oil prices settle at a new seven year high, oil supplies fall to new 10 year low with SPR at a 19 year low; total oil & products supplies at 7 1/2 year low after across the board inventory draw; global oil shortage at 440,000 barrels per day in January as OPEC’s output falls 749,000 barrels per day short; 2021 shortage revised to 1.5 million barrels per day; US drilling rigs jump most in 48 months
oil prices rose for an eighth straight week and established a fourth consecutive 7 year high after the White House advised that a Russian invasion of Ukraine was imminent.. after rising 6.3% to $92.31 a barrel last week following OPEC's decision to limit their March production increase and on fears of production well freeze-offs, the contract price for US light sweet crude for March delivery opened 49 cents lower on Monday as progress in the Iran nuclear talks raised the specter that up to 2 million barrels per day of their supplies could return to the global oil market, and settled 99 cents lower at $91.32 a barrel as the prospect of an Iran deal offset bullish sentiment on rising consumption across industrialized countries and ongoing supply constraints from the OPEC+ alliance... oil extended Monday's losses into early trading Tuesday, as fears of easing geopolitical risks increased with the partial lifting of Iranian sanctions on civilian nuclear projects ahead of multinational talks in Vienna, and continued to tumble to settle $1.96, or more than 2% lower at $89.36 a barrel, amid a one-two punch of easing geopolitical tensions across the Ukraine-Russian border and reported progress in Iranian nuclear talks in Vienna....oil prices stabilized early Wedneday after Tuesday night's API report of across-the-board inventory draws, and then surged to over $90 after the weekly EIA report also showed across-the-board draws from U.S. stockpiles, and that US refiners had boosted crude throughputs to meet stronger fuel demand, before settling with a modest 30 cent gain to $89.66 a barrel as the prospect of increased supply from Iran and the US kept pressure on the market...oil prices jumped more than $2 early Thursday as traders weighed the possibility of an aggressive Fed response to new data showing annual inflation at a 40 year high, but settled just 22 cents higher at $89.88 a barrel as the inflation increase was also seen sapping US growth.. oil prices then spiked to nearly $95 a barrel Friday, after US National Security Adviser Jake Sullivan told a White House media briefing that a Russian attack on Ukraine could happen by next week and would likely begin with an air assault, before prices backtracked but still settled with a gain of $3.22 at $93.10 a barrel after the International Energy Agency raised its 2022 demand forecast and expects global demand to expand by 3.2 million barrels per day (bpd) this year, reaching an all-time record 100.6 million bpd....with that big Friday gain, US crude prices managed a 0.9% increase on the week and settled at another 7 year closing high..
on the other hand, natural gas prices finished lower for a second week as temperature forecasts continued to moderate throughout the week...after falling 1.4% to $4.572 per mmBTU last week as traders looked past the ongoing winter storm to warmer forecasts ahead, the contract price of natural gas for March delivery opened 4% lower on Monday and tumbled 34 cents, or more than 7% to $4.232 per mmBTU, as output recovered from last week's freeze-offs and on forecasts for lower heating demand over the next two weeks than was previously expected...natural gas prices rose as much as 15 cents early Tuesday as weather models showed a shot of chilly air hitting the eastern half of the country this weekend through early next week, but ultimately just settled 1.6 cents higher at $4.248 per mmBTU....natural gas prices headed south on rising temperatures and waning supply concerns on Wednesday and settled 23.9 cents or more than 5% lower at a two week low of $4.009 per mmBTU, and then fell 5.0 cents more to a three week low on Thursday despite a massive storage draw last week that was much bigger than usual for a fourth week in a row...natural gas prices slipped again on Friday, edging down 1.8 cents to another 3 week low of $3.941 per mmBTU, as a steadily warming February forecast proved too much for bulls to overcome and thus finished 13.8% lower on the week...
The EIA's natural gas storage report for the week ending February 4th indicated that the amount of working natural gas held in underground storage in the US fell by 222 billion cubic feet to 2,101 billion cubic feet by the end of the week, which left our gas supplies 441 billion cubic feet, or 17.3% below the 2,542 billion cubic feet that were in storage on February 4th of last year, and 215 billion cubic feet, or 9.3% below the five-year average of 2,316 billion cubic feet of natural gas that have been in storage as of the 4th of February over the most recent five years....the 222 billion cubic foot withdrawal from US natural gas working storage for the cited week was close to the average forecast for a 221 billion cubic foot withdrawal expected by an S&P Global Platts survey of analysts, but was more than the 174 billion cubic feet that were pulled from natural gas storage during the corresponding week of 2021, and also quite a bit more than the average withdrawal of 150 billion cubic feet of natural gas that have typically been pulled out natural gas storage during the same week over the past 5 years…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending February 4th indicated that after a drop in our oil imports, a jump in our oil exports, and an increase in our refining, we again had to pull oil out of our stored commercial crude supplies for the ninth time in 11 weeks and for the 25th time in the past thirty-seven weeks….our imports of crude oil fell by an average of 696,000 barrels per day to an average of 6,389,000 barrels per day, after rising by an average of 849,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 724,000 barrels per day to an average of 3,100,000 barrels per day during the week, which together meant that our effective trade in oil worked out to a net import average of 3,289,000 barrels of per day during the week ending February 4th, 1,420,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, production of crude oil from US wells was reportedly 100,000 barrels per day higher at 11,600,000 barrels per day, and hence our daily supply of oil from the net of our international trade in oil and from domestic well production appears to have totaled an average of 14,889,000 barrels per day during the cited reporting week…
Meanwhile, US oil refineries reported they were processing an average of 15,577,000 barrels of crude per day during the week ending February 4th, an average of 328,000 more barrels per day than the amount of oil than our refineries processed during the prior week, while over the same period the EIA’s surveys indicated that a net of 879,000 barrels of oil per day were being pulled out the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 191,000 barrels per day more than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (-191,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a balance sheet fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or omission of that magnitude in this week’s oil supply & demand figures that we have just transcribed...however, since last week’s EIA fudge factor was at (-1,377,000) barrels per day, that means there was still a 1,185,000 barrel per day difference between this week's balance sheet error and the EIA's crude oil balance sheet error from a week ago, and hence the week over week supply and demand changes indicated by this week's report are completely worthless.....however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing, and hence decisions to drill or complete oil wells, we’ll continue to report this data just as it's published, and just as it's watched & believed to be reasonably accurate by most everyone in the industry...(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
This week's 879,000 barrel per day decrease in our overall crude oil inventories left our total oil supplies at 997,902,000 barrels, the lowest since December 12th, 2011, and therefore at a new 10 year low...this week's oil inventory decrease came as 679,000 barrels per day were being pulled out of our commercially available stocks of crude oil, while 200,000 more barrels per day of oil were being pulled out of our Strategic Petroleum Reserve, part of the first installment of Biden's plan to release 50 million barrels from the SPR to incentivize US gasoline consumption....including the drawdowns from the Strategic Petroleum Reserve under such politically motivated programs, a total of 68,634,000 barrels have been removed from the Strategic Petroleum Reserve over the past 18 months, and as a result the 587,515,000 barrels of oil left in our Strategic Petroleum Reserve is now the lowest since October 4th, 2002, or at yet another new 19 year low, as repeated tapping of our emergency supplies for political reasons or to “pay for” other programs had already drained those supplies considerably over the past dozen years...based on an estimated prepandemic consumption level of around 18 million barrels per day, the US will have roughly 30 1/2 days of oil supply left in the Strategic Petroleum Reserve when the Biden program is complete...
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,614,000 barrels per day last week, which was 12.7% more than the 5,868,000 barrel per day average that we were importing over the same four-week period last year….this week’s crude oil production was reported to be 100,000 barrels per day higher at 11,600,000 barrels per day even though the EIA's rounded estimate of the output from wells in the lower 48 states was unchanged at 11,100,000 barrels per day, because Alaska’s oil production was 12,000 barrels per day higher at 456,000 barrels per day and therefore added 100,000 barrels per day to the rounded national production total (by the EIA's math)...US crude oil production had reached a pre-pandemic high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 11.5% below that of our pre-pandemic production peak, but 37.6% above the interim low of 8,428,000 barrels per day that US oil production had fallen to during the last week of June of 2016...
US oil refineries were operating at 88.2% of their capacity while using those 15,577,000 barrels of crude per day during the week ending February 4th, up from a utilization rate of 86.7% the prior week, but a bit lower than the historical utilization rate for early February refinery operations…the 15,577,000 barrels per day of oil that were refined this week were 5.3% more barrels than the 14,793,000 barrels of crude that were being processed daily during the pandemic impacted week ending February 5th of 2021, but still 2.8% less than the 16,020,000 barrels of crude that were being processed daily during the week ending February 7th, 2020, when US refineries were operating at what was then also a below normal 87.5% of capacity...
With the big increase in oil being refined this week, gasoline output from our refineries was also much higher, increasing by 740,000 barrels per day to 8,650,000 barrels per day during the week ending February 4th, after our gasoline output had decreased by 267,000 barrels per day over the prior week.…this week’s gasoline production was 8.5% more than the 8,656,000 barrels of gasoline that were being produced daily over the same week of last year, and 1.6% more than the gasoline production of 9,241,000 barrels per day during the week ending February 7th, 2020....at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 97,000 barrels per day to 4,699,000 barrels per day, after our distillates output had decreased by 148,000 barrels per day over the prior week…after that increase, our distillates output was fractionally more than the 4,660,000 barrels of distillates that were being produced daily during the week ending February 5th of 2021, but 2.9% less than the 4,837,000 barrels of distillates that were being produced daily during the week ending January 31st, 2020...
Even with the increase in our gasoline production, our supplies of gasoline in storage at the end of the week fell for the third time in the past 11 weeks, decreasing by 1,644,000 barrels to 248,393,000 barrels during the week ending February 4th, after our gasoline inventories had increased by a near record 27,378,000 barrels over the prior five weeks....our gasoline supplies decreased this week because the amount of gasoline supplied to US users increased by 900,000 barrels per day to 9,126,000 barrels per day, even as our imports of gasoline rose by 81,000 barrels per day to 514,000 barrels per day, and as our exports of gasoline fell by 334,000 barrels per day to 306,000 barrels per day…after this week's decrease, our gasoline supplies were 3.1% lower than last February 5th's gasoline inventories of 256,412,000 barrels, and are now about 3% below the five year average of our gasoline supplies for this time of the year…
Meanwhile, despite this week's increase in our distillates production, our supplies of distillate fuels decreased for the seventeenth time in twenty-four weeks, falling by 930,000 barrels to 121,814,000 barrels during the week ending February 4th, after our distillates supplies had decreased by 2,410,000 barrels during the prior week….our distillates supplies fell again this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 373,000 barrels per day to 4,296,000 barrels per day, because our exports of distillates rose by 449,000 barrels per day to 976,000 barrels per day, while our imports of distillates rose by 190,000 barrels per day to 440,000 barrels per day....after thirty inventory decreases over the past forty-four weeks, our distillate supplies at the end of the week were 24.4% below the 161,106,000 barrels of distillates that we had in storage on February 5th of 2021, and about 19% below the five year average of distillates inventories for this time of the year…
Meanwhile, drop in our oil imports, a jump in our oil exports, and an increase in our refining, our commercial supplies of crude oil in storage fell for the 18th time in 27 weeks and for the 34th time in the past year, decreasing by 4,756,000 barrels over the week, from 415,143,000 barrels on January 28th to a 39 month low of 410,387,000 barrels on February 4th, after our commercial crude supplies had decreased by 1,047,000 barrels over the prior week…after this week’s decrease, our commercial crude oil inventories fell to about 11% below the most recent five-year average of crude oil supplies for this time of year, but were still about 28% above the average of our crude oil stocks as of first weekend of February over the 5 years at the beginning of the past decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels....since our crude oil inventories had jumped to record highs during the Covid lockdowns of spring 2020 and remained elevated for most of a year after that, our commercial crude oil supplies as of this February 4th were 12.5% less than the 469,014,000 barrels of oil we had in commercial storage on February 5th of 2021, and are now 7.2% less than the 442,468,000 barrels of oil that we had in storage on February 7th of 2020, and also 8.9% less than the 450,840,000 barrels of oil we had in commercial storage on February 8th of 2019…
Finally, with our inventory of crude oil and our supplies of all products made from oil all near multi year lows, we are continuing to track the total of all U.S. Stocks of Crude Oil and Petroleum Products, including those in the SPR....the EIA's data shows that the total of our oil and oil product inventories, including those in the Strategic Petroleum Reserve and those held by the oil industry, and thus including everything from gasoline and jet fuel to propane/propylene and residual fuel oil, fell by 9,449,000 barrels this week, from 1,767,813,000 barrels on January 28th to1,758,364,000 barrels on February 4th....that leaves our total supplies of oil & its products now at the lowest since May 30th, 2014, or at a fresh seven and a half year low, despite the recent near record increase in gasoline inventories....
