2021’s oil price rise was most in 12 years; multi-year lows for total crude supply and total oil + products inventories

oil prices rose 55% in 2021, the most since 2009; with oil in the Strategic Petroleum Reserve at fresh 19 year low, total crude supplies fell to a 118 month low; distillate supplies fell to a 21 month low, leading total oil & products supplies to largest drop in 63 months, ending at a 7 1/2 year low for total inventories…

oil prices rose for a second week after the initial Omicron selloff, as oil traders and most everyone else have become convinced that Omicron poses little risk to oil demand...after rising 4.3% to $73.79 a barrel last week on trouble in Libya, a big drawdown on US crude supplies, and on a refinery explosion in Texas, the contract price for US light sweet crude for February delivery opened lower on Monday amid new Omicron related travel restrictions, as traders worried if Omicron risks had been prematurely dismissed, but then reversed the early morning losses to rally to one month highs despite surging Omicron infections, chasing equitiy prices higher after the resumption of multilateral nuclear talks with Iran in Vienna, and settled 2.4%, or $1.78, higher at $75.57 per barrel on hopes that the Omicron variant would have a limited impact on global demand in 2022....oil rose another 2% to fresh one month highs early Tuesday along with rallying equities and a sagging U.S. dollar index, after the CDC shortened the recommended quarantine times for those who have tested positive for COVID-19 from ten days to five days , but pared a portion of the earlier gains in afternoon trading on a stronger US dollar ahead of the weekly release of U.S. inventory data from the American Petroleum Institute, to settle with a gain of 41 cents on the day to $75.98 a barrel...oil contracts again traded higher Wednesday morning after the API’s weekly report, and then spiked to new one-month highs after the EIA reported big withdrawals from crude and oil product inventories, but turned lower amid profit-taking ahead of end-year accounting and the upcoming holiday weekend, while later recovering to settle 58 cents higher at a five week closing high of $76.56 a barrel, as Americans resumed year-end travel and festivities after being assured of lower risks from Covid’s Omicron variant...after initially moving lower, oil prices again rose to new intraday highs on Thursday, as fading omicron concerns and signs of strong uptake of energy-related assets helped to support year-end buying, and settled 43 cents higher at $76.99 a barrel​,​ driven by data showing strong demand along with falling inventories and production levels in the U.S. and elsewhere still below pre-pandemic levels...oil's seven session rising streak, the longest since an eight-session rally ended February 10th, finally came to an end on Friday, when prices tumbled steadily to end $1.78 lower at $75.21 a barrel, largely due to profit taking after recent gains, but still ended 1.9% higher on the week, and 13.7% higher for December, and more than 55% higher for the year, to clinch its sharpest annual increase since 2009..

meanwhile, natural gas price quotes finished slightly lower on a change in the cited contracts, even as the now current February contract price ended higher... after rising 1.1% to $3.731 per mmBTU last week on signs of an impending polar air mass intrusion, the contract price of natural gas for January delivery opened 6% higher on Monday after forecasts showed that a bout of cold temperatures would spur heating demand for large parts of the U.S. this week, and continued rising to settle 32.9 cents higher at $4.060 per mmBTU, the largest one day price jump in over a month...natural gas prices held onto those gains on Tuesday, slipping only a half cent to $4.0​55 per mmBTU, on forecasts for milder weather and less heating demand over the next two weeks than was previously expected, while the more heavily traded February​ natural​ gas contract fell 5.7 cents to $3.885 per mmBTU at the same time, reflecting additional warming in the longer term forecast...after an initial spurt 5% higher on the potential for cold weather to last a couple of weeks, Wednesday's trading in the contract for January gas expired with gas priced 3.1 cents lower at 4.024 per mmBTU, while the incoming ​front-month February contract settled at $3.850 per mmBTU, down 3.5 cents from Tuesday's close...with the contract price of natural gas for February delivery now being quoted as the price of natural gas, prices tumbled 28.9 cents or 7.5% to a six month low of $3.561 per mmBTU on Thursday, following a 10% slide to a three week low in European gas prices despite a bigger-than-expected storage withdrawal and colder forecasts​, ​​as domestic ​gas ​production continued to rise...however, natural gas prices rebounded to recover more than half of that drop on Friday, settling 16.9 higher at $3.730 per mmBTU, on a heating degree days forecast over the next two weeks that was higher than the 30-year normal for this time of year...natural gas prices thus finished the week a tenth of a cent lower than last week's closing quote, while the February contract price, which had finished last week at $3.630 per mmBTU, ended the week 2.8% higher....for the year, natural gas prices finished over 47% higher, their biggest annual percentage rise since 2016.

The EIA's natural gas storage report for the week ending December 24th indicated that the amount of working natural gas held in underground storage in the US fell by 136 billion cubic feet to 3,226 billion cubic feet by the end of the week, which left our gas supplies 250 billion cubic feet, or 7.2% below the 3,476 billion cubic feet that were in storage on December 24th of last year, but still 19 billion cubic feet, or 0.6% above the five-year average of 3,207 billion cubic feet of natural gas that have been in storage as of the 24th of December over the most recent​ five​ years...the 136 billion cubic foot withdrawal from US natural gas working storage this week was more than the average forecast for a 127 billion cubic foot withdrawal from a S&P Global Platts' survey of analysts, and was also more than the 121 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2020, and more than the average withdrawal of 120 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 24th showed that despite increases in our oil imports and in our oil production, we still needed to pull oil out of our stored commercial crude supplies for the fifth week in a row for the 21st time in the past thirty-one weeks….our imports of crude oil rose by an average of 565,000 barrels per day to an average of 6,759,000 barrels per day, after falling by an average of 277,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 50,000 barrels per day to an average of 2,929,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,830,000 barrels of per day during the week ending December 24th, 515,000 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 200,000 barrels per day higher at 11,800,000 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 15,630,000 barrels per day during the cited reporting week…

Meanwhile, US oil refineries reported they were processing an average of 15,703,000 barrels of crude per day during the week ending December 24th, an average of 115,000 fewer barrels per day than the amount of oil that our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 704,000 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 631,000 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 inserted a (-631,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed...and since last week’s EIA fudge factor was at (-133,000) barrels per day, that means there was a 498,000 barrel per day difference between this week's error and the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are fairly useless.....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….

This week's 704,000 barrel per day decrease in our total crude oil inventories left them at 1,015,023,000 barrels, the lowest level since February 10th 2012, or at a 118 month low....this week's inventory drop came as 511,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 193,000 barrels per day of oil were pulled out of our Strategic Petroleum Reserve, part of the first installment from Biden's plan to release 50 million barrels from the SPR, in order to incentive continued use of US gas guzzlers...however, most of that unrefined sour crude is expected to go to China and India, so how it could impact US gasoline prices is unclear... including the drawdowns from the Strategic Petroleum Reserve under such politically motivated programs, a total of 57,787,000 barrels have been removed from the Strategic Petroleum Reserve over the past 18 months, and as a result the amount of oil in our Strategic Petroleum Reserve has fallen to an 19 year low of 595,028,000 barrels per day, or to the lowest since November 29, 2002, as repeated tapping of our emergency supplies for political expediency or to “pay for” other programs had already drained those supplies over the past dozen years...based on an estimated prepandemic consumption level of 18 million barrels per day, the US will have roughly 30 1/2 days of oil supply left in the Strategic Petroleum Reserve when the Biden program is complete...

Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,481,000 barrels per day last week, which was still 13.7% more than the 5,698,000 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 200,000 barrels per day higher at 11,800,000 barrels per day because the EIA's rounded estimate of the output from wells in the lower 48 states was 300,000 barrels per day higher at 11,400,000 barrels per day, while Alaska’s oil production was 5,000 barrels per day lower at 449,000 barrels per day and subtracted 100,000 barrels per day from the reported rounded national production total (by the EIA's math)...US crude oil production had reached a pre-pandemic 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 9.9% below that of our pre-pandemic production peak, but is now 40.0% 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 89.7% of their capacity while using those 15,703,000 barrels of crude per day during the week ending December 24th, up from a utilization rate of 89.6% the prior week, but still lower than the historical utilization rate for late December refinery operations…the 15,703,000 barrels per day of oil that were refined this week were 9.9% more barrels than the 14,287,000 barrels of crude that were being processed daily during the pandemic impacted week ending December 25th of last year, but 9.1% less than the 17,283,000 barrels of crude that were being processed daily during the week ending December 27th, 2019, when US refineries were operating at what was a more seasonal 94.5% of capacity...

Even with the decrease in oil being refined this week, the gasoline output from our refineries was somewhat higher, increasing by 171,000 barrels per day to 10,113,000 barrels per day during the week ending December 24th, after our gasoline output had decreased by 100,000 barrels per day over the prior week.…this week’s gasoline production was 10.0% more than the 9,191,000 barrels of gasoline that were being produced daily over the same week of last year, but 0.6% less than the gasoline production of 10,173,000 barrels per day during the week ending December 27th, 2019….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 83,000 barrels per day to 4,935,000 barrels per day, after our distillates output had increased by 40,000 barrels per day over the prior week…after that increase, our distillates output was 6.4% more than the 4,639,000 barrels of distillates that were being produced daily during the week ending December 25th, 2020, but 7.1% less than the 5,311,000 barrels of distillates that were being produced daily during the week ending December 27th, 2019..

Even with the increase in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the ninth time in twelve weeks, and for the fourteenth time in thirty-six weeks, decreasing by 1,459,000 barrels to 222,659,000 barrels during the week ending December 24th, after our gasoline inventories had increased by 5,533,000 barrels over the prior week...our gasoline supplies decreased this week because the amount of gasoline supplied to US users increased by 738,000 barrels per day to 9,724,000 barrels per day, and because our imports of gasoline fell by 256,000 barrels per day to 432,000 barrels per day, while our exports of gasoline fell by 207,000 barrels per day to 614,000 barrels per day…after this week’s inventory decrease, our gasoline supplies were 5.9% lower than last December 25th's gasoline inventories of 236,562,000 barrels, and about 6% below the five year average of our gasoline supplies for this time of the year…

Likewise, even with the increase in our distillates production, our supplies of distillate fuels decreased for the thirteenth time in eighteen weeks and for the 26th time in 38 weeks, falling by 1,726,000 barrels to a 21 month low of 122,428,000 barrels during the week ending December 24th, after our distillates supplies had increased by 396,000 barrels during the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 229,000 barrels per day to 3,882,000 barrels per day, and because our exports of distillates rose by 116,000 barrels per day to 4,051,000 barrels per day, and because our imports of distillates fell by 41,000 barrels per day to 162,000 barrels per day....after twenty-six inventory decreases over the past thirty-eight weeks, our distillate supplies at the end of the week were 19.5% below the 152,029,000 barrels of distillates that we had in storage on December 25th, 2020, and about 14% below the five year average of distillates inventories for this time of the year…

Meanwhile, despite the increases in our oil imports and in our domestic oil production, our commercial supplies of crude oil in storage fell for the 14th time in 21 weeks and for the 34th time in the past year, decreasing by 3,576,000 barrels over the week, from 423,571,000 barrels on December 17th to 419,995,000 barrels on December 24th, after our commercial crude supplies had decreased by 4,715,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories were about 7% below the most recent five-year average of crude oil supplies for this time of year, but were still 28.1% above the average of our crude oil stocks as of the fourth 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 24th were 14.9% less than the 493,469,000 barrels of oil we had in commercial storage on December 18th of 2020, and are now 2.3% less than the 441,359,000 barrels of oil that we had in storage on December 27th of 2019, and also 4.9% less than the 441,418,000 barrels of oil we had in commercial storage on December 28th 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, and including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 20,267,000 barrels this week, from 1,799,881,000 barrels on December 17th to 1,779,614,000 barrels on December 24th, the largest total inventory drop since September 30 2016, and left our total inventories at the lowest level since June 27th, 2014, or at a 7 1/2 year low... 

This Week's Rig Count

The number of drilling rigs active in the US w​as unchanged over the week ending December 31st, after they had risen 56 times over the prior 66 weeks, but still remained 26.1% below the prepandemic rig count....​(​note that last week's rig count was released on December 23rd ahead of the ensuing holiday, and hence this week's report covers the intervening eight days​)...Baker Hughes reported that the total count of rotary rigs running in the US was unchanged at 586 rigs after that period, which was still 235 more rigs than the pandemic hit 351 rigs that were in use as of the December 30th report of 2020, but was ​also ​still 1,343 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global oil market in an attempt to put US shale out of business….

The number of rigs drilling for oil was unchanged at 480 oil rigs during this week, after they had increased by 5 rigs during the prior week, while there are still 213 more oil rigs active now than were running a year ago, even as they still amount to just 29.8% 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 was unchanged at 106 natural gas rigs, which was still up by 23 natural gas rigs from the 83 natural gas rigs that were drilling during the same week a year ago, but still only 6.6% 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 unchanged at 15 rigs this week, with thirteen 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 two less than the count of 17 rigs that were active in the Gulf a year ago, when 14 Gulf rigs were drilling for oil offshore from Louisiana and three were 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 counts are equal to the national offshore totals for both years....In addition to those rigs offshore, we continue to have one water based rig drilling for oil inland in the Galveston Bay area, and hence the inland waters rig count of one is down from two a year ago..

The count of active horizontal drilling rigs was up by 2 to 530 horizontal rigs this week, which was also 217 more than the 313 horizontal rigs that were in use in the US on December 30th of last year, but still 61.4% less than the record 1,374 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the vertical rig count was down by 1 to 26 vertical rigs this week, but those were still up by 9 from the 17 vertical rigs that were operating during the same week a year ago….at the same time, the directional rig count was​ also​ down by one to 30 directional rigs this week, but those were also still up by 9 from the 21 directional rigs that were in use on December 30th 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 31st, the second column shows the change in the number of working rigs between last week’s count (December 23rd) and this week’s (December 31st) count, the third column shows last week’s December 23rd 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 30th of December, 2020...

with just a few changes this week, we'll start by checking the Rigs by State file at Baker Hughes for changes in the Texas Permian basin...there we find that two rigs were pulled out of Texas Oil District 8, which is the core Permian Delaware, and that the rig counts in the other Texas Permian basin Districts were unchanged....since the Texas Permian rig count was thus down by two while the national Permian rig count was down by just one, that means that the rig that was added in New Mexico had to have been deployed in the western Permian Delaware...meanwhile, since there are no other ​rig count ​changes elsewhere in Texas, the 2 Permian rigs that were pulled out of District 8 account for this week's 2 rig Texas decrease..

in Louisiana, we have a natural gas rig addition in the Haynesville shale in the northwestern part of the state, and in Oklahoma, we have an oil rig addition in the Cana Woodford, while in Utah, there was an oil rig pulled out of the Uintah basin, which Baker Hughes does not report but which we were able to ​ascertain by checking the individual well records in the North America Rotary Rig Count Pivot Table (Feb 2011 - Current), which shows that a directional rig targeting oil rig ​was missing from Duchesne county, which happens to overlie the Uintah basin in that state...meanwhile, not apparent in the tables above is that a natural gas rig was pulled out of a basin that Baker Hughes doesn't track, which would have had to have been matched by a similar untracked oil rig addition in the same state, because all of our other counts balance otherwise...

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Ohio oil, gas counties' economy grew in 2020, urban areas declined - The Columbus Dispatch --Two small eastern Ohio counties in the heart of Ohio's natural gas country posted the biggest economic gains among the state's counties in 2020.The big gains in Harrison and Monroe counties came even as COVID-19 plunged most of Ohio's 88 counties and its biggest metro areas into a brief, but steep, recession. Only 18 counties had growth last year.Harrison and Monroe counties each posted a 20.5% increase in their economy in 2020, according to federal data released this month.Both counties are small so even a minimal increase in the economy can produce big change.Monroe County's economic activity was measured at $1.9 billion in 2020, while Harrison's was measured at $1.6 billion.Both counties have benefited from the surge in natural gas and oil drilling in Appalachia over the past decade that has helped offset thedecline in coal use.Total investment in the region has hit $93 billion from 2011 through 2020, according to Cleveland State University researchers who track oil and gas spending in the region.Monroe County also has benefited from the redevelopment of the old Ormet aluminum smelter site in recent years that includes the new natural gas power plant at the Long Ridge Energy Terminal, which one day could run on hydrogen as well as gas.Harrison County also is developing a power plant. Monroe County's gain follows a 23.7% increase in 2019 and 7.7% in 2018."There's been a lot of capital investment," said Jason Hamman, an economic development consultant for onroe County, citing the drilling, pipelines, the power plant and other activity taking place.

FERC Issues Show Cause Orders to Two Natural Gas Pipelines – Lexology -- The Federal Energy Regulatory Commission issued show cause orders to two natural pipelines—Rover Pipeline and Midship Pipeline Company—following its December 2021 open meeting, and sent a related dispute involving Midship for an administrative hearing. Chairman Richard Glick has signaled in the last year his desire for a more active enforcement program.

• Rover Pipeline LLC: During the construction of a 711-mile interstate gas pipeline in 2017, a large inadvertent release of two million gallons of drill mud flowed into a nearby wetland. Testing of the release by a state agency revealed the presence of diesel fuel and other chemicals that were not approved for use in drilling operations.FERC’s Office of Enforcement commenced an investigation (Docket No. IN17-4). Based on interviews with witnesses and contractors, the office alleges that Rover Pipeline LLC intentionally employed or directed its contractors to employ these unapproved additives to maintain drilling progress in the face of difficult drilling conditions. Based on the investigatory report, the Commission has ordered Rover to show cause as to why it has not violated the Natural Gas Act and the Commission’s regulations. Specifically, FERC alleges that Rover
  • intentionally included diesel fuel and other toxic substances and unapproved additives in the drilling mud during its horizontal directional drilling (HDD) operations under the Tuscarawas River in Stark County, Ohio;
  • failed to adequately monitor the right-of-way at the site of the Tuscarawas River HDD operation; and
  • improperly disposed of inadvertently released drilling mud that was contaminated with diesel fuel and hydraulic oil.

  FERC’s Office of Enforcement also recommended a $40 million civil penalty, and the Commission ordered Rover to show cause as to why it should not face that penalty.

