winter weather, record output and ample amounts of gas in storage. Front-month gas futures for January delivery fell 30.9 cents, or 6.8%, to settle at $4.258 per million British thermal units (mmBtu), their lowest close since Aug. 26. That put the front-month down about 24% so far this week, its biggest three-day losing streak since December 2005. In addition to the collapse in the front-month, the 2022 March-April spread dropped to its lowest in 20 months as the market stops worrying about the possibility of supply shortages this winter. In recent months, global gas prices hit record highs as utilities around the world scrambled for liquefied natural gas (LNG) cargoes to replenish extremely low stockpiles in Europe and meet insatiable demand in Asia, where energy shortfalls have caused power blackouts in China. Following those global gas prices, U.S. futures jumped to a 12-year high in early October, but have since pulled back because the United States has plenty of gas in storage and ample production for the winter. Overseas prices were trading about seven times higher than U.S. futures. Analysts have said European inventories were about 17% below normal for this time of year, compared with just 2% below normal in the United States. Data provider Refinitiv said output in the U.S. Lower 48 states jumped to a record average of 96.5 billion cubic feet per day (bcfd) in November, up from 94.2 bcfd in October, easily topping the prior all-time monthly high of 95.4 bcfd in November 2019. Refinitiv projected average U.S. gas demand, including exports, would rise from 112.5 bcfd this week to 116.8 bcfd next week as the weather turns seasonally colder and homes and businesses crank up their heaters. Those forecasts were higher than Refinitiv's forecast on Tuesday. The amount of gas flowing to U.S. LNG export plants averaged 11.4 bcfd so far in November, up from 10.5 bcfd in October as the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana started producing LNG. That compares with a monthly record of 11.5 bcfd in April. With gas prices around $31 per mmBtu in Europe and $36 in Asia, compared with about $4 in the United States, traders said buyers around the world will keep purchasing all the LNG the United States can produce.

U.S. natgas drops to three-month low on mild weather outlook | 路透 (Reuters) - U.S. natural gas futures fell almost 5% on Thursday to a fresh three-month low on forecasts for milder weather and less heating demand over the next two weeks than previously expected, a decline in gas prices overseas and an easing of liquefied natural gas (LNG) exports. That price drop came despite a small reduction in output and a slightly bigger-than-expected storage withdrawal last week when colder-than-normal weather boosted heating demand. "The market has been waking up to the fact that December will be a warmer month than usual," Refinitiv analyst John Abeln said. "This doesn't preclude weather from getting much colder in January or February. But if the first part of winter is warm, that does reduce the risk that storage will be at extremely low levels by the end of the winter withdrawal season," he said. The U.S. Energy Information Administration (EIA) said utilities pulled 59 billion cubic feet (bcf) of gas from storage during the week ended Nov. 26. That was a little more than the 57-bcf draw analysts forecast in a Reuters poll and compares with a decline of 4 bcf in the same week last year and a five-year (2016-2020) average decline of 31 bcf. Last week's withdrawal reduced stockpiles to 3.564 trillion cubic feet (tcf), or 2.4% below the five-year average of 3.650 tcf for this time of year. Front-month gas futures fell 20.2 cents, or 4.7%, to settle at $4.056 per million British thermal units (mmBtu), their lowest close since Aug. 25. That put the front-month down about 28% so far this week, its biggest four-day losing streak since February 2014.

Colder Turn in Latest Weather Data Snaps Four-Day Slide for Natural Gas Futures - In an unsurprising move, natural gas futures bounced back from a four-day decline to finish the week firmly in positive territory. With a boost from technicals, colder changes in the weather models sparked a 7.6-cent rally for the January Nymex gas futures contract, which settled at $4.132. February also climbed 7.6 cents to $4.073. - Spot gas prices recorded another day in the red given a mostly mild temperature backdrop. NGI Spot Gas National Avg. fell 31.0 cents to $3.865. After plunging a steep $1.42 over the past four trading sessions, the January contract was poised for a recovery. A colder turn in the overnight weather models sealed the swing to the upside, with futures opening about a nickel higher day/day on the added heating demand in the long-range forecasts. Despite the gain in projected demand, the weather pattern overall continues to favor below-normal heating needs, with forecasters still calling for December to rank in the top five warmest on record. Bespoke Weather Services said given the look of both the Pacific and Atlantic sides of the pattern heading into the middle of the month, risk remains to the warmer side in that time frame. Furthermore, the pattern still looks to be in “warm mode” at the end of the forecast period, making it likely that days beyond Dec. 17 would continue to roll in with weak demand. “…Any potential material change in the pattern seems unlikely until at least the end of the month,” the forecaster said.

On completion of planned projects, U.S. LNG export capacity will be the world’s largest in 2022 - EIA Weekly - Since exports of liquefied natural gas (LNG) began from the Lower 48 states in February 2016, U.S. LNG export capacity has grown rapidly. Within four years, the United States became the world’s third-largest LNG exporter behind only Australia and Qatar. Once the new LNG liquefaction units (called trains) at Sabine Pass LNG and Calcasieu Pass LNG are placed in service in 2022, U.S. LNG export capacity will become the world’s largest.According to announced project plans, the following U.S. LNG export capacity expansions will occur between December 2021 and fall 2022:

• Completion of Train 6 at the Sabine Pass LNG export facility. Train 6 will add up to 0.76 billion cubic feet per day (Bcf/d) of peak export capacity. Train 6 began producing LNG in late November and the first export cargo from this train is expected to be shipped before the end of this year.
• Increase in LNG production at Sabine Pass and Corpus Christi LNG terminals as a result of optimizing operations. The U.S. Federal Energy Regulatory Commission (FERC) approved an increase in annual LNG production at these two facilities by a combined 261 billion cubic feet per year (Bcf/y) or 0.7 Bcf/d (11.5%) through uprates and modifications to maintenance. Individually:
  • FERC granted approval to increase LNG production at Sabine Pass LNG from 1,509 Bcf/y to 1,662 Bcf/y across six liquefaction trains, an increase of 10%.
  • FERC approved an LNG production increase at Corpus Christi LNG from 767 Bcf/y to 875 Bcf/y across three trains currently in operation, an increase of 14%.
• New LNG export facility Calcasieu Pass LNG in Louisiana comes online. The project consists of 9 blocks, each containing 2 mid-scale modular liquefaction units for a total of 18 liquefaction units with a combined peak capacity of 1.6 Bcf/d. Commissioning activities at Calcasieu Pass LNGstarted in November 2021, and the first LNG production is expected before the end of this year. All units are expected to be placed in service by the fourth quarter of 2022.

We estimate that as of November 2021, existing U.S. LNG nominal baseload liquefaction capacity was 9.5 Bcf/d and peak capacity was 11.6 Bcf/d (which includes uprates to LNG production capacity at Sabine Pass and Corpus Christi). By the end of 2022, U.S. nominal capacity will increase to 11.4 Bcf/d and peak capacity to 13.9 Bcf/d across 7 LNG export facilities and 44 liquefaction trains, including 16 full-scale, 18 mid-scale, and 10 small-scale trains at Sabine Pass,Cove Point, Corpus Christi, Cameron, Elba Island, Freeport, and Calcasieu Pass. In 2022, U.S. LNG export capacity will exceed that of the two current largest global LNG exporters, Australia (11.4 Bcf/d) and Qatar (10.3 Bcf/d). By 2024, when Golden Pass LNG—the eighth U.S. LNG export facility—completes construction and begins operations, U.S. LNG peak export capacity will further increase to an estimated 16.3 Bcf/d. In addition, FERC and the U.S. Department of Energy have approved another 10 U.S. LNG export projects and capacity expansions at 3 existing LNG terminals—Cameron, Freeport, and Corpus Christi—totaling 25 Bcf/d of new capacity. Developers of some of these projects announced plans to make a final investment decision (FID) in 2022.

Divide Grows Between Sweet, Sour Oil Prices as OPEC-Plus, Natural Gas Play Key Roles Mounting output from the Organization of the Petroleum Exporting Countries (OPEC) and its allies and lofty global natural gas prices are widening the spread between sweet and sour crude prices, the U.S. Energy Information Administration (EIA) said Friday. While crude prices have recently come off 2021 highs in large part because of coronavirus resurgence concerns, they remain firmly in positive territory for the year. However, prices of high-sulfur oils have been declining relative to low-sulfur alternatives, EIA said. The alliance — known as OPEC-plus — produces mostly medium- or high-sulfur oils, aka sour crude. Its mounting exports contributed to the expanding gulf. Sour oils typically sell at a discount to low-sulfur, or sweet, crude because they must first be treated with hydrogen to meet low-sulfur fuel specifications, EIA said. In the second half of 2021, sour crude discounts increased compared with historical averages, the agency’s researchers said in a report, with Mars crude, a sour oil, falling in price relative to sweet Brent oil, they said. The Saudi-led OPEC and partner countries on Thursday agreed to further boost production by 400,000 b/d in January, continuing a pace of monthly supply increases the cartel began in the summer. The Mars spot price averaged $4.92/bbl less than its Brent counterpart in November, the agency said. This was notably steeper than the $4.09 average difference between the two in August, when OPEC-plus launched its monthly supply increases. OPEC-plus increases have been most notable in countries that produce sour grades. Supply from members that produce mostly sweet crude “has been relatively flat. Likewise, U.S. production in the Lower 48 states (primarily sweet crude) has also been relatively flat,” EIA said. U.S. crude production for the week ended Nov. 26 rose to 11.6 million b/d, up 100,000 b/d from the prior week and far ahead of the 11.1 million b/d a year earlier, according to EIA data. But U.S. output has only inched up this year and remained 1.5 million b/d below the 2020 high reached during the week ended March 13, just prior to the pandemic. “We expect wide” crude spreads in 2022, Bank of America Corp. analysts said in a note to clients. “Importantly, the shale industry has shown good discipline.” High natural gas prices have also contributed to the divide between sweet and sour crudes. EIA researchers noted that hydrogen used to treat sour crude is often produced using steam methane reforming, a process that uses natural gas as an input. “As a result, the recent increases in global natural gas prices have contributed to higher refinery feedstock costs. Higher costs have led to lower demand for sour crude oils that incur more of these costs, at the same time increasing demand for sweeter oils that avoid these extra costs.”

U.S. Drilling Activity Steady Against Backdrop of Omicron Worries - -The domestic oil and gas patch turned in a relatively uneventful week in terms of net changes to drilling activity, according to the latest round of Baker Hughes Co. (BKR) data. Both oil and natural gas rig counts went unchanged overall for the week ended Friday (Dec. 3), holding flat at 467 and 102, respectively. The combined U.S. rig count stood at 569 as of Friday, up from 323 a year ago. Land drilling increased by two units overall, offsetting a two-rig decline in the Gulf of Mexico, according to the BKR numbers, which are based in part on data from Enverus. Vertical rigs increased by three in the United States for the period, offset by a three-rig decrease in directional rigs. The Canadian rig count climbed nine units to finish the week at 180, up from 102 in the year-earlier period. Gains included seven oil-directed rigs and two natural gas-directed units. BKR’s state-by-state breakdown showed some shuffling around of units even as the overall tally went unchanged week/week. New Mexico saw a net increase of five rigs for the period, reaching 88, versus 59 a year ago. Texas and Louisiana posted net declines of two rigs each, while one rig exited in California. By major play, the Permian Basin added three rigs to raise its total to 283, up from 164 at this time last year. The Cana Woodford, meanwhile, dropped one rig to fall to 23 overall, up from nine in the year-earlier period.