OPEC's January Oil Market Report
Thursday of the past week saw the release of OPEC's February Oil Market Report, which includes details on OPEC & global oil data for January, and hence it gives us a picture of the global oil supply & demand situation for the sixth month after 'OPEC+' agreed to increase their output by 400,000 barrels per day each month from the previously agreed to July level, which was in turn part of the fifth production quota policy reset that they've made over the past twenty months, all in response to the pandemic-related slowdown and subsequent irregular recovery....with US Omicron infections apparently subsiding at the time of this report, we need to again caution that the global oil demand estimates made by OPEC herein, while the eventual global course of the Covid-19 pandemic still remains uncertain, should be considered as having a much larger margin of error than we'd expect from this report during stable and hence more predictable periods..
the first table from this monthly report that we'll review is from the page numbered 46 of this month's report (pdf page 56), and it shows oil production in thousands of barrels per day for each of the current OPEC members over the recent years, quarters and months, as the column headings below indicate...for all their official production measurements, OPEC uses an average of estimates from six "secondary sources", namely the International Energy Agency (IEA), the oil-pricing agencies Platts and Argus, the U.S. Energy Information Administration (EIA), the oil consultancy Cambridge Energy Research Associates (CERA) and the industry newsletter Petroleum Intelligence Weekly, as a means of impartially adjudicating whether their output quotas and production cuts are being met, to thereby avert any potential disputes that could arise if each member reported their own figures...
As we can see on the bottom line of the above table, OPEC's oil output increased by 64,000 barrels per day to 27,981,000 barrels per day during January, up from their revised December production total which averaged 27,918,000 barrels per day....however, that December output figure was originally reported as 27,882,000 barrels per day, which therefore means that OPEC's December production was revised 36,000 barrels per day higher with this report, and hence OPEC's January production was, in effect, a 100,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official December OPEC output figures as reported a month ago, before this month's revision)...
According to the agreement reached between OPEC and the other oil producers at their Ministerial Meeting on July 18th, 2021, the oil producers party to that agreement were to raise their output by a total of 400,000 barrels per day each month through December, which was subsequently renewed to include another 400,000 barrel per day production increase in January,and which would include an increase of 254,000 barrels per day from the OPEC members listed above ...but as we can see from the above table, OPEC's increase of 64,000 barrels per day was far short of that...the apparent reasons for their production shortfall in January were the 51,000 barrel per day decrease in Venezuela's output, the 45,000 barrel per day decrease in Libya's output, the 27,000 barrel per day decrease in Iraq's output, and to a lesser extent the production decreases by Congo and Gabon...while we knew that Libyan production has frequently been disrupted by episodes of civil strife and that Iraq's output was interrupted by an explosion on a key export pipeline to Turkey, it turns out that Venezuela was unable to meet their quota because a shipment of Iranian condensate, which it uses to blend its extra-heavy crude, did not arrive in January, forcing a production shutdown....
Recall that the original 2020 oil producer's agreement was to cut oil production by 9.7 million barrels per day from an October 2018 baseline for just two months early in the pandemic, during May and June of 2020, but that initial 9.7 million bpd production cut agreement was extended to include July 2020 at a meeting between OPEC and other producers on June 6th, 2020....then, in a subsequent meeting in July of that year, OPEC and the other oil producers agreed to ease their deep supply cuts by 2 million barrels per day to 7.7 million barrels per day for August 2020 and subsequent months, which thus became the agreement that governed OPEC's output for the rest of 2020...the OPEC+ agreement for their January 2021 production, which was later extended to include February and March and then April's output, was to further ease their supply cuts by 500,000 barrels per day to a cut of 7.2 million barrels per day from that original 2018 baseline...then, during a difficult meeting on April 1st of last year, OPEC and the other oil producers that are aligned with them agreed to incrementally adjust their oil production higher each month by a pre-set amount over the following three months, thus extending their joint output cut agreement through July....production levels for August and the following months of this year were to be determined by a July 1st OPEC meeting, but that meeting was adjourned on July 2nd due to a dispute between the UAE and the Saudis over the 2018 reference production levels, and a subsequent attempt to restart that meeting on July 5th was called off....so it wasn't until July 18th 2021 that a tentative compromise addressing August's output quotas was worked out, allowing oil producers in aggregate to increase their production by 400,000 barrels per day in August, and again by that amount in each of the following months, and also to boost reference production levels for the UAE, the Saudis, Iraq and Kuwait beginning in April 2022....OPEC and other producers then agreed to increase their production in January 2022 by a further 400,000 barrels per day in a meeting concluded on the 2nd of December, 2021, and reaffirmed their intention to continue that policy with another 400,000 barrel per day increase in February at a meeting concluded January 4, 2022, and then agreed to stick to that 400,000 bpd oil output increase in March, despite pressure from the US to raise output more quickly, at a meeting on February 2nd, a little over a week ago...
Hence OPEC arrived at the production quotas for August 2021 through March of this year by repeatedly readjusting the original 23%, or 9.7 million barrel per day production cut from the October 2018 baseline that they first agreed to for May and June 2020, first to a 7.7 million barrel per day output reduction from the baseline for the remainder of 2020, then to a 7.2 million barrel per day production cut from the baseline for the first four months of this year, which was actually raised to an 8.2 million barrel per day oil output reduction after the Saudis unilaterally committed to cut their own production by a million barrels per day during February, March, and then later during April of last year....under the agreement prior to the current one, OPEC's production cut in April 2021 was set at 4,564,000 barrels per day below the October 2018 baseline, which was lowered to a cut of 3,650,000 barrels per day from the baseline with the prior comprehensive agreement, which thus set the July production quota for the "OPEC 10" at 23,033,000 barrels per day, with war torn Libya and US sanctioned producers Iran and Venezuela exempt from the production cuts imposed by thiat agreement....for OPEC and the other producers to increase their output by 400,000 barrels per day from that July 2021 level, each producer would be allowed to initially increase their production by just over 1% per month...for the ten members of OPEC who agreed to impose production cuts on themselves, that would mean their August output quota would be roughly 23,277,000 barrels per day, then 23,531,000 barrels per day in September, then roughly 23,786,000 barrels per day in October, then 24,041,000 barrels per day in November, then 24,296,000 barrels per day in December, and finally to 24,551,000 barrels per day in January ...therefore, the 23,802,000 barrels those 10 OPEC members actually produced in January were 749,000 barrels per day short of what they were expected to produce during the month, with Nigeria, Angola, and the Saudis accounting for most of this month's shortfall....
The next graphic from this month's report that we'll look at shows us both OPEC's and worldwide oil production monthly on the same graph, over the period from February 2020 to January 2022, and it comes from page 47 (pdf page 57) of OPEC's February Oil Market Report....on this graph, the cerulean blue bars represent OPEC's monthly oil production in millions of barrels per day as shown on the left scale, while the purple graph represents global oil production in millions of barrels per day, with the metrics for global output shown on the right scale....
Including this month's modest 64,000 barrel per day increase in OPEC's production from their revised production of a month earlier, OPEC's preliminary estimate indicates that total global liquids production increased by a rounded 710,000 barrels per day to average 98.69 million barrels per day in January, a reported increase which came after December's total global output figure was apparently revised down by 530,000 barrels per day from the 98.51 million barrels per day of global oil output that was estimated for December a month ago, as non-OPEC oil production rose by a rounded 650,000 barrels per day in January after that downward revision, with 80,000 barrels per day of the increase coming from OECD countries, primarily Norway and the UK, while non-OECD countries increased their output by 530,000 barrels per day, predominantly driven by production increases from Russia, Ecuador and Brazil... note that the graph above now shows a decline in December's global production, whereas a month ago OPEC had reported an 650,000 barrels per day global production increase for the month
After that increase in January's global output, the 98.69 million barrels of oil per day that were produced globally during the month were 5.10 million barrels per day, or 5.4 more than the revised 93.59 million barrels of oil per day that were being produced globally in January a year ago, which was the initial month that OPEC and their allied producers agreed to reduce their output cuts by 500,000 barrels per day from the 7.7 million barrels per day production cut that they applied to the last 5 months of 2020 (see the February 2021 OPEC report (online pdf) for the originally reported January 2021 details)...with this month's relatively small increase in OPEC's output, their January oil production of 27,981,000 barrels per day amounted to 28.4% of what was produced globally during the month, down from their 28.5% revised share of the global total in December....OPEC's January 2021 production was reported at 25,496,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 2,485,000 barrels per day, or 9.7% more barrels per day of oil this January than what they produced a year earlier, when they accounted for 27.4% of global output...
Even after the increases in OPEC's and global oil output that we've seen in this report, the amount of oil being produced globally during the month still fell a bit short of the expected global demand, as this next table from the OPEC report will show us....
The above table came from page 27 of the February Oil Market Report (pdf page 37), and it shows regional and total oil demand estimates in millions of barrels per day for 2021 in the first column, and then OPEC's estimate of oil demand by region and globally quarterly over 2022 over the rest of the table...on the "Total world" line in the second column, we've circled in blue the figure that's relevant for January, which is their estimate of global oil demand during the first quarter of 2022....OPEC is estimating that during the 1st quarter of this year, all oil consuming regions of the globe will be using an average of 99.13 million barrels of oil per day, and that oil consumers will be using 100.80 barrels per day over the entire year, now indicating a level of demand above that of 2019, when global demand averaged 99.98 million barrels per day....but as OPEC showed us in the oil supply section of this report and the summary supply graph above, OPEC and the rest of the world's oil producers were only producing 98.69 million barrels million barrels per day during January, which would imply that there was a modest shortage of around 440,000 barrels per day in global oil production in January when compared to the demand estimated for the month..
Also note on the table above that we've circled in green a small upward revision of 10,000 barrels per day to the demand figure for last year...a separate table on page 26 of tths months Oil Market Report indicates that was due to a 20,000 barrels per day upward revision to the demand figure for the fourth quarter of 2021, and a 30,000 barrels per day upward revision to the demand figure for the third quarter of 2021, which thus means that the supply shortfalls or surpluses that we previously reported for those quarters of last year would need to be revised....a month ago we estimated that there was a shortage of around 1,240,000 barrels per day in global oil production in December, based on the figures that were published at that time...however, as we saw earlier, December's global output figure was revised down by 530,000 barrels per day from those figures, while global demand for the 4th quarter of 2021 has now been revised 20,000 barrels per day higher, so with those revised figures, we now find that global oil production in December was running roughly 1,790,000 barrels per day short of demand...
In addition to figuring the December oil shortage that's indicated by this report, the upward revision of 20,000 barrels per day to 4th quarter demand we've noted above means that the 1,890,000 barrels per day global oil output shortage we had previously figured for November would now be revised to an oil shortage of 1,910,000 barrels per day...likewise, the upward revision of 20,000 barrels per day to 4th quarter demand noted above means that the 2,350,000 barrels per day global oil output shortage we had previously figured for October would now be revised to an oil shortage of 2,370,000 barrels per day...
As we previously mentioned, there was also a upward revision of 30,000 barrels per day to the third quarter's demand....that means that the 1,600,000 barrels per day global oil output shortage we had previously figured for September would now be revised to a shortage of 1,630,000 barrels per day....in like manner, the 30,000 barrels per day upward revision to 3rd quarter demand means that the shortage of 2,110,000 barrels per day we had previously figured for August would now be revised to a shortage of 2,140,000 barrels per day, and that the shortage of 1,690,000 barrels per day barrels per day we had previously figured for July would have to be revised to a shortage of 1,720,000 barrels per day...
After those revisions to our oil shortage estimates for the last 6 months of 2021, we should also go back and revise our estimate of the oil supply shortage for all last year...a month ago, we had listed our revised estimates for each month of last year based on the 12 monthly oil market reports that OPEC released over the year, and the monthly revisions to the supply and demand figures therein, and we found that the world was short 527,910,000 barrels of oil in 2021, which worked out to a shortage of 1,446,300 barrels of oil per day...with January's revisions, we now find that the world was short 548,940,000 barrels of oil in 2021, which works out to a shortage of 1,503,950 barrels of oil per day....despite that, we're still far from running out, because the quantities of oil being produced globally during the pandemic of 2020 still averaged over 3 million barrels per day more than anyone wanted....
This Week's Rig Count
The number of drilling rigs running in the US increased for the 62nd time over the past 73 weeks during the week ending February 11th, and by the most since February 9th 2018, but were still 19.9% below the prepandemic rig count....Baker Hughes reported that the total count of rotary rigs drilling in the US increased by twenty-two to 635 rigs this past week, which was also 238 more rigs than the pandemic hit 397 rigs that were in use as of the February 12th report of 2021, but was still 1,294 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, a week before OPEC began to flood the global market with oil in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 19 to 516 oil rigs during this week, after they had increased by 2 oil rigs during the prior week, and there are now 210 more oil rigs active now than were running a year ago, even as they still amount to just 32.1% of the shale era high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was up by 2 to 118 natural gas rigs, which was also up by 28 natural gas rigs from the 90 natural gas rigs that were drilling during the same week a year ago, but still only 7.3% of the modern high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…this week also saw the startup of a new rig drilling vertically in Mercer county North Dakota that Baker Hughes has classified as 'miscellaneous', which i'm told is for a well intended to store CO2 emissions from an area ethanol plant....that lone 'miscellaneous' rig thus matches to the 'miscellaneous' rig count of 1 a year ago
The Gulf of Mexico rig count was unchanged at 16 rigs this week, with fifteen of this week's Gulf rigs drilling for oil in Louisiana waters and another rig drilling for oil in Alaminos Canyon, offshore from Texas....that's down from the 17 Gulf rigs that were active in the Gulf a year ago, when 15 Gulf rigs were drilling for oil offshore from Louisiana and two were deployed for oil in Texas waters…since there is not any drilling off our other coasts at this time, nor was there a year ago, those Gulf rig counts are equal to the national offshore totals for both years....