• Midship Pipeline Company LLC: Midship Pipeline Company constructed an approximately 200-mile interstate natural gas pipeline in Oklahoma in 2019–2020 under a certification issued in 2019 (Docket No. CP17-458). Midship placed the pipeline into service in April 2020. During a subsequent review of Midship’s compliance with environmental conditions imposed on the project, FERC identified instances of noncompliance, namely instances of failing to remediate landowner properties—rocks and other construction debris had not been removed from landowner property, and had been buried on the property without landowner approval. Natural gas companies are required by their certificates of public convenience and necessity to return lands impacted by pipeline construction to their preconstruction condition. The Commission ordered Midship to remediate the noncompliance in March 2021, but a June 2021 report identified the continued presence of rocks and other construction debris left in the right-of-way or improperly buried in the project workplace. Further evaluation in September and October identified that construction debris remained improperly buried within the right-of-way, including on properties not originally identified by FERC. The Commission expressed concern that “buried rock and construction debris may be pervasive throughout the 200-mile-long pipeline.” In response, FERC ordered several actions:
  1. The Commission ordered Midship to show cause as to why the Commission (a) should not find that Midship improperly disposed of rock and debris along the right-of-way and (b) should not require Midship to immediately remove this rock and debris.
  2. The show cause order also ordered Midship to file within 60 days a detailed plan to investigate the extent of the buried rock and debris along the pipeline. Midship must then present a remediation plan for Commission approval.
  3. The show cause order indicated that the Commission has referred this matter to the Office of Enforcement for investigation. Further investigation indicates future Commission action, such as an imposition of civil penalties, if warranted by the investigatory findings.
  4. In a separate order, the Commission noted that one affected landowner seeks to reach a settlement by which it can self-perform outstanding remedial activities. The landowner fears further property damage if Midship remobilizes to restore the property. Midship and the landowner are at an impasse. Accordingly, the Commission has set this matter for an administrative hearing to determine the remaining scope of work necessary for Midship to meet its certificate obligations and a reasonable cost to complete the activities. But although FERC can order remediation, it cannot order damages. Thus, it is not clear what FERC intends to do with the results of the hearing, or if the aim is instead to encourage settlement.
  5. The Commission ordered Midship to file a plan to remediate another landowner’s property within 120 days of the order and in consultation with the landowner. Midship must then allow 30 days for the landowner to comment and, if applicable, explain any decision not to adopt the landowner’s recommendations. Midship must then await FERC approval before undertaking mitigation. Alternatively, Midship and the landowner may reach a settlement for the landowner to self-perform remediation activities.

Mariner East to Resume Construction After Marsh Creek Settlement - Pennsylvania’s Department of Environmental Protection (DEP) has cleared the way for Sunoco Pipeline LP to reroute part of its Mariner East natural gas liquids system near Marsh Creek Lake State Park in Chester County, PA. Construction was halted last August when drilling fluids and mud seeped into a part of the lake called Ranger Cove during the pipeline installation. The cove then was closed.As part of a settlement, Sunoco agreed to pay $4 million to the Pennsylvania Department of Conservation and Natural Resources (DCNR). The company also agreed to dredge Ranger Cove and pay a $341,000 civil penalty for permit violations.In return, DEP approved major amendment applications and permits allowing for a new route and pipeline installation method.“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,” DCNR Secretary Cindy Adams Dunn said. “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.”The modification changes the pipeline route slightly on a 1,400-foot section of the line, according to Energy Transfer LP, which is expanding the pipeline system. Once work begins, installation takes five to 10 weeks. No drilling fluids would be used, the company said. The pipeline system, which traverses Pennsylvania and extends into Ohio and West Virginia, can move 280,000-300,000 b/d of liquefied petroleum gas and 70,000 b/d of ethane eastward. Online since 2016, the pipeline project has faced numerous regulatory, legal and construction setbacks. In October, the Delaware County Court of Common Pleas in Pennsylvaniaordered the public release of emails between Energy Transfer/Sunoco LP and officials with Middletown Township. In late May, a water main break that occurred during ME construction left residents of the Glen Riddle Station Apartments without water and prompted subsequent questions from the apartment complex owner about whether the water was safe to drink after service was restored.

Restoring Lands Impacted by Scuttled Appalachian Natural Gas Pipelines to Cause Minimal Impacts, FERC Affirms --Restoration projects for the now canceled Atlantic Coast Pipeline (ACP) and Supply Header Project (SHP), which would have carried 1.5 Bcf/d from Appalachia, are unlikely to cause significant environmental impacts based on the mitigation measures planned, according to FERC.Dominion Energy and joint venture partner Duke Energy last year canceled the 600-mile, 1.5 Bcf/d ACP, designed to run from West Virginia into Virginia and North Carolina. The related SHP system also was canceled.The staff of the Federal Energy Regulatory Commission in July had determined in a draft environmental impact statement (EIS) that restoring lands impacted by the scuttled systems would likely be able to avoid or reduce impacts to less than significant levels. The sponsors, Atlantic Coast Pipeline LLC and Eastern Gas Transmission and Storage Inc., are proposing to stabilize the lands that were affected by the previous construction efforts. The projects are part of ceasing all project-related activities. The restoration projects, “with the mitigation measures discussed” in the supplemental EIS, would continue to avoid or reduce impacts to less than significant levels, “with the exception of climate change impacts, for which FERC staff is unable to determine significance,” it noted.The final supplemental EIS was issued earlier in December to comply with the National Environmental Policy Act. The U.S. Fish and Wildlife Service and the U.S. Department of Agriculture – Forest Service were cooperating agencies.The supplemental EIS determination, said FERC staff, was based on reviewing the information filed by the sponsors “and developed further using data requests, scoping, literature research and contacts with federal agencies.”In the review, staff developed specific mitigation measures that it determined would appropriately and reasonably reduce the environmental impacts resulting from restoration activities. The Commission is to consider the staff recommendations when the decisions are made about the restoration projects.

Another Legal Battle Looms Over Mountain Valley Pipeline | WVPB -- Opponents of the Mountain Valley Pipeline are gearing up for another legal fight to try to stop the natural gas project. The Roanoke Times reports that environmental and community groups filed a petition this week with a federal appeals court. The groups want the court to review last week's decision by the State Water Control Board to allow the infrastructure to cross streams and wetlands. The pipeline's planned 300-mile route cuts through West Virginia and Virginia. The Sierra Club was among the groups that filed the petition with the 4th U.S. Circuit Court of Appeals. Pipeline opponents say Mountain Valley should not be allowed to continue given its past track record of violating erosion and sediment regulations in southwest Virginia. But Mountain Valley said those problems were largely caused by heavy rain in 2018 and have been corrected. Attempts to kill the $6.2 billion project have so far failed. Five energy companies constructing the pipeline say it's necessary to provide natural gas along the East Coast.

Massachusetts Court Tosses Lawsuit Challenging Atlantic Bridge Natural Gas Facility - A Massachusetts appeals court has dismissed a lawsuit challenging one of the approvals of the Weymouth natural gas compressor station along the Atlantic Bridge Project, which transports Appalachia supply into Canada. A three-judge panel agreed with the Supreme Judicial Court judge’s ruling that the Fore River Residents Against the Compressor Station (FRRACS) could not seek judicial review of the Weymouth compressor approval. The approval was issued by the Massachusetts Office of Coastal Zone Management (CZM). The group did not have the right to an agency hearing, and therefore could not request a judicial review, the appeals court stated. The appellate panel also agreed with the judge that FRRACS did not meet other standards under which it could have sought a judicial review. The panel in its ruling said “nothing in the statutory language, legislative intent or regulatory scheme indicates that the public may seek judicial review of a CZM consistency determination” [AC 21-P-149]. The Weymouth compressor was one of the final pieces of the Atlantic Bridge Project to be placed into service by Enbridge Inc. subsidiary Algonquin Gas Transmission (AGT). The expansion added 132,705 Dth/d to the AGT and Maritimes & Northeast (M&NE) pipeline systems in New England, which transport gas into Canada. AGT comprises 1,129 miles of pipeline in New England, New Jersey and New York. M&NE comprises 346 miles of pipeline in the Northeast and 543 miles in Canada.AGT and Maritimes filed for a certificate to construct Atlantic Bridge in 2015. Although approved by federal regulators in January 2017, AGT took three more years to bring the project online following opposition from environmental groups.Since coming into service in late 2020, the Weymouth compressor has experienced two unplanned outages. The first occurred immediately after in-service when emergency shutdowns led to a release of gas into the air. The force majeure lasted from Oct. 1, 2020, through Jan. 24. A second force majeure was declared in April.

Paloma Gains Gassy Haynesville – and More – in Completing Goodrich Takeover - An affiliate of private equity giant EnCap Investments has officially taken Houston-based Goodrich Petroleum Corp. private after completing a $23/share tender offer. Paloma Partners VI Holdings LLC, an entity of Houston’s Paloma Resources LLC, on Dec. 23 completed the estimated $480 million takeover, which was announced in November. Paloma, now active in Oklahoma, gains a broad set of assets across the Lower 48, including a substantial and growing business in the natural gas-rich Haynesville Shale. Goodrich has around 32,000 net acres in the Haynesville, 34,000 net acres in the Tuscaloosa Marine Shale and 4,300 net undeveloped acres in the Eagle Ford Shale. The Haynesville has been the primary target, with its proved gas reserves making up 99% of the total 543 Bcfe at the end of 2020. Goodrich’s production climbed 7% sequentially in 3Q2021 to 166 MMcfe/d, 99% weighted to natural gas. During the quarterly conference call in November, CEO Gil Goodrich said the company’s current hedge position for natural gas prices provided “substantial downside protection while also giving us substantial exposure to higher unhedged prices as we execute our 2022 plans.” The company has an estimated 2.4 Tcfe of resource potential in Northern Louisiana, with 127 net potential drilling locations using 880-foot spacing. Goodrich has an 85% working interest in the core of the Haynesville position, with Chesapeake Energy Corp. holding 15%. Capital expenditures in 3Q2021 totaled almost $28 million, with most of it “spent on drilling, completion and facility costs associated with Haynesville wells,” COO Robert Turnham told analysts in November. “To date, we’ve only seen a small amount of service cost inflation, and our economics…are as good as we have seen them in the basin.” The Paloma Resources arm initially was sponsored by EnCap in 2014. Previous entities have created and sold positions in the Barnett, Eagle Ford and Utica shales.

Natural-Gas Prices Rise on Colder Weather Forecasts – WSJ Natural-gas prices rose Monday after weather forecasts showed a bout of cold temperatures that could spur heating demand for parts of the U.S. this week.U.S. natural-gas futures finished Monday’s session at $4.060 per million British thermal units. That is up 8.8% from $3.731 per million BTUs at Friday’s close and the largest dollar gain since Nov. 26.The Weather Prediction Center predicted heavy snow, freezing temperatures and strong winds in the northern and western parts of the country.“The colder weather coming to the U.S. will be watched and we should see a substantial pick up in heating demand next week,” wrote BOK Financial analysts in a note. As the weather turns colder this week, Refinitiv is projecting average U.S. gas demand, including exports, to jump to 126.7 billion cubic feet a day, up from 110 billion.Most investors have been betting on a decline in gas prices. The number of bets by hedge funds and other speculators that prices will decline continue to outnumber those on rising prices by a wide margin, according to recent Commodity Futures Trading Commission data. Monday’s rise marks a break from themonthslong decline in natural-gas prices. An uptick in domestic gas production and an unseasonably warm fall and winter delayed heating season in much of the country, causing prices to come down. Natural-gas prices extended declines last week after the U.S. Energy Information Administration storage report showed a weekly decline of 55 billion cubic feet. That fell short of the 57 billion forecast from analysts surveyed by The Wall Street Journal, helping push gas storage into a small surplus. Prices skyrocketed earlier in the year, however, surpassing $6 per MMBtu in October. It isn’t unusual for natural-gas prices to bounce around a lot this time of year, when traders must triangulate winter weather forecasts with production reports and inventory data. Much of the world is on watch for heating-fuel shortages this winter after a lot of gas was burned for air-conditioning during some of the hottest summer weather ever recorded in the Northern Hemisphere. Other factors have put pressure on gas prices. A lack of coal supplies has caused generators to conserve coal stockpiles and boost natural-gas-fired generation, said Bank of America analysts in a recent note.

UPDATE 1-U.S. natgas jumps nearly 9% to 3-week high on colder weather outlook (Reuters) - U.S. natural gas futures jumped almost 9% on Monday to a three-week high on forecasts for colder weather and higher heating demand over the next two weeks. Front-month gas futures rose 32.9 cents, or 8.8%, to settle at $4.060 per million British thermal units (mmBtu), their highest close since Dec. 3. The contract fell more than 6% on Thursday. "Reversal from last week's profit taking is being driven by colder weather model runs," Robert DiDona of Energy Ventures Analysis said. "Overall, the discussion will focus on the short-term weather forecast. Futures will be highly dependent on this cold weather pattern setting up for H1 January. If we get the cold air pushing into the L48, prices have a chance to rise. If not, we will see selling." Data provider Refinitiv estimated 420 heating degree days (HDDs) over the next two weeks in the Lower 48 U.S. states, up from the 402 HDDs estimated on Friday. The normal is 437 HDDs for this time of year. HDDs, used to estimate demand to heat homes and businesses, measure the number of degrees a day's average temperature is below 65 Fahrenheit (18 Celsius). Refinitiv projected average U.S. gas demand, including exports, would jump from 110.0 billion cubic feet per day (bcfd) this week to 126.7 bcfd next week as the weather turns seasonally colder. In recent months, global gas prices hit record highs as utilities around the world scrambled for LNG cargoes to replenish low stockpiles in Europe and meet insatiable demand in Asia, where energy shortfalls have caused power blackouts in China. The amount of gas flowing to U.S. LNG export plants has averaged 11.9 bcfd so far in December, now the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana is producing LNG. That compares with 11.4 bcfd in November and a monthly record of 11.5 bcfd in April. Output in the U.S. Lower 48 has averaged 97.0 billion cubic feet per day (bcfd) so far in December, which would top the monthly record of 96.5 bcfd in November.

Natural Gas Futures Steady in Rare Quiet Session Ahead of Expiration; Cash Rising - Natural gas futures held onto the extensive gains they accumulated at the start of the holiday week, slipping only a few pennies on additional warming in the forecast. The January Nymex contract settled Tuesday at $4.055/MMBtu, off only a half-cent from Monday’s close. The February contract slipped 5.7 cents to $3.885. Spot gas prices gathered momentum in every U.S. region except the East Coast. NGI’s Spot Gas National Avg. climbed 9.5 cents to $4.125. The week between Christmas and New Year’s Day is a notoriously volatile period for Nymex futures, with big swings and thin volumes seen as the year draws to a close. On Tuesday, only about 31,000 prompt-month contracts were traded, compared to more than 107,000 February contracts. Mobius Risk Group pointed out that futures traders – the few there are this week – are dealing with the push and pull of several fundamental factors. Increasingly volatile liquefied natural gas (LNG) destination markets and a “seemingly perpetually lingering” threat of cold also are being considered. Nevertheless, “January has remained anchored near $4.00,” the firm said. On the weather front, models have trended warmer in recent runs, failing to bring forward any widespread cold despite some support in global pattern drivers. NatGasWeather said cold air over the Northern Plains is expected to slide south into North Texas and eastward across the rest of the northern United States late in the week. Overnight temperatures are forecast to fall as low as the single digits, but the blast of chilly air has lost some intensity in recent days. Furthermore, there is a warmer-trending break during the middle and end of next week, according to the forecaster, where much of the southern and eastern halves of the country are seeing warming above normal once again. Even a subsequent cold shot on the radar for Jan. 7-9 has lost some of its chill factor in recent model runs.“What still needs resolving is just how much cold air advances out of the Northern Plains south and eastward Jan. 9-12 since there’s potential these days still play out rather frosty,” NatGasWeather said. “We continue to see some risk Texas and the Southern Plains eventually will see a shot of frigid air at some point in mid-January, thereby requiring close monitoring.” Meanwhile, Bloomberg data showed production holding near 97 Bcf/d, its highest level since late November.

January Natural Gas Futures Expire Lower Despite Colder Turns in Latest Weather Data; Cash Soft - Natural gas futures surged midweek as Old Man Winter appeared ready to ring in the new year. Even with the potential for cold weather to last a couple of weeks, though, the January Nymex futures contract expired 3.1 cents lower at $4.024/MMBtu. The incoming prompt-month February contract settled at $3.850, down 3.5 cents from Tuesday’s close. Spot gas, which traded Wednesday for gas delivery on Thursday and Friday, was lower across most of the country. NGI’s Spot Gas National Avg. tumbled 18.5 cents to $3.860. After trending warmer in recent runs, weather models moved in the colder direction overnight and generally maintained the added demand in the 15-day outlook in the midday run. NatGasWeather said the Global Forecast System (GFS) reflected little change in the first seven days of the forecast, with a few more days of exceptionally mild temperatures and modest demand. However, the American model shifted even colder for the Jan. 6-11 period. Weather forecasts continued to show frosty air in the Northern Plains sliding south across North Texas on Sunday and Monday before tracking eastward across the rest of the northern United States. NatGasWeather said overnight lows could fall below zero in some areas. This is a sharp departure from the record high temperatures set in the Lone Star State this week. For example, temperatures Wednesday morning had already reached a balmy 75, which is a staggering 30 degrees above normal for late December. By Sunday, morning lows are forecast in the 30s. The latest midday GFS showed a milder break starting next Tuesday through Jan. 7, according to NatGasWeather. However, it was quicker with the next cold shot arriving Jan. 7 instead of Jan. 8 to gain several heating degree days. Furthermore, there is enough cold air lingering across the northern United States Jan. 9-12 in the latest GFS to keep the back end of the 15-day forecast cold enough to satisfy. With volatility continuing in the final days of the year, the next government inventory report also could cause a stir in the market. Market estimates ahead of the Energy Information Administration’s (EIA) weekly storage report, scheduled for 10:30 a.m. Thursday, were wide ranging, with no clear indication of how steep inventories may fall. A Wall Street Journal survey of 11 analysts produced a range of withdrawal estimates from 66 Bcf to 128 Bcf, with an average draw of 114 Bcf. A Reuters poll had an even wider range, with a median pull of 126 Bcf. NGI modeled a 142 Bcf withdrawal. For reference, the EIA recorded a 120 Bcf draw in the same week last year and the five-year average pull is 121 Bcf.

U.S. natgas falls to six-month low on rising output, drop in European prices - (Reuters) - U.S. natural gas futures dropped more than 7% on Thursday to a six-month low, following a slide in European gas prices, as output continues to rise. The price drop came despite a bigger-than-expected storage withdrawal last week and forecasts for colder weather and more heating demand over the next two weeks. On its first day as the front-month, gas futures fell 28.9 cents, or 7.5%, to settle at $3.561 per million British thermal units (mmBtu), their lowest close since June 25. The U.S. Energy Information Administration (EIA) said utilities pulled 136 billion cubic feet (bcf) of gas from storage during the week ended Dec. 24.. That was higher to the 125-bcf decline that analysts had forecast in a Reuters poll and compared with a draw of 120 bcf in the same week last year and a five-year (2016-2020) average decline of 121 bcf. Last week's withdrawal reduced stockpiles to 3.226 trillion cubic feet (tcf), or 0.6% above the five-year average of 3.207 tcf for this time of the year. "A slide in European prices might be having some downward effect on the U.S. market, although I do expect U.S. LNG exports to remain at full capacity for many months to come," said John Abeln, an analyst with data provider Refinitiv. "However, near-term outlook remains slightly bearish with production increasing over the past few weeks." Output in the U.S. Lower 48 has averaged 97.1 billion cubic feet per day (bcfd) so far in December, which would top the monthly record of 96.5 bcfd in November. Gas prices in Europe dropped more than 10% to a more than three-week low as mild weather capped demand and a steady flow of liquefied natural gas (LNG) offset low Russian pipeline flows. Refinitiv estimated 464 heating degree days (HDDs) over the next two weeks in the Lower 48 U.S. states, up from the 454 HDDs estimated on Tuesday. The normal is 440 HDDs for this time of year. HDDs, used to estimate demand to heat homes and businesses, measure the number of degrees a day's average temperature is below 65 Fahrenheit (18 Celsius). Refinitiv projected average U.S. gas demand, including exports, would jump from 109.6 billion cubic feet per day this week to 125.9 bcfd next week as the weather turns seasonally colder. The amount of gas flowing to U.S. LNG export plants has averaged 11.9 bcfd so far in December, now the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana is producing LNG. That compares with 11.4 bcfd in November and a monthly record of 11.5 bcfd in April.