Another Texas House primary showdown is coming, and it's all about climate policy and Big Oil donations - The Washington Post --Jessica Cisneros is vying for the seat of one of the biggest Democratic recipients of fossil fuel industry money in Congress. And she's making climate change a centerpiece of her campaign.Cisneros, a 28-year-old immigration and human rights lawyer, is mounting a second primary challenge against Rep. Henry Cuellar, a 66-year-old former attorney who has represented south Texas in Congress for nearly two decades. Story continues below advertisement In the 2020 primary, Cuellar beat Cisneros by less than 3,000 votes. This time around, Cisneros is seeking to highlight Cuellar's donations from the oil and gas industry, which she says have driven his opposition to certain climate policies.Cuellar is the fourth-biggest recipient in the House of oil and gas campaign contributions in the 2022 cycle so far, receiving $100,200, according to OpenSecrets. He previously received $165,305 from the fossil fuel industry over the 2015-16 campaign cycle, leading McClatchy to speculate whether he was "Big Oil's favorite Democrat." In the climate policy arena, Cuellar opposes the Green New Deal, the sweeping proposal to wean the nation off fossil fuels in a decade with a government-led jobs program. He has also expressed concern about including a fee on emissions of methane, a potent greenhouse gas that can leak from oil and gas wells, in Democrats' climate and social spending bill. While Cuellar voted for the Build Back Better Act when it passed the House this month, he is continuing to lobby the Senate to drop the methane fee from the spending bill, the Associated Press reported last week. "It's no surprise that as a result of his track record, he's known as Big Oil's favorite Democrat," Cisneros said of Cuellar in an interview with The Climate 202. "And it's no surprise that he's doing their bidding after all the support he's received from them."

New Mexico taking action on oil and gas-induced earthquakes -- A growing threat of earthquakes in southeast New Mexico prompted the State to take action by upping its seismic monitoring and calling for oil and gas operators to curb the amount of produced water disposed of underground. The byproduct water, known as produced water in industry terms, is a combination of flowback water created during hydraulic fracturing operations and water brought up from underground shale formations along with oil and natural gas. Traditionally this water, briny and contaminated with toxic chemicals, is pumped back into the shale for disposal, but such a process was recently linked to increased seismic events in the Permian Basin shared by southeast New Mexico and West Texas. Earlier this year, the Texas Railroad Commission announced it was establishing two seismic response areas (SRAs) in the Midland areaand along the Texas-New Mexico border in Culberson and Reeves counties. It called for reductions in produced water injection volumes and advocated blocking any new permits for saltwater disposal wells (SWDs). And on Tuesday, New Mexico’s Oil Conservation Division (OCD) announced similar actions as a string of earthquakes were reported in New Mexico throughout November. Permits under review for SWDs in the area south of Malaga, near the Texas State Line, will require additional review, the department said. Meanwhile, a “statewide response protocol” was put in place by the OCD that will increase reporting and monitoring measures while also reducing the volume of water injected based on further observed seismic activity. “Category 1” of the protocol would go into effect when two quakes of magnitude (M) 2.5 or higher occur within 30 days and within a 10-mile radius of each other. An M 2.5 earthquake is the first level where it could be lightly felt, according to the Richter Scale. Serious damage can occur at a M 3 or greater. With 10 miles of the epicenter of such an event, operators would be required to provide to the state weekly reporting of daily injection volumes and average daily surface pressure, while digitally measuring injections volumes and pressure and providing analysis and data to the OCD when requested. At “Category 2,” which goes into effect if one M 3 event occurs, all of Category 1 requirements would be imposed, along with requirements that operators within 3 miles reduce injection rates by 50 percent. Within 3-6 miles, operators would be required to cut injection by 25 percent. If a M 3.5 or higher quake is reported, operators with 3 miles must shut in their wells, and cut injection by 50 percent at 3-6 miles, and 25 percent at 6-10 miles.

Uinta Basin is hemorrhaging methane as leaks go undetected - As much as 8% of the Uinta Basin’s natural gas production escapes into the atmosphere, an indication that the basin’s methane emissions are among the worst in the nation for energy-producing regions, according to new research from the University of Utah. Monitoring data indicate leaks from wells, pipelines, compressors and processing facilities release 6 to 8% of the natural gas pulled from the ground in northeastern Utah, representing a huge waste of a largely publicly owned natural resource. These “fugitive” emissions also pose an avoidable threat to the climate. That’s because methane, the main ingredient in natural gas, has a much stronger greenhouse effect than carbon dioxide. An estimated 2.3% of U.S. natural gas production escapes into the atmosphere, according to other research, accounting for 30% of the nation’s human-caused methane emissions. Other leading sources include coal mines, landfills and possibly bovine flatulence.The Biden administration highlighted “methane abatement” as one of its strategies for achieving its goal of cutting the nation’s 2005 greenhouse emissions in half by 2030. On Nov. 2, the Environmental Protection Agency proposed tighter standards and guidelines for reducing methaneemissions from oil and gas operations. These rules would cut emissions by 41 million tons through 2035, the agency said.Despite the severity of methane’s impact, quantifying these fugitive emissions has been elusive. Labor-intensive methods of surveying oil and gas sites for leaks has proven unreliable. But a research team led by John Lin, a U. atmospheric scientist, is now using long-term monitoring data to determine how much methane escapes from the Uinta Basin’s oil and gas operations. According to a peer-reviewed study released this week in Scientific Reports, Lin’s team documented how the basin’s methane emissions dropped by half since 2015, in virtual lockstep with declining natural gas production over the same period when commodity prices tanked. “This means that the leak rate has stayed at a constant—albeit high—rate, even with decreases in natural gas production,” Lin said. Previous research suggested lower-production wells would leak a higher proportion of methane. “This may account for the high leak rate in general in the Uinta Basin since the average Uinta well produces less gas compared to many other counterparts around the U.S.,” Lin said. “However, it was nonetheless surprising that the leak rate did not increase as the Uinta wells decreased in production.” His findings support similar findings from eight years ago by the National Oceanic and Atmospheric Administration, or NOAA, which estimated that 6 to 12% of the basin’s production leaked into the air.

Democrats press drillers for methane leak data - Democrats are asking 10 oil and gas companies for data on leaks of a planet-warming gas called methane, as these leaks can add significantly to fuels' contributions to climate change. As part of a new inquiry announced on Friday, House Space, Science and Technology Committee Chairwoman Eddie Bernice Johnson (D-Texas) wrote to companies seeking such data. She wrote to 10 companies, including ExxonMobil and Chevron, that operate in the Permian Basin producing region in the southwestern U.S. in what she described as an attempt to understand whether their technology can achieve significant emissions reductions. The inquiry also seeks information about whether and how to strengthen the federal government’s role in monitoring methane leaks. When they’re burned, oil and especially natural gas give off fewer planet-warming emissions than coal, and the industry has often touted them as cleaner alternative energy sources. However, leaks of methane, which is 25 times more powerful than carbon dioxide over a 100-year period, can occur during the process of producing and transporting oil and gas. These leaks in turn increase how the fuels contribute to global warming and undercut such assertions from the industry.Johnson, in her letters, cited a study that found that about 60 percent more methane was leaked in 2015 than was counted by the Environmental Protection Agency (EPA). The study attributed the underestimate to inventory methods that do not account for “abnormal operating conditions.” “The existence of these leaks, as well as continued uncertainty regarding their size, duration, and frequency, threatens America’s ability to avoid the worst impacts of climate change,” Johnson said in a statement. “I am concerned that oil and gas sector Leak Detection and Repair (LDAR) programs may not be designed and equipped to comprehensively monitor and detect methane leaks, particularly the intermittent, ‘super-emitting’ leaks that are responsible for much of the sector’s leak emissions.”In the letters, she specifically asked companies whether they have developed estimates of their emissions in the Permian Basin that differ from the EPA estimates. She also asked them to provide information about how much methane they have leaked annually since 2016.

Senator Warren’s oil price conspiracy theory - As Friday’s 10% oil price plunge demonstrated, there is only one truth when it comes to oil prices: if you don’t like the price today, just wait a little. Yet for some, everything is politics, and the recent increase in gasoline prices has seen many from both parties weighing in, responding to public anger. Sadly, little of the discussion involves supply and demand, nationally or globally, but rather finger-pointing and trolling. Take for example, the recent appearance by Massachusetts Senator Elizabeth Warren on Joy Reid’s MSNBC show, where the host expressed consternation that people had been staying home but gasoline prices had risen anyway. In response, the senator replied, “If this were just ordinary inflation, we might see prices go up, but prices at the pump have gone up why? Chevron, Exxon, have doubled their profits. This isn’t about inflation, this is about price gouging for these guys.” Both the question and the reply were nonsense. Ms. Reid apparently thinks demand determines prices, rather than both demand AND supply. Last year, soaring inventories led to a collapse in oil prices, briefly below $25/barrel (ignoring the one day’s negative price). OECD oil inventories rose by a phenomenal 300 million barrels in three months, far above normal. Then two things happened. First, OPEC and its allies (OPEC+) cut production by an astonishing amount—but not an outrageous amount, given the collapse in demand. This brought inventories down to a more normal level, as the figure shows. However, the global economy recovered faster than expected: the July 2020 IEA forecast for 2021 demand was low by about 3 mb/d, which translates into an annual amount of over 1 billion barrels. Add Hurricane Ida which caused a loss of over 40 million barrels of production at a time when inventories were already low, and you have the (cough) perfect storm. But Senator Warren’s comment is problematic for a number of reasons, not just because she ignores the actual market developments. First, she conveniently ignores the huge financial losses that the oil industry in 2020. If she called for their losses to be subsidized, or bailed out, I must have missed it. Her focus on only most recent quarterly profits certainly confirms her political bias. More bizarrely, she adopts the not uncommon view that the oil industry, especially the big companies, can control the price—but usually choose not to. Does she think that last year, the industry ‘allowed’ the price to collapse? Then this year, just by coincidence, they choose to raise prices as global oil inventories shrank? She is hardly alone in thinking that the invisible hand of the market is really a group of individuals or companies who control it for their own interests. In fact, there are those in the oil industry who think the market is being controlled by outsiders such as traders on Wall Street who are antagonistic to them and periodically drive the price down to their detriment. The reality is that the price is the result of myriad decisions by thousands of traders and producers in the short-run and millions of consumers in the long run. As Senator Warren has shown repeatedly over her career, her progressive instinct is to distrust and “fix” seemingly inefficient markets, believing that she knows better than the collective decisions of thousands of market participants what is best for the citizenry. Percolating from the progressives are suggestions that exports of oil and gas should be banned on the grounds that creating a domestic surplus would lower prices — at least for the U.S. The next time gasoline prices surge, watch for Senator Warren to embrace her inner Richard Nixon and propose oil price controls.

Biden administration releases report saying oil and gas companies should pay more to drill on public lands - In an effort to boost revenue and protect the environment, the Biden administration on Friday laid out plans to make fossil fuel companies pay more to drill on federal lands and waters. The 18-page Interior Department report describes an “outdated” federal oil and gas leasing program that “fails to provide a fair return to taxpayers, even before factoring in the resulting climate-related costs.” The document calls for increasing the government’s royalty rate — the 12.5 percent of profits fossil fuel developers must pay to the federal government in exchange for drilling on public lands — to be more in line with the higher rates charged by most private landowners and major oil- and gas-producing states. It also makes the case for raising the bond companies must set aside for cleanup before they begin new development. Though Friday’s report focuses on the fiscal case for updating the leasing program, Interior officials say they will also consider how to incorporate the real-world toll of climate change into the price of permits for new fossil fuel extraction. The Biden administration this year set its “social cost of carbon” at $51 per ton of emissions, but suggested the number could go even higher as researchers develop new estimates of the damage caused by raging wildfires, deadly heat, crop-destroying droughts and catastrophic floods. “The direct and indirect impacts associated with oil and gas development on our nation’s land, water, wildlife, and the health and security of communities — particularly communities of color, who bear a disproportionate burden of pollution — merit a fundamental rebalancing of the federal oil and gas program,” the report says. But many activists were dissatisfied with the document, which they say breaks President Biden’s campaign promise to ban new oil and gas leasing on public lands. Advertisement “We are destroying life on Earth by extracting fossil fuels,” said Randi Spivak, public lands program director at the Center for Biological Diversity. “The process needs to end, not be reformed.” Economic analyses suggest the changes to royalty and bonding rates will increase revenue, but they will not significantly curb carbon emissions. After a summer during which 1 in 3 Americans experienced a climate disaster, Spivak compared the administration’s plans to “rearranging deck chairs on the Titanic.” The American Petroleum Institute’s Frank Macchiarola criticized the proposal for increasing the cost of fuel development in the United States. “During one of the busiest travel weeks of the year when rising costs of energy are even more apparent to Americans, the Biden Administration is sending mixed signals,” Macchiarola, API’s senior vice president for policy, economics and regulatory affairs, said in a statement.

