oil prices rose for the first time in seven weeks as fears about the Omicron mutant's impact on fuel demand waned ...after falling 2.8% to $66.26 a barrel last week after OPEC decided to increase production even as the Omicron surge loomed, the contract price for US light sweet crude for January delivery opened more than 1% higher on Monday after Saudi Aramco raised its official January crude prices to Asia and to the United States for the second consecutive month, signaling a confidence in demand that led to a 5% rally in oil prices, as US crude closed $3.23 higher at $69.49 a barrel while concerns about the omicron variant of coronavirus eased on widespread reports that its effects were less severe than other strains of Covid....oil prices extended those gains into early trading on Tuesday as traders became cautiously optimistic that the new Omicron Covid variant would not lead to massive lockdowns such that would severely reduce oil demand, and continued higher throughout the session to settle $2.56 higher at $72.05 a barrel, as concerns about the impact of the Omicron variant on global fuel demand continued to ease further...oil held its gains in overnight trading after the API reported a larger than expected draw of crude and then rebounded from early lossses on Wednesday to close 31 cents higher at $72.36 a barrel as traders had a muted reaction to U.S. weekly inventory figures, which showed a smaller-than-anticipated decline in crude stocks and another bump up in overall production, giving credence to expectations that supply will increase in coming months. but instead focused on the resumption of talks between Washington and Tehran over Iran's nuclear program. which could lead to higher exports of Iranian oil, which could add downward pressure on oil prices...oil prices then moved lower Thursday following ratings downgrades to two Chinese property developers, and after some governments took measures to fight the Omicron variant, and settled down $1.42 at $70.94 a barrel, pressured by a stronger US dollar, as risk sentiment around the omicron variant and larger-than-expected increases refined fuel stockpiles turned sour....but oil prices moved back up in early trading Friday as traders awaited the release of US inflation data that could shed light on the direction of Federal Reserve monetary policy in the coming months. and settled 73 cents, or 1% higher at $71.67 a barrel after Pfizer said their booster shot would be effective against the variant, thus finishing with a gain of 8.2% on the week and posting their biggest weekly gain since late August, spurred by easing concerns over the omicron variant that appeared to be less lethal compared to the original strain of Covid-19...
on the other hand, natural gas prices finished lower for a second week as forecasts for sustained heating demand remained far off....after falling by a record 24% to $4.132 per mmBTU last week on a forecast for a warm December, which suggested gas supplies would be adequate for the rest of the winter, the contract price of natural gas for January delivery opened nearly 7% lower on Monday as record-high December temperatures were killing heating demand ahead of winter, and ultimately tumbled 47.5 cents to a fourth and a half month low of $3.657 per mmBTU as forecasts for warmer-than-usual temperatures through the third week of December soured the demand outlook... natural gas prices rebounded from those lows on Tuesday, following a 6% gain in European gas futures that was expected to keep U.S. liquefied natural gas exports at record highs, and settled 5.7 cents higher at $3.708 per mmBTU, and then extended that recovery into Wednesday to close 10.7 cents higher at $3.815 per mmBTU, as European prices continued to soar and the prospect of cooler weather brightened trader's outlook...natural gas prices drifted lower early Thursday as traders awaited the EIA inventory data that was expected to show a lighter-than-average weekly withdrawal of gas from storage. but recovered to close nearly unchanged at $3.814 per mmBTU as a bigger than expected storage withdrawal and hiked forecasts for U.S. demand over the next two weeks offset a 3% decline in European gas prices...natural gas prices then moved higher on Friday on forecasts for heating demand to rise in a couple of weeks with a seasonal cooling of the weather and settled 11.1 cents higher at $3.925 per mmBTU, but still ended 5.0% lower on the week...
The EIA's natural gas storage report for the week ending December 3rd indicated that the amount of working natural gas held in underground storage in the US fell by 59 billion cubic feet to 3,505 billion cubic feet by the end of the week, which left our gas supplies 356 billion cubic feet, or 9.2% below the 3,861 billion cubic feet that were in storage on December 3rd of last year, and 90 billion cubic feet, or 2.4% below the five-year average of 3,695 billion cubic feet of natural gas that have been in storage as of the 3rd of December over the most recent years...the 59 billion cubic foot withdrawal from US natural gas working storage this week was more than the average forecast for a 54 billion cubic foot withdrawal from a Reuters survey of analysts, and was nearly triple the 22 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2020, and was also well more than the average withdrawal of 45 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 December 3rd showed that despite a sizable decrease in our oil exports, we needed to pull oil out of our stored commercial crude supplies for the fourth time in eleven weeks and for the twenty-fourth time in the past thirty-six weeks….our imports of crude oil fell by an average of 105,000 barrels per day to an average of 6,499,000 barrels per day, after rising by an average of 168,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 434,000 barrels per day to an average of 2,270,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 4,229,000 barrels of per day during the week ending December 3rd, 329,000 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 11,700,000 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 15,929,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,785,000 barrels of crude per day during the week ending December 3rd, an average of 153,000 more barrels per day than the amount of oil that refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 276,000 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 420,000 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 (-420,000) 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....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 276,000 barrel per day net decrease in our crude oil inventories came as 34,000 barrels per day were pulled out of our commercially available stocks of crude oil, while 241,000 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 52,161,000 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 600,867,000 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 two weeks ago 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 6,432,000 barrels per day last week, which was 15.4% more than the 5,590,000 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 11,700,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at 11,200,000 barrels per day, while Alaska’s oil production to was unchanged at 454,000 barrels per day and added 500,000 barrels per day to the reported rounded national production total...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 10.7% below that of our pre-pandemic production peak, but 38.8% 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 89.8% of their capacity while using those 15,785,000 barrels of crude per day during the week ending December 3rd, up from 88.8% of capacity the prior week, but still a bit lower than normal utilization for early December refinery operations… the 15,785,000 barrels per day of oil that were refined this week were 9.3% more barrels than the 14,436,000 barrels of crude that were being processed daily during the pandemic impacted week ending December 4th of last year, but 4.9% less than the 16,597,000 barrels of crude that were being processed daily during the week ending December 6th, 2019, when US refineries were operating at what was then also a less than seasonal 90.6% of capacity...
Even with the increase in oil being refined this week, the gasoline output from our refineries was still a bit lower, decreasing by 86,000 barrels per day to 9,563,000 barrels per day during the week ending December 3rd, after our gasoline output had decreased by 450,000 barrels per day over the prior week.…this week’s gasoline production was still 14.7% more than the 8,340,000 barrels of gasoline that were being produced daily over the same week of last year, but 1.9% less than the gasoline production of 9,753,000 barrels per day during the week ending December 6th, 2019….on the other hand, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 45,000 barrels per day to 4,917,000 barrels per day, after our distillates output had increased by 88,000 barrels per day over the prior week…with that increase, our distillates output was 5.3% more than the 4,917,000 barrels of distillates that were being produced daily during the week ending December 4th, 2020, but still 5.9% less than the 5,228,000 barrels of distillates that were being produced daily during the week ending December 6th, 2019..
Even with the big drop in our gasoline production, our supplies of gasoline in storage at the end of the week rose for the second time in nine weeks, and for the fourteenth time in thirty-three weeks, increasing by 3,882,000 to 219,304,000 barrels during the week ending December 3rd, after our gasoline inventories had increased by 4,029,000 barrels over the prior week...our gasoline supplies increased again this week even though the amount of gasoline supplied to US users increased by 167,000 barrels per day to 8,963,000 barrels per day, and even as our imports of gasoline fell by 85,000 barrels per day to 558,000 barrels per day, while our exports of gasoline fell by 95,000 barrels per day to 792,000 barrels per day…and even after this week’s big inventory increase, our gasoline supplies were still 7.8% lower than last December 4th's gasoline inventories of 237,859,000 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 fourth time in fifteen weeks and for the 12th time in 35 weeks, rising by 2,733,000 barrels to 126,610,000 barrels during the week ending December 3rd, after our distillates supplies had increased by 2,160,000 barrels 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 631,000 barrels per day to 3,578,000 barrels per day, even as our exports of distillates jumped by 630,000 barrels per day to 1,218,000 barrels per day, while our imports of distillates rose by 35,000 barrels per day to 269,000 barrels per day....but after twenty-four inventory decreases over the past thirty-five weeks, our distillate supplies at the end of the week were still 16.2% below the 151,092,000 barrels of distillates that we had in storage on December 4th, 2020, and about 7% below the five year average of distillates stocks for this time of the year…
Meanwhile, despite the drop in our oil exports, our commercial supplies of crude oil in storage fell for the 18th time in the past twenty-eight-weeks and for the 34th time in the past year, decreasing by 241,000 barrels over the week, from 433,111,000 barrels on November 26th to 432,870,000 barrels on December 3rd, after our commercial crude supplies had decreased by 909,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories slipped to around 7% below the most recent five-year average of crude oil supplies for this time of year, but were still 25% above the average of our crude oil stocks as of the second weekend of December 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 December 3rd were 14.0% less than the 503,231,000 barrels of oil we had in commercial storage on December 4th of 2020, and are now 3.4% less than the 447,918,000 barrels of oil that we had in storage on December 6th of 2019, and 2.1% less than the 441,954,000 barrels of oil we had in commercial storage on December 7th of 2018…
Finally, with our inventory of crude oil and our supplies of all products made from oil all 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 2,511,000 barrels this week, from 1,824,711,000 barrels on November 26th 1,827,222,000 barrels on December 3rd, and is now up by 4,830,000 barrels, or by 0.3%, from the 82 month low of two weeks ago...
This Week's Rig Count
The number of drilling rigs active in the US increased for the 54th time during the past 64 weeks during the week ending December 10th, but still remained 27.4% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs running in the US increased by seven to 576 rigs this past week, which was also 238 more rigs than the pandemic hit 338 rigs that were in use as of the December 11th report of 2020, but was also still 1,353 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 increased by 4 to 471 oil rigs during this period, after they had been unchanged during the prior week, and there are now 213 more oil rigs active now than were running a year ago, even as they still amount to just 29.3% of the shale era 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 increased by 3 to 105 natural gas rigs, which was also up by 26 natural gas rigs from the 79 natural gas rigs that were drilling during the same week a year ago, but still only 6.5% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….note that last year's rig count also included a rig that Baker Hughes had classified as "miscellaneous', while there are no such "miscellaneous' rigs deployed this week...
The Gulf of Mexico rig count was up by a rig to 14 rigs this week, with twelve 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's one more than the count of 13 rigs in the Gulf a year ago, when 12 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 up by 8 to 521 horizontal rigs this week, which was also 215 more than the 306 horizontal rigs that were in use in the US on December 11th of last year, but was 62.1% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014...meanwhile, the directional rig count was unchanged at 31 directional rigs this week, but those were still up by 14 from the 14 directional rigs that were operating during the same week a year ago….however, the vertical rig count was down by 1 to 24 vertical rigs this week, even as those were up by 9 from the 15 vertical rigs that were in use on December 11th 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 10th, the second column shows the change in the number of working rigs between last week’s count (December 3rd) and this week’s (December 10th) count, the third column shows last week’s December 3rd 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 11th of December, 2020...
as you can see, this week's rig changes were widely distributed through producing states and basins...we'll first check the Rigs by State file at Baker Hughes for changes in the Texas Permian basin...there we find that one rig was added in Texas Oil District 8, which is the core Permian Delaware, and that another rig was added in Texas Oil District 7B, which includes the easternmost county of the Permian Midland, but that two rigs were pulled out of Texas Oil District 7C, which covers the northernmost Permian Midland....since the national Permian rig count was up by 3 and only two rigs were added in New Mexico, either one of the rigs removed from Texas District 7C had not been targeting the Permian, or a non-Permian rig was pulled out in New Mexico while 3 Permian rigs were added in that state at the same time...that can be determined by checking the individual well records in the North America Rotary Rig Count Pivot Table (Feb 2011 - Current), if anyone needs to know..
elsewhere in Texas, a rig was added in Texas Oil District 1, another rig was added in Texas Oil District 4, while a rig was pulled out of Texas Oil District 2, all districts where drilling is primarily into the Eagle Ford shale...however, since the Eagle Ford rig count was up by two, we have to assume the rig pulled out of District 2 had not been targeting that formation...note that there was also an oil rig pulled out of the Barnett shale in the Dallas-Ft Worth area that isn't evident on the Baker Hughes the Texas state table, suggesting that a non-Barnett rig was added in that area at the same time...
meanwhile, Oklahoma's count rose by 2 rigs with the addition of two oil rigs in the Cana Woodford, the addition of another oil rig in the Granite Wash basin, and the removal of an oil rig from the Arkoma Woodford...at the same time, the increase in Louisiana was due to the rig added state's offshore waters, while counts in all other regions of Louisiana were unchanged....the oil rig added in Utah and and the oil rig pulled from Alaska were in basins that Baker Hughes doesn't track..
for natural gas rigs, there was one added in Eagle Ford shale, where there are now six, one added in Ohio's Utica shale, and another added in the Haynesville shale....the latter was accompanied by the removal of one of the two oil rigs that had been drilling in the Haynesville at the same time, and hence the Haynesville shale rig count remained unchanged....likewise, the Marcellus shale rig count remained unchanged as the natural gas rig that was added in West Virginia's Marcellus was offset by the removal of a rig that had been drilling in Pennsylvania's Marcellus...
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EIA: Most new natural gas-fired capacity to be from Appalachia region - A total of 27.3 gigawatts (GW) new natural gas-fired are scheduled to come online in the United States between 2022 and 2025, according to the U.S. Energy Information Administration’s latest Monthly Electric Generator Inventory. This is a 6 percent increase from August’s baseline capacity of 489.1 GW. Many of the planned natural gas-fired capacity additions are located in the Appalachia region close to major shale plays as well as in Texas and in Florida. The Appalachia region stretches across Pennsylvania, West Virginia and Ohio, and includes the Marcellus and Utica shale plays. Over the past several years, these shale plays have led the growth in U.S. natural gas production, and were 34 percent of U.S. dry natural gas production in the first half of 2021. Four states – Pennsylvania, Ohio, Michigan and Illinois – have pipeline access to natural gas from the Marcellus and Utica shale plays. These states account for a combined 43% of the natural gas-fired capacity planned to come online Pennsylvania has the fewest planned additions, only 1.9 GW. Illinois has the most at 3.8 GW, followed by Michigan, 3.2 GW, and Ohio, 2.9 GW. In addition, natural gas transport infrastructure is expected to continue to increase the region’s pipeline takeaway capacity.
Certifying Appalachia Natural Gas as Responsibly Sourced Expands for Private E&Ps, Midstreamers - More Lower 48 producers and increasingly, midstream operators, are looking to Project Canary to earn environmental certification for their natural gas supplies. Related entities Tug Hill Operating LLC and XcL Midstream Operating LLC, which principally operate in West Virginia’s Marshall and Wetzel counties, have partnered to gain the responsibly sourced gas (RSG) designation across all of their upstream and midstream operations. Earlier this year, privately held exploration and production (E&P) company Tug Hill launched a pilot in which 45 wells were certified through Project Canary’s TrustWell system. “The partnership between Tug Hill and XcL means, for the first time, gas purchasers will have the opportunity to buy RSG that has been TrustWell certified from the wellhead to the receipt point,” said CEO Michael Radler, who oversees both companies. Tug Hill produces more than 800 MMcf/d of gas and delivers it to market via XcL’s gathering system. Tug Hill and Xcl, both sponsored by private equity giant Quantum Energy Partners, would be the first upstream and midstream companies to jointly seek independent certification of 100% of their operating assets. The management teams “believe the integration of independent, high fidelity upstream and midstream certifications will result in a unique and unmatched RSG offering for the market.” Earlier this year, Tug Hill joined Our Nation’s Energy Future, aka ONE Future, a coalition that has pledged to reduce collective methane emissions to 1% or lower. “Tug Hill places an extremely high focus on operational excellence, sustainability and being a good neighbor within the communities where we operate,” said COO Sean Willis. “Tug Hill is committed to utilizing high fidelity technology and rigorous operating standards to reduce the methane intensity of our operations and produce energy responsibly.”
Sunoco Ordered to Dredge Lake, Pay $4M Over Pipeline Spill - A pipeline developer will dredge part of a contaminated lake and pay more than $4 million for spilling thousands of gallons of drilling fluids at a popular state park outside Philadelphia, Pennsylvania state officials announced Monday. Sunoco Pipeline LP will dredge at least six inches of sediment from Ranger Cove, part of Marsh Creek State Park in Downingtown. It will also replace fish, turtle and bird habitat, restore the shoreline, and reroute its Mariner East 2 pipeline, according to the state Departments of Environmental Protection and Conservation and Natural Resources, which jointly announced the settlement. The spill, which happened in August 2020 during construction of the troubled pipeline, contaminated wetlands, tributaries and part of the 535-acre lake. About 33 acres of the lake were placed off limits to boating and fishing because of the spill. The natural resources department said it will use the $4 million from Sunoco for park rehabilitation and improvements that will include an accessible boat launch, a visitor center and suppression of invasive species, among other things. The 1,784-acre park in Chester County hosts more than 1 million visitors each year. “Southeast Pennsylvania lost a significant recreational resource when the impacted area of the lake was closed due to the drilling fluid impacts, and many residents and community members expressed the need to restore those opportunities,” said Conservation and Natural Resources Secretary Cindy Adams Dunn. A message was sent to Energy Transfer, Sunoco's corporate parent, seeking comment. The August 2020 spill at Marsh Creek was among a series of mishaps that has plagued Mariner East since construction began in 2017. In October, Energy Transfer, the developer of the multi-billion-dollar pipeline project, was charged criminally after a grand jury concluded that it flouted Pennsylvania environmental laws and fouled waterways and residential water supplies across hundreds of miles. The company has yet to enter a plea in the case. Energy Transfer has also been assessed more than $24 million in civil fines, including a $12.6 million fine in 2018 that was one of the largest ever imposed by the state. State regulators have periodically shut down construction.
Mariner East builder Sunoco agrees to $4M settlement over Marsh Creek Lake spill --Mariner East pipeline builder Sunoco, a subsidiary of Energy Transfer, will pay $4 million to the Pennsylvania Department of Conservation and Natural Resources as part of a settlement that allows the company to resume construction near Marsh Creek Lake State Park in Chester County. The company spilled between 21,000 and 28,000 gallons of drilling mud into the 535-acre Marsh Creek Lake in August 2020, which led to the shut down of a part of the lake known as Ranger’s Cove, and a halt to construction along the approximately one-mile-long stretch of pipe. The settlement comes just two months after Pennsylvania Attorney General Josh Shapiro filed 48 criminal charges related to Mariner East construction against the Texas-based company, including a felony of failing to report a pollution event. The grand jury report singled out the Marsh Creek Lake spill as one of several examples where Sunoco under-reported the amount of drilling mud released into the lake. The mud is primarily bentonite clay, which is non-toxic to humans but can kill macroinvertebrates, or small aquatic life that provide food for larger fish. The grand jury also reported the company used unauthorized chemicals in its drilling mud. The settlement requires Sunoco to dredge the top 6 inches of sediment in Ranger’s Cove; replace damaged fish, turtle, and bird habitat; remove all dredging material from the lake, as well as restore the shoreline and streamside buffers. The company will also pay a penalty of $341,000 for DEP permit violations and post a $4 million bond to ensure completion of the remediation. The $4 million payment to DCNR will be used toward “rehabilitation and improvements to the park, including an accessible boat launch, stream and shoreline restoration, invasive species suppression, efficiency measures that will take the park to net-zero energy, and to add a public visitor center to the park office,” according to a press release from DCNR. Marsh Creek Lake Park is a popular spot for boating and fishing. The spill drew outrage and protests from the surrounding community of West Whiteland Township, especially since Mariner East pipeline construction had already led to sinkholes and drinking water contamination in Chester County. Residents of Southeastern Pennsylvania have fiercely opposed the natural gas liquids pipeline due to safety concerns, and the spill renewed calls for a complete halt to construction. Gov. Tom Wolf has said he will not halt construction, but would hold the company accountable for pollution. “Southeast Pennsylvania lost a significant recreational resource when the impacted area of the lake was closed due to the drilling fluid impacts, and many residents and community members expressed the need to restore those opportunities,” said Department of Conservation and Natural Resources Secretary Cindy Dunn. “This resolution will put us on the fastest track possible to dredge and restore Ranger Cove, and also will result in habitat and visitor improvements at Pennsylvania’s fifth most-visited state park.” Not everyone praised the agreement. Virginia Kerslake from the group Del-Chesco United, which opposes the pipeline, said it is more “pay to pollute.” “It is unconscionable that the DEP has given approval to resume Mariner East construction at Marsh Creek Lake to this serial violator, which has racked up 48 criminal charges, and has still not cleaned up the 21,000 gallons of drilling mud spilled into our treasured lake and water reservoir in August 2020,” Kerslake said.
CNX chief calls for change in Pa.'s gas impact fees -The head of one of Pennsylvania’s largest natural gas producers had sharp words Tuesday regarding state impact fees and claimed the industry has been “villified” by opponents. Nick DeIuliis, chief executive of CNX Resources Corp. of Cecil, called for a revamp of the impact fee levied on natural gas producers, which have pumped more than $2 billion into the coffers of state and local governments since 2012. “We’ve (natural gas producers) paid more than our fair share” over the past nine years under Act 13, a formula used to determine the levy, DeIuliis said Tuesday during a speech to industry representatives at the David L. Lawrence Convention Center in Pittsburgh. No other energy sector pays an equivalent impact fee to the state, DeIuliis said. “It’s time for a refresher,” DeIuliis said to more than 200 representatives at the DUG East and Marcellus-Utica Midstream Conference. The formula for levying the annual impact fees, primarily on the operators of unconventional gas wells, is determined by a multiyear fee schedule based on the average natural gas price. The fees can be adjusted to reflect increases in the Consumer Price Index if the total number of unconventional wells spud in a given year exceeds the number the previous year, according to the Pennsylvania Public Utility Commission. DeIuliis said after his speech that he did not have a specific formula in mind, but it should be one in which the gas industry production can increase, while raising more money for those benefiting from the fee. The Pennsylvania Public Utility Commission said the state has collected more than $2 billion since Act 13 was enacted in February 2012. For production in 2020, the state collected $146.2 million from the impact fee, which was down from $251 million in 2018. About $71 million of the 2020 collection was distributed to county and local governments, while the state took $23.7 million to cover the impact on state agencies of drilling activities. Local governments can spend the money on infrastructure projects, water and stormwater projects, emergency preparedness and public safety and environmental programs, including trails.
