oil prices ended higher for the eighth week in the past nine this week, as a new stimulus bill and a weaker dollar supported prices...after falling 2.1% to $48.24 per barrel last week as a new mutant strain of the coronavirus spreading in the UK worried traders that it would hurt demand for energy, the contract price of US light sweet crude for February delivery rose more than 1% early on Monday after Trump signed the Covid stimulus bill, backing down from his earlier threat to block the $2.3 trillion package, but resumed their slide of the prior week by the afternoon on worries about how the new variant of the Covid-19 would impact demand for energy to end the day down 61 cents at $47.62 a barrel...but oil prices opened higher on Tuesday on progress on a final Brexit deal, which would stabilize trade between Europe and the UK, and finished with a gain of 38 cents at $48.00 a barrel on hopes that a larger pandemic aid payment to US consumers would spur fuel demand and stimulate economic growth...oil prices opened higher again on Wednesday after a bigger-than-anticipated draw from U.S. crude inventories was reported late Tuesday by the American Petroleum Institute, but then fluctuated between gains and losses even after the EIA data showed a larger-than-expected drop in U.S. crude inventories, before settling 40 cents higher at $48.40 a barrel, with gains limited by the detection in Colorado of the more contagious variant of the coronavirus that causes Covid-19...oil then traded in a narrow range in light trading on New Years Eve before settling 12 cents higher at $48.52 a barrel, thus posting a 0.6% gain on the week...while finishing the month of December 6.6% higher, oil contracts still lost more than a fifth of their value in 2020, as lockdowns to combat the coronavirus depressed economic activity and sent oil markets reeling...
natural gas prices also ended slightly higher in volatile trading this week, as prices first tumbled, and then rallied, on swings in the weather outlook...after falling 6.7% to $2.518 per mmBTU last week as the weather turned milder and inventory withdrawals failed to meet expectations, the contract price of natural gas for January delivery opened more than 8% lower on Monday and quickly fell to an 11% loss on weather models that suggested temperatures for much of the country could be well above normal for early January, before recovering a bit to close down 8 1/2% at $2.305 per mmBTU...but almost as quickly as it fell, the January Nymex natural gas futures contract rebounded sharply ahead of its expiration on Tuesday to post a 7% gain at $2.467 per mmBTU, as robust LNG demand took center stage...now quoting the contract price of natural gas for February delivery, which had ended last week at $2.512 per mmBTU and fell 18 cents monday before bouncing back11.8 cents Tuesday, natural gas prices fell 2.2 cents to $2.422 per mmBTU on Wednesday on a continued bearish weather outlook and a slip in LNG demand, before jumping 11.7 cents or nearly 5% higher to $2.539 per mmBTU on Thursday despite a bearish storage report, after weather models flipped colder for the next couple of weeks and gas production dipped back below 90 billion cubic feet per day ..natural gas price quotes thus finished the week 0.8% higher, with the February contract showing a 1.0% gain, as natural gas prices posted their strongest year since 2016...
the natural gas storage report from the EIA for the week ending December 25th indicated that the quantity of natural gas held in underground storage in the US decreased by 114 billion cubic feet to 3,460 billion cubic feet by the end of the week, which still left our gas supplies 251 billion cubic feet, or 7.8% higher than the 3,209 billion cubic feet that were in storage on December 25th of last year, and 206 billion cubic feet, or 6.3% above the five-year average of 3,254 billion cubic feet of natural gas that have been in storage as of the 25th of December in recent years....the 114 billion cubic feet that were drawn out of US natural gas storage this week was less than the average forecast of a 123 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, but it was higher than the average withdrawal of 105 billion cubic feet of natural gas that have typically been pulled out of natural gas storage during the same week over the past 5 years, and much more than the 87 billion cubic feet withdrawal from natural gas storage seen during the corresponding week of 2019....
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending December 25th indicated that because of a decrease in our oil imports and another increase in our oil exports, we had to withdraw oil from our stored commercial supplies for the 16th time in the past twenty-three weeks and for the 22nd time in the past fifty weeks ...our imports of crude oil fell by an average of 238,000 barrels per day to an average of 5,326,000 barrels per day, after risng by an average of 140,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 526,000 barrels per day to a forty week high of 3,625,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 1,701,000 barrels of per day during the week ending December 25th, 764,000 fewer barrels per day than the net of our imports minus our exports during the prior week...over the same period, the production of crude oil from US wells was reportedly unchanged at 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 12,701,000 barrels per day during this reporting week...
meanwhile, US oil refineries reported they were processing 14,287,000 barrels of crude per day during the week ending December 25th, 273,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA's surveys indicated that a net of 866,000 barrels of oil per day were being pulled out of 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 719,000 barrels per day less 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 (+719,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as "unaccounted for crude oil", thus suggesting that there must have been an error or errors of that magnitude in the oil supply & demand figures that we have just transcribed....however, since most everyone treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill or complete wells, we'll continue to report them as published, just as they're watched & believed to be accurate by most everyone in the industry....(for more on how this weekly oil data is gathered, and the possible reasons for that "unaccounted for" oil, see this EIA explainer)....
further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports slipped to an average of 5,698,000 barrels per day last week, which was 14.4% less than the 6,657,000 barrel per day average that we were importing over the same four-week period last year.....the 866,000 barrel per day net withdrawal from our crude inventories was due to a 866,000 barrels per day withdrawal from our commercially available stocks of crude oil, while the oil supplies in our Strategic Petroleum Reserve remained unchanged....this week's crude oil production was reported to be unchanged at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,500,000 barrels per day, while a 2,000 barrels per day decrease to 512,000 barrels per day in Alaska's oil production had no impact on the rounded national total...last year's US crude oil production for the week ending December 27th was rounded to 12,900,000 barrels per day, so this reporting week's rounded oil production figure was 14.7% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016...
meanwhile, US oil refineries were operating at 79.4% of their capacity while using those 14,287,000 barrels of crude per day during the week ending December 25th, up from 78.0% of capacity during the prior week, but excluding the covid collapse earlier this year and the 2005, 2008, and 2017 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the past twenty-eight years....hence, the 14,287,000 barrels per day of oil that were refined this week were still 17.3% fewer barrels than the 17,283,000 barrels of crude that were being processed daily during the week ending December 27th of last year, when US refineries were operating at 94.5% of capacity...
with the increase in the amount of oil being refined, gasoline output from our refineries was higher for the 2nd time in six weeks, increasing by 362,000 barrels per day to 9,191,000 barrels per day during the week ending December 18th, after our gasoline output had increased by 307,000 barrels per day over the prior week...but since our gasoline production is still recovering from a multi-year low in the wake of this Spring's covid lockdowns, this week's gasoline output was still 9.7% less than the 10,173,000 barrels of gasoline that were being produced daily over the same week of last year....at the same time, our refineries' production of distillate fuels (diesel fuel and heat oil) increased by 49,000 barrels per day to 4,639,000 barrels per day, after our distillates output had decreased by 14,000 barrels per day over the prior week....but since it's also just coming off a three year low, our distillates' production was 12.7% less than the 5,311,000 barrels of distillates per day that were being produced during the week ending December 27th, 2019...
even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the second time in seven weeks and for 16th time in 26 weeks, falling by 1,192,000 barrels to 237,754,000 barrels during the week ending December 25th, after our gasoline inventories had decreased by 1,125,000 barrels over the prior week...our gasoline supplies decreased this again week because the amount of gasoline supplied to US users increased by 106,000 barrels per day to 8,128,000 barrels per day, and because our exports of gasoline rose by 154,000 barrels per day to 911,000 barrels per day, while our imports of gasoline rose by 30,000 barrels per day to 601,000 barrels per day....after this week's decrease, our gasoline supplies were 2.4% lower than last December 27th's gasoline inventories of 242,472,000 barrels, but still about 1% above the five year average of our gasoline supplies for this time of the year...
meanwhile, with the modest increase in our distillates production, our supplies of distillate fuels increased for the 4th time in 15 weeks, and for the 22nd time in the past year, rising by 3,095,000 barrels to 152,029,000 barrels during the week ending December 25th, after our distillates supplies had decreased by 2,325,000 barrels during the prior week....our distillates supplies rose this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 580,000 barrels per day to 3,594,000 barrels per day, and because our imports of distillates rose by 175,000 barrels per day to 444,000 barrels per day, while our exports of distillates rose by 29,000 barrels per day to 1,222,000 barrels per day....after this week's inventory increase, our distillate supplies at the end of the week were 13.7% above the 133,720,000 barrels of distillates that we had in storage on December 27th, 2019, and about 6% above the five year average of distillates stocks for this time of the year...
finally, with the decrease in our oil imports and the increase in our oil exports, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) fell for the 18th time in the past twenty-nine weeks but for just the 22nd time in the past year, decreasing by 6,065,000 barrels, from 499,534,000 barrels on December 18th to 493,469,000 barrels on December 25th....but even after that big decrease, our commercial crude oil inventories were still about 11% above the five-year average of crude oil supplies for this time of year, and about 50% above the prior 5 year (2010 - 2014) average of our crude oil stocks as of the last weekend of December, with the disparity between those comparisons arising because it wasn't until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had generally been rising over the past two years, except for this autumn and during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of December 25th were still 14.8% above the 429,896,000 barrels of oil we had in commercial storage on December 27th of 2019, and also 11.8% more than the 441,418,000 barrels of oil that we had in storage on December 28th of 2018, and 16.3% above the 424,463,000 barrels of oil we had in commercial storage on December 29th of 2017...
This Week's Rig Count
note: this week's rig count was released on Wednesday ahead of the New Year's weekend, just as last week's rig count was released on Wednesday ahead of Christmas, which thus means that this week's count still covers 7 days, albeit not the usual 7 days ending on a Friday...that said, the US rig count rose for the 15th time in the past sixteen weeks during the period ending December 30th, but for just the 17th time in the past 42 weeks, and hence it is still down by 55.7% over that forty-two week period....Baker Hughes reported that the total count of rotary rigs running in the US rose by 3 to 351 rigs this past week, which was still down by 445 rigs from the 769 rigs that were in use as of the January 3rd report of 2020, and was also still 53 fewer rigs than the all time low rig count prior to this year, and 1,578 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business....
The number of rigs drilling for oil increased by 3 rigs to 267 oil rigs this week, after rising by 1 oil rig the prior week, leaving us with 403 fewer oil rigs than were running a year ago, and still less than a sixth of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014....at the same time, the number of drilling rigs targeting natural gas bearing formations remained unchanged at 83 natural gas rigs, which was still down by 40 natural gas rigs from the 123 natural gas rigs that were drilling a year ago, and just 5.3% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008...in addition to those rigs drilling for oil or gas, one rig classified as 'miscellaneous' continue to drill in Lake County, California this week, while a year ago there were three such "miscellaneous" rigs deployed...
The Gulf of Mexico rig count remained unchanged at 17 rigs this week, with 14 of those rigs drilling for oil in Louisiana's offshore waters and three drilling for oil offshore from Texas...that was 5 fewer Gulf rigs than the 22 rigs drilling in the Gulf a year ago, when 20 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the Mississippi Canyon offshore from Louisiana, and one rig was drilling for oil offshore from Texas...since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week's national offshore rig figures are equal to the Gulf rig counts....however, in addition to those rigs offshore, two rigs continue to drill through inland bodies of water this week, one in St Mary parish in southern Louisiana and the other in Chambers County, Texas, just east of Houston, while a year ago there was just one rig drilling on US inland waters..
The count of active horizontal drilling rigs was up by 4 to 313 horizontal rigs this week, which was still 388 fewer horizontal rigs than the 701 horizontal rigs that were in use in the US on January 3rd of last year, and less than a quarter of the record of 1372 horizontal rigs that were deployed on November 21st of 2014...on the other hand, the directional rig count was down by 1 to 21 directional rigs this week, and those were also down by 30 from the 51 directional rigs that were operating during the same week a year ago....meanwhile, the vertical rig count was unchanged at 17 vertical rigs this week, and those were still down by 27from the 44 vertical rigs that were in use on January 3rd 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 30th, the second column shows the change in the number of working rigs between last week's count (December 23rd) and this week's (December 30th) 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 during the count before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 3rd of January, 2020..
as you can see, there were only a few changes in drilling activity this week...checking for the details on the Permian in Texas from the Rigs by State file at Baker Hughes, we find that two rigs were added in Texas Oil District 8, which corresponds to the core Permian Delaware, while the rig count in all other Texas oil districts remained unchanged, which thus accounts for the total change in Texas and the 2 rig increase in the Permian...this week's only other change is equally straightforward, as the rig that was added in Oklahoma was added in the Cana Woodford, thus accounting for the two other changes we see in the tables above...