In addition to those rigs offshore, we also have 2 water based rigs drilling inland; one is a horizontal rig targeting oil at a depth of between 5000 and 10,000 feet, drilling from an inland body of water in Plaquemines Parish, Louisiana, near the mouth of the Mississippi, and the other is a directional rig drilling for oil at a depth of over 15,000 feet in the Galveston Bay area... this week's inland waters rig count of two is up by one from the single inland waters rigs that was deployed a year ago..
The count of active horizontal drilling rigs was up by 19 to 574 horizontal rigs this week, which was also 218 more rigs than the 356 horizontal rigs that were in use in the US on February 12th of last year, but still 58.2% less than the record 1,374 horizontal rigs that were drilling on November 21st of 2014....at the same time, the vertical rig count was up by 4 rigs to 28 vertical rigs this week, which was also up by 5 from the 23 vertical rigs that were operating during the same week a year ago…on the other hand, the directional rig count was down by 1 to 33 directional rigs this week, but those were still up by 15 from the 18 directional rigs that were in use on February 12th of 2021….
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 February 11th, the second column shows the change in the number of working rigs between last week’s count (February 4th) and this week’s (February 11th) count, the third column shows last week’s February 4th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 12th of February, 2021...
with a 22 rig increase, we may not find details on all of them, but we'll start by checking the Rigs by State file at Baker Hughes for changes in Texas, where we find that two rigs were added in Texas Oil District 8, which encompasses the core Permian Delaware, that four rigs were added in Texas Oil District 7C, which includes the counties of the southern Permian Midland, and that two more rigs were added in Texas Oil District 7B, which includes a couple counties in the far eastern Permian Midland...since that adds up to eight new rigs and the Permian rig count was only up by seven, and since there were no changes evident in New Mexico, that means that one of those rigs in the Permian basin region of Texas was not targeting the Permian..
elsewhere in Texas, there were two rigs added in Texas Oil District 1, another rig added in Texas Oil District 2, yet another rig added in Texas Oil District 3, and also a rig added in Texas Oil District 4 at the same time, any four of which would account for the 4 rig increase in the Eagle Ford shale...since the Eagle Ford saw a natural gas rig pulled out this week while 5 oil rigs were added, that means one of those districts had an offsetting change which doesn't show up in the totals..
meanwhile, the three rigs added in North Dakota were all in the Williston basin, but as we mentioned earlier, one was drilling a well for carbon capture & storage... in Oklahoma, oil rigs added to the Arkoma Woodford and the Ardmore Woodford account for 2 of the state's 3 rig increase, while another rig was added elsewhere in the state targeting a basin that Baker Hughes doesn't track...there were also two rigs added in Utah targeting oil in the Uintah basin, which Baker Hughes doesn't track, and a rig pulled out from southern Louisiana, also from a basin which Baker Hughes doesn't track...
for rigs targeting natural gas, there were three added in Pennsylvania's Marcellus, while a natural gas rig was removed from West Virginia's Marcellus at the same time...there was also a natural gas rig added in a basin not identified by Baker Hughes, while a natural gas was pulled out of the Eagle Ford, where 7 gas rigs and 47 oil rigs remain active..
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Northeast Ohio injection well operator asks state board to allow more powerful earthquakes before required shutdown - cleveland.com — A company that ran a wastewater injection drilling well in Northeast Ohio wants a state board to change certain parameters it was ordered to follow to resume operations, including allowing for more powerful earthquakes before it must shut down. AWMS Water Solutions of Warren is asking the Oil and Gas Commission to amend an order from the Ohio Department of Natural Resources’ Oil and Gas Resources Division for a well on a 5-acre site in Weathersfield Township in Trumbull County, about 70 miles southeast of Cleveland.
Utica Shale Academy to fall short of funding expectations — The latest funding formula will leave the Utica Shale Academy about $120,000 short of expectations in this fiscal year. “We have to keep an eye on spending,” said Robert Barrett, fiscal officer. “We are trying to evolve this program into something that is worthwhile for these kids so that they have a career that they can go into when they graduate.” Barrett said after analyzing the latest school funding figures for the U.S.A., which emphasizes career training and assistance for students needing to recover credits in order to graduate, he has determined the latest funding formula does not take into account the growth the school has seen in the last couple years. The school funding formula for the state is basing numbers on the number of students involved in career tech during the fiscal year 2020, instead of the current enrollment figures in 2022. Barrett said the school only had six to eight kids involved in career tech at that time, but now there are about 70.Barrett said he has questioned if there will be a correction for the school’s growth and told there is not one planned for this fiscal year. During Monday’s meeting, the U.S.A. board approved a resolution to join the GRADS Coalition, which provides schools dropout prevention and recovery schools a voice in Columbus. The school will break ground on an outdoor welding lab in the next few weeks, a steel building that will have lean-to bays of the side where students will be able to learn to weld outside in the elements. Plans are also approved now for the indoor welding lab planned for the basement of the Utica Shale Academy school housed in the Hutson Building. Watson also talked about future equity grants for next year with the continued symbiotic relationship with Southern Local and the potential partnership in the works with someone in the northern part of the county, but declined to further name the organization.
Boone Co. residents concerned after vandalism causes oil leak into river --An act of vandalism is causing oil to spill into the Pond Fork River in Boone County. Firefighters say the tank that was vandalized help up to 5,000 gallons of oil inside and it is currently unknown how much oil escaped from the tank. G.W. Davis lives at the mouth of Jack Branch Road less that a mile from the transformer substation. “I had no idea they had anything with oil or whatever,” said Davis. He said he did not know there was oil in the tanks of an old transformer substation. Saturday he grew concerned when he saw fire trucks driving by in the afternoon, but said he did not know what they were doing. Boone County firefighters said they went up to check the substation owned by Lexington Coal Company after a person came forward and said they could see oil sheen on the Pond Fork River. Firefighters said they found out the station had been vandalized. The gate to a 5,000 gallon oil tank had been cut and the valve to the tank had been turned to let oil leak out. “There is always shady people coming in and out of here plus they can come in from another way besides this way,” said Davis. The West Virginia Department of Environmental Protection was called out to investigate. Officials with the DEP said the tank contained mineral oil inside and when it was vandalized that oil spilled into a sediment pond nearby. Firefighters say the oil also leaked into the Pond Fork River. A spokesperson with the DEP said no sheen or residue was visible and no fishkill had been observed
Unclear who is investigating oil leak and vandalism; community activist speaks out - Oil sits on top of the areas where the water pools on the Pond Fork River.Maria Gunnoe is the director of a non-profit, Mother Jones Community Foundation, with a long list of awards for community activism in West Virginia. She has been capturing the oil leak the only way she can which is on video.“I have seen a very clear sheen of oil and oil substance I’ll call it, on the river and it has a very pungent smell to it,” said Gunnoe.Boone County firefighters, including the Van Fire Department, said they got a call from a concerned person Saturday afternoon when they also saw the sheen on the river. “It’s everywhere that I know, from Bull Creek up in and through Madison. Every place that the water slows down, this is puddling up,” said Gunnoe.Firefighters traced the leakage back to this transformer substation in the Jack’s Branch area.They found the gate to the station cut open and the valve on a 5,000-gallon oil tank turned on and with oil flowing straight out with very little left.The West Virginia Department of Environmental Protection said the act of vandalism released mineral oil from the tank. While looking out at the rainbow colored ripples, Gunnoe thinks of the kids she teaches to fish in these waters.“Then I hear that it is mineral oil, it’s only mineral oil, and everything should be fine. I don’t agree with that and I would like full disclosure on it because our kids recreate in this water. We fish, we eat the fish, and we need to know,” said Gunnoe.Boone County dispatch said no law enforcement was ever dispatched to the call, although EMS, fire, emergency management and the WV DEP were called out.WSAZ followed up with both the Boone County Sheriff’s Office and the West Virginia State Police. Neither said they are part of any investigation. Gunnoe lives five miles from where the spill happened. With her experience, she said this is one of the worst spills she has seen. “That substation is not well secured, so anyone can go up in there. Anyone could have got into it and done the damage that has been done to our stream,” said Gunnoe. The DEP said the Madison Fire Department put mats down at the substation to contain the oil near the tank.
State could develop natural gas property tax rule - — A bill considered by the House Finance Committee on Monday afternoon would give the State Tax Department another try at developing a rule for determining tax assessments for natural gas-producing property in West Virginia. The committee recommended House Bill 4162 for passage, authorizing the State Tax Department to promulgate a legislative rule relating to valuation of property that produces oil, natural gas, and natural gas liquids. It also states the legislative rule previously filed by the State Tax Department is not authorized. HB 4162 comes nearly one month since the West Virginia Legislature’s Rule-Making Review Committee moved to not approve an earlier legislative rule submitted by the State Tax Department last summer regarding assessments of natural-gas producing property. House Bill 2581, passed during the 2021 legislative session, required the State Tax Commissioner to develop a revised methodology to value oil and natural gas properties based on the fair market value based on a yield capitalization model applied to gross royalty payments for royalty interest to net proceeds once royalties and annual operating costs are subtracted from gross receipts. Instead, the emergency rule and the draft rule developed by the State Tax Department lowered the capitalization rate, eliminated the use of a three-year weighting, and left it up to the State Tax Department to use its own reasonable standard, which is undefined in the rule itself instead of the actual revenues and expenses of the producer. By not approving the agency-submitted rule in January, the emergency rule submitted by the State Tax Department remains in place for tax year 2022. Both the emergency rule and the final rule proved to be unpopular with lawmakers, county assessors, and representatives of the natural gas industry. The original version of last year’s HB 2581 would have resulted in a $9.1 million property tax revenue loss to county governments and county school systems, with $7 million of that cost hitting eight counties in the Northern Panhandle and North Central West Virginia.
Federal Court Rejects Mountain Valley Pipeline Permit - A federal court in Virginia has struck down a proposed permit for the Mountain Valley Pipeline, siding with environmental groups who said the project would threaten endangered wildlife and habitat.The pipeline would run more than 300 miles, transporting natural gas through eleven counties in West Virginia and neighboring states. The decision is the second rejection by a federal court over permitting for the pipeline's construction.Cindy Rank, chair of the extractive industries committee for the West Virginia Highlands Conservancy, one of several groups behind a lawsuit against the pipeline, said it would cross many of the state's headwater streams, both large and small."And the impact on both of those is going to be a tremendous amount of sedimentation," Rank explained. "Both from the construction sites on either side of the stream if you're going to drill under; and the actual in-stream degradation as you're blocking up one side and digging up another side to put that pipeline down."High levels of sediment can disrupt ecosystems, harm fish, and increase algae blooms. The interstate pipeline would be owned and operated by Mountain Valley Pipeline, LLC, a joint venture between several energy companies, and regulated by the Federal Energy Regulatory Commission. On its website, the company said it has provided funding to preserve land and remains dedicated to ongoing environmental preservation efforts.Rank argued a decision last December by the West Virginia Department of Environmental Protection (DEP) to issue awater quality certification failed to consider the pipeline's potentially harmful impacts to wildlife and the environment."Because we believe that certification is based on fallacies," Rank asserted. "DEP did not consider everything they needed to consider, before determining that this would not violate water-quality standards."She believes it would be a mistake to tie West Virginia into more fossil fuels, at a time when the nation is focused on creating a sustainable renewable-energy infrastructure."But now is the time to make those changes," Rank contended. "To solar, to wind, to other options that don't have as big a carbon footprint. And in fact these permits are supposed to take that kind of future impact into account." According to the Center for Biological Diversity, the pipeline has been required to pay millions of dollars in fines for more than 350 water-quality related violations in Virginia and West Virginia.
Future of Mountain Valley Pipeline clouded by court decisions -- For four years now, the half-mile hike from David Seriff’s front door to a ridgetop has offered the same vista: a 125-foot-wide trough plowed up one side of the mountain and down the other. Along the route, segments of an unfinished natural gas pipeline lie in a state of suspended animation. A federal appeals court recently rejected two government permits that are needed to complete a massive infrastructure project that opponents say is an environmental train wreck. On Friday morning, as he stood on the windswept ridge, Seriff’s outlook had not changed. “I think it’s another nail in the coffin,” he said of the 4th U.S. Circuit Court of Appeals’ Jan. 25 reversal of a permit allowing the pipeline to pass through the Jefferson National Forest, which abuts his home north of Blacksburg. A second ruling last Thursday invalidated a finding that endangered species would not be jeopardized. “But we haven’t killed the beast.” If the complex regulatory and legal proceedings that have enveloped the 303-mile pipeline since 2018 could be reduced to a simple baseball analogy, Mountain Valley has two strikes against it. Three sets of key permits — the U.S. Forest Service’s approval for the buried pipe to cut through 3.5 miles of public woodlands, the U.S. Fish and Wildlife Service’s finding that it would not destroy the habitats of endangered species, and the U.S. Army Corps of Engineers’ green light for Mountain Valley to cross streams and wetlands — have each been struck down twice by the Fourth Circuit. Mountain Valley is still swinging, though. “With total project work nearly 94% complete, Mountain Valley remains committed to meeting Americans’ energy needs and completing this pipeline,” company spokeswoman Natalie Cox wrote in an email Friday. “The MVP has undergone an unprecedented level of review, and rigorous analysis has repeatedly demonstrated that this project can in fact be built safely and responsibly. “ If the pipeline is to survive, government agencies must again rewrite permits to satisfy the Fourth Circuit — which has been perhaps the biggest challenge for developers since they first announced the project nearly a decade ago. “MVP is now highly unlikely to enter service in 2022, in our view, and the in-service date could be pushed into 2024 depending on how the court’s concerns are addressed,” Height Capital Markets, an investment banking firm that has followed the project, said in a written commentary last week. Of the two most recent decisions, the reversal of a biological opinion that found no jeopardy to two endangered fish — the Roanoke logperch and the candy darter — was seen as the more troubling for Mountain Valley. In its “non-legal expert” reading, Height said the Fourth Circuit appears to have extended the scope of the Endangered Species Act “to include a standard that would be difficult for most new infrastructure projects to meet.” Judge James Wynn wrote in a unanimous opinion from a three-judge panel that the Fish and Wildlife Service failed to adequately consider two things: the environmental baseline of the two imperiled fish and the cumulative effects of future events, such as climate change. “We recognize that this decision will further delay the completion of an already mostly finished pipeline, but the Endangered Species Act’s directive to federal agencies could not be clearer: halt and reverse the trend toward species extinction, whatever the cost,” the 40-page opinion concluded.