Pennsylvania Nears Approval of New Oil And Gas Methane Rule -- Pennsylvania is in the final stages of approving a new rule that would crack down on methane emissions from older oil and gas infrastructure, while exempting a vast number of low-producing wells. The rule would be a significant change for producers in the state, which is the second-largest natural gas producer in the U.S., responsible for about one-fifth of the country’s gas output in 2020, according to the U.S. Energy Information Administration. While many states have imposed methane limits on new wells, Pennsylvania is joining only a handful, including Colorado and New Mexico, that have restrictions on older wells. Those can be a major source of emissions relative to their production. Texas, the largest gas producer, has no methane limits at all.
Diversified Investing $9M for Aerial Scans to Detect Methane Leaks --In November Diversified Energy announced it is expanding methane emissions detection at the company’s operations in the Appalachian Basin by deploying an extra 500 handheld detection devices (in addition to 100 already in use) at its worksites (seeDiversified Uses Handheld Devices to Detect, Eliminate Methane Leaks). Diversified owns close to 8 million acres of leases with some 67,000 (mostly) conventional oil and gas wells (with over 400 Marcellus/Utica shale wells). The company has just announced it will further expand its methane detection efforts by investing $9 million over the next three years to use LiDAR detection. LiDAR stands for precision laser imaging, detection, and ranging equipment used to identify methane emissions from gas and oil facilities. Diversified cut a deal with Montana-based Bridger Photonics to perform multi-year aerial scans of Diversified’s natural gas production and distribution assets, beginning with the company’s assets in the Appalachian region.Diversified used Bridger earlier this year in a field trial to aerially detect fugitive natural gas emissions in a large segment of a pipeline Diversified acquired in Appalachia. They obviously liked the results from that test. In early 2021, Diversified collaborated with Bridger to aerially detect fugitive natural gas emissions in a large segment of pipeline the Company acquired in Appalachia. During the field trial, Diversified confirmed that Bridger’s advanced LiDAR technology detected emissions well below the EPA-defined leak definition of 500 parts per million.Based on the successful field trial and as part of its $15 million annual initial funding commitment, the Company will expand its investment in aerial emissions scanning activities by spending $3 million per year on this aerial methane emissions detection over the next three years. This partnership with Bridger further validates the Company’s investment in aerial LiDAR announced at its 17 November 2021 Capital Markets Day. Initially, Diversified will focus its scanning efforts on its Appalachian operations, and expects to expand the program to cover its assets in the Central Region.The aerial emissions detection scans, coupled with newly deployed handheld detection devices, support Diversified’s commitment to perform comprehensive fugitive emissions assessments at all Appalachia wells by mid-2023, reflective of Diversified’s zero-tolerance policy toward fugitive natural gas emissions. Diversified’s investment in aerial emissions detection is an extension of its Smarter Asset Management (“SAM”) program focused on operational excellence, stewardship of existing assets and enhanced asset integrity that serves as a return on this methane emission-reduction investment.
'Responsibly sourced' tag could shift from bonus to necessity for gas drillers --Shale gas drillers face increasing market pressure to have their product certified as "responsibly sourced," even though gas awarded the designation might not fetch a premium price. "The paradigm shift is going to be: If your gas is not certified in one way or another, you may not be able to sell it," Jennifer Stewart, principal adviser to nonprofit Equitable Origin Inc., told an audience of shale executives Dec. 8 at Hart Energy's DUG East conference. Equitable Origin has a set of environmental, social and governance standards for producers desiring certification as responsibly sourced natural gas. Industry players have begun responding to concerns over greenhouse gas emissions in the natural gas supply chain by competing to offer the cleanest supplies, and certification offers a way to assure buyers that drillers are limiting methane emissions at their production and gathering operations. Two private Appalachian shale gas drillers used the conference to announce that they are seeking certification from Project Canary Inc., a widely used auditor of methane emissions. Tug Hill Operating LLC, backed by private equity firm Quantum Energy Partners LLC, and Blackstone Inc.-backed Olympus Energy LLC are joining their larger, publicly traded peers in pursuing certification, which could help them market to overseas LNG buyers that have been uneasy about the amount of methane emitted in producing and transporting the gas. Gas traders are "blowing our phones up" with questions about certified low-emissions natural gas, Stewart said. "I think we've had a call almost every day this week from various trading shops wanting to know about certified gas: 'How do we buy your certified gas, and who do we buy it from?'" But due to the opacity of bilateral gas trades, it is not clear that those buyers are willing to pay a premium for the certified gas. Stewart said that when she worked at Southwestern Energy Co., the shale gas producer closed four deals for responsibly sourced gas, and all received a premium price. Regulatory agencies such as the U.S. Environmental Protection Agency and the U.S. Energy Department have expressed interest in the standards and process for getting certified, Stewart said, but the market will decide what value, if any, a "responsibly sourced" tag will have. To venture capitalist Chris Kalnin, the certification debate misses the point. "You need to go to end consumers and help them help you pay for some of your ESG efforts, just like organic food in the grocery store," Kalnin told executives at the conference. "I don't believe that you're going to go out in the market and be able to charge a premium for renewable gas or responsible gas."
National Grid says not ‘more than 20 gallons’ of coal tar oil spilled in Seekonk River at Tidewater Landing site - The Boston Globe -On Dec. 1, weathered coal tar oil breached the booms at National Grid’s $400 million Tidewater Landing site in Pawtucket, marking the second spill in the last month at the site — Officials at National Grid told the Globe that it’s likely that “no more than 20 gallons” of weathered coal tar oil breached the absorbent boom and turbidity curtain in the Seekonk River last week. Ted Kresse, a spokesman with the company, said National Grid is not characterizing the breach as “a spill,” and that it’s difficult to calculate exactly how much oil seeped into the river. “Considering this isn’t a traditional ‘spill’ where the volume released might be easily quantifiable in comparison to a spill from a broken pipe or hit tanker, we do not know the exact amount of coal tar oils that seeped into the river and breached the boom containment system,” said Kresse in an email to the Globe. “That being said, an initial analysis estimated that it would likely not have been more than 20 gallons of weathered coal tar that breached the absorbent boom and turbidity curtain based on the type of sheen observed and the area the sheen covered.”
US District Court issues wrist slap fine for serious environmental pollution at BP refinery in northwest Indiana - The UK-based oil giant BP has been ordered to pay the US federal government $500,000 in fines for emitting illegal amounts of soot particles into the air from its Whiting, Indiana oil refinery, according to a legal settlement filed last Thursday in the US District Court of Hammond, Indiana. The Chicago Tribune reported that BP’s own testing revealed that catalytic crackers, which help turn crude oil into gasoline, were emitting “concentrations of particulate matter,” more commonly known as soot, in excess of legal limits between 2016 and 2018. The recent lawsuit found that BP was in violation of the terms of an agreement from a 2012 lawsuit brought by the US Department of Justice and the Environmental Protection Agency (EPA), including BP’s failure to “properly operate pollution-control equipment” during that period when BP was required to install the equipment as a result of the 2012 settlement. The 2012 lawsuit alleged “violations of the Clean Air Act at the Whiting refinery in connection with the construction and expansion of the refinery, as well as violations of a 2001 consent decree with the company that covered all of BP’s refineries and was entered into as part of EPA’s Petroleum Refinery Initiative.” In the 2012 settlement which the company signed, BP agreed to pay an $8 million penalty and invest more than $400 million to install pollution controls and cut emissions and reduce air pollution by over 4,000 tons per year. The settlement recognized that BP’s activities were harmful to life in the area around northwest Indiana, which includes the Chicago metropolitan area, stating that they “can cause respiratory problems such as asthma and are significant contributors to acid rain, smog and haze.” A number of nonprofit groups were represented in Thursday’s lawsuit, including the Environmental Integrity Project (EIP), the Environmental Law and Policy Center, the Natural Resources Defense Council (NRDC), Save the Dunes Project, and the Sierra Club. Ann Alexander, senior attorney at NRDC, told the Tribune that “We sued [BP] in 2008 for Clean Air Act violations, reached an agreement with them to curb emissions in 2012, and now here we are in 2021 reaching another agreement after they violated the first one.” In April of this year, a separate court ruling issued by Judge Philip P. Simon of the U.S. District Court in Northern Indiana found that BP “repeatedly violated legal limits on deadly soot-like particulate air pollution.” The Sierra Club and Environmental Integrity Project had sued the corporation in 2019 because the Indiana Department of Environmental Management (IDEM) did not act against BP to enforce the terms it agreed to in the 2012 lawsuit, according to an April 14 post on the Sierra Club’s website. The Sierra Club and EIP found that between August 3, 2015 and October 9, 2018, the results of nine emissions tests conducted by BP on the smokestacks from three of its boilers at the refinery showed that the company continued to release “soot-like particles” into the air “over the permitted limits.” Although these results were available publicly online through the IDEM as part of the 2012 agreement, the IDEM did not intervene and allowed BP to continue the violations.
Meet a clean water activist fighting to protect Virginia streams from the Mountain Valley Pipeline -— State officials, residents, and representatives from various organizations requested Tuesday night that the permit for a power-generating facility be denied or made provisional to make way for cleaner solutions such as grid energy storage. About two dozen people attended the public hearing held virtually by the state Department of Environmental Protection for Pittsfield Generating Co.'s facility located to 235 Merrill Road. The company is seeking an Air Quality Operating Permit. A draft permit was issued on Nov. 17 and if approved, it would renew operations for five years. "Clearly this is the moment we need to be acting as robustly as possible in kind of redirecting our use of peaker plants and making sure we're doing everything we can to reduce our emissions and standing up for environmental justice communities," state Senator Adam Hinds said. "And it starts right here one permit at a time, one plant at a time, one community at a time." A "Zoom bomber," or many, interrupted testimonies at various points during the hearing. Berkshire Environmental Action Team has led the movement with a campaign "Put Peakers in the Past" demanding that the three peaking power plants located in Berkshire County revert to only renewable and clean alternatives. "The facility is considered to be a major source since it has the potential to emit greater than major source thresholds for sulfur dioxide, nitrogen oxides volatile organic compounds and carbon monoxide, though actual emissions are much lower," Marc Simpson, MassDEP's section chief for the Western Regional Office Air Program, said.
Permit denied for proposed Mountain Valley Pipeline Southgate compressor station in Pittsylvania County — A state board denied an air permit Friday for the Mountain Valley Pipeline Southgate’s Lambert Compressor Station in Pittsylvania County. MVP spokesman Shawn Day expressed disappointment at the decision that came “despite the overwhelming evidence that our application met or exceeded all previously stated requirements.” MVP Southgate is evaluating the next steps it will take in response to the board’s decision, Day said. “The proposed facility would have been one of the most stringently controlled natural gas compressor stations in the United States,” Day said in a prepared statement. “The board’s decision is not supported by factual evidence.” The Virginia Air Pollution Control Board voted 5-2 to deny the permit, despite recommendation for approval from the Virginia Department of Environmental Quality during the board’s meeting that was held Thursday and Friday at the Olde Dominion Agricultural Complex in Chatham. The meeting to consider MVP Southgate’s permit application included public comment Thursday and Friday. The board denied the permit after members determined that the proposed project did not meet the fair treatment requirements of the Virginia Environmental Justice Act, would affect an environmental justice community and that the project’s site is not suitable under the act, legal precedent or state code. “Given these reasons, the board is varying from the recommendation of the department and denying the above referenced permit application,” Board Chair Kajal B. Kapur said in a board statement outlining its decision Friday. “Air board members fulfilled their responsibility to their fellow citizens,” NAACP President Anita Royston said in a prepared statement. “They listened to the voice of the people and made a decision that is in the best long-term interest of our community.” Elizabeth Jones, chair the county NAACP’s Environmental Justice Committee, said the board’s decision took courage. “Environmental and climate justice is a civil rights issue,” Jones said in a prepared statement. “We all depend on the physical environment and its bounty.” The board based its decision on several items, including public comments made at the meeting, staff presentations, a copy of the draft permit, a summary of and response to public comments and a copy of the permit engineering analysis.
Virginia board denies permit to extend fracking pipeline into North Carolina - Virginia’s air pollution governing body on Friday voted against approving an air quality permit for a proposed compressor station in the southern Virginia town of Chatham. On the second day of a two-day meeting, the Virginia Air Pollution Control Board voted 6-1 against the proposal. The proposal would have extended the Mountain Valley Pipeline, which carries fracked fuel, over the border into North Carolina. Environmental groups and local advocates have vocally opposed the project, citing environmental reviews indicating it would increase the levels of air pollutants such as carbon monoxide, sulfur dioxide and formaldehyde. Sixteen members of Virginia’s House of Delegates had previously urged the board to deny the permit in October, citing environmental justice concerns. “Emissions from compressor stations contain toxic materials and any proposed project that would introduce new health hazards into a community should be very carefully considered,” they wrote. “A project’s potential impacts and contribution to cumulative impacts must be weighed against any arguments as to its necessity.” “No one should be asked to sacrifice their air, water, and health so that fossil fuel executives can make a quick buck in a world transitioning to clean energy. This is a win for Virginia communities who already live with elevated levels of fossil fuel pollution, and everyone everywhere who wants a livable future for their children,” Lynn Godfrey, community outreach coordinator for the Sierra Club’s Virginia chapter, said in a statement. “The writing is on the wall if the wealthy investors backing this project are willing to read it: the age of fossil fuels is over, it’s time to drop this polluting pipeline.”
MVP Southgate Developers Eye ‘Next Steps’ After Virginia DEQ Panel Denies Permit --A Virginia Department of Environmental Quality (DEQ) panel late last week voted to deny an air permit for a compressor station needed to extend the Equitrans Midstream Partners LP-led Mountain Valley Pipeline (MVP) into North Carolina. Going against DEQ’s recommendation, the Virginia Air Pollution Control Board voted 6-1 to deny a draft minor new source review permit for the proposed Lambert Compressor Station (LCS), a key link to extend MVP — via the separate MVP Southgate project — 75 miles from Pittsylvania County, VA, into the North Carolina counties of Rockingham and Alamance.“We are disappointed that the majority of the board voted Friday to deny an air permit for the proposed MVP Southgate Lambert Compressor Station despite the overwhelming evidence that our application met or exceeded all previously stated requirements,” Shawn Day, MVP Southgate project spokesperson, told NGI. “The proposed facility would have been one of the most stringently controlled natural gas compressor stations in the United States.”Day stressed that the MVP Southgate decision has no bearing on the MVP project, which will transport 2 million Dth/d of natural gas from West Virginia to a Transcontinental Gas Pipe Line interconnect in southwestern Virginia. “MVP Southgate is a separate project, with its own regulatory processes, its own FERC docket number, its own customer,” he said. “Regardless of the Air Board’s decision, MVP will still deliver 2 million Dth/d to the Transco interconnect.”To be sure, MVP has faced setbacks of its own. However, MVP developers have also secured victories this year with FERC, which granted approvals tied to the pipeline’s construction and water-crossing method. MVP is a joint venture of Equitrans Midstream Partners LP, NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream and RGC Midstream LLC. Equitrans, which holds a 47.8% stake in the JV and will operate MVP, said in a recent investor presentation that the targeted full in-service date for the 300-mile pipeline is the summer of 2022. Equitrans Midstream owns 47.2% of the MVP Southgate project and plans to operate that pipeline as well, according to the project website. NextEra, Con Edison, WGL, RGC, and PSNC Energy also own MVP Southgate interests.
Chickahominy Pipeline hosts first 'warm body outreach' event to address questions about proposed 83-mile natural gas pipeline --Chickahominy Pipeline LLC held a highly anticipated virtual public meeting Thursday night, five months after residents in five central Virginia counties were surprised with land survey letters about the potential for a then-unknown pipeline project that may go through their properties. Led by company representatives, the virtual Zoom meeting — described by Chickahominy Project Outreach’s Beth Minear as the first “warm body outreach” — was the first public engagement event held by Chickahominy, which wants to build an 83-mile pipeline as part of a proposed project that involves a new power plant in Charles City County. The pipeline would run through the counties of Louisa, Hanover, Henrico, New Kent and Charles City and supply the natural gas for the plant. Chickahominy Pipeline is affiliated with a company called Chickahominy Power, which wants to build the plant. Both are subsidiaries of a Northern Virginia-based energy firm called Balico LLC. On Thursday night, company representatives said more than 40 people were participating in the Zoom meeting, and that they had received dozens of questions ahead of time. They also allowed viewers to submit questions throughout. Questions focused on such issues as lack of outreach, pipeline construction, the project’s private investors, and benefits to landowners, as well as the larger issue of what happens to the project if the State Corporation Commission decides that Chickahominy must be a regulated utility.
With natural gas supplies disrupted, citizens and businesses may be asked to reduce energy use this winter - The top official running New England's electricity grid says the region faces a "precarious" winter, in which consumers and businesses may be asked to limit their use of electricity and natural gas to help avert extended brownouts or worse. Gordon Van Welie, CEO of the Independent System Operator of New England, or ISO-NE, also says that the region will need more hydro-electricity from Canada to help the transition to a greener grid, whether it gets here via Central Maine Power's contentious energy corridor, or by other routes. With national and international supplies of the natural gas that fuels the majority of New England's power generation disrupted by the pandemic and other issues, Van Welie says requests for citizens and businesses to reduce energy usage, and even forced brownouts, are real possibilities this winter. “I think we're feeling more vulnerable,” Van Welie says. That despite predictions of a relatively mild winter. Extended cold snaps can happen any winter, Van Welie told reporters during a briefing Monday. He pointed to what happened in Texas during its extended outages early this year. “What happened in Texas changed everything. We've not rested well since the February event… we know that we are operating close to the edge here in the wintertime, in particular here in New England, we've known that for a long time,” Van Welie says. “I think that what Texas drove home for me is that with almost 15 million people living in this region need to understand is that we are in a precarious position particularly when we get into cold weather." New England's grid is more robust than in Texas, he adds. But the reliance on natural gas here can escalate quickly when supply chain issues coincide with a cold snap, because fuel dealers are required to deliver first to homes that heat with gas, and power generators are second in line. This season, ISO-NE is planning to issue energy supply advisories along with 21-day weather predictions and may call on the public to curtail use of both electricity and gas before a cold snap arrives, in order to avert a crisis. ISO system administrator Peter Brandien says the agency may issue advisories similar to summer-time heat-wave messaging that come from utilities. "Turn down your thermostat so that you're not using as much electricity or gas to heat your homes, don't do as much laundry, try to minimize the amount of cooking you're doing," Brandien says.
Energy Pros Mock Liz Warren's Complaints: 'It's Econ 101, Not Rocket Science' - Sen. Elizabeth Warren’s latest attempt to “turn up the heat” on the energy sector sparked a backlash from industry leaders who say the real problem comes from policies the Massachusetts’ Democrat has endorsed. In recent letters to natural gas producers, Warren blasted what she called their “corporate greed” and demanded an explanation for the record exports of natural gas at the same time prices are rising in the U.S. Warren wants the industry to respond to questions about “the extent to which these price increases are being driven by energy companies’ corporate greed and profiteering as they moved record amounts of U.S. gas out of the country,” she wrote. She got a response, but not the one she demanded. Leaders in the natural gas sector responded with a letter of their own, dismissing Warren’s comments as a diversion, one intended to distract consumers from the impact of the energy policies she’s championed. “This a misguided and headline-grabbing ploy,” says David E. Callahan, president of the Marcellus Shale Coalition (MSC). “If she knows anything about these highly complex energy markets, she must know what’s really going on here,” added Callahan, who co-authored a response letter alongside the leaders of the Gas & Oil Association of West Virginia (GO-WV), and Ohio Oil & Gas Association (OOGA). “It’s a commodity market, prices ebb and flow, and the market is responding to those signals.” Pennsylvania and West Virginia are among the top five natural gas producers in the nation, with the Keystone State alone producing one-fifth (21.1 percent) of the nation’s supply. (Texas edges out Pennsylvania for the top spot at 23.9 percent.) Warren is an aggressive supporter of the Green New Deal, which would drastically restrict the production of oil and natural gas. In her state of Massachusetts, policies blocking the expansion of natural gas pipelines have resulted in Russian LNG tankers in Boston Harbor bringing fuel to the Bay State.. “She has her constituents to represent and her political affiliation to support,” said Charlie Burd, executive director of GO-WV. “But to be perfectly honest, I just think those comments almost show a complete lack of understanding on how energy is explored for, produced, and transported in this country.” And those constituents are paying the price, according to Callahan.
Who’s to Blame for Higher Heating Costs This Winter? | NRDC --As winter approaches and retail prices for energy remain at multiyear highs, many people are looking at their utility bills with increasing concern. In its most recent Winter Fuels Outlook, the U.S. Energy Information Administration predicts that U.S. households that rely on natural gas to stay warm (which is nearly half of them) can expect to spend 30 percent more for heat than they spent last winter, and as much as 50 percent more if their local temperatures this season are just 10 percent lower than average.Anticipating public frustration, oil and gas companies—and the politicians who take their cash—are trying to pin the blame on policies designed to promote renewable energy and reduce the extraction and consumption of fossil fuels. Don’t buy it.Senator John Barrasso of Wyoming—who’s received nearly $1.2 million in contributions from the oil and gas industry since taking office in 2007—issued a lengthy diatribe on the Senate floor blaming Biden and unspecified “environmentalists” for “shut[ting] down the abundant and affordable energy sources that fuel our economy” and for turning the United States from “a nation of energy wealth and energy dominance” into “a nation of energy weakness.” On the same day as Barrasso’s outburst, Representative Garret Graves of Louisiana called rising fossil fuel prices “an unforced error” by the administration and accused it of “trying to manipulate markets and force us in a direction of taking on things like solar and wind energy and other renewable sources.”Predicting the price of the natural gas that’s used to heat homes during cold weather—like predicting the weather itself—is a tricky business. There are few commodities as susceptible to price fluctuations as oil and gas. “The oil and gas extraction industry has been a boom-and-bust business since the world's first commercial oil well was drilled in 1859, and boom-bust cycles inevitably mean volatile prices,” Szybist says. One example is the recent dramatic swings in the price of methane, which has gone from a high of more than $20 per thousand cubic feet (mcf) to a low of less than $2 per mcf over the last 16 years, and which in just the past 18 months has shot up more than 300 percent, from $1.76 to $5.62. “This isn't an aberration,” Szybist adds. “It's the nature of the oil and gas market.”