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Pennsylvania natural gas industry ends 2020 with fewer rigs drilling in Marcellus - Pennsylvania’s natural gas industry ends the year with a rig count not only around the lowest of 2020 but also well below where it started the year before the Covid-19 pandemic, oil price wars and overall economic turmoil turned everything upside down. There were an average of 18 rigs working in Pennsylvania in the middle of December, according to data from energy analysis firm Baker Hughes. That’s down from 25 at the same time last year before the pandemic and recession but smack dab in the middle of a glut in the natural gas industry that led to more production than the market needed and sustained low prices in the bargain. Pennsylvania is the country’s second-largest state for natural gas production, behind only Texas, as well as being the center of the Marcellus and Utica Shale boom of the past decade and a half. But production has been taking a hit over the past year as natural gas companies like EQT Corp. (NYSE: EQT) and CNX Resources Corp. (NYSE: CNX), among others, shut off the spigot at some of its gas wells temporarily as prices lagged. The strategy allows the drillers to produce less natural gas when the prices are low — and they were down to near historic lows in 2020 — and then turn it back on when they can get more in a higher price environment. Current production is only one part of the story. Natural gas wells are most productive in the first year or so after they become operational and older wells bring out less gas over time. A natural gas company must keep drilling new wells to maintain or increase production to take into account the older wells. For much of the past decade, that’s meant more wells being drilled and higher production year over year. But 2020 is already destined to have less production in the Appalachian basin, and most of the publicly traded drillers have made clear that they aren’t planning to do any more drilling in 2021 than is required to keep the same production as 2020. Jen Snyder, director at energy analysis firm Enverus, said that the discipline on holding the line in production is due to investors handing “religion and a prayer book” to drillers. That’s showing up in the rig counts. After starting the year at 25, it fell to 22 in May in the heat of the early pandemic and then dropped to 18 in September where it mostly stayed for the rest of the year even though the market signaled that prices could go over the $3 per million British Thermal Units that the drillers say they need to be stable. The rig count was only above 18 once, in November, since the late summer. And that was only two rigs drilling in Pennsylvania for a short time.
University of Pittsburgh receives contract to study health effects of fracking -- The University of Pittsburgh Graduate School of Public Health will receive a $2.5 million contract from the state of Pennsylvania to study the health effects of hydraulic fracturing, or fracking. In recent years, dozens of cases of Ewing sarcoma, a rare bone cancer, and other childhood and young adult cancers have been identified in Washington, Greene, Fayette and Westmoreland counties, where shale gas sites are operating. The state Department of Health last year declined to designate Washington County, where six Ewing sarcoma cases had occurred in the Canon-McMillan School District area, as a cancer cluster. Residents were dissatisfied with those results, which only included three of the six cases in the investigation. In March of 2020, the Department of Health published a four-county report on the number childhood cancer cases. “We have heard the concerns from families and community members impacted by cancer and other health issues in the southwestern part of the state, and we are dedicated to taking the proper steps to keep our residents healthy,” Secretary of Health Dr. Rachel Levine said. Pitt Public Health will be conducting two observational epidemiological studies focusing on known or suspected health effects of hydraulic fracturing. One study will be led by Dr. Evelyn Talbott, professor of epidemiology at Pitt Public Health and director of the Environmental Epidemiology section, who has over 35 years of experience conducting cancer and other health effects studies in Southwestern Pennsylvania and abroad. She will investigate the relationship between hydraulic fracturing and the development of childhood cancers in Southwestern Pennsylvania. “I grew up in Washington County, and one of my first epidemiology investigations at Pitt involved a health study of thyroid cancer among those living near a uranium mill tailings site,” Talbott said. “So this investigation holds both personal and professional significance to me. I am committed to community inclusion and openness as we go forward in our endeavor to learn the facts.” The other study, led by the director of Pitt Public Health’s Center for Occupational Biostatistics and Epidemiology and Research Associate Professor of Biostatistics, Dr. Jeanine Buchanich, will aim to replicate earlier studies on acute conditions, such as asthma and birth outcomes, using data from Southwestern Pennsylvania.
Celebs Protest Fed Approval of Liquid Natural Gas Facility Near Philly - A liquid natural gas facility near Philadelphia got the go-ahead from a federal agency, resulting in a big thumbs-down from some very famous environmental activists.The Delaware River Basin Commission (DRBC) recently approved a construction permit for the Gibbstown Logistics Center in Gloucester County, NJ, which will be capable of handling exports of liquified natural gas. The project from New Fortress Energy involves transporting the gas from the Marcellus Shale across Pennsylvania to the terminal using 100-car trains that activists have called “bomb trains.”Pennsylvania State Sen. Katie Muth, who represents Philadelphia’s suburbs, likened the trains to “the energy of the Hiroshima bomb” in a tweet opposing the project.A flurry of statements from environmental groups came out after Wednesday’s ruling, including one from actor Mark Ruffalo who recently starred in a movie about contaminated water in West Virginia calling the commission’s decision “shameful.” Ruffalo and fellow actor and activist Leonardo DiCaprio were among the signatories on a letter to Govs. Phil Murphy (D-NJ), Andrew Cuomo (D-NY), John Carney (D-DE), and Tom Wolf (D-PA) opposing the terminal. The governors serve as ex-officio members of the Commission and appoint alternates to represent them.The letter argued that the project violates the “strict water quality laws and regulations for toxic” chemicals, and the commission should hold off on voting until President-elect Joe Biden takes offices. The U.S. Army Corps of Engineers, which is also represented on the Commission, previously approved the project as has the New Jersey Department of Environmental Protection.Ruffalo issued a statement calling the decision “shameful” and put the governors on notice. “We will not stand by and let our leaders deceive us in this way,” he said. “We will hold them accountable. And we will replace them.”
Gas-fired Electricity Advances Across Most U.S. Regions Over Past 5 Years, EIA Says -Natural gas-fired electricity generation jumped across all but one U.S. region over the past five years, and the trend continued through November 2020, according to the latest U.S. Energy Information Administration (EIA) Power Plant Operations Report. U.S. natural gas power plants boosted electricity generation by 31% in the Northeast, by 20% in the Central region, and by 17% in the South between 2015 and 2019, EIA said.Gas-fired electricity over the same period in the West declined 1%, dragged lower by a 29% drop in California, where solar-generated power is on the rise. The decline in California more than offset growth in the Northwest and Southwest subregions, according to the agency.Even in California, however, natural gas continues to play an important role. Output from gas-fired power plants in the state is often in high demand in the late afternoon and early evening “because solar power tends to peak and then plateau around midday, rapidly declining by the evening as the sun sets,” according to EIA.“As solar output declines, natural gas-fired generators often have to ramp up, or increase their output, considerably,” researchers said.Through November 2020, the Central, South, and Northeast regions each maintained levels of electricity from natural gas power plants on par with the level of the prior five-year period. The West was up modestly.Increased gas-fired generation reflects a boost in capacity, EIA said. Between 2015 and 2019, nearly 35 GW of net summer capacity entered service, an 11% increase during that period. Most of this new capacity was added in the Northeast region, the agency said.The largest increases in gas-fired generation were in the Northeast and Central regions, near the Appalachian natural gas production region of Ohio, Pennsylvania, and West Virginia. Affordable prices “made it more economical to generate electricity using natural gas instead of coal,” EIA said. “This trend has been most pronounced in regions with competition between coal and natural gas generators,” particularly in the Midcontinent area in the Central region and the PJM Interconnection in the Northeast. “When natural gas and coal are similarly priced on a cost-per-energy-content basis, most natural gas-fired generators can produce electricity more efficiently than coal-fired generators, providing an economic advantage in electricity markets,” EIA said.
Christmas Eve Decline Sets Stage for Natural Gas Futures' Post-Holiday Crash - Natural gas traders on Thursday couldn’t be convinced to go long despite the extended Christmas holiday weekend, especially with the weather data turning milder with every run of the latest models. The January Nymex gas futures contract settled Christmas Eve at $2.518, down 9.0 cents. February slipped 7.6 cents to $2.512. Spot gas prices, which were for gas delivered through Monday, were mostly lower amid the mostly light holiday weekend demand outlook. However, a chilly, wet forecast in the Northeast sparked big gains there. NGI’s Spot Gas National Avg. ultimately climbed 9.0 cents to $2.780.. On Thursday, the few traders that hadn’t quite punched the clock were still digesting the latest storage inventory report. The Energy Information Administration (EIA) reported Wednesday that inventories fell 152 Bcf for the week ending Dec. 18, a pull that came in well short of the near 160 Bcf draw that the market had been expecting.Mobius Risk Group said the published withdrawal of 152 Bcf shows how fragile a market with a short-term memory and a long net speculative position can be. The inventory reduction was 5 Bcf more than the same week last year despite warmer temperatures, and importantly, South Central inventory posted the largest surplus reduction of all EIA regions.“This mattered little to a market which had begun to consider the possibility of a 160-170 Bcf-like withdrawal in the days leading up to the number,” Mobius said.Pausing for a moment and considering what the latest EIA figure implies for the remainder of withdrawal season is an important sanity check, according to Mobius. It’s also a valuable exercise for the producing and consuming community, the firm said.For producers, the fear that a price response like Wednesday’s can generate “feels like being locked outside on a snowy winter day with no shoes, no coat and no one home to unlock the door.” Consumers, on the other hand, may feel “cozily settled in front of the fire with little concern of what’s happening outside, and the perception that cheap fuel is as reliable as the sun rising in the East and setting in the West,” according to Mobius.
Natgas Plunges 10% On "Extremely Bearish" Warmer January Forecast -- Natural gas futures are down more than 10% on Monday morning following new weather models that suggest warmer weather is ahead. Meteorologists at BAMWX show one model that suggests temperature anomalies for much of the country could be well above average for early January. For the next two weeks, heating degree days for US-Lower 48 will be below trend, suggesting warmer temperatures and a decline in energy use to heat homes. "I suspect, however, the forecast for January came out extremely bearish over the weekend, triggering the gap opening, but we'll learn more about that on Monday. The big takeaway this week is likely to be that next week's government report is going to show an average draw. Remember that professionals look at least two weeks ahead," said FX Empire.
Natural Gas Futures Pummeled by Increasingly Warmer Weather Outlooks; Cash Sinks Too - Natural gas futures tumbled more than 20 cents lower in post-Christmas trading as weather data “failed miserably” over the weekend, shedding a hefty amount of demand from the 15-day outlook. With any opportunity for truly cold weather not expected before the middle of next month, the January Nymex gas futures contract settled Monday at $2.305/MMBtu, down 21.3 cents from last Thursday’s close. February plunged 18.6 cents to $2.326. Spot gas prices also tumbled, with widespread losses of 30.0 cents or more seen across the United States. NGI’s Spot Gas National Avg. fell 24.5 cents to $2.535. With the European weather data erasing more than 25 heating degree days from the long-range outlook, and the American model also backing off the projected demand in the early part of January, natural gas traders wasted no time in taking a hatchet to prices. The January Nymex contract opened Monday’s session at $2.311 and traded in a roughly 10.0-cent range before ultimately settling very close to where it started. After trending milder with several consecutive runs right before the Christmas holiday, the weekend weather data trended further milder, according to NatGasWeather. The Global Forecast System (GFS) lost 12 heating degree days (HDD), while the European model lost a heftier 25-plus HDDs. The midday GFS failed to add any “meaningful” demand, the forecaster said, with modest bouts of cooling into the United States over the next week but without widespread frigid cold. “What makes the coming pattern strongly bearish is the eight- to 15-day period favors mild conditions over most of the U.S. with continued only minor bouts of subfreezing temperatures into the northern U.S.,” NatGasWeather said. The firm expects the period is now “too bearish” and will likely add demand in time, “although it would need to be a hefty amount” in order to flip bearish weather sentiment to bullish, which isn’t expected. “We continue to look to Jan. 10-13 as the next best opportunity for more impressive/widespread cold.” Bespoke Weather Services said until the warmer momentum halts, it is difficult to say where a price bottom may be. There is still a healthy block expected to form by the middle third of January, aided by a strong warming in the polar stratosphere, according to the forecaster. However, the Pacific flow needs to slow down for this to send temperatures materially colder. “That is something that may happen in the back half of the month, enough to at least bring back some variability, but confidence is lower after seeing such a huge model bust over the last several days,” Bespoke said. The firm doesn’t see much risk/reward in being bearish, though it advised caution until the market clears the January contract’s expiration on Tuesday, as well as the holiday period, so that it can see how balances shape up once clear of any holiday impact. “It is worth noting that both Europe and Asia are seeing cold,” which should keep high liquefied natural gas (LNG) volumes in play for the foreseeable future, Bespoke said. “This low price environment should give power burns a boost as well into the new year.”
January Natural Gas Bounces Sharply Upon Expiration; Cool Blast Boosts Cash - On a day of heightened volatility, the January Nymex natural gas futures contract rebounded sharply ahead of expiration as robust liquefied natural gas (LNG) demand took center stage. Though a full recovery from Monday’s steep sell-off proved difficult, the January contract expired a whopping 16.2 cents higher at $2.467. The February contract, which takes over the prompt position on Wednesday, jumped 11.8 cents to $2.444. Spot gas prices were mixed, but several locations across the country posted double-digit gains. NGI’s Spot Gas National Avg. ultimately slipped 1.0 cent to $2.525. Whether Tuesday’s swift turnaround in the futures market is warranted is up for debate. That’s primarily because nothing much has changed on the weather front. The latest weather models still don’t show potential for sustained widespread cold until Jan. 12 at the earliest, according to NatGasWeather. The firm said the midday Global Forecast System model held a warmer-than-normal pattern for the coming 15 days, with only the western United States to see weather systems considered cold enough to induce stronger demand. Even then, any boost in demand would be marginal. “We continue to look to Jan. 12-15 as the next best opportunity for more impressive cold shots to arrive into the U.S., and it will need to if weather patterns are to finally take advantage of a tighter year over year supply/demand balance,” NatGasWeather said. The forecaster said Tuesday’s gains are likely because of other reasons, including the January contract’s expiration. “Or, it could simply be a technically oversold bounce after prices plummeted more than 30 cents in less than 24 hours of trading.” The ill-timed span of warm weather is set to occur as the clock ticks away on the remaining storage withdrawal season. When taking into account actual weather over the Christmas holiday, forecasted weather changes through Jan. 7, and newly instituted forecasts for Jan. 8-11, Mobius Risk Group said the change in the cumulative population-weighted heating degree days equates to the loss of roughly 175 Bcf of demand.