EQT Considers Selling More Shares in MVP Sponsor as Uncertainty Plagues Project -EQT Corp. now expects the Mountain Valley Pipeline (MVP) to come online in 2023, which could help narrow its natural gas price differentials and ease Appalachian takeaway constraints, but management acknowledged Thursday that the “specter of timing” continues to loom over the project. EQT has capacity booked on the system and a stake in MVP’s lead sponsor Equitrans Midstream Corp, which expects the project to start up this summer. Equitrans is reviewing that timeline after a federal appeals court last week vacated MVP’s Endangered Species Act authorizations and set back construction further. The 303-mile, 2 Bcf/d system would move more Appalachian natural gas from West Virginia to the Southeast. EQT’s fourth quarter investor presentation assumes a mid-2023 start-up for MVP.The pipeline has been dogged by regulatory delays. EQT CFO David Khani said during a call on Thursday to discuss year-end results that the company sold some of its shares in Equitrans during the fourth quarter and would consider selling more as the stock has declined. “We’ll be thoughtful in when we want to sell them again,” he said. EQT, the nation’s largest natural gas producer, reported higher average realized prices for 2021 of $2.50/Mcfe, up from $2.37 in the prior year. Those gains were offset by wider differentials, however, as pipeline constraints in the Northeast have dented the realizations of Appalachian producers. CEO Toby Rice said high energy prices in New England are the direct result of takeaway issues in Appalachia. He also cautioned that a rapid energy transition and resistance to natural gas projects in places like Europe have led to higher energy costs as well.. “It’s relevant to the people in the southeast United State. You need to understand there is a pipeline that is going to allow you to benefit from low cost, reliable, clean energy, and this is something that people need to be aware of, because what’s happening in Europe, what’s happening in New England, starts with the things right now happening to MVP.” Rice said his team has been working to get a stronger grip on what they can control. EQT reported steep losses on hedges last year as prices crept upward. However, Rice said the company has started implementing an updated hedging strategy that “provides downside protection, while leaving large-to-upside exposure to higher natural gas prices.” CFO David Khani noted that the company has paid off more debt, allowing it to “switch from a defensive hedging strategy with nearly all swaps to a more balanced approach” for 2023. The company has about 65% of its production volumes hedged for 2022 and another 42% hedged next year. EQT has layered on an overall floor of $3/Dth and a ceiling of $5/Dth in 2023. Management also guided for 2022 capital expenditures (capex) of $1.3-1.45 billion to produce between 1.95-2.05 Tcfe. Guidance was higher than last year’s capex of $1.1 billion and above Wall Street consensus. Inflationary pressures and incremental spending for a new well design are likely to push spending higher this year. Management said the company would phase in a “next generation” well design in 2022 that’s been under development for the past year. Preliminary results from those wells are expected by the end of the year. EQT produced 527 Bcfe in the fourth quarter across its Marcellus and Utica shale assets in Ohio, Pennsylvania and West Virginia. That’s up from 401 Bcfe in 4Q2020. Full year production was 1.9 Tcfe, up from 1.5 Tcfe in 2020. Rising volumes were the result of EQT’s acquisition of Alta Resources Development LLC and Appalachian assets it purchased from Chevron Corp.
Big Oil Has a Plan to Turn Appalachia Into Hydrogen Country - - The fossil fuel industry has a new plan for Appalachia: Blue hydrogen. An alliance between some of the largest corporations in the energy business—Shell, General Electric Gas Power, EQT Corporation, Equinor, Mitsubishi, US Steel and Marathon Petroleum—announced in a press release late last week their plan to create a “hydrogen industrial hub” in Ohio, Pennsylvania, and West Virginia. Their plan is to work with local stakeholders in the process, creating “a national model for sustainable energy and production systems.” The companies are putting their faith in an element that’s gained traction as an energy form in recent months, as the bipartisan infrastructure bill includes billions of dollars to build out clean hydrogen energy development. Hydrogen is also the most abundant element in the universe, existing in water, alcohols, and the like. Producing hydrogen as an energy source requires separating H atoms from other elements in the molecules where it naturally occurs (so, removing the H from H2O, for example). This is most commonly done commercially using steam to separate hydrogen from methane in natural gas; the finished product is referred to as ‘blue hydrogen,’ because it is emissions-free when burned, but is made with polluting sources of energy. Matt Kelso, manager of data and technology at the non-profit environmental watchdog FracTracker Alliance told Motherboard he sees the investment in hydrogen as “an extension of the existing polluting industries, by the exact same companies that are polluting our air, land, and water today.” “It is an excuse to keep drilling, obfuscated under a new identity, in an environment where there is increasing awareness of the damages that oil and gas extraction has caused to the region,” said Kelso, who lives in Pittsburgh, near southwest Pennsylvania’s oil and gas hub. The plan will capitalize on the region’s natural gas stores, largely trapped in the Marcellus Shale geologic formation, … Actual job numbers paled in comparison to those promised. A 2021 economic analysis by the non-profit think tank Ohio River Valley Institute found that jobs in Appalachian fracking counties climbed by merely 1.6 percent in the 2010s, compared to the 450,000 jobs that industry estimates from the early 2010s laid out. It also led to an oversupply of natural gas that the industry is now trying to offload (most notably by pushing plastics). The companies are positioning the move as an environmentally-sound one, or a way to achieve “aggressive net zero carbon goals,” . In fact, the fossil fuel industry more broadly has rallied around using carbon capture and sequestration as a technique to eliminate emissions from steam-methane reforming in the hydrogen production process. These emissions are substantial. An August, 2021 report out of Cornell and Stanford Universities found that the carbon footprint that comes with creating blue hydrogen is 20 percent larger than that of burning natural gas and coal for heat and 60 percent greater than burning diesel oil for the same purpose.Thus, carbon capture and storage—in which carbon dioxide is collected at the source of emissions and shot underground into stores—is essential to the fossil fuel companies’ plan if it is to be ‘net zero.’ But CCS comes with its own set of risks; pipelines carrying captured carbon have, in the past,exploded, and in the Marcellus Shale, where oil and gas wells, manyabandoned, dot the landscape, shooting it underground could prove geologically risky — pressure from two wells interacting could lead to explosions.)
‘There’s no closure’: 12 years after deadly Kleen Energy plant explosion, lawsuits drag on --On a snow-covered morning in February 2010, workers at the Kleen Energy plant under construction in Middletown were attempting to clear any remaining debris from the network of pipes by using the force of roughly 480,000 gallons of natural gas — enough to fill more than five Olympic swimming pools. What exactly caused the cloud of gas to ignite was never determined, though investigators would later point to several possible sources. The resulting explosion killed six workers and injured more than 50, while leading to new national standards that called on companies to stop the use of flammable natural gas in so-called “gas blows.” But as friends and family members of the victims along with the survivors marked the 12-year anniversary of the explosion on Monday, some are still engaged in a drawn-out legal battle seeking to hold the operators of the plant responsible for the disaster. “They’ve accepted no responsibility,” said Paula Dobratz, whose husband Raymond was among those killed in the powerful blast. “Think of how long they’ve had to fight also with their attorneys for 12 years to make sure that the rest of the people that have cases against them get nothing and still have to wait,” Dobratz said. “There’s no closure.” In the years following the explosion, New Haven attorney Joel Faxon has represented the Dobratz family along with roughly a dozen injured workers in a series of lawsuits related to the disaster. Most of their claims, Faxon said Monday, have proceeded through the courts as part “test cases” brought on the behalf of two injured workers. In December, the Connecticut Supreme Court dismissed the latest part of that effort, finding that the plant's operator, Kleen Energy Systems, lacked sufficient control over the independent contractor in charge of construction to be held liable for the explosion. The court’s decision follows its own earlier ruling in 2016, finding that the contractor, O&G Industries of Torrington, had already paid worker’s compensation benefits and was immune from having to pay further damages. The decisions have left the victims and their families with just two pending claims against Kleen Energy related to the inherent dangers of using flammable gas to clean piping equipment, Flaxon said.
New gas plant for electrical co-ops draws fire, highlights bumpy path to renewable energy -The natural gas-fired Magnolia Power Generating Station proposed for Iberville Parish would be an important cog in a plan by five rural Louisiana electrical cooperatives to provide reliable, cheap electricity through 2045, backers say. Its critics have concerns. State utility regulators recently gave their nod to thegroundbreaking 20-year power plan for the co-ops' 119,000 customers that, in addition to Magnolia Power, would count on renewable energy in a big way. Under the new deal, more than a third of the power would come from renewable sources, but local environmental groups say the plan isn't doing enough with renewables given the grave threat that global climate change poses for south Louisiana. Building a new $750 million fossil fuel-reliant power plant, these critics say, would contradict the central goal of Gov. John Bel Edwards' climate task force — net zero carbon emissions by 2050 — by permitting a new greenhouse gas emissions source and potentially locking in those emissions through 2045. Though the financial backers of the plant say it could be switched to hydrogen fuel that they argue would be carbon-free, these critics say the details of when and how that switch would happen are vague and not included in regulatory filings. "We're saying they should go all renewable, and, if they've got to go with this natural gas plant, they need to really seriously talk about reducing emissions from the plant and ... give us details about this idea that they're going to go 100% hydrogen, a fuel that no place in the world is currently doing 50%," said Darryl Malek-Wiley, a senior organizing representative for the Sierra Club in New Orleans. "It's a test plant, and we don't know what that involves." Under Edwards, Louisiana has proposed a rarity for the Deep South: a plan to cut the state's fossil fuel emissions either by eliminating those sources, offsetting them or storing them underground in a bid to slow global climate change. A scientific consensus has concluded that emissions from burning fossil fuels is sending more heat-trapping gases into the atmosphere. The gases are raising overall global temperatures and setting off dynamic changes to the climate, ice caps and glaciers that are inducing sea level rise, according to the United Nations Intergovernmental Panel on Climate Change. Much of south Louisiana could see 1.5 feet of sea level rise by 2050 and, in the worst case, up to 7 feet by 2100, the IPCC found.
Gas pipeline constraints showing along East Coast, manufacturers say - Limited capacity on natural gas pipelines is driving up gas prices for U.S. manufacturers, making it tougher to compete with low-cost manufactures abroad, the trade group Industrial Energy Consumers of America said in a letter to members of Congress Wednesday.The group, which represents U.S. manufacturing and industrial firms, said pipeline companies were putting strict limits on gas flows to maintain system stability. They said increased demand from natural gas-fired power plants and liquefied natural gas export facilities, centered along the Texas and Louisiana Gulf Coast, had resulted in less available pipeline capacity for manufacturing. "New pipeline capacity is not getting built," said Paul Cicio, president of IECA. "Inadequate pipeline capacity impacts existing manufacturing facilities and is detrimental to new investments and job creation." In his letter, Cicio specifically cited the use of what are known as operational flow orders along the Transco pipeline, which runs along the Gulf and Atlantic coastlines between Houston and New York. He said gas prices where the pipeline runs through Virginia and North Carolina averaged $11.37 per million British thermal units in January - more than double the U.S. benchmark Henry Hub - and at one point exceeded $21."We've seen some cold weather over the last several weeks, from Boston all the way down to Atlanta, and demand has been really high," said Scott Hallam, senior vice president at Williams Co., which operates Transco. "We're seeing differences in pricing regionally. Henry Hub is trading around $4 but you get to New York it's $10 to $15. In Boston it's $30. That's the challenging consuming sectors like manufacturing face." Under an operational flow order, buyers and sellers must tell pipeline companies nearly exactly how much gas they are transporting. If they're wrong, they must pay a steep financial penalty that can far exceed the cost of the gas they're buying.