3 issues to watch with Biden's oil and gas overhaul - The Biden administration’s “high level blueprint” for revamping the federal oil and gas program, published over the Thanksgiving holiday, is either a bombshell or a dud depending on who’s talking.On the one hand, it lays out an overhaul of the the federal oil program that has been largely unchanged for decades. It’s won accolades from many environmental groups that have fought for these changes for years and elicited groans from industry allies who say the proposals would hamper production at a time when this country should actually be encouraging development.But some climate activists countered the Interior Department’s long-awaited report merely embraces incremental reforms that fail to sufficiently address the federal oil program’s contributions to climate change, and certainly do not uphold President Biden’s campaign pledge to end new leasing on public lands and waters.If Interior Secretary Deb Haaland implements the report’s recommendations, oil drillers on public land could face a dramatic increase in royalty rates for the first time in 100 years. They also may need to secure insurance to cover their cleanup costs, a multibillion-dollar hole in current bonding that would ensure wells are plugged and lands restored after drilling (Greenwire, Nov. 26).While Interior would need to write new rules to implement some of these plans, new practices at its offices could be enough to implement other suggestions — such as the recommendation that lands with little oil potential not be made available for auction. The report, too, said Interior should no longer open the entire Gulf of Mexico to oil and gas drillers in each lease sale.The report completes the review ordered by President Biden shortly after taking office in January. At the time, he also temporarily froze new leasing — a moratorium later ended by a federal judge. The report’s conclusion for the president is blunt: “The review found a Federal oil and gas program that fails to provide a fair return to taxpayers, even before factoring in the resulting climate-related costs that must be borne by taxpayers.”

US Interior leasing reforms to have minor production impact despite higher costs - The Biden administration's proposed reforms to federal oil and gas leasing could raise costs to drillers and potentially shrink available acreage, but the expected production impact continues to be minor, analysts said Nov. 29. The US Interior Department issued an 18-page report laying out its goals for overhauling the leasing program with the aim of providing a "fair return" to US taxpayers, in line with past recommendations by the Government Accountability Office and Interior's Office of Inspector General. The report proposed increasing royalties, rental rates, minimum bids, and bonding requirements; while curbing royalty relief and imposing new leasing fees, among other changes. "There is nothing in this report that would that tangibly impact near or medium-term supply from the US if enacted," said Parker Fawcett, North American supply analyst for S&P Global Platts Analytics. "Further out, a restriction in available acreage for leasing does put lingering risk to the long-term development of federal lands." About 7% of US oil production and 8% of US gas output is produced on federal onshore lands, while federal offshore acreage accounts for about 16% of US oil output and 3% of gas output, the report said. Democrats' Build Back Better budget reconciliation bill currently proposes even more aggressive changes to royalty rates, royalty relief, minimum bids, and non-competitive leasing than Interior's report, said Glenn Schwartz, energy policy director of Rapidan Energy Group. Schwartz added that any regulatory changes on acreage are not "all that necessary." While the Mineral Leasing Act requires quarterly auctions for federal leasing, it gives the Interior Secretary wide discretion under the existing statute to "determine where and how much acreage is offered up." "While an outright ban was always illegal, this discretion vests [Interior and its Bureau of Land Management] with all the authority it needs to control the flow of leases and permits as it sees fit," Schwartz said. "So, in that way, the changes proposed by this report don't really change our outlook on oil and gas production. Any changes made through regulation or bureaucratic discretion can be undone fairly easily by a future administration that takes a more positive view towards fossil fuel development on federal lands." Kevin Book, managing director of ClearView Energy Partners, said the timing of the report — the Friday after Thanksgiving — suggests "that the White House may have hoped to minimize criticisms linking current gasoline prices to the administration's federal oil and gas strictures."

Oil industry and Biden administration clash over latest proposals -- New proposals by the Biden administration and Congress could have a major impact on the mainstay of Louisiana and Houma-Thibodaux's economies: oil and gas. Biden and the oil industry have long been at odds as he follows through on a campaign pledge to reduce the pollution, rising seas and other ill effects greenhouse gasses from fossil fuels are wreaking on the planet. His latest action came Friday when the Interior Department proposed major changes to the federal government's oil and gas leasing program. The report includes a recommendation to increase royalty rates, or the price the government charges oil and gas companies to drill on federal lands and waters, including the Gulf of Mexico. “Our nation faces a profound climate crisis that is impacting every American. The Interior Department has an obligation to responsibly manage our public lands and waters – providing a fair return to the taxpayer and mitigating worsening climate impacts – while staying steadfast in the pursuit of environmental justice,” Interior Secretary Deb Haaland said in releasing the report. “This review outlines significant deficiencies in the federal oil and gas programs and identifies important and urgent fiscal and programmatic reforms that will benefit the American people.” Oil-industry groups expressed immediate opposition. "During one of the busiest travel weeks of the year, when rising costs of energy are even more apparent to Americans, the Biden administration is sending mixed signals," Frank Macchiarola, senior vice president with the American Petroleum Institute, said in a news release. "Days after a public speech in which the White House said the president 'is using every tool available to him to work to lower prices and address the lack of supply,' his Interior Department proposed to increase costs on American energy development with no clear roadmap for the future of federal leasing."Meanwhile, the Biden-backed Build Back Better legislation passed Nov. 19 by the House includes several provisions that would also limit drilling and make it more difficult and expensive to explore for and produce oil and gas. Among its provisions:

• A permanent ban on drilling off most of the nation's coasts, including the eastern Gulf of Mexico. Congress has repeatedly enacted bans in that area, with the latest set to expire in June. The Trump administration issued an executive order extending the ban through 2032, but that could be undone by any president without congressional action.
• A fee on methane released from wells, pipelines and oil and gas storage sites.
• About $300 in combined tax credits aimed at encouraging the use of renewable energy instead of fossil fuels to produce electricity, power vehicles and manufacture goods.
• Tax credits of up to $12,500 on the purchase of a new electric vehicle and $4,000 for a used one.

Michigan drops one lawsuit, revisits another in Enbridge Line 5 fight -After a federal judge this month dealt a blow to Gov. Gretchen Whitmer’s campaign to shut down Enbridge Energy’s Line 5 pipeline, Michigan is hoping for better legal luck in state court. State Attorney General Dana Nessel on Tuesday filed notice with U.S. District Court Judge Janet Neff that she is voluntarily dismissing the state's federal lawsuit. The suit, originally filed in state court but later moved, sought to reinforce the governor's year-old order for Enbridge to stop transporting oil through the Straits of Mackinac. Instead, Nessel is seeking to kickstart an earlier lawsuit she filed against the company in Ingham County Circuit Court soon after taking office. That lawsuit, which also seeks a Line 5 shutdown, was paused this year while Michigan and Enbridge fought in federal court over Whitmer’s shutdown order. In November of last year, Whitmer gave Enbridge a 6-month deadline to stop transporting oil through the Straits, and Nessel followed with a lawsuit seeking to reinforce the order before a Michigan judge. Enbridge quickly counter-sued, arguing the state had no authority to shut down a federally-regulated pipeline. The company also was successful in getting the case removed to federal court, arguing, over Nessel’s protests, that the case belonged before a federal judge. In a statement, Nessel noted that the dismissal Tuesday of the federal suit was the governor’s decision and said Michigan will continue fighting Enbridge in state court. “The state court case is the quickest and most viable path to permanently decommission Line 5,” Nessel said. “The Governor and I continue to be aligned in our commitment to protect the Great Lakes and this The dismissal follows Neff’s ruling earlier in November that the lawsuit over Whitmer’s shutdown order must continue in federal court because Line 5 is now subject to an international treaty dispute, and because it falls under the regulatory purview of the federal Pipeline and Hazardous Materials Safety Administration. That decision was a blow to state attorneys, who had argued that the state’s public trust authority gives the Whitmer administration authority to shut down Line 5. By keeping the case in federal court, Neff was essentially nullifying the state’s central argument. M

Michigan is now 'on weak legal ground' in Line 5 debate, DeWine administration says - —Ohio Lt. Gov. Jon Husted believes the new strategy Michigan Gov. Gretchen Whitmer is taking in hopes of an eventual closing of the controversial pipeline known as Line 5 "is a sign that Michigan understands it is on weak legal ground in federal court and is seeking a more favorable forum to plea their case," he told The Blade via email Wednesday. "Ohio will continue to fight to keep Line 5 open so fuel gas prices don't go up and jobs won't be lost," the lieutenant governor said. "We urge Michigan to honor the commitment they made with the pipeline owner under [former] Governor [Rick] Snyder to keep the pipeline operating in an environmentally responsible manner." Governor Whitmer caused a bit of a stir on Tuesday when she announced she was voluntarily dismissing a lawsuit she filed in U.S. District Court against Enbridge in November of 2020, one which largely mirrored a lawsuit that Michigan Attorney General Dana Nessel filed in June of 2019 in state court. One of the questions has been over jurisdiction. Canadian-based Enbridge, the pipeline's owner-operator, had wanted the case heard in federal court, citing interstate laws and agreements with Canada over the transport of fuel products through Line 5. Proponents of keeping the matter in state court have cited precedents about common law. U.S. District Judge Janet Neff agreed with Enbridge that the matter belonged in federal court. Ms. Whitmer responded by dismissing the lawsuit she brought over whether a federal judge should give the ultimate ruling. Line 5 has become one of North America's biggest debates over pipelines. Although it traverses more than 645 miles across Canada and the United States, four of them run through the Straits of Mackinac, which Governor Whitmer considers an environmentally risky location because of the potential impact on one of the world's largest collections of fresh surface water. At stake is the future protection for the Great Lakes, and the economic well-being of industries, including two Toledo-area refineries and one in Detroit, which provide thousands of high-paying jobs and produce much of the region's gasoline, propane, jet fuel, and other petroleum products. Several are dependent on Line 5.

Canada says talks with U.S. over pipeline dispute should start soon - Formal talks between Canada and the United States over a disputed Michigan pipeline should start soon, Ottawa said on Wednesday, the latest development in an affair souring bilateral relations. Last month Canada invoked a 1977 treaty with the United States to trigger negotiations over Enbridge Inc’s Line 5, which Michigan wants to shut down on environmental grounds. Michigan’s governor said on Tuesday she would dismiss her lawsuit against the pipeline in federal court, clearing the way for a separate case in state court. Canada’s foreign ministry said the move did not affect talks under the 1977 treaty. “We expect the formal negotiations to begin soon,” ministry spokeswoman Clara Trudeau said by email, noting that “Canada has consistently supported the continued, safe operation of Line 5, and raised it with the U.S. government at every level”. The treaty has never been invoked before. Line 5 ships 540,000 barrels per day of crude and refined products from Superior, Wisconsin, to Sarnia, Ontario. Michigan ordered it shut down by May over worries a leak could develop in a four-mile section running beneath the Straits of Mackinac in the Great Lakes. Enbridge ignored Michigan’s order and the sides are embroiled in a legal battle. Canada’s federal Trade Minister Mary Ng is due to raise the matter during three days of talks in Washington this week, her office said. She will also discuss irritants such as U.S. duties on Canadian software lumber and planned U.S. tax breaks for domestically produced electric vehicles.

Commentary: Biden Is Making Russia Great Again - Under former President Donald J. Trump, for the first time in decades, the United States became a net exporter of natural gas and oil. That helped to keep global energy prices relatively low. It also gave the United States leverage over the international system in ways it had not enjoyed since before the 1970s. Alas, the propagation of the novel coronavirus from Wuhan, China, along with the ceaseless lies of the Western “mainstream” media made such a prosperous and secure future under Trump an impossibility.In the eight months since assuming office under a cloud of controversy, Joe Biden has done more to harm America’s inherent strategic advantages in the global energy market than any U.S. rival could have imagined. Under Biden, the United States has gone from being a net exporter of global energy to begging the Organization of Petroleum Exporting Countries (OPEC) to produce more oil for the world to consume.Why?Because the Biden Administration killed the much-needed KeystoneXL Pipeline that would have linked Canadian energy sources with American refiners. Once inaugurated, the Biden Administration’s Environmental Protection Agency (EPA) enacted a bevy of onerous regulations that ensured American fossil fuel producers would not produce their essential product out of fear of retribution from vengeful federal regulators.Biden also killed similar pipelines linking northern Michigan with Canada. Meanwhile, global supply chain woes following the painful COVID-19 lockdowns from the previous year ensured that there would be even more strain on the already stretched global energy supply. Plus, the reopening of the world’s major economies, coupled with the massive government spending that occurred over the previous year to combat COVID-19, forced a spike in demand that was not commensurate with supply—further straining that already limited energy supply and sending the price of energy into the stratosphere. Higher energy prices not only harmed American consumers but, over the last year, it has given renewed life to the Putin regime in Russia. Since Russia is a major producer of natural gas and oil, Moscow needs consistently high prices of energy to survive—and dominate—in their region of the world.