February Natural Gas Dips on Continued Bearish Weather Outlook, Slip in LNG Demand -- A decline in liquefied natural gas (LNG) demand aided a small pullback in natural gas futures on Wednesday. With weather models stabilizing around a warm outlook for the first half of January, the new prompt February Nymex contract settled at $2.422/MMBtu, down 2.2 cents from Tuesday’s close. March slipped 1.7 cents to $2.422. Spot gas prices were mixed, but big losses on the East and West coasts left NGI’s Spot Gas National Avg. unchanged at $2.525.After some major price fluctuations during the first two trading sessions of the short holiday week, Wednesday’s more muted action along the Nymex futures curve offered traders a chance to digest the whirlwind swings. “As the market limps towards 2021, there are numerous questions in the air regarding the price path in the New Year and the fundamental factors that will be at play,” said Mobius Risk Group. With weather models offering little new insight into the January pattern, Thursday’s government storage report may be the next big price mover for the February contract.The Energy Information Administration (EIA) is scheduled to release its weekly inventory report at 10:30 a.m. ET Thursday. Analysts are expecting another larger-than-normal draw, with major surveys ahead of the report clustering around a pull in the mid-120s Bcf. Last week, EIA reported a 152 Bcf draw that lowered stocks to 3,574 Bcf, which is 278 Bcf above year-ago levels and 218 Bcf above the five-year average.
2020 Ends With Fireworks for Natural Gas Futures as Chillier Weather Models Trump EIA Data - Natural Gas Intelligence - Natural gas futures closed the book on 2020 with a bang after weather models flipped colder for the next couple of weeks and production dipped back below 90 Bcf/d. The February Nymex futures contract settled Thursday at $2.539, up 11.7 cents day/day. March climbed 10.4 cents to $2.526. Spot gas, which traded Thursday for delivery through Monday, was mostly lower on a lack of widespread cold in the near term. NGI’s Spot Gas National Avg. fell 8.5 cents to $2.440. New Year’s Eve action in the futures market started off on solid footing, with the February Nymex contract opening about a penny higher and climbing about 6.0 cents or so early in the session, ahead of Thursday’s government storage inventory report. The Energy Information Administration (EIA) report proved to be another disappointment, though, coming in with another lower-than-expected withdrawal. The EIA said inventories fell 114 Bcf for the week ending Dec. 25, about 10 Bcf below what the market had expected. Ahead of the report, major surveys clustered around a pull in the mid-120s Bcf, though estimates ranged widely from as low as 85 Bcf to as large as 150 Bcf. NGI had pegged the draw at 124 Bcf. Participants on The Desk’s online energy chat Enelyst attributed the big miss to several factors, including the Christmas holiday, the heavy wind penetration across the country during the reference week and Covid-19’s ongoing impacts on consumption. EIA recorded an 87 Bcf draw for the similar week last year, and the five-year average is a 102 Bcf draw. The EIA withdrawal included a 42 Bcf decline in Midwest inventories and a 34 Bcf decrease in East stocks, according to EIA. In the South Central, 21 Bcf was pulled from nonsalt facilities and 3 Bcf was drawn from salts. Total working gas in storage fell to 3,460 Bcf, which is still 251 Bcf above year-ago levels and 206 Bcf above the five-year average. Despite the hugely bearish EIA report, Nymex futures remained well in the green after the data was released. The February contract’s $2.429 intraday low was still a modest improvement from Wednesday’s settlement, and prices continued to gather momentum with each run of the American and European weather models. The latest European Centre (EC) model run, which already was quite a bit colder than the American Global Forecast System (GFS) model, added even more demand to the 15-day outlook. Specifically, it favors stronger weather systems with colder temperatures into the western United States, Southern Plains, Texas and the South during the Jan. 9-15 period.
US natural gas futures post best year since 2016 - US natural gas futures rose on Thursday, recording their best year since 2016, as forecasts for slightly colder weather and record liquefied natural gas (LNG) exports overshadowed a smaller-than-expected storage draw last week. Front-month natural gas futures for February delivery gained 11.7 cents, or 4.8%, to settle at $2.539 per million British thermal units. For the year, the contract is up 15.5%, its biggest yearly percentage rise since 2016. The US Energy Information Administration (EIA) said utilities pulled 114 billion cubic feet (bcf) of gas from storage during the week ended Dec. 25. That was less than the 125-bcf decline analysts forecast in a Reuters poll and compares with a decrease of 87 bcf during the same week last year and a five-year (2015-19) average withdrawal of 102 bcf. "While demand is not expected to change much over the next few days, lower supply and the potential for a colder second half of January is giving the market a lift (today)," said Robert DiDona of Energy Ventures Analysis. Data provider Refinitiv estimated 381 heating degree days (HDDs) over the next two weeks in the Lower 48 US states, up from Tuesday's forecast of 371 HDDs. The normal is 461 HDDs for this time of year. HDDs measure the number of degrees a day's average temperature is below 65 degrees Fahrenheit (18 degrees Celsius). The measure is used to estimate demand to heat homes and businesses. "Couple that insight with today being the last trading day of 2020 and we are seeing increased volatility early in the session," DiDona added. However, Refinitiv projected average demand, including exports, would slip from 123.0 billion cubic feet per day (bcfd) this week to 117.8 bcfd next week. The amount of gas flowing to US LNG export plants, meanwhile, has averaged 10.7 bcfd in December, which would top November's 9.8 bcfd record as rising prices in Europe and Asia in recent months have prompted global buyers to buy more US gas. Output in the Lower 48 has averaged 91.1 billion bcfd in December. That compares with a seven-month high of 91.1 bcfd in November 2020 and an all-time monthly high of 95.4 bcfd in November 2019./p>
LNG Market Readies for Swift Recovery-- Liquefied natural gas traders anticipate a swift demand recovery in 2021 after a year in which the coronavirus pandemic prompted dramatic price swings. Colder weather in key importing nations, outages at major production hubs and congestion along global shipping routes already have combined to push spot prices in Asia to the highest level since 2014. That’s a more than sixfold jump from a record low in April, making Asian LNG the best performer among major commodities in 2020. Demand for the fuel used in heating and power generation is growing faster than for any other fossil fuel as nations look for a cheap, reliable and cleaner alternative to coal. The pandemic derailed that growth for 2020, but China and India are emerging as major sources of demand. “A lot of countries are looking to import LNG,” “I still think we are going to see growth in the LNG market.” Below are the key areas likely to shape the market in 2021: Global LNG imports in 2020 were roughly equal to the previous year, according to ship-tracking data compiled by Bloomberg. That was a big disappointment for an industry that has enjoyed 10% annual growth rate since 2016. However, global gas demand is expected to resume growth next year. LNG demand, which makes up roughly 10% of the total, may rebound even faster, depending on how Pakistan, India and Bangladesh perform, Shipments of the fuel into Asia have mostly recovered since the height of the pandemic, and the region’s LNG demand will rebound sharply next year, according to S&P Global Platts. On the last day of 2020, spot Asian LNG price - the Japan-Korea Marker benchmark - rallied above $15 per million British thermal units for the first time since April 2014. “It has been interesting to see how quickly Asian demand seems to have ramped up,” The picture in Europe is very different as countries grapple with a new surge of infections and lockdowns that sap energy demand. The continent is headed for a “very neutral recovery” in 2021, according to Satapathy. Europe mainly relies on storage and pipeline gas shipments, which may be boosted with flows from a new link from Azerbaijan and the controversial Nord Stream 2 project that’s nearing completion. Unplanned maintenance at LNG export facilities from Australia to Qatar to Malaysia has led to a tighter than expected market in the second half of the year. And delays in navigating the Panama Canal curbed supplies to Asia. If these disruptions persist well into the year, then prices could remain elevated well above current levels.
How The Fracking Revolution Is Killing the U.S. Oil and Gas Industry -After over a decade of the much-hyped U.S. fracking miracle, the U.S. oil and gas industry is having to deal with years of losses and falling asset values which has dealt the industry a serious financial blow. This is despite the fracking revolution delivering record oil and gas production for the past decade, peaking in 2019. While the pandemic has hurt the industry, companies have also benefited from excessive bailoutsfrom pandemic relief programs but these bailouts are a stop gap financial band-aid for the struggling industry.The oil and gas industry has always required huge amounts of money to explore for and produce oil and gas but up until now the industry made returns on those investmentsThe industry made a huge bet on fracking shale deposits to unleash the oil and gas reserves in that shale. It worked from a production standpoint; the industry produced record amounts of oil and gas. The difference is that, unlike traditional oil and gas production, the cost to produce fracked oil and gas was more than what the market was willing to pay for it.As a result, the U.S. fracking industry has lost over $300 billion. Fracking was supposed to be the future of the U.S. oil and gas industry — instead it has dealt the industry a major financial blow which has likely sped up the energy transition away from oil and gas towards a lower carbon future.In April 2018, while many were predicting a bright financial future for the U.S.fracking industry, DeSmog started a series on the finances of the fracking industry with the article, The Secret of the Great American Fracking Bubble. This article highlighted the huge losses by the U.S. fracking industry, which were around a quarter trillion dollars at the time.More than two years later the Washington Post ran an article on “Shale’s Bust” and updated the losses to-date to be $300 billion — noting that while the pandemic made things worse, “the sector’s weaknesses extend back many years.”In late 2019, before the pandemic hit, Chevron wrote off $11 billion, the majority of which was related to gas fracking assets.This trend continued in the industry in 2020 with historic write-downs of the industry’s remaining fracking assets, and in June, accounting firm Deloitte estimated the industry could soon write off $300 billion more. This is what the fracking revolution has done to the U.S. oil and gas industry: financial devastation.
Texas fracking billionaires drew Covid-19 aid while investing in rivals -As the coronavirus pandemic and low oil prices walloped US frackers this spring, Texas billionaires Dan and Farris Wilks got a $35 million relief loan to help one of their fracking companies stay afloat. At the same time, they were on a buying spree in the country’s oil patch.Since spring, businesses controlled by the Wilks brothers have hunted for deals among fracking firms going through bankruptcy and taken or increased stakes in at least six other companies, corporate filings show. But when it looked like the oil-and-gas industry would be shut out of a key pandemic lending program, they and others in the industry turned their attention to Washington, making an appeal for help in meetings with home-state senator Ted Cruz.The twin dynamics of acquisitions and government rescue show how the economic tumult caused by the pandemic has reshaped the landscape for a key US industry. But the industry was already under pressure from international competition and a sagging oil price by the time the pandemic hit, and its mounting woes prompted the Wilkses and others to turn to allies in Washington, including Mr. Cruz. The Republican senator helped convince the Trump administration and the Federal Reserve to change the rules for pandemic loans to ensure oil and gas firms could participate.Soon after the US government changed the rules of its lending program in April, a Wilks family company, ProFrac Holdings LLC, applied for and received a $35 million loan, federal records show. ProFrac, a supplier of pumping equipment and services, is just one slice of the sprawling portfolio of fracking businesses that the Wilks family owns in part or outright across the American West and Canada.The Wilks brothers are longtime financial backers of Mr. Cruz. The brothers donated $15 million to a super PAC called Keeping the Promise that championed Mr. Cruz’s 2016 presidential campaign, making them the largest financial backers of his political career. BailoutWatch, a nonprofit group that tracks pandemic aid to industry, said Mr. Cruz’s efforts to get relief for the oil-and-gas industry amount to a reward for a campaign contributor.“ProFrac’s loan is blatant misappropriation of taxpayer dollars," said Chris Kuveke, an analyst for the organization, which has received funding from Climate Nexus, a group that advocates for clean energy. He said Mr. Cruz’s biggest political benefactors ended up receiving one of the relief program’s largest loans to the fossil-fuel industry. “It’s hard not to connect the dots."