The natural gas industry is ready for a net-zero future — as long as it still includes pipelines -Every minute, a new customer is hooked up to the natural gas system, says Karen Harbert, president of the American Gas Association, or AGA, the primary trade association for U.S. gas utilities. Today, that’s a major problem for the climate. Leaks are common throughout the natural gas system, from wells, pipelines, and appliances, and they release the powerful greenhouse gas methane into the atmosphere. When natural gas is ultimately burned in a heater or stove, carbon dioxide is emitted. All told, residential and commercial use of gas was responsible for about 10 percent of U.S. emissions in 2019. In colder parts of the country that rely primarily on natural gas heating, it makes up a much larger portion of emissions.But at a press conference on Tuesday, Harbert told reporters that the natural gas system can grow by 24 percent over the next three decades while at the same time becoming cleaner, and eventually not contribute to climate change at all. That’s the key finding of the AGA’s new “Net-Zero Emissions Opportunities for Gas Utilities” report.The report comes as many cities and states with climate goals are passing policies and creating incentives to staunch the tide of new natural gas users by encouraging people to install appliances that can run on clean electricity, like heat pumps and induction stoves. The shift threatens gas utilities’ bottom line, and the industry is pushing for solutions that utilize their existing infrastructure. The AGA report outlines four potential pathways that gas utilities could follow to zero out their emissions by 2050. All four would require a radical transformation of the industry, with the amount of energy supplied by fossil natural gas dropping from 12 quadrillion British thermal units today down to 1 quadrillion or less by mid-century. All the pathways feature a similar set of solutions but vary in how much they rely on each one. The AGA is proposing that utilities reduce their energy demand through energy efficiency programs; repurpose the existing pipeline system to deliver alternative gases that have a lower (but not zero) carbon footprint, like biogas or a blend of natural gas and hydrogen; build new pipelines in select areas that can carry pure hydrogen; and ramp up leak detection and pipe replacement programs to reduce methane emissions. The AGA also sees carbon capture playing a role to cut emissions from natural gas use in the industrial sector and in the production of hydrogen. All four of the industry group’s pathways rely on carbon capture and carbon offsets to eliminate the last 8 to 14 percent of gas utilities’ current emissions.
U.S. natgas drops over 7% on less cold forecasts, rising output (Reuters) - U.S. natural gas futures fell over 7% to a near two-week low on Monday, keeping volatility at record highs for a third day in a row, as output slowly recovers from last week's freezing weather and on forecasts for less cold and lower heating demand over the next two weeks than previously expected. Over the past month, trade in gas futures was the most volatile on record due in part to worries that Winter Storm Landon, which battered the eastern half of the country last week, would cut output and boost heating demand like last February's Winter Storm Uri. But Landon - with just one day below freezing in the West Texas Permian basin - was much weaker than Uri, which froze West Texas for eight days in a row. Uri killed more than 200 people in Texas, caused power and gas prices to soar to record highs in many parts of the country and left millions of homes and businesses without heat and power for days after gas pipes and power plants froze, cutting as much as 17.4 billion cubic feet per day (bcfd) of gas output. Front-month gas futures for March delivery on the New York Mercantile Exchange (NYMEX) fell 34.0 cents, or 7.4%, to settle at $4.232 per million British thermal units, their lowest close since Jan. 25. During a period of record volatility for NYMEX futures ahead of Landon, U.S. speculators last week boosted their net long futures and options positions on the NYMEX and Intercontinental Exchanges to the highest since October 2021 by cutting their NYMEX shorts by the most in a week since February 2021, Data provider Refinitiv said output in the U.S. Lower 48 states fell from a record 97.3 bcfd in December to 93.9 bcfd in January and 89.9 bcfd so far in February after wells in several regions froze, including the Permian in Texas and New Mexico, the Bakken in North Dakota and the Appalachia in Pennsylvania, West Virginia and Ohio. With less cold expected, Refinitiv projected average U.S. gas demand, including exports, would drop from 130.3 bcfd this week to 119.8 bcfd next week. Those forecasts were lower than Refinitiv's outlook on Friday. The amount of gas flowing to U.S. liquefied natural gas (LNG) export plants was on track to rise from a monthly record of 12.4 bcfd in January to 12.7 bcfd in February as liquefaction trains at Venture Global LNG's Calcasieu Pass export plant in Louisiana enter service. A vessel arrived near Calcasieu on Monday and may be the first to pick up LNG from the plant.
U.S. natgas falls over 5% to 2-wk low on rising output, less cold (Reuters) - U.S. natural gas futures fell over 5% to a two-week low on Wednesday as output slowly increased after weeks of reductions from freezing wells and on forecasts for slightly less cold weather and lower heating demand than expected in the next two weeks. After weeks of near record volatility, front-month gas futures for March delivery fell 23.9 cents to settle at $4.009 per million British thermal units (mmBtu), their lowest close since Jan. 21. The American Public Power Association (APPA) industry trade group said it asked the U.S. Commodity Futures Trading Commission (CFTC) to investigate natural gas trading activity on Jan. 27 when prices spiked by a record 46%. In the spot market, frigid weather and high heating demand in the U.S. Northeast have kept next-day power and gas prices in New York and New England at or near their highest levels since January 2018. Those high prices have made it economic for the region's power generators to burn lots of expensive oil and liquefied natural gas (LNG) this winter. Data provider Refinitiv said output in the U.S. Lower 48 states fell from a record 97.3 billion cubic feet per day (bcfd) in December to 93.9 bcfd in January and 90.8 bcfd in February after wells in several producing regions froze, including the Permian in Texas and New Mexico, the Bakken in North Dakota and the Appalachia in Pennsylvania, West Virginia and Ohio. Output has been rising almost daily since it dropped to 86.3 bcfd during a winter storm on Feb. 4, its lowest since February 2021. With the cold weather moderating, Refinitiv projected average U.S. gas demand, including exports, would drop from 130.0 bcfd this week to 122.6 bcfd next week. The forecast for this week was lower than Refinitiv's outlook on Tuesday. Traders said demand for U.S. LNG would remain strong so long as global gas prices keep trading well above U.S. futures as utilities around the world scramble for cargoes to meet surging demand in Asia and replenish low inventories in Europe - especially with the threat that Russia could invade Ukraine and cut gas supplies to Europe. Russia provides 35%-40% of Europe's gas supplies, totaling about 16.3 bcfd in 2021, according to analysts and U.S. energy data. Gas futures traded around $25 per mmBtu in Europe and Asia, compared with just $4 in the United States. But no matter how high global prices rise, the United States only has capacity to turn about 12.4 bcfd of gas into LNG. The rest of the gas flowing to LNG facilities is used to run plant equipment.
US natural gas storage fields draw more than 200 Bcf for fourth straight week | S&P Global Platts -- US natural gas storage volumes fell by more than 200 Bcf for the fourth week, but milder weather could slow withdrawals in the weeks ahead as the Henry Hub summer strip remains above $4/MMBtu. Storage fields withdrew 222 Bcf for the week ended Feb. 4, according to US Energy Information Administration data released Feb. 10. The pull was well within and barely above the 221 Bcf draw an S&P Global Platts survey of analysts expected. Responses to the survey were withdrawals in a 211-235 Bcf range. The drawdown outpaced the five-year average of 150 Bcf and the 174 Bcf pull in the corresponding week a year ago. Working gas inventories fell to 2.101 Tcf. US storage volumes now stand 441 Bcf, or 17.3%, below the year-ago level of 2.542 Tcf and 215 Bcf, or 9.3%, below the five-year average of 2.316 Tcf. As recently as mid-January, stocks sat at a slight surplus to the five-year average. The first two months of the heating season held mild weather and higher US production. But fundamentals changed significantly in early 2022 on a mix of lower US population-weighted temperatures, production declines, and strong LNG exports. The NYMEX Henry Hub March contract slid 3.5 cents to $3.97/MMBtu following the release of EIA's storage report. The upcoming summer strip fell 2.5 cents to average $4.04/MMBtu. Significantly stronger demand, coupled with lower production, has pulled hard on US storage inventories during January and into February, lowering expectations for the end-of-winter inventories to 1.65 Tcf, 10 Bcf below five-year levels. Tighter balances in January pushed the NYMEX Henry Hub 2022 curve to $4.03/MMBtu as of Jan. 25, 12 cents above the current Platts Analytics forecast of $3.91/MMBtu, from a low of $3.62/MMBtu Dec. 23. A Platts Analytics forecast calls for a 190 Bcf draw for the week ending Feb. 11, which would increase the deficit to the five-year average by 36 Bcf. However, an early forecast for the week ending Feb. 18 shows a pull about 30 Bcf smaller than average. Total US demand fell 5.6 Bcf/d Feb. 9 to 113.5 Bcf/d. US residential-commercial demand fell 4 Bcf/d while US power burn fell 1.7 Bcf/d as average US population-weighted temperatures climbed nearly 2 degrees. The Rockies was the only region to see an increase in res-comm demand, up 0.4 Bcf/d, as population-weighted temperatures fell more than 4 degrees in the region. Power burn declines were concentrated in the Southeast, which was down 1 Bcf/d. The Upper Midwest and the Northeast each saw a 300 MMcf/d decline in power burn. Total US supply was flat on a net basis, as a 700 MMcf/d increase in US production was offset by a 500 MMcf/d decline in Canadian imports and a 200 MMcf/d decline in LNG imports.
Natural Gas Futures Extend Losses as Storage Deficits Seen Stalling; Northeast Cash Surges on Storm - Roses are red and so were natural gas futures on Friday as selling action continued along the Nymex curve. A steadily warming February forecast proved too much for bulls to overcome, with the rising temperatures likely preventing a much deeper drawdown of storage inventories heading toward the end of the traditional withdrawal season. The March Nymex contract closed out the week at $3.941/MMBtu, off 1.8 cents on the day. April slipped only eight-tenths of a cent to $3.935. Spot gas prices, however, managed to move back into the black as a strong winter storm moved into the Lower 48. Led by $10-plus gains in the Northeast, NGI’s Spot Gas National Avg. climbed 94.0 cents to $4.630. The latest cold blast stretching across the eastern half of the country is expected to give a major jolt to gas consumption after a multi-day period of springlike weather and tepid heating demand. Forecasters expected the winter storm to pack a punch from the Mid-Atlantic to New England, sending temperatures tumbling and setting the stage for several inches of snow. However, after climbing close to 60 degrees in the region on Saturday, AccuWeather said the recent warmth may help to limit accumulations when snow begins to fall on Saturday night and into Sunday. Since the air could take some time to cool, it is possible that rain may be part of the wintry mix. AccuWeather meteorologists expected up to three inches of snow to fall from the West Virginia and North Carolina mountains, northeastward through much of Delaware, Maryland and Virginia. The snow then is forecast to move into central and southern New Jersey, Long Island, New York and southeastern New England. There also could be a pocket of moderate snow – up to six inches – in parts of Virginia. The frosty air was expected to push well into the southern United States, too, with the coldest day expected to be Monday before a warmup begins midweek. Although another cold shot is expected the following weekend (Feb. 18-20), the long-range weather data show increasing odds that the coldest winter weather is now in the rearview mirror.
Bechtel To Start Construction Of $30B Driftwood LNG Plant In April - U.S. LNG project developer Tellurian has stated that the construction of its Driftwood LNG export facility will begin in April 2022. The total cost of the project, designed to produce 27.6 million tons per annum of LNG, is near $30 billion while $12 billion are needed just to complete Phase 1 of the Driftwood LNG facility, which will be located on the Calcasieu River, south of Lake Charles, Louisiana, and it will only take several years to pay this cost back. Driftwood already has a $15.5 billion turnkey engineering, procurement, and construction contract with Bechtel in place that guarantees cost, performance, and schedule. The dal was agreed back in 2017. The first phase will consist of two plants, each with up to four liquefaction trains. According to Tellurian, this will create about 400 direct jobs and 6,500 construction jobs. Tellurian has already invested around $150 million and purchased some 1,000 acres of real estate ensuring a construction site for the project. Each Driftwood LNG plant is expected to have up to four liquefication trains, for a total design capacity of as much as 27.6M mt/year. The facility will have an annual capacity of 550 bcf once Phase 1 is complete. The first delivery could take place in 2026. Charif Souki, executive chairman of Tellurian and frequently referred to as 'the Godfather of LNG', said in a YouTube video the company posted on its website that it signed 10-year deals with Shell, Guvnor, and Vitol for 9 million tons of gas and that this justified beginning work on the first phase of the scheme. He confirmed that construction would start in April 'as promised.' "We have access to enough capital to make sure we can do the first year of construction," Souki said. He added that Tellurian was attempting to arrange financing with 45 different lenders, which was "like herding cats". "It is critical to get it right for the value of the shareholder, so we're not going to rush through that process," Souki said in his latest public message. "We're very comfortable starting the construction program without being completely sure that the financing will be put in place." "We now have a number of banks that are willing to consider a project like this. We feel very confident and comfortable that this will be done," he concluded.