North Dakota eyes federal money for expansion of oil well plugging program -North Dakota’s top oil regulator wants to extend the state’s abandoned well plugging program by tapping into $4 billion made available in the federal infrastructure bill for the purpose of cleaning up old oil and gas sites across the nation. Tens of millions of dollars could potentially come North Dakota’s way each year over the next decade to continue the work the Oil and Gas Division started in 2020 to clean up hundreds of wells. Other oil and gas states also are eligible to apply, and advocates for North Dakota landowners say the rest of the country could learn from the state’s experience. The funding is meant “to tackle this problem nationwide and to improve state regulations and federal regulations so that the problem not only doesn’t continue to grow but doesn’t continue to extend and require another infusion of money at some point in the future,” State Mineral Resources Director Lynn Helms said. “We’re really excited about that,” he added. North Dakota spent tens of millions of dollars in federal coronavirus aid plugging more than 300 abandoned wells and reclaiming the sites over the past two years. The cleanup work is ongoing. State officials billed the program as a way to keep oil workers employed when the pandemic prompted a downturn in their industry, as well as a means to address the growing number of wells producers had abandoned.While landowners are eager to see abandoned wells dealt with, some advocates have concerns about the way the program was implemented last year. “If they would be more thoughtful in the approach to this, we could do a much better job than last time when it was very rushed,” said Troy Coons, chairman of the Northwest Landowners Association. Coons’ group released a report last month evaluating North Dakota’s program. Among the concerns it raised is that reclamation work meant to restore a well site to its original state was sometimes left incomplete, with contamination from saltwater spills still lingering. Saltwater is a byproduct of oil production and can render land infertile if it leaks.

Pipeline documents case headed to North Dakota high court — A legal battle is headed to North Dakota’s Supreme Court over access to thousands of documents related to the developer of the Dakota Access Pipeline and the company that oversaw security during construction.Pipeline developer Energy Transfer and its subsidiary Dakota Access LLC last year sued the state board that regulates private investigators and security firms, seeking the return of some 16,000 documents. The Houston-based company argues the records are confidential and could present a security risk if released publicly.Arguments in the case likely will be held in January or February, state Supreme Court clerk Petra Hulm said Wednesday.The security company, North Carolina-based TigerSwan, gave the documents to the North Dakota Private Investigative and Security Board during a two-year-long fight over whether the company operated illegally without a license in North Dakota while the pipeline was under construction in 2016 and 2017.TigerSwan settled its case with the state last year for $175,000 but denied any wrongdoing. Energy Transfer wants the documents back and has sued TigerSwan for breach of contract. Separately, litigation has arisen over release of the documents to the media. First Look Institute Inc., the nonprofit publisher of The Intercept, sued North Dakota last year, seeking to obtain the documents, under the state’s open records law.The North Dakota attorney general’s office is representing the board in that case. Attorney General Wayne Stenehjem said he could not comment on the case due to the ongoing litigation.

Industrial Commission approves guidelines for the new 'Natural Gas Pipeline Grant' program - North Dakota’s Industrial Commission has approved the timelines and the guidelines for the new Natural Gas Pipeline Grant Program. That program was funded in the special Legislative Session, and will be paid for through the American Recovery Plan Act, or “ARPA.” The Legislature appropriated $150 million from ARPA funds for the project, which aims to bring natural gas from the Bakken to central and eastern North Dakota. $10 million of that has been earmarked to build a short pipeline from the Viking Pipeline in western Minnesota to Grand Forks County, for a new “wet corn milling “plant. The guidelines include requiring a minimum 60% match from the applicant; requiring that the applicant operate as a "common carrier," and demonstrates sufficient shipper commitments before receiving any money; and the establishment of a Natural Gas Review Committee, that will make a recommendation to the Industrial Commission. The deadline for companies to apply for that $10 million grant is March First, 2022, with a decision due in August, 2022. "The time frame for that Grand Forks portion, is to have it in-service by mid 2024," said North Dakota Pipeline Authority director Justin Kringstad. For the larger project, the deadline for application is April First, 2022, with a potential completion date of 2025 or 2026. "We know gas volumes are ramping up in western North Dakota extremely quickly," Kringstad said. "Time is of the essence." State officials are concerned that — because of the gas-oil ratio in the Bakken — oil production could be curtailed, to prevent flaring of natural gas. Kringstad said this project will continue to shape North Dakota's oil and gas industry. "This will continue to help shape North Dakota's oil and gas industry," Kringstad said. "It's an exciting time." Kringstad said he's already been contacted by companies interested in the project.

Jordan Cove project dies. What it means for FERC, gas - - The developer of an Oregon liquefied natural gas export terminal told the Federal Energy Regulatory Commission for the first time yesterday it would not move forward with the embattled project, putting to rest years of uncertainty for landowners.Citing challenges in obtaining necessary permits from state agencies as the reason for abandoning the Jordan Cove project, Pembina Pipeline Corp. asked FERC to cancel authorizations for the LNG terminal and associated Pacific Connector pipeline, which would have carried natural gas from Canada to the proposed facility in Coos Bay, Ore.“Among other considerations, Applicants remain concerned regarding their ability to obtain the necessary state permits in the immediate future in addition to other external obstacles,” Pembina said in its brief to FERC.The announcement adds to a debate about the role of natural gas at a time of high prices and as industry groups are pressuring the Biden administration to clarify exactly how LNG exports fit into its broader climate agenda (Energywire, July 8). It also may influence FERC’s ongoing review of how it approves gas projects.Pembina’s move is a win for landowners who have been steadfastly opposing the project for years, said David Bookbinder, chief counsel for the Niskanen Center and attorney for some of the landowners affected by the pipeline. The Niskanen Center and others submitted a brief of their own yesterday, urging FERC to grant Pembina’s request to ax the certificate."I can say the landowners are utterly delighted that this chapter of their 15-year nightmare is over and hopefully that will truly be the end of Pembina’s hopes to build this project," he said.The company had put the export project on an indefinite hold in April after failing to get key state and federal approvals.But Pembina’s decision to cancel the project outright means affected landowners can now move forward with plans to improve or sell their property, Bookbinder added.The commission did not respond to a request for comment on the brief, since the issue remains pending.Scott Lauermann, a spokesperson for the American Petroleum Institute, called the cancellation of Jordan Cove “yet another unfortunate example of a much needed U.S. energy infrastructure project being terminated due to unnecessary regulatory delays.” Canceling the project, which was slated to carry LNG to Asian markets, meant the U.S. had "lost an opportunity to export its success in reducing emissions," said Western States and Tribal Nations President Andrew Browning in a statement.

Oil pipeline planned even as California moves away from gas - (AP) — A proposal to replace an oil pipeline that was shut down in 2015 after causing California's worst coastal spill in 25 years is inching though a government review, even as the state moves toward banning gas-powered vehicles and oil drilling. Consideration of the $300 million proposal by Houston-based Plains All American Pipeline is expected to enter a critical phase next year at a time when new scrutiny is being placed on the state’s oil industry after an offshore pipeline break in October near Huntington Beach. That rupture released at least 25,000 gallons (94,635 liters) of crude that closed beaches and took a deadly toll on sea life along one of the world’s fabled surf breaks. Farther north, the 123-mile (198 kilometer) Plains pipeline travels along the coastline near Santa Barbara before turning inland. It's buried and nearly invisible for much of its length to Kern County, in the state's midsection. For decades it was a vital link between oil platforms off the coast and processing plants on shore, with shipments averaging 1.8 million gallons (6.9 million liters) a day. California Democratic U.S. Sen. Alex Padilla opposes the proposal, bluntly warning of future risks. “We’ve seen time and time again how damaging offshore oil spills are to our coastal ecosystems as well as to our outdoor recreation and tourism economies,” Padilla said in a statement. “We should not risk repeating history by rebuilding or restarting the Plains pipeline.” Plains spokesman Brad Leone said the company safely transported 90 billion gallons (341 billion liters) last year throughout North America. “Plains is committed to designing, constructing and maintaining these lines in a safe, reliable manner,” he said. The project faces numerous hurdles, including a federal class-action lawsuit from property owners who say Plains lacks the right to use existing easements for a new pipeline. Lead trial counsel Barry Cappello said the project would rip up vineyards and coastal ranches and “our clients never signed up for that.”

Fossil Fuel Companies Stand to Make Billions From Tax Break in Democrats’ Build Back Better Bill - With the Senate turning its attention to President Joe Biden’s climate and social policy bill in the coming weeks, lawmakers are poised to expand a key tax credit that energy industry lobbyists and some experts say could unleash an important climate tool.But the legislation, which includes changes to a tax credit for removing carbon dioxide from smokestacks or the atmosphere, could also funnel tens of billions of dollars to fossil fuel companies and other polluters over the next two decades. The House passed the bill last month.Together with the bipartisan infrastructure bill enacted in November, which included more than $12 billion in funding for carbon capture and carbon removal technologies, the Build Back Better legislation would hand fossil fuel companies nearly every item on their carbon capture wishlist.Perhaps the most important change in the bill is a 70 percent increase in the value of the tax credit. The payouts from the expanded credit could be so large that, if energy companies reach the scale they say they can, it could largely wipe away their corporate income tax bills, according to recent comments by Erik Oswald, an ExxonMobil lobbyist.“If you did this at scale, like the gigatons of sequestration I was talking about,” companies’ federal income taxes “would be entirely eaten by that,” he said in a recording obtained by the watchdog group Documented and provided to Inside Climate News.Oswald was speaking at a meeting of the Interstate Oil and Gas Compact Commission, a group of state energy regulators, on November 9, the week before the House passed the Build Back Better package. The comments came in response to a question about whether carbon capture and storage could be viable without government support. Oswald said it could, eventually, suggesting that policy makers could scale back the credit if the technology took off.The legislation passed by the House would not only raise the amount of the tax credit but would also tweak it to allow companies to receive direct payments from the federal government, rather than having to deduct the value from their income tax statements. It also would extend the credit’s eligibility by six years. Some industry executives have said that the changes could finally make the finances work for projects including gas-fired power plants fitted with carbon capture equipment.

Canada Regulators Say No to Long-Term Oil Contracts on Enbridge Mainline - A 28-month fight over access to Enbridge Inc.’s oil Mainline ended in defeat Friday for its plan to sell decades-long contracts to fill 90% of the conduit’s capacity for 3 million b/d to a handful of refineries and brokers. “Mainline contracting would likely reduce the access to pipeline capacity realistically available to certain shippers,” said the Canada Energy Regulator (CER) in a decision to continue a 71-year tradition of filling the pipe with monthly bookings available to all. “The package of tolls, terms, and conditions in the service offering would result in a distribution of benefits and negative impacts that is uneven and disproportionate,” CER stated. Enbridge said Sunday it accepted the CER decision and pledged to begin discussions within weeks on a new package of services, tolls and expansion planning with Mainline shippers. The new deal would replace an agreement that expired in June. “Any negotiated settlement would require CER approval,” said Enbridge. “The negotiating process may take through 2022. We expect the subsequent CER review and decision process to conclude in 2023.” The pipeline firm assured investors that a financially “manageable” settlement would be sought to prevent harm to its corporate books or share prices. “Mainline throughput is expected to be strong over the next several years and the company’s outlook is positive.”