Ted Cruz helped Texas fracking billionaires reap millions in COVID-19 aid relief: report - According to a report from the Wall Street Journal, Sen. Ted Cruz (R-TX) lent a helping hand to two Texas fracking billionaires by asking for changes to rules that would allow them to acquire a $35 million COVID-19 relief loan aimed at helping struggling businesses stay afloat. The report notes that Texas billionaires Dan and Farris Wilks were on a buying spree as the coronavirus pandemic spread across the country -- buying up bankrupt competitors and investing in others -- only to find they were prohibited from taking advantage of the government-backed loan program as one of their many companies struggled. According to the Journal, they then reached out to Cruz for help. "Since spring, businesses controlled by the Wilks brothers have hunted for deals among fracking firms going through bankruptcy and taken or increased stakes in at least six other companies, corporate filings show,": the Journal's Ted Mann and Brody Mullins reported before adding, "But the industry was already under pressure from international competition and a sagging oil price by the time the pandemic hit, and its mounting woes prompted the Wilkses and others to turn to allies in Washington, including Mr. Cruz. The Republican senator helped convince the Trump administration and the Federal Reserve to change the rules for pandemic loans to ensure oil and gas firms could participate." The report goes on to note that the changes Cruz asked for quickly allowed the wealthy Texas oilmen to cash in. "Soon after the U.S. government changed the rules of its lending program in April, a Wilks family company, ProFrac Holdings LLC, applied for and received a $35 million loan, federal records show," the report notes before adding, "The Wilks brothers are longtime financial backers of Mr. Cruz. The brothers donated $15 million to a super PAC called Keeping the Promise that championed Mr. Cruz's 2016 presidential campaign, making them the largest financial backers of his political career."
Texas Deepwater Oil Terminal Achieves VLCC Milestone --Buckeye Partners reported Wednesday that crude oil export operations have begun at the second deepwater dock at its South Texas Gateway (STG) Terminal, which sits at the mouth of the Corpus Christi Ship Channel.The company pointed out in a written statement emailed to Rigzone that the new dock enables the Ingleside, Texas, facility to accommodate the berthing and loading of two vessels simultaneously. Moreover, it stated that STG has loaded its first very large crude carrier (VLCC) tanker with crude oil for export. “ “STG’s new terminal, alongside our nearby Buckeye Texas Partners facility, will be instrumental in providing our customers with cutting-edge logistics solutions and in reinforcing the role of the Port of Corpus Christi as a top export location for U.S. energy producers.”With the exception of final construction of storage facilities that will conclude during the first quarter of 2021, STG’s marine facilities are now fully operational and can safely and efficiency load up to VLCC-sized vessels, Buckeye stated. Upon completion, STG will boast 8.6 million barrels of petroleum products storage capacity – expandable to 10 million barrels – and throughput capacity of up to 800,000 barrels per day via its two deepwater docks, the company added. “The completion of the second dock and loading of its first VLCC cargo at the STG Terminal are significant milestones for Buckeye and the Port of Corpus Christi,” commented Sean Strawbridge, the port’s CEO. “As Texas moves into the next phase of economic recovery from the COVID-19 pandemic, partnerships like those between the Port of Corpus Christi and its customers such as STG are critical to the continuance of American leadership in the global energy marketplace.” Buckeye Partners owns a 50-percent stake in STG and operates the joint venture. Its co-venturers, each of which holds a 25-percent interest, include Phillips 66 Partners and Marathon Petroleum Corp.
Vandalism string leaves thousands in Colorado without heat, hot water - A natural gas company is working to restore service to thousands of customers in Colorado following vandalism that damaged lines and forced gas to be shut off, leaving residents without heat and hot water. According to a statement Monday from Black Hills Energy's vice president of operations, Vance Crocker, crews were working to bring more than 3,500 gas meters in Aspen back online, a process that “requires several steps."“We must first make sure all gas meters are off, then purge the system so it’s ready for the reintroduction of the natural gas supply,” Crocker added. “Finally, our technicians will go door-to-door and relight each customer’s gas appliances.”According to NBC’s Denver affiliate KUSA, Crocker said during a community meeting Monday that the process of restoring gas lines was expected to go into Tuesday, with 150 technicians deployed to work on the issue and 4,000 heaters being distributed during repairs. The Aspen Times reported that gas lines across the city were found damaged, with the name of environmental advocacy organization Earth First! written on one pipe at one of three Black Hills Energy sites vandalized.It was not clear as of Monday whether the organization’s members were directly involved in the damages, according to the Aspen newspaper. “They would have had to have some familiarity with the system” to carry out the sabotage, Bill Linn, Aspen assistant police chief, said Monday. “They tampered with flow lines. They turned off gas lines,” he continued. Linn added that police have not received any communication from Earth First! in response to the damages. In Monday’s community meeting,Aspen Police Chief Richard Pryor said that a multijurisdictional investigation was being carried out to determine who was behind the vandalism and how they were able to carry it out. Linn said Monday that the FBI was assisting local detectives in the investigation, as well as state law enforcement officials, according to the Times. Pitkin County Commissioner Patti Clapper, who was without heat Monday at her Smuggler Mountain-area home, called the vandalism "an act of terrorism." “It’s trying to destroy a mountain community at the height of the holiday season,” Clapper continued, the Times reported. “This wasn’t a national gas glitch. This was a purposeful act.”
Colorado Officials to Ramp Up Ozone Controls on Natural Gas, Oil Industry - Colorado officials have agreed to enact more stringent regulations on ozone emissions from sectors including oil and natural gas at the instruction of Gov. Jared Polis. The commitment follows a review of air quality data from 2018-2020 which showed that despite a downward trend in ozone concentrations, the Denver Metropolitan/North Front Range (DMNFR) area remains a trouble spot for ground-level ozone, the main component of smog. The area is likely to receive a status downgrade under the ground-level ozone standards outlined in the Clean Air Act (CAA), Polis said in a Dec. 15 letter to the Colorado Air Quality Control Commission (AQCC). The DMNFR area currently is in serious nonattainment status for the 75 parts per billion (ppb) standard, with an attainment date scheduled by July 2021. Based on the review, “it is apparent that the DMNFR area will not meet the standard in time for the attainment date, even excluding the days of high pollution from wildfires in Colorado in 2020,” said Polis. “As a result, state agencies and stakeholders should plan for the downgrade of the DMNFR nonattainment area to a severe status following the attainment deadline…” Polis said Colorado will not seek a waiver for the downgrade, despite an option in the CAA to show that ozone exceedances are caused by international emissions. Economic impacts of the downgrade will include “a requirement for federal reformulated gasoline in the nonattainment area during the summer months,” Polis said. “The state is concerned about the potential costs, as well as the limited environmental benefits of this requirement.” As a result, Polis said he has asked the state’s Department of Public Health and Environment (DPHE), the Energy Office and the Department of Transportation “to explore other options both for more effective and cost-effective means of reducing emissions.”
U.S. Upstream Partnership Unveils New Natural Gas Flaring Program Focused on Reduction, Best Practices - The U.S. oil and gas industry faced a unique set of challenges this year but it did not deter the Environmental Partnership from making strides to reduce natural gas flaring in upstream operations. The 80-plus members, which together represent more than 70% of total oil and gas production in the Lower 48, launched its latest performance program to expand on their core mission to reduce gas flaring. The group, which recently added midstream operators, encourages companies of all sizes to join. Members share information on best practices, advance technologies and foster collaboration to reduce emissions and collect data to help minimize flaring. “Despite the challenges this year, the Environmental Partnership continues to grow and advance innovative solutions for a cleaner future,” Director Matthew Todd said. “This commitment to reduce flaring builds on the industry’s progress in reducing methane emissions and is the latest example of how companies are constantly innovating to improve environmental performance while delivering affordable, reliable energy around the world.” As part of the new program announced earlier this month, members plan to advance best practices, promote the beneficial use of associated gas and improve flare reliability and efficiency when it occurs. Flaring typically is used by producers when there is a lack of gas gathering lines or processing capacity, as well as during maintenance activities. It sometimes is used for unplanned events as a safety measure to alleviate pressure. In these instances, flaring is considered the safer environmental option. Rather than venting the gas into the air, flaring burns the gas, which releases fewer emissions than venting.To gauge progress each year, participants of the partnership’s Flare Management Program have committed to report data to calculate flare intensity, a measurement of volumes relative to production. The program would analyze and aggregate the data for an annual report and use the insights from the participant’s combined actions and reporting to identify opportunities to further reduce flaring.
FERC Clears Kenai LNG Terminal in Alaska for Imports - FERC has approved a Marathon Petroleum Corp. subsidiary’s request to convert the Kenai liquefied natural gas (LNG) export terminal in Alaska to import operations. Trans-Foreland Pipeline Co. LLC filed an application to import natural gas earlier this year at the terminal in Nikiski on the Kenai Peninsula. The facility began operating in 1969 and for more than 40 years was the only LNG export terminal in North America. Kenai has a liquefaction capacity of 200 MMcf/d, but the plant hasn’t exported LNG since 2015. It’s been idled since Marathon acquired it from ConocoPhillips in 2018. Trans-Foreland wants to construct new facilities, return two 35,000 cubic meter storage tanks and other equipment to service to import up to four vessel loads of LNG annually. The company plans to apply for import approval with the U.S. Department of Energy a month before the conversion project enters service. The import terminal would have the capacity to take in 1.825 MMBtu of natural gas each year for delivery to Marathon’s Kenai Refinery on the Cook Inlet, 60 miles southwest of Anchorage, AK. The refinery processes mainly Alaska domestic crude to manufacture gasoline, distillates, heavy fuel oil, asphalt and propane. The Federal Energy Regulatory Commission found the conversion project is in the public’s interest and would not significantly impact the environment. The project must be constructed and put into service within two years, according to FERC’s order authorizing the project. Commissioner Richard Glick dissented from the order as he has repeatedly since joining FERC in 2017, saying the Commission “is again refusing to consider the consequences its actions have for climate change.”
U.S. crude output drops in October as demand falls further (Reuters) -U.S. crude oil production was down more than 2 million barrels per day (bpd) in October from earlier this year, as weak prices and tepid demand due to the coronavirus pandemic weighed on output, a government report showed on Thursday. The report suggested that crude demand in the world’s largest economy remained below the highs of earlier this year, and production was largely flat since cuts began in the spring. Total U.S. oil demand in October was down by 2.15 million bpd, or more than 10% below the same month a year earlier. The decline was sharper than the 9.5% seen in September. Output has fallen from a record-high monthly average of 12.86 million bpd in November, 2019. Production dropped sharply in May as low demand and prices forced widespread drilling cuts. Oil output dropped by 442,000 barrels per day to 10.42 million bpd in October, the latest month for which data was available. The losses were led by declines in the offshore U.S. Gulf of Mexico, according to the Energy Information Administration report. Storms that month caused offshore production shut-ins, contributing to the losses. Still, even without the Gulf declines, production remained below pre-pandemic levels. Top onshore producers Texas and North Dakota reported modest gains in the month as some producers brought into production wells that had been shut, as prices improved. Meanwhile, U.S. natural gas production for October was 99,568 million cubic feet a day, down from 100,221 in September.
Baker Hughes Posts Gain in US Rig Count -The total number of rotary drilling rigs operating in the United States increased by three this week to hit 351, Baker Hughes Co. (NYSE: BKR) reported Wednesday. The service company’s latest U.S. rig count reflects a three-unit gain in oil rigs (to 267) and no change in gas rigs, which stood at 83 again this week. Also, the miscellaneous rig figure held steady at one unit. Against the year-ago figure of 796, the latest total U.S. rig count is down 445 drilling units, Baker Hughes continued. It pointed out that oil rigs are down 403, gas rigs are down 40 and miscellaneous rigs are down two. Baker Hughes added the U.S. offshore rig count remained flat at 17 this week, compared to 22 this time last year. Canada’s fleet of operating drilling units plunged by 23 this week, bringing the country’s total to 59. The most recent figures comprise 18 oil rigs (down 13 from last week) and 41 gas rigs (down 10), Baker Hughes noted. At this time last year, 85 rigs (27 oil and 58 gas) were operating in Canada, the firm added.
Exxon Signals 4th Consecutive Loss-- Exxon Mobil Corp., which is struggling to maintain a $15 billion-a-year dividend program, indicated it incurred a fourth straight quarterly loss. Exxon confirmed in a filing Wednesday it will take a writedown of as much as $20 billion on its upstream assets, a possibility first disclosed at the end of October. It also reported much smaller non-cash impairments related to its refining business. There were some positives. Higher oil and gas prices had an impact of up to $1 billion on upstream profits compared with the third quarter. The chemicals segment saw an earnings boost of as much as $400 million due to improved margins. Exxon’s shares were little changed in after-hours trading in New York. Still, a fourth-quarter loss would confirm Exxon’s challenges in covering both dividends and capital expenditures from operational cash flow, and remains reliant on debt. The last time the Irving, Texas-based company generated enough free cash to cover its payout was the third quarter of 2018, according to data compiled by Bloomberg. Exxon is set to disclose its full quarterly results on Feb. 2, amid one of the most-punishing periods in the company’s 150-year history. Its stock cratered to a 22-year low during 2020 amid a worldwide glut of oil and collapsing demand that gutted cash flow, spurring widespread job cuts. Exxon was kicked out of the Dow Jones Industrial Average, warned it will incur the biggest writedown of its modern history, and was assailed by activist investors seeking better returns and more climate accountability. Exxon, which has long prided itself on its decades-long record of annual dividend increases, may have opened the door to changing course in late November, according to Cowen & Co. analyst Jason Gabelman. Whereas company executives touted Exxon’s “reliable and growing dividend” during an October conference call, a Nov. 30 statement announcing writedowns and spending cuts only mentioned its commitment to a “reliable” payout, Gabelman said in a note to clients.