Growing U.S. LNG Output Has Influenced Global Logistics, Pricing - The first wave of LNG projects has done more than just catapult the U.S. to the top tier of LNG exporters, it has reshaped markets, helped move LNG closer to being a true global commodity, and spurred changes in everything from ship sizes and routes to contract types and pricing formulas. Talk about having an impact! And, with new projects still coming online in the U.S. and final investment decisions expected on new terminals and expansions this year, the U.S. LNG industry’s effect on the global gas trade is sure to grow. In today’s RBN blog, we look at the practical impacts that have accompanied growing U.S. production with an emphasis on logistics and, perhaps most important, the changes to LNG pricing in Asia. U.S. LNG export growth has exceeded that of any other nation over the past few years, moving from zero at the start of 2016 to more than 80 million tons per annum (MMtpa; 10.6 Bcf/d) with Venture Global’s Calcasieu Pass facility about to load its first cargo, as we described in Part 1 of this blog series. In Figure 1 below, you can see that the U.S. (blue segments) has been on a tear, shifting from minor player to global leader in only six years. Meanwhile, of the other two major LNG-producing nations, Qatar’s LNG exports (gray segments) have remained close to static since the mid-2010s (though it’s planning a big expansion by mid-decade — see our recent blog on that), and Australia (orange segments), up until this year, had been a step ahead of the U.S. in adding new capacity. The U.S.’s quick rise has had a number of significant effects on everything from the size of the global LNG carrier fleet to how the expanded Panama Canal is being used and — as we’ll get to in a minute — how LNG is priced. We’ll discuss these one by one. The rise of U.S. LNG has had a significant impact on shipping, one that has largely gone unnoticed by casual observers. U.S. projects are located farther from the major consuming markets in Asia than their primary competitors (Qatar and Australia), which has resulted in the need for a lot of new shipping capacity to move the produced volumes — the longer the voyage, the more time that vessel is unavailable for other shipments. However, it hasn’t been an easy transition to a higher-volume era. In the early 2010s, when project sponsors such as Cheniere announced their intentions to produce LNG in the U.S., independent shipowners including Golar, Thenamaris, GasLog, and Cardiff placed speculative orders for new LNG carriers with capacities of 155,000-165,000 cubic meters (cm). But shipowners misjudged the situation and struggled to find employment for vessels in a market of depressed charter rates, which led to the formation of the “Cool Pool” in August 2015, whereby GasLog, Golar, and Dynagas pooled 14 of their new LNG carriers to seek spot-market employment. Shipowner hopes that offtakers of U.S. LNG would offer long-term employment of their new vessels also proved to be overly optimistic as LNG buyers JERA, Mitsui, Mitsubishi, and Kogas opted instead to commission and charter newbuild vessels from other shipowners with whom they had longstanding relationships. Over the longer term, though, the willingness of the independent owners to invest in speculative vessels has proved to be a boon to the LNG market and reflects another element of LNG’s gradual commoditization: commodity markets are characterized by ready access to transportation.
Increased U.S. natural gas exports = higher U.S. prices: Who knew? -- Few people noticed when energy reporters wrote in early January that the United States had become the world's largest exporter of liquefied natural gas (LNG). Now, a group of U.S. senators has noticed and say those exports may be driving up heating and electricity costs for their constituents. In a letter to the secretary of energy, they are asking the secretary "to conduct a review of LNG exports and their impact on domestic prices and the public interest, and develop a plan to ensure natural gas remains affordable for American households." Who knew that exporting natural gas from American gas fields would raise natural gas prices at home? Well, the natural gas industry certainly knew. In the last decade, the industry was smarting under persistent low prices as it continually overproduced gas into a flooded domestic market. It pushed for and succeeded in relaxing rules for exports and expedited approvals of new export cargoes and facilities. The U.S. Department of Energy still has de facto control over most natural gas exports. But policy in the last five years has been to assist and encourage expansion of those exports. The industry has always contended that there would be plenty of gas to go around because of the extraordinary growth in gas production from deep shale deposits that new technology can now extract. But the revolution seems to have stalled as marketed U.S. natural gas production has hit a plateau around 3 trillion cubic feet per month since late 2018. Prices have not been favorable until recently, and investors have fled the industry as they realized that negative free cash flows for practically the entire previous decade were not likely to turn around. That has meant less money for drilling with a predictable result: stagnant production. So, stagnant production has now collided with growing LNG exports. The latest numbers available from November 2021 show that LNG exports now constitute 9.7 percent of all U.S. marketed production. As recently as November 2015 those exports constituted a tiny 13/100ths of a percent of total domestic production. The raw numbers show an increase from a little under 3 billion cubic feet of LNG exports for November 2015 to 306 billion for November 2021. The industry makes the point that practically everything else America produces can be exported freely and so is priced based on world prices. Why then should natural gas be singled out? Shouldn't natural gas producers have the same opportunity to sell their product to whomever they choose as practically every other American business does? If U.S. natural gas prices continue upward, look for this battle between consumers and producers of natural gas to escalate. The U.S. Congress has the power to intervene and rein in exports if it chooses. That fact may become relevant later in the year when voters who heat their homes with natural gas and buy electricity from gas-fired utilities decide who should represent them in Washington.
API: Don’t constrain LNG exports; bolster cold-weather states’ infrastructure Ten 10 U.S. senators from cold-weather states wrote to U.S. Energy Secretary Jennifer Granholm, expressing concern about getting affordable, reliable natural gas for their constituents’ homes and businesses in the dead of winter, the American Petroleum Institute said in an Energy Tomorrow Update on LinkedIn. Instead of supporting increased natural gas production and the construction of natural gas pipelines, processing stations, power plants and other infrastructure, the senators’ proposed solution is to go after U.S. exports of liquefied natural gas (LNG), which is especially troubling with the Russia-Ukraine situation and energy supply challenges across Europe. Representing Maine, Massachusetts, Vermont, Connecticut, Rhode Island, Michigan and Minnesota, the senators asked Granholm to review U.S. LNG exports and their impact on domestic prices. In the meantime, they want Granholm to consider halting permit approvals for U.S. LNG export facilities. Notably, seven of the 10 senators represent New England states, where nearly every winter families there get hit in their wallets because of constrained natural gas supplies amid high demand. The U.S. Energy Information Administration (EIA) just reported that the benchmark price for natural gas in New England during January was the highest monthly average price since February 2014. The problem is relatively simple: New England doesn’t have enough natural gas infrastructure to meet winter natural gas demand, either for heat or electricity generation, and hardship has resulted. The sad twist to New England’s tale is that abundant natural gas is practically next door in Pennsylvania, sitting atop the Marcellus shale. Unfortunately for New Englanders, this has been their plight for several years, as state and local leaders and several communities have blocked additional infrastructure needed to help meet demand. In 2022, it’s a case of same tune, different verse. Michael Giaimo, API Northeast Region director, for CommonWealth Magazine: New England sits a few hundred miles away from one of the most prolific natural gas producing-regions in the world, yet anti-consumer policies at the cost of pragmatism have blocked construction of critical pipeline infrastructure needed to transport domestically produced natural gas to markets here. So, we as a region are forced to turn to Russia, Trinidad and Tobago, and other places across the globe. … All the constraints and complaints about pipeline construction and natural gas generation have done nothing to decrease demand for power, which is expected to continue to rise. Instead of focusing on this recurring infrastructure/supply problem that is impacting their constituents, the senators want Granholm to consider halting approvals for LNG export facilities. And then the question is whether at some point the group might push for reducing or stopping LNG exports themselves.
36 Gallons Of Crude Oil Spilled From Pipeline Near Century -About 36 gallons of crude oil were spilled during an incident east-northeast of Century Sunday morning. According to a Florida Department of Environmental Protection notice, a release occurred at 6:33 a.m. on a St. Regis Gas Treating Facility production line located in Escambia County, Florida. An employee saw steam release from the site and notified the field lead and control room senior operator, and the production line was isolated by 7:10 a.m. A vacuum truck was called to remove any fluids. According to the FDEP notice, about 136.2 barrels of produced water and rainwater mix and 36 gallons of crude oil were recovered. Spill booms were placed at the release site. The line will be contained and flushed with fresh water in advance of inspection and repairs. All impacted soil will be removed and disposed of at an approved landfill.
Pipeline's safeguards not working in Louisiana diesel spill (AP) — A corroded pipeline that ruptured and spilled 350,000 gallons (1.6 million liters) of diesel fuel into a New Orleans area wetland did not have a fully functioning leak detection system at the time, according to federal records, which also show the spill was larger than previously reported. Two of three components of a leak detection system for the 16-inch (40-centimeter) pipeline did not issue alarms as they were supposed to when it broke just east of New Orleans on Dec. 27, 2021, Collins Pipeline Company disclosed in an accident report submitted to federal regulators. The third part of the system worked as designed and issued an alarm, according to the report. It was not clear from the information provided by the company when that alarm went off or if the parts of the system that malfunctioned caused any delay in its response. Quickly detecting pipeline ruptures is crucial to containing environmental damage. Yet coming up with systems that can do so reliably has been a longstanding challenge for the industry. Collins, a Mississippi-based subsidiary of Parsippany, New Jersey-based PBF Energy Inc., reported the spill to authorities about eight hours after workers shut down the 42-year-old Meraux Pipeline a few miles from the company’s refinery in Chalmette. Company personnel shut it off when they noticed a pressure change and flow meter measurements indicated a problem, according to federal records. The company’s report said the spill detection system did not help identify the spill.Collins initially estimated that as few as 8,400 gallons (38,200 liters) of diesel were released, then updated that days later to just over 300,000 gallons (1.4 million liters). On Jan. 27, the company increased its estimate yet again, to 350,000 gallons, the accident report shows. The diesel flowed into two man-made ponds and killed thousands of fish and dozens of birds, turtles, alligators and other animals. Most of the fuel was recovered but the accident caused an estimated $3.8 million in property damages, according to the company.
Documents show major gaps in Texas gas inspections - Oil and gas regulators are assuring Texans the natural gas system will keep functioning this winter, saying they’ve done more than 3,000 inspections to check on it. What they’re not saying is many of those inspections found that gas production and transmission facilities can’t guarantee they’re prepared for another hard freeze. For about 40 percent of the pipeline and storage sites Texas deems critical, operators hadn’t conducted a winterization test or company officials didn’t know if one had been performed, according to records from the state Railroad Commission obtained under a Public Information Act request. State inspectors also didn’t actually visit dozens of sites because of “time constraints,” the records show. One gas-fired plant was forced to shut down a month after state inspectors said its supply pipelines had passed an inspection, records show. In other cases, inspectors appear to have overlooked important information. Critics said there’s an underlying problem — the Railroad Commission has yet to write winterization standards for gas wells, pipelines and storage facilities. The lack of clear guidelines makes it hard to judge the effectiveness of the commission’s inspection campaign, said Luke Metzger, executive director of Environment Texas. “I worry that might be more of a public relations stunt than a credible regulatory effort,” Metzger said in an interview. The Railroad Commission, which despite its name oversees the state’s gas system, said the inspection records are just a snapshot of conditions, and that companies have made progress since the reports were filed. “In the fall, some of the sites had yet to finish winterizing or test winterization because they were coming off summer operations,” Andrew Keese, a commission spokesperson, said in a statement. During last February’s power crisis and winter storm, gas-fueled generators were the largest source of unavailable capacity on Texas’ main power grid. And parts of the gas system were forced to shut down because of a lack of electricity. More than 4 million homes and businesses lost power in Texas, many of them for days, and over 240 deaths were linked to the winter storm, according to a state tally. Damage has been estimated at more than $100 billion.
Permian oil output to grow for several years, Plains All American CEO says— Crude oil production from the prolific Permian basin of West Texas has topped estimates and may grow by an annual rate of 600,000 barrels a day over the next several years, according to pipeline giant Plains All American Pipeline LP. “North American energy supply will continue to play a key role in meeting global demand growth, and the Permian is positioned to drive a vast majority of U.S. production growth,” Chief Executive Officer Willie Chiang said Wednesday in a conference call with analysts. The Houston-based company said crude-oil volumes transported on its Permian pipeline system jumped 26% in the fourth quarter from a year earlier, exceeding analysts’ estimates. Plains All American, which owns 18,700 miles of conduits across the U.S. and Canada, expects to move nearly 5.3 million barrels a day of oil in the Permian this year, up 19% from last year.