Record December heat in the U.S. wilts natural gas prices - U.S. natural gas collapsed to the lowest level in more than four months as record-high temperatures kill heating demand ahead of winter. Futures for January delivery plunged 12% Monday, making the commodity the worst performer among U.S.-traded raw materials. Gas has already shed about 40% of its value since October, when traders betting on global fuel shortages drove prices to the highest level in seven years. Investors have since been forced to unwind some of those bets. While natural gas inventories in Europe and Asia remain strained, fueling higher prices there, unseasonably warm weather in the U.S. has allowed domestic stockpiles to rebound, deflating most of this year’s rally. In the last seven days alone, more than 4,000 daily records were set for higher-than-normal temperatures. December is expected be the third warmest going back to 1950 based on natural gas consumption, according to Bradley Harvey, a meteorologist at commercial forecaster Maxar. Temperature could reach 61 degrees Fahrenheit (16 Celsius) in New York and 81 degrees in Houston this week, according to the Weather Channel. In one sign of how supply fears have eased, the price premiums traders added to winter contracts have been almost completely erased. 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, narrowed to as low as 3 cents after surging to $1.90 per million British thermal units in early October. “The widows of the market are those who went along expecting a really strong winter demand,” said Gary Cunningham, director of market research at Tradition Energy. “We’re just not seeing it right now.” Losses in the spring and summer futures have been much less severe. Gas for August delivery dropped 7% Monday and is down by 18% from a Nov. 26 high.
U.S. natgas futures drop to 4-1/2 month low on warmer-than-usual December outlook (Reuters) - U.S. natural gas futures shed over 11% on Monday to the lowest in more than 4-1/2 months, as forecasts for mild December temperatures soured the demand outlook. Front-month gas futures dropped 47.5 cents, or 11.5%, to settle at $3.657 per million British thermal units (mmBtu), their lowest close since July 15. "We're seeing a lot warmer than normal weather in the forecast here, and it looks like it might be sticking around towards the third week in December, which is not sending any bullish signals to the traders," Since Nov. 26, the front month has dropped over 30% in six sessions and has lost about $1.8 per mmBtu, in stark contrast to the seven-year high of nearly $6.5 per mmBtu hit two months ago. A lot of risk premium relating to a supply shortfall has been taken out of the market, DiDona added. Global gas prices have hit record highs in recent months as utilities around the world scrambled for LNG cargoes to replenish low stocks in Europe and meet surging demand in Asia, where energy shortfalls have caused power blackouts in China. Tracking the global rally, 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 winter. "Some lower price levels would appear to lie ahead that could carry January futures to the $3.40-3.50 zone as a minimum if the (weather) forecasts stay mild this week." advisory firm Ritterbusch and Associates said in a note. Data provider Refinitiv said output in the U.S. Lower 48 states has averaged 96.4 billion cubic feet per day (bcfd) so far in December, down slightly from a monthly record of 96.5 bcfd in November. Refinitiv projected average U.S. gas demand, including exports, would rise from 112.1 bcfd last week to 115.4 bcfd this week, but estimated a drop to 112.6 bcfd next week.
U.S. natgas edges up from four-month low on soaring European prices (Reuters) - U.S. natural gas futures rose from a four-month low on Tuesday following a 4% gain in U.S. crude futures and a 6% gain in European gas futures that was expected to keep U.S. liquefied natural gas exports at record highs. Traders noted that rise in U.S. gas prices came despite forecasts for milder U.S. weather and lower heating demand over the next two weeks than previously expected. Front-month gas futures rose 5.1 cents, or 1.4%, to settle at $3.708 per million British thermal units. On Monday, the contract plunged over 11% to its lowest close since July 15. That kept the front-month in oversold territory with a relative strength index (RSI) under 30 for a second day in a row for the first time since March. Crude futures rose almost 4% on Tuesday after rising almost 5% on Monday as concerns over the impact of the Omicron coronavirus variant on global fuel demand eased. 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. The amount of gas flowing to U.S. LNG export plants averaged 11.82 bcfd so far in December now that he sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana was producing LNG. That compares 11.39 bcfd in November and a monthly record of 11.48 bcfd in April. With gas prices around $31 per mmBtu in Europe and $34 in Asia, compared with about $4 in the United States, traders said buyers around the world would keep purchasing all the LNG the United States can produce.
UPDATE 2-U.S. natgas steady after bigger than expected storage draw (Reuters) - U.S. natural gas futures held mostly steady on Thursday as a bigger than expected storage withdrawal and hiked forecasts for U.S. demand over the next two weeks offset a 3% decline in European gas prices. The U.S. Energy Information Administration (EIA) said U.S. utilities pulled 59 billion cubic feet (bcf) of gas from storage during the week ended Dec. 3. That was more than the 54-bcf withdrawal analysts forecast in a Reuters poll and compares with a decline of 78 bcf in the same week last year and a five-year (2016-2020) average decline of 55 bcf. Last week's withdrawal cut stockpiles to 3.505 trillion cubic feet (tcf), or 2.5% below the five-year average of 3.595 tcf for this time of year. "The period of this storage announcement covers the weekend after Thanksgiving, and gas usage over holiday weekends is always difficult to predict," Refinitiv analyst John Abeln said. "So while there was a small bullish signal, it is not enough to cause significant market movement." Looking ahead, many analysts said mild weather expected in coming weeks will allow U.S. utilities to leave enough gas in storage and cause stockpiles to reach above normal levels by mid-December. That would be the first time since April that storage would be above normal levels. Front-month gas futures fell 0.1 cents to settle at $3.814 per million British thermal units. Data provider Refinitiv said output in the U.S. Lower 48 states has averaged 96.3 billion cubic feet per day (bcfd) so far in December, down from a monthly record of 96.5 bcfd in November. With an unusual warming expected in mid-December, Refinitiv projected average U.S. gas demand, including exports, would drop from 117.0 bcfd this week to 110.3 bcfd next week. Those forecasts were higher than Refinitiv's outlook on Wednesday.
Natural Gas Futures Cap Week with Gain on Colder Weather Models - Natural gas futures started off Friday fairly steady as the market continued to monitor the weather data for any convincing evidence that colder temperatures could arrive before the calendar flips to 2022. Traders got just that with the midday models, which ultimately sent the January Nymex futures contract up 11.1 cents day/day to $3.925/MMBtu. February settled 10.5 cents higher at $3.889. Spot gas prices also rebounded across most of the United States. However, steep losses in California and the Rockies sent NGI’s Spot Gas National Avg. down 4.0 cents to $3.720. With the weeks winding down to the holiday season, gas bulls have been waiting to pounce, looking for any indication of more sustained cold on the horizon that would drive up heating demand. There have been brief bouts of chilly air that have circulated across the country, but each one so far has failed to last more than a few days. Things could change around Christmastime, though. Weather models have been hinting for a few days that a significant shift in the pattern could send temperatures plunging. NatGasWeather said the overnight data added as many as nine heating degree days (HDD) to the 15-day outlook. Specifically, there were slightly cooler trends across the far northern United States. The midday Global Forecast System followed up with additional gains in projected demand, resulting in a 15-day outlook that added 20 HDDs between Thursday and Friday. “To our view, the weather data is likely still a little too bearish and risks adding a few more HDDs over the weekend,” NatGasWeather said. While the latest data suggested that more impressive cold is possible Dec. 25-31, the forecaster said there still is more for the data to prove if it’s to be expected. Also of note is that the chillier air would likely arrive in the middle of the Christmas and New Year holidays, a time of year when gas demand typically is low, thereby limiting its impact on the market. For now, the supply outlook continues to improve, at least on the surface. Though the balmy weather has done nothing to boost prices, it has resulted in a far more comfortable level of underground storage inventories ahead of the peak winter season. On Thursday, the Energy Information Administration (EIA) reported a 59 Bcf withdrawal from storage for the week ending Dec. 3. The draw was in line with consensus and trimmed the deficit to the five-year average to 90 Bcf. Total working in gas in storage as of Dec. 3 stood at 3,505 Bcf, 356 Bcf below year-ago levels and 90 Bcf below the five-year average.
EIA forecasts that U.S. natural gas production will increase in 2022 -In the December 2021 Short-Term Energy Outlook (STEO), we forecast that U.S. dry natural gas production will increase from 95.1 billion cubic feet per day (Bcf/d) in October 2021 to 97.5 Bcf/d by December 2022, an increase of 2.4 Bcf/d (2.5%). If realized, the December 2022 forecast production level will exceed the previous record of 97.2 Bcf/d, which was set in November 2019. The November 2019 record was set before COVID-19 was declared a pandemic, and before the COVID-19-associated declines in demand resulted in production declines to a low of 87.3 Bcf/d in May 2020. Dry natural gas production has generally risen since October 2020. Natural gas production remained above 92.0 Bcf/d in 2021, except in February, when a winter storm substantially affected oil and natural gas production in Texas.The forecast for natural gas production is influenced by expectations for natural gas production from newly drilled gas-directed wells, natural gas production from existing wells, and the amount ofassociated natural gas resulting from oil production. The number of natural gas-directed rigs—rigs drilling primarily in natural gas-bearing formations—decreased throughout 2019 and into 2020. In August 2020, the rig count was at its lowest monthly average since 1987 (the earliest year of available data). Since August 2020, the natural gas-directed rig count has generally increased, averaging 102 rigs in November 2021, but remains about 40% lower than the average monthly count in 2019. In both the Haynesville region and the Appalachian Basin, according to our Drilling Productivity Report, we expect dry natural gas production will set new highs this December as a result of both increased drilling activity and output per well. Associated natural gas production also increased because producers have been completing wells from their inventories of drilled but uncompleted (DUC) wells, which peaked in June 2020. Increases in both the number of natural gas-directed rigs and in associated natural gas production are expected to result in growing dry natural gas production in ourDecember STEO forecast.
Increasing investment in natural gas is a mistake, Sierra Club Wisconsin official warns - After the Biden administration announced plans last month to limit methane emissions, an official with the Sierra Club Wisconsin said it made "no sense" to tinker with gas regulations because much more dramatic changes are needed.Laura Lane, chair of Sierra Club Wisconsin, said the idea that utilities need more investment in gas power as a bridge from coal to renewable energy was a "myth.""It makes no sense to be dumping millions of dollars to build the infrastructure, to be dealing with more strict regulations," Lane said Thursday on WPR’s "The Morning Show." "We need to go with renewables and related technologies that are available."She agreed that strict regulations can help keep people safer because, "every part of getting gas — extraction, the processing, the shipping — it’s harmful."The Sierra Club Wisconsin with its Beyond Gas initiative lists why gas hurts the environment. The reasons include the high levels of carbon dioxide emissions that come from burning gas, air pollution and how gas plants disproportionately affect communities of color.Bill Skewes is the executive director for the Wisconsin Utilities Association, a lobbying group for the state’s gas and electric utilities. He told "The Morning Show" there is a needed but "sometimes uncomfortable tension" between his industry and environmental activists."That’s not necessarily a bad thing," he said. "But it does tend to move the needle of public policy faster than all the stakeholders at the table may want to go sometimes." Skewes said natural gas has about half of the greenhouse gas emissions than the coal units that utilities are trying to replace."That’s pretty big," he said, adding that utilities are "committed to a goal of being carbon neutral by 2050 — and some are even accelerating that."
Can U.S. phase out natural gas? Lessons from the Southeast - Even with the Biden administration’s call for the power sector to decarbonize, many Southeastern utilities plan to add large amounts of natural gas to their grids, a move they say is necessary to support renewable projects in the queue. The plans illustrate the challenge facing some U.S. regions as they aim to decarbonize: How can utilities move away from fossil fuels when they say natural gas is needed to back up renewables? Can gas lower emissions in the long run? Is it true that policies such as cancellation of the Keystone XL pipeline have raised gas prices? Will a reduction in gas lead to less grid reliability? Take the case of Atlanta-based Southern Co., which recently announced plans to shutter roughly half of its coal fleet, following guidelines from federal wastewater regulations for power plants (Energywire, Nov. 5). Alabama’s electricity powerhouse this fall told the state Public Service Commission it wanted to buy a 750-megawatt natural gas plant in Calhoun County, arguing that the generation is necessary to replace some of the coal that will be removed from the grid at the end of 2023. Absent that, what’s known as Barry Unit 5 will have to keep running to ensure system reliability, the company said in an Oct. 28 filing. Running that inefficient coal unit is more costly, not to mention produces higher emissions, the document said. “Alabama Power has a capacity need in the very near term, especially in 2023,” John Kelley, the company’s forecasting and resource planning director, said in written testimony to the PSC. “Calhoun can help meet this need if the resource is acquired by the target date in late 2022.” Environmental advocates are skeptical, however, that the electric company needs the replacement megawatts at all. If it does, “then Alabama Power should not be looking to replace it with another fossil fuel,” said Christina Andreen Tidwell, a senior attorney with the Southern Environmental Law Center. “Alabama Power seems to be doubling down on gas at a time where utilities should be pursuing lower-cost and less-risky renewable energy and energy efficiency options,” said Tidwell. SELC is representing Energy Alabama and the Greater Birmingham Alliance to Stop Pollution, or GASP, in this case. Similarly, with the Tennessee Valley Authority, critics frequently call out the federal agency for not cutting carbon emissions more aggressively, especially as President Biden has made fighting climate change a central part of his administration. Biden has called for decarbonizing the power sector by 2035.
Spire’s pipeline receives temporary reprieve to run until regulators decide its fate - Spire’s 2-year-old natural gas pipeline serving the St. Louis region will be allowed to continue running until federal regulators make a long-term decision about the project’s future, as they were ordered to do in a June court ruling that revoked the line’s approval.The 65-mile Spire STL Pipeline was granted an extension of a temporary operating permit Friday by leaders of the Federal Energy Regulatory Commission. The extension is set to last as long as it takes for the agency to reach its court-ordered conclusion on the project. The move should quell a recent stretch of strong rhetoric and public anxiety surrounding Spire’s information campaign warning of potential winter gas outages, given the pipeline’s uncertain future.Comments from the St. Louis-based gas utility have drawn widespreadaccusations of “fearmongering” from regulatory officials at FERC and the Missouri Public Service Commission, as well as from legal opponents at the Environmental Defense Fund, which launched the lawsuit against the pipeline project. FERC originally granted approval of the pipeline through a process that a unanimous panel of judges later blasted for multiple flaws. The judges cited an “ostrich-like approach,” including a failure to adequately demonstrate a need for the project. That decision, handed down over the summer, sent the matter back to FERC to chart a solution for the line and those it affects, such as Spire customers.
BP Gains MiQ Natural Gas Certification for Haynesville Wells in Texas - BP plc has become the latest major to differentiate its natural gas through MiQ, with the U.S. onshore business achieving a top grade for the methane emissions performance of some wells in the Haynesville Shale. bp MiQ’s independently audited certification system reviewed emissions in the Haynesville that are managed by BP’s Lower 48 arm BPX Energy Inc. MiQ helps operators differentiate themselves through methane-emissions performance. MiQ currently certifies about 10 Bcf/d, or around 2.5% of the global gas market and 11% of U.S. gas production. “Tackling methane emissions is vital for natural gas to play its fullest role in the energy transition,” said BPX’s Faye Gerard, vice president of Low Carbon and Sustainability. “We’re in action to reduce these emissions from our operations. MiQ’s certification helps validate the steps we’re taking and makes us even more confident we’re providing the energy the world needs with fewer emissions.” Possible Permian, Eagle Ford Certification BPX’s South Haynesville Facility in Texas produces about 0.2 Bcf/d. The 70 well sites were certified using the MiQ Standard, which grades a facility’s production from “A” to “F” based on its methane emissions. An A grade represents methane intensity of less than 0.05%, while F represents up to 2%. Third-party auditor GHD independently verified and awarded the top grade to the BPX facility. BPX now is “assessing further certification opportunities across its U.S. onshore operated portfolio” in the Haynesville, as well as the Eagle Ford Shale and Permian Basin. BPX said it provides certification data using a combination of advanced methane-monitoring technologies that include optical gas imaging cameras. The cameras are mounted to drones and fixed-wing aircraft, as well as ground-based cameras. BPX also uses data from field-measurement devices to quantify methane emissions from targeted sources. For each MMBtu of certified gas, MiQ is providing one certificate from the 70 wells that make up BPX’s South Haynesville Facility. The verifications are delivered to certified gas buyers and traders through BP’s account at the MiQ Digital Registry.
U.S. liquefied natural gas export capacity will be world’s largest by end of 2022 - U.S. liquefied natural gas (LNG) export capacity has grown rapidly since the Lower 48 states first began exporting LNG in February 2016. In 2020, the United States became the world’s third-largest LNG exporter, behind Australia and Qatar. Once the new LNG liquefaction units, called trains, at Sabine Pass and Calcasieu Pass in Louisiana are placed in service by the end of 2022, the United States will have the world’s largest LNG export capacity.The following new LNG export capacity additions will come online by the end of 2022, according to announced project plans:
- 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; the first export cargo from this train is expected to be shipped before the end of 2021.
- Calcasieu Pass LNG. This new export facility has 18 liquefaction trains with a combined peak capacity of 12 million metric tons per annum (1.6 Bcf/d). Commissioning activities at Calcasieu Pass LNG started in November 2021; the first LNG production is expected before the end of this year. All liquefaction trains are expected to be operational by the end of 2022.
The nameplate, or nominal, capacity of a liquefaction facility specifies the amount of LNG produced in a calendar year under normal operating conditions, based on the engineering design of a facility. Peak LNG production capacity is the amount of LNG produced under optimal operating conditions, including modifications to production processes that increase operational efficiency.In October 2021, the U.S. Federal Energy Regulatory Commission (FERC) approved requests to increase authorized LNG production at the Sabine Pass and Corpus Christi LNG terminals by a combined 261 billion cubic feet per year (0.7 Bcf/d). The terminals will achieve these increases by optimizing operations, including production uprates and modifications to maintenance.As of November 2021, we estimate that U.S. LNG nominal liquefaction capacity was 9.5 Bcf/d and peak capacity was 11.6 Bcf/d. This peak capacity includes uprates to LNG production capacity at Sabine Pass and Corpus Christi.By the end of 2022, U.S. nominal capacity is expected to increase to 11.4 Bcf/d, and peak capacity will increase to 13.9 Bcf/d, exceeding capacities of the two largest LNG exporters, Australia (which has an estimated peak LNG production capacity of 11.4 Bcf/d) and Qatar (peak capacity of 10.4 Bcf/d). In 2024, when construction on Golden Pass LNG—the eighth U.S. LNG export facility—is completed and the facility begins operations, U.S. LNG peak export capacity will further increase to an estimated 16.3 Bcf/d.The latest information on the status of U.S. liquefaction facilities, including expected online dates and capacities, is available in our database of U.S. LNG export facilities.
BP oil spill fund: $103m to projects in 3 Gulf states - Alabama, Florida and Mississippi are receiving more than $103 million in BP oil spill settlement money for new and continued coastal projects. “These projects, combined with existing investments, continue to advance our goal of protecting and restoring species and habitats impacted by the 2010 Deepwater Horizon oil spill,” The 11 new projects and two extensions from the foundation's Gulf Environmental Benefit Fund bring its total allocations across the five Gulf states to $1.6 billion, a news release said. Alabama is getting more than $43 million for four new projects, the foundation said. Florida is getting nearly $33 million for one new project. The remaining $27 million will support six new projects and continue two others in Mississippi. The Gulf Environmental Benefit Fund received $2.5 billion in settlement money from criminal charges against BP and its codefendants. The fund is for work to fix damage and reduce risks of future damage to natural resources affected by the 2010 Deepwater Horizon oil spill. Three of the new projects in Alabama are designed to stabilize eroding shorelines and restore coastal marsh in Mobile County and on the north side of Dauphin Island. Previous grants covered engineering, design and permitting for those projects. The fourth grant will pay for engineering and design of beach and dune restoration on Dauphin Island's west end. Florida plans to use its award to acquire and manage about 32,000 acres (13,000 hectares) of wetland and floodplain habitat in the Apalachicola watershed. That's aimed at ensuring sufficient freshwater and nutrient flow to Apalachicola Bay and the Gulf of Mexico to support oysters and marine fishes. Mississippi's new projects will expand and plan for future enhancements of artificial reefs across the Mississippi Sound and restore and protect vulnerable coastal habitats along the Mississippi Gulf Coast.
Envisioning the Effects of Big Oil and Gas Along the Texas Coast -All along the nearly 400-mile stretch of Texas’ Gulf Coast, nearly a dozen oil and gas export terminals are slated to come online within the next decade. In “The Export Boom,” reporter Amal Ahmed writes how this expansion of the United States’ oil and gas export industry has been a decade in the making. For this investigation, photographers Ivan Armando Flores and Jordan Vonderhaar worked to create a more comprehensive understanding of the extent to which liquified natural gas facilities impact their environments and our climate. Employing the use of long-exposure photography and light painting with the aid of a drone, they were able to impose the specter of industrialization on these pristine coastal environments. These images create an ahistorical record of the land and allow our readers to visualize clearly the impact and scale these facilities will have on the land.
Baker Reports Oil, Natural Gas Drilling Increases as Latest US Tally Rises - A result of gains in both oil and natural gas-directed drilling, the combined U.S. rig count climbed seven units to 576 for the week ended Friday (Dec. 10), according to updated figures from Baker Hughes Co. (BKR). shale count Four oil-directed rigs and three natural gas-directed units were added in the United States for the week, putting the overall domestic tally 238 units ahead of its year-earlier total, according to the BKR numbers, which are partly based on data from Enverus. Six U.S. rigs were added on land, along with one in the Gulf of Mexico. Eight horizontal rigs were added, partially offset by a one-rig decline in vertical units. The Canadian rig count fell three units to 177 for the week, up 66 rigs year/year. The three-rig net decline there was focused entirely in the oil patch. Broken down by major region, the Permian Basin led with an additional three rigs on the week, with the Cana Woodford and Eagle Ford Shale each adding two rigs. The Granite Wash and Utica Shale each added a rig, while the Arkoma Woodford and Barnett Shale each saw one rig exit for the period. In the state-by-state breakdown, New Mexico and Oklahoma each posted net increases of two rigs, while Louisiana, Ohio, Texas, Utah and West Virginia each added one rig overall. Alaska and Pennsylvania each dropped one rig week/week, according to the BKR data.