Trans Mountain Pipeline Detour to Increase Construction Costs An extra C$20 million ($15 million) has been added to construction costs of the Trans Mountain Pipeline expansion for a detour around a southern British Columbia (BC) native tribe, according to evidence before the Canada Energy Regulator (CER). The oil pipeline’s route change raises the expense of steering the project past the Coldwater Indian Band to C$70 million ($52.5 million) from C$50 million ($37.5 million), Trans Mountain disclosed in a reply to a CER information request. The extra bill is a relatively small addition to the total cost of expanding Trans Mountain as an export route for Canada’s top natural gas user, Alberta thermal oilsands production. The added expense of the Coldwater detour is just 1.6% of the C$12.6 billion ($9.4 billion) current estimate for nearly tripling capacity to 890,000 b/d on the pipeline from Alberta to a tanker port in Vancouver Harbor. The detour, now going through the CER approval process, would settle a seven-year feud over the project route. Coldwater fought the original plan to use the established right-of-way along the east side of its reservation as a threat to the tribal water supply. The proposed settlement, a new right-of-way west of the reservation, emerged after the pipeline and tribal chiefs agreed to stop butting heads and engage in a meeting of the minds, according to Trans Mountain’s CER application for the detour. “Since May of this year, Trans Mountain president and CEO Ian Anderson has been meeting regularly with Chief Lee Spahan of Coldwater, attempting to reach consensus on routing,” the application said. “In early October, Coldwater confirmed that the west alternative route for the TMEP [Trans Mountain expansion project] addresses its concerns regarding potential impacts to the aquifer used by the Coldwater community.” In addition to written support from Coldwater and seven other southern BC tribes, the detour has won a favor from the owner of the pipeline, Canada’s federal government. Natural Resources Canada has served notice that it will refrain from using its authority under the Canada Energy Regulator Act to require time-consuming cabinet review of any CER detour approval and possibly add conditions. The federal ministry’s decision not to interfere enables Trans Mountain to hit a detour construction start target of August 2021, in order to complete the full 1,150 (690-mile) project on schedule the following year. The only qualification of the detour consensus between Trans Mountain and the BC natives is that Coldwater says its continued support remains subject to engagement by the tribal leadership with its community. About four-fifths of the 18.3-kilometer (11-mile) detour crosses provincially owned BC public land. The provincial government has not intervened in the approval case to date. The BC Oil and Gas Commission controls construction permits on the provincial property.
Supply Crunch, Brexit Deal Push Global Gas Prices Higher — LNG Recap -Global natural gas prices remain strong coming off a week shortened by Christmas and heading into another with limited trading activity as the New Year holiday nears. The Dutch Title Transfer Facility (TTF) contract for February delivery finished the short week on Thursday at $6.321/MMBtu, while the UK’s National Balancing Point finished at $7.015 and the Japan Korea Marker prompt month contract kept climbing to finish at $11.000. TTF traded near two-year highs after the Christmas holiday on colder weather and optimism over a Christmas Eve Brexit deal in which terms were finally reached over trade and other issues for the UK to leave the European Union (EU). European prices climbed higher Monday. In North Asia, spot prices for February delivery remain above $13.00 as bids support the mark on cold weather and a supply crunch.Meanwhile, in the United States, front-month Henry Hub finished lower last week at $2.512 as milder temperatures forecast over the next two weeks are seen dragging down heating demand. The U.S. benchmark fell again on Monday, with the January contract falling to $2.305 before expiring. “January is normally one of the highest demand months of the year for natural gas, driven primarily by heating demand, so mild weather next month would be quite bearish for prices,” said Schneider Electric analyst Christin Redmond of the U.S. natural gas market. “The current weather outlooks have traders so confident about winter supply that the remainder of the winter strip is now trading at a discount to the 2021 summer strip.”As Henry Hub prices fall and overseas benchmarks move upward, the arbitrage window for U.S. LNG deliveries remains wide open, particularly to Asia. According to NGI data, the spread between the Gulf Coast and the Asian market was at $7.429 on Christmas Eve, well above the $6.304 spread recorded on the same day a week earlier. As a result, U.S. feed gas deliveries remain at or near capacity and stood over 11 Bcf/d on Monday. The shipping market continues to remain tight as it has since colder weather set in across the Northern Hemisphere in recent weeks. Shipbroker Braemar ACM said that vessel rates were up by more than 35% across three different classes of LNG carriers between November and December. Spot vessel rates haven’t budged and were at $180,000/day in the Atlantic Basin, where demand remains elevated to capture particularly strong winter spreads to Asia, and $170,000/day in the Pacific Basin.
LNG Shipbuilders See Influx of Orders as Year Comes to an End - Two of Asia’s leading shipbuilders saw an influx of orders for new liquefied natural gas (LNG) carriers this month, capping an otherwise slow year for newbuilds. Korea Shipbuilding & Offshore Engineering said in a regulatory filing last week that it landed various contracts to build nine LNG carriers. KSOE is scheduled to deliver one vessel to a Panamanian shipping company in 2024, while another two ships will be delivered to a buyer in Bermuda in 2023. KSOE subsidiary Hyundai Samho Heavy Industries will build the ships. KSOE announced other deals earlier last week to build six more LNG vessels for two undisclosed companies. In another deal, Samsung Heavy Industries Co. Ltd said it signed a contract with an African owner that’s worth more than $700 million for four LNG carriers that are expected to be delivered in 2024, according to a regulatory filing. Despite the late surge in orders, it’s been a slow year for new LNG vessels as the Covid-19 pandemic has impacted the global economy and the natural gas trade. According to shipbroker Braemar ACM, just 19 vessels in the large conventional class with sizes of 160,000-190,000 cubic meters have been ordered this year. Vessels of that size have become more common as global supplies of LNG have increased. Last year, owners ordered 67 vessels in that class, Braemar said. Activity in the global LNG trade slowed this year as the pandemic took a bite out of energy demand. But trading has increased with colder weather, which has strained vessel availability with only so many on the water at one time.Increased U.S. LNG exports to Asia this winter have driven vessel spot charter rates to two-year highs. Spot vessel rates on Tuesday were at $180,000/day in the Atlantic Basin and $170,000/day in the Pacific Basin, according to NGI data provided by Fearnleys. Japan Korea Marker prices have reached levels not seen in years, with spot deals assessed at over $13.00/MMBtu in early February. Stronger prices have lifted the February arbitrage spread between the Gulf Coast and Asia to $7.725 for those with vessels chartered and to $5.312 for those who need to secure a vessel.
Troops Fight Off Attack Near $20B LNG Project -- Mozambique said its security forces repelled an attack by Islamist insurgents on a town close to the site where Total SE is building a $20 billion natural gas facility. The attack took place about 21 kilometers (13 miles) from Total’s project overnight on Wednesday, according to a statement from the Ministry of Defense, and is the second this month on the town of Mute in the northern Cabo Delgado province. It accused the militants of trying to derail the investment. Fighters who’ve aligned with Islamic State in August have already seized the port town of Mocimboa da Praia, about 42 kilometers south of Mute, raising the stakes in a conflict that’s killed about 2,500 people and caused 570,000 to flee their homes since it started three years ago. Mozambique’s government has struggled to contain the insurgency and President Filipe Nyusi has faced criticism for refusing outside help. Leaders from the Southern African Development Community are set to meet in January to agree on a plan to prevent the conflict from spilling across Mozambique’s borders.
As 2020 Ends, Door Remains Closed to New Oil and Gas E&P Contracts in Mexico - As 2020 draws to a close, the door remains closed for new exploration and production (E&P) contracts in Mexico’s oil and gas sector, with little visibility as to when they might resume. With bid rounds, farmout tenders and service contract migrations frozen until further notice by President Andrés Manuel López Obrador, upstream activity will in the meantime be limited to state oil company Petróleos Mexicanos (Pemex) and the 111 E&P contracts awarded from 2015-2018 under the previous government following the 2013-2014 market-opening energy reform. A recently published five-year plan for oil and gas auctions published by energy ministry Sener offered some hope that bid rounds may return, although Sener may have just released the document in order to comply with the law, according to analysts at Talanza Energy Consulting. The reform’s mechanisms for awarding new upstream contracts remains halted despite dire financial circumstances facing Pemex. In a decree published Monday in Mexico’s federal register, López Obrador authorized the deferral until January 7 of production-sharing duties owed to the government by Pemex that were supposed to be paid in November. The relief was not extended to private sector operators, whom López Obrador has antagonized since taking office in December 2018. To justify the extension, López Obrador cited the unexpected decline of Mexico’s crude oil export basket price due to the destruction of global oil demand caused by the Covid-19 pandemic. The basket price averaged $38.07/bbl in the third quarter, down 29.6% year/year. The deferral follows legislation introduced in December by Senator Armando Guadiana that would see Pemex’s profit-sharing duty reduced to 35% from the current effective rate of 58%. However, even if the tax break is approved, Pemex will likely require additional government support in order to increase capital spending without taking on more debt, Fitch Ratings analysts said recently. Pemex’s total financial debt stood at $110.3 billion as of September 30, up 24.9% from year-end 2019. Pemex said the increase was “mainly due to the drawn amounts from credit facilities and the depreciation of the Mexican peso against the U.S. dollar during the period.”
New Fuel Permit Rules in Mexico Said Damaging to Energy Sector Competition - New regulation over the permitting process involved in the importing and exporting of fuels in Mexico published in the country’s Official Gazette on Dec. 26 could prove harmful to competition in the Mexican energy sector. petroleum trade Mexico’s Comisión Federal de Competencia Económica (Cofece), the federal economic competition commission, published a statement last week warning the rules would “seriously hamper competition and free markets in the commercialization of petroleum products, and would affect consumer access to supply options at the best possible prices.” Still, Mexico’s Energy Ministry (Sener) made the requirements for permits official over the holiday weekend. Read the details, in Spanish, here. One of the major changes in the published rules is the reduction in duration of refined fuel permits for private sector companies to five years, from twenty years. This reduces incentives to invest in long term transportation and storage infrastructure, Cofece alleges. The bill also establishes unclear and burdensome requirements for requesting permits and grants wide discretion to Sener in their ability to revoke them. It turns the granting of permits into “a public policy instrument” to control the makeup of the energy sector. In sum, the rules would essentially hand Petróleos Mexicanos (Pemex) a more dominant monopoly position in the marketing of refined fuels within Mexico, according to Cofece.
Argentina Natural Gas Production Down 13% in October - Natural gas production in Argentina fell by 12.9% year/year in October to 121.9 million cubic meters/day (MMm3/d), or 4.3 Bcf/d, according to the latest report by the IAE Argentine Energy Institute. Production was down from 4.37 Bcf/d in September. Analysts attributed the drop to restrictions in place because of the coronavirus pandemic. Argentina has had one of the strictest lockdowns in place globally since the pandemic began to spread in March. In November, executives at Argentina’s state energy firm Yacimientos PetrolÃferos Fiscales SA (YPF) said their oil and gas fields were starting to return to work after the complete shutdown in April that became “the worst” month in the company’s history. YPF shale production in the Vaca Muerta formation has returned to pre-Covid levels, the executive said, as wells have come back online at the flagship Loma Campana field. Power demand on Argentina’s national grid was down 6.6% year/year in October at 323 GWh/day. Gas production was down in October in Neuquén, home to most of Vaca Muerta. Neuquén, the largest gas-producing province in Argentina, saw production fall 16.3% year/year to 2.61 Bcf/d in October. Natural gas production in Neuquén was 2.65 Bcf/d in September. Production from Vaca Muerta in October fell to 1.06 Bcf/d, from 1.25 Bcf/d in October 2019. Meanwhile, the national government handed out 23 contracts in its natural gas plan ‘Plan Gas 4’ in mid-December. Winning companies included YPF, Tecpetrol SA and Pampa Energia SA.
Russian Gas Gets New Rival in Europe -- Azerbaijan started commercial natural gas exports to Europe via the U.S.-backed Southern Gas Corridor, helping the region to diversify supplies away from Russia. Gas pumped from the BP Plc-led Shah Deniz deposit in the Caspian Sea began flowing into Italy, Greece and Bulgaria on Thursday, BP and Azerbaijan’s state energy company Socar said in a joint statement. The European Union has worked for years to ease its dependence on Russia, which accounts for about a third of the region’s gas supplies. The Southern Gas Corridor, which took $33 billion and seven years to build, includes the Shah Deniz field and more than 2,000 miles of pipelines connecting the Caspian Sea with Europe via Georgia and Turkey. Azerbaijan will ship 10 billion cubic meters of gas to Europe every year over the next quarter-century, with 8 billion of that going to Italy and 1 billion each to Greece and Bulgaria. “Some people were skeptical about the project” at the outset, Socar President Rovnaq Abdullayev said. “Now the mission is accomplished. Azerbaijan’s natural gas has arrived in Europe.” Shah Deniz, which means King of the Sea in Azeri, is the nation’s largest gas deposit, containing about 1 trillion cubic meters of the fuel and 2 billion barrels of condensate, according to BP estimates. Azerbaijan plans to ship gas to more countries in Europe in the future as additional Caspian Sea fields start production. BP leads Shah Deniz with a 28.8% interest. Other partners in the project include Socar, Turkiye Petrolleri AO, Petroliam Nasional Bhd, Lukoil PJSC and a unit of Iran’s national oil company.