Husky Oil Spill Case Postponed Until January - Lawyers for Husky Energy will return to court in January to answer to charges in connection with the largest oil spill in the history of the province’s offshore. Husky is facing three charges stemming from the incident which occurred three years ago, as crews in the White Rose field were preparing to restart production, which had been suspended due to stormy weather. It’s estimated 250,000 litres of oil spilled into the ocean from a leak in a flowline to the SeaRose FPSO, about 350 kilometres southeast of St. John’s. Husky is accused of causing or allowing the spill to occur, failing to ensure an immediate work stoppage to avoid further pollution, and starting up again before ensuring it was environmentally safe to do so. The spill has been blamed on a faulty connector with underwater cables to the FPSO, but questions were also raised about the speed with which Husky restated operations. In provincial court this week, the case was postponed until January 14, as the defence gathers more disclosure from the Crown.

Quebec to Pay “Significantly More” than $5B to Jilted Utica Drillers -In October the province of Quebec, Canada announced it will expropriate all of the rights for all oil and gas companies in the province to drill and extract oil and natural gas (see Lights Out for All O&G Production in Quebec, Including Utica Shale). It’s all being shut down–including actively producing wells. Shutting down existing businesses in the province is something you might expect in Communist China, or Soviet Russia, or tin-horn dictatorships in South America. It’s not something you expect to see in Western democracies. Yet it’s happening in Quebec, home to a large deposit of the Utica Shale. Now Quebec drillers, those who had planned to tap their vast Utica Shale assets, are demanding Quebec pay up, and the price will be “significantly more” than the $3 billion to $5 billion floated by the province’s energy association.

Quebec: Burning fossil fuels has a cost. Keeping them in the ground also has a price - Quebec killed Utica Resource's business plan — now the company wants billions of dollars in compensation — Mario Lévesque wants the Quebec government to pay him to not drill for oil and gas. Lévesque’s company, Utica Resources, holds 33 exploration licences covering over 5,000 square kilometres of Quebec heartland. Were it up to him, he would be drilling roughly 1,500 metres into the ground to obtain his piece of the estimated 31 trillion cubic feet of recoverable natural gas in Quebec’s portion of the Utica Shale, the same formation from which Pennsylvania and Ohio have wrung riches over the last decade. But it isn’t up to him. Last month, Quebec Premier François Legault announced that the government was effectively banning hydrocarbon extraction in the province. The decision, which Legault said was part of the government’s plan to hit its emissions-reduction targets, effectively killed Utica Resources’ raison d’être . So Lévesque wants compensation for Utica and the other nine licence-holding companies in the province. The starting bid: “significantly more” than the $3 billion to $5 billion floated by the province’s energy association, Lévesque told me the other day. It’s an often-overlooked expense in the push to decarbonize the economy. As countries around the world make it more difficult to find, extract and transport hydrocarbons, the companies that make it their business to do so are demanding billions in compensation. These cases almost invariably end up in court or in trade arbitration, and are potentially very expensive. Consider Calgary-based TC Energy’s Keystone XL Pipeline extension, the proposed conduit for 830,000 daily barrels of oil from Alberta to Nebraska. Presented in 2008, the pipeline extension was rejected in 2015 by the Obama administration, only to have Trump sign it back to life in 2017. Revoking the Keystone permit was among Joe Biden’s first presidential acts. That penstroke, which delighted environmentalists on both sides of the border, could be costly. TC Energy filed a formal request for arbitration last week, seeking over US$15 billion in damages as a result of what it says is a U.S. government breach of North American trade regulations. Meanwhile, four companies are suing European governments under the Energy Charter Treaty, an international agreement governing energy security among its 53 signatories. All told, the four companies are seeking just over US$3.1 billion for instituting laws that protect the environment but damage their bottom lines. The various complaints and lawsuits underscore the fossil fuel industry’s more muscular approach to selling its wares. After decades of trying to be as green as possible—and weathering the resulting accusations of greenwashing—many in the industry are pushing back. Earlier this month, Scott Sheffield, CEO of Texas-based Pioneer Natural Resources, publicly rebuked the Biden administration for its legislative attempts to wean the U.S. off fossil fuels.

‘Pipelines will be blown up,’ says David Suzuki, if leaders don’t act on climate change -- David Suzuki, the godfather of the Canadian environmental movement, warned over the weekend that if politicians don’t act to reverse climate change, there could be attacks against oil and gas infrastructure.“We’re in deep, deep doo-doo,” said Suzuki Saturday, speaking at an Extinction Rebellion protest on Vancouver Island. “This is what we’re come to. The next stage after this, there are going to be pipelines blown up if our leaders don’t pay attention to what’s going on.”Suzuki, reached by the National Post on Monday, said violence within the environmental movement is already happening, although he identified police actions against anti-logging protesters and anti-gas pipeline protesters as the culprits.Asked whether or not he would support the bombing of pipelines, Suzuki said, “Of course not.”“The violence is coming from the authorities, from government, from the RCMP,” said Suzuki. “They’re declaring war against those that are protesting.”Still, Suzuki warned he feels that there are few remaining options for protesters who feel government isn’t moving rapidly enough to tackle climate change. What else is there but violence, he wondered.“I think it’s going to be threatened by groups that feel government isn’t going anything,” Suzuki said.It wouldn’t be unprecedented. In Alberta, in the 1990s, Wiebo Ludwig, who died in 2012, engaged in a running war with the oil and gas sector in northwestern Alberta. He was convicted in 2000 for bombing a Suncor well in 1998, though Ludwig maintained his innocence.“If the oil companies run roughshod over your lives, you have to take defensive action against them, whatever is necessary,” Ludwig said in 1997, after two wells near his home were blown up. “You can’t just let them kill your children.”Alberta Premier Jason Kenney called for Suzuki’s comments to be universally condemned.“This incitement to violence by David Suzuki is dangerous,” he wrote in a tweet on Monday. “In Canada we resolve our differences peacefully and democratically, not with threats of terrorism or acts of violence.”

Canadian Radical Threatens to Blow Up Oil & Gas Pipelines - Leftists are not only anti-fossil fuels and anti-freedom, they’re also (when they eventually don’t convince others with their inane arguments) violent. Case in point: David Suzuki, the so-called godfather of the Canadian environmental movement, warned over the weekend that if politicians don’t act to reverse climate change, there could be attacks against oil and gas infrastructure. He flat-out threatened to blow up pipelines. Why is this man not in jail? Making threats against major infrastructure here in the United States will earn you a quick trip to the clink where you can reconsider your threats against your fellow humans. But apparently not in Canada, where such talk earns you kudos.

Canada's Ambitious New Plan To Save Its Oil Sands -In Canada, a renewable energy trend could lend itself to the oil and gas industry, with the potential for geothermal energy to help oil sands to thrive for another 30 years. Ongoing feasibility studies could provide a way for Canada to reduce its carbon emissions in line with Paris Agreement and COP26 expectations without curbing its oil production.Canada’s Oil Sands Innovation Alliance (COSIA) has partnered with Eavor Technologies Inc. and C-FER Technologies to conduct an assessment on the potential for using geothermal energy rather than natural gas to heat water for mining, set to be complete by early 2022. The project was established to curb greenhouse gas emissions in oil production while demand for the energy source is still high. This could be just what Canada’s oil industry needed, as oil sands typically require greater energy in the mining process due to the viscous nature of the substance, often leading to the release of higher levels of greenhouse gasses. The difficult extraction method means production often creates three to five times as many CO2 emissions per barrel of oil equivalent than other crudes. C-FER Technologies and COSIA previously carried out an assessment with promising results, hoping a second study will scale the project to the commercial level. The preliminary study suggests it is possible to use Enhanced Geothermal Systems (EGS), through C-FER’s Eavor-Loop™, in oil sands extraction. The technology collects heat from below the earth’s surface using deep a subsurface heat exchanger, or radiator. C-FER believes it offers the potential to reduce greenhouse gas emissions by 60 kilotonnes of CO2over a project lifecycle of three decades. Robert Mugo, Director of Greenhouse Gases at COSIA, stated of the project, “this is an exciting step forward in the potential application of this clean energy solution and one of several avenues of innovation that COSIA and its members are pursuing to support the sustainable development of the oil sands through reducing emissions.”

Scoop: Germany urges Congress not to sanction Putin’s pipeline -The German government has urged members of Congress not to sanction the Nord Stream 2 pipeline, arguing that doing so will "weaken" U.S. credibility and "ultimately damage transatlantic unity," according to documents obtained by Axios.: At a time when roughly 100,000 Russian troops are massing at its border, Ukraine views Nord Stream 2 as an existential threat to its security. The pipeline would circumvent Ukrainian transit infrastructure and deliver Russian gas directly to Germany, eliminating one of the last deterrents Ukraine has against an invasion. : President Biden says he opposes the pipeline, but waived sanctions this spring in order to avoid alienating a key U.S. ally over a project that was already close to completion.Biden and German Chancellor Angela Merkel struck a deal in July in which Germany agreed to take action — including pushing for sanctions at the EU level — if Russia "used energy as a weapon" against Ukraine and Europe. Some experts say that's already happening, as Russia has stoked Europe's energy crisis and suggested that soaring gas prices could be alleviated by expediting Nord Stream 2's certification. Dissatisfied Senate Republicans are now pushing for new sanctions as an amendment to the annual must-pass defense bill, with a vote possible as soon as this week. In an attempt to reassure Congress, the German embassy in Washington privately detailed what retaliatory action against Russia could look like in a "non-paper," which is typically used in closed discussions to convey candid policy positions.A Nov. 19 document marked as "classified" outlines steps Germany would take at the national level, including "strong public messages" condemning Russia's behavior; "assessing" the suspension of future political meetings; and reviewing "possible" restrictions on future Russian fossil fuel projects — not including Nord Stream 2. At the EU level, the document says Germany is "actively participating in the process to identify options for additional restrictive measures," without going into further details. The paper claims that Nord Stream 2 currently presents "no threat to Ukraine as long as reasonable gas transit is ensured," and refers to potential sanctions on the pipeline as "a victory for Putin" because it would divide Western allies. The paper is intended to show how serious Germany is about its commitments in the July joint statement, which the Biden administration has held up as the basis for waiving sanctions. But it will do little to satisfy Ukraine or Nord Stream's critics on Capitol Hill.: "Our approach is about far more than alliance maintenance; it's about doing what will be most effective to protect and preserve Ukraine's energy security," a senior State Department official told Axios.

IEA boss blames “deliberate policies” of energy producers for price spikes - Energy producers — not the transition to a greener economy — are a key reason for soaring natural gas and power prices in Europe, according to International Energy Agency Executive Director Fatih Birol. The price spike is the result of factors including demand growth, supply outages and extreme-weather events, “but also — I want to underline this — some of the deliberate policies of energy producers,” Birol said at the European Hydrogen Week conference in Brussels. He didn’t name specific producers. Birol’s comments come as colder weather threatens to exacerbate a natural gas supply crunch that has pushed prices to record levels in recent months. Europe’s storage sites are seasonally low, and primary supplier Russia has signaled that it has little appetite to boost gas flows to the continent. At the same time, competition for liquefied natural gas is tight due to demand from Asia. Earlier this month, Belarus threatened to shut a key pipeline carrying Russian gas to the European Union amid a dispute over migration. In September, a group of EU lawmakers urged the European Commission to investigate the role of Gazprom PJSC in the increase in gas prices. Meanwhile, Nord Stream 2, a gas pipeline project linking Russia to Germany, remains mired in the approval process amid the prospect of U.S. sanctions. Qatar, a major gas exporter, says it’s producing what it can. The energy crunch comes as the EU attempts to shift its economy away from a reliance on fossil fuels in a bid to become the first climate-neutral continent by the middle of the century. A legislative package that would slash emissions still has to be approved by member states. Some countries have warned the pace of transition could leave the continent more exposed to price spikes. Birol said it’s “wrong” to say that high prices are the result of the clean-energy transition. The IEA leader added that the policies of some producing countries don’t make sense, given that gas has been touted as a fuel to help smooth any potential price hiccups during the transition. He warned that if the problem isn’t addressed and evaluated in the right way, it could become a barrier for further climate policies. “The recent price spikes in natural gas did not get good marks from millions of consumers around the world, including Europe,” Birol said. “I am not sure the current gas prices are in the benefit of the gas producers.”