U.S. natgas marks best year since 2016 amid global price surge (Reuters) - U.S. natural gas futures on Friday closed out their biggest yearly gain in five powered mostly by strong demand for U.S. liquefied natural gas (LNG) exports helped by an initial surge in global prices. The contract climbed to its highest in more than a decade, at about $6.5 per million British thermal units (mmBtu) earlier in 2021. But the last quarter of the year was still its worst since the third quarter of 2008, with the market pressured by a subsequent retreat in European prices with forecasts projecting a milder-than-expected winter. "We're getting more tied to the global market." Front-month gas futures rose 16.9 cents, or about 5%, to settle at $3.730 per million British thermal units. For the year, the contract jumped over 47%, its biggest yearly percentage rise since 2016. Data provider Refinitiv estimated 462 heating degree days (HDDs) over the next two weeks in the lower 48 U.S. states, higher than the 30-year normal of 441 HDDs for this time of year. HDDs, used to estimate demand to heat homes and businesses, measure the number of degrees a day's average temperature is below 65 Fahrenheit (18 Celsius). Preliminary data from Refinitiv showed output in the U.S. lower 48 has averaged 97.4 billion cubic feet per day (bcfd) so far in December, which would top November's monthly record of 96.5 bcfd. The amount of gas flowing to U.S. LNG export plants has averaged 12.2 bcfd so far in December, now that the sixth train at Cheniere Energy Inc's Sabine Pass plant in Louisiana is producing LNG. That compares with 11.4 bcfd in November and is likely to beat the monthly record of 11.5 bcfd set in April.

Sempra sells stake in North Am LNG business for $1.8bn --Sempra announced on December 22 it had sold a 10% stake in Sempra Infrastructure Partners, which manages the group's North American LNG assets, to the Abu Dhabi Investment Authority (ADIA) for some $1.785bn. The transaction places Sempra Infrastructure's overall value at $26.5bn, including some $8.6bn in asset-related debt. It comes two months after Sempra divested a 20% interest in Sempra Infrastructure to US investment firm KKR for $3.38bn. Sempra Infrastructure's business includes the Energia Costa Azul (ECA) LNG export project in Mexico's Baja California region, as well as the Cameron LNG export terminal in Louisiana, and gas pipeline and renewable energy assets. Sempra took a final investment decision on ECA's 3.25mn mt/yr first phase in November 2020, representing the only sanctioning of new liquefaction capacity in that year. The terminal provides an outlet for US gas to be delivered to Asian markets without having to pass through the Suez Canal. It is expected to start up in 2024. Bringing on board ADIA as an investor will help Sempra "build out a growth platform with an increasingly global capability," the US company's CEO Jeffrey Martin said in a statement. "The timing of the transaction is attractive because it allows us to efficiently rotate capital into a growing set of investment opportunities at our utilities and return capital to our owners in the form of share repurchases," he continued. "This transaction allows us to do both, while also supporting our balance sheet." Sempra said it will repurchase $500mn of its stock using some of the proceeds. "At ADIA, we see tremendous opportunity in the ongoing transformation of global energy markets," the UAE agency's director of retail estate and infrastructure, Khadem Al Remaithi commented. "In North America, few businesses are as well positioned as Sempra Infrastructure to build the new energy systems for the 21st century."

Texas, Louisiana and New Mexico Energy Execs Optimistic on ‘22 Natural Gas, Oil Prices - Executives in the energy breadbasket of the country are forecasting Henry Hub natural gas prices to average $4.06/MMBtu at the end of 2022, according to the latest quarterly survey by the Federal Reserve Bank of Dallas. The Dallas Fed, as it is known, every three months surveys exploration and production (E&P) companies and oilfield services (OFS) firms headquartered in the Eleventh District, which encompasses Texas, Northern Louisiana and southern New Mexico. For the latest survey, 134 executives responded, including 90 E&Ps and 44 OFS firms. The survey, conducted Dec. 8-16, queried executives about capital expenditures (capex) plans and commodity prices, among other things. They also were asked for their outlook on prices for goods and services. Overall, the region’s oil and gas sector continued to grow in the final three months, executives said. “The business activity index, which is the survey’s broadest measure of conditions facing Eleventh District energy firms, remained elevated at 42.6, essentially unchanged from its third quarter reading,” the Dallas Fed’s researchers said. Executives from 129 firms offered their forecast for year-end 2022 Henry Hub gas. Spot prices averaged $3.76 during the survey period. While more than 30% predicted the average gas price outlook would be $4.00-4.06, slightly fewer forecast prices would average $3.50-3.99 by the end of 2022. Close to 5% expect the gas price to exceed $6.00 by the end of next year. For West Texas Intermediate (WTI) oil, respondents predicted a year-end 2022 price would average $75/bbl, with a range of $50 to $125. WTI spot averaged $71 during the survey collection period. Oil production increased at a faster pace during 4Q2021, E&P executives said. “The oil production index moved up from 10.7 in the third quarter to 19.1 in the fourth quarter,” according to the survey. “Similarly, the natural gas production index advanced seven points to 26.1.” Along with rising output, costs also increased sharply for the third straight quarter. Among OFS firms, “the index for input costs increased from 60.8 to 69.8 – a record high and suggestive of significant cost pressures,” said researchers. “Only one of the 44 responding OFS firms reported lower input costs this quarter. “Among E&P firms, the index for finding and development costs advanced from 33.0 in the third quarter to 44.9 in the fourth. Additionally, the index for lease operating expenses also increased, from 29.4 to 42.0. Both of these indexes reached their highest readings in the survey’s five-year history.”

Marathon to receive second release from U.S. strategic petroleum reserve --The U.S. Energy Department awarded a second batch of crude oil from the strategic reserve to Marathon Petroleum Corp. as part of the Biden administration’s effort to lower energy costs. Marathon will receive 250,000 barrels of crude oil as part of an exchange from the Strategic Petroleum Reserve, the Department of Energy said on its website. Exxon Mobil Corp. was granted the first batch of crude of 4.8 million barrels. The government offered a total of 32 million barrels of high sulfur crude for exchange supply from January through March, with an option for December deliveries. West Texas Intermediate crude futures have dropped about 14% since late October, when the U.S. began indicating they were considering a variety of tools to bring down fuel prices. Oil dropped more sharply since news of the omicron variant of the coronavirus broke in late November. But perceptions that the latest strain won’t severely impact demand is giving crude prices some support. On Dec. 17, the agency issued a tender to sell 18 million barrels of sour crude from the SPR to be delivered in February and March. The tender will close on January 4.

Listen: Refiners urge US EPA to grant biofuel waivers to ease pump prices - S&P Global Platts Capitol Crude podcast -- US oil refiners are pushing back against the Environmental Protection Agency's proposal to deny small refinery exemptions and other aspects of the latest biofuel mandate. They argue the policy will force some plants to close and increase gasoline prices further at a time the Biden administration is looking to ease pain at the pump for US drivers. In its long-awaited Renewable Fuel Standard proposal, EPA adjusted down blending volumes for 2020 and 2021 to take into account the severe drop in transportation fuel demand resulting from coronavirus pandemic lockdowns. Refiners report gasoline and diesel demand inching back up to over 90% of 2019 levels, but a full recovery is not expected until late in 2022. Platts senior writer Janet McGurty spoke with Derrick Morgan, senior vice president for federal and regulatory affairs at the American Fuel & Petrochemical Manufacturers, about the small refinery waivers, RIN market volatility and how refiners view the latest blending targets.

Regiment Building Pump-Down Arsenal in Permian, Eagle Ford --Regiment LLC, whose oilfield services are focused in the Permian Basin and Eagle Ford Shale, said it has expanded its completions fleet with two recent acquisitions. The privately held operator disclosed few financial details. In late September, it said it acquired a fleet of pumps and high specification fracture stack equipment from a private pressure pumper. In a separate transaction in November, Regiment said it tacked on more pressure pumping equipment with a Permian operator.Together, the purchases increased the total asset base to more than 75,000 hydraulic hp, the Midland, TX-based operator said. “The addition of Tier IV equipment and the optionality of dual-fuel consumption will help Regiment lower its emissions as customers seek to reduce their carbon footprint. “We have grown our equipment base substantially in 2021, with plans for continued expansion in 2022.” Regiment is a portfolio company of Energy Founders Fund LP, which is sponsored by Houston-based private equity fund Donovan Ventures. Upstream oil and gas employment in Texas reached 185,800 in November, representing increases of 2,400 jobs month/month and 24,800 positions year/year, the Texas Independent Producers and Royalty Owners Association recently reported. According to Baker Hughes Co. (BKR), the oil and gas rig count in the Permian has risen by about 70% from a year ago, with the Eagle Ford up by 69%. Regiment specializes in pump down and toe preparations to complete wells. Pump-down perforating, according to BKR, is a “completion technique of conveying perforating guns and a plug into horizontal wells by pumping fluids from surface. Once the plug is set at its required depth, the guns receive commands via wireline to fire, creating production pathways through the cased and cemented well and into the formation.”

Pioneer Natural Resources completes $3 billion exit from Delaware Basin -- A $3 billion sale of Pioneer Natural Resources’ assets in the Delaware Basin was completed last week and the company plans to focus its oil and gas operations to the east. Pioneer announced the sale to Continental Resources in November, seeking to divest from the Delaware – a sub-basin that spans southeast New Mexico and West Texas on the western side of the larger Permian Basin – in favor of developing operations in the Permian’s eastern Midland sub-Basin. Pioneer Chief Executive Officer Scott Sheffield said the deal would allow Pioneer to refocus its resources in the Midland area where he said the company is the largest acreage holder. The sale included about 92,000 acres with an estimated production of about 50,000 barrels of oil equivalent per day and 35,000 barrels of oil per day. “This transaction returns Pioneer to being 100% focused on its high-margin, high-return Midland Basin assets, where we have the largest acreage position and drilling inventory,” Sheffield said. “Proceeds from this divestment will be used to further strengthen Pioneer’s balance sheet, improving our already strong leverage metrics.” Continental CEO Bill Berry said the purchase will mark the company’s entrance into the Permian Basin region, complimenting assets held in the Bakken region in North Dakota, along with the Powder River Basin in Colorado and operations in Oklahoma. "Continental's foundation has always been built upon a strong geology-led corporate strategy,” Berry said. “This continues today and has directly led us to our new strategic position in the Permian Basin.” Following the sale, Continental expected the assets to $750 million in annual cashflow from operations as 98 percent of the lands were in operations. In total, the assets include more than 1,000 locations in the Bone Spring and Wolfcamp formations along with others in the Northern Delaware Basin, including water management infrastructure.

Texas Natural Gas, Oil Regulator Investigating Another Permian Earthquake - The Railroad Commission of Texas (RRC) is suspending all disposal well permits to inject oil and gas waste into deep strata within a portion of the Permian Basin following a series of earthquakes. The action, taken earlier in December and set to take effect on Friday (Dec. 31), applies to 33 deep disposal wells within the boundaries of the Gardendale Seismic Response Area (SRA). The area includes northeastern Ector County to southwest Martin County. Injections also were suspended as of Dec. 15 in a smaller area within the Gardendale SRA, and other limitations have been put in place in Northern Culberson and Reeves counties. The permit suspensions preceded an investigation by the RRC into a 4.5 magnitude earthquake that struck about 11 miles north of the sleepy town of Stanton, in West Texas, late Monday. The quake struck at a depth of 4.8 miles in Martin County in the Midland sub-basin of the Permian, according to the U.S. Geological Survey (USGS). No injuries were reported. The RRC has been in contact with oil and gas disposal well operators in the area, according to spokesperson Andrew Keese. “We’re sending inspectors to the facilities as well.” The state regulator plans to continue closely monitoring seismic activity in the area and “will take any actions, as necessary,” according to Keese. Monday’s quake follows a series of smaller tremors in recent months detected by the University of Texas at Austin’s Bureau of Economic Geology. The Bureau’s TexNet Seismic Monitoring Program was developed after the Texas Legislature tasked it with helping to locate and determine the origins of earthquakes in the state. On Dec. 15 and 16, TexNet reported that four earthquakes occurred in northwestern Midland County with magnitudes of 3.1, 3.6, 3.7 and 3.3, respectively. These were the most recent events in an increasing sequence of earthquakes that has occurred in this area over the last two years, according to the RRC. The Permian, a sprawling basin spanning 86,000 square miles in West Texas and southeastern New Mexico, had 294 active rigs as of Dec. 23, according to the latest available data from Baker Hughes Co. (BKR). This was the most of any other play in the United States. Of that total, 127 were in the Midland sub-basin and 157 were in the Delaware. For comparison, the Haynesville Shale had the second-largest number of rigs at 48, BKR data showed. In a study published earlier this month, the USGS said efforts should continue to systematically quantify nationwide earthquake risks to natural gas pipelines. Because they are buried underground, pipelines are vulnerable to the compounding effects of an earthquake, such as strong shaking, fault ruptures, landslides and liquefaction, according to the federal agency. Leveraging publicly available data on gas pipelines such as incident data from past earthquakes and information collected by the Pipelines and Hazardous Materials Safety Administration, the USGS developed a first-order assessment of quake risks to U.S. gas transmission pipelines caused by strong ground shaking. Models determined that California had the highest distribution of average annual loss (AAL) for pipelines from earthquake-induced shaking. Other western states also saw a higher percentage of AAL, while Arkansas, Mississippi, Missouri and Tennessee recorded a moderate percentage of AAL. “To quantify the risk and its associated uncertainties, we systematically integrated the latest USGS National Seismic Hazard Model, a logic tree-based exposure model, three different vulnerability models and a consequence model,” said lead author Neal Simon Kwong. The results enable comparisons against other risk assessment efforts, encourage more transparent deliberation regarding alternative approaches – such as characterizing displacement demands or alternate models to evaluate leaks or breaks – and facilitate decisions on potentially assessing localized risks due to ground failures that require site-specific data.

US oil, gas rig count drops 13 to 706 on week, as Permian Basin losses mount - S&P Global The US oil and gas rig count fell by 13 to 706 on the week, energy analytics and software company Enverus said Dec. 30, as the Permian Basin recorded by far the biggest decline — and biggest move — of any of the eight largest domestic plays. Overall, the drop in the total rig count came from crude plays where rigs fell by 14 on the week to 552. Rigs working in gas plays rose by one to 168. Rigs in the Permian, sited in West Texas/southeast New Mexico, fell by five to 300, on top of a one-rig dip the previous week. But generally, the basin — the largest in the US with 4.88 million b/d of current oil production and about 14.3 Bcf/d of natural gas output — had been gaining rigs from a level of 260 in mid-September. Permian drilling activity has risen 70% in 2021, after starting the year at 176 rigs. Moreover, the Haynesville Shale of East Texas/northwest Louisiana rose by two rigs to 63 — the highest activity level in the largely dry gas play since late April 2019. The past week's 63 rigs were also well above Haynesville's pre-coronavirus level of 42 in late February 2020. Rigs at the Haynesville Shale generally stayed in the 30s-40s through the first year of the coronavirus pandemic and began to rise in the second quarter of 2021, in tandem with natural gas prices. A mix of small gains, losses Otherwise, the US rig count for the week ended Dec. 29 was a hodgepodge of upticks and downticks by a rig or two. Rigs in the Bakken Shale of North Dakota/Montana also rose by two to 32. Bakken activity had dropped sharply as the pandemic hit in March 2020 from levels in the low 50s. Bakken activity began 2021 at only 12 rigs, then picked up from there. Recovery was slow as severe winter storms hit the region, and by mid-year, the large oil play's rig count only topped 20, but activity has continued to increase since then. The SCOOP-STACK play in Oklahoma rose by a rig for the week ended Dec. 29, for a total of 39. Rigs in the play have bounced around the high 30s to low 40s since October, after starting 2021 at 15. But that means the SCOOP-STACK is back to its pre-pandemic level of 42. The two names are acronyms of the names of the counties and areas in which they are located. Apart from the Permian, only one other basin posted a rig loss during the week ended Dec. 29 — the DJ Basin, mostly located in Colorado. It fell by one rig for the week ended Dec. 29, leaving 17. The DJ's pre-pandemic level was 25, but it hasn't been above 20 since April 2020. In three other US basins during the same week, activity was stagnant with no weekly net change in rigs. That left the Eagle Ford Shale, sited in South Texas, at 57 rigs, the Marcellus Shale in Pennsylvania/West Virginia at 37, and the Utica Shale at 10.

Shale drillers face record cost pressures as banks shun the sector--Oil drillers in the biggest U.S. fields are shouldering record costs at the same time that some banks are increasingly reluctant to loan money to the sector, according to the Federal Reserve Bank of Dallas. Equipment, leasing and other input costs for oil explorers and the contractors they hire surged to an all-time high during the current quarter, the Dallas Fed said in a report released on Wednesday. Drillers also are seeing the universe of willing lenders shrink in the Eleventh Federal Reserve District that includes Texas and parts of Louisiana and New Mexico. “The political pressure forcing available capital away from the energy industry is a problem for everyone,” an unidentified survey respondent said. “Banks view lending to the energy industry as having a ‘political risk.’ The capital availability has moved down-market to family offices, etc., and it is drastically reducing the size and availability of commitments regardless of commodity prices.” Meanwhile, supply-chain snarls are hindering efforts to replace diesel-burning pumps with cleaner, electric-powered gear in the Permian Basin, where components such as transformers are in “extremely short supply,” another respondent said.