Fracking fears in Texas: Families fight natural gas fracking near day care center, homes amid health worries from drilling - — At a playground outside a North Texas day care center, giggling preschoolers chase each other into a playhouse. Toddlers scoot by on tricycles. A boy cries as a teacher helps him negotiate over a toy. Uphill from the playground, peeking between trees, 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 three wells and two existing ones would lie about 600 feet from where the children planted a garden of sunflowers. For families of the children and for others nearby, it’s a prospect fraught with fear and anxiety. Living near drilling sites has been linked to health risks, especially to children, ranging from asthma to neurological and developmental disorders. While some states are requiring energy companies to drill farther from day care centers, schools and homes, Texas has made it exceedingly difficult for local governments to fight back. The affected areas also include communities near related infrastructure — compressor stations, for example, which push gas through pipelines and emit toxic fumes, and export facilities, where gas is cooled before being shipped overseas. “I’m trying to protect my little one,” said Guerda Philemond, whose 2-year-old Olivia Grace Charles attends the day care center in Arlington. “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 an interview request. In a written statement, the company said it has operated near Mother’s Heart for more than a decade without any safety concerns expressed by the city of Arlington.
Permian Basin winter gas market faces pressure on maintenance, supply growth - Ongoing pipeline maintenance on El Paso Natural Gas, now extended indefinitely, promises to weigh on Permian Basin gas prices this winter as it limits egress capacity from West Texas. The continuing maintenance could also magnify emerging supply pressure in the Permian that has come amid a recent surge in production and drilling activity there. In a critical notice published Nov. 30, El Paso told shippers that it does not yet have a definitive timeline for returning its Line 2000 back to full commercial service. The pipeline’s westbound mainline, a critical transmission corridor for Permian Basin gas flowing into Southern California, is now expected to remain out of service for several months, El Paso said. The critical notice updates El Paso’s original force majeure declaration posted Aug. 15 when the pipeline failure on Line 2000 first occurred near Coolidge, Arizona. El Paso advised that repair work and diagnostic inspections continue and that the incident remains under investigation by the NTSB. SoCal, West Texas impacts Since its announcement in August, the force majeure and subsequent maintenance on El Paso has mostly affected the southern California gas market by limiting its access to Permian Basin supply. Following the announcement of El Paso’s Line 2000 maintenance in August, westbound flows from the Permian immediately dropped by some 500 to 600 MMcf/d in response to the new capacity restrictions. In part, the force majeure helped to fuel a spectacular rise winter gas prices at the SoCal Gas city-gate to over $13/MMBtu as traders became increasingly concerned over the restrictions on West Texas supply. Following a subsequent move by the California Public Utilities Commission, though, temporarily expanding the region’s storage capacity at Aliso Canyon, the SoCal Gas market has since cooled. In the Permian Basin, meanwhile, ample transmission capacity to the Texas Gulf Coast, the US Midcontinent and to Mexico allowed production and prices in West Texas to remain relatively unscathed by the reduction in westbound capacity on El Paso. More recently though, an uptick in production and drilling activity in the Permian has raised doubts over the basin’s capacity to simply absorb more supply without no, or only limited, impact on prices.
Oil traders take a long-shot bet on a possible U.S. oil export ban --Oil traders are scooping up options contracts that would pay out if U.S. crude futures plummet against international benchmark Brent, a signal that some believe the Biden administration could intervene in the market again to bring down oil prices. Some traders have bet on the small chance that West Texas Intermediate’s discount to Brent surges past $10 a barrel next year. The last time the spread traded near $10 was in 2018 and 2019 when severe pipeline constraints trapped barrels in the Permian Basin - the largest oilfield in the country. The spread was trading around $3.60 a barrel Tuesday. The oil market has been volatile as top consuming nations came together in an unprecedented move last month to release crude from their emergency reserves and bring down energy costs. The Biden Administration’s ongoing focus on lowering gasoline prices has now prompted some traders to purchase some contracts that could pay out just in case they takes further steps, such as limiting or pausing crude exports. Even if the spread between the benchmark contracts - a key indicator for pricing imports and exports - doesn’t widen all the way to $10, the options could still pay out marginally. The options also act as protection for physical traders who could risk losing millions of dollars on a cargo if the U.S. suddenly bans exports. While small in volume, the option trades have popped up consistently over the past week. Since last Tuesday, the equivalent of 11.25 million barrels have changed hands, with 10.1 million barrels of brand new positions being opened, betting on the chance that the premium of Brent to West Texas Intermediate crude futures surges past $10 a barrel next year. Most traders believe an outright ban on U.S. exports is unlikely, making the trades akin to buying a lottery ticket. A halt in exports would trap more oil in the U.S. and pressure domestic prices as local refiners are not designed to process the type of light crude produced at home efficiently.
Exxon Mobil Aims for Net-Zero Emissions in Permian Basin - NYTimes— Exxon Mobil said on Monday that it aimed to achieve net-zero greenhouse gas emissions from its operations in oil and gas fields in West Texas and New Mexico by 2030.The announcement is part of Exxon’s previously stated plans to reduce greenhouse gas emissions across its business, as activists and some investors pressure the oil industry to do more to fight climate change. But Exxon’s goal does not include offsetting emissions from its customers, such as car and truck owners and airlines. Exxon, the nation’s largest oil company, said it would reach net-zero emissions in the Permian Basin, which straddles the two Southwestern states, by electrifying its operations, improving its ability to detect and capture methane gas and eliminating the routine burning of waste gas emitted from oil wells. The company said it might also employ “nature-based solutions,” which could include planting trees.
ExxonMobil plans to end routine flaring, cut all emissions in Permian Basin by 2030 - Global energy giant ExxonMobil vowed to completely cut its greenhouse gas emissions from oil and gas operations in the Permian Basin by 2030. The company also pledged to end routine flaring by the end of 2022, electrify operations in New Mexico and Texas and increase monitoring for methane releases while upgrading equipment to avoid emissions. Exxon’s plans in the Permian were part of company-wide commitment to reduce emissions intensity, referring to the amount of emissions per facility, by 40 to 50 percent by 2030, compared with 2016 levels. More: Multi-million-dollar oil and gas deals in the Permian Basin mark recovery from COVID-19 At the end of 2021’s third quarter, Exxon reported it produced 530,000 barrels of oil per day in the Permian, accounting for 40 percent of the company’s U.S. production. Company officials said that as fuel demand grows and production increases, so too would greenhouse gas mitigation. Chief Executive Officer Darren Woods said the Nov. 6 announcement was part of a company-wide strategy to reduce the oil and gas leader’s impact on climate change. “Our groundbreaking plans to reach net zero for Permian Basin operations further demonstrate our commitment and support of society’s ambitions for a lower-emissions future,” Woods said. “We have plans to reduce greenhouse gas emissions intensity across our businesses by deploying the capabilities and technical strengths that are foundational to ExxonMobil.” Electrification of ExxonMobil’s facilities in the Permian – one of the nation’s most active oilfields spanning southeast New Mexico and West Texas – would use “low-carbon power,” read a company news release, that could include renewable energy like wind and solar power. The company also said it could use hydrogen power for its facilities, or natural gas using carbon capture and storage technologies.
Locked out ExxonMobil workers make noise at world petroleum conference -World and oil industry leaders have gathered for the World Petroleum Congress in Houston for discussions that could shape the future of global energy, and Southeast Texas is making sure it has its own kind of representation outside the security lines around the George R. Brown Convention Center.For almost 90 years, the WPC periodically has been convening across the world to host debates and dialogue about oil and gas and returned to the United States on Sunday for the first time in more than 30 years.When attendees entered into the convention center Monday, they also heard opinions from United Steelworkers Union representatives and workers from the ExxonMobil Beaumont refinery who were gathered around the meeting place.The USW and other unions gathered in solidarity to protest, drawing attention to the more than eight-month-old lock out of ExxonMobil workers at the company’s refinery and lube complex in Beaumont.USW District 13 Representative Bryan Gross said the group of workers were trying to send a message to the company’s CEO, Darren Woods, hoping he might direct the company back to the negotiating table.“There is no reason to continue hurting these families with the lockout, especially with the holidays coming up,” Gross said. “We can continue bargaining outside of that, and we need to get our people back to work. It’s hurting families and the local economy.”
WPC 2021: ConocoPhillips CEO says U.S. government holds back oil supply --In the debate over why U.S. oil producers haven’t added additional supply, the boss of ConocoPhillips lays the blame squarely with the government. An increasingly bitter war of words has developed between the Biden administration, which has called for more production to alleviate high energy prices, and an U.S. oil and gas sector that has kept output relatively flat while criticizing White House regulatory moves. “There’s no fast way to return supply,” ConocoPhillips Chief Executive Officer Ryan Lance said Tuesday in a Bloomberg Television interview from the World Petroleum Congress in Houston. “But if you get a stable, transparent system here in the U.S., and manage through the uncertainties, then we will invest to grow, not at the expense of returns, but there is some growth that can come out of U.S.” President Joe Biden campaigned on a pledge to ban new fracking on federal lands, and more recently his administration has focused on clamping down on the industry’s emissions of methane, a far more potent greenhouse gas than carbon dioxide. The House Science Committee last week requested that Houston-based ConocoPhillips and none other leading U.S. producers share data on methane leaks. Lance said that’s another example of unnecessary regulatory burden, and that in his view the industry is already making strides in self-regulating when it comes to methane.
Top US Shale CEO "Worried" Years Of Underinvestment Could Boost Oil Over $100 -After half a decade of U.S. oil drillers underinvesting in projects and returning money to shareholders, it could take years to resume pre-pandemic production levels that could further roil oil markets for years to come. "I'm worried that it may get too high, above $100 (per barrel)," according to Scott Sheffield, CEO of shale explorer Pioneer Natural Resources Co., who was speaking to Reuters in an interview at the Petroleum Congress in Houston on Tuesday. "I hope it stabilizes between an $80 to $100 range over the next several years. We need stability in the oil markets," he said. Sheffield said U.S. oil production would only increase by 3% annually because oil companies return cash to shareholders rather than boost CAPEX. In that case, he added oil prices would continue to bid more than $70 a barrel for the foreseeable future. He was mind-boggled last month when the Biden administration requested OPEC to increase crude output to suppress prices, overlooking U.S. oil/gas companies. "The Biden administration called up OPEC to increase production and didn't ask the U.S. to do it," he said. Sheffield's outlook differs drastically from the Biden administration, desperately trying to squash oil prices amid plunging poll numbers due to high inflation ahead of the midterms.
U.S. cuts oil demand, price forecasts on Omicron concerns --The Biden administration’s efforts to lower energy costs may have gotten unexpected help from the latest coronavirus variant. As a result of travel restrictions following the outbreak of the omicron variant of Covid-19, the Energy Information Administration cut its projections for both global benchmark Brent and U.S. crude futures by nearly $2 a barrel for 2022, according to the Short-Term Energy Outlook. The agency also lowered its outlook for consumption of petroleum and liquid fuels in the fourth quarter and first quarter while raising its forecast for oil output from OPEC+ and the U.S. The latest forecast comes as the Biden Administration continues to focus on lowering gasoline prices and just after decision from OPEC and its allies to proceed with a scheduled oil-production hike. The producer group left the door open to changing the plan on short notice due to the uncertainty surrounding the impact of the omicron variant of Covid-19 on oil demand. Meanwhile, the U.S. pushed ahead with its planned release of strategic oil in an exchange program for which bids were closed Monday. The EIA softened its outlook on petroleum and liquid fuels demand by over half a million barrels a day to 99.3 million from its previous forecast for the first quarter. It revised its demand estimate lower for the current quarter as well on rising Covid-19 cases in the last month that prompted renewed mobility restrictions in Austria, Ireland and the Netherlands, and several other guidelines in the rest of Europe. Globally, output is set to average 100.93 million barrels a day in 2022, leaving the market in a surplus for the year. The agency now expects Brent to average $70.05 a barrel next year. Its projections for West Texas Intermediate were lowered to $66.42 a barrel, the report said. Meanwhile, the EIA lowered slightly its crude oil production forecast next year to 11.8 million barrels a day while adjusting it slightly higher for 2021.
PRC rejects PNM/Avangrid merger The New Mexico Public Regulation Commission essentially denied the merger between Avangrid and Public Service Company of New Mexico on Wednesday.. The commissioners voted unanimously on Wednesday to reject the stipulated agreement, following a recommendation from the PRC hearing examiner that the potential risks to customers outweigh the benefits. “This whole deal to me kind of boils down to promises versus actual performance,” Commission Chairman Stephen Fischmann said, highlighting Avangrid’s past performance in New England where it owns several utilities and has faced more than $60 million in fines from regulators. PNM and Avangrid promoted the merger as an opportunity to transition faster away from fossil fuels through access to Avangrid’s better credit ratings as well as benefits associated with Avangrid’s scale. Avangrid’s large size could lead to lower costs for equipment because the company would be able to buy in bulk. But several commissioners said the merger is not the way to approach the transition. The commissioners expressed concerns that the merger could lead to higher rates for customers and decreased reliability. While the rate increases would require approval from the commission, the PRC had concerns that if the merger was approved PNM could favor Avangrid resources during the procurement process, which could lead to higher rates.
Biden tribal policy would shake up energy law on public lands - New initiatives from the Biden administration to expand the influence of Indigenous tribes could bolster legal opposition to energy projects on public lands. In the first Tribal Nations Summit since 2016, President Biden this month committed to, among other things, pursue more collaborative public lands management strategies with tribes and incorporate traditional ecological knowledge into federal agencies’ scientific analysis of projects. "We’re going to make some substantial changes in Indian Country," Biden said during the virtual event. The same day, the government released a memorandum of understanding signed by 17 federal agencies agreeing to increase consultation and collaboration, in recognition of existing treaty obligations between the United States and tribal nations. The announcements drew praise from Indian and environmental law experts, who saw the change as an important step for the Biden administration in improving relations between sovereign tribes and the United States. The agreement, signed by agencies such as EPA and the Interior and Agriculture departments, is not legally binding, so it cannot by itself serve as the basis of a legal challenge to federal approval of energy projects on treaty lands. But the agreement could help tribes hold the federal government legally accountable to its commitments to treat tribes as an equal partner in energy development on public lands. The Biden administration’s pronouncements "may be relevant if there is litigation down the road, even if the tribe wouldn’t be able to just say, ‘You violated this [memorandum of understanding], and therefore, we’re suing you, and we win,’"
Biden Administration Is ‘Rubber Stamping’ Oil and Gas Permits on Public Land, Activists Say - The Biden administration came under fire last month for overseeing the largest offshore oil and gas leasing sale in U.S. history. Now, a new report suggests this wasn’t an isolated incident. The analysis from Public Citizen reveals that the new administration has issued more permits for oil and gasdrilling on public lands per month than the Trump administration did in its first three years, as Yahoo News reported. “When it comes to climate change policy, President Biden is saying the right things. But we need more than just promises,” study author Alan Zibel told The Independent.Public Citizen looked at federal public lands drilling permit data and found that the government had approved an average of 336 permits per month in 2021. Excluding January 2021, when former President Donald Trumpremained in office for most of the month, that’s 333 permits per month while President Joe Biden was in charge. The average is a more than 35 percent increase from when Trump took office in 2017 but is down by more than 25 percent from the average for 2020. Biden promised in his campaign to ban new oil and gas leasing in public lands and waters and issued a moratorium on the practice, but this was struck down by a judge in June of 2021. However, the permits covered in the new analysis are not new sales but rather permit approvals for previous sales, Yahoo News pointed out. “Certainly, the deck is stacked against the Biden administration when it comes to leases that have been sold in the past,” Jesse Prentice-Dunn, policy director at the Center for Western Priorities, told Yahoo News. “However, it doesn't have to be a complete rubber stamp. The administration can ask companies to go back to the drawing board if they haven't done a full environmental analysis of what the impacts could be.”Prentice-Dunn noted that the Biden administration had approved 98 percent of the permits it had reviewed through the end of September, even more than the Trump administration’s 2020 approval rate of 94 percent.“If 98 percent approval isn’t a rubber stamp, I don’t know what is,” Prentice-Dunn said.
Biden continues where Trump left off with oil drilling permits: report - President Joe Biden is approving more oil and gas drilling permits each month than Donald Trump did during the first three years in the White House, according to new research. Among President Biden’s “Day One” campaign promises was not only to reverse the environmental damage wreaked by the previous administration but make progress on an ambitious agenda that would tackle the climate crisis and rampant pollution. Part of Mr Biden’s pledge was to conserve “America’s natural treasures” by permanently protecting areas impacted by President Trump’s “fire sale” along with “banning new oil and gas leasing on public lands and waters”. However analysis of federal data, published on Monday by progressive think tank Public Citizen, showed that excluding January 2021 – when Mr Trump remained in office until the 20th – the Bureau of Land Management (BLM) approved an average of roughly 333 drilling permits per month. This number is more than 35 per cent higher than when Mr Trump took office in 2017. Under the Biden administration, monthly permit approvals by BLM, the federal agency which leases public lands to oil and gas corporations, peaked at 652 in April. They have been below 2020 levels since the summer after falling under 300 in July. Mr Biden heralded America’s climate progress at the Cop26 summit in Glasgow last month. He underlined the importance of his clean energy agenda as the US suffers an ever-worsening cycle of disasters linked to global heating driven by the burning of fossil fuels. “We’ll demonstrate to the world the United States is not only back at the table but hopefully leading by the power of our example,” Mr Biden said in Glasgow. Days after Cop26 ended, the Biden administration auctioned off drilling permits to the fossil fuel industry across 1.7m acres in the Gulf of Mexico. “When it comes to climate change policy, President Biden is saying the right things. But we need more than just promises,” said Alan Zibel, the new study’s author. Emissions from burning and extracting fossil fuels from public lands and waters account for about 25 per cent of domestic carbon emissions, according to the US Geological Survey. Earthjustice contends that government officials violated federal law by relying on a flawed and out-of-date environmental analysis from 2017, while ignoring new information about the severity of the climate crisis. “The administration is legally obligated to evaluate this information before taking any action,” the environmental law organisation said in a statement last month. Fossil fuel corporations including Shell, BP, Chevron and ExxonMobil were able to bid in the November lease sale which could keep them actively pumping oil in the Gulf for many years.
Biden Promised to Stop Oil Drilling on Public Lands. Is His Failure to Do So a Betrayal or a Smart Political Move? - As a candidate, President Joe Biden never embraced the strict curbs on fossil fuel development that progressives sought, like a ban on fracking. But his climate plan included a clear pledge to halt any further advance of the oil and gas industry on federal lands or offshore.“Banning new oil and gas permitting on public lands and waters” and “modifying royalties to account for climate costs” were two steps Biden said he would take if elected, to help put the nation on track to net-zero greenhouse gas emissions by 2050. Environmentalists were enthusiastic about these proposals because Biden wouldn’t need Congressional approval; the president could just invoke the Department of Interior’s broad authority to manage federal lands. So green groups said they were deeply disappointed when Interior Secretary Deb Haaland released the roadmap for the future of federal oil and gas leasing the day after Thanksgiving. The document proposed little change beyond raising the fees that the industry must pay to extract resources on public lands and requiring companies to increase their insurance coverage—proposals already under consideration in Congress, although opposed by industry.“Our biggest criticism is simply that it basically ignores the elephant in the room, which is climate change,” said Joshua Axelrod, senior advocate for the Natural Resources Defense Council’s nature program. He said the reforms proposed are indeed necessary—royalty rates have not changed since the 1920s—but they don’t go nearly far enough, at a time when the president says he wants every government agency to be acting to slash carbon emissions. “We’re at a critical juncture on climate,” said Axelrod. “At the very least, it would have been nice to see some recognition of that, even if they didn’t propose any definite policy changes. The lack of it is a major disappointment.” But some observers argue that from a climate perspective, the administration had little to gain and a lot to lose politically by going forward with a ban on new federal leasing at this time. Oil and gas from federal lands and offshore has become a smaller portion of U.S. production over the last 18 years, while drilling on private land has soared. A ban on new leasing would not make a significant dent in U.S. greenhouse gas emissions, they say, but it would stir up a political firestorm that would hurt Biden and other Democrats, especially in two swing states with substantial federal oil and gas leasing, New Mexico and Colorado.
Biden’s oil reserve sale attracts foreign bidders --The Biden administration’s efforts to lower energy costs takes a step forward Monday, with bids due for the first 32 million barrels of crude planned for release from federal stockpiles. Bids for the exchange offer, which is the first part of government’s 50 million-barrel release from the Strategic Petroleum Reserve, were due at 10 a.m C.T., the Department of Energy said when it first announced the release last month. Although winning bids won’t be announced until Dec. 14, at least two international oil refiners have expressed interested in the swap, according to people familiar with the matter. The release is part of the Biden Administration’s effort to lower energy costs and tackle surging gasoline prices, which touched a seven-year high last month. Crude futures have dropped about 20% since late October, when the U.S. indicated it was considering a variety of tools to bring down fuel prices. The reserve is typically tapped when natural disasters disrupt the flow of oil. U.S. refiners and international oil companies are expected to make up the majority of the participants. Most of the oil being released is high in sulfur and costs more to refine because it requires hydrogen produced from natural gas to run units to strip it of sulfur. U.S. oil processors particularly in Texas, America’s refining hub, are subject to year-end taxes on their oil stocks and may limit appetite there to add barrels to storage. “Taxes on U.S. inventories may discourage refiners from adding inventories in December,” said Chris Barber, principal analyst at consultant ESAI. “China and India do process sour crude and that is what many of their refineries are configured to do. It’s just more expensive to do with high prices natural gas,” Barber said. “I think high gas prices will make SPR barrels less attractive for China and India unless heavily discounted.”