This could be when shale driller discipline cracks, Citi warns— Oil executives tempted by the prospect of the highest crude prices in seven years are showing all the signs of abandoning pledges to hold the line on drilling budgets, Citigroup Inc. said. U.S. shale explorers are poised to boost spending by almost 40% this year, based on comments and plans revealed during recent earnings presentations, Citi analyst Scott Gruber wrote in a note to investors on Monday. That’s up from the bank’s previous call for a 30% rise. Overseas budgets are seen jumping by 32% from the old forecast of 17%. “E&P managements will be hard pressed to abandon their commitments,” Gruber wrote. “But we foresee an increasing number beginning to lean into the market as the challenge of managing supply in a market as disaggregated as the global oil market becomes increasingly clear.” U.S. companies probably will lift domestic daily crude production by as much as 1 million barrels this year, according to various analysts. American oil prices have climbed 21% this year to more than $90 a barrel, extending last year’s 55% advance. 12:21 PM
Earthquakes in Texas doubled in 2021 due to oil companies' water injections | The Texas Tribune — One local said it sounded like a pickup truck had rammed into the side of their house. Another said it sounded like the air conditioner fell off the roof. A third compared the experience to getting off of a rollercoaster, dizzy and a bit shaky. “In the hardest ones we’ve experienced, there is a bunch of shaking, and the pictures shook off the walls,” said Christina Bock, 45, who lives in Gardendale, a rural community north of Odessa in the heart of West Texas oil and gas country. Earthquakes have dislodged her deck from the house and left cracks in her walls, she said. “You’ll hear a loud bang. If you’re inside, you assume it’s a car wreck or that something exploded outside,” said Bock, a paralegal who has lived in Gardendale for 13 years. “The scary thing is that they are happening pretty much daily at this point.” More than 200 earthquakes of 3 magnitude and greater shook Texans in 2021, more than double the 98 recorded in 2020, according to a Texas Tribune analysis of state data maintained by the Bureau of Economic Geology at the University of Texas at Austin. The record-setting seismic activity is largely concentrated in West Texas’ Permian Basin, the most productive oil and gas region in the state. Scientific studies show that the spike in earthquakes is almost certainly a consequence of disposing huge quantities of contaminated, salty water deep underground — a common practice by oil companies at the end of the hydraulic fracturing process that can awaken dormant fault lines. During hydraulic fracking, oil companies shoot a mixture of fluids and sand through ancient shale formations, fracturing the rock to free the flow of oil. But oil isn’t the only thing that’s been trapped underground for millions of years: Between three and six barrels of salty, polluted water also come up to the surface with every barrel of oil. The cheapest, and most commonly used, way to dispose of this “produced water” is to drill another well and inject it into porous rock formations deep underground. For years, oil companies have loaded those formations with hundreds of millions of gallons of the black watery mixture — which contains a slurry of minerals, oil and chemicals used in fracking — every day, slowly increasing the pressure on ancient fault lines. An analysis by Rystad Energy provided to The Texas Tribune found that the amount of wastewater injected underground in the Permian Basin quadrupled in a decade, from 54 billion gallons in 2011 to 217 billion gallons last year. In a 2021 study published in the Journal of Geophysical Research, scientists at the U.S. Geological Survey and the University of Texas found that the vast majority of seismicity since 2000 near Pecos — a city roughly 100 miles southwest of Midland — was likely triggered by increased wastewater disposal. State regulators, too, have found that an increase in seismic activity most likely occurs as a consequence of saltwater disposal. “The cumulative volumes [of water] increase the pressure, and that is the force that triggers the fault to slip,” said Alexandros Savvaidis, a research scientist at the Bureau of Economic Geology at UT-Austin. The result is that communities like Gardendale, where Bock lives, as well as the bustling cities of Odessa and Midland — which many oilfield workers, engineers and service workers call home — are experiencing not only more frequent earthquakes, but stronger ones.
Shaken by fracking quakes, Texas is forced to act - "You get used to it. The walls shake," says Sam, a resident of Midland, a town in west Texas where hydraulic fracturing for oil and gas—known as "fracking"—is causing more and more earthquakes. "Then another tremor comes a second later, like a truck passing nearby," said the 44-year-old, who did not wish to disclose his last name. Echoing his words, three quakes rocked the ground in just one day on February 4. This region of the Permian Basin, from which 40 percent of US oil and 15 percent of its gas are extracted, experienced nine earthquakes greater than three-magnitude in 2019, 51 in 2020 and 176 in 2021, according to market intelligence firm Sourcenergy. What causes earthquakes is not fracking itself, but injecting the wastewater into wells. The Railroad Commission of Texas, which regulates oil activities, has had to impose new rules on water disposal. Drilling companies must deal with huge quantities of water that come up when fracking—water makes up about 80 percent of the fluid pumped out of the ground. Almost 4,000 active wells have been drilled specifically to collect the wastewater in the Permian Basin. "As you get more and more water getting pumped into the ground... you're filling up these spaces," said Joshua Adler, CEO of Sourcenergy, which helps oil companies improve water management. "In some of these spaces, you got these cracks or fault lines. You're pushing it harder and harder, and maybe you hit that fault line and maybe it makes it slip and that's an earthquake." Since 2012, daily oil production have multiplied five-fold in the Permian Basin, so water injections into wells has also multiplied. "In Oklahoma, they basically kind of dragged their feet for years and denied that there was any problem" when earthquakes increased in the 2010s, Adler said. In Texas, as soon as earthquakes increased, the Railroad Commission started to study the issue, he said. "They didn't wait until it was a giant problem." Between September and January, it defined three geographical areas at risk. In the most populous, Gardendale, where the cities of Midland and Odessa are located, it ordered the suspension of deep injections of water into seven wells in mid-December. After four more earthquakes of magnitudes between 3.1 and 3.7, it extended the measure to 26 more wells. The regulator is waiting for industry proposals in the two other areas identified, Stanton and Northern Culberson-Reeves. But Neta Rhyne, 72, who lives near Northern Culberson-Reeves, believes that "it's like asking the fox to guard the chicken coop." Last week, she again asked the Railroad Commission, as she has been doing since 2016, for a hearing following new requests to drill water disposal wells in her region. She fears an earthquake could affect the source of one of the largest natural spring-fed pools in the world, a stone's throw from her home in Balmorhea Nature Park, Toyahvale. The Texas Parks Department declined to respond to AFP's questions, but press officer Stephanie Salinas Garcia acknowledged "concerns that earthquakes could affect the spring system."
These 23 year-old Texans made $4 million last year mining bitcoin off flare gas from oil drilling — When Brent Whitehead and Matt Lohstroh were sophomores at Texas A&M University, they decided to get into the business of mining bitcoin on the oil fields of East Texas. The year was 2019, and at the time, the idea of oil and gas companies joining forces with bitcoin miners was considered both avant-garde — and a major taboo. But Whitehead, an engineer hailing from a family with a long history in oil and gas production, and Lohstroh, a finance major with a bitcoin obsession, ignored the skeptics, and sunk all the cash they had earned from their high school side gigs in lawn care and landscaping into Giga Energy Solutions, a company that mints bitcoin from stranded natural gas. For years, oil and gas companies have struggled with the problem of what to do when they accidentally hit a natural gas formation while drilling for oil. Whereas oil can easily be trucked out to a remote destination, gas delivery requires a pipeline. If a drilling site is right next door to a pipeline, they chuck the gas in and take whatever cash the buyer on the other end is willing to pay that day. But if it's 20 miles from a pipeline, drillers often burn it off, or flare it. That is why you will typically see flames rising from oil fields. Beyond the environmental implications of flare gas, drillers are also, in effect, burning cash. To these two 23-year-old Aggie alums, it was a big problem with an obvious solution. Giga places a shipping container full of thousands of bitcoin miners on an oil well, then diverts the natural gas into generators, which convert the gas into electricity that is then used to power the miners. The process reduces CO2-equivalent emissions by about 63% compared to continued flaring, according to research from Denver-based Crusoe Energy Systems. "Growing up, I always saw flares, just being in the oil and gas industry. I knew how wasteful it was," Whitehead told CNBC on the sidelines of the North American Prospect Expo summit in Houston, a flagship event for the industry. "It's a new way to not only lower emissions but to monetize gas." Whitehead tells CNBC they have signed deals with more than 20 oil and gas companies, four of which are publicly traded. Giga also says they're also in talks with sovereign wealth funds, and they are expanding, fast. Giga's 11-person team is adding another six employees this month. Lohstroh and Whitehead are part of a growing movement of people placing big bets on the potential for bitcoin mining to transform the economics of the energy industry.
What states stand to gain if Biden hikes oil and gas royalty rates - For a president who campaigned on the promise to end new oil and gas leasing on public land, Joe Biden has been dragging his feet, to say the least. A long-anticipated government report on the federal oil and gas leasing program that was released last November did not indicate any end in sight. And while the Biden administration has yet to auction off any new leases on public land, it has approved almost 900 more drilling permits than former President Donald Trump did during his first year in office, according to a recent analysis. But last week an update popped up on the Interior Department’s website that showed Biden might be ready to make a change to the oil and gas leasing program that no other administration has dared to make for the last 100 years: increase royalty rates. The notice, which was published by accident and quickly removed from the site, said the agency would increase the royalty rate on leases sold in upcoming auctions from 12.5 percent of the value of the oil or gas produced to 18.75 percent, according to E&E News.That would bring royalty rates for federal leases in line with those for oil and gas leases on state-owned lands, which range from 16.6 percent to a whopping 25 percent in Texas. Increasing the federal rate could be a boon for state governments, which receive half of the royalty revenue the federal government takes in for leases in their borders and often rely on it to fund schools, public health programs, and critical infrastructure. That’s the message of a new report from the nonprofit watchdog organization Accountable.US, which calculated just how much states are being shortchanged by the outdated federal royalty rate. It found that in 2019, Western states could have taken in additional $1.58 billion if the royalty rate had been 20 percent instead of 12.5. The worst affected state, New Mexico, missed out on $804 million in potential revenue in 2019, or about 13 percent of its budget that year.
As oil nears $100 a barrel, U.S. drillers get busy in costly shale basins --As U.S. oil rises toward $100 a barrel (bbl), producers in some high-cost shale basins are buying properties and adding rigs and frack crews in places that fell silent when prices crashed early in the pandemic two years ago.Benchmark U.S. prices last week topped $93/bbl, up around 65% in the last 52 weeks and the highest since 2014. U.S. producers are cranking up spending at double-digit rates as fuel demand has soared and fears have waned that OPEC will again punish them by flooding the market with crude that is cheaper to produce. Some executives say current high prices and relatively low service costs make production economics the best in years. Firms are buying U.S. oil, pipeline and gas processing rivals in a bet that higher prices will more than cover rising costs of labor and equipment."Drilling economics today are better than they’ve ever been since the shale revolution started," Chris Wright, CEO of Liberty Oilfield Services, said.Closely held companies, in particular, are accelerating output, he added. New activity is stirring in secondary oilfields like Colorado's DJ Basin, Wyoming's Powder River, Louisiana's Haynesville and North Dakota's Bakken shale, which last year lost its spot as the second largest U.S. oil producing region. Spending budgets among U.S. independent producers are up 13% over a year ago, according to analysts at Cowen. Among secondary fields, the natural gas-rich Haynesville is among the only to fully recover output from the 2020 oil-price crash. Other shale fields, including the second-largest producing oilfield, are adding to holdings and rigs. "When you look at the oil prices in the Bakken, the prompt price is close to $90 a barrel," Bob Phillips, CEO of energy pipeline company Crestwood Equity Partners, said. "That doesn't happen very often." Last week, Crestwood completed a $1.8 billion deal to purchase Oasis Midstream Partners' oil, gas and gas-processing assets in North Dakota and Texas as part of a plan to become a top-three midstream operator in the Bakken, Powder River and Permian shale fields.Shale dealmaking that leads to more output could accelerate this year, said Andrew Dittmar, who specializes in merger and acquisitions for energy tech firm Enverus. In Wyoming's Powder River oilfield, Continental Resources has made several acquisitions since last year, the latest from Chesapeake Energy. That purchase could revive the area's output, said Crestwood's Phillips. Continental is scheduled to release its fourth-quarter results next week and has not yet highlighted its 2022 budget or plan, a spokesperson said.
Oil and Gas Companies Routinely Frack With “Trade Secret” Chemicals, Including PFAS - Peggy Tibbetts stopped drinking the tap water in her home in Silt, Colorado, 13 years ago. Silt, located in Garfield County, is surrounded by oil and gas wells; in every direction, there is a well pad within just a few miles of Tibbetts’s home. The town gets its water from the Colorado River, downstream from the West Divide Creek tributary, where two well pads blew up in 2004, causing a benzene seep. When Tibbetts’s health began to deteriorate in 2013, she suspected the toxic air emissions from fracking operations were the cause. “We’ve always known that there are dangerous chemicals being used, but we weren’t allowed to know what they are,” she told Sierra.Oil and gas companies routinely withhold from regulators and the public the identities of chemicals used in drilling and fracking operations by claiming that the names of those chemicals are a trade secret. Now, a report by Physicians for Social Responsibility (PSR) sheds new light on how residents like Tibbetts are potentially being exposed to dangerous chemicals—including PFAS, proven carcinogens—without their knowledge. The report provides a more precise picture of how much PFAS have been used in the past 10 years in Colorado, though the actual numbers could be much greater. According to the report, PFAS chemicals were used in at least 10 Colorado counties. In Weld County alone, researchers determined that at least 7,840 pounds of PTFE, also known as Teflon, were used in oil and gas operations there. That number, though, could be a vast undercount of the actual total. In Colorado, well operators are required to disclose chemical use in the fracking process but have the option to shield the precise identity of those chemicals as a “trade secret.” What’s more, operators are not required to disclose the chemicals they use in drilling (the process that precedes fracking). In Weld and Garfield Counties, well operators shielded the identities of chemicals as a “trade secret” in a total of 11,289 wells; a staggering 368 million pounds of unidentified chemicals designated as “trade secret” were used in Weld County alone from 2011 to 2021. In Garfield, 16 million pounds of non-identified chemicals were used.PFAS is a class of what are known as “forever” chemicals because they do not break down in the environment or the human body. And they are as dangerous as they are persistent. Exposure to PFAS chemicals can lead to a wide spectrum of health impacts, including kidney and testicular cancer, as well as childhood leukemia, thyroid disease, high cholesterol, and pre-eclampsia. One measuring cup of PFOA, a class of PFAS used to make industrial and household products such as grease-resistant cookware, would be enough to contaminate 8 billion gallons of water—about as much water as New York City uses in a six-day period. Michigan determined that the maximum allowable level of PFOA in drinking water should be no more than 8 parts per trillion. Meanwhile in Colorado, according to PSR researchers, nearly 9,000 pounds of PTFE were used in oil and gas drilling and fracking over the past decade, with a total of 414 million pounds of chemicals left unidentified as “trade secret.”;
‘They criminalize us’: how felony charges are weaponized against pipeline protesters -Last summer Sabine von Mering, a professor of German at Brandeis University, drove more than 1,500 miles from Boston to Minneapolis to protest against the replacement of the Line 3 oil pipeline that stretches from Canada’s tar sands down to Minnesota.Along with another protester, she locked herself to a semi-truck in the middle of a roadway, according to a filed court brief, as a means of peaceful resistance. But when she was arrested, she was charged with a serious crime: felony theft, which carries up to five years in prison.“It’s very scary that they criminalize us like that, and to face jail time,” said Von Mering, 54, of her June arrest. “But what can I do? I feel responsible to my kids and future generations.”The felony charges come as more than a dozen states have passed laws to criminalize fossil fuel protests, and as the federal government has ramped up its own tactics for surveilling and penalizing protesters.Von Mering is one of nearly 900 protesters who were arrested in Minnesota for protesting against the pipeline’s construction, with the vast majority of arrests taking place during the summer of 2021, and one of dozens facing felony charges. Construction on the Line 3 pipeline was finalized in October 2021 and carries 760,000 barrels of oil per day across northern Minnesota. But its construction for years has stoked fierce protests and legal challenges, led by Indigenous activists in northern Minnesota who worried about potential impacts of oil spills and the pipeline’s threat to treaty rights to gather wild rice. While most of the arrests have led to misdemeanor or gross misdemeanor charges for crimes including “disturbing the peace” and “trespassing”, felony charges like Von Mering’s mean protesters are facing years of jail time. Legal advocates say that in Minnesota the elevated charges are a novel tactic to challenge protest actions against pipeline construction. They see them as furthering evidence of close ties between Minnesota’s government and the fossil fuel industry. It follows reporting by the Guardian that the Canadian pipeline company Enbridge, which is building Line 3, reimbursed Minnesota’s police department $2.4m for time spent arresting protesters and on equipment including ballistic helmets. Experts say the reimbursement strategy for arrests is a new technique in both Minnesota and across the US, and there’s concern it can be replicated.