Chronic Underinvestment Could Push Oil Prices Higher In 2022 - U.S. shale is literally running on empty: according to the U.S. Energy Information Administration's latest Drilling Productivity Report, the United States had 5,957 drilled but uncompleted wells (DUCs) in July 2021, the lowest for any month since November 2017 from nearly 8,900 at its 2019 peak. At this rate, shale producers will have to sharply ramp up the drilling of new wells just to maintain the current production clip.The EIA says the sharp decline in DUCs in most major U.S. onshore oil-producing regions reflects more well completions and, at the same time, less new well drilling activity--proof that shale producers have been sticking to their pledge to drill less. Whereas the higher completion rate of more wells has been increasing oil production, especially in the Permian region, the completions have sharply lowered DUC inventories, which could sharply limit oil production growth in the United States in the coming months. According to S&P Capital IQ data, 27 major oil makers tripled capital spending between 2004 and 2014 to $294 billion and then cut it to $111 billion by last year. Once old wells were capped, new ones haven't been available to fill the production gap quickly. The question is how long the restraint by publicly traded oil companies will last. Capital spending is expected to clock in around $135 billion next year, good for a 21.6% Y/Y jump but still less than half 2014's level.Other than severely limiting new drilling activity, U.S. shale has also been keeping its pledge to return more cash to shareholders in the form of dividends and share buybacks.A recent report by progressive advocacy group Accountable.us says that 16 of 24 large U.S. energy companies have raised their dividends this year, while 11 made special dividend payouts totaling more than $36.5 billion. That's a pretty impressive payout ratio considering that the sector has so far reported $174 billion in profits this year. Indeed, "variable dividends" that allow companies to hike dividends when times are good and to lower them when the going gets tough has become a favorite tool for oil and gas companies.Meanwhile, oil and gas companies have spent a more modest $8 billion in share buybacks, though ExxonMobil ((NYSE:XOM)and Chevron (NYSE:CVX) have pledged to buy back as much as $20 billion of stock in the next two years. The energy sector has made robust share gains in the current year, which could explain the reluctance to spend too much on share repurchases.The most important reason, however, why oil prices are likely to remain high in the coming year is OPEC discipline:According to the IEA, crude consumption is expected to improve to 99.53 million barrels per day (bpd), up from 96.2 million bpd this year, leaving it just a hair short of 2019's daily consumption of 99.55 million barrels. That will, of course, depend on the world bringing the new Omicron variant of Covid-19 quickly under control. Higher oil demand will put pressure on both OPEC and the U.S. shale industry to meet demand. But let's not forget that numerous OPEC nations have already been struggling to add to output, while the U.S. shale industry has to deal with investor demands to hold the line on spending. So far, the U.S. shale industry has not responded to higher oil prices as they had done previously, with overall U.S. production averaged 11.2 million bpd in 2021 compared with a record of nearly 13 million bpd in late 2019. U.S. production is expected to only increase by 700,000 b/d in 2022 to 11.9 b/d, according to Rystad Energy

EIA's Weekly Petroleum Report -- US Implied Oil Demand -- All-Time High -- December 29, 2021 - Before we get to the EIA report: US implied oil demand on a four-week basis just hit an all-time high for this time of the year. Link here. Link here.

• US crude oil in storage decreased by an impressive 3.6 million bbls. WTI: up slightly on news.
• US crude oil in storage stands at 420.0 million bbls; 7% below five-year average
• US crude oil imports averaged 6.8 million bbls; yawn; increased by 0.6 million bbls; four-week average of 6.5 million bpd is almost 14% more than same four-week period last year;
• US refiners are operating at 89.7% of their operable capacity; yawn
• distillate fuel inventories decreased by 1.7 million bbls; 14% below the five-year average
• jet fuel product supplied was up 20.6% compared with same four-week period last year;

US crude oil and oil products in storage, including SPR: This was part of President Biden's plan to lower gasoline prices. Much of the decrease in US storage was due to the release of "our" strategic reserve as ordered by President Biden. Most of our "strategic reserve" released crude oil went to China and India. An example of strategic thinking.

Despite Omicron, U.S. Petroleum Demand Mounts and Production Hits 2021 Peak --Domestic consumption of gasoline and other petroleum products climbed last week, and producers boosted output to a 2021 high to meet the mounting demand, data from the U.S. Energy Information Administration (EIA) showed. The increases for the week ended Dec. 24 came even as the Omicron variant of the coronavirus spread rapidly throughout the Lower 48. New outbreaks caused air travel interruptions and raised fresh concerns among public health officials about the pandemic as winter weather settles in and people spend more time indoors, where the virus is more transmissible. Americans, however, appeared to shrug off the threat in the run-up to the long Christmas holiday weekend, as consumption of all petroleum products tracked by EIA rose last week. Overall demand jumped 9% week/week, the agency said Wednesday in its latest Weekly Petroleum Status Report. Motor gasoline demand rose 8% week/week, while jet fuel consumption advanced 9%. Over the past four-week period, total products supplied – EIA terminology for demand — averaged 21.4 million b/d, up 12% from the same period last year. Over the past four weeks, gasoline consumption averaged 9.3 million b/d, up 17%, while distillate fuel product supplied averaged 4.1 million b/d, up 8%. Jet fuel demand spiked 21% to 1.5 million b/d. Raymond James & Associates Inc.’s Mike Gibbs, managing director, noted that an increasing number of Americans are inoculated against the virus and confident that vaccines would protect against serious illness. Additionally, he said, early indications from studies of Omicron “suggest a very transmissible but less severe disease.” Hospitalizations, Gibbs added, “are rising but not to the degree of previous strains” and “deaths have stayed relatively low for now. We want to at least be mindful of the possibility that Covid may be transitioning toward an endemic (something we live with like the flu) rather than a pandemic. We are hopeful that the global reopening can progress over the coming months as Covid concerns subside.” U.S. producers are betting on continued momentum as well. Crude output reached 11.8 million b/d last week – a 2021 peak and up 200 million b/d from the previous week.

U.S. oil production set to increase further in 2022, energy expert Dan Yergin says -U.S. oil production is back and set to increase in 2022 after more than a year of OPEC and its allies "running the show," according to Daniel Yergin, vice chairman of IHS Markit.Output could rise by as much as 900,000 barrels per day, he told CNBC's"Squawk Box Asia" on Wednesday.U.S. oil firms slashed production in 2020 as the coronavirus pandemic destroyed demand and supply has not yet recovered to pre-Covid levels. In 2019, the U.S. produced 12.29 million barrels of crude oil per day, according to the U.S. Energy Information Administration.That figure was 11.28 million in 2020 and is estimated to be 11.18 million in 2021 and 11.85 million in 2022. "The U.S. is back," Yergin said. "For the last year, year and a half, it's been OPEC+ running the show, but U.S. production is coming back already, and it's going to come back more in 2022."

'Turn the valve off': Climate activists push for an abrupt end to the fossil fuel era --Climate activists and campaign groups are pursuing an abrupt end to the fossil fuel era, condemning the latest round of net-zero pledges from many governments and corporations as a smokescreen that fails to meet the demands of the climate emergency. Calls to keep fossil fuels in the ground are anathema to leaders in the oil and gas industry, who insist the world will continue "to be thirsty for all energy sources" in the years ahead. To be sure, the burning of fossil fuels, such as coal, oil and gas, is the chief driver of the climate crisis and researchers have repeatedly stressed that the best weapon to tackle rising global temperatures is to cut greenhouse gas emissions as quickly as possible. Yet, even as politicians and business leaders publicly acknowledge the necessity of transitioning to renewable alternatives, current policy trends show dirty fuels are not going away — or even declining — anytime soon. Tom Goldtooth, a climate activist and executive director of the North American Indigenous Environmental Network, described the burning of fossil fuels as like filling a bathtub with far too much water. "It is overflowing with too much carbon. The world can't absorb any more." "The simple solution, that we are still demanding, is the world has to turn the valve off," Goldtooth said. His comments came as he spoke at The People's Summit for Climate Justice, an event hosted by the COP26 Coalition on the sidelines of the Glasgow summit in November. "The net-zero solution is not a solution," he said. "It is not going to get this world where we need to go, it is not going to get us to 1.5 degrees Celsius." To have any chance of capping global heating to the goal of 1.5 degrees Celsius, the aspirational goal of the landmark 2015 Paris Agreement, the world needs to almost halve greenhouse gas emissions in the next 8 years and reach net-zero emissions by 2050.That's a huge undertaking, and one that the world's leading climate scientists have warned will have to incur "rapid, far-reaching and unprecedented changes" across all aspects of society.

U.S., Global Oil Prices Poised to Extend Rebound into New Year - Despite a November lull imposed by the Omicron variant of the coronavirus, crude prices in the United States and globally were positioned Thursday to finish 2021 up more than 50% on the year, led upward by mounting demand for travel fuels and heating oil that outshined modestly increased production levels. West Texas Intermediate (WTI) oil in the United States traded around $77/bbl on Thursday, far higher than the $48 level at which it started 2021. Brent crude, the international benchmark, hovered near $80 in Thursday trading, well above the sub-$52 price it fetched at the beginning of the year. The prices mark a stark reversal from the doldrums of 2020, when the coronavirus paralyzed demand and, in the early days of the pandemic, briefly sent oil prices into negative territory. Should the United States and other major economies continue to navigate the pandemic without the widespread business lockdowns and travel restrictions endured in 2020, traders said demand is likely to continue climbing, and prices could remain elevated deep into 2022. “Oil is a reflection of economic activity, and there’s so much pent-up demand across the global economy driving momentum now,” U.S. Global Investors Inc.’s Mike Matousek, head trader, told NGI’s Shale Daily. “I think markets expect that to continue well into the year ahead, and oil prices show that.” The Federal Reserve Bank of Atlanta estimated the U.S. economy grew at a 7.6% annual rate in the final quarter of 2021 – one of the strongest quarterly advances in a generation. Federal Reserve researchers in December forecast U.S. economic growth of 4% in 2022. To be sure, the pandemic ebbed and flowed throughout 2021, making economic projections dicey, and the Omicron variant is expected to curb the pace of growth at least temporarily early in 2022 as cases mount in the winter months. The concern extends to energy. In November, after Omicron emerged, Brent and WTI prices finished the month more than 15% lower, marking the largest monthly decline since the coronavirus was declared a pandemic in March 2020. Still, prices in December rebounded again. Economists increasingly expect lighter impacts from new variants than previous virus waves, given increased vaccination levels and governments’ collective aversion to new lockdowns. “The Omicron variant is likely to be a near-term constraint on growth, but a temporary one,” said Raymond James & Associates Inc.’s Scott Brown, chief economist. If he is right, energy demand could continue surging. Robust demand for travel fuels derived from oil – in addition to mounting calls for natural gas to fuel power plants and heat homes – galvanized seismic price gains in 2021. November energy prices jumped 33% from a year earlier — far more than any other category tracked by the U.S. Bureau of Labor Statistics — and rose 3.5% from October. The cost of gasoline was up more than 58% year/year in November, the latest month for which data was available. Energy commodities – chiefly oil and gas – climbed 5.9% month/month in November and 57.5% year/year. Of course, the soaring consumer energy prices added to widespread inflation concerns, Matousek said, and participants across energy markets are leery about runaway price increases that would eventually curb demand. What’s more, inflation has hampered energy companies that focus on equipment, storage, transportation and refining – areas affected by high fuel and input costs.

Natural gas leak in Dodge County causes evacuations and closures -- A large natural gas leak from a damaged pipe has caused temporary evacuations and road closures. Around 2:30 p.m. on Wednesday, a crash happened on STH-26 near the airport, about one mile north of Juneau. The crash damaged an above-ground gas pipe, causing a large natural gas leak. People within a one-mile radius of the leak were notified and evacuated from the area. The Dodge County Sheriff's Office says there will likely be long-term road closures in and around the Juneau area. Natural gas in the City of Juneau was shut off, and is expected to stay off throughout the night. Electricity to the city was also turned off for a short period of time, and it's unclear if it may need to be temporarily turned off again during repairs. A temporary warming shelter was set up at the Sacred Heart Catholic Church on the west side of Horicon for those who were evacuated. It's unknown how long it will need to remain open. The Dodge County Sheriff's Office says it will send out updated information as it's available or necessary.

Officials declare California oil spill cleanup complete - Nearly three months after an undersea pipeline spilled thousands of gallons of crude oil into the waters off Southern California, authorities have announced that coastal cleanup efforts are now complete. "After sustained cleanup operations for the Southern California oil spill, affected shoreline segments have been returned to their original condition," officials said in a news release Tuesday. The unified command cleanup response was led by the U.S. Coast Guard, the California Department of Fish and Wildlife's office of oil spill prevention and response, and Orange and San Diego counties. Authorities were first alerted to the possibility of an oil spill off Orange County on Friday, Oct. 1. Residents noticed a sheen that Saturday, and by sunrise the following morning, a diesel-like odor had overtaken the area as an oil slick neared Huntington Beach. Crashing waves brought dark crude onto the shore, along with dead birds and fish. Response teams mobilized quickly, including biologists and environmentalists who scrambled to put barriers between the oil and Talbert Marsh, a 25-acre ecological reserve that is home to dozens of species. Gov. Gavin Newsom declared a state of emergency in Orange County. "In a year that has been filled with incredibly challenging issues, this oil spill constitutes one of the most devastating situations that our community has dealt with in decades," Huntington Beach Mayor Kim Carr said at the time. The spill sparked a statewide conversation about fossil fuel reliance and also renewed calls for the government to take more aggressive action against the aging oil platforms that dot the state's coast. Orange County Supervisor Katrina Foley, whose district includes Huntington Beach, said Wednesday it was "great to have the cleanup component of this behind us," but that there is still much work to be done. "The first thing that we've learned is that this aging infrastructure is decomposing and is not being well-maintained, and that has to be addressed immediately," Foley said. "The second most important lesson is that there is a galvanization of community support to decommission these rigs, so long as we are able to transfer those 'dirty energy' jobs to 'clean energy' jobs and take care of the workers." Foley said the spill's effects rippled through the coastal community—from local fisheries and surf schools that lost business, to damaged properties and canceled events, including the Pacific Airshow that had been scheduled that weekend.

Three years before ban takes effect, state banning most fracking permits - California regulators haven’t approved permits for the controversial oil and gas extraction process known as fracking since February, effectively phasing out the process ahead of Gov. Gavin Newsom’s 2024 deadline to end it.The state’s Geologic Energy Management Division, known as CalGEM, has rejected an unprecedented 109 fracking permits in 2021, the San Francisco Chronicle reported. That’s the most denials the division has issued in a single year since California began permitting fracking in 2015. Fifty of the permits, mostly from Bakersfield-based Aera Energy, were denied based solely on climate change concerns.State oil and gas supervisor Uduak-Joe Ntuk wrote in a September letter to Aera that he could “not in good conscience” grant the permits “given the increasingly urgent climate effects of fossil-fuel production” and “the continuing impacts of climate change and hydraulic fracturing on public health and natural resources.”Newsom, a Democrat, called in 2020 for state lawmakers to ban the practice by 2024. But a proposal before lawmakers failed, leading Newsom to direct CalGEM to proceed with the timeline on its own. It’s only one piece of Newsom’s climate change agenda, which includes a complete end to oil and gas production in the state by 2045, long after he’s left office.Kern County, where most fracking in the state occurs, and the Western States Petroleum Association have sued the state over the denials. WSPA’s lawsuit, filed in October, argues state law requires CalGEM to permit fracking if it meets technical requirements and that the denials amount to a de facto ban on the process that hasn’t been approved by the Legislature. A hearing in the Kern case is scheduled for Monday and the state must respond to WSPA’s lawsuit by Dec. 2.

Could Methane Unlock A Canadian Natural Gas And Oil Brand Revamp? --A 15-year Canadian research, product development and field testing campaign has made available proven technology capable of reducing methane emissions by more than 45%, according to the oil and gas industry agency leading the environmental effort. “Methane is the key to creating a clean Canadian oil and gas brand,” Petroleum Technology Alliance Canada (PTAC) stated in the Methane Detection and Mitigation Initiatives Report, a 35-page summary of leak detection and mitigation initiatives that it spearheaded. The Canadian Energy Research Institute has estimated a C$700 million ($542 million)-plus cost for oil and gas producers to hit the country’s methane emission targets. PTAC said that research groups of industry and government experts collected “a tsunami of methane emissions data” with mobile remote sensors using lasers and spectrometers mounted on light aircraft, drones, and ground vehicles. To use the information for field operations guidance and devising cleanup methods, the agency formed a methane emission reduction network, or MERN – an industry cleanup cooperative. As an outdoor laboratory and field proving ground, PTAC crews used a 2,500-square-kilometer (965-square-mile) area of central Alberta studded with production sites, pipelines, and processing plants. MERN set out to create and prove technology capable of making a 45% methane emissions cut – and to accomplish the feat economically. The cost target was C$5.00 ($4.00) for a methane emission volume equivalent to a ton of carbon dioxide (CO2). The resulting package put more than 40 technologies on the industrial market. Innovations include capturing and using methane leaks for field equipment fuel and power generation, replacing natural gas with compressed air in pneumatic hardware, new electric devices, improved pumps, and low-carbon emissions combustion. GHG reductions achieved by methane leak control exceed gains from tackling only CO2 emissions by a wide margin, said PTAC. The agency cited an international environmental measurement known as GWP, short for global warming potential. The yardstick rates a ton of methane emissions as equal to 28-36 tons of CO2 per century and 84-87 tons over a 20-year period.

Mexico to end oil exports in 2023 in bid to meet its own fuel needs--Mexico plans to end crude oil exports in 2023 as part of a strategy by the nationalist government of Andres Manuel Lopez Obrador to reach self-sufficiency in the domestic fuels market. Pemex will reduce crude oil exports to 435,000 barrels a day in 2022 before phasing out sales to clients abroad the following year, Chief Executive Officer Octavio Romero said during a press conference in Mexico City on Tuesday. The move is part of a drive by Lopez Obrador to expand Mexico’s domestic production of fuels instead of sending its oil abroad while it imports costly refined products, like gasoline and diesel. Mexico currently buys the bulk of the fuels it consumes from U.S. refineries. If fulfilled, Pemex’s pledge will mark the withdrawal from the international oil market by one of its most prominent players of the past decades. At its peak in 2004, Pemex exported almost 1.9 million barrels a day to refineries from the Japan to India, and was a participant in meetings by the Organization of Petroleum Exporting Countries as observer. Last month, the Mexican company sold abroad slightly more than one million daily barrels, according to Pemex data. The export reduction will come as Pemex increases its domestic crude processing, which will reach 1.51 million barrels a day in 2022 and 2 million daily barrels in 2023, Romero said. The Mexican driller will plow all of its production into its six refineries, including a facility under construction in the southeastern state of Tabasco and another one being bought near Houston, Texas. This plant is considered part of Mexico’s refining system even if located across the U.S. border. Asian refineries, which account for more than a quarter of Mexican crude exports, are expected to bear the brunt of the export cuts. The reductions are expected to hit refiners in South Korea and India the hardest, with smaller cuts seen to buyers in the U.S. and Europe, as Pemex backtracks on earlier plans to diversify away from the U.S. market.

Mexico To End Oil Exports In 2023 - Mexico will suspend crude oil exports in two years in a bid to focus on domestic self-sufficiency, Bloomberg has reported.The move is part of President Andres Manuel Lopez Obrador’s plan to increase local fuel production to reduce dependence on imported fuels. The export phase-out announcement was made by the chief executive of Pemex, Octavio Romero, who also said that Mexico would reduce oil exports from next year by more than 50 percent, to 435,000 bpd. Currently, Mexico is the third-largest oil exporter in the Americas, after the United States and Canada, according to data from the U.S. Energy Information Administration.The main destinations for its crude are its northern neighbors in North America and China, India, and South Korea, as well as European countries. A cut in exports could make some of these importers look for alternative suppliers. Fuel demand in Mexico has risen during the pandemic but local oil production has failed to follow. Refining capacity is also a problem, although President Lopez Obrador’s plans include the construction of a new refinery with a capacity of 340,000 bpd. The refinery has a price tag of $12.4 billion, according to calculations from earlier this year, as reported by Argus. If Mexico indeed stops exporting crude oil, this will hit U.S. Gulf Coast refiners hard as it will cut off yet another source of heavy oil, for which their refineries have been configured. Another major source of heavy crude used to be Venezuela, but U.S. sanctions against Caracas ended the flow of heavy Venezuelan crude to the Gulf Coast.According to the Bloomberg report, there are also doubts about Pemex’s own capacity of refining all of its crude oil output. A long period of underinvestment in refinery maintenance has reduced operating capacity significantly, and it is questionable whether the state energy giant would be able to turn things around in just two years.Pemex is currently the most indebted oil company in the world despite major efforts by the Lopez Obrador government to support it through tax breaks and other debt-relief measures.