Energy Transfer Boosts Natural Gas, Oil Capacity with Enable Acquisition Completed - Dallas-based Energy Transfer LP owns and operates another 14,000 miles of natural gas and oil pipeline in Arkansas, Louisiana, Oklahoma and Texas after completing its merger earlier this month with Enable Midstream Partners LP. The $7.2 billion tie-up, first announced in February, strengthens the midstream and gas transportation systems in the Anadarko Basin in Oklahoma, along with intrastate and interstate pipelines in Oklahoma and surrounding states. The merger also boosts Energy Transfer’s gas gathering and processing assets in the Arkoma Basin across Oklahoma and Arkansas, as well as in the Haynesville Shale in East Texas and North Louisiana. Altogether, Energy Transfer said it has more than 114,000 miles of pipelines and other infrastructure. Enable’s assets include about 14,000 miles of natural gas, crude oil, condensate and produced water gathering pipelines, around 2.6 Bcf/d of natural gas processing capacity and roughly 7,800 miles of interstate pipelines. Its portfolio also includes around 2,200 miles of intrastate pipelines and seven natural gas storage facilities comprising 84.5 Bcf of storage capacity. When the deal was announced, Energy Transfer said it could build off the combination to increasingly meet global demand for U.S. liquefied natural gas (LNG) exports. “Energy Transfer will further enhance its connectivity to the global LNG market and the growing global demand for natural gas as the world transitions to cleaner power and fuel sources,” it said at the time. Enable received federal approval in June to construct the Gulf Run natural gas pipeline. The $540 million pipeline project is backed by a 20-year commitment for 1.1 Bcf/d from cornerstone shipper Golden Pass LNG. Gulf Run is expected to be placed into service in late 2022. Golden Pass is underway in Sabine Pass on the upper Texas coast. Energy Transfer, meanwhile, continues to face setbacks in its bid to expand the controversial Dakota Access oil pipeline. The pipeline subsidiary in September asked the U.S. Supreme Court to weigh in on the case.
Rural Minnesota hit hard by high cost of propane - Minnesota Reformer— The cost of propane hasn’t been this high in nearly a decade, up more than 60% from last year alone, forcing consumers to spend hundreds of dollars more this winter to heat their homes.Virtually every household can expect to pay more for heat this winter, but the pain will be especially acute for people who rely on propane. The average cost of propane in the Midwest is $2.37 a gallon, up more than a dollar from this time last year, according to the U.S. Energy Information Administration.Swings in propane prices are felt more broadly in Minnesota, where 10% of households use propane to heat their homes, more than twice the national rate. Propane use is even more common in rural areas where people can’t access natural gas, which is generally more cost-effective than propane.Thirty percent of households in Pine County are heated with propane, while in a handful of other counties, more than 40% of households do so.And unlike electricity and natural gas, propane prices aren’t regulated by the state’s Public Utilities Commission, so consumers pay what the market demands.
What’s next for the Line 5 court battles? --Since mid-2019, Canadian pipeline company Enbridge and the state of Michigan have been locked in numerous court disputes about the fate of the controversial Line 5 pipeline that has transported oil under the environmentally sensitive Straits of Mackinac since 1953. Until last week, the first and primary legal battle had been on pause since January, as a federal court deliberated and ultimately ruled against Gov. Gretchen Whitmer’s attempt to keep her shutdown lawsuit against Enbridge in state court. Options are whittling down for the governor and Attorney General Dana Nessel, who both ran on platform promises to decommission Line 5. Essentially, just one option for the Democrats remains, aside from smaller lawsuits and bold, seemingly unlikely actions from a federal regulatory agency and/or President Joe Biden. In an interview with Attorney General Dana Nessel last week, the Advance asked about the state’s new strategy for shutting down Line 5, how things will now proceed in the court system and what certain court decisions or slowdowns might mean for the fate of the pipelines. “I will say that the governor remains just as committed now as she’s ever been to shutting down Line 5 and to averting what could be, obviously, a cataclysmic oil spill in the Great Lakes. But, from a strategy standpoint, it just made sense to pursue one [legal] track,” Nessel said Wednesday.
Enbridge says aggressive climate policies shortening life of its pipelines - Faced with growing uncertainties over the future of fossil fuels, Enbridge wants to cut by a decade the estimated economic life span of its Upper Midwest pipeline system, which includes the newly built Line 3. Enbridge's acknowledgement of growing climate policy pressure on its pipelines' longevity came in federal regulatory filings earlier this year. Last week, Indigenous environmental group Honor the Earth asked Minnesota regulators to "promptly" start setting up a decommissioning fund for new Line 3, given a possible shorter-than-expected life span. Enbridge maintains that its controversial new Line 3 oil pipeline in Minnesota will have a 30-year economic life extending to 2051, regardless of the new life span analysis of its pipeline system that pegs 2040 as an ending point. Assets can continue to operate well beyond their originally scheduled economic life; Enbridge has oil pipelines running through Minnesota and other states that date back to the 1950s. The new Line 3, completed in October, replaces a 1960s pipeline. As part of its approval of the Line 3 project, the Minnesota Public Utilities Commission mandated a decommissioning fund for the pipeline's eventual demise. However, the fund has not been established, nor have any details on how much money Enbridge must pay into it. "We thought it was useful to put some pressure on them," said Paul Blackburn, an attorney for Honor the Earth. Enbridge said in a statement it is awaiting direction from the PUC on the decommissioning fund. The PUC said in a statement that "there is no requirement that the trust fund be established or funded on a specific timeline." The commission said, however, that last week it created a docket specifically to move forward on the issue. When new Line 3 was proposed, Calgary, Alberta-based Enbridge said it would have an economic life of at least 30 years. Economic life marks how long an asset will be useful and profitable — and over how many years its costs will be depreciated. In May, consultants for Enbridge prepared a "technical depreciation update" for the company's Lakehead pipeline system. The Lakehead system — the largest conduit of Canadian oil into the United States — includes six pipelines across Minnesota and several more in Wisconsin and other states. Enbridge's consultants, looking at the Lakehead system as of 2020, calculated that generally its economic life would be "truncated" as of Dec. 31, 2040, according to a document filed with the Federal Energy Regulatory Commission (FERC). That truncation date was based on expectations of increasing competition to Enbridge's system combined with "uncertainty" from a rising tide of "decarbonization" legislation in Canada and the U.S., according to another document filed with FERC. The filing specifically noted President Joe Biden's "detailed climate plans" to achieve a 100% clean energy economy by 2050 and Canada's plans for a four-fold increase in its carbon taxes by 2030..
Big Oil cautions against disruptive energy transition -The chief executives of the two largest U.S. oil companies on Monday reiterated their beliefs that the world will continue to rely on fossil fuels for years, if not decades, to come — even as society shifts toward cleaner forms of energy. Exxon Mobil CEO Darren Woods and Chevron CEO Mike Wirth told thousands of attendees at the first full day of the World Petroleum Congress in downtown Houston that they shared the world’s concerns about climate change and touted their efforts to reduce their carbon emissions. While European oil majors have expanded into wind and solar power to prepare for a low-carbon future, Exxon and Chevron are investing heavily in carbon capture and storage, hydrogen and biofuels, reflecting their beliefs that fossil fuels will remain the world’s choice for affordable and reliable fuel — as long as they can mitigate harmful carbon emissions. “The growth of emissions-free energy is good for society and an objective our company supports,” Woods said. “The fact remains that under most critical scenarios, including net-zero pathways, oil and natural gas will continue to play a significant role in meeting society’s needs.” A debate over the future of fossil fuels is playing out at the World Petroleum Congress, the triennial energy conference that brings together the world’s energy ministers and professionals for a week of panel discussions and trade exhibits. The conference, held in Houston for the first time in three decades, was postponed last year because of the pandemic. About 5,000 attendees are expected this year, about half of the 10,000 attendees anticipated before the coronavirus spread in early 2020. As economic activity and travel recovers from the pandemic, the sharp uptick in demand for gasoline and jet fuel hasn’t kept up with crude production, causing gasoline prices in the U.S. and natural gas prices in Europe and Asia to skyrocket in recent months. High fuel prices have forced the climate-minded Biden administration to urge OPEC to boost production, and European countries to appeal to Russia to supply more natural gas to ensure adequate winter supplies. Chevron’s Wirth pointed to these energy price shocks as evidence of fossil fuels’ staying power. “The world needs affordable, reliable and ever cleaner energy every day. It’s indispensable in today’s global economy,” Wirth said. “Our products make the world run, and we can make it run even better.” Woods cautioned against a disruptive energy transition that would create shortages and boost prices, adding that many people take for granted the benefits of fossil fuels, which provided the low-cost energy that helped create modern society. They also forget the billions of people in developing countries who lack access to affordable energy that could help provide them with higher standards of living.
Top Republicans Introduce Bill Forcing Biden To Boost US Oil, Gas Production --A group of top House Republicans introduced a bill Thursday that would force President Joe Biden to increase domestic oil and gas production when he taps the nation’s emergency stockpile.The Strategic Production Response Act would require the Department of Energy to develop a plan for fossil fuel extraction on federal lands every time the government taps the Strategic Petroleum Reserve (SPR) for non-emergency purposes, the Republicans announced. The bill is a companion to one that was introduced by Senate Energy and Natural Resources Committee Republicans on Dec. 1.“The Strategic Petroleum Reserve was created by Congress to respond to oil supply disruptions that may arise after a natural disaster or war,” Energy and Commerce Committee Ranking Member Cathy McMorris Rodgers, one of the bill’s sponsors, said in a statement. “The SPR is not supposed to be tapped as a bailout for the President’s anti-fossil fuel agenda, which has led to the highest gas prices in seven years.”“Releasing oil from the Strategic Petroleum Reserve is not a long-term solution to help hard-working families devastated by these failed policies,” Rodgers said.On Nov. 23, Biden ordered the Energy Department to release 50 million barrels of crude A group of top House Republicans introduced a bill Thursday that would force President Joe Biden to increase domestic oil and gas production when he taps the nation’s emergency stockpile.The Strategic Production Response Act would require the Department of Energy to develop a plan for fossil fuel extraction on federal lands every time the government taps the Strategic Petroleum Reserve (SPR) for non-emergency purposes, the Republicans announced. The bill is a companion to one that was introduced by Senate Energy and Natural Resources Committee Republicans on Dec. 1.“The Strategic Petroleum Reserve was created by Congress to respond to oil supply disruptions that may arise after a natural disaster or war,” Energy and Commerce Committee Ranking Member Cathy McMorris Rodgers, one of the bill’s sponsors, said in a statement. “The SPR is not supposed to be tapped as a bailout for the President’s anti-fossil fuel agenda, which has led to the highest gas prices in seven years.”“Releasing oil from the Strategic Petroleum Reserve is not a long-term solution to help hard-working families devastated by these failed policies,” Rodgers said.On Nov. 23, Biden ordered the Energy Department to release 50 million barrels of crude oil from the SPR in an effort to halt surging gasoline prices ahead of Thanksgiving. Oil prices, a key factor in determining gas prices, quickly rose after the announcement, however.
How ‘Big Oil’ Works the System and Keeps Winning --Despite countless investigations, lawsuits, social shaming, and regulations dating back decades, the oil and gas industry remains formidable. After all, it has made consuming its products seem like a human necessity. It has confused the public about climate science, bought the eternal gratitude of one of America’s two main political parties, and repeatedly out-maneuvered regulatory efforts. And it has done all this in part by thinking ahead and then acting ruthlessly. While the rest of us were playing checkers, its executives were playing three-dimensional chess. Take this brief tour of the industry’s history, and then ask yourself: Is there any doubt that these companies are now working to keep the profits rolling in, even as mega-hurricanes and roaring wildfires scream the dangers of the climate emergency? […] Here’s a final example of how the oil and gas industry plans for the next war even as its adversaries are still fighting the last one. Almost no one outside of a few law firms, trade groups, and congressional staff in Washington, DC, knows what the Federal Energy Regulatory Commission is or does. But the oil and gas industry knows, and it moved quickly after Donald Trump became president to lay the groundwork for decades of future fossil fuel dependency.FERC has long been seen as a rubber stamp for the oil and gas industry: The industry proposes gas pipelines, and FERC approves them. When FERC approves a pipeline, that approval grants the pipeline eminent domain, which in effect makes the pipeline all but impossible to stop.Oil and gas industry executives seized upon Donald Trump’s arrival in the White House. In the opening days of his administration, independent researchers listened in on public trade gatherings of the executives, who talked about “flooding the zone” at FERC. The industry planned to submit not just one or two but nearly a dozen interstate gas pipeline requests. Plotted on a map, the projected pipelines covered so much of the U.S. that they resembled a spider’s web. Once pipelines are in the system, companies can start to build them, and utility commissioners in every corner of America see this gas “infrastructure” as a fait accompli. And pipelines are built to last decades. In fact, if properly maintained, a pipeline can last forever in principle. This strategy could allow the oil and gas industry to lock in fossil fuel dependency for the rest of the century.
North Dakota’s natural gas producers meet the state’s natural gas capture target - (EIA) - In North Dakota, the rate of natural gas flaring (which is natural gas burned at the wellhead of the production site rather than being captured) declined to an average of 7.5% this year through September. This decline in natural gas flaring resulted in producers capturing 92.5% of produced natural gas, which meets the state’s goal to capture 91% of the natural gas produced in the state. In early 2020, natural gas production fell rapidly as a result of COVID-19-related impacts, from 3.2 billion cubic feet per day (Bcf/d) in March to 1.9 Bcf/d in May, but returned to pre-pandemic levels almost as rapidly, reaching 2.9 Bcf/d by October of the same year. From April 2020 to September 2021, producers met the state capture target for every month except July 2021.In July 2014, the North Dakota Industrial Commission adopted natural gas capture targets in response to increased natural gas flaring in the state’s Bakken and Three Forks formations. The rapid development of hydrocarbon resources in North Dakota, especially crude oil, over the past decade has outpaced the ability of regional infrastructure to process and transport associated natural gas from crude oil production. Flared natural gas produced from oil wells increased as a result of inadequate gathering and processing infrastructure. In 2013, the year before natural gas capture targets took effect, more than 30% of the natural gas produced in North Dakota was flared.Meeting the capture targets required a buildout of natural gas gathering lines to transport natural gas from wells to processing plants and a buildout of the processing plants that remove impurities and heavier hydrocarbons from the natural gas. The North Dakota Industrial Commission reports that natural gas processing capacity in the state increased from 1 Bcf/d in 2013 to 3.4 Bcf/d in 2020, and they expect it to exceed 4.0 Bcf/d by the end of 2021.Expanded pipeline capacity to move natural gas plant liquids (NGPLs) out of the state has further improved North Dakota’s midstream infrastructure. NGPLs must be separated from the raw natural gas before the natural gas can enter interstate pipelines. This process requires a dedicated pipeline network that moves the mixed NGPLs to fractionation plants where the mix is separated into its individual components, such as ethane and propane.Without an outlet for NGPLs, natural gas processing plants cannot process raw natural gas. According to ourLiquids Pipeline Projects Database, the pipeline capacity to move NGPLs out of the North Dakota production region increased from 60,000 barrels per day (b/d) in 2013 to more than 580,000 b/d as of September 2021.
Criminal case for largest oil field spill in North Dakota history resolves with $15M fine, probation Summit Midstream Partners entered into a $36 million settlement agreement with the federal government and the state of North Dakota earlier this year after an investigation found the company allowed nearly 30 million gallons of contaminated water to spill in western North Dakota in 2014 and 2015. — A federal judge sentenced the company responsible for North Dakota's largest ever oil field spill to $15 million in criminal fines and three years of probation on Monday, Dec. 6.The sentence for Summit Midstream Partners was entered by U.S. District Court Judge Daniel Traynor and comes three months after the U.S. Department of Justice and the state of North Dakota announced a settlement agreement with the company totaling more than $36 million in criminal and civil penalties and natural resource damages.Federal prosecutors charged Summit for negligence and violations of environmental laws in the spill of 29 million gallons of produced water — a highly concentrated salt fluid that is a byproduct of oil extraction — north of Williston over a five-month period in 2014 and 2015. The incident resulted in the contamination of land, groundwater and more than 30 miles of Blacktail Creek, a Missouri River tributary.A federal investigation found Summit continued operating its produced water pipeline after multiple warning signs indicated a leak. In one instance, court records show, a drop in pressure prompted a facilities engineer to suggest shutting down the pipeline, but the company kept running it. Summit pleaded guilty to the criminal charges in September. Later that month, Traynor approved $20 million in civil fines. No individuals have been chargedDave Glatt, director of the North Dakota Department of Environmental Quality, said cleanup at the site of the Summit spill is ongoing seven years after the incident. The stream rebounded well from the spill, Glatt said, but some groundwater in the area remains contaminated.The spill is the largest in North Dakota history and also believed to be the biggest ever to occur on land anywhere in the country.In addition to the criminal fine, Traynor approved a series of probation requirements aimed at ensuring Summit's adherence to environmental laws and mitigating possible future spills. Among the probationary penalties is a requirement that the company implement a system for employees to anonymously report leaks or breaches of environmental law.
California Oil Regulators Deny New Fracking Permits - — California denied 21 oil drilling permits this week in the latest move toward ending fracking in a state that makes millions from the petroleum industry but is seeing widespread drought and more dangerous fire seasons linked to climate change. State Oil and Gas Supervisor Uduak-Joe Ntuk sent letters Thursday to Aera Energy denying permits to drill using hydraulic fracturing in two Kern County oil fields to “protect “public health and safety and environmental quality, including (the) reduction and mitigation of greenhouse gas emissions." Aera Energy, a joint venture Shell and ExxonMobil, called the permit denials “disappointing though not surprising." “This is the latest decision attacking the oil and gas industry that is based solely on politics rather than sound data or science,” Aera spokeswoman Cindy Pollard said Friday, adding that the company was evaluating its legal options. “Banning hydraulic fracturing will only put hard-working people of California out of work and threaten our energy supplies by making the state more dependent on foreign oil," she said. “In the face of the effects of the climate emergency, the risks to everyday Californians are too high to approve these permits,” Ntuk said Friday in emails to the Bakersfield Californian and the San Francisco Chronicle. Gov. Gavin Newsom applauded the move, his office said. In April, Newsom directed the state's Geologic Energy Management Division, or CalGEM, to develop a plan to stop issuing new fracking permits by 2024 after a measure to ban fracking died in the Legislature. Newsom also has ordered the California Air Resources Board to figure out how the state can end all oil production by 2045. Those decisions would make California the largest state to ban fracking and likely the first in the world to set a deadline for ending oil production. Still Newsom, who is facing a recall election in September, is treading a risky path. California is the seventh-largest oil-producing state, with more than 60,000 active wells. CalGEM has approved 100 new oil well-drilling permits and a dozen new fracking permits this year, according to state records cited by the Chronicle. The industry directly employed about 152,000 people and was responsible for $152.3 billion in economic output, according to a 2019 study commissioned by the Western States Petroleum Association.
Crude reality: One U.S. state consumes half the oil from the Amazon rainforest, report finds — The bulldozers rumble through after sunrise, clearing out massive amounts of trees in this remote and remarkable section of the Amazon rainforest. It's a place where giant otters patrol the waterways and endangered white-bellied spider monkeys swing from tree to tree. Where a dazzling array of birds — upward of 600 species — nest in the dense canopy. Where more than 60 kinds of snakes and 140 different frogs and toads inhabit the ground below. The Yasunà National Park is home to one of the most diverse collections of plants and animals on the planet. But beneath this 3,800-square-mile swath of forest lies another kind of treasure: crude oil. More than 1 billion barrels of it. Over the past 50 years, oil companies have extracted immense amounts of crude from the Amazon, causing the destruction of rainforest crucial to slowing climate change and jeopardizing the Indigenous tribes who rely on it. Now, a state-run oil company that subcontracts its field operations to the Chinese is building a road to reach what will be a new section of wells deep inside YasunÃ. "It hurts me to see the little that is left of our rainforest inside this protected area," Nemo Guiquita, a leader of the Waorani tribe, told NBC News during a boat trip through the national park. "We should be fighting to protect our rainforest in Ecuador, but instead they are granting more oil concessions." The oil extracted from Yasunà and the wider Amazon is exported around the world, but 66 percent goes to the U.S. on average and the vast majority of that to one state in particular: California, according to a new report shared exclusively with NBC News. The report by the environmental groups Stand.earth and Amazon Watch found that on average 1 in every 7 tanks of gas, diesel or jet fuel pumped in southern California last year came from the Amazon rainforest. Among the top 25 largest corporate consumers are companies such as Costco, PepsiCo and Amazon, according to the report. "This is no longer one of those things where we're supposed to have sympathy for a crisis that's happening somewhere else," said Angeline Robertson, a senior researcher at Stand.earth and the lead author of the report. "It's occurring in California, and it's linked to Amazon destruction."
Fuel-Contaminated Water From Aging Navy Facility Sickens Pearl Harbor Families -- Barely one week before top military brass, veterans and Hawaii government officials were to mark the 80th anniversary of the bombing of Pearl Harbor, families living in military housing around Joint Base Pearl Harbor-Hickam on Oahu noticed something was wrong with their tap water. They smelled gasoline and saw a sheen on the surface. Complaints and questions were soon followed by sickness. Infants developed bright red rashes, people and pets vomited, and children and adults were rushed to emergency rooms with sores in their mouths, headaches, stomach cramps, nausea and bloody stool. Initially, U.S. Navy officials dismissed concerns and said they had been drinking the water themselves without problem. On November 29, the base commander said in a statement, “[T]here are no immediate indications that the water is not safe.” But three days later, Navy officials reported that tests found that Navy drinking water lines had been contaminated with volatile hydrocarbons like those present in JP-5 jet fuel used for aircraft carriers. At the center of the crisis is the U.S. military’s Red Hill Bulk Fuel Storage Facility which includes 20 steel-lined tanks built between 1940-43 underground into the Kapukaki Ridge just east of Ke Awa Lau O Puuloa (known as Pearl Harbor) near U.S. Indo-Pacific Command headquarters. Each tank holds 12.5 million gallons of fuel which is used for the endless stream of naval vessels and military aircraft that operate from Joint Base Pearl Harbor-Hickam and nearby military installations at the heart of the U.S. military presence in the Pacific. The Red Hill facility has a history of spills and leaks, dating back as far as 1948. Since its construction, the nearly 80-year-old tanks have leaked more than 180,000 gallons of fuel, according to Sierra Club of Hawaii estimates. Built vertically in porous volcanic rock, the tanks sit roughly 100 feet above a key aquifer that provides water to more than 90,000 military service members and their families, as well as the greater Honolulu metropolitan area, home to some 400,000 people. Infants developed bright red rashes, people and pets vomited, and children and adults were rushed to emergency rooms with sores in their mouths, headaches, stomach cramps, nausea and bloody stool. Speaking at a town hall meeting on December 2, Rear Admiral Blake Converse, deputy commander of the U.S. Pacific Fleet, said a test found petroleum products just above the waterline in a Red Hill well. He said that the problem would be resolved with “significant additional flushing … with a good water source.” However, that same day, Hawaii Congressman Kaialii (Kai) Kahele called the situation a “crisis of astronomical proportions.” Kahele, an Iraq and Afghanistan war combat veteran and Hawaii Air National Guard pilot, described visiting the home of one impacted Navy family who took their daughter to the emergency room for a headache and throat irritation where she was diagnosed with “chemical burns in her mouth.”Holding up a plastic bottle filled at the family’s home, Kahele said, “If you smell this water, you would know that there is something wrong with this water.” At a subsequent public meeting, Captain Michael McGinnis, a surgeon with U.S. Pacific Fleet, advised, “There are no long-term consequences from a short-term exposure”…” According to a Honolulu Star-Advertiser report, petroleum contamination in the Navy’s water supply was present as early as last July.Meanwhile, some schools in the affected area have stopped using tap water and the military has established medical walk-in facilities, medical and counseling services, a hotline, portable showers and bottled water distribution sites to serve impacted residents.