Russian annual oil output falls for the first time since 2008 on OPEC+ deal, pandemic(Reuters) - Oil production in Russia declined last year for the first time since 2008 and reached its lowest level since 2011 following a global deal to cut output and sluggish demand caused by the coronavirus, statistics showed on Saturday. Russian oil and gas condensate output declined to 10.27 million barrels per day (bpd) last year, according to energy ministry data cited by the Interfax news agency. In tonnes, oil and gas condensate output dropped to 512.68 million in 2020 from a post-Soviet record-high of 560.2 million, or 11.25 million bpd, in 2019. The sharp decline was almost in line with expectations. The 512.68 million tonnes reading for 2020 was the lowest since 511.43 million tonnes in 2011, and the first annualised decline since 2008 amid the global financial crisis and falling oil prices. Russia agreed to reduce its oil production in April last year by more than 2 million barrels per day, an unprecedented voluntary cut, along with other leading oil producers and the Organization of the Petroleum Exporting Countries (OPEC). The move was designed to bolster the oil market beset by the fallout from the COVID-19 pandemic. Since the April agreement, a record for global supply reductions, the group known as OPEC+ has progressively reduced the cuts and is expected to release an extra 500,000 bpd into the market in January. OPEC+ is due to hold its next summit on Monday, Jan. 4. Russia has been expected to increase its oil output by 125,000 bpd from the New Year. Russian Deputy Prime Minister Alexander Novak, in charge of Moscow’s ties with OPEC+, has said Russia would support a gradual increase of the group’s output by another 500,000 bpd starting in February.
Petrobras Makes Oil Find - Petrobras announced Tuesday that it has confirmed oil of “excellent quality” at well 9-BUZ-48D-RJS, which is located in the extreme northwest of the Buzios field in the Santos Basin. Situated 116 miles from Rio de Janeiro, the well was drilled at a water depth of 6,069 feet. Tests carried out from a depth of 18,175 feet confirmed the presence of an oil reservoir of “excellent quality”, according to Petrobras, which said the discovery reinforces the potential of the pre-salt in the Buzios field. Petrobras is the operator of the Buzios field consortium with a 90 percent interest. CNOOC holds a five percent stake in the project and CNODC holds the remaining five percent interest. In April this year, Petrobras announced that it had identified the presence of oil in an exploratory well located in the Campos Basin. The well, informally called Natator, is located 80 miles from Macae, in water depths of 3,543 feet. During the same month, the company revealed that it had identified the presence of oil in the pioneer well of the Uirapuru block, which is located in the Santos Basin pre-salt. The Santos Basin is the largest offshore sedimentary basin in Brazil, covering total area of over 135,000 square miles, all the way from Cabo Frio to Florianopolis, Petrobras’ website highlights, adding that the first investments in exploration and production studies for this basin date back to the 1970s.
Eni Finds Oil in Egypt Desert - Eni has announced a new oil discovery in the Meleiha Concession in the Western Desert of Egypt. Achieved through the Arcadia 9 well on the Arcadia South structure, the find is located a mile south of the main Arcadia field already in production. The well was said to have encountered an 85 foot oil column in the Cretaceous sandstones of the Alam El Bueib 3G formation. Arcadia 9 has registered a stabilized rate of 5,500 barrels of oil per day, Eni revealed. Following the discovery, two development wells, Arcadia 10 and Arcadia 11, were drilled back to back. The first one encountered a 25 foot oil column and the second one an 80 foot oil column within the Alam El Bueib 3G formation. The three wells share the same oil-water contact in the discovered reservoir, Eni highlighted. Arcadia 11 was also said to have encountered 20 feet of oil pay in the overlying Alam El Bueib 3D formation. Through its subsidiary Ieoc, Eni holds a 38 percent interest in the Meleiha concession. Lukoil holds a 12 percent stake and EGPC holds the remaining 50 percent interest. Eni has been present in Egypt since 1954 and is the country’s main producer. The company’s current equity hydrocarbon production is said to be around 320,000 barrels of oil equivalent per day.
India - NIO, NPC sign MoU on oil spill management-The Goa-based National Institute of Oceanography has signed a memorandum of understanding with New Delhi-based National Productivity Council (NPC) to jointly work in the areas of climate change, environment-related data analytics, combating oil spills, and exploration of renewable energy, a statement said on Saturday."The aim of this MoU is primarily to develop a long-term joint working partnership in the areas of environment management, climate resilience in coastal zones and communities, oceanographic data analytics, environmental impact studies and modelling to predict environmental impact, besides identifying remedial and mitigation measures and contributing to policy research," the statement said.The NIO, which functions under the aegis of the Council for Scientific and Industrial Research, and the NPC, an arm of the central government's Department for Promotion of Industry and Internal Trade, will also focus on assessment of macro and microplastics in the country's rivers, seas and other marine bodies.The two organisations will also jointly carry out "oceanographic modeling and data analytics pertaining to environmental factors and pollutants and related impact assessments in Coastal Regulatory Zone, marine environment and forecasting". Preparation of emergency plans and conducting risk analysis related to oil spills as well as "periodic monitoring of environmental conditions and assessment studies prescribed for projects in CRZ, ports, harbours, etc" is also a part of the MoU.
Iraq aims to boost southern ports crude export capacity - - Iraq aims to increase crude oil export capacity from its southern ports to 6 million barrels per day from the current 3.5 million barrels a day capacity, Karim Hattab, deputy oil minister for distribution affairs said in a statement. Hattab said the increased capacity would be after 2023 and that the plan includes building 24 storage tanks.
Iraq plans to produce 6 mln b/d crude oil after 2023 - On Saturday, Iraqi deputy oil minister, Karim Hattab, said that they are planning to double the country’s crude oil production to 6 million barrels per day after 2023. In a statement, Hattab said”The goal is to implement large-scale projects, including the installation of another 24 tanks to increase export capacity from the current 3. 5 million to 6 million barrels per day after 2023,” Hattab was quoted by the ministry as saying during his inspection of oil storage facilities on the Al-Faw peninsula. According to Hattab, the ministry is also planning to build an offshore pipeline linking the Al-Faw storage facilities to ports that export oil. Last week, the ministry reported that Iraq’s oil output totaled 81 million barrels in November.
Iran slashes gas exports to Iraq, threatening electricity shortages -Iran has slashed the amount of natural gas it exports to Iraq and threatened further cutbacks over unpaid bills, increasing the likelihood of more electricity shortages in Baghdad and other major cities. Iraq has been receiving 5 million cubic meters a day since Iran cut its daily exports from 50 million cubic meters two weeks ago, Ahmed Moussa, a spokesman for Iraq’s electricity ministry, said in an interview. The Iranian government told Iraq it will reduce its supplies to 3 million cubic meters a day starting Sunday, but has not yet implemented the move, he added. Iran started cutting exports to its neighbor, which is OPEC’s second-biggest oil producer, after Iraq fell behind on its gas payments. Iraq owes around $2.7 billion in unpaid bills, Moussa said. Iranian Energy Minister Reza Ardakanian will meet Iraqi officials in Baghdad on Tuesday to discuss the issue, the spokesman said. Power production has dropped by around 7 gigawatts as a result of the gas supply curbs, Moussa said. Baghdad and other central locations have been hit hardest by electricity shortages. While Iraq’s supply of Iranian gas has been disrupted, its electricity imports have continued as normal, he added.
CHINA DATA: Nov crude imports from Oman hit fresh high at 1.25 mil b/d, up 33% on year | S&P Global Platts — China's imports of Oman crude oil surged 63.7% in November to a record high of 5.1 million mt, or 1.25 million b/d, from October, making the producer the third-biggest crude supplier in the month, data from the General Administration of Customs, or GAC, showed on Dec. 26. The previous high was at 4.16 million mt, or 983,101 b/d, in December 2019, GAC data showed. The volume brought imports from Oman at 36.2 million mt in January-November, jumping 21.9% year on year. Saudi Arabia returned to the top spot with a month-on-month increase of 42.8% in shipments delivered in November, at 8.48 million mt, or 2.07 million b/d. These led crude imports from the Middle East to jump 15.9% year on year at 5.19 million b/d over the January-November period to take 47.1% market share compared with 44.3% in the same period last year. Volume increase was also seen from North America, 137.7% on the year at 428,000 b/d in the period, making the region's market share gain 2.1 percentage points to 3.9% due to an 154.6% growth in US crude imports. Crude imports from the US rebounded 122.2% from October at 3.61 million mt, or 882,451 b/d, in November. The volume was 7% lower than the record high of 952,254 b/d imported in September. Imports from Africa and South America fell 14.6% and 8.8%, respectively, at 1.56 million b/d and 1.25 million b/d in January-November, GAC data showed. China's top crude suppliers ('000 mt):
China’s Energy Dependence To Grow Despite Major Oil Discoveries -- Energy independence is an important precondition for any country which allows for relatively unbound foreign and economic policies. China’s growing reliance on imports concerning fossil fuels is a major headache for Beijing. Therefore, increasing domestic production is high on the agenda. Despite some successes in exploration and production activities, import reliance is expected to rise over the next couple of years. Beijing has instructed its three domestic energy champions PetroChina, CNOOC, and Sinopec, to increase spending on domestic resources. In the next five years, these companies have vowed to invest 517 billion yuan ($77 billion), which is a growth of 18 percent year-on-year. These investments have already achieved reversing falling domestic oil production. According to the U.S. Energy Information Administration (EIA), the production of petroleum and other liquids in China has increased to 4.9 million barrels per day (mbpd). Despite the increase, foreign oil dependency has reached 70 percent and the number is expected to grow. Announcements of the discovery of new oil and gas fields are not a rare occasion in China these days. According to media group Netease, some 200 million tonnes (around 1.5 billion barrels) of oil and 300 million tonnes of gas have been discovered in November only. CNOOC has started using China's first domestically designed and produced self-operated large-scale deepwater rig and the world's largest oil and gas storage platform on the coast of Hainan. The company also made a significant discovery in the shallow waters of the Pearl River Mouth Basin. Due to growing investments, the Chinese energy sector is hitting new records this year. Despite these successes, the industry is facing an uphill battle due to insatiable domestic demand for oil. Stellar economic growth has led to a booming market for energy, but the level of reliance on fossil fuels is different. Dependence on coal is limited due to significant domestic production and gas has a moderate share in the national energy mix. Oil, however, is the biggest challenge.
Oil Trading Changing Forever After Wrong Virus Bet - In January, as a mysterious illness ripped through the Chinese city of Wuhan, global oil prices plunged. Two thousand miles away in the island state of Singapore, one of the most powerful men in the world of commodities trading, Lim Oon Kuin, quietly added to his vast stockpiles of fuel – making a bet that China would successfully control the spread of the new disease. That gamble soured quickly. While China did curb the coronavirus at home, the pandemic that followed brought crude oil prices tumbling as much as 70%. Banks tried to recover loans from Lim’s company, Hin Leong Trading Pte, triggering one of the biggest scandals in the oil industry this century. Lim’s empire collapsed, owing $3.5 billion to 23 banks, and the fallout from the debacle is still reverberating into 2021, shaking out large tracts of the vast and often opaque $4 trillion global oil-trading industry. The losers are likely to be the hundreds of small trading firms, many of them employing only a handful of people, who will find it expensive, if not impossible, to meet the increased demands for information from banks that have become wary of lending them money. Those gaining from the crisis are the big global trading houses such as Trafigura Group and Vitol SA, that retain the confidence of the finance companies and are better able to absorb the costs of increased oversight. A sign of those changes came earlier this month when banks in the major oil trading hub of Singapore issued new guidelines for financing that could curb some of the practices that led to the shock from Hin Leong, whose creditors, including HSBC Holdings Plc. and Singapore’s DBS Group Holdings Ltd., are still fighting to recover funds. Netherlands-based ABN Amro Bank NV has said it will pull out of commodity trade finance altogether, and others, including France’s BNP Paribas SA, said they were scaling back or reviewing their businesses. More than 20 veteran traders and industry bankers told Bloomberg News in interviews that financing for the industry is tightening, with the contraction likely to continue next year as bankers apply stricter standards or cut their exposure to smaller merchants.
Russian gov’t considers $45-$55 a barrel oil price range optimum– Russia’s government considers the oil price range of USD45 to USD55 per barrel optimum in the current market situation, which allows preventing the market from overheating and supporting producers, Deputy Prime Minister Alexander Novak told reporters. “The range of prices of USD45 to USD55 per barrel is optimum for recovery of our production, which we have let strongly down, otherwise we will never restore production, others will do, whereas we will remain at our level all the time,” Novak said. The head of the commodity strategy department at Saxo Bank, Ole Hansen, said earlier the price of Brent crude oil might decrease amid reports about a new strain of the coronavirus that may push the infecting rates up and lead to new lockdowns. That may halt the growth of futures and even get them back to USD46 per barrel in the short-term. On December 14, Britain’s Secretary of State for Health and Social Care Matt Hancock said British scientists had identified a new coronavirus strain that might be to blame for high infection rates in southeastern England. On December 19, UK Prime Minister Boris Johnson said according to the current findings, the new strain might be 70 percent more contagious. However, there is no proof yet of a greater risk of lethal outcome. The World Health Organization has said the mutated strain has already reached Australia, Denmark, and the Netherlands.