Petrobras completes sale of onshore acreage --Brazilian energy company Petrobras said December 29 it concluded the sale of its entire holdings in 27 onshore exploration and production assets in the Espirito Santo basin. “This transaction is in line with the company's portfolio management strategy and the improved allocation of its capital, aiming to maximize value and provide greater return to society. Petrobras is increasingly concentrating its resources on assets in deep and ultradeep waters, where it has shown a great competitive edge over the years, producing better quality oil and with lower greenhouse gas emissions,” the company, known formally as Petroleo Brasileiro, stated. The sale concluded with a final payment of $27mn, on top of the $11mn paid on signing in August. The company can expect another $118mn in contingent payments tied to future oil prices. Production rates of crude oil and natural gas were relatively minor, though most of the output was in the form of natural gas. The sale announced follows a December 23 announcement from Petrobras that it sold its interest in the onshore Carmopolis area to Carmo Energy for $1.1bn. The Carmopolis area comprises 11 production concessions in the Brazilian state of Sergipe, with access to oil and gas processing, storage and transportation infrastructure. The cluster averaged 7,600 barrels/day of oil and 43,000 m3/d of gas in November.

Fueled by Vaca Muerta, Argentina Oil, Natural Gas Production Riding Hot Streak - Argentina continues to ramp up its oil and gas production amid high prices and a push from the government to increase output. November oil production was up 15% year/year to 557,000 b/d, the highest monthly figure in nine years, Energy Secretary Darío Martínez said recently. The improvement is mainly because of the Vaca Muerta formation in western Argentina, the Energy Secretariat said. Production from unconventional plays jumped 64% in November. “We are moving in the right direction and that allows us to promote a key sector for the growth of Argentina,” Martínez said.After a general slump in 2020, oil and gas activity has now exceeded pre-pandemic numbers, Martínez said. “In a world of uncertainty, oil and gas production in Argentina is providing the country certainty.” Natural gas production hit 128 million cubic meters/day (Mm3/d) in November, up 10% compared with the same month last year. Unconventional plays saw 40.9% growth in the same comparison.Earlier this month, the Argentine government announced an infrastructure project to further spur natural gas production from Vaca Muerta and to reduce the nation’s reliance during winter months on liquefied natural gas (LNG) imports. A second phase of the project might include potential export infrastructure, President Alberto Fernández said.The $1.5 billion first phase would involve constructing the 24 Mm3/d Néstor Kirchner pipeline. The pipeline would run from Tratayen in Neuquén to Salliqueló in Buenos Aires province. Other construction includes upgrades to the Gasoducto Norte pipeline system, which would allow natural gas to reach northern Argentina and potentially displace Bolivian gas imports. The news comes as Argentina comes out of a winter of high LNG needs. Infrastructure bottlenecks in Neuquén have also slowed growing domestic production.In a hydrocarbons promotion bill sent to congress in September, Argentina’s government said natural gas would be an essential part of the country’s energy transition. The bill includes price stabilization mechanisms, and guarantees that volumes produced for export will see preferential tax rates and access to capital markets. This would be in addition to current incentive programs in the sector.

Nord Stream 2 startup waiting on German regulatory approval--Gazprom PJSC has finished preparing the controversial Nord Stream 2 pipeline for natural gas exports to Europe, yet actual deliveries depend on how quickly regulators grant the project approval amid souring relations between Russia and Western nations. “Nord Stream 2 is ready for operations,” Russian President Vladimir Putin said Wednesday at a meeting with energy officials broadcast on Rossiya 24 TV. “Now everything depends on our partners, consumers in Europe, in Germany,” he said. The pipeline can start delivering “large additional volumes of Russian gas” to the continent as soon as European regulators certify the project operator, Putin said. It’s designed to carry as much as 55 billion cubic meters per year from Russia to Germany across the Baltic Sea. Europe is facing a supply crunch that has pushed fuel and power prices to record levels this year, with inventories abnormally low and insufficient inflows to the continent. While shipments of liquefied natural gas have provided some recent relief, benchmark gas prices are up about 400% this year and could remain elevated into early 2023. Putin’s statement came just hours after Gazprom completed filling the second line of the twin link with so-called technical gas in order to build up pressure required for pumping fuel along the line. The procedure, which was completed on the first line in October, is the final technical step for Nord Stream 2, with certification the only remaining hurdle before actual gas deliveries can begin. The pipeline has been a source of tensions between Russia and Western nations over the past five years. Officials from the U.S. and a number of countries in eastern Europe, including Poland and Ukraine, have protested that it would give Gazprom additional leverage over the European market. The timeframe of Nord Stream 2’s start became a critical issue for the continent after Europe’s energy deficit became severe several months ago. While Gazprom, the single-largest supplier of gas to Europe, has been fully meeting its supply obligations under long-term contracts, it hasn’t offered spot gas with deliveries in late 2021 or early 2022 to European clients for several months, exacerbating the shortage. The German regulator Bundesnetzagentur earlier this month said it doesn’t expect to certify the Nord Stream 2 operator in the first half of 2022. The delay comes as the company needs to set up a German subsidiary to comply with European Union legislation. This signaled to the energy-hungry European market that the Russian pipeline may only start operating once stockpiling for next winter is already well under way. Nord Stream 2 was initially expected to begin operating by the end of 2019, but it has faced multiple hurdles, including U.S. sanctions targeting the project’s insurers and pipe-laying ships. Its construction was finally completed in September. However, Germany and the U.S. have indicated the start of the link could be at risk if Russia, which earlier this year escalated its troop presence near the border with Ukraine, were to attack its neighbor.

European Gas Prices Surge Above 100 Euros With Eyes on Russia.Europe’s benchmark natural gas price rose above 100 euros, or $190 per barrel of oil equivalent, ahead of a series of auctions for pipeline capacity that are seen as a test of Russia’s willingness to ease a supply crunch.The day-ahead auctions for space on Ukrainian pipelines and capacity at Germany’s Mallnow compressor station will provide a strong signal for how serious Russia is about increasing flows to the west. While the region’s biggest supplier has said it aims to keep refilling European storage sites until the end of December, it hasn’t used short-term auctions to ship more fuel. So right now we have this situation which is going to make your head spin. Europe is out of gas. They’ve spent the better part of the last decade getting rid of their own domestic energy, replacing it with baubles and toys, which, while scoring big on the woke scorecard, have proven abysmal at producing… well, electricity. With Europeans now cold and very shortly hungry we are due for a war. Remember that historically, the spiraling food prices have caused civil unrest, revolutions, and wars. You can’t make fertilizer without urea and natural gas. As the price of either of these goes higher (both are), it significantly impacts the price of fertilizer. The price of fertilizer impacts in turn the price of food. This is because fert is the second largest cost component of most agricultural production. The first being… you guessed it, diesel.

Eastward gas supplies jump via Russian Yamal-Europe pipeline (Reuters) - The Yamal-Europe pipeline that usually delivers Russian gas to Western Europe was sending fuel to Poland for the 12th straight day on Saturday at elevated levels, data from German network operator Gascade shows. Flows at the Mallnow metering point on the German-Polish border were going east into Poland at an hourly volume of more than 5.2 million kilowatt hours (kWh/h) on Saturday morning, the data shows, up from around 1.2 million kWh/h in the previous 24 hours. The pipeline is a major route for Russian gas exports to Europe. At the same time, requests for westward flows through the pipeline into Germany at the Mallnow station emerged on Friday for Jan. 1 at 8.3 million kWh/h and now stand at more than 6 million kWh/h. Auction results showed Russian gas exporter Gazprom GAZP.MM has not booked gas transit capacity for exports via the Yamal-Europe pipeline for Saturday. The company booked 8.3 million kWh/h of gas transit capacity via the Yamal-Europe pipeline for January in a last-month auction. Russian President Vladimir Putin said last week that Germany was reselling Russian gas to Poland and Ukraine rather than relieving an overheated market, putting blame for the reversal, and rocketing prices, on German gas importers. The German Economy Ministry has declined comment on Putin's remark. Gas importers have not responded to Reuters requests for comment.

Eastbound gas flows rise along Yamal pipeline but westbound requests emerge (Reuters) - Flows along the Yamal-Europe pipeline that carries Russian gas west into Europe remained reversed for a 12th day and increased on Saturday, but requests for westbound deliveries suggested the unusual reversal might end soon. The pipeline annually delivers about one-sixth of the gas Russia sends to Europe and Turkey. Gas was flowing east from Germany into Poland at an elevated rate early Saturday, with data at the Mallnow metering point on the border showing at an hourly volume of more than 5.2 million kilowatt hours (kWh/h) versus around 1.2 million kWh/h in the previous 24 hours. But on Friday requests for westbound gas emerged via Mallnow for Jan. 1 at 8.3 million kWh/h and on Saturday stood at more than 6 million kWh/h, data from German network operator Gascade showed. Russian gas exporter Gazprom GAZP.MM has not booked gas transit capacity on the pipeline for Saturday, auction results showed. Gazprom booked 8.3 million kWh/h of gas transit capacity via the pipeline for January in an auction last month. The reversed flows which began in Dec 21 sent already high European gas prices to record highs. Those high spot prices, and traders using up their annual volumes of contracted gas from Gazprom early prompted sellers in Germany, for example, to tap storage to sell to buyers in Poland, prompting the unusual reversal of flows, according to analysts and industry sources. Separately, Russian gas flows from Ukraine to Slovakia via the Velke Kapusany border point, another major route, fell to their lowest volume since Nov 2. Capacity nominations for Saturday were down to 524,631 megawatt hours (MWh) from 887,094 MWh on Friday, data from Slovak pipeline operator Eustream showed.

LNG Tanker Bound For Asia Turns Around, Heads To Europe For Massive Arbitrage Opportunity --Fuel-starved Europe is attracting liquefied natural gas (LNG) tankers from around the world. We reported Monday that a flotilla of US LNG is headed to the continent. There are reports that tankers in the Pacific are turning around and ditching Chinese markets for Europe. Bloomberg reports LNG tanker Hellas Diana (IMO: 9872987) left Corpus Christi, Texas, on Nov. 27 has since made a U-turn near Hawaii and is traveling back to the Panama Canal and is likely headed to Europe. So far, seven tankers bound for Asia have diverted to Europe as there are massive arbitrage opportunities for US LNG amid an energy crunch on the continent. Even though Dutch TTF natural gas prices soared to record highs last week and have since been halved on the news, a US LNG flotilla is in the Atlantic headed for the continent. There is still a lot of money to be made as Europeans are willing to pay a heft premium. The massive blowout spread between US and EU natural gas prices has more than halved but is considerably higher than the beginning of the year -- implying there's money to be made in sending US LNG to Europe rather than Asia. As long as European natural gas prices remain elevated, more tankers will be diverted to the fuel-starved continent as Russian gas flows remain depressed.

LNG Cargoes Enter Europe As British Power Bills To Remain High Until 2023 - Europe's energy crunch is far from over, but a flotilla of liquefied natural gas (LNG) tankers from the U.S. are set to resupply the fuel-starved continent. European gas prices fell for the sixth day, the longest decline in more than a year. Even though natural gas prices are retreating from record highs, household power bills, especially in Brittian, are likely to remain high until 2023. This year, Dutch TTF natural gas prices surged more than 400% on low supplies ahead of the Northern Hemisphere winter and Russia reducing flows. The news of the flotilla of U.S. LNG tankers headed to the region last week began the decline, nearly halving gas prices. On Wednesday, prices slumped again, down as much as 10%, for the sixth consecutive session but remained five times higher than the five-year average. Even though new data shows, the US-EU shipping lane is clogged with LNG tankers headed for Europe, as many as 20 at the moment -- there is reason to believe this will only be a temporary relief. "Europe's gas problem may not go away next year," said Andrew Hill, head of European gas analysis at BloombergNEF, in a report on Wednesday."Geopolitical issues and acrimony with Russia, particularly around the Nord Stream 2 pipeline, will increase the scope for Russia to limit flows to Europe in the first half of the year, and potentially much longer," Hill explained. The good news is that LNG supplies are entering the grid as current weather outlooks are mild for the time being. Also, electricity and gas suppliers are warning the energy crunch will persist through 2023. According to the Financial Times, British households will feel the pain of unprecedented power bills for at least another 18 months. Martin Young, an analyst at Investec, said, "directionally, we could see further upward pressure on household energy bills come October 2022."

LNG shipping’s wild ride: Record, plunge, new record, new plunge --Shippers of containerized goods were caught off guard this year. Never before had container spot rates risen so far, so fast. But shippers of liquid and dry bulk commodities know such cost swings all too well.When bulk commodity transport demand exceeds supply, shipping spot rates can keep rising until cargo shippers’ profit margins are erased. The spectacular rise and fall of liquefied natural gas shipping rates is the latest example.LNG carriers boast the highest day rates of any cargo vessel type. Shippers can afford to pay eye-wateringly high freight because the profit on moving a cargo can be enormous: In mid-November, a cargo could be bought for $20 million in the U.S. and sold for $120 million in Asia.The wild ride for spot rates began early this year as cold temperatures pushed up commodity pricing in Asia. An LNG carrier was chartered for $350,000 per day in January, a new all-time high for any cargo vessel. Then rates crashed. U.S. Gulf-Japan rates were down to just $16,800 in mid-March.Rates rebounded to a new record high last month. The Baltic Exchange assessment for the Australia-Japan route for a tri-fuel, diesel-engine (TFDE) LNG carrier peaked at $366,700 per day in late November. Lloyd’s List reported that one vessel was chartered for $424,000 per day.Then pricing collapsed. As of Tuesday, the Baltic’s Australia-Japan TFDE assessment was all the way down to $107,100 per day. Clarksons Platou Securities put the global average for TFDE LNG ships at $114,800 per day, down from a high of $205,000 in late November.“There could be a spike should weather get cold, but very likely the peak in shipping rates for the next few years already happened,” said Stifel analyst Ben Nolan.Extremely high spot rates generally coincide with higher LNG pricing in Asia than in Europe. That incentivizes transport of more U.S. cargoes to Asia as opposed to Europe, and more European reexports of LNG to Asia. More long-haul voyages soak up vessel capacity, boosting rates.Commodity pricing is now in a reverse — and highly unusual — situation: LNG cargoes are fetching more in Europe than in Asia, as Europe heads into the winter with decade-low inventories and restricted Russian pipeline inflows.Nolan said on Tuesday, “With the European price of gas surging past the Asian price, more cargoes are staying or being routed to the Atlantic. The result of shorter average distances with more U.S., Middle Eastern and African cargoes going to Europe instead of Asia is not good news for shipping.”

LNG trade flow dynamics shift as inter basin derivative spreads turn positive -- Inter-basin spreads returned to positive territory, signaling better economics for delivering LNG to Asia, as European prices came off faster amid mild weather forecast through January. The market dynamics shifted quickly, with most cargoes still heading to Europe in the Atlantic Basin Dec. 31, based on data from S&P Global Platts' vessel-tracking software tool cFlow. Deals concluded based on the flip in spreads, assuming the trend sticks, likely won't shift the direction of trade flows for several weeks, according to sources. The change in spreads characterized the volatility in the LNG markets in 2021. The spread between the Platts JKM, the benchmark for spot-traded LNG delivered to Northeast Asia, and the Dutch TTF European gas hub is often used as a sign of arbitrage potential between the Atlantic and Pacific basins. JKM/TTF March derivatives finished the day in positive territory for the first time since Dec. 13, trading at 45 cents/MMBtu before the close of the holiday-shortened London session Dec. 31. The latest weather forecasts suggest that most of Europe is set for warmer-than-usual temperatures in January, following mild weather during second-half December. That could drive bearish conditions in the European gas markets, which have retreated sharply from a record high Dec. 21. Market sources in Asia reported some latent buying interest from Japanese buyers, although most did not commit, preferring to reevaluate demand and inventory status after New Year's Day. US Gulf Coast FOB cargoes were closer to a toss-up from a netback standpoint when combined with the dramatic declines in shipping rates over the last month. Maximum waiting days for unreserved LNG tankers transiting the Panama Canal were in the low single digits in both directions, though they have slightly risen recently. Platts assessed the US FOB Gulf Coast marker for February at $21/MMBtu Dec. 31, down $5/MMBtu day on day and almost $34/MMBtu from a record high set Dec. 21. The current value is the lowest since Nov. 1. The US Gulf Coast versus Northwest Europe differential for February stood at $1.613/MMBtu. The arbitrage was effectively closed, when factoring in the Platts-assessed USGC-NWE freight rate of around $1.57/MMBtu and loading terminal lifting and destination terminal regasification costs.

Ukraine orders gas producers to sell 20% of output on energy exchange (Reuters) - Ukraine has called on private gas producers to sell at least 20% of their production on the country's energy exchange until April 30 to help avert winter shortages, the government said on Friday. Record high prices in Europe have tempted Ukrainian gas producers to export, straining supply in a country that is a net importer of gas. The government on Friday also decided to cap the price mark-up to 25% on gas sales to food producers as it looks to rein in double-digit inflation. Inflation in Ukraine has exceeded 10% in the second half of 2021 for the first time since 2018, despite the central bank tightened monetary policy as it targets a rate of 5%. Prime Minister Denys Shmygal last week promised that the government would prepare measures to help food producers, including bakers, cope with expensive gas. At the beginning of the year, the government limited the rise in gas prices for households by switching retail consumers to annual contracts with state energy company Naftogaz, fixing prices until the end of April 2022.

European gas traders suggest high energy prices will persist beyond winter --For a glimpse of how much longer this year’s energy crunch is going to last, look no further than the European natural gas market. Forward prices have more than doubled over the past month, with traders betting the unprecedented squeeze will last into early 2023. Gas will be expensive even when the weather is hot. Prices for the summer exceeded 100 euros ($113) a megawatt-hour this week, the highest on record. Europe is facing an energy crisis, with Russia curbing supplies and nuclear outages in France straining power grids in the coldest months of the year. And there’s no relief in sight. Germany said Russia’s controversial Nord Stream 2 pipeline won’t be approved in the first half of 2022, a move that will probably keep supplies capped in the summer, when Europe need gas to fill storage sites. “Help does not appear to be on the way,” said Kaushal Ramesh, a senior analyst at consultants Rystad Energy in Norway. The increase in forward prices is “suggesting another year of volatility and a continued high price environment.” Geopolitical tensions between Russia and Ukraine are also keeping traders on edge, with heightened concerns about a possible invasion. At his annual press conference on Thursday, President Vladimir Putin didn’t directly mention the threat of military action, but said an expansion of North Atlantic Treaty Organization expansion up to Russia’s borders was unacceptable. While a flotilla of liquefied natural gas tankers is currently heading to Europe, the region will remain at the mercy of global markets to ensure it continues to get cargoes throughout next year.