Hawaii governor orders the Navy to shutdown its WWII-era fuel storage facility at Pearl Harbor after petroleum leaks into water supply -The US Navy announced Monday it has suspended operations at the Red Hill bulk fuel storage facility after petroleum leaked into the Navy Water System used as drinking water for residents and personnel on base. The service is now using above ground storage tanks on Joint Base Pearl Harbor-Hickam for fueling aircraft, ground vehicles and ships, a spokesperson confirmed to Insider. On Tuesday, Hawaii's leaders asked the service to take that action one step further. Hawaii's governor, alongside the state's Department of Health, issued an order to the Navy to not only suspend fuel operations at Red Hill but to come up with a plan to drain as much as 250 million gallons of fuel stored in its 20 underground tanks. "If at some point the tanks have been remediated and corrective action has been taken, they may apply for a permit or ask the permission of the Department of Health" to continue operations at Red Hill, said Kathleen Ho, the deputy director of environmental health at the DOH during a press conference Tuesday. Although the Navy now says it suspended operations at Red Hill on Nov. 27, the state was not informed of that action until Dec. 7, the governor confirmed to reporters during a press conference on Tuesday. Military residents at Joint Base Pearl Harbor-Hickam first reported feeling ill and smelling gasoline in their water on Nov. 28. The Navy confirmed the presence of petroleum in their water supply on Dec. 3. Secretary of the Navy Carlos Del Toro apologized to Hawaii's military families and said the Navy is "already working extremely hard" to find a solution to the water crisis. The Navy has said they believe that the source of the contamination is the Red Hill water shaft, just a half a mile from the Red Hill fuel storage facility. However, state leaders said today that no one has been able to confirm how fuel is getting into the water system. The Navy's water system serves over 93,000 people on Oahu. The Red Hill bulk fuel storage was built in 1941 and consists of 20 underground steel-lined tanks that can each hold about 12.5 million gallons of fuel. The facility currently stores and dispenses three types of petroleum fuel — marine diesel for ships and two types of jet fuel, JP-5 and JP-8 — according to the Environmental Protection Agency.
Gravel or Green: What Will Become of Alaska’s Coastal Plain? - Life on the coastal plain of Alaska exists on a scale difficult to capture. It’s a wild place where herds of caribou move around wolves and bears in wide arcs, musk oxen graze among dwarf willows, and gyrfalcons search the terrain for waterbirds. The tundra ground cover — a thick mat of damp, stunted vegetation — has sat atop the permafrost that’s existed since at least the last ice age. Conspicuous clusters of bright metal buildings also dot this landscape: oil wells, storage tanks, and generators — all linked by a sprawling system of roads and pipelines. Prudhoe Bay, at the center of the north Alaskan coastal plain, is one of the largest oil fields in North America. More than 800 wells stretch across more than 300 square miles, drawing oil from deep underground. Caribou migrate here across the imposing mountains of the Brooks Range unimpeded by human-made obstruction, only to bow their heads under pipelines when they reach the plains. Brown bears meander across the tundra under the watchful eye of oil workers, like teenagers shadowed by mall security. And wolves sniff the air to disentangle the mingling scents of prey and diesel. In some ways this arrangement works. The oil companies, perhaps reluctant to attract additional public scrutiny, have imposed on themselves rules about how to live and work in the oil fields. Most travel directly on the tundra is forbidden for workers, and any interactions with animals are prohibited. For a place with so many roads and so much wildlife, vehicle strikes are surprisingly rare. The heart of this industrial landscape is unexpectedly clean. Yet despite these safeguards, the ecosystem is thrown off balance. Oil infrastructure provides artificial nesting places for previously uncommon predators such as ravens. Red foxes, likely lured by anthropogenic sources of food and warmth, have moved into Prudhoe Bay to kill and displace Arctic foxes. Dust blowing off a gravel road may collect on adjacent land and hasten snowmelt. These disruptions — perhaps more than oil industry executives and the people who regulate them initially understood — have a long half-life.
Trans Mountain Pipeline Resumes Service Following BC Floods - Oil and refined products flows resumed Sunday through Trans Mountain Pipeline after a three-week suspension of deliveries as a safety precaution during floods in southern British Columbia. “The restart comes following completion of all necessary assessments, repairs, and construction of protective earthworks needed for the pipeline to be returned to service,” said the Calgary firm.Trans Mountain reported no pipe breaks or leaks but said 470 crewmen, six helicopters and 100 earth-moving machines replaced 57,200 cubic yards of ground cover that rain and mudslides washed away during storms that started Nov. 14.Costs of the suspension and restoration operations were not disclosed. The storms hit western and southern sections of the 1,150-kilometer (690-mile) pipeline that delivers 300,000 b/d to the Vancouver area from the Alberta capital in Edmonton.Outside the bad weather zone, work continued on an expansion project to increase Trans Mountain’s capacity to 890,000 b/d, primarily for overseas exports of Alberta oilsands production.The B.C. government said a mild form of fuel rationing would continue while Trans Mountain and a 55,000 b/d refinery operated in suburban Burnaby by Parkland Corp. resume normal operations.The program stops short of reviving wartime-style ration coupons. Instead, gasoline refills for personal travel at any one service station are limited to 30 liters (eight gallons) per car. No restrictions apply to public service and commercial vehicles from ambulances and police cruisers to taxis, buses, delivery trucks and farm machines.Parkland replaced suspended Trans Mountain refined products shipments with imports from the United States on railways and ocean barges. But flooding and road damage disrupted fuel truck deliveries to southern and western B.C. service stations.The storms did not cut B.C. natural gas supplies and only caused a brief precautionary reduction of exports to the northwestern U.S. by Enbridge Inc.’s Westcoast pipeline system, which has different routes than Trans Mountain.As the oil pipeline resumed operations, the B.C. government ended evacuation orders for two small cities that suffered the worst flooding: Abbotsford, 70 kilometers (42 miles) west of Vancouver, and Merritt, 375 kilometers (225 miles) northwest of Vancouver.
Enbridge sees two options for pipelines after Canadian regulatory pushback --Enbridge Inc. is evaluating two tolling options for its vast Mainline oil pipeline network after a proposal to offer long-term contracts to keep the conduits full was rejected by Canada’s energy regulator. North America’s largest pipeline company will either pursue a modified, incentive-based version of its current arrangement, which allows producers to decide the volumes they want to ship each month, or a system that would ensure tolls are enough to cover costs and provide a return on investments, Chief Executive Officer Al Monaco said in a presentation Tuesday. The Mainline pipeline network ships more than 3 million barrels of crude a day from Alberta to the U.S. Midwest, where it connects to the Gulf Coast, as well as Ontario and Quebec. It includes the Line 3 and Line 5 conduits that have faced opposition in the U.S. New tolling options are being discussed after Canada Energy Regulator rejected Enbridge’s proposal to offer as much as 90% of space on its Mainline to companies with long-term contracts. Enbridge sought the new system to ensure that it could keep pipelines full as it faces increasing competition from projects that have contracted space, including the Trans Mountain expansion scheduled to be completed as early as next year. The incentive-based version of the current tolling arrangement could be implemented by the middle of 2023, but reaching “consensus can be difficult” among those who use the Mainline, said Colin Gruending, the company’s president of liquid pipelines. Switching to a so-called cost-of-service system would take longer, he said.
Cermaq fined $500,000 for 2017 diesel spill at fish farm northwest of Campbell River – Cermaq Canada has been fined $500,000 for spilling approximately 522 litres of marine diesel into the ocean near Campbell River sometime overnight between March 4 and 5, 2017. The Crown was seeking a fine of $1.4 million but Judge Catherine Crockett decided on Nov. 30 in Campbell River Provincial Court that Cermaq’s culpability in the case is “at the lower end of the scale but is more than a ‘near miss.’” The company also has no prior record, accepted responsibility and is “sincerely remorseful,” the judge said She also said that the Crown “has not proven harm and the potential for harm was low.” Cermaq pleaded guilty to the charge at “an early opportunity.” “The law is clear that the predominant sentencing consideration for offences of this nature is deterrence of both Cermaq and others,” Judge Crockett said. “I conclude that the consequences of this incident to Cermaq to date, including the monetary cost and damage to its reputation, go a long way to impress upon Cermaq the need to ensure its systems and training are sufficient to prevent similar offences in the future. Nevertheless, I must impose a fine in keeping with Cermaq’s corporate size and relative financial means, so the fine could not be seen by Cermaq, or other companies that operate in the marine environment, as simply the cost of doing business. I agree with the Crown that general deterrence is particularly important in the context of the fish farming industry which operates directly upon the ocean.”
Alberta Enacts More Stringent Rules to Seal Backlog of Idle Oil, Natural Gas Wells - Alberta’s oil and natural gas firms are set to make a C$2.3 billion ($1.8 billion) start to seal a backlog of 95,524 inactive wells over the next five years under rules enacted Wednesday by the province’s production watchdog agency. The requirements translate the more stringent environmental legislation into “tools we need to begin to move the needle on liability,” said Alberta Energy Regulator (AER) President Laurie Pushor. “With these new requirements, we’re pushing industry to clean up their sites sooner and ensuring the cost and responsibility of the cleanup rests on the shoulders of industry — where it should be.” The Licensee Life-Cycle Management rules enable the AER to identify idle wells that have no prospects of resuming production. They also set minimum cleanup expenditure targets for their owners. In addition, annual five-year plans are to be compiled by the well owners. For the first five-year plan the AER calculated total industry spending requirements would be C$422 million ($338 million) in 2022; C$443 million ($354 million) in 2023; C$465 million ($372 million) in 2024; C$489 million ($391 million) in 2015; and C$513 million ($410 million) in 2026. The cleanup budgets for the last three years of each five-year plan would be forecasts instead of fixed demands.
New type of earthquake discovered - A Canadian-German research team have documented a new type of earthquake in an injection environment in British Columbia, Canada. Unlike conventional earthquakes of the same magnitude, they are slower and last longer. The events are a new type of induced earthquake that have been triggered by hydraulic fracturing, a method used in western Canada for oil and gas extraction. With a network of eight seismic stations surrounding an injection well at distances of a few kilometers, researchers from the Geological Survey of Canada, Ruhr-Universität Bochum, and McGill University recorded seismic data of approximately 350 earthquakes. Around ten percent of the located earthquakes turned out to exhibit unique features suggesting that they rupture more slowly, similar to what has previously been observed mainly in volcanic areas. To date, researchers have explained the occurrence of earthquakes in the hydraulic-fracturing process with two processes. The first says that the fluid pumped into the rock generates a pressure increase substantial enough to generate a new network of fractures in the subsurface rocks near the well. As a result, the pressure increase can be large enough to unclamp existing faults and trigger an earthquake. According to the second process, the fluid pressure increase from injection in the subsurface also exerts elastic stress changes on the surrounding rocks that can be transmitted over longer distances. If the stress changes occur in rocks where faults exist, it can also lead to changes that cause the fault to slip and cause an earthquake. Recently, numerical models and lab analyses have predicted a process on faults near injection wells that has been observed elsewhere on tectonic faults. The process, termed aseismic slip, starts out as slow slip that does not release any seismic energy. The slow slip can also cause a stress change on nearby faults that causes them slip rapidly and lead to an earthquake. The lack of seismic energy from aseismic slip and the size of the faults involved make it difficult to observe in nature. Researchers have therefore not yet been able to document aseismic slip broadly with any association to induced earthquakes. The work of the current study, provides indirect evidence of aseismic loading, and a transition from aseismic to seismic slip. The German-Canadian research team interpret the recently discovered slow earthquakes as an intermediate form of conventional earthquake and aseismic slip—and thus as indirect evidence that aseismic slip can also occur in the vicinity of wells. The researchers therefore dubbed the events hybrid-frequency waveform earthquakes (EHW).
Brazil was the only South American country to increase crude oil production in 2020 --Brazil was the only oil-producing country in South America to report an increase in crude oil and condensate production in 2020 compared with 2019, according to our Country Analysis Brief: Brazil, which we updated this summer. In 2020, Brazil produced an average of 2.94 million barrels per day (b/d) of crude oil and condensate, an increase of more than 150,000 b/d on average compared with 2019.Brazil increased its petroleum production in 2020 despite the drop in global petroleum demand caused by the COVID-19 pandemic. Petroleum production in other South American countries, such as Ecuador, fell year over year in 2020. We expect Brazil's production to continue to grow, contributing to global petroleum production growth in 2021, according to our November Short-Term Energy Outlook.The Oil & Gas Journal estimates that as of January 2021, Brazil had 12.7 billion barrels of proved oil reserves, the second-largest oil reserves in South America after Venezuela.Within the last two years, Brazil’s state-controlled Petróleo Brasileiro S.A. (commonly known as Petrobras) has significantly increased the number of production vessels operating in its pre-salt fields to boost crude oil production. Pre-salt oil refers to oil reserves that are exceptionally deep below the ocean under thick layers of rock and salt. The great depth and pressure involved in pre-salt production present significant technical hurdles. The company has overcome previous technological difficulties for drilling in deep water.Petrobras is the main participant in Brazil’s upstream, midstream, and downstream oil sector activities. The company held a monopoly on oil-related activities in Brazil until 1997, when the government opened the sector to competition.The Agência Nacional do Petróleo, Gás Natural e BiocombustÃveis (ANP) is responsible for issuing exploration and production licenses and ensuring compliance with relevant regulations. In 2018, the ANP loosened rules that set the minimum percentages of the locally sourced goods and services required in exploration and production contracts. These changes could significantly affect Brazil’s growth in oil production in the future. Breakeven prices could fall significantly and lead to increased oil production. Producers saw Brazil’s previous local content rules as a disincentive for investment because of the limited and uncompetitive local supply chain, according to Business News Americas.
Maersk secures contract to drill well in Norwegian North Sea - Drilling-rig operator Maersk Drilling has secured a new contract from OMV (Norge) to drill a high pressure, high temperature exploration well in the Norwegian North Sea. As agreed, the rig owner will use the low-emission jack-up rig Maersk Intrepid to drill the exploration well in Block 30/5C of the North Sea basin. Contracted works are expected to start in the middle of next year. There are two companies currently working to add other services to the scope of works. Maersk Drilling COO Morten Kelstrup said: “We’re delighted that OMV once again trusts us with the exploration of their prospects and look forward to building further on the close and extremely efficient collaboration we established during Maersk Integrator’s campaign for the customer earlier this year.” As an ultra-harsh environment CJ70 XLE jack-up rig, Maersk Intrepid is designed for year-round operations in the North Sea. The rig is also one of the first Maersk Drilling’s rigs to be upgraded to a hybrid, low-emission rig. Initial data shows that the upgrade reduced fuel consumption and carbon dioxide emissions by approximately 25%. It is currently working for Equinor Energy offshore Norway.
European gas stocks deplete rapidly in cold start to winter: Kemp (Reuters) - Europe’s gas stocks started the winter at their lowest for eight years and have been depleting rapidly, heightening concerns they could become uncomfortably low in early 2022 and exert upward pressure on prices. Inventories in the EU and Britain (EU28) fell to the equivalent of only 742 terawatt hours (TWh) on Dec. 5. That was the lowest for this time of year since 2013, according to data compiled by Gas Infrastructure Europe. Stocks have reduced by 97 TWh (12%) since the start of October, one of the largest drawdowns in the past decade, despite prices trading near record highs, which had been expected to limit consumption. Storage facilities are now only 66% full, a level of depletion they would not normally reach until the middle of January in an average winter (Link). Lower than normal temperatures across much of Northwest Europe so far this autumn and winter have intensified gas consumption and the pressure on storage. Average daily temperatures in Frankfurt, Germany, have been below the long-term seasonal average for 11 of the past 14 days. Frankfurt temperatures have averaged 0.4°C below the long-term seasonal norm over the 62 days since the start of October, boosting heating demand. At the same time, wind speeds have been slower than average over the past two months, which has depressed electricity generation from wind farms. The result has been increased direct consumption for residential and commercial heating as well as increased indirect consumption for power generation.
Gas price windfall makes Gazprom patient over Nord Stream 2 delay - Windfall revenues from high European gas prices mean Russia’s Gazprom will not start pumping gas through the Nord Stream 2 pipeline before certification and it will not press Germany to speed up the process, two sources said. Pumping gas without the German approval would only incur a modest fine, but as Germany gets new political leadership and Russia’s ties with the West are severely strained, a source at Gazprom said it was content to wait. “We don’t want to seek faster approval for the pipeline. Now it’s Germany that is in charge,” the source said on condition of anonymity. The same source said that Gazprom, Russia’s biggest tax payer, and the Kremlin were also keen to understand how ties with Germany’s new government would evolve after the departure of Angela Merkel, who supported Nord Stream 2. The Kremlin has said publicly it does not view as political the certification process, understands it is complex and that Russia must be patient. The second source said Gazprom was “feeling great” and expected next year’s gas market to remain as short of gas as it is now, keeping prices high. Gazprom’s additional supplies were not yet onstream, the source said. Elevated electricity costs have forced some industries to curtail production and European consumers are paying more for home heating as winter approaches, adding to wider inflationary pressures. The Russian gas export pipeline monopoly, which supplies 35% of European needs, says it is meeting contracted commitments – which top European clients have confirmed to Reuters. But European politicians, under pressure from consumers who face a jump in winter heating bills, say Russia could supply more and is using gas prices as leverage in a dispute over the Gazprom-backed Nord Stream 2. Gazprom, which declined to comment on Nord Stream 2, on Monday reported an all-time high quarterly net profit of 582 billion roubles ($8 billion) for the July-September quarter, reflecting high natural gas prices. It said it expected even higher earnings in coming months. The pipeline, which will double Russian gas export capacities to Europe via the Baltic Sea, is fiercely opposed by Ukraine, which stands to lose lucrative transit fees, and by many Western politicians who say Moscow uses energy as a political weapon, something it denies.
South Africans protest against Shell oil exploration in pristine coastal area - South Africans took to their beaches on Sunday to protest against plans by Royal Dutch Shell to do seimsic oil exploration they say will threaten marine wildlife such as whales, dolphins, seals and penguins on a pristine coastal stretch. A South African court on Friday struck down an application brought by environmentalists to stop the oil major exploring in the eastern seaboard’s Wild Coast, rejecting as unproven their argument that it would cause “irreparable harm” to the marine environment, especially migrating hump-back whales. The Wild Coast is home to some of the country’s most undisturbed wildlife refuges, and its stunning coastal wildernesses are also a major tourist draw. At least 1,000 demonstrators gathered on a beach near Port Edward, a Reuters TV correspondent saw.“It’s just absolutely horrendous that they are even considering this. Look around you?” said demonstrator Kas Wilson, indicating an unspoilt stretch of beach. “It’s unacceptable and … we will stop it. “Shell officials were not immediately available for comment, but the company said on Friday that its planned exploration has regulatory approval, and it will significantly contribute to South Africa’s energy security if resources are found. But local people fear the seismic blasting conducted over 6,000 square kilometres will kill or scare away the fish they depend on to live. “I don’t want them to operate here because if they do we won’t be able to catch fish,” said 62-year-old free dive fisherwoman Toloza Mzobe, after pulling a wild lobster from the ground. “What are we going to eat?” Environmentalists are urging Shell and other oil companies to stop prospecting for oil, arguing that the world has no chance of reaching net-zero carbon by 2050 if existing oil deposits are burned, let alone if new ones are found. Earlier this year, a Dutch court ordered Shell to reduce its planet-warming carbon emissions by 45% by 2030 from 2019 levels, a decision it plans to appeal.
Monarch seeks more relief for victims of Nembe oil spill - KING Biobelemoye Josiah of Opu-Nembe Kingdom has called for more relief for victims of the recent Nembe oil spillage in Bayelsa State. The monarch also expressed appreciation to Governor Douye Diri of Bayelsa State for his empathy over the spillage. Josiah gave the commendation in a letter addressed to the governor and made available to newsmen on Saturday in Abuja. An oil well operated by indigenous oil firm, Aiteo Eastern Exploration and Production, within Oil Mining Lease (OML) 29, has been discharging oil and gas into Nembe Creeks since November 5. Although the oil firm has sought foreign technical assistance from a US firm, Boots and Coots, to cap the leak, the discharge is still ongoing. The traditional ruler lamented the continued destruction done to the environment and the loss of livelihood of the people of Opu-Nembe Kingdom, commending Diri for setting up a committee to assess the extent and effect of the spillage. He appreciated the visit of the governor for an on-the-spot assessment of the spillage, which is yet to be contained for about a month. ”Your Excellency, on behalf of the good people of Opu- Nembe Kingdom, I passionately request that you use your honoured office to ask the National Emergency Management Agency (NEMA) to swiftly distribute relief materials to communities affected by the persistently gushing oil and gas spill. ”Also for the following federal government agencies: The National Oil Spill Detection and Response Agency (NOSDRA), Regulatory Commissions of the relevant Streams(up, mid and down) in the oil industry, The National Environmental Sanitation and Regulatory Agency (NESREA) and the Nigerian National Petroleum Corporation Limited (NNPC) to show more concern for the well-being of my people as well as reduce their sufferings,” he said. It would be recalled that management of Aiteo had visited the monarch few days after the incident occurred to brief him on response measures to contain the leak, express concerns over the impact of the leak, and donated relief materials. A Director of Aiteo Group Andrew Oru had, on Thursday, visited the spill site and said that in addition to an earlier four truck loads of food items and medical supplies, additional five truck loads of relief materials had been handed over to the victims. President Muhammad Buhari had earlier, on Nov. 25, dispatched Minister of State for Petroleum Chief Timipre Sylva to visit the spill site and empathise with impacted residents and ensure adequate response.