Novak Backs Further OPEC+ Output Hike-- Russia plans to support a further gradual increase in OPEC+ production at the next meeting in January, because crude prices are within an optimal range. “To restore our output, that we’ve reduced a lot, the price range of $45 to $55 a barrel is the most optimal,” Deputy Prime Minister Alexander Novak told reporters in Moscow. “Otherwise we’ll never restore production, others will restore it.” Brent crude has averaged about $50 a barrel since early December, when the Organization of Petroleum Exporting Countries and its allies adopted a new plan to make gradual output increases. The group, which is led by Russia and Saudi Arabia, will boost daily crude production in monthly increments of as much as 500,000 barrels next year, instead of the previous plan to add almost 2 million barrels from Jan. 1. OPEC+ ministers will gather every month to discuss the size of each increment, allowing the group to react to uncertain demand as the Covid-19 pandemic continues. The next meeting, scheduled for Jan. 4, will determine how much supply should be added to the market in February. “If the situation is normal, stable, we will support the increase,” Novak said, when asked if Russia wants a further hike of 500,000 barrels a day in February. “We must reach levels that were envisaged earlier, from Jan. 1, gradually, without pulling the market too much.” That change would mean OPEC+ is still withholding about 6.7 million barrels a day from the market in February, compared with the current supply cuts of 7.7 million barrels a day. It’s unclear whether Saudi Arabia, the leader of OPEC+ alongside Russia, will back an increase in crude output. Last week, after face-to-face talks with Novak in Riyadh, Saudi Arabia Energy Minister Crown Prince Abdulaziz bin Salman said he wants to keep market speculators “on their toes.” “Nobody will know what we will do on the 4th of January until the day of the meeting,” Abdulaziz said.
Oil Steady as Virus Pessimism Balanced by Stimulus -- Oil steadied -- after posting its first weekly loss since October -- as pessimism over a new strain of Covid-19 that’s threatening more travel restrictions was balanced by the passage of a U.S. stimulus bill into law. Futures in New York traded near $48 a barrel after sliding 1.8% last week. Tougher restrictions were extended to much of England to try and stem the virus mutation, while American officials warned of a post-Christmas surge of infections. Japanese industrial production missed analyst expectations to come in unchanged last month from October, more evidence that the resurgent pandemic is stalling the economic recovery in some parts of Asia. Crude pared losses of as much as 1.5% after President Donald Trump signed the long-awaited bill containing $900 billion of virus relief that’s expected to boost energy demand in the world’s largest economy. Trump had previously expressed his displeasure with the package that Congress approved last week. Oil is finishing the year on a somber note as the short-term demand risk of more travel restrictions outweighs optimism over vaccine rollouts, which are already underway and will eventually boost energy demand. The OPEC+ alliance will also return 500,000 barrels a day of output to the market from January. West Texas Intermediate for February delivery fell 0.1% to $48.19 a barrel on the New York Mercantile Exchange as of 7:47 a.m. in London. Brent for February settlement declined 0.2% to $51.20 on the ICE Futures Europe exchange after closing up 0.2% on Thursday. Crude’s futures curve is reflecting the pessimism. Brent’s prompt timespread is 5 cents a barrel in contango, a bearish market structure where near-term prices are cheaper than later-dated ones. The spread was as much as 13 cents in backwardation earlier this month. President Trump, meanwhile, has raised geopolitical tensions in the Middle East, accusing Iran of being responsible for a rocket attack near the U.S. embassy in Baghdad. The Islamic Republic’s Foreign Ministry said the claims were baseless. The country’s oil minister said this month that Iran was planning to double its production in 2021, which will clash with OPEC+ efforts to gradually increase supply without flooding the market.
Oil rises after Trump signs aid bill - Oil rose towards $52 a barrel on Monday as U.S. President Donald Trump's signing of a coronavirus aid package and the start of a European vaccination campaign outweighed concern about weak near-term demand. Brent crude rose 43 cents, or 0.84%, to $51.72 a barrel, reversing an earlier decline. U.S. West Texas Intermediate (WTI) crude added 45 cents, or 0.93%, to $48.68. "The signing of the U.S. stimulus bill, with the possibility of an increased size, should put a floor under oil prices in a shortened week," said Jeffrey Halley, analyst at broker OANDA. Trump, whose presidency is set to end next month, had earlier threatened to block the $2.3 trillion aid and spending package. Oil has recovered from historic lows reached in the spring as the emerging pandemic hammered demand. And in a further sign of progress against COVID-19, Europe launched a mass vaccination drive on Sunday. But, the emergence of a new variant of the virus, first seen in Britain and now detected in other countries, has led to movement restrictions being reimposed, hitting near-term demand and weighing on prices. And Brent is still below the $52.48 level reached on Dec. 18, which was its strongest since March. Oil remains vulnerable to any further setbacks in efforts to control the virus, said Stephen Innes, chief global market strategist at Axi, in a note. Also coming into focus will be a Jan. 4 meeting of the Organization of the Petroleum Exporting Countries and allies, a group known as OPEC+. The group is slowly tapering record oil output cuts made this year to support the market. OPEC+ is set to boost output by 500,000 barrels per day in January.
Oil gains on hopes U.S. pandemic stimulus payments to spur fuel demand - Oil rose on Tuesday, for the third time in four sessions, on expectations for rising fuel demand as the United States may expand their pandemic aid payments and a final Brexit deal is set to stabilize trade between Europe and the UK. Brent crude futures climbed 36 cents, or 0.7%, to $51.22 a barrel, as of 0151 GMT and U.S. West Texas Intermediate (WTI) crude futures added 34 cents, or 0.7%, to $47.96 a barrel. Crude rose along with a gains in Asian shares, with Japanese stocks hitting a 29-year high, on rising investor risk appetite as the U.S. House of Representatives voted to raise pandemic relief payments to $2,000 from $600. The Senate still needs to vote on the measure. Forecasts for tightening U.S. crude oil stocks also added support to prices. U.S. crude oil stockpiles are expected to have declined last week, while refined products inventories likely rose, a preliminary Reuters poll ahead of this week's data showed on Monday. Five analysts polled by Reuters estimated, on average, that crude stocks likely fell by 2.1 million barrels in the week to Dec. 25. Still, concerns over coronavirus lockdowns are capping gains. A new variant of the virus in the United Kingdom has led to the reimposition of movement restrictions, hitting near-term demand and weighing on prices, while hospitalizations and infections have surged in parts of Europe and Africa. A Jan. 4 meeting of the Organization of the Petroleum Exporting Countries (OPEC) and allies including Russia, a group known as OPEC+, also looms over the market. OPEC+ is tapering record oil output cuts made this year to support the market. The group is set to boost output by 500,000 barrels per day (bpd) in January and Russia supports another increase of the same amount in February. Russian Deputy Prime Minister Alexander Novak said on Monday he expected there would be 5 million to 6 million bpd additional oil demand in 2021, which has not fully recovered from the pandemic. Money managers raised their net-long U.S. crude futures and options positions in the week to December 21, the U.S. Commodity Futures Trading Commission said on Monday. The speculator group raise its combined futures and options position in New York and London by 4,455 contracts to 325,787 during the period.
Oil Prices Climb On Stimulus Hopes - Oil has seesawed back and forth over the past week, sandwiched between very strong bullish and bearish forces on each side. Covid-19 is at its worst in many parts of the world, but vaccinations are picking up in earnest as well. Brent edged back above $51 per barrel after the house passed a major stimulus bill on Monday evening. “Markets feel very rangy into the New Year but should find support today from broader risk markets as stocks are soaring on the prospects of larger stimulus checks,” said Stephen Innes, chief global market strategist at Axi. The terms of the OPEC+ production pact could berevised if oil demand recovers next year faster than currently expected, Russian Deputy Prime Minister Alexander Novak, who is still in charge of coordinating Russia’s oil policy with OPEC, told Rossiya TV news channel in an interview on Monday. Rising JKM prices for LNG in Asia brighten the outlook for U.S. LNG exports. “We assume near-max utilization rates of US LNG export facilities next year,” Bank of America said. Oil and gas companies in North America and Europe wrote down around $145 billion in assets in the first three quarters of 2020, the most since 2010. Prices are rebounding, but the write-downs also reflect long-term concerns. “They are coming to grips with the fact that demand for the product will decline, and the write-downs are a harbinger of that,” KPMG’s Regina Mayor told the WSJ. Japan said it would end sales of gasoline vehicles by the mid-2030s, the latest major economy to chart a course away from the internal combustion engine. Internal planning documents reviewed byBloomberg Green reveal detailed emissions projections for individual projects from ExxonMobil. For instance, the Golden Pass LNG project would emit 3.1 million metric tons, and the liquefaction process would emit as much as a coal-fired power plant. Investors are growing increasingly concerned that carbon-intensive projects will be subjected to future regulation or taxation, and they are pressuring Exxon to detail more of their risk.
Oil Rise Aided by Dollar - - Oil pushed higher with support from a weakening dollar as investors weighed a worsening short-term demand outlook against an eventual rebound as Covid-19 vaccines are rolled out. Futures in New York rose past $48 a barrel after falling 1.3% Monday. A dip in the dollar boosted the appeal of commodities like oil that are priced in the currency. Crude was also aided by an improvement in broad market sentiment after the House backed higher stimulus checks following President Donald Trump’s signing of a $900 billion virus relief package. The coronavirus continued to surge unabated, however. Southern California is set to extend a lockdown amid a surge in cases, while Germany is concerned the slow pace of its vaccine rollout could prolong the economic damage from the pandemic. The virus is also making a comeback in Asia, with Thailand tightening restrictions and South Korea’s daily death toll rising to a record. Crude’s vaccine-driven rally has faltered in the last couple of weeks on signs it may have gotten ahead of the recovery in energy demand. The OPEC+ alliance is also set to add another 500,000 barrels a day of output to the market from January, while Russia’s deputy prime minister said last week the nation would support a further gradual increase in production in February. “Renewed concern over the virus will limit the upside for oil in the near term” and noise around Russia supposedly favoring adding more output in February won’t help either, said Warren Patterson, head of commodities strategy at ING Groep NV in Singapore. Price moves will continue to be driven by Covid-19 developments, he said. West Texas Intermediate for February delivery rose 0.9% to $48.06 a barrel on the New York Mercantile Exchange as of 7:49 a.m. in London. Brent for February settlement climbed 0.9% to $51.33 on the ICE Futures Europe exchange after falling 0.8% on Monday. OPEC+ will meet next week to decide on production levels for February, with traders looking out for indications of changing sentiment among its members. Over the longer term, Iranian plans to hike oil output may undermine the alliance’s efforts to raise production while avoiding flooding the market.
Oil holds steady on U.S. inventory draw, but demand fears weigh - Oil held steady on Wednesday as a U.S. coronavirus fiscal aid package and a decline in crude oil inventories supported prices. Brent crude futures rose 11 cents, or 0.2%, to $51.19 a barrel, and U.S. West Texas Intermediate (WTI) crude was unchanged at $48. "Oil prices have remained supported by a weaker U.S. dollar overnight and have finally found a friend in the API inventory report," said Stephen Innes, chief global market strategist at Axi, a broker. "This morning the American Petroleum Institute reported a much larger draw versus consensus in crude oil inventories for the week ending December 25." The dollar fell to its lowest in more than two years against the euro as currency traders looked past a new delay in U.S. stimulus checks and maintained bets that additional financial aid was still likely. The Democrat-led U.S. House of Representatives voted to meet President Donald Trump's demand to increase direct Covid-19 aid payments to Americans hurting from the pandemic to $2,000. Asian shares retreated as investors cashed in on a recent rally, while the euro flirted with highs not seen in more than 2-1/2 years on as hopes of a gradual global economic recovery. Oil prices could gain strength as vaccination programs around the world begin next year, allowing countries to relax restrictions on movement and business activity. U.S. physical crude oil grades strengthened on Tuesday as the API reported a decline in stockpiles, dealers said. Crude oil stocks fell by 4.8 million barrels last week to about 492.9 million barrels, exceeding analysts' expectations in a Reuters poll for a draw of 2.6 million barrels, data from API showed. In the short-term, concerns over coronavirus lockdowns are likely to cap gains. A new variant of the virus in the United Kingdom has led to the reimposition of movement restrictions, hitting near-term demand and weighing on prices, while hospitalizations and infections have surged in parts of Europe and Africa. Fossil-fuel demand in coming years could remain softer even after the pandemic as countries seek to limit emissions to slow climate change. Major oil companies, such as BP and Total SE, published forecasts that include scenarios where global oil demand may have peaked in 2019. A Jan. 4 meeting of the Organization of the Petroleum Exporting Countries (OPEC) and allies including Russia, a group known as OPEC+, also looms over the market. OPEC+ is tapering record oil output cuts made this year to support the market. The group is set to boost output by 500,000 barrels per day (bpd) in January, and Russia supports another increase of the same amount in February.