Worldwide Oil, Natural Gas Discoveries in 2021 Said Lowest in Decades - Global oil and natural gas discoveries in 2021 were tracking to hit their lowest full-year level in 75 years and decline considerably from 2020. Total discovered volumes through November were calculated at 4.7 billion boe, according to an analysis by Rystad Energy. No major discoveries had been announced through the first three weeks of December, setting the industry on course for its “worst discoveries toll since 1946.”By comparison, around 12.5 billion boe was unearthed around the globe in 2020, the consultancy noted.“Liquids continue to dominate the hydrocarbon mix, making up 66% of total finds,” the Rystad team said of 2021 discoveries. Seven were announced in November, with an estimated 219 million boe of new oil and gas volumes. Through Dec. 20, the monthly average of discovered volumes in 2021 stood at 424 million boe. The reduction in cumulative volumes “highlights the absence of large individual finds, as has been the case in previous years,” according to researchers. “Although some of the highly ranked prospects are scheduled to be drilled before the end of the year, even a substantial discovery may not be able to contribute toward 2021 discovered volumes as these wells may not be completed in this calendar year,” said Rystad’s Palzor Shenga, vice president of upstream research. “Therefore, the cumulative discovered volume for 2021 is on course to be its lowest in decades.” The Yoti West discovery off the coast of Mexico was the largest announced discovery in November, according to Rystad. Russia’s Lukoil estimated Yoti holds around 75 million boe of recoverable resources. An assessment plan is to be developed based on additional drilling results, Lukoil said. The company won rights to the block, which it shares with Italy’s Eni SpA (40%), in 2017.“The discovery strengthens Lukoil’s cumulative discovered volumes in the North American nation,” the Rystad researchers said. “However, these volumes are still insufficient for commercial development and would require further discoveries of a comparable scale before a development concept could be drawn up.”Still, the discoveries “give hope to Mexico that the country can halt or slow down its production decline. Several wells were scheduled to be drilled in blocks offered in various bid rounds, many by leading international oil companies.”Another big discovery in November was offshore Malaysia, Nangka-1. It was the second successive exploration well drilled within Block SK 417. The wildcat, drilled to a depth of 3,758 meters, was by Thailand’s PTT Exploration and Production Public Co. Ltd., which has followed other discoveries offshore Malaysia by PTTEP, as it is known. Sweet gas was discovered within the Middle to Late Miocene Cycle VI clastic reservoirs, researchers said.

APA, Sinopec to recover $900MM of “backlogged costs” in Egyptian project--APA Corp. and its Chinese partner in an Egyptian oil project will recover almost $900 million in prior investments under a new drilling contract with the North African nation. APA was the day’s best performer in the S&P 500 Index.APA and Sinopec will collect the “backlogged costs” over a five-year period that began on April 1, the Houston-based explorer formerly known as Apache said in a statement on Monday.Under the terms of the so-called production-sharing contract, the partners also plan to deploy more rigs and boost crude production. APA and Sinopec agreed to jointly pay Egypt a $100 million signing bonus. APA rose 6.1% to $27.67 at 1:14 p.m. in New York after earlier touching $27.68. The agreement, which comes almost nine years after APA sold Sinopec a 33% stake in its Egyptian business for $3.1 billion, included technical revisions such as consolidating most of the venture’s output within a single concession. The deal followed two years of negotiations to improve returns on the project for APA and Sinopec after back-to-back oil busts crimped profitability. The joint venture agreed to invest a minimum of $3.5 billion on research, development and production in Egypt’s western desert, the Oil Ministry said in a separate statement.

Oil spills hit 14m litres as Shell’s N800b judgment upsets industry - As International Oil Companies (IOCs) are planning to divest from Nigeria, concerns are beginning to mount over growing cases of oil spillage in the Niger Delta region and the N800 billion court judgment between Shell Nigeria and some communities in the region. In less than three years, weak infrastructure, especially pipelines, according to stakeholders, has led to the spillage of 14 million litres of crude oil, worth N2.8 billion coupled with cascading environmental dangers and health burden, leading to increase in cases of infant mortality and cancers. In fact, fresh intrigues are beginning to emerge ahead January, when the court would decide the fate of Shell Nigeria in an N800 billion damages earlier awarded by the Federal High Court in Owerri for the 2019 spillage in Eleme communities of River State. The jury is nearly out in the biggest dispute award ever in Nigeria’s volatile oil industry. But whether Shell Petroleum Development Company (SPDC) Limited, along with its two parent companies in the United Kingdom and The Hague, Netherlands, can come clean of culpability in a historic dispute debt awarded against it in a spill that occurred on swamp farmlands in Egbalor, Ebubu in Eleme Local Government Area of Rivers State, is what industry watchers are waiting to see next month. Shell, using all its legal resources, is seeking to convince the judge at the Court of Appeal to obviate payment of damages to some 88 persons, who got judgment in November 2020 from a Federal High Court in Owerri over spillage on their fishing facilities in Ejalawa community, Oken-Ogogu swamp farmlands. The judge of the Federal High Court, Owerri, Imo State, T.G. Ringim, had in the judgment last year, held that Shell Nigeria, Shell International Exploration and Production BV (SIE&P) and the Nigerian National Petroleum Corporation (NNPC) were liable for the spill. Isaac Torchi and 87 members of the Ejalawa community had gone to court against SPDC, SIE&P BV and NNPC over oil spillage in January 2020, which they claimed destroyed their environment and their sources of livelihood – mainly fishing and agriculture. Earlier in August this year, the Anglo-Dutch oil giant finally agreed to pay N45.7 billion to the Ejama-Ebubu community, after 31 years of legal tussle. The court has fixed January 25, 2022 to hear the oil company’s application.

Nembe Oil Spill: Prosecute Culprits To Avert Future Occurrence – Groups --Concerned groups, including environmental rights groups and ethnic youth leaders, have welcomed the findings of the joint investigation visit which attributed the recent oil spill in Nembe to human sabotage. The groups, which include Friends of the Environment, Nigerian Ethnic Youth Leaders Council (NEYLC), the Niger Delta Youth Movement (NDYM), and the African Centre for Justice and Human Rights (ACJHR) made their positions known in their separate reactions to the findings. They described the report that human sabotage caused the spill as truth based on science and facts that must be applauded by all stakeholders. They agreed that the findings should be used to get the culprits and avert future occurrences. The groups, in applauding AITEO which has been vindicated by the findings, said they entertained no fear from the beginning that being a socially responsible company, the spill could not have been caused by AITEO’s negligence. They said the report which absolved the company of any fault or wrongdoing has further confirmed the saying that if lies travel for 20 years, the truth will catch up with it in one day. “This is a vindication for AITEO. Findings have shown that the spill, as we have been suspecting from the beginning, was an act of sabotage by enemies of the Federal Government and a plot to undermine President Buhari’s Niger Delta agenda,” the NEYLC, which is made up of the Arewa Consultative Youth Movement, Ohanaeze Ndigbo Youth Movement, Oduduwa Youths and Middle Belt Youths said in a statement signed by the Acting Head of the coalition’s secretariat, Nduka Edede Chinomso . The Niger Delta Youth Movement (NDYM) regretted that while experts in the industry, with their science-based evidence, believe the spill was sabotage, the Bayelsa State Government’s agents were using emotion to look for scapegoats. “What the findings have shown us that the Bayelsa State Government had since been playing on the emotion of the people of the area and indeed all stakeholders. “With this evidence and science-based findings, we hope that the state government will be humble enough to make a public apology based on the wrong position it earlier took on the matter,” the group said in a statement. The popular environmental rights group, Friends of the Environment, in its separate statement, said the issue of the six persons who were arrested at the scene at about 2.30 am when the spill happened should not be overlooked by the state government. It said in a statement, “Six persons were said to have been arrested at the scene at an ungodly hour of about 2.30 am. “This revelation is very key and should not be overlooked by the state government and all others concerned.”

Shell ordered to pause seismic survey offshore South Africa --Royal Dutch Shell Plc has been ordered by a South African court to temporarily halt an offshore seismic survey after local communities took legal action to block the project. The groups on Tuesday were granted an interim interdict that will stand until a ruling can be made on whether further environmental authorization is required, according to the judgment by a High Court in the Eastern Cape division. The claimants argue the activity will harm local marine life and disrupt fishing, while Shell maintains the practice has been in use for decades to search for oil and gas. “We respect the court’s decision and have paused the survey while we review the judgment,” a Shell spokesman said. “If viable resources were to be found offshore, this could significantly contribute to the country’s energy security.” The ruling follows a public outcry against Shell’s project, which is taking place along South Africa’s Wild Coast, a remote stretch of eastern shoreline where whales are frequently spotted. Mineral Resources and Energy Minister Gwede Mantashe has defended the activity, citing a dozen seismic surveys conducted in the past five years. He is also a respondent in the case. Local groups in the Wild Coast are concerned that they were not properly consulted and of the impact the survey will have on the climate, communities and marine life, Judge Gerald Bloem wrote, adding that Shell’s community notification was flawed. The decision comes after a separate legal attempt brought by groups including Greenpeace failed to stop the activity earlier this month. In that case, a different judge dismissed the assertion of irreparable harm to marine life as speculative. Environmental groups are globally pushing Shell and others to halt oil and gas developments in their earliest stages or before they even start. Mantashe and the energy giant have been ordered to pay costs of the application for the interim interdict. No date has been set for a decision on whether authorization will be required under the National Environmental Management Act. Shell has said it already has the appropriate permission to conduct the survey.

Indian State Oil Giant To Significantly Expand Oil Exploration -Indian state firm Oil and Natural Gas Corporation (ONGC) plans to raise fourfold its exploration and production acreage by 2025, India’s petroleum minister said on Thursday, as the world’s third-biggest oil importer looks to reduce its large dependence on crude imports.ONGC’s strategy for the future includes boosting the E&P acreage from the current 127,000 square kilometers to 500,000 square kilometers by 2025, Indian Petroleum and Natural Gas Minister Hardeep Singh Puri tweeted on Thursday after visiting the company’s integrated energy center in Maharatna.The state oil firm will “also focus on green hydrogen & other sources of enhancing domestic petroleum & natural gas production in the country which will contribute in reducing the fuel import bill,” the minister added.ONGC accounts for around 75 percent of India’s oil and gas production, while its long reserve life of 15 years provides visibility on future cash flows and is comparable to that of ‘A’ rated peers, Fitch Ratings said in a report on the company earlier this month. Fitch has a ‘bbb+’ standalone credit profile (SCP) rating on ONGC.The company’s chairman Subhash Kumar told local outlet The Tribune in an interview this week that the Himachal Pradesh state in northern India had “immense potential in oil and natural gas exploration.”In recent months, India has not been happy with its import bill as its economy and refiners are more sensitive to international crude oil prices than some other oil-importing nations. India, where imports meet more than 80 percent of oil demand, is one of the large oil consumers that has repeatedly called on OPEC+ to increase oil production more than planned in order to cool the rally in prices. Last month, reports emerged that India was looking to boost its domestic oil production by asking ONGC to weigh a potential sale of majority stakes in two large offshore oil and gas fields.

Ship's captain gets 20 months in jail for oil spill, admitted to "partying" - The Bharat Express News - Sunil Kumar Nandeshwar admitted to drinking and partying (performance) The captain and first officer of a bulk carrier, which triggered the biggest environmental disaster in Mauritius, have been sentenced to 20 months in prison in this island nation in the Indian Ocean. Sunil Kumar Nandeshwar, the captain, and Subodha Tilakaratna, the first officer of MV Wakashio were sentenced on Monday by the Mauritius Intermediate Court. Both pleaded guilty on December 20 to the charge of endangering the safety of navigation. The two men having been in police custody for nearly 16 months and the guilty plea signifying leniency in the pronouncement of the sentence, the duration of the imprisonment is deemed to have been completed. “If we take into account the time spent in pre-trial detention and in remand for good behavior, the sentence can be considered served,” said Amira Peeroo, lawyer for Tilakaratna, in a telephone interview from Port Louis, after sentence. Mauritius has battled widespread pollution from the oil spill, which threatened the livelihoods of communities that depend on the ocean, and the Blue Bay Marine Reserve, popular with snorkelers. Mauritius’ economy relies on tourists flocking to its white sand beaches is also reeling from the fallout from the coronavirus. ALSO READ Biden told team to 'prepare' for failed nuclear talks with Iran: Psaki The 300-meter-long Japanese ship was en route to Brazil from China when it deviated from course on the evening of July 25, 2020 and struck a coral reef. Two weeks later, the fuel oil began to leak with about 1000 tonnes reaching the coast. The ship then broke in two and sank. Nandeshwar admitted to drinking and partying. He agreed the ship was sailing near the coast of Mauritius so that they could get mobile phone signals, according to media reports.

There is a semi-abandoned oil tanker off the coast of Yemen - A large oil tanker, the FSO Safer, owned by the US oil company ExxonMobil, has been docked for fourteen years a few miles off the coast of Yemen and is in danger of exploding, catching fire or sinking and spilling a huge amount of oil into the Red Sea. The risk has been compared to the historic 1989 Exxon Valdez disaster: then the supertanker Exxon Valdez, owned by the US oil company Exxon (named ExxonMobil after a 1999 merger), collided with a reef in Prince William Strait, in Alaska. According to estimates by the Exxon Valdez Oil Spill Trustee Council, the committee responsible for rehabilitating the areas affected by the accident, the ship spilled 257,000 barrels of oil into the sea, causing one of the worst ecological disasters in history. The amount of oil that could be lost from the FSO Safer ship is four times that of the Exxon Valdez, and would cause enormous environmental, human and economic damage. «The unit of measurement used for oil tankers is the deadweight, which is the tons that the ship can carry when fully loaded. According to this parameter, the Safer is one of the largest ever, “wrote the journalist Ed Caesar, who reconstructed the story of the supertanker in a long reportage for the New Yorker. Built in 1976 in Japan, the supertanker, which at the time was called Esso Japan, traveled for six years between Europe and the Middle East before being bought by the Hunt Oil Company, a US oil company that had discovered an oil field near Marib. , a city in the hinterland of the then Arab Republic of Yemen (the unification with the People’s Democratic Republic of Yemen and the birth of Yemen as we know it today occurred in 1990). The Hunt Oil Company and Exxon had built a pipeline to transport the oil from Marib to the coast, where there was no facility to store it. Instead of spending hundreds of millions of dollars to build it from scratch, the company converted the Esso Japan ship into a floating terminal. Floating Storage and Offloading unit, FSO), changing its name to FSO Safer and positioning it off the Yemeni coast, north of the port city of Hodeidah. “In the late 1980s, Safer was one of the best places to work in Yemen,” writes Caesar. Some of the crew members were Italians – “including excellent chefs,” he writes – and over time more and more Yemenis found work on the ship. In 2005, FSO Safer became administered by the Safer Exploration & Production Operations Company (SEPOC), a Yemeni state-owned company, while the government began planning to build a coastal terminal to replace it. “The new terminal was half-built when the capital of Yemen, Sana’a, was conquered by the Houtis,” writes Caesar. The Houtis are a Zaydite Shiite militia, a very particular sect of Shiism from the mountains in northern Yemen. Starting in 2011, the Houthis intensified their armed uprising against the government, rebelling first against the regime of President Ali Abdullah Saleh, then against that of his successor, Abdel Rabbo Mansour Hadi. In 2014 the Houtis, with the support of Iran, occupied the capital of Yemen Sana’a and in March 2015 they entered Aden, the provisional capital of the country after the occupation of San’a, causing the flight of President Hadi in Saudi Arabia. Later a coalition of Arab countries led by Saudi Arabia began bombing the Houti positions, starting a war that has continued ever since and that the United Nations and other organizations believe caused the worst humanitarian crisis in the world.

Saudi oil exports surged in October on higher oil prices--Saudi Arabia’s exports soared in October as the world’s biggest oil exporter benefited from higher crude prices. The value of exports jumped to 106.2 billion riyals ($28 billion) from 55.9 billion riyals a year ago, according to the kingdom’s General Authority for Statistics. The share of oil in total exports rose to 77.6% in October from 66.1%. Saudi Arabia’s economy has rebounded this year as oil prices soared and the impact of the coronavirus pandemic eased. This month, the kingdom boosted its revenue forecast for next year, with higher crude output and prices poised to deliver the first budget surplus in eight years and the fastest economic growth since 2011. The value of oil exports rose 123%, or by 45.5 billion riyals, year-on-year in October, according to the statistics authority. Non-oil exports increased 25.5% to 23.8 billion riyals. Oil has gained about 50% this year with a robust rebound from the pandemic, but the rally has faltered recently, in part due to concerns about omicron. There are some signs of tightening emerging, however, with supply disruptions in Libya and Nigeria, while the demand outlook was boosted in recent days by positive news about the severity of omicron.

Fuel for Thought: Asian oil buyers have little room to play around with SPRs -- The word "strategic" in the phrase Strategic Petroleum Reserves is there for a reason and no one understands it better than Asia's biggest oil importers. With the energy security aspirations of Asia's biggest four oil importers—China, India, Japan and South Korea—perpetually vulnerable to global price gyrations, they have increasingly expanded their SPR capacity over the past decades—an effort to ensure they have an emergency oil storage facility that can be used to mitigate oil supply disruptions. But when crude oil prices crossed $85 a barrel earlier this year, Asian oil importers worried this would derail a fragile economic recovery. As a result, for the first time countries like India and China turned to strategic oil reserves to cushion the impact of rising prices. The market also witnessed coordinated SPR releases by Asian consumers, along with the United States. While market reaction to the development has been muted so far, largely because actual releases have come in below expectations, traders have one key question in mind: Will this be an ongoing trend? "Adding a layer of uncertainty is the fact that China and India are large net oil importers. So they will likely seek to restock their strategic buffers at some point." Immediately after the White House announced Nov. 23 that the US will release 50 million barrels from its SPR early next year, India, China, South Korea and Japan followed suit and announced their plans to release SPRs. While India agreed to release 5 million barrels of crude, China is expected to release more crude from state reserves amid expectations that the second set of auctions could potentially include at least 7 million barrels of medium sweet ESPO blend crude. South Korea has agreed to release 3.17 million barrels from its SPRs, including 2.08 million barrels of crude oil and 1.09 million barrels of refined products, over a three-month period starting January. And Japan's sales of national petroleum reserves will be made by advancing its planned sales of crude oil grades for replacement in the national petroleum reserves without violating the country's petroleum stockpiling law. The sales could amount to around "a couple of hundred thousand kiloliters," according to Minister of Economy, Trade and Industry Koichi Hagiuda. Market sources are unanimous in their view that Asian importers will be reluctant to release huge volumes from SPRs and make it an ongoing trend—just as a cushion for high prices. Take the example of India. The country has an SPR capacity of 5.33 million mt. And for the second phase, the federal cabinet has given its approval to build a further 6.5 million mt of SPRs. While the first phase, which is fully filled, can cater to about 9.5 days of India's crude oil requirements, the second phase will add another 12 days. "While state refiners in India also hold substantial volumes of oil, the overall volumes are not big enough. The last thing countries like India will want is expose themselves by releasing huge volumes when prices are high and find themselves being caught off guard when there is a supply disruption," Asian countries have followed a similar model of building SPRs that of the United States. While the idea of stockpiling emergency oil in the US arose as early as 1944, it took the oil embargo of 1973-74 to spur the creation of the Strategic Petroleum Reserve. But for the US, the growth of shale and a large SPR balance provide the country with flexibility to sell SPR stocks to plug fiscal deficits, as Congress has done with budget bills since 2015, as well as enact price-related releases without a need to ever return the barrels. According to Platts Analytics, the Congress appears determined to sell of the majority of the SPR for fiscal reasons. Large deliveries required through 2031 are set to reduce the Reserve's balance to 316 million barrels, versus 695 million barrels as recently as 2016. This would no doubt reduce the flexibility to release strategic stocks during a supply interruption, as the SPR was originally intended. But despite that, the risks for the US would be much lower due to its growing shale sector, compared with some Asian countries like South Korea, which imports 100% of its oil needs, and India, which ships in 85% of its petroleum requirements.