Nigerian wellhead has spilled 2m barrels of oil and gas - -A wellhead leak in Nigeria’s Bayelsa state has spewed two million barrels of oil and gas equivalent into the Delta creeks, the senate said on Tuesday. Nigerian oil firm Aiteo Eastern E&P reported the “extremely high order” leak from the Santa Barbara wellhead that it jointly owns with state oil company NNPC in early November. Weeks later, the wellhead was still violently spewing oil and gas. “Attempts to stop the continuous oil and gas spill by the operators had failed repeatedly for over one month running, wasting an estimated over 2 million barrels of hydrocarbon and gas,” a senate resolution stated, adding it showed “a disappointing appearance of technical incompetence in handling the incident on the part of Aiteo.” An Aiteo spokesman did not immediately reply to a request for comment. The company said previously it had contracted Halliburton subsidiary Boots & Coots to stop the spill, while President Muhammadu Buhari last month pledged it would be speedily addressed. The resolution, put forward by Bayelsa Senator Biobarakuma Degi-Eremienyo, expressed concern over the impact of the spill on the mangrove forests, aquatic life and air and water in the region. Nigeria’s Delta creeks and mangrove swamps are among the most polluted areas on earth after decades of oil and gas exploration. Senate President Ahmad Lawan said he was particularly disappointed an indigenous company was involved. “I believe that this particular case should be made to be an example of what government and its agencies can do, not only to force the alleged culprit to remedy the environment but also to penalize the oil company for devastating the lives of the people of that area,” Lawan said.
Upstream Regulatory Commission to explore provisions of PIA in tackling oil spills, says CEO - THE Nigerian Upstream Petroleum Regulatory Commission (NUPRC) has assured on its commitment to tackle oil spills in Nigerian communities using the instrumentality of the Petroleum Industrial Act (Act).. This assurance, the agency said, was in fulfillment of its regulatory mandate as enshrined in the Petroleum Industry Act (PIA) 2021, the Petroleum Act and the Petroleum (Drilling and Production) Regulations and Subsidiary Legislations. The regulatory agency’s assurance follows concerns trailing the oil spill incident of November 3, 2021, which occurred at the Santa Barbara Well 1 operated by AITEO Eastern Exploration and Production Company in Bassambiri, Nembe Local Government Area of Bayelsa State. Chief Executive Officer of the regulatory agency Gbenga Komolafe said in a statement that the commission would continue to monitor the site situation and guide the operator until the spill and its attendant problems were completely addressed. He noted that the agency would implement all effective physical and engineering solutions to the incident, managing the safety of the response providers and people in the neighbouring communities while educating the general public on the site situation periodically. He said, “It will ensure that the pressure from the well is stopped to put an end to the oil release, the already released oil is appropriately contained and skimmed off as it is being released. A joint investigation visit (JIV) is conducted as soon as it is safe to do so, and cleanup and restorative actions are done immediately after the spill is stopped and compensation paid to affected communities timeously and in accordance with the law.
Senate condemns Bayelsa oil spill, demands environmental impact assessment - The Nigerian Senate has passed resolutions condemning the oil spill at Santa Babara well 1, OML 29 operated by AITEO Eastern Exploration and Production Company Nigeria Limited in Opu Nembe in Nembe Local Government Area of Bayelsa State. The Senate, therefore, asked the company to “urgently seek, explore, and deploy relevant highest level of expertise and technology to stop the spill and prevent the continuous damage to the environment as well as restore the life support system of the people.” The resolution was reached when Senator Biobarakuma Degi Eremienyo (Bayelsa East), drew the attention of the Senate by a motion on the oil spill as a matter of urgent public importance. A statement issued on Wednesday by his Special Assistant (Media), Ebinim Omubo, said the Senate urged the relevant agencies to “undertake environmental impact assessment to determine the extent of the pollution with a view to undertaking remediation in accordance with internationally accepted standards.” According to him, the Senate also resolved that the National Emergency Management Agency should as a matter of urgency provide relief materials because the ugly incident has taken a negative toll on the health and well-being of the people of the host communities which can be declared a disaster area. Omubo said, “During the presentation of his motion, Senator Degi Eremienyo noted that the policy on divestments by international oil companies in exploration and production of oil and gas is a welcome development as it creates space for indigenous companies to invest and grow in the industry.”
Oil spill in Nigeria’s Delta halted, state official says- (Reuters) – A wellhead that has been spilling oil and gas in Nigeria’s Bayelsa state has been successfully shut, more than a month after it started polluting the Delta creeks, the state’s minister for petroleum said on Wednesday. Nigerian oil firm Aiteo Eastern E&P reported the “extremely high order” leak from the Santa Barbara wellhead that it jointly owns with state oil company NNPC in early November. Weeks later, the wellhead was still violently spewing oil and gas. “We have put out the leak at SBAS-1. We are grateful for all the support,” minister Timipre Sylva said in a statement. Sylva said the next stage was to carry out a comprehensive service of the wellhead as well as clean up the surrounding area. An Aiteo spokesman said he would issue a statement later. The company said previously it had contracted Halliburton subsidiary Boots & Coots to stop the spill. A senate resolution on Tuesday said the leak had spewed two million barrels of oil and gas equivalent into the Niger Delta creeks and mangrove swamps, which are among some of the most polluted areas on earth after decades of gas and oil exploration.M
Surging LNG exports drive Australia's output to a record high but EnergyQuest issues reserves warning -Australian liquefied natural gas production hit a record high in the third quarter, but concern continues to mount for long-term output without further development.EnergyQuest estimates Australian petroleum production was a record 288.4 million barrels of oil equivalent during the quarter, up 21.6% on the previous three months, driven by record LNG exports of 21.1 million tonnes. The consultancy said the result highlighted “a recovery in national LNG production”, which had been affected recently by the performance of several developments in Western Australia.Rolling shut-downs of all three trains at Chevron’s Gorgon LNG development had affected production over the financial year ending 30 June, after cracks were found in the eight heat exchangers of Train 2 during routine maintenance in July last year.After a subsequent inspection, the project’s other two trains were sequentially shut down for repairs and maintenance. All three returned to production by the third quarter of 2021.Chevron did experience another short shutdown last month at Train 1 following the detection of a gas leak on piping associated with the dehydration unit. However,the train was back up and running before the end of the month.EnergyQuest also noted in its quarterly report that output had been affected in the previous financial year by “patchy results” from the Woodside Petroleum-operated North West Shelf venture, while Shell’s Prelude floating LNG development was finally operating at near nameplate capacity in the third quarter, following multiple issues since start-up. Prelude’s improved performance has been short-lived, however: Shell suspended production and evacuated staff following a fire on 2 December.EnergyQuest also highlighted “a strong recovery in production” at the Inpex-operated Ichthys development after a scheduled maintenance shutdown in the second quarter. It noted that Australia’s strong LNG production continued into the final quarter. A record 7.32 million tonnes was shipped in October, equating to 85.1 million tonnes per annum on an annualised basis, which is above the previous record of 84.8 million tpa on an annualised basis set in March this year. Australia's liquids production was also on the rise in the third quarter, with condensate production hitting a record 26.3 million barrels, which EnergyQuest said was due to "the stars aligning at most of the country's liquid-rich LNG projects". Oil output also totalled 10.4 million barrels in the recent quarter, up from 9.6 million barrels in the second quarter, which EnergyQuest attributed to good results from Woodside's Vincent project and the NWS, and a rebuild of volumes from the Santos-operated Van Gogh project.
Shell evacuates Prelude floating LNG plant after power outage -Royal Dutch Shell Plc has evacuated non-essential staff from its floating liquefied natural gas facility in northwest Australia as the operator struggled to restore power that knocked out operations earlier in the week, according to people familiar with the matter. The delay in bringing essential power generators back online at the Prelude LNG export plant had left workers without ventilation, potable water services and a sewage treatment system, said one of the people, who spoke on the condition of anonymity as they’re not authorized to speak to media. The evacuation of non-essential staff was assisted by Inpex Corp.’s helicopter and rescue vessel, the people said. Shell said in an emailed statement that work to restore main power is underway, without commenting on the evacuation. The world’s biggest floating LNG plant suspended production and delayed the loading of a prompt cargo on Friday after suffering an issue that tripped power at the facility. The evacuation indicates that the plant could be shut for longer than originally anticipated, exacerbating a global shortage of natural gas. Shell and its partners are now considering canceling the scheduled LNG cargo loading due to the ongoing power issue, one of the people said.
DOE to invest P502 B for gas extraction – The Philippines is planning to invest P502 billion in the next two decades for its targeted gas reserves extraction of up to 4.0 trillion cubic feet (TCF) as a replacement to the depleting Malampaya field, according to the Department of Energy (DOE). DOE Undersecretary Felix William B. Fuentebella, during the Energy Investment Forum last Dec. 3, said the investments and capital raising for exploration and development of indigenous oil and gas upstream resources will be among the anchors of the country’s energy security. “We will continuously provide for the development and utilization of indigenous sources in the form of coal, oil and natural gas,” said Fuentebella. On the overall target of pursuing developments on indigenous energy resources, Fuentebella stated that aggregate investments could top P1.176 trillion with the heftier pie of P656.06 billion likely funneled into coal mining exploration and development ventures. Relative to the country’s persistent quest for Malampaya’s replacement, DOE Secretary Alfonso G. Cusi indicated that the Duterte administration’s initiative on lifting the exploration moratorium at the West Philippine Sea could reinforce eventual oil and gas development prospects in the specified diplomatically-saddled territories. The 4.0 TCF target of the exiting Duterte administration is even higher than the full commercial development potential at Malampaya, which had been pegged at a high of 3.4 trillion cubic feet. “For our petroleum sector, President Duterte’s lifting of the moratorium on the West Philippine Sea has enabled the resumption of exploration activities and the fulfillment of previously halted work program commitments,” Cusi said. At this stage though, most exploration and production (E&P) investors are still at the process of seeking guidance from the DOE how they could proceed with planned extended seismic surveys and eventual drilling activities, without being hamstrung by Chinese vessels roaming around conflict-ridden areas within the West Philippine Sea.
BlackRock, Saudi asset manager Hassana sign deal for Aramco's gas pipelines (Reuters) -Saudi Aramco said on Monday it has signed a $15.5 billion lease-and-leaseback deal for its gas pipeline network with a consortium led by BlackRock Real Assets and state-backed Hassana Investment Co. Gulf oil producers are looking at sales of stakes in energy assets and raising cash through long-term leases, capitalising on a rebound in crude prices to attract foreign investors. Earlier this year Aramco sold a 49% stake in its oil pipelines to a consortium led by U.S.-based EIG under a similar structure for $12.4 billion. As part of the latest transaction, a newly formed subsidiary, Aramco Gas Pipelines Co, will lease usage rights in the state energy firm’s gas pipelines network and lease them back to Aramco for a 20-year period, it said. In return, Aramco Gas Pipelines Co will receive a tariff payable by Aramco for the gas products that will flow through the network, backed by minimum commitments on throughput. Aramco will hold a 51% majority stake in Aramco Gas Pipeline Company and sell a 49% stake to investors led by BlackRock and Hassana, the asset management arm of the General Organization for Social Insurance (GOSI). Other bidders in the race included EIG and Brookfield, sources told Reuters earlier. Aramco will continue to retain full ownership and operational control of its gas pipeline network, and the transaction will not impose any restrictions on its production volumes, it said.
Saudi Arabia Proppants Market Insights by Leading Companies Future Growth, Revenue Analysis and Demand Forecast -- A proppant is a solid material which is suspended in water so as to facilitate the opening of an induced hydraulic fracture. These are used during the fracking stage of oil & gas extraction. With COVID-19 resulting in the economic fallout, numerous economies are working on game-changing improvements to protect their employees and clients. While focusing on the ongoing challenges, the leaders are embracing new plans in order to manage and stay afloat in this competitive environment. A proppant is a solid material which is suspended in water so as to facilitate the opening of an induced hydraulic fracture. These are used during the fracking stage of oil & gas extraction. Saudi Arabia Proppants Market Analysis, 2020 research report depicts a deep-dive market analysis of statistics of Saudi Arabia Proppants market which consists of regional and country-wise market size, market forecast, CAGR market segmentation, market shares of diverse regions and countries, market share of various end users, applications, product type, technologies, competitive benchmarking, etc. According to MarkNtel Advisors' research report titled“Saudi Arabia Proppants Market Analysis, 2020”, the Saudi Arabia Proppants market is anticipated to grow at a CAGR of around 6% during 2020-25 on account of surging government investment toward the setup of proppant plants and shale gas plants, and burgeoning demand for proppants in the oil & gas sector. Moreover, rising hydraulic fracturing activities and surging inclination to produce domestic gas to power the electric grid are projected to boost the demand for proppants in the forecast period. Based on Type, Frac Sand acquired the largest market share in the Saudi Arabia Proppant market in 2019 due to an increasing local production of frac sand for the fracking of shale gas. Moreover, boost in government spending toward shale gas development is projected to bolster the demand for frac sand due to its efficiency, low cost, and availability. Therefore, this is anticipated to place a significant impact toward the growth of Saudi Arabia Proppants market in the forthcoming years.
OPEC will continue with supply adjustments for oil market, chief says -- The Organization of the Petroleum Exporting Countries (OPEC) will continue with its supply adjustments for the oil market, the OPEC Secretary General said on Saturday. “We will continue to do what we know best to ensure we attain stability in the oil market on a sustainable basis,” Mohammad Barkindo said in a webinar organized by Italian think-tank ISPI. Oil prices fell on Thursday after OPEC and its allies stuck to their existing policy of monthly oil output increases despite fears a release from U.S. crude reserves and the new Omicron coronavirus variant would put renewed pressure on prices. Barkindo said in terms of oil demand the estimate at the moment was for a growth of 5.7 million barrels per day. “In 2022 we expect another 4.2 million,” he said. He said the uncertainty and volatility on the markets was also due to extraneous factors such as the ongoing Covid pandemic and not necessarily the fundamentals of oil and gas. “Now we are on course of returning the level of consumption in 2022 to pre-COVID levels,” he said. Barkindo said that the forecast was for oil and gas to account for more than 50% of the global energy mix in 2045 or even to mid century. “In all the pronouncements we had from Glasgow we have not yet seen any concrete road map or plans of how to replace this 50% … without creating unprecedented turmoil in the energy markets,” he said, referring to the Glasgow climate conference. “Oil and gas will be needed for the foreseeable future.”
Saudi Arabia raises January Arab Light crude prices to Asia - Saudi Arabia's state oil producer Aramco 2222.SE raised its January official selling price (OSP) to Asia for its flagship Arab Light crude to $3.30 a barrel versus Oman/Dubai crude, up $0.60 from December, the company said on Sunday. The company set the Arab Light OSP to Northwestern Europe at minus $1.30 per barrel versus ICE Brent and to the United States at plus $2.15 per barrel over ASCI (Argus Sour Crude Index).
Oil Futures Climb on Saudi Price Hike, Easing Omicron Fears-- Nearby delivery oil futures on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange rallied in early trade Monday after Saudi Aramco raised its official selling crude prices to Asia and the United States for the second consecutive month in January, signaling confidence in a demand recovery this winter. Early data on the omicron variant of coronavirus suggests the highly mutated strain is less lethal but more transmittable compared to the original COVID-19 virus. Omicron variant is now found in more than 40 countries worldwide but there are no reported deaths related to the new strain of COVID-19, according to official data from the Word Health Organization. South African President Cyril Ramaphosa said this weekend the country is recording a rapid spread of omicron variant, but the rate of hospitalizations is lagging far behind the number of confirmed cases. Domestically, at least 15 states have confirmed omicron on Sunday, including in the Northeast, the South, the Great Plains, and the West Coast. Delta variant of coronavirus remains the dominant variant, making up more than 99% of cases and driving a surge of hospitalizations in the north. Oil futures early gains came on the back of Saudi Aramco's latest price move, where the world's top oil exporter raised its prices for crude oil bound to Asian and U.S. buyers for the second month in a row. The biggest price increases were for medium and heavy grades to Asian buyers. Aramco boosted its medium grade to Asia by 70 cents to a $3.05 barrel (bbl) premium over Oman/Dubai and its heavy grade by 80 cents bbl to a $1.80 bbl premium. Super light was raised by 30 cents bbl to a $6.15 bbl premium while extra light was increased to a $4.50 bbl premium. For U.S.-bound crudes, Aramco boosted its extra light OSP by 60 cents bbl to a $3.50 bbl premium. Higher premiums can be viewed as a sign of robust demand, supporting last week's decision by the Organization of the Petroleum Exporting Countries and their allies to raise oil production by 400,000 barrels per day (bpd) in January in spite of concerns related to the Omicron variant. Despite upbeat demand signals, OPEC+'s technical panel estimated the oil market is rapidly moving into oversupply next year, 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 a surplus on the global market to reach a whopping 3.8 million bpd. Near 7:30 a.m. EST, West Texas Intermediate January futures rallied more than $2 bbl to trade near $68.38 bbl and the international benchmark ICE February Brent contract jumped above $72 bbl, up $2.30 bbl in early trading. NYMEX RBOB January futures added 4.85 cents or 2.5% to $2.0014 gallon, and the front-month NYMEX ULSD contract strengthened to $2.1466 gallon.
Oil settles at highest in a week, up nearly 5%, as omicron fears ease -- Crude-oil prices on Monday settled with a gain of nearly 5%, as concerns surrounding the omicron variant of coronavirus that causes COVID-19 eased a bit. Other factors, including a move by the Saudis to raise crude prices for some buyers, and rising tensions in the Middle East, helped to shift some focus away from the pandemic. Energy prices have moved up “off chatter that the omicron virus might not present severe health problems,” analysts at Zaner wrote in Monday’s commentary. Recent reports have offered some cause for optimism about the new strain’s potential impact on the economy. The U.S.’s top medical adviser Anthony Fauci said that omicron didn’t appear to produce a “great deal of severity” in cases, aligning with some early research that indicates that infections tend to be milder compared against other variants. Meanwhile, Saudi Arabia increased its prices of Arab Light oil over the weekend for January delivery that it sells to Asia and U.S. by up to a two-year high, according to Reuters. The decision by the Saudis, the de facto head of the Organization of the Petroleum Exporting Countries and one of the biggest oil producers in the world, to hike the cost of the oil to the U.S. and Asia “comes amidst expectations that demand will remain high in the new year,”
Oil Prices Rise As Fears Of Omicron Lockdowns Subside - Oil prices rose early on Tuesday for the second day in a row, as traders are cautiously optimistic that the new Omicron COVID variant would not lead to massive lockdowns around the world to the point of severely reducing global oil demand. As of 10:00 a.m. EST on Tuesday, WTI Crude was up 2.85% at $71.55 and Brent Crude had gained 2.30% to $74.86. Oil prices had started to rebound on Monday after Saudi Arabia signaled optimism about demand by hiking its official January crude oil selling prices for Asia and the United States—its biggest markets. Amid heightened worry about the course of the pandemic after the emergence of Omicron, Saudi Arabia injected a dose of confidence in markets by raising its official selling price for its flagship Arab Light to a nearly two-year high.The market was also relieved on Monday that early reports into Omicron have shown milder symptoms, although the variant is thought to be much more transmissible.“Although it’s too early to make any definitive statements about it, thus far it does not look like there’s a great degree of severity to it,” the White House’s chief medical advisor, Dr. Anthony Fauci, told CNN on Monday, but cautioned it was still too early to make sweeping assessments of the severity of the variant. “The signals are a bit encouraging,” he added.“Investors have begun to recalibrate their assessment of the economic impact of the Omicron, setting aside the worst fears triggered by news of the heavily-mutated variant about 10 days ago,” Vanda Insights said in a note on Tuesday.“Yesterday’s optimism can quickly turn into gloom again unless scientific evidence confirms that the economic impact of the latest variant is, in fact, negligible. Yesterday’s impressive performance is being followed-through this morning, partly due to a decent jump in Chinese crude oil imports last month,” broker PVM Oil Associates commented on the oil market on Tuesday.Finally, a stalemate in the Iran nuclear talks is also bullish for the market, with Germany saying on Monday that Iran should return to the talks with realistic proposals that don’t breach previously reached compromises.
Oil rises 3%, extending rally as Omicron fears retreat - Oil prices climbed by more than 3% on Tuesday, extending the previous day's rebound of almost 5% as concerns eased further about the impact on global fuel demand of the Omicron coronavirus variant. Brent crude futures settled up $2.36, or 3.2%, at $75.44 a barrel, after Monday's rise of 4.6%. U.S. West Texas Intermediate crude rose $2.56, or 3.7%, to $72.05, building on a 4.9% gain the previous session. At the session highs on Tuesday, each contract was up more than $3. Oil prices tumbled last week on concerns that vaccines might be less effective against the new Omicron variant, sparking fears that governments could impose fresh restrictions that would sink fuel demand. However, a South African health official reported over the weekend that Omicron cases there had shown only mild symptoms while the top U.S. infectious disease official, Anthony Fauci, also said there did not appear to be "a great degree of severity" with the variant so far. "The market was oversold as a knee-jerk reaction to Omicron and its potential spread and impact on travel restrictions," In another sign of confidence in oil demand, the world's top exporter, Saudi Arabia, raised monthly crude prices on Sunday. Last week, the Organization of the Petroleum Exporting Countries and its allies, a group known as OPEC+, agreed to keep raising output by 400,000 barrels per day (bpd) in January despite release of U.S. strategic petroleum reserves. "The market is starting to take this variant in its stride," Oil prices were also supported by delays to the return of Iranian oil, with indirect nuclear talks between the United States and Iran having hit stumbling blocks. Germany urged Iran on Monday to present realistic proposals in talks over its nuclear programme.
WTI Holds Gains After Bigger Than Expected Crude Draw - Oil prices closed higher on the day, but well off the intraday highs, on optimism that the omicron variant may not be as severe as feared, easing concern over the demand outlook.“While there is probably going to be some demand destruction because of omicron, the market priced in a lot worse than what it’s going to be,” said Phil Flynn, senior market analyst at Price Futures Group Inc.“We are getting back to more real fundamentals versus the fear fundamentals we were trading on last week.”Adding to bullish sentiment, the prospect of a deal to unlock sanctions on over 1 million barrels per day of Iranian oil exports is receding, RBC analyst Helima Croft said in a report.API
- Crude -3.089mm (-1.2mm exp)
- Cushing +2.4mm
- Gasoline +3.7mm (+1.4mm exp)
- Distillates +1.2mm (+900k exp)
A bigger than expected crude draw last week, according to API, but big builds at Cushing and for products...WTI was hovering around $71.60 ahead of the API print.The outlook for oil demand has "returned to being positive, while oil supply remains tight as economies recuperate from the rock bottom situation witnessed in 2020," said Naeem Aslam, chief market analyst at AvaTrade.However, not everyone is as bulled up as the EIA also cut its oil forecasts for 2022 by 2.7% to $66.42 for WTI and by 2.6% to $70.05 for Brent."This is a very complicated environment for the entire energy sector," said EIA Acting Administrator Steve Nalley, in a statement."Our forecasts for petroleum and other energy prices, consumption, and production could change significantly as we learn more about how responses to the omicron variant could affect oil demand and the broader economy."On a side note, while the Biden admin celebrates the 'drop' in the gas price at the pump, the underlying (Crude and Wholesale Gasoline) are starting to rally again as Omicron fears - which sent prices lower - fade...