Activists Make Last-Minute Bid to Stop Shell From Blasting for Oil in Whale Breeding Grounds --Activists have made a last-minute bid to stop Royal Dutch Shell from exploring for oil and gas in whalebreeding grounds off the coast of South Africa.The fossil-fuel giant had planned to search for oil and gas reserves by setting off underwater explosions along a stretch of South Africa known as the Wild Coast, according to MSN. The explorations were slated to begin December 1. However, four environmental and human rights organizations filed a legal challenge Monday night to stop the blasting, Greenpeace Africa said.“Shell’s activities threaten to destroy the Wild Coast and the lives of the people living there,” Greenpeace Africa senior climate campaigner Happy Khambule said in a statement about the challenge. “We know that Shell is a climate criminal, destroying people’s lives and the planet for profit.”The Wild Coast stretches along South Africa’s Eastern Cape from Morgan Bay in the south and Port St Johns, according to MSN. It is rich in biodiversity and an important habitat for marine life.“To give you an idea about the Wild Coast, where my family come from, it is the most incredibly breathtaking place one could ever dream of,” concerned citizen Tracy Carter told MSN. “The ocean is lush and abundant with sea life in all shapes and sizes.”The testing was also slated to begin when Southern right and humpback whales are migrating back from South Africa to Antarctica after the breeding period, and the testing could injure or kill the traveling families.The exploratory plans were first approved in 2014, before the country passed its One Environmental Systemlegislation to coordinate mining and environmental regulations, The Guardian reported.The environmental groups behind the court case — Border Deep Sea Angling Association, Kei Mouth Ski Boat Club, Natural Justice and Greenpeace Africa — argue that the exploration is illegal because Shell has not applied for the necessary permit under the National Environmental Management Act (NEMA). They say that the seismic testing would mean that a vessel would fire air guns every 10 seconds for five months. The shock waves would reverberate through three kilometers (approximately 1.9 miles) of water and 40 kilometers (approximately 25 miles) below the seabed into the earth’s crust. This would harm whales, dolphins, sharks, seals, penguins and smaller animals like crabs. It would also have a negative impact on the human communities of eXolobeni, Nqamakwe and Port Saint Johns, who consider the land sacred and rely on eco-tourism and fishing for their livelihoods.

Guyana To Become The 11th Country To Produce Over 1 Million Bpd -The tiny South American nation of Guyana has emerged as the hottest offshore drilling location on the continent over the last six years. The swathe of oil discoveries made byExxonMobil and its partners, Hess and CNOOC, in the offshore Stabroek Block, since 2015, recently saw the energy supermajor upgrade its resources estimate for the block from 9 billion to 10 billion barrels of oil equivalent. The energy supermajor’s success in offshore Guyana sees it forecasting that it will be pumping over 800,000 barrels of light (32° API gravity) sweet (0.58% sulfur content) crude oil per day by 2026. There are signs that Guyana’s oil boom is gaining greater momentum with other international energy companies expressing interest in developing operations in the country. This comes at a time when considerable headwinds regarding the outlook for crude oil exist, including the demand threats posed by the COVID-19 pandemic, the looming arrival of peak oil demand and growing climate change pressures. Despite the risks, Guyana is an attractive jurisdiction for energy companies to operate in because of high-quality crude oil, low breakeven prices and a favorable regulatory environment. The Stabroek Block consortium, led by Exxon, was able to secure a production sharing agreement with Georgetown that has an incredibly low royalty rate of a mere 2%, far lower than any other jurisdiction in South America. Guyana’s government is also on the hook to reimburse the consortium for all development costs, operating expenses, estimated abandonment costs and interest expenses. That is a very lucrative deal for Exxon, Hess and CNOOC, with it expected to be a major contributor to earnings for those energy companies as production in the Stabroek Block ramps up, to 1 million barrels per day or more before the end of the decade.

Egyptian gas should start flowing to Lebanon in the next 3 months, U.S. energy envoy says - Natural gas from Egypt may start flowing to Lebanon within two or three months, and hopefully "long before" the country's elections in 2022, according to Amos Hochstein, the U.S. State Department's senior advisor for global energy security.The governments of four countries in September reached an agreement to pipe gas from Egypt, through Jordan and Syria, to ease the power crisis in Lebanon.At the time, Egypt's Petroleum Minister Tarek El-Molla said the plan, which is backed by the U.S., would be put into action at the "earliest opportunity,"Reuters reported.Hochstein said there is still work to be done before the pipeline is ready, but said he is confident that the plan, as well as an effort to interconnect Jordan and Lebanon's power grids, will succeed."Every week that goes by, I am more optimistic that we're going to be in a position to have the gas flowing, the energy interconnected in the coming couple of two, three months," he told CNBC's Hadley Gamble on Monday.Asked if that could happen before Lebanon's elections, which are scheduled to take place in March 2022, he said he is "quite hopeful [that] at least the gas deal would work, and would have gas flowing long before that."

OPEC to decide on oil output policy as omicron Covid variant rattles markets A group of some of the world's most powerful oil producers is meeting Wednesday to discuss how much of an impact the new omicron Covid variant is likely to have on energy demand. Led by Saudi Arabia, the Organization of the Petroleum Exporting Countries is scheduled to meet via videoconference from 1 p.m. London time. The 13-member group will be joined by non-OPEC allies such as Russia on Thursday. There is little sign the broader group, often referred to as OPEC+, intends to change course from its current output plan of a monthly hike of 400,000 barrels per day. OPEC ministers representing Saudi Arabia and Iraq have both indicated the group is likely to sustain this output policy, while non-OPEC leader Russia said earlier this week that there would be no need for urgent action on the oil market. Some analysts have questioned whether OPEC+ may be tempted to take a pause to assess the market, however, citing heightened price volatility and fears over the potential hit to energy demand because of the omicron variant. Indeed, it is thought some OPEC+ producers may struggle to meet their quota next month if the group does push ahead with an output hike. A Reuters survey published on Tuesday found OPEC pumped 27.74 million barrels per day in November, up 220,000 barrels from October, but that was below the 254,000 increase allowed for OPEC members under the OPEC+ agreement. International benchmark Brent crude futures traded at $72.62 on Wednesday afternoon in London, up over 4.8% for the session, while U.S. West Texas Intermediate futures stood at $69.24, around 4.6% higher. Oil prices have whipsawed in recent days. Both Brent and WTI futures contracts are on track to register their steepest monthly falls in percentage terms since March last year, Reuters reported, down 16% and 21%, respectively. Brennock said OPEC had several issues to discuss this week, including the potential impact of the omicron variant on future demand, the U.S.-led release of strategic reserves from oil-importing nations and Iran's possible re-entry into the oil markets.

Biden’s Blunder Could Send Oil Prices To $100 - When President Biden announced earlier last week that the federal government would be releasing 50 million barrels of crude from the strategic petroleum reserve, perhaps those around him expected prices to go down significantly and stay down. Instead, prices rose, and OPEC+ gave a heavy hint it might cut supply. By Friday, oil prices fell sharply, but that was due to a new wave of Covid-19 fears and has little if anything to do with Biden's announcement that oil would be unleashed from emergency stockpiles. But what comes next could send oil to $100.Energy analysts warned that a release of SPR may not have the desired effect. They explained that however many barrels the U.S. or its partners in Asia and the UK release, OPEC could withhold more and for longer. They explained that the SPR crude is sour, and refiners don't like it because it needs additional processing to reduce the sulfur content—a process that requires natural gas, which is also expensive currently. These explanations fell on deaf but determined ears. Now, analysts are warning about $100 Brent."It's not going to work simply because the strategic petroleum reserve — any country's strategic petroleum reserve is not there to try to manipulate price," said Stephen Schork, editor of the Schork Report, speaking to CNBC earlier this week. "There's a considerable amount of bets out there that we will see $100 a barrel oil," he added.John Kilduff of Again Capital put it even more bluntly: "The battle lines are being drawn," hetold Bloomberg this week. "Certainly, OPEC and the Saudis can win this in that they are holding all the cards. They can keep more oil off the market than a SPR release can put on the market. If you see WTI get under $70, then I would expect a response from OPEC+."What's more, the planned release of these 50 million barrels will not happen overnight. It won't happen over a week, either. In fact, the plan is, per an Argus report, to offer long-term loans of up to 32 million barrels of crude from the SPR—sour crude, at that—and to sell another 18 million barrels over several months. For starters, there is no guarantee about the degree of uptake of the oil loans. For seconds, 18 million barrels over a few months amounts to less than 1 million barrels per day on average.

Oil jumps, recouping some losses following worst day of the year - Oil prices jumped Monday as traders bet that Friday's sharp sell-off, prompted by fears that the new omicron Covid variant will curb demand for petroleum products, was overdone. West Texas Intermediate crude futures, the U.S. oil benchmark, gained $1.80, or 2.6%, to settle at $69.95 per barrel. Earlier in the session it traded as high as $72.93, although the contract drifted lower throughout the session and was unable to hold the key $70 level. WTI tumbled 13% on Friday for its worst day since April 2020. It also closed below its 200-day moving average — a closely followed technical indicator — for the first time since November 2020. Brent crude, the international oil benchmark, settled 0.99% higher at $73.44 per barrel. The contract declined 11.55% on Friday, and along with WTI registered a fifth straight week of losses. "Friday's price slide was excessive," said analysts at Commerzbank. "Admittedly, the omicron variant is fueling concerns about demand, but it is not yet possible to put any serious figure on what effect this will genuinely have on demand." Even before Friday's sharp drop oil had been trending lower after WTI hit a seven-year high above $85 in October. Brent crude hit a three-year high last month. Given oil's strong 2021 rebound, analysts at RBC added that some of Friday's sell-off can be attributed to traders locking in profits. "At least part of the air pocket lower on Friday was a function of winding down risk, potentially for the year," the firm said Sunday in a note to clients. "Following a strong 11 months of pricing, oil traders would rather de-risk and protect the nest egg, than fight the tide of market moving events like COVID for another month into year-end." Oil's seesaw moves come ahead of a key meeting between OPEC and its oil-producing allies, where the group will decide on production policy for January. The alliance, known as OPEC+, has been returning 400,000 barrels per day to the market each month as it unwinds the historic production cuts it implemented in April 2020 as the pandemic sapped demand for petroleum products. In addition to the latest price action, the group will be evaluating the supply and demand trajectory after the U.S. and other nations last week announced plans to tap the Strategic Petroleum Reserve in an effort to curb the rapid rise in fuel costs. The Biden administration said that the U.S. would release 50 million barrels from the SPR.

Oil Futures Down Tuesday Morning-- Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange resumed losses Tuesday, sending the U.S. and international benchmarks down as much as 3% in early morning trade as investors re-assess risks of the highly-mutated strain of the coronavirus, omicron, after Moderna's CEO said COVID-19 vaccines were unlikely to be as affective against the new variant as they were against delta, raising concerns over deeper travel controls and delayed demand recovery.When asked about the efficacy of COVID-19 vaccines against the new variant, Moderna CEO Stephane Bancel said in an interview published this morning, "I think it's going to be a material drop. We just don't know how much yet. Every scientist I spoke to told me it's not going to be good." He also added that it might take months to develop a new vaccine, scale up production and redistribute it. The comments sent global markets back in retreat, with Dow Jones Industrial futures falling as much as 350 points, Treasury bond yields tumbling and U.S. oil benchmarks sliding below $67 per barrel (bbl), down more than $3 bbl in overnight trade. Early assessment of omicron symptoms showed a rather mild illness that could be easily treated at home, but a lot is still unknown about the virus. There is little or no data available whether any omicron patients have been vaccinated or previously infected with another variant of COVID-19. Scientists also don't know how deadly omicron may be among more vulnerable populations. Dutch health authorities announced Tuesday morning that the omicron variant was detected in the country well before flights from South Africa were grounded this weekend, raising the alarm that omicron might have circulated around the world earlier than initially thought. The U.S., UK and several other nations have imposed travel bans on South Africa and neighboring countries associated with the latest COVID variant, dealing a further blow to air travel at the time when fears of winter resurgence in Northern Hemisphere were already rising. Japan on Monday (11/29) followed Israel in shutting its borders completely to foreigners for at least a month, just weeks after it eased entry rules to the country. President Joe Biden, however, ruled out any return to the lockdowns for the U.S. Against this backdrop, OPEC+ ministers postponed their monthly meeting until Thursday (12/2) to assess the impact of tougher travel restrictions on global demand growth. Renewed COVID controls could alter the group's output, which was jointly expected to bring back next month 400,000 barrels per day (bpd) of their record 9.7 million bpd cuts introduced at the beginning of the pandemic. OPEC+ still has about 3.8 million bpd of these cuts in place and some analysts suggest that should the coalition choose to support prices against the threat of the emerging variant, it might forgo planned increases until February, buying more time for the market to recover.