Russia says OPEC+ prioritises mid-term strategy over U.S. calls for more oil (Reuters) - Russian Deputy Prime Minister Alexander Novak said on Wednesday that OPEC+ group of largest oil producers has resisted calls from Washington to boost output because it wants to provide the market with clear guidance and not deviate from policy. The United States has repeatedly pushed OPEC+ to accelerate output hikes as U.S. gasoline prices soared and President Joe Biden's approval ratings slid. Faced with resistance, Washington said in November it and other consumers would release reserves. Asked why OPEC+ rebuffed the calls, Novak said OPEC+ had a long-term vision. "We believe that it would be right for the market to show in the mid-term how we will increase production as demand grows," he told RBC media outlet. "The producing companies should understand beforehand which investments they have to plan in order to ensure a production increase." OPEC and its allies agreed earlier this month to stick to their existing policy of monthly oil output increases despite fears that a U.S. release from crude reserves and the new Omicron coronavirus variant would lead to a fresh oil price rout. Novak also said the possible release of the strategic stockpiles by the United States and other large consumers will have a limited short-term impact on the oil market. He said global oil demand was seen rising by around 4 million barrels per day (bpd) next year after an increase of up to 5 million bpd this year. Novak said an oil price of between $65 and $80 per barrel should be comfortable next year. Currently, oil is trading below $80.

OPEC+ likely to stick to existing oil production policy at Jan. 4 meeting: Reuters --OPEC and its allies will probably stick to their existing policy of modest monthly increases in oil output at a meeting next week, four sources said, as demand concerns raised by the omicron coronavirus variant ease and oil prices recover, according to Reuters. The Organization of the Petroleum Exporting Countries and allies, known as OPEC+, is set to decide on Jan. 4 whether to proceed with a 400,000 barrels per day output hike for February, the latest in a steady unwinding of record cuts made last year. “At the moment, I have not heard of any moves to change course,” said an OPEC+ source. A Russian oil source and two other OPEC+ sources also said no changes to the deal were expected next week. At its last meeting on Dec. 2, OPEC+ stuck to the plan for a 400,000 bpd rise in January, despite fears that a US release from crude reserves and omicron would lead to an oil-price rout. The benchmark oil price tumbled more than 10 percent on Nov. 26 toward $72 a barrel when reports of the new variant first appeared, but has since recovered to almost $80 and OPEC+ sources have said the December decision to go ahead with the supply boost was correct. “Great outcome,” a separate OPEC+ source said of the market’s rally since the last meeting. Russian Deputy Prime Minister Alexander Novak said on Wednesday OPEC+ has resisted calls from Washington to boost output further because it wants to provide the market with clear guidance and not deviate from policy. The United States has repeatedly pushed OPEC+ to accelerate output hikes as US gasoline prices soared and President Joe Biden’s approval ratings slid. Faced with resistance, Washington said in November it and other consumers would release reserves. Novak also said on Wednesday the possible release of the strategic stockpiles will have a limited short-term impact on the market. OPEC ministers are also set to discuss who will become the group’s new secretary general to replace Mohammad Barkindo, who is scheduled to leave at the end of July. Kuwait’s candidate for the job has widespread support, sources have said.

Saudi Arabia May Cut Oil Prices For Asia --Saudi Arabia could cut the official selling price for oil to Asian buyers in February after raising them substantially this month.According to a Reuters report citing industry insiders and poll data, the Kingdom could slash the prices for all its export grades by as much as $1 per barrel and more, which would push these prices to their lowest in three to four months.Earlier this month, Saudi Arabia raised its official selling prices for oil to Asia by $0.60 per barrel, which brought them $3.30 per barrel above the Oman/Dubai benchmark. The price hike suggested expectations of strong demand, which in turn implied that Saudi Arabia is not all that worried about the Omicron variant that caused a more than $10 plunge in oil prices in late November, with Brent at one point dipping below $70 per barrel. This month, however, prices have rebounded globally, but the spot market premium for Middles Eastern and Russian grades has fallen by more than 50 percent since the start of the month, Reuters noted in its report. The drop was a result of higher OPEC+ production this month.The price cut for February is in part a move in anticipation of lower demand from Asian buyers as refineries on the continent prepare for maintenance season in the second quarter of the year, Reuters noted.Saudi Arabia will announce its official selling prices for oil after the January OPEC+ meeting, to take place on the 4 ^th of the month. Asia accounts for more than half of Saudi oil exports.

Oil Futures Chase Equities Higher; Iranian Talks Resume -- Reversing early morning losses, oil futures nearest delivery on the New York Mercantile Exchange and Brent crude traded on the Intercontinental Exchange rallied to one-month highs on Monday. Futures found buying support from expectations for demand growth in 2022 amid ongoing economic strength while what is known as the year-end "Santa Claus" rally in financial markets offset some concerns over the rapid spread of the omicron COVID variant across major oil-consuming economies.U.S. stock indexes rose sharply on Monday as investors looked at fresh data from Mastercard's SpendingPulse report that found holiday sales from Nov. 1 through Dec. 24 surged 8.5% year-on-year -- the fastest pace in 17 years. Strong sales came despite ongoing headwinds including supply chain disruptions and growing inflationary pressures joined by the spread of Omicron in December. the United States recorded 189,000 new COVID-19 infections on Christmas Day -- the highest since January.Among latest disruptions from Omicron, U.S. airlines canceled more than 1,800 flights over the holiday weekend because of personnel shortages linked to a spike in cases of the new variant. Real-time flight tracking data from FlightAware showed 951 flights to and from the United States canceled as of Saturday, Dec. 25, afternoon. Delta listed 309 flight cancellations, United had 240, Jet Blue had 123 and American Airlines had 92. The cancellations stoked concerns over demand implications from the Omicron surge as consumers retreat to the safety of their homes and governments renew quarantine restrictions.Still, some analysts believe that the new variant will be successfully mitigated by the vaccines and the rollout of booster shots. In a note to clients Monday, J&P Morgan said, "We do not expect Omicron to impact the growth outlook in any significant way, but rather it is likely to accelerate the end of the pandemic." Also on Monday, oil traders monitored the start of multilateral nuclear talks in Vienna after Iran's negotiators adjourned talks for further consultations with officials in Tehran. Wire services reported Iran's chief negotiator, Ali Bagheri, insisted today that the United States and Western allies guarantee free flow of crude oil exports as a precondition for any agreement. Previous rounds saw similar demands made by Tehran that went unfulfilled. U.S. sanctions have slashed Iran's oil exports -- the country's main revenue source -- from about 2.8 million barrels per day (bpd) in 2018 to as low as 200,000 bpd in late 2020. Reuters survey pegged Iran's oil exports at 600,000 bpd in June.At settlement, NYMEX February West Texas Intermediate futures advanced $1.78 to $75.57 per barrel (bbl), with gains accelerating post-settlement, and the front-month Brent crude rallied $2.46 for a $78.60-per-bbl settlement. NYMEX January RBOB futures surged 2.78 cents to $2.2339 gallon, and the January ULSD contract gained 2.21 cents to $2.3535 gallon.

Oil rises as Omicron concern eases - Oil prices rose on Monday due to hopes that the Omicron COVID-19 variant will have a limited impact on global demand in 2022, even as U.S. crude came under pressure from flight cancellations amid surging cases. More than 1,300 flights were cancelled by U.S. airlines on Sunday as COVID-19 reduced the number of available crews while several cruise ships had to cancel stops. Global benchmark Brent crude ended the day up 3.2%, or $.46, at $78.60 per barrel. U.S. West Texas Intermediate (WTI) crude settled 2.4%, or $1.78, higher at $75.57 per barrel. The U.S. market was closed on Friday for a holiday. "Lower travel equalling lower economic activity in the U.S. equals lower WTI," said Jeffrey Halley, analyst at brokerage OANDA, who added that the divergence between Brent and WTI could reflect that global recovery remains on course. "The disruption to goods and services from isolating workers, notably air travel, seems to be the main fallout so far," he said of rising Omicron cases. "That is only likely to cause short-term nerves, with the global recovery story for 2022 still on track." Brent has risen by more than 45% this year, supported by recovering demand and supply cuts by the Organization of the Petroleum Exporting Countries and its allies, collectively known as OPEC+. Oil, which plunged by more than 10% on Nov. 26 when reports of a new variant first appeared, gained last week after early data suggested that Omicron could cause a milder level of illness. "Though Omicron is spreading faster than any COVID-19 variant yet, a relatively relieving news is that most people infected with Omicron are showing mild symptoms, at least so far," said Leona Liu, analyst at Singapore-based DailyFX. Talks resume today between world powers and Iran on reviving Tehran's 2015 nuclear deal. Iran on Monday said that oil exports were the focus of the talks, which so far appear to have made little progress on boosting Iran's shipments. Also on investors' radar is the next OPEC+ meeting on Jan. 4, in which the producer alliance will decide whether to go ahead with a planned 400,000 barrels per day (bpd) production increase in February. OPEC+ stuck to its plans at its last meeting to boost output for January despite Omicron.

Oil prices reach four-week high as markets account for Omicron--Oil rose in tandem with equity markets as investors weighed the rapid spread of omicron against signs it may be milder than previous variants. West Texas Intermediate futures surpassed $75 a barrel on Monday for the first time in a month amid light trading. Daily omicron infections in the U.S. have surpassed those in the delta wave, CNN reported, while China posted the highest number of cases since January. Thousands of flight delays and cancellations in the U.S. stemming from airline-employee illnesses were a reminder that the more infectious Covid variant could still wreak havoc. Despite the omicron spread and airline cancellations, mobility numbers were strong over the holiday, said John Kilduff, founding partner at Again Capital LLC. The strong economic activity has played into a “rebound in petroleum demand, which we saw this morning.” Oil is heading for a yearly gain after a robust rebound from the pandemic, but the rally has wavered in recent weeks, in part due to concerns about omicron. There are some signs of softening consumption in Asia and crude market’s structure has weakened significantly, indicating over-supply in the near term. The market structure for international benchmark Brent crude is starting to show signs of optimism. The prompt timespread -- the gap between the two nearest contracts -- has returned to a bullish pattern in recent days after flipping briefly into a bearish contango structure. The spread was 33 cents in backwardation on Monday, compared with as much as 10 cents in contango about a week ago. WTI for February delivery rose $1.82 to $75.61 a barrel at 12:53 p.m. in New York. Brent for February settlement rose $2.51 to $78.65 a barrel. The fast-spreading omicron has forced airlines to cancel some services due to crew shortages, threatening a nascent rebound in jet fuel usage. Anthony Fauci, President Joe Biden’s top medical adviser, said Americans should stay vigilant against the new strain, despite evidence its symptoms may be less severe, because the volume of cases can still overwhelm hospitals.

Oil Futures Rally to Fresh Highs -- Along with rallying equities and a sagging U.S. dollar index, oil futures nearest delivery extended gains into early trade Tuesday amid renewed optimism that the winter wave of omicron-led COVID infections would have a short-lived impact on the global economy as governments mostly resist new quarantine restrictions and consumers have not pulled backed on spending despite the resurgent pandemic. Supporting the sentiment, the U.S. Centers for Disease Control and Prevention on Monday shortened the recommended quarantine times for the people that have tested positive for COVID-19 from ten days to five days, followed by five days of wearing a mask around others. People who are fully vaccinated and boosted may not need to quarantine at all, the CDC added. The change in CDC guidelines came after several U.S. airlines were forced to cancel nearly 2,000 flights over the Christmas weekend due to staffing shortages, arguing that the lengthy quarantine times were to blame for the staffing problems. Despite a higher transmission rate, the Omicron variant has so far proved to have milder symptoms compared to the original strain of COVID-19 and the Delta variant. United Kingdom said on Monday there would not be any new COVID-19 restrictions in England before the end of 2021 as health authorities await more data on whether hospitals can cope with an Omicron wave of infections. The daily count of new COVID-19 infections in England is at the highest since March at 122,189, although hospitalizations have not yet shown a marked increase. The World Health Organization, meanwhile, cautioned that it could take "several weeks" to assess the severity of the newly discovered Omicron variant. Oil traders will closely monitor any new developments on the Omicron spread and potential implications for global oil demand at the start of the new year. Oil and equity shares were boosted on Monday by data released from Mastercard's SpendingPulse report that found holiday sales from Nov. 1 through Dec. 24 surged 8.5% year-on-year -- the fastest pace in 17 years. This week, oil traders will also monitor the restart of Iranian nuclear talks in Vienna, with early indications suggesting the hardline government in Tehran doubling down on its demands to remove all sanctions before reaching a new comprehensive agreement. Previous rounds saw similar demands made by Tehran that went unfulfilled. U.S. sanctions have slashed Iran's oil exports -- the country's main revenue source -- from about 2.8 million bpd in 2018 to as low as 200,000 bpd in late 2020. Near 7:30 a.m. ET, NYMEX February West Texas Intermediate futures advanced $1.11 to $76.69 per barrel (bbl), and the front-month Brent crude rallied $1 to near $79.60 bbl. NYMEX January RBOB futures surged 2.81 cents or 1.2% to $2.2620 gallon and the January ULSD contract rallied 3.49 cents to $2.3884 gallon.

Oil settles higher despite Omicron concerns (Reuters) - Oil prices settled higher on Tuesday, with Brent crude ending the session near $80 a barrel despite the rapid spread of the Omicron coronavirus variant, supported by supply outages and expectations that U.S. inventories fell last week. Brent crude settled up 34 cents, or 0.4%, at $78.94 a barrel by 1:39 p.m. EST (1839 GMT). U.S. West Texas Intermediate (WTI) crude settled up 41 cents, or 0.5%, at $75.98. Both contracts traded at their highest levels in a month, aided by strength in U.S. equities. "The stock market appears poised to finish the year at or near record highs with easy spillover into the oil space pushing crude values higher," "Support comes as well from high aggregated production disruptions in Ecuador, Libya and Nigeria and the expectation of another large drop in U.S. crude inventories," . The three oil producers declared forces majeures this month on part of their oil production because of maintenance issues and oilfield shutdowns. A preliminary Reuters poll showed on Monday that U.S. crude oil inventories are likely to have dropped for the fifth week in a row, while gasoline inventories were seen mostly unchanged last week. [EIA/S] England will not face any new COVID-19 restrictions before the end of 2021, British health minister Sajid Javid said on Monday, as the government awaits more evidence on whether the health service can cope with high infection rates. U.S. President Joe Biden, meanwhile, pledged to ease a shortage of COVID-19 tests as the Omicron variant threatens to overwhelm hospitals and stifle travel plans. Omicron-induced staff shortages led to thousands of flight cancellations over the Christmas weekend in the United States. Investors are awaiting an OPEC+ meeting on Jan. 4, at which the alliance will decide whether to go ahead with a planned production increase of 400,000 barrels per day in February. At its last meeting, OPEC+ stuck to its plans to boost output for January despite Omicron. Money managers raised their net long U.S. crude futures and options positions in the week to Dec. 21, the U.S. Commodity Futures Trading Commission said on Monday. The speculator group raised its combined futures and options position in New York and London by 4,634 contracts to 259,093 during the period.7:23 PM

WTI Spikes Near One-Month Highs After Big Crude, Product Inventory Draws - Oil prices have rollercoastered back into the green (back bear one-month highs) this morning after weakness overnight (which could have been driven by reports out of China's Xi'an province of COVID-based driving bans).“Crude oil trades near a one-month high after API’s weekly stock report,” said Ole Hansen, head of commodities strategy at Saxo Bank A/S. The market is “currently betting the omicron virus, despite a global surge, will not derail robust global demand.”So the bulls are hoping the official data backs API, and Biden is hoping it doesn't. API

• Crude -3.09mm (-3.233mm exp)
• Cushing +1.594mm
• Gasoline -319k
• Distillates -716k

DOE:

• Crude -3.576mm
• Cushing +1.055mm
• Gasoline -1.459mm
• Distillates -1.726mm

The official DOE data confirmed API's sizable crude draw and showed bigger than expected product draws while Cushing stocks rose for the 7th straight week... Graphics Source: Bloomberg. Crude production rose to the highest since May 2020... WTI hovered around $75.80 ahead of the print and spiked almost $1 after the big draws... Crude is heading for its biggest annual gain in more than a decade after global consumption recovered from the pandemic with the roll-out of vaccines.

Oil Futures Slip on Profit-taking After Bullish EIA Report -- After initially rallying in response to a bullish weekly report from the U.S. Energy Information Administration, oil futures nearest delivery on the New York Mercantile Exchange turned lower amid profit-taking ahead of end-year accounting and the upcoming holiday weekend. The midmorning inventory report showed total commercial petroleum stockpiles fell by a whopping 18.9 million barrels (bbl) during the week ended Dec. 24, with 3.6 million bbl of that drop realized in commercial crude oil inventories. The draw was bullish against expectations for a 3.2 million bbl decline from analysts and estimates of a 3.09 million bbl drawdown by the American Petroleum Institute. At 420 million bbl, nationwide crude oil inventories stand about 7% below the five-year average. Oil stored at Cushing, the delivery point for West Texas Intermediate, rose by 1.1 million bbl from the previous week to 34.7 million bbl. Refiners, meanwhile, increased run rates by 0.1% last week to 89.7% of capacity compared with estimates for a 0.2% decrease. The bearish part of the report could be found on the production side, with domestic operators ramping up crude output by 200,000 barrels per day (bpd) from the previous week to 11.8 million bpd -- a 19 months high. In the gasoline complex, EIA data showed supplies fell by 1.5 million bbl to 222.7 million bbl, about 6% below the five-year average. Earlier this week, analysts were expecting a 200,000 bbl build and API reported a much smaller 319,000 bbl draw from gasoline inventories. Demand for motor gasoline surged 738,000 bpd or 19.6% to 9.724 million bpd -- the highest demand rate since the final week of July. EIA figures were directionally in line with DTN Refined Fuels Demand data that found a 5.1% increase in week-on-week U.S. gasoline demand. Gasoline consumption has mostly remained on par with 2019 levels in the fourth quarter despite ongoing surge in Omicron COVID cases and higher gasoline prices. The strength in gasoline demand might also suggest that some Americans have chosen to get behind the wheel for Christmas travel instead of boarding a plane amid widespread flight cancellations. Demand for middle distillates also surged to above 4 million bpd, up 229,000 bpd from the previous week, according to the EIA report. Distillate stocks fell by 1.7 million bbl from the previous week to 122.4 million bbl and are now about 14% below the five-year average. Analysts expected distillates inventories would rise by 200,000 bbl. Surging imports of goods, demand-driven manufacturing activity and strong retail sales have all contributed to burgeoning diesel demand this year that has consistently surpassed pre-pandemic levels. Total products supplied over the last four-week period averaged 21.4 million bpd, up 12.4% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.3 million bpd, up 17.1% from the same period last year. Distillate fuel product supplied averaged 4.1 million bpd over the past four weeks, up 7.8% from the same period last year. Near the noon hour in New York, February West Texas Intermediate futures slipped $0.25 to $75.73 bbl. NYMEX January RBOB futures was flat at $2.2471 gallon, with the next-month February contract trading near parity. January ULSD contract declined 1.24 cents to $2.3588 gallon and the February contract widened its discount to 0.11 cents. Both RBOB and ULSD January contracts expire Friday afternoon.