Oil jumps back above $75 as investors assess Omicron's impact - Oil prices edged higher in choppy trade on Wednesday, taking a breather after gains earlier this week, as investors assessed the impact of the Omicron coronavirus variant on the global economy. The market had a muted reaction to U.S. weekly inventory figures, which showed a smaller-than-anticipated decline in crude stocks and another bump up in overall production, giving credence to expectations that supply will increase in coming months. Brent crude futures advanced 38 cents, or 0.5%, to settle at $75.83 per barrel. U.S. West Texas Intermediate crude settled 31 cents, or 0.43%, higher at $72.36 per barrel. Brent crude prices have rebounded by over 9% since Dec. 1 on signs Omicron has had only a limited impact on oil demand, after a 16% drop since Nov. 25. "There has been no noticeable slowing effect on oil demand as yet. Even aviation, the sector that should have been hit first, has seen only a marginal decrease in seating capacity." The emergence of the Omicron variant combined with the U.S. decision to release inventories from its strategic reserve to knock the market back on expectations that supply would outweigh demand by the early months of 2022. Ultimately, the Organization of the Petroleum Exporting Countries and its allies including Russia, known as OPEC+, chose to maintain its schedule of boosting supply by 400,000 barrels per day every month - despite fears that the new coronavirus variant would sap demand. U.S. output, meanwhile, rose to 11.7 million barrels per day in the most recent week, though weekly output figures are volatile. The U.S. Energy Department also said gasoline and distillate inventories rose more than anticipated, while crude stocks fell by a mere 240,000 barrels, less than expected. The market was also focused on the resumption of talks between Washington and Tehran over Iran's nuclear programme. Western officials have voiced dismay at sweeping Iranian demands. If U.S. sanctions were eased, it could lead to higher exports of Iranian oil, which could add downward pressure on oil prices. Tensions between Western powers and Russia over Ukraine also remained high after President Joe Biden warned Russian President Vladimir Putin on Tuesday that the West would impose "strong economic and other measures" on Russia if it invades Ukraine, while Putin demanded guarantees that NATO would not expand farther eastward.
Oil Futures Decline Amid Stronger USD, Demand Concerns -- Oil futures nearest delivery settled lower Thursday as risk sentiment turned sour around the omicron variant of the coronavirus and larger-than-expected build on refined fuel stockpiles. Deeming the post-Thanksgiving holiday selloff overdone after early signs suggest that omicron, while more transmittable appears less lethal, oil futures rallied this week through Wednesday. Yet worries over demand persist as mobility and travel restrictions continue in parts of Europe and Asia. On Tuesday, the Energy Information Administration revised lower their forecast for global oil demand for 2022 by 420,000 barrels per day (bpd) from their projection in November to 100.46 million bpd. Risk-on sentiment across markets supported higher prices earlier in the week. EIA data released Wednesday showed U.S. crude oil inventories fell by a smaller-than-expected 240,000 barrels (bbl) in the week ended Dec. 3 to 432.87 million bbl as strengthened refinery demand offset rising production. However, at the Cushing, Oklahoma, hub crude stocks rose 2.37 million bbl to a seven-week high 30.92 million bbl. Nationwide gasoline stocks moved 3.88 million bbl higher to 219.3 million bbl, while distillate inventories climbed 2.73 million bbl to 126.6 million bbl. EIA in its latest Short-Term Energy Outlook projects oversupply for next year despite adjusting their expectation for world oil production down 490,000 bpd to 100.93 million bpd, with the Organization of the Petroleum Exporting Countries this month also projecting a supply surplus in early 2022. OPEC+ earlier this month agreed to move ahead with their 400,000 bpd production increase in January despite the weakening demand outlook, sticking to their July agreement of gradually unwinding production cuts instituted in April 2020, but also said they could adjust that decision if they believe demand will weaken further than projected. Meantime, it remains unclear if resumed talks in Vienna over reviving the JCPOA will yield a deal after the United States withdrew from the agreement in 2018 under the Trump administration. The discussion is taking place through intermediaries, as Tehran has refused to talk directly with U.S. officials, while reportedly hardening its position. Amid concern over slowing demand growth and rising oil production, the backwardated market structures for West Texas Intermediate and Brent crude futures continue to weaken. Commodity Futures Trading Commission shows money managers reducing long positions in the oil complex, as the bullish scenario softens. At settlement, January WTI futures fell $1.42 to $70.94 bbl and ICE February Brent fell $1.40 to $74.42 bbl. NYMEX January ULSD futures fell 1.10 cents to $2.2503 gallon, and January RBOB futures fell 2.01 cents to $2.1284 gallon.
Oil settles lower as China developer downgrades add to fears of demand outlook - Oil prices settled lower on Thursday on fears about the economic outlook in the world's biggest oil importer following ratings downgrades to two Chinese property developers, and after some governments took measures to fight the Omicron variant of the coronavirus. Brent crude futures settled down $1.40, or 1.9%, to $74.42 a barrel, backing off a session high of $76.70. U.S. West Texas Intermediate (WTI) crude futures were down $1.42, or 2%, at $70.94 after hitting a peak of $73.34. On Thursday, ratings agency Fitch downgraded property developers China Evergrande Group and Kaisa Group to "restricted default" status, saying they had defaulted on offshore bonds, while a source said that Kaisa had started work on restructuring its $12 billion offshore debt. The news "exacerbates the Chinese GDP growth fears and ultimately could impact the oil-buying appetite of the world's biggest crude customer," said Rystad Energy analyst Louise Dickson. On Wednesday, British Prime Minister Boris Johnson imposed tougher COVID-19 restrictions in England, saying people should work from home where possible, wear masks in public places and show COVID-19 vaccine passes for entry to certain events and venues.. Denmark also plans new restrictions, including closure of restaurants, bars and schools, while China has halted group tourist trips from Guangdong. South Korea has registered record infections while cases remain elevated in Singapore and Australia. The number of Americans filing new claims for unemployment benefits dropped last week to the lowest level in more than 52 years amid an acute shortage of workers, according to new data published by the U.S. Labor Department. "The oil market doesn't always respond well to good economic news either, because it could prompt the Federal Reserve to tighten monetary policy," said John Kilduff, partner at Again Capital LLC in New York. Markets were buoyed by comments from BioNTech and Pfizer that a three-shot course of their COVID-19 vaccine could protect against infection from the Omicron variant. The Omicron outbreak sparked a 16% slump in Brent prices from Nov. 25 to Dec. 1. More than half of the drop has been recouped this week, but analysts say a further recovery could be limited until Omicron's impact is clearer. U.S. inventory data released on Wednesday also weighed on prices. Energy Information Administration (EIA) data showed that crude inventories were down by 240,000 barrels last week, much less than analysts in a Reuters poll had expected, with stocks at the Cushing delivery hub in Oklahoma rising by 2.4 million barrels. Fuel stocks also rose by a combined 6.6 million barrels, the data showed.
Oil Futures, Equities Advance Ahead of US Inflation Data -- Oil futures nearest delivery on the New York Mercantile Exchange and Brent crude on the Intercontinental Exchange advanced in early morning trade Friday, with the front-month West Texas Intermediate contact holding above $71 per barrel (bbl) as investors await the release of key inflation data in the United States that could shed light on the direction of Federal Reserve monetary policy in the coming months. Investors are bracing for the highest inflation reading in over forty years. Economists predict the consumer price index slated for release Friday morning to show a 0.7% gain for November, which would translate into a 6.7% increase from a year ago. If the actual figure meets expectations, this will mark the highest year-over-year price increase since 1982. Federal Reserve Chairman Jerome Powell said last week that the central bank needs to be ready to respond to the possibility that inflation might not recede in the second half of next year as most forecasts have expected. The implications for Federal Reserve policy are clear; Chairman Powell's hawkish turn last week, alongside his decision to retire the word "transitory" in terms of inflation pressures, likely means a faster pace of bond purchase tapering from the central bank next week, as well as earlier-than-expected rate hikes. Separately, inventory data released from the U.S. Energy Information Administration on Wednesday showed commercial crude oil inventories fell by a smaller-than-expected 240,000 bbl in the week ended Dec. 3 to 432.87 million bbl as strengthened refinery demand offset rising production. However, at the Cushing, Oklahoma, hub crude stocks rose 2.37 million bbl to a seven-week high 30.92 million bbl. Nationwide gasoline stocks moved 3.88 million bbl higher to 219.3 million bbl, while distillate inventories climbed 2.73 million bbl to 126.6 million bbl. EIA in its latest Short-Term Energy Outlook projects oversupply for next year despite adjusting their expectation for world oil production down 490,000 barrels per day (bpd) to 100.93 million bpd, with the Organization of the Petroleum Exporting Countries this month also projecting a supply surplus in early 2022. Oil production is also growing in the U.S., with the EIA on Wednesday reporting the third 100,000 bpd weekly increase in domestic oil output through Dec. 3 to average 11.7 million bpd. That's the greatest weekly production rate since the depths of U.S. lockdowns in response to the COVID-19 pandemic in April 2020. EIA projects U.S. output to average 11.8 million bpd in 2022, climbing to 12.1 million bpd in the fourth quarter. Near 6:45 a.m. ET, January WTI futures gained $0.55 to $71.53 bbl and ICE February Brent added $0.56 to $74.98 bbl. NYMEX January ULSD futures edged 0.36 cents higher to $2.2539 gallon, and January RBOB futures gained to $2.1388 gallon.
WTI Settles Up 8.2% on the Week -- Crude had the strongest week since August on fading omicron fears. Oil set its biggest weekly gain in more than three months as the worst fears over the new virus strain have receded. West Texas Intermediate futures climbed 8.2% this week. Fuel consumption so far has escaped any major blows from the omicron variant. Yet confidence is limited. Rallies are still punctuated by selloffs such as that on Thursday after rising infection rates prompted some governments to tighten travel restrictions. “Crude prices are having a good week as omicron jitters have eased and as the 2022 growth outlook for the US economy remains mostly undeterred,” said Ed Moya, senior market analyst at Oanda Corp. Oil has seen a remarkable turnaround after tumbling into a bear market on Nov. 30, following a multiweek plunge. But concerns persist over the omicron variant, which one study indicates is 4.2 times more transmissible than the delta strain in its early stages. Some signs of weakness are emerging. Traders are facing the prospect of a weakening physical market for crude in Asia, despite Saudi Arabia’s move to increase oil prices for January. The prompt timespread for global benchmark Brent has also narrowed this week, pointing bearish sentiments. Prices: WTI for January delivery rose 73 cents to settle at $71.67 a barrel in New York Brent for February settlement increased 73 cents to settle at $75.15 a barrel. Many parts of the eastern U.S., including New Jersey and Connecticut, are seeing a rise in hospitalizations. The City of London may be on the verge of becoming a ghost town again after firms started telling thousands of staff to work from home in response to the latest U.K. government guidance. In the U.S., consumer prices rose last month at the fastest annual pace in nearly 40 years, magnifying persistent inflation and with consumers facing the biggest jump in energy bills in more than a decade. The inflation headline numbers continue to add pressure for the Federal Reserve to tighten monetary policy.
Oil prices post biggest weekly gain since August (Reuters) -Oil prices rose slightly on Friday and posted their biggest weekly gain since late August, with market sentiment buoyed by easing concerns over the Omicron coronavirus variant's impact on global economic growth and fuel demand. The Brent and U.S. West Texas Intermediate (WTI) crude benchmarks each posted gains of about 8% this week, their first weekly gain in seven, even after a brief bout of profit-taking. Brent futures settled up 73 cents, or 1%, at $75.15 a barrel, after falling 1.9% on Thursday. WTI rose 73 cents, or 1%, to $71.67 after sliding 2% in a volatile session the previous day. "Oil traders are coming out of their shell-shock and feeling more bullish as they recalibrate their demand expectations in the aftermath of the Omicron variation of the coronavirus," said Phil Flynn, senior analyst price futures group in Chicago. U.S. consumer prices rose further in November to produce the largest year-on-year rise since 1982, government data showed, adding to bullish sentiment on oil demand. Earlier in the week the oil market had recovered about half the losses suffered since the Omicron outbreak on Nov. 25, with prices lifted by early studies suggesting that three doses of Pfizer (NYSE:PFE)'s COVID-19 vaccine offers protection against the Omicron variant. "The oil market has thus rightly priced out the 'worst-case scenario' again, but it would be well-advised to leave a certain residual risk to oil demand in place," said Commerzbank (DE:CBKG) analyst Carsten Fritsch. Keeping a lid on prices are faltering domestic air traffic in China, owing to tighter travel restrictions, and weaker consumer confidence after repeated small outbreaks. Ratings agency Fitch downgraded property developers China Evergrande Group and Kaisa Group, saying they had defaulted on offshore bonds. That reinforced fears of a potential slowdown in China's property sector, as well as the broader economy of the world's biggest oil importer.
Green hydrogen hub backed by $5 billion of investment planned for the UAE - France's Engie and Abu Dhabi-based renewable energy business Masdar have established a strategic alliance focused on the development of projects related to green hydrogen. In an announcement at the end of last week, the companies said the agreement would "explore the co-development of a UAE-based green hydrogen hub." While fine details of the plan were relatively sparse, the firms will look to develop projects with an electrolyzer capacity of 2 gigawatts. Investment in the initiative will amount to approximately $5 billion. In a statement, Engie CEO Catherine MacGregor described renewable hydrogen as "an essential tool for the energy transition." Engie and Masdar said they would leverage existing infrastructure to "initially target local supply, with the aim of expanding capacity to create a giga-scale green hydrogen hub for the GCC, with the potential to export to other markets." The GCC refers to the Gulf Cooperation Council, which consists of Saudi Arabia, the UAE, Bahrain, Kuwait, Qatar and Oman. Hydrogen has a diverse range of applications and can be deployed in a wide range of industries. It can be produced in a number of ways. One method includes using electrolysis, with an electric current splitting water into oxygen and hydrogen. If the electricity used in this process comes from a renewable source such as wind or solar then some call it green or renewable hydrogen. A member of oil cartel OPEC, the United Arab Emirates is a significant producer of crude and gas. It's also blessed with huge amounts of sunshine — the crucial ingredient for solar power installations.
Saudi Aramco CEO warns of social unrest if new investment in fossil fuels ends too quickly - Amin Nasser, the chief executive of Saudi Aramco, the world's biggest oil producer, urged global leaders on Monday to continue investing in planet-warming fossil fuels in the years ahead, arguing that the assumption the world could transition to clean energy "overnight" was "deeply flawed." Nasser, during remarks at the World Petroleum Congress in Houston, Texas, claimed that transitioning to cleaner fuels too rapidly could prompt uncontrolled inflation and social unrest, and ultimately upend nations' emissions targets to curb carbon pollution. "I understand that publicly admitting that oil and gas will play an essential and significant role during the transition and beyond will be hard for some," Nasser said during the conference, which has focused on low-carbon strategies and technology. "But admitting this reality will be far easier than dealing with energy insecurity, rampant inflation and social unrest as the prices become intolerably high, and seeing net-zero commitments by countries start to unravel," he continued. Nasser's remarks come amid mounting pressure on the oil and gas industry to limit exploration and production of fossil fuels and shift to renewable power development, as countries set new carbon emissions reduction targets to battle climate change. The International Energy Agency in May warned that investments in new oil and gas projects must immediately stop in order for the world to achieve net-zero emissions by 2050 and avoid the worst consequences of climate change. Keeping global temperatures from surpassing 1.5 degrees Celsius of warming will require the world to slash greenhouse gas emissions nearly in half within the next decade and reach net-zero emissions by 2050, according to the Intergovernmental Panel on Climate Change. The Earth has already warmed about 1.1 degrees Celsius above pre-industrial levels and is set to see a temperature rise of 2.4 degrees Celsius by 2100. But other world energy leaders at the conference, including the chief executives of Exxon and Chevron, also argued that demand for oil and gas will remain high in upcoming years despite efforts to transition to a clean energy economy.
Iran Nuclear Talks To Resume Thursday As US Complains Tehran 'Demanding More, Concedes Less' -The result of last week's resumption of nuclear talks in Vienna between Iran and signatories to the original Joint Comprehensive Plan of Action deal is being described in Western sources as Tehran demanding more from the US while willing to concede less. "More than five months after multilateral nuclear talks with Iran were paused before the country’s presidential elections in June, a new negotiating team arrived in Vienna in late November with additional demands and fewer concessions than its predecessors," NATO's Atlantic Council lamented in an op-ed.Over the weekend Biden administration officials questioned the Iranian side's "seriousness" - suggesting they came to the table unwilling to compromise from the start while demanding the US drop all Trump era sanctions. But on Tuesday Iranian official media announced that Vienna talks will resume Thursday."The date for the resumption of the P4 + 1 talks in Vienna has been finalized," Iran's Tasnim news agency has reported. "Iran, P4 + 1 resume talks in Vienna on Thursday."But despite Iran's willingness to continue the dialogue toward restoration of a deal, White House officials are casting severe doubts on the possibility that something firm can be reached:A US official said Saturday that Iran had backed away from all its previous compromises on reviving the 2015 nuclear deal and that the US would not allow Iran to "slow walk" the international negotiationswhile at the same time ramping up its atomic activities.The warning came a day after Washington hit out at Iran, saying talks with world powers on a return to the 2015 nuclear accord had stalled because Tehran "does not seem to be serious."
In bid to blow up nuclear talks, US imposes sanctions, steals Iranian oil --With Washington deliberately stoking tensions that could trigger all-out military clashes with both Russia and China, there is every indication that it is simultaneously seeking to blow up Iranian nuclear talks, setting the stage for a dangerous new escalation of conflict in the Middle East. On the eve of the resumption of talks in Vienna between Iran and the P4+1 (the four permanent members of the UN Security Council still nominally party to the agreement plus Germany), along with indirect talks between Tehran and Washington, the Biden administration has carried out a series of flagrant provocations. On Tuesday, the US Treasury and State Departments piled on a set of new sanctions against Iranian government entities and officials on the grounds of alleged “human rights” abuses. These come on top of the “maximum pressure” sanctions campaign imposed by the Trump administration in 2018 after it unilaterally abrogated the 2015 Iran nuclear accord. The US sanctions regime amounts to an economic blockade of Iran, targeting countries and companies daring to do business with the nation of over 85 million people and resulting in deepening poverty for the Iranian masses, while severely hindering the country’s response to the COVID-19 pandemic, which has inflicted over 130,000 recorded deaths. The Biden administration has maintained Trump’s “maximum pressure” campaign in place, continuing actions against Iran that are tantamount to a state of war. On Wednesday, the US Justice Department announced that it had carried out the “successful forfeiture” of 1.1 million barrels of Iranian petroleum products seized by the US Navy from four tankers bound for Venezuela. Seized in separate acts of US piracy in the Arabian Sea were Iranian weapons, including surface-to-air and anti-tank weapons, allegedly bound for Yemen to aid Houthi rebels in their protracted struggle against the US-backed forces of the Saudi monarchy. The proceeds from the “forfeitures”—court orders allowing the government to sell seized goods—amounted to nearly $27 million, according to the DOJ. Meanwhile, the Pentagon announced that US Defense Secretary Gen. Lloyd Austin (ret.) will meet with his Israeli counterpart Benny Gantz today “to discuss the United States’ commitment to Israel’s security and shared concerns regarding Iran’s nuclear provocations and destabilizing actions in the region.”
The Taliban are courting Iran and China, hoping to avoid blackouts if other countries cut off power to Afghanistan for non-payment The Taliban opened talks with Iran and China over electricity supplies with Afghanistan, a new attempt to stave off the possibility of a frigid winter without power. The state's embattled power company has struggled to repay other countries for imported power, according to reports in the months since the last government fell to the Taliban. Da Afghanistan Breshna Sherkat (DABS), the state power company, has spent the last months under threat of being cut off by Tajikistan, a major supplier. The risk of blackouts from non-payment was first reported by The Wall Street Journal. According to the outlet, the Taliban replaced the former DABS COO with one of its clerics in October, part of a trend of installing officials with little technical experience but strong ideology. Tajikistan is a staunch opponent of the regime, likely complicating the situation. DABS said it has struggled to pull in 26 million afghani ($270,000) in unpaid bills, and set a one-month deadline for companies and individuals to pay before it pursues legal action, local outlet TOLO News reported. On December 1, DABS spokesperson Hikmatullah Noorzaihas also said the company has been in touch with Chinese government-affiliated companies about power production, TOLO said. It came after a mid-November deal between Afghanistan and Iran for 100 megawatts of power, which was also noted by TOLO. It is unclear what terms were discussed for these deals.
Israel Launches Rare Airstrikes On Syrian Port Close To Russian Airbase Shortly after 1am local time Israeli warplanes mounted a large-scale missile strike on Syria's key port of Latakia, igniting large fires as shipping containers were engulfed. International reports underscored that "It was a rare attack on the city's port, a vital facility where much of Syria's imports are brought into the war-torn country." Indeed it was the first such known attack on Latakia's main port throughout the conflict which began over a decade ago. Syrian state TV said at least five explosions were heard, with circulating social media videos from the site showing high-reaching flames. The Israeli government didn't comment in the immediate aftermath, but its media is calling the attack a "gamechanger" in terms of drastically shifting the rules of engagement towards civilian ports. Over the course of prior years, Damascus International Airport has been struck several times. Typically the Israelis claim to be acting against Iranian weapons shipments. Regional Al-Mayadeen media described that "A military source said in a statement to SANA that at around 1.32 a.m. today, the Israeli enemy carried out an air attack with several missiles from the direction of the Mediterranean, southwest of Latakia, targeting the container yard in the commercial port of Latakia."
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