Oil prices dip as demand concerns counter U.S. stimulus (Reuters) -Oil prices fell on Monday as concerns about weakening fuel demand and the prospect of higher OPEC+ output outweighed optimism over a U.S. stimulus package. Oil prices strengthened earlier in the day, with Brent rising above $52 a barrel, as Democrats aimed for larger $2,000 COVID-19 relief payments following U.S. President Donald Trump’s signing of a $2.3 trillion stimulus deal. But a new variant of the virus in the United Kingdom has led to restrictions on movement being reimposed, hitting near-term demand and weighing on prices, while hospitalizations and infections surged in parts of Europe and Africa. Brent crude settled at $50.86 a barrel, falling 43 cents, or 0.84%, after trading as high as $52.02 earlier in the session. U.S. West Texas Intermediate (WTI) crude settled at $47.62 a barrel, losing 61 cents, or 1.26%. “We continue to focus on this pandemic and what January is going to bring,” “The prospects of more lockdowns are looming and I think that is what’s holding things back.” A Jan. 4 meeting of the Organization of the Petroleum Exporting Countries and allies including Russia, a group known as OPEC+, also looms over the market. “While much focus will remain on the demand side of the global oil balances this week and into the new year, the supply side of the equation will be garnering more attention next month after OPEC+ cranks up its production allowances,”
Oil Prices Rise as U.S. Crude Stock Draw Supports but Demand Hopes Dim - (Reuters) -Oil prices settled higher on Wednesday, supported by a draw in U.S. crude inventories and Britain's approval of a second coronavirus vaccine but pressured by swelling year-over-year supply. Brent crude futures settled up 25 cents to $51.34 a barrel, off the session high of $51.56 and well lower than the $66 price that started the year. U.S. West Texas Intermediate (WTI) crude settled up 40 cents to trade at $48.40, substantially down from about $62 at the start of 2020. Both contracts slipped early the session as a bigger fiscal aid package in the United States looked increasingly unlikely, dampening hopes for a swifter recovery of oil demand that has been hammered by the COVID-19 pandemic. Prices rallied after an Energy Information Administration report showed crude inventories fell by 6.1 million barrels in the latest week to 493.5 million barrels. [EIA/S] But traders noted that U.S. crude inventories still were ending the year more than 10% higher than the last week of 2019. "We couldn't even pull down storage levels with a 6.1 million inventory draw which is sad but a reality, and it took the wind out of the sails for a big rally" said Bob Yawger, director of energy futures at Mizuho. On the supply front, U.S. energy firms this week added 3 oil and natural gas rigs to the best quarter for boosting the rig count since the second quarter of 2017, according to data from Baker Hughes. A Jan. 4 meeting of the Organization of the Petroleum Exporting Countries (OPEC) and allies, including Russia, a group known as OPEC+, is set to boost output by 500,000 barrels per day (bpd) in January. Oil prices found some support on Wednesday from the U.S. dollar hitting its lowest against a basket of currencies since 2018, making oil cheaper for holders of other currencies. Raising hopes of a faster normalization of travel and work, Britain on Wednesday became the first country to approve a coronavirus vaccine developed by the University of Oxford and AstraZeneca.
Oil Prices Settle Higher on Final Day of 2020 | Rigzone -- West Texas Intermediate (WTI) and Brent crude oil prices posted increases on the final trading day of 2020. The February WTI futures price gained 12 cents, settling at $48.52 per barrel. The light crude marker Thursday traded within a range from $47.77 to $48.58.Brent crude for March delivery finished Thursday’s session at $51.80 per barrel, reflecting a 17-cent gain.Although oil prices have recovered since plunging this past spring amid steep pandemic-driven demand destruction, the benchmarks are still 20-plus percent overall for the year. By comparison, the closing WTI and Brent per-barrel prices on Jan. 2, 2020, were $61.18 (21 percent higher) and $66.25 (22 percent higher), respectively.The price of a gallon of reformulated gasoline (RBOB) often moves in the same direction as the oil benchmarks, but such was not the case Thursday. January RBOB posted a slight loss – well under a penny – to close just below $1.41. Henry Hub natural gas futures finished higher, with the February contract adding nearly 12 cents to settle at $2.54.
Oil edges higher, but posts 20% annual drop in tumultuous 2020 (Reuters) -Global crude prices edged higher on Thursday but lost more than a fifth of their value in 2020, as lockdowns to combat the novel coronavirus depressed economic activity and sent oil markets reeling. Still, Brent and U.S. crude benchmarks have more than doubled from April’s nadir as producers cut output to match weaker demand. News of coronavirus vaccine distributions also bolstered prices in the fourth quarter, helping futures recover to the highest in about 10 months. On the last trading day of 2020, Brent rose 17 cents to settle at $51.80 a barrel. U.S. West Texas Intermediate rose 12 cents to settle at $48.52 a barrel. Brent fell 21.5% for the year, with WTI falling 20.5%. Prices for 2020 bottomed in April as fuel demand collapsed due to the COVID-19 pandemic and after a price war between oil giants Saudi Arabia and Russia. WTI plummeted to a record low negative-$40.32 per barrel, while Brent fell to $15.98 barrel, the lowest since 1999. From there prices drifted higher and took off once vaccine optimism hit the market. “The first half was remarkable and unprecedented with a steep move lower and a snapback rally,” said John Kilduff, a partner at Again Capital Management in New York. “Then it was like watching paint dry for several months through October.” Though prices have climbed the last two months, additional lockdowns have weighed again on fuel demand and a new, highly infectious variant of the virus has raised alarms. A monthly Reuters poll on Thursday showed oil prices are not expected to make much progress in 2021. And the demand outlook for fuel still remains murky. U.S. gasoline futures fell 17% for the year, while U.S. heating oil futures dropped 27%. Some commodity markets, including spot Asian LNG and silver, were ending 2020 on a strong note, with recovering demand and widespread stimulus packages buoying prices. Rollouts of vaccines to combat the virus and trillions of dollars’ worth of fiscal support were expected to boost investment and spending in 2021.
'So Frustrated': Iranians' Fears Skyrocket That They Won't Get Access To COVID-19 Vaccines - Amid the launch of mass COVID-19 vaccination drives in the West, there’s growing concern among Iranians that they could be left behind. They fear U.S. sanctions and what some regard as the Iranian clerical establishment’s failure to prioritize the well-being of its citizens. Iranians, including health workers, have taken to social media to call on their leaders to purchase vaccines against the coronavirus amid allegations by Iranian officials that U.S. sanctions are impeding their ability to procure them through COVAX, a global payment facility aimed at ensuring vaccine distribution around the world. The concern over Iranians’ access to vaccines was also highlighted in a December 22 statement by more than two dozen rights groups and humanitarian organizations, including Human Rights Watch (HRW), who called on "all stakeholders to ensure that Iranians have swift, unencumbered, and equitable access to safe, effective, and affordable COVID-19 vaccines." Without inoculations, many more Iranians are likely to die from the Middle East’s worst COVID-19 outbreak, which has already infected more than 1.1 million Iranians and claimed the lives of nearly 54,000, according to officials figures. Health officials have suggested that the country’s real coronavirus death toll could be twice that number. Earlier this month, Iranian Central Bank Governor Abdolnaser Hemmati said in a social-media post that "inhumane sanctions by the U.S. government" were preventing the country from making any payment for vaccine doses via "the official channel of the World Health Organization (WHO)." Republican U.S. President Donald Trump reimposed stifling sanctions on Iran in 2018 after withdrawing the United States from a multilateral 2015 nuclear deal that exchanged sanctions relief for curbs on Iran's disputed nuclear program. Democratic President-elect Joe Biden has said the United States will rejoin the accord if Tehran returns to strict compliance, although there is at least one effort afoot among Republicans in the U.S. Senate to prevent that.
Iran's President Claims Washington Demanding That Coronavirus Vaccine Transaction Run Through U.S. Bank - Following an announcement that Tehran had won approval from the United States to use foreign-currency reserves to buy coronavirus vaccines, Iran's president has claimed that Washington is now demanding that such a transaction go through a U.S. bank. President Hassan Rohani told a meeting of the government's coronavirus-response team on December 26 that Iran sought to transfer money from an unidentified third country, and that it had received approval from the U.S. Treasury Department's Office of Foreign Assets Control (OFAC). However, Rohani claimed, while the OFAC "had initially indicated that it was not a problem," it "later said that the money had to first pass through a U.S. bank before it reaches [the recipient]." Rohani blasted the alleged demand, which the Treasury Department has not confirmed, and questioned whether the United States might confiscate the funds. On December 24, Iranian central bank chief Abdolnaser Hemmati said that the OFAC had approved the transfer of around $244 million to a Swiss bank in order to purchase 16.8 million doses of vaccines from COVAX, a global COVID-19 vaccine-allocation plan led by the World Health Organization (WHO). While punitive financial sanctions imposed by the United States against Iran over its nuclear and regional activities prevented such transactions, Washington had been constrained by global public opinion to make an exception in this case, Hemmati claimed on Iranian state TV. Iran has been hard-hit by COVID-19, with nearly 1.2 million coronavirus cases recorded along with more than 54,000 deaths. Those numbers, which would make Iran the worst-affected country in the Middle East, are considered to be far lower than the actual figures released by Iranian health authorities.
B-52s fly over Persian Gulf as Washington escalates war threat against Iran --For the third time in little more than a month, the Pentagon has sent a pair of B-52 Stratofortress long-range heavy bombers to the Persian Gulf in a threat of war against Iran. This threat is being steadily escalated on the orders of US President Donald Trump as he continues to demand the overturning of the results of November’s US presidential election. The warplanes, which are capable of launching both nuclear and conventional weapons, flew low over the Gulf after a midair refueling over the Eastern Mediterranean in a 30-hour round-trip flight from their base in North Dakota. They were escorted by a squadron of F-16 fighter planes. A U.S. Air Force B-52H “Stratofortress” from Minot Air Force Base, N.D., is refueled by a KC-135 “Stratotanker” over the Persian Gulf. (Senior Airman Roslyn Ward/U.S. Air Force via AP) Without mentioning Iran by name, the chief of the US Central Command (CENTCOM), which oversees US military operations throughout the Middle East, left no doubt as to the target of the provocative bomber deployment. “The United States continues to deploy combat-ready capabilities into the US Central Command area of responsibility to deter any potential adversary, and make clear that we are ready and able to respond to any aggression directed at Americans or our interests,” said CENTCOM commander General Frank McKenzie in announcing the Gulf overflight. “We do not seek conflict, but no one should underestimate our ability to defend our forces or to act decisively in response to any attack.” The B-52 flights are only part of a continuous and ominous US military buildup in the region. Last week, the Navy sent the nuclear-powered submarine USS Georgia, armed with cruise missiles, along with accompanying warships, into the Persian Gulf, joining the USS Nimitz carrier strike group already deployed there. The Israeli and other Middle Eastern media have also revealed that Israel has dispatched its own submarine through the Suez Canal in an apparent approach to the Persian Gulf. The Dolphin-class submarine is capable of firing nuclear cruise missiles. Meanwhile Israel has continued its airstrikes against Iranian-linked targets in Syria, bombing the Nabi Habil area near Damascus on Wednesday.
Saudi women's rights activist sentenced to nearly 6 years(AP) — One of Saudi Arabia’s most prominent women’s rights activists was sentenced Monday to nearly six years in prison, according to state-linked media, under a vague and broadly worded counterterrorism law. The ruling nearly brings to a close a case that has drawn international criticism and the ire of U.S. lawmakers. Loujain al-Hathloul has already been in pre-trial detention and has endured several stretches of solitary confinement. Her continued imprisonment was likely to be a point of contention in relations between the kingdom and the incoming presidency of Joe Biden, whose inauguration takes place in January — around two months before what is now expected to be al-Hathloul’s release date. Rights group “Prisoners of Conscience,” which focuses on Saudi political detainees, said al-Hathloul could be released in March 2021 based on time served. She has been imprisoned since May 2018, and 34 months of her sentencing will be suspended. Her family said in a statement she will be barred from leaving the kingdom for five years and required to serve three years of probation after her release. Biden has vowed to review the U.S.-Saudi relationship and take into greater consideration human rights and democratic principles. He has also vowed to reverse President Donald Trump’s policy of giving Saudi Arabia “a blank check to pursue a disastrous set of policies,” including the targeting of female activists. Al-Hathloul was found guilty and sentenced to five years and eight months by the kingdom’s anti-terrorism court on charges of agitating for change, pursuing a foreign agenda, using the internet to harm public order and cooperating with individuals and entities that have committed crimes under anti-terror laws, according to state-linked Saudi news site Sabq. The charges all come under the country’s broadly worded counterterrorism law. She has 30 days to appeal the verdict. “She was charged, tried and convicted using counter-terrorism laws,” her sister, Lina al-Hathloul, said in a statement. “My sister is not a terrorist, she is an activist. To be sentenced for her activism for the very reforms that MBS and the Saudi kingdom so proudly tout is the ultimate hypocrisy,” she said, referring to the Saudi crown prince by his initials. Sabq, which said its reporter was allowed inside the courtroom, reported that the judge said the defendant had confessed to committing the crimes and that her confessions were made voluntarily and without coercion.
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