Oil Up on Strong Year-End U.S. Crude, Gasoline Draws By Investing.com -- Oil prices rose for a sixth straight day on Wednesday after U.S. inventory data showed strong drawdowns for both crude and fuels last week as Americans resumed year-end travel and festivities after being assured of lower risks from Covid’s Omicron variant. Crude prices have also been trending higher in anticipation of positive action and remarks in the coming week when global producer group OPEC+ holds its first meeting for the new year. West Texas Intermediate, the benchmark for U.S. crude, settled Wednesday’s trade up 58 cents, or 0.8%, at $76.56 per barrel. WTI has risen more than 12% over the past six sessions, after slumping to a three-week low of $66.04 on Dec. 20 on fears about a wave of Omicron infections reported that week. Year-to-date, WTI is up 57%. London-traded Brent, the global benchmark for oil, settled up 29 cents, or 0.4%, at $79.23. Brent is up more than 11% from its Dec. 20 low of $72.87. Year-to-date, Brent is up 53%. U.S. health authorities, led by the Centers for Disease Control and Prevention, have told Americans over the past week that Omicron appears to be a milder form of the coronavirus compared with the original Covid-19 strain or the Delta variant, especially for those who are vaccinated. Separately, the average number of daily confirmed coronavirus cases in the United States hit a record high of 258,312 over the past seven days, figures compiled by Reuters showed. The report did not determine how many of those infected were unvaccinated. The final weeks of December are typically strong periods for gasoline and diesel consumption in the United States as people take to the road for Christmas, New Year and holiday travels. Trucking activity is also heavy at this time of year due to seasonal gift deliveries. Weekly oil inventory data from the Energy Information Administration on Wednesday reinforced those trends. Crude inventories fell by 3.576 million barrels during the week ended Dec. 24, the EIA reported in its Weekly Petroleum Status Report. Industry analysts tracked by Investing.com had anticipated a drawdown of just around 3.233 million barrels for the week. The latest crude stockpile drop followed back-to-back declines of 4.715 million and 4.584 million barrels in two previous weeks that also exceeded expectations. In an aberration to usual consumption, U.S. gasoline stockpiles swelled two weeks ago by their most in six months as fuel demand briefly slumped amid cutbacks to social activity triggered by Omicron concerns. By last week though, gasoline usage was back to seasonal trends, with inventories falling by 1.459 million barrels, their most since early November. Analysts had forecast a gasoline consumption of 31,000 barrels for last week. Distillates inventories also fell by a substantial 1.726 million barrels last week, the most in three weeks, versus expectations for a drawdown of 59,000 barrels.

Crude Oil Pares Gains After China Cuts Import Allocations -- Oil prices stabilized Thursday, paring earlier gains after China cut its first crude import allocations for the new year, a cut in demand from the largest importer of crude in the world.By 9:05 AM ET (1405 GMT), U.S. crude futures traded 0.1% higher at $76.66 a barrel and the Brent contract rose 0.1% to $79.28.U.S. Gasoline RBOB Futures were largely flat at $2.2677 a gallon.Beijing granted 109 million tons of crude to 42 private refiners in the first set of import allowances for 2022, a drop of 11% from the equivalent period at the start of this year.The market had posted earlier gains after data Wednesday showed U.S. crude oil inventories fell by 3.6 million barrels in the week to Dec. 24, according to data from the Energy Information Administration, roughly in line with what the American Petroleum Institute reported on Tuesday.Gasoline and distillate inventories also fell, indicating demand remains strong despite record Covid-19 cases in the United States, the world’s largest consumer.Crude is on course to post gains of between 50% and 60% in 2021 as demand has climbed back to near pre-pandemic levels while top producers have taken a very cautious stance in returning output to the market.This puts the focus very much on the Organization of the Petroleum Exporting Countries and its allies including Russia, a group known as OPEC+, which is due to meet next week to assess production policy heading into 2022.Another factor that could influence the oil price moving into the new year is risk sentiment, particularly regarding Russia’s intentions toward Ukraine.U.S. President Joe Biden and Russian President Vladimir Putin are set to speak later Thursday in an attempt to defuse tensions, with the U.S. accusing Moscow of plotting to invade the Eastern European country, pointing to the massing of tens of thousands of troops near the Ukraine border in the past two months.“Europe and the U.S. are concerned that Russia may exert further military influence over Ukraine, and this has led to talk of potential oil and gas sanctions,” said Ellen Ward, president and founder of Transversal Consulting, an energy and geopolitics firm. “Amidst this situation, it must be noted that Russia is the primary supplier of natural gas for Europe, which it has been curtailing. Less Russian natural gas in Europe leads to greater use of oil as a power generating fuel.”

Crude Extends Win Streak- Oil edged higher as the market weighed a series of supply outages against smaller import quotas in China, the world’s largest crude buyer. West Texas Intermediate closed 0.6% higher on Thursday, rising for a seventh day for its longest run of increases in 10 months. Oil prices have risen over the past month since the initial plunge in late November, when fears of a global economic lockdown due to the omicron variant jolted markets. “That creep up reflects recognition that economic activity remains quite strong despite the obvious worsening of the pandemic,” said Pavel Molchanov, an analyst at Raymond James & Associates Inc. “Consumer behavior and the overall economy is in good shape, and ultimately that’s what matters more for oil demand.” Crude is on course for the biggest annual advance in more than a decade, with the market now largely shrugging off the emergence of the omicron virus variant. The rollout of vaccines accelerated the reopening of economies, propelling crude’s advance. Additionally, surging natural gas prices spurred greater demand for oil-derived products while OPEC+ continues to only drip-feed additional supplies onto the market. Goldman Sachs Group Inc. forecasts further gains in oil prices next year. The market’s lack of reaction to omicron “bodes well for demand to start 2022,” according to Jens Pedersen, a senior analyst at Danske Bank A/S. “It further suggests OPEC+ made the right call to stick to its plans of further normalizing production.” The Organization of Petroleum Exporting Countries and its allies including Russia are set to gather next week to assess the state of the market and to review supply policy into 2022. This year, the group has restored shuttered capacity at a gradual pace, arguing that a cautious approach is merited. Consultant JBC Energy estimates that OPEC members boosted production by 195,000 barrels a day in December, led by gains in Saudi Arabia. Prices: WTI for February delivery rose 43 cents to settle at $76.99 a barrel in New York. Brent for February, which expires Thursday, gained 9 cents to settle at $79.32. Earlier in the session, crude was under pressure as China cut the amount of import quota awarded to private refiners and favored complex processors as it seeks to reform the sector. Beijing granted 109 million tons, 11% less than last year, in the first batch for 2022, according to officials from companies that received notification of the allowances. The price dip blunted a recent rally sparked by a series of supply outages in Ecuador, Libya and Nigeria -- though flows from Nigeria’s Forcados terminal resumed Wednesday. U.S. crude stockpiles also shrank for a fifth consecutive week, according to Energy Information Administration data released Wednesday.

Oil up for 7th Straight Day as New Year’s Eve Closes In - Oil prices rose for a seventh-straight day and as New Year's Eve neared, on optimism about global travel in 2020 despite risks expected from Covid variants.Saudi King Salman’s call on oil producers to stick with OPEC+’s output caps and recommendations to ensure market stability also supported crude prices on Thursday. The 23-nation oil producing alliance, led by Saudi Arabia and Russia, meets on Jan. 4 to confirm a 400,000 barrels-per-day increase in output for February if it deems market conditions appropriate.West Texas Intermediate, the benchmark for U.S. crude, settled Thursday’s trade up 43 cents, or 0.6%, at $76.99 per barrel. WTI has risen more than 13% over the past seven sessions, after slumping to a three-week low of $66.04 on Dec. 20 on fears about a wave of Omicron infections reported that week. Year-to-date, the U.S. benchmark is up 58%.London-traded Brent, the global benchmark for oil, settled up 9 cents, or 0.1%, at $79.32. Brent is up more than 11% from its Dec. 20 low of $72.87. Year-to-date, the global benchmark is up 53%.U.S. health authorities, led by the Centers for Disease Control and Prevention, have assured Americans over the past week that Omicron was a less risky form of the coronavirus compared with the original Covid-19 strain or the Delta variant, especially for those who are vaccinated.The average number of daily confirmed coronavirus cases in the United States hit a record high of 258,312 over the past seven days, figures compiled by Reuters showed on Wednesday. The report did not determine how many of those infected were unvaccinated. Separately, CDC data shows that more than 61% of the total U.S. population is fully vaccinated, and over 32% of fully vaccinated adults have received a booster.The final weeks of December are typically strong periods for gasoline and diesel consumption in the United States as people take to the road for Christmas, New Year and holiday travels. Trucking activity is also heavy at this time of year due to seasonal gift deliveries.Weekly oil inventory data from the Energy Information Administration on Wednesday reinforced those trends.Crude inventories fell by 3.576 million barrels during the week ended Dec. 24, the EIA reported in its Weekly Petroleum Status Report. Industry analysts tracked by Investing.com had anticipated a drawdown of just around 3.233 million barrels for the week.The latest crude stockpile drop followed back-to-back declines of 4.715 million and 4.584 million barrels in two previous weeks that also exceeded expectations.In an aberration to usual consumption, U.S. gasoline stockpiles swelled two weeks ago by their most in six months as fuel demand briefly slumped amid cutbacks to social activity triggered by Omicron concerns.By last week though, gasoline usage was back to seasonal trends, with inventories falling by 1.459 million barrels, their most since early November. Analysts had forecast a gasoline consumption of 31,000 barrels for last week. Distillates inventories also fell by a substantial 1.726 million barrels last week, the most in three weeks, versus expectations for a drawdown of 59,000 barrels.

Crude Oil Futures Snap 7-day Winning Streak, Settle Sharply Lower - Crude oil futures settled lower on Friday, after a 7-session winning streak, but still posted a strong gain for the week and the month.Oil prices dropped, due largely to profit taking after recent gains.West Texas Intermediate Crude oil futures for February ended down $1.78 or about 2.3% at $75.21 a barrel.Crude oil futures climbed 1.9% in the week. In the October - December quarter, WTI futures gained 0.3%, and added 13.7% in the year.Oil futures climbed as much as 55% in the year, the sharpest annual rise since 2016.Brent crude futures were down $1.68 or 2.1% at $77.85 a barrel a little while ago. Brent crude futures gained about 11% in December, and posted a gain of 51% in the year.Traders continued to closely follow the updates on the virus fron. Coronavirus cases surged to record highs around the world despite the imposition of lockdowns and travel restrictions by several governments.U.S. health experts warned Americans to prepare for severe disruptions in the first weeks of 2002 amid increased holiday travel, New Year celebrations and school reopenings following winter breaks.Traders also looked ahead to the upcoming OPEC+ meeting, scheduled to take place on January 4. The oil producing alliance will decide whether to continue increasing output in February.On Thursday, Saudi King Salman called on all major oil prducers to stock with OPEC+'s output caps and recommendations in order to ensure market stability.

U.S. oil snaps 7-session streak of gains but logs best yearly rise in over a decade - U.S. oil futures on Friday settled lower on the eve of 2022, marking the first decline in the past eight sessions, but the loss belies a stellar year for crude bulls, with the commodity posting the sharpest annual rise since 2009. West Texas Intermediate crude oil for February delivery declined $1.78, or 2.3%, to end at $75.21 a barrel on the New York Mercantile Exchange, after gaining 0.6% on Thursday. For the week, oil rose 1.9%, rose 13.7% in December and posteed a 0.3% rise in the quarter. For the year, WTI rallied more than 55% to clinch its sharpest annual gain in 12 years, FactSet data show.

Market Sees Minimal Pandemic Demand Destruction - Oil markets started the week on a high note as traders took on more risk aided by a bullish U.S. inventory report and despite the spread of the Omicron variant. WTI rallied to a five week high at just under $77.45 barrel during its seventh straight session of gains. Brent crested the $80 per barrel mark as the market continues to see minimal demand destruction coming from pandemic-related closures and restrictions. Daily cases of both Covid-19 variants are on the rise but symptoms are fewer and hospital stays are shorter for the vaccinated. However, the virus outbreak did put a dent in holiday air travel as thousands of flights were canceled due to ill staff. Prices are still below the seven year high of $84.65 per barrel set on 10/26/21.This week’s crude inventory report indicated strong demand with the EIA’s weekly petroleum status report reporting that commercial crude inventories fell last week by 3.6 million barrels to 420 million barrels, now seven percent below the average for this time of year, while API report that inventories decreased by 3.7 million barrels. WSJ analysts called for a drop of 3.2 million barrels while the API had called for a decrease of 3.1 million barrels. Refinery utilization rose slightly to 89.7 percent from 89.6 percent. Total motor gasoline inventories decreased 1.45 million barrels and are now six percent below the five average for this time of year. Distillate inventories fell 1.7 million barrels and now stand at 14 percent below the five year average which could lead to heating oil shortages should cold hit the U.S. Northeast for a prolonged period. Crude oil stocks at the key Cushing, OK, hub gained 1.05 million barrels to 34.7 million barrels, or about 46 percent of capacity there, for the seventh straight weekly gain. 1.35 million barrels was withdrawn from the U.S. Strategic Petroleum Reserve, which now stands at 595 million barrels. U.S. oil production rose by 200,000 barrels per day to 11.8 million barrels per day vs. 11 million barrels per day at this time last year. And, the U.S. added seven new drilling rigs last week.Venezuela reported producing one million barrels per day on 12/24/21, the largest one day output since 2019, when U.S. sanctions hurt their exports. However, that level is not expected to be maintained consistently due to unreliable infrastructure. Meanwhile, Mexico’s PEMEX announced that it will stop exporting crude in 2023 as its own refining needs will cover production. The national oil company recently acquired a 50 percent interest in the Deer Park, TX, refinery and is building another in southern Mexico. China, on the other hand, is cutting by nine percent the amount of crude it allows its refineries to import for early 2022.…The S&P 500 hit a record close this week while the Dow reached an intra-day High. All three major U.S. stock indices look to settle higher on the week. The U.S. dollar traded lower, helping support oil prices.Natural gas crashed this week, breaching the $3.60/MMBtu mark despite a bullish storage report and after trading over $4 for five sessions. Mild temperatures have finally reached the UK and Continental Europe providing a break from record-high natural gas prices while in the U.S., unseasonably mild weather has lasted throughout most of December…

U.S. says Iran “dragging its feet” on return to nuclear deal--Talks on reviving the Iran nuclear deal that have resumed in Vienna show some progress but it’s “far too slow,” a U.S. official said Tuesday. “Iran has at best been dragging its feet in the talks while accelerating its nuclear escalation,” State Department spokesman Ned Price said in a press briefing. “We have been very clear that that won’t work.” If Iran continues at that pace, it will be too late to restore the 2015 nuclear accord between Iran and world powers known as the Joint Comprehensive Plan of Action, he said. Diplomats reconvened Monday in the Austrian capital for an eighth round of negotiations meant to limit the Persian Gulf country’s nuclear activities in exchange for relief from U.S. sanctions. Deep divisions continue to plague the European Union-brokered talks, forcing diplomats to contemplate outcomes that fall short of fully reviving the landmark 2015 accord, according to officials with knowledge of the discussions. The new round of talks in Vienna could leave the accord neither quite alive nor categorically dead. While there’s no formal discussion of an interim deal, even leaving the accord in a state of limbo would require an implicit understanding among all sides not to escalate further. Iran took a big step in that direction when it said on Dec. 25 that it wouldn’t exceed 60% enrichment of uranium. “The most important issue for us is to reach a point where Iran can sell its oil comfortably and without any restrictions and receive its money in foreign currency in its own bank accounts,” Iran’s Foreign Minister Hossein Amirabdollahian said Monday, according to the semi-official ISNA news agency. “We should be able to fully reap the nuclear deal’s economic benefits.” But European and U.S. diplomats are increasingly skeptical they can offer the kind of sanctions relief Iran demands. The Islamic Republic has continued to dramatically increase its nuclear activities in the wake of the U.S. decision to unilaterally exit the accord almost four years ago. That’s resulted in a dwindling time horizon for diplomacy to prevent Iran from marshaling the resources necessary to build a nuclear weapon.

Iran says its rocket sends three 'research payloads' into space -Iranian state television showed footage on Thursday (December 30) of what it said was the firing of the launch vehicle. The Simorgh satellite carrier rocket, whose name translates as "Phoenix", had launched the three research devices at an altitude of 470 kilometres (290 miles), spokesman Ahmad Hosseini said.He gave no further details on whether the devices had reached orbit but said an operational launch could take place soon.Iran, which has one of the biggest missile programmes in the Middle East, has suffered several failed satellite launches in the past few years due to technical issues and sabotage.

Israel Launches Massive Attack On Syrian Port, Fires Burn 14 Hours --In the second such major attack this month on Syria's key northern city, the port of Latakia was struck overnight by multiple Israeli missiles, erupting in huge fireballs and massive damage, with the blaze appearing to burn into the morning and even afternoon hours of Tuesday.Syrian state SANA described that "At around 3:21am (05:21 GMT), the Israeli enemy carried out an aerial aggression with several missiles from the direction of the Mediterranean... targeting the container yard in Latakia port." SANA also said there was damage to a nearby hospital.By many accounts this marked a much larger strike compared to a similar attack on the port weeks ago. Likely Israeli warplanes flying over the Mediterranean launched the attack, while some reports suggested cruise missiles. "Live footage aired by state television showed flames and smoke in the container terminal," according to further details in Al Jazeera. "Later on Tuesday, the Syrian government’s media office said emergency services brought under control fires that had broken out in the port’s container storage area." the report added.Fires raged through the day Tuesday, with some eyewitnesses saying they burned out of control for at least fourteen hours.There were no immediate reports of casualties, and any possible injuries remains unclear. Israel has not commented on the strikes, which is typical in the aftermath of its semi-regular attacks on Syria.Importantly, attacks on Latakia - which were a rarity during prior years of Israeli operations inside Syria - are very risky given there's a major Russian airbase a mere dozen miles to the south of the port.