Oil prices fall nearly 5 pct on jitters over vaccine efficacy -Oil prices tumbled nearly 5 percent on Tuesday after Moderna’s chief cast doubt on the efficacy of COVID-19 vaccines against the Omicron coronavirus variant, spooking financial markets and adding to worries about oil demand. The head of drugmaker Moderna told the Financial Times that COVID-19 vaccines are unlikely to be as effective against the Omicron variant of the coronavirus as they have been against the Delta variant. Brent crude futures fell $2.76, or 3.76 percent, to $70.68 a barrel at 1338 GMT after slipping to an intraday low of $70.22, their lowest since late August. US West Texas Intermediate (WTI) crude futures fell $2.86, or 4 percent, close to $67 a barrel, after falling to a session low of $66.51. Fed Chairman Jerome Powell will also tell US lawmakers later in the day the variant could imperil economic recovery, prepared remarks show. “The economic impact is driven by fear, and by the policy response... Fear is impacting travel. There are outright bans. But also the fear of being stranded which causes travel plans to alter,” Paul Donovan from UBS said in a note. Oil plunged around 12 percent on Friday along with other markets on fears the heavily mutated Omicron would spark fresh lockdowns and dent global oil demand. It is still unclear how severe the new variant is. With a weakening demand outlook , expectations are growing that the Organization of the Petroleum Exporting countries, Russia and their allies, together called OPEC+, will put on hold plans to add 400,000 barrels per day (bpd) to supply in January. . Pressure was already growing within OPEC+, due to meet on Dec. 2, to reconsider its supply plan after last week’s release of emergency crude reserves by the United States and other major oil-consuming nations to address soaring prices. “Following the global strategic reserve releases and the announcement of dozens of countries restricting travel... OPEC and its allies can easily justify an output halt or even a slight cut,”

Oil Slumps on Omicron Fears; Posts Biggest Monthly Fall in 20 Months -- Crude futures ended November with their biggest monthly declines since the outset of the pandemic, as the new variant, along with expectations that coming emergency reserve releases will juice growing supply, has cut the legs out of the market's year-long rally. The head of drugmaker Moderna Inc told the Financial Times that COVID-19 vaccines are unlikely to be as effective against the Omicron variant of the coronavirus as they have been against the Delta variant. Brent crude futures fell $2.87, or 3.9%, to settle at $70.57 a barrel, after hitting an intraday low of $70.22, lowest since August. U.S. West Texas Intermediate (WTI) crude futures ended $3.77, or 5.4%, lower at $66.18 a barrel. The benchmark dropped to a session low of $64.43, also its lowest since August. WTI edged up in post-settlement trade to $66.74, after industry data showed a smaller U.S. crude stock drawdown than the 1.2 million barrels forecast in a Reuters poll. Stocks fell 747,000 barrels last week, according to market sources citing American Petroleum Institute figures. Government data will be released on Wednesday. For November, Brent fell by 16.4%, while WTI fell 20.8%, the biggest monthly fall since March 2020. Also pressuring prices, Federal Reserve Chair Jerome Powell said the U.S. central bank likely will discuss speeding its reduction of large-scale bond purchases at its next policy meeting, amid a strong economy and expectations that a surge in inflation will persist into the middle of next year. Activity in later-dated futures contracts shows that the market is becoming less worried about demand outstripping supply in the short term, and of oversupply in the first half of next year. The premium on Brent and U.S. crude contracts expiring in one month versus those expiring in six months has narrowed to its lowest levels since March. This metric is closely watched by traders as an indicator for future supply; the higher the cost of the near-dated contract, the more worries there are about a coming supply deficit. Brent's six-month backwardation narrowed to around $1.50 per barrel, the lowest since March. WTI's six-month backwardation fell to about $1.90 per barrel, its lowest since September. That reduced premium indicates less worry about future supply and current levels of demand. It is unclear if the Organization of the Petroleum Exporting countries and their allies, together called OPEC+, will put on hold plans to add 400,000 barrels per day (bpd) to supply in January. The group was already weighing the effects of last week's announcement by the United States and other countries to release emergency crude reserves to temper energy prices.

Oil Prices Jump More Than 4% Ahead Of OPEC+ Meeting Oil prices are up sharply as ministers of the Organization of Petroleum Exporting Countries (OPEC) prepare to meet amid ongoing market volatility.Prices for West Texas Intermediate (WTI) crude oil rallied as much as 4.6% after losing almost $4 U.S. a barrel yesterday (November 30). That selloff was driven by escalating concerns over the impact on demand of the Omicron variant of COVID-19 and prospects for a faster tapering of stimulus by the U.S. Federal Reserve.The focus now shifts to the reaction from producers. OPEC and its allies (OPEC+) meet over the next few days (December 1-2) to set output policy, with some analysts expecting the group to pause supply hikes.The U.S. frustrated OPEC+ last week by announcing a release from its strategic oil reserves, although America has since moved to cool tensions with Saudi Arabia.WTI for January rose 4.2% to $68.93 U.S. a barrel in London trading. Brent crude oil for February settlement climbed 4.5% to $72.31 U.S. a barrel.Oil's volatility has spiked, with WTI closing down 13% at the end of last week before climbing on Monday and slumping again on Tuesday of this week. Gauges of swings in both WTI and Brent crude oil are at their highest level since May 2020.

WTI Slips After US Crude Production Rise, Big Product Inventory Builds -After yesterday's plunge, crude prices rebounded overnight after a modest API draw, helped by a Goldman report putting the plunge in context as being dramatically overdone. OPEC+ uncertainty is weighing on prices this morning however ahead of today's official inventory/production data.OPEC+ has “erred on the side of caution since it began slowly boosting supplies,” said Stephen Brennock, an analyst at PVM Oil Associates.A potential decision to shelve January’s planned increase and keep quotas flat “comports with its cautious approach.”While OPEC+ and the omicron variant dominating the market, there is also another wildcard in the background - the Iranian nuclear deal. Diplomats are working on a draft agreement, state-run Press TV reported, but there was little sign of an imminent deal after talks resumed on Monday. DOE:

• Crude -909k (-1.45mm exp, -700k API)
• Cushing +1.159mm
• Gasoline +4.059mm - biggest build since June
• Distillates +2.16mm - biggest build since July

A smaller than expected crude draw and major product builds are not what the bullsih doctor ordered...Cushing stocks continue to hover near multi-year lows (anything below 30m bbls is considered significantly low) but rose for the 3rd straight week (the longest streak since August)...

Oil Futures Pare Gains as Products Build, Output Rises -- Crude and refined product futures on the New York Mercantile Exchange pared a portion of overnight gains late morning Wednesday after an inventory report from the Energy Information Administration showed domestic crude oil production jumped to an 18-month high at 11.6 million barrels per day (bpd) last week and, despite refinery runs rising by a smaller-than-expected margin, nationwide gasoline and distillate fuels supplies registered large builds.Offsetting bearish parts of the reports, U.S. crude oil inventories decreased by 909,000 barrels (bbl) from the previous week to 433.1 million bbl compared with expectations for stocks to have added 800,000 bbl. The draw was realized even as domestic refiners raised run rates by a modest 0.2% to 88.8%, missing market expectations for a 0.6% increase. U.S. producers, meanwhile, raised production by 100,000 bpd to 11.6 million bbl -- the highest weekly output rate since April 2020 when the coronavirus pandemic reigned havoc on the domestic oil industry. U.S. oil production still stands 1.4 million bpd below its pre-pandemic peak of 13 million bpd. Oil stored at Cushing in Oklahoma, the delivery point for West Texas Intermediate futures, rose 1.2 million bbl from the previous week to 28.5 million bbl.The bearish parts of the report were found in in the fuels complex, showing demand for gasoline and distillates weakened during the Thanksgiving holiday week and stockpiles unexpectedly increased. Gasoline inventories jumped 4 million bbl to 215.4 million bbl compared with analyst expectations for inventories to have decreased 500,000 bbl. Gasoline supplied to the U.S. market, a measure of demand, declined 538,000 bpd last week to 8.796 million bpd, likely reflecting demand pulled forward during the previous week as suppliers staged product near retail centers.Distillate stocks, meanwhile, rose 2.2 million bbl to 123.9 million bbl last week, and are now about 9% below the five-year average, EIA said. Analysts expected distillate inventories would remain unchanged from the previous week. Distillate supplied to the U.S. market decreased by 182,000 bpd from the previous week to 4.209 million bpd. Distillate demand looks to have peaked for the fourth quarter, albeit at a far higher level than was seen both last year and in 2019.Total products supplied over the last four-week period averaged 20.7 million bpd, up 7.1% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.2 million bpd, up 10.6% from the same period last year. Distillate fuel product supplied averaged 4.3 million bpd over the past four weeks, up 6.1% from the same period last year. Jet fuel product supplied was up 34.5% compared with the same four-week period last year.

Oil Rebounds on OPEC, Only to Drop Back on 1st US Omicron Case - Oil prices recovered from 3-month lows on Wednesday in anticipation of supportive action from OPEC, before closing lower for a fifth time in six days after the United States announced its first Omicron case of Covid.WTI, or the West Texas Intermediate benchmark for U.S. crude settled down 61 cents, or almost 1%, at $65.57 per barrel, after rebounding to $69.49 earlier in the session. WTI has lost almost 17% since its last positive close of $78.50 on Nov. 23. It is also down more than 23% from the seven-year high of $85.41 notched in mid-October.London-traded Brent crude, the global benchmark for oil, settled down 36 cents, or 0.5%, at $68.87. Brent has lost 16% since its last positive close of $82.31 a week ago. It is also down 21% from its seven-year high of $86.70 attained in mid-October. “There’re still lots of moving parts to this Omicron thing, but I imagine that will be the first target for WTI before we try to take out $60.”The US individual infected with the latest-discovered variant of Covid is a California resident who had traveled home from South Africa on Nov. 22, top U.S. virologist Dr. Anthony Fauci told a news conference. The person was fully vaccinated, has mild symptoms and is self-quarantining.The news dragged down crude prices, already weighed by unsupportive weekly supply-demand inventory data released by the Energy Information Administration.The 13-member OPEC, or Organization of the Petroleum Exporting Countries, led by Saudi Arabia met on Wednesday before a larger summit due on Thursday with 10 other oil producers steered by Russia. OPEC did not divulge any production plans on Wednesday, meaning that it could be up to the 23-nation OPEC+ alliance to decide how producers react to what could be the second biggest crisis in oil demand since the onset of the first Covid outbreak 20 months ago.

OPEC+ to hike January output as planned, but meeting is ongoing -- OPEC and non-OPEC oil producers, an influential group known as OPEC+, decided on Thursday to stick to a previously agreed upon plan of hiking output by 400,000 barrels per day in January. However the alliance said in a statement that "the meeting remains in session," meaning they can "make immediate adjustments" should the current market conditions shift.In what was a hotly anticipated meeting, the energy alliance convened via videoconference to determine whether to stick with its plan to release more oil into the market or to restrain supply amid fears over the omicron Covid-19 variant. Other issues on the table included a U.S.-led release of strategic reserves from crude-importing nations and Iran's possible re-entry into oil markets.Oil clawed back early losses to trade in the green following the announcement, which some believed was already priced into the market.International benchmark Brent crude futures advanced 1.1% to $69.95 per barrel, while U.S. West Texas Intermediate futures stood at $66.43 per barrel, for a gain of 1.3%.Energy analysts broadly had expected OPEC+ to push ahead with its current plan to hike monthly output by 400,000 barrels per day. However, some had questioned whether the group may be tempted to take a pause to assess the market following a period of heightened price volatility."We think OPEC+ are likely to maintain that momentum in releasing additional oil," Alex Booth, head of research at Kpler, told CNBC's "Squawk Box Europe" on Thursday."Let's not forget, we're talking about additional oil in January, the decision for December has basically already been made."

Oil Futures Whipsaw After OPEC+ Proceeds With Output Hike - After sideways trade for most of the session Thursday, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled higher. Investors reassessed near-term supply fundamentals after OPEC+ unexpectedly decided to proceed with a 400,000-barrel-per-day (bpd) production increase next month in a move that will likely exacerbate a buildup in global oil inventories early next year but reduce the cartel's own spare capacity faster than estimated.OPEC+ Ministerial Committee Meeting concluded Thursday with a surprise decision to keep production quotas intact despite growing concerns over the rapid spread of the omicron COVID variant and signs of rapidly building global oil inventories. The group's technical panel estimated oil market is rapidly moving into oversupply, with gains in production seen outpacing demand by 2 million bpd next month and widening further to 3.4 million bpd in February. In March, OPEC+ expects surplus on the global market to reach a whopping 3.8 million bpd.Making matters worse, the new COVID-19 variant has upended international air travel this week, triggering renewed quarantine controls and curbs on economic activity. Germany banned all unvaccinated people on Thursday from entering bars and restaurants and the United States tightened testing requirements on all international travelers entering the country. Japan and Israel have suspended all inbound flights for December.Against this backdrop, traders upped their bets that OPEC+ would forgo a planned production increase until at least February to balance the market this winter. Analysts at JP Morgan estimated that a three-month pause of production increases is needed to reverse a restocking pattern in global inventories.The surprise decision, meanwhile, could be a strategy to reduce OPEC+ spare capacity at a faster rate next year and to undermine investment in the U.S. shale industry. OPEC's "true" spare capacity next year is estimated at 2 million bpd or 43% below previously held consensus of 4.8 million bpd, according to JP Morgan. The cartel is already struggling to increase production in line with agreed quotas plagued by chronic underinvestment and political unrest in a number of African oil producing countries. A Reuters survey published on Tuesday found OPEC pumped 27.74 million bpd in November, up 220,000 bpd from October, but that was below the 254,000-bpd increase allowed for OPEC members under the OPEC+ agreement.

Oil rises as OPEC+ sticks to January output hike -- OPEC and non-OPEC oil producers, an influential group known as OPEC+, decided on Thursday to stick to a previously agreed upon plan of hiking output by 400,000 barrels per day in January.However the alliance said in a statement that "the meeting remains in session," meaning they can "make immediate adjustments" should the current market conditions shift.In what was a hotly anticipated meeting, the energy alliance convened via videoconference to determine whether to stick with its plan to release more oil into the market or to restrain supply amid fears over the omicron Covid-19 variant. Other issues on the table included a U.S.-led release of strategic reserves from crude-importing nations and Iran's possible re-entry into oil markets.Oil clawed back early losses to trade in the green following the announcement, which some believed was already priced into the market.International benchmark Brent crude futures rose 1.16%, or 80 cents, to end the day at $69.67 per barrel. U.S. West Texas Intermediate futures settled 1.4%, or 93 cents, higher at $66.50 per barrel. Energy analysts broadly had expected OPEC+ to push ahead with its current plan to hike monthly output by 400,000 barrels per day. However, some had questioned whether the group may be tempted to take a pause to assess the market following a period of heightened price volatility. "We think OPEC+ are likely to maintain that momentum in releasing additional oil," "Let's not forget, we're talking about additional oil in January, the decision for December has basically already been made." Brent crude futures have slumped more than $10 since last Thursday when the emergence of the omicron Covid variant became widely known. The World Health Organization has said it will take weeks to understand how the variant may affect diagnostics, therapeutics and vaccines.OPEC+ has an agreement in place to add 400,000 barrels a month to global supplies as it gradually reverses last year's record supply cuts of roughly 10 million barrels per day.OPEC kingpin Saudi Arabia has indicated the group is likely to sustain this output policy, while non-OPEC leader Russia said earlier this week that there would be no need for urgent action on the oil market.

Oil Jumps As OPEC+ Leaves The Door Open To Revisiting Supply Increase - Oil prices rose by 3% early on Friday, extending gains from late Thursday, after the OPEC+ alliance said it could immediately revisit the planned 400,000 bpd increase for January if demand suffers in coming weeks. As of 9:25 a.m. EST on Friday, WTI Crude was rallying 3.49% at $68.82 and Brent Crude was up 3.67% to $72.23. OPEC+ decided on Thursday to stick to its initial plans to add 400,000 barrels per day to its collective oil production each month, to the surprise of some analysts who had expected a pause in the monthly supply additions in light of an expected oversupply early next year, a potential impact of the Omicron variant, and SPR releases from several nations led by the United States. As early as the dust settled after the OPEC+ meeting, oil prices erased losses and bounced back on Thursday, after OPEC said that the group “agree that the meeting shall remain in session pending further developments of the pandemic and continue to monitor the market closely and make immediate adjustments if required.” Analysts interpreted the wording as OPEC+ leaving the door open to a flexible approach to production and the group potentially meeting before the next scheduled meeting on January 4 if signs emerge of a serious impact of the new COVID variant on oil demand. “The market appears to have taken comfort in the fact that OPEC+ is willing to reconvene and adjust production if necessary due to the Omicron variant,” “The decision by the group appears to be an attempt to buy themselves more time,” According to Saxo Bank, the market rallied after the meeting due to several reasons. These include the fact that traders have already priced in a significant and not yet realized drop in demand, the OPEC+ flexibility to make changes before January, the easing of the US-OPEC+ tensions, and the already months-long struggle of some OPEC+ members to pump to their quotas.

WTI, Brent Down 5% Week Over Week on Omicron Variant, Oversupply Risks -- Nearby delivery oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange settled Friday's session mostly lower, with both U.S. and international crude benchmarks registering steep weekly losses. The losses came amid a one-two punch with the winter season resurgence in COVID-19 infections across the Northern Hemisphere and concerns over the emergence of a highly mutated omicron variant of coronavirus, with both developments potentially derailing the recovery in global jet fuel demand. Additionally, the Organization of the Petroleum Exporting Countries and Russia-led partners decided this week to release more supplies into the market early next year despite clear signals of near-term demand weakness. OPEC+'s technical panel estimated oil market is rapidly moving into oversupply next year, with gains in production seen outpacing demand by 2 million barrels per day (bpd) next month and widening further to 3.4 million bpd in February. In March, OPEC+ expects a surplus on the global market to reach a whopping 3.8 million bpd. Nevertheless, the group agreed Thursday, Dec. 2, to raise production quotas by 400,000 bpd as planned, shrugging off market jitters over the emergence of Omicron and U.S.-coordinated releases from strategic petroleum reserves in a handful of countries. OPEC+'s official communique said it stood ready to reconvene "pending further developments of the pandemic and continue to monitor the market closely and make immediate adjustments if required." Latest reports suggest Omicron is spreading twice as fast as other variants in the country of its origin. It remains unclear whether COVID-19 vaccines are as affective against this variant as they were with now dominant Delta strain. The consensus in the oil industry so far is that international air travel will feel an immediate impact from renewed travel controls imposed by the governments of European Union, United States, and Asia. After showing growth early in the fourth quarter, a long-awaited recovery in jet fuel demand has now been pushed further in 2022 as consumers begin to pull back on international air travel. As this pocket of demand evaporates, the oil market is left with a big hole that is seen rapidly expanding with more non-OPEC supplies hitting the market. S&P Platts Analytics estimates global oil demand would likely contract by a sharp 1.6 million bpd from the fourth quarter to the first quarter of 2022 on a combination of seasonal weakness and the winter resurgence of COVID-19 infections. Separately, U.S. Labor Department reported on Friday the economy added a disappointing 210,000 new jobs in November compared with expectations for at least 500,000 new positions opened. The unemployment rate, meanwhile, dropped more than expected to 4.2% from 4.6% -- the lowest level since the pandemic began. On the session, West Texas Intermediate January futures slipped $0.24 to settle at $66.26 per barrel (bbl) and the international benchmark ICE February Brent contract posted a gain of $0.21 for a $69.88-per-bbl settlement. NYMEX RBOB January futures moved down 1.48 cents to $1.9529 per gallon, and the front-month NYMEX ULSD contract weakened 0.5 cent to $2.0984 gallon.

Oil drops for sixth straight week as Omicron jolts markets Oil slid for a sixth straight week, marking the longest stretch of weekly declines since 2018, as the omicron variant jolts markets and OPEC+ continues to hike supply.West Texas Intermediate crude futures fell 2.8% this week. The spread of the omicron variant has investors concerned about any potential hit to demand as the U.S. reported at least six states with cases. Covid-19 infections in South Africa have almost quadrupled since Tuesday. Meanwhile, OPEC and its allies this week decided to add 400,000 barrels a day of crude to global markets in January, ultimately bowing to consumer pressure. “The short-term demand outlook was shaky at best and if the U.S. sees new restrictions, the oil market could see a supply surplus by the end of the month,”Crude has dropped sharply since late October amid moves by major consuming nations to tap their reserves and the emergence of the new virus variant. A more hawkish Federal Reserve was put in a tough spot Friday as U.S. jobs data missed expectations. Meanwhile, the sharp increase in volatility has oil traders heading for the exit, with open interest across the main oil futures contracts plunging to its lowest level in years.While OPEC+ decided to continuing supplying the market with barrels, the group essentially placed a floor under prices by giving itself the option to change the plan at short notice. Prior to this week’s meeting, ministers indicated they were concerned about the impact of omicron on crude demand but were struggling to figure out how serious the new strain would become. By effectively keeping its monthly meeting open, the alliance now has more flexibility to address price swings.West Texas Intermediate crude for January delivery slipped 24 cents to settle at $66.26 a barrel in New York Brent for February settlement rose 21 cents to settle at $69.88 a barrel Meanwhile, in Vienna, diplomats attempting to restore the nuclear deal between Iran and world powers face substantial challenges that need urgent solutions, the top European envoy said Friday. Talks are set to resume in the middle of next week.

The Inevitable Recovery Of Iran’s Oil Industry -Iran’s recent hydrocarbon agreement with Azerbaijan is the latest in a string of developments that demonstrate the country’s determination to overcome U.S. sanctions. Its plans to boost oil production to 5 million bpd and its improving trade relations with China suggest that Iran will not be back by Biden for much longer. Iran and Azerbaijan are expected to finalize a number of energy deals that would see joint development of a new oil field off the coast of Iran, adding to the energy cooperation between the two states. In 2018, the two countries signed a convention stating that resources from the Caspian sea would be shared with neighboring countries Kazakhstan, Russia, and Turkmenistan. Talks over a joint development between the two states are not uncommon, with previous discussions taking place in 2018 but resulting in no action. Few details have been released about the most recent talks, meaning nothing is official quite yet. Azerbaijan hopes to boost its gas production to 47.5 Bcm by 2025, as international demand for gas continues to rise, ensuring national energy security and the potential to export. Azerbaijan has already improved its connectivity to Europe with the opening of the Trans-Adriatic Pipeline (TAP) gas pipeline in December 2020, connecting it with Greece and Bulgaria. The country is now in talks with countries around Europe about increasing its gas exports as demand across the region rises. Iran, which saw an output of 2.52 million bpd of crude in October, is hoping to raise this production level even higher. Despite little progress with ongoing talks over a nuclear agreement with the U.S., Iran plans to continue increasing its oil production, aiming to reach an output of 5 million bpd, and hoping to produce 4 million bpd as soon as March 2022. The country’s oil minister, Javad Owji, stated that he was targeting $145 billion of foreign and domestic investment in the energy sector over the next eight years. Talks between the U.S. and Iran, with representatives from Iran, China, France, Germany, Russia, and the United Kingdom, resumed this week in Vienna following the sixth round of talks in June. However, Iran is adamant that if an agreement is reached, the U.S. must lift all sanctions imposed in 2018, while the U.S. would like to maintain certain sanctions around human rights and terrorism.Meanwhile, China is buying even more Iranian crude, opting for cheap prices even as U.S. sanctions on the oil-rich state hold strong. China continues to risk retaliation from the U.S. for breaking its sanction agreement on Iranian oil, importing over half a million bpd on average for the last three months, accounting for around 6 percent of China's crude oil imports. This figure could increase if Covid-19 restrictions ease across the country and demand for oil goes up.