Whiting to Expand Operated Bakken Footprint, Pursue Modest Growth in 2022 - Whiting Petroleum Corp. has two agreements in hand to expand its operated leasehold in the Bakken Shale, and it has raised its capital budget for 2022. Management of the Denver-based independent said Tuesday the agreements entail acquiring nonoperated assets in the Bakken’s Sanish field from two undisclosed private companies for $273 million total.“These transactions continue the strategy we put forth beginning in late 2020,” said CEO Lynn Peterson. “By increasing our working interest, we are immediately recognizing substantial cash flow that is accretive for shareholders. “We know and understand the Sanish field extremely well and are very comfortable with the rate of return we are achieving.” Located in Mountrail County, ND, the assets increase Whiting’s average operated working interest to 74% from 61% throughout the Sanish area. The additional acreage would be “impacting many of the drilling units included in the company’s current 2022 development program,” management said. The assets span 14,563 net acres and should contribute about 4,500 boe/d net production (67% oil), the company said. The smaller transaction closed in late 2021 and the larger one is slated to close by the end of March. The assets include 32 net undrilled locations, which Whiting plans to develop in the “near term,” management said. Whiting also announced capital expenditure (capex) guidance of $360-400 million for 2022. The company plans to have two drilling rigs and one completions crew operating in the Williston for most of the year. The rigs would operate in North Dakota’s Mountrail, McKenzie and Williams counties.
Huntington Beach oil spill inspires legislation to ban California offshore drilling - Alarmed by damage caused by a major oil spill off the Huntington Beach coast in October, an Orange County legislator on Wednesday introduced a bill to end offshore oil production from rigs in California-controlled waters by 2024, a proposal sure to face fierce opposition and potential legal challenges from the petroleum industry. The legislation would affect 11 oil leases, all off the Orange and Ventura county coastlines. It would also allow the State Lands Commission, the agency with oversight of those contracts, to negotiate a voluntary relinquishment of the leases by oil companies before the state takes action. The cost of buying out or rescinding those leases is unclear, though the size of the industry suggests that the price tag could possibly cost the state tens if not hundreds of millions of dollars. State Sen. Dave Min, an Irvine Democrat, said the action is necessary to protect the California coastline from another catastrophic oil spill similar to the one in October, which caused widespread environmental damage and led to beach closures that hurt the economies of Orange County coastal communities. The oil rigs off the coast and their aging infrastructure continue to pose a serious threat to California's coast, he said. "It is clear to me, and I think clear to anyone who looks at the sort of status of these rigs, that it's a ticking time bomb," Min said Wednesday. "You're asking for more and more spills, and we know that this is just horrific for our coastlines, for our coastal tourism economies, for our marine ecosystems." Kevin Slagle, a spokesperson for the Western States Petroleum Association, said the proposal would decrease California's local oil supply and burden California taxpayers. Eliminating the oil leases amounts to a government "taking," which would require those companies to be compensated, he said. "Eliminating existing offshore production will lead to importing even more of the energy we need from foreign sources and putting California at significant risk for takings claims," Slagle said. The president of the State Building and Constructions Trades Council of California, a labor organization that represents oil workers and has tremendous influence in Sacramento, also expressed concerns about the potential impact of the legislation. Reducing local oil production could require the state to import more oil by tanker ships, adding more stress to California's already crowded ports, said council President Andrew Meredith. "There's a constant drumbeat to cease oil and gas production in California with no corresponding responsible plan to power our state," he said. "Nearly half of the oil coming out of the Amazon is already coming to California. Should we really be tanking more oil into California, greatly increasing carbon emissions as hundreds of tankers idle in our ports waiting to offload?"
Rightwing lobby group Alec driving laws to blacklist companies that boycott the oil industry - The influential rightwing lobby group the American Legislative Exchange Council (Alec) is driving a surge in new state laws to block boycotts of the oil industry. The group’s strategy, which aims to protect large oil firms and other conservative-friendly industries, is modelled on legislation to punish divestment from Israel. Since the beginning of the year, state legislatures in West Virginia, Oklahoma and Indiana have introduced a version of a law drafted by Alec, called the Energy Discrimination Elimination Act, to shield big oil from share selloffs and other measures intended to protest the fossil fuel industry’s role in the climate crisis. A dozen other states have publicly supported the intent of the legislation. Texas has already begun compiling a list of companies to target for refusing to do business with the oil industry after the state passed a version of the law last year. Top of the list is the world’s largest asset manager, BlackRock. The push to blacklist firms that boycott the oil industry follows a meeting in December between politicians and Alec, a corporate-funded organisation that writes legislation for Republican-controlled states to adopt and drive conservative causes. At that meeting in San Diego, members of Alec’s energy taskforce voted to promote the model legislation requiring banks and financial companies to sign a pledge to not boycott petroleum companies in order to obtain state contracts. The wording closely resembles that of laws drafted by Alec and adopted in more than 30 states to block support for the Boycott, Divestment and Sanctions (BDS) movement against Israel’s oppression of the Palestinians. Similar laws are also being promoted to protect the gun industry from boycotts. The legislation written by Alec, which has a history of extreme denial of the climate crisis, claims that “American and European fossil energy producers … are among the most socially and environmentally responsible companies in the world”. It laments that “corporations are boycotting fossil energy companies by refusing to provide them with products or services”, and says that share selloffs by financial funds hurt investors. “Banks are increasingly denying financing to creditworthy fossil energy companies solely for the purpose of decarbonizing their lending portfolios and marketing their environmental credentials,” the draft legislation says. “This model bill proposes a strategy in which states use their collective economic purchasing power to counter the rise of politically motivated and discriminatory investing practices.” The drive to pass the legislation follows the refusal of major financial firms to fund new oil and gas drilling in the Arctic. Banks and other financial institutions are also under pressure from environmental groups and customers to divest from fossil fuel companies. JPMorgan Chase, Citibank and Goldman Sachs are among those firms to publicly commit to supporting the transition away from oil. As with anti-BDS laws, any business with more than 10 employees would have to certify that it is not boycotting fossil fuel companies in order to do business with a state government. State funds, such as pensions, will usually be obliged to sell investments in corporations that refuse loans to the oil industry.
U.S. sees record oil production next year moving even higher — U.S. oil production will grow even more than the government previously expected as a scorching price rally drives producers to boost drilling. Oil output will average 12.6 million barrels a day in 2023, an increase from its previous estimate of 12.41 million, according to Energy Information Administration data. The current annual all-time high of 12.3 million barrels a day was set in 2019. This year’s production forecast was also revised higher to 11.97 million barrels a day from an earlier projection of 11.8 million, the EIA said in its monthly Short-Term Energy Outlook report. This extra U.S. supply is a welcome boon for President Joe Biden, who has asked suppliers to raise production in order to help tamp down energy prices that are contributing to the highest inflation in decades. In the wake of oil prices surging to their highest since 2014, two of the largest U.S. oil companies announced they would increase production by double digits in the Permian Basin, America’s most prolific oil patch. Prices have rallied with supplies consistently falling short of demand surging around the globe as economies recover from pandemic-era slowdowns. Global consumption is set to reach 100.6 million barrels a day this year, a higher revision from the last estimate of 100.52 million, according to the report. Consumption is expected to rise to 102.5 million barrels a day in 2023. The agency raised its price forecasts for benchmark crudes West Texas Intermediate and Brent this year by around $8 a barrel, thought it does expect oil’s rally to cool as more supplies come online. “We expect downward price pressures will emerge in the middle of the year as growth in oil production from OPEC+, the United States, and other non-OPEC countries outpaces slowing growth in global oil consumption.” Global petroleum supply are expected to rise to 101.39 million barrels a day this year. That’s an upward revision from last month’s forecast of 101.05 million. The EIA expects global production will rise further to 103.47 million barrels a day in 2023.
U.S. oil market heats up further as demand surges to record— The U.S. oil market is flashing ever more signs of tightness and supplies can barely keep up with a scorching surge in fuel demand. Last week crude stockpiles in one of the biggest oil consumers in the world plunged to the lowest since 2018, with inventories at a key storage hub falling toward critical levels. At the same time, the four-week average for total oil product supplied, a proxy for demand, surged to nearly 22 million barrels a day, the highest on record. The tightness in U.S. markets has vaulted oil and retail fuel prices to levels not seen since 2014 - a key source of concern for consuming nations due to the economic impact of high energy costs. A surge toward $100 a barrel will stoke further worries about inflation, that is already at multi-year highs in many countries. “The oil market is too tight,” said Ed Moya, senior market analyst at OANDA. “The outlook for consumption continues to improve domestically and across Europe, which means that West Texas Intermediate crude might not have much resistance getting to the $95 region this month,” he said. While gasoline demand has turned a corner from winter lows and is near pre-pandemic levels, consumption of diesel, heating oil, and propane are underpinning the fresh record. Demand for fuels has been boosted by cold weather in many parts of the U.S., adding to the broad recovery from the lows seen during the Covid-19 pandemic. The rolling average for distillates consumption rose to the highest level since 2007 after back-to-back winter storms drove demand for heating and power generation in the Northeast. In the rest of the country, highway trucking demand has remained strong as well, exceeding 2019 levels for January, according to data from the Federal Highway Administration. The four-week average for gasoline consumption rose for a second straight week and the weekly demand figure was the highest for this time of year since 2007.
Biden Is Disconnected From American’s Reluctance To Be Regulated Out Of Fossil Fuel Prosperity – OpEd – Eurasia Review -Civilization has benefited from more than 6,000 products made from the oil derivatives manufactured out of raw crude oil at refineries. None of these products were available to society before 1900. With no known replacement for crude oil in the foreseeable future, President Biden has stated “we are going to get rid of fossil fuels” implying that he is going to change society’s lifestyle and economy demands for the products made from fossil fuels that were not available before 1900.Virtually all the components of wind turbines, solar panels, and all forms of transportation are assembled with products made from oil derivatives manufactured from crude oil. Ridding the world of crude oil would eliminate most forms of transportation and electricity generation from wind and solar.The public has demonstrated that they are not going to be mandated and regulated away from using the products essential to maintaining their basic standard of living and keeping the prices for thousands of everyday goods and services low as it would reverse most of the progress humanity has made over the last century. Those products made from fossil fuels and the inventions of the automobile, airplane, and the use of petroleum in the early 1900’s led us into the Industrial Revolution and victories in World Wars I and II. President Biden appears to be disconnected from most Americans, as he must be oblivious to his own Environmental Information Agency’s (EIA) Jan 11, 2022, report that US Fossil Fuels Production to Reach Record Highs in 2023. Biden may be sabotaging the American economy with shortages and inflation in the name of unattainable climate targets and may go down in history as causing the continent to be homage to China for the materials to go green, and to Russia and OPEC for crude oil.His continuous use of executive orders, regulations, and policies to alter the social demands of society for Americans to live without reliable and affordable power supplies – supplies critical to peace, prosperity and the survival of Western civilization, and the products and infrastructures made possible from fossil fuels is not working. The shortages and inflation upon society with his tinkering of the supply chain of fossil fuels is not working as shown by his own EIA agency. Under the Biden multiple restrictions on domestic oil production and climate plan, America will be discouraging U.S. energy independence, starting with tightening restrictions on fossil fuel development by suspending Federal Oil and Gas Permits, encouraging the shuttering, and halting of further fracking efforts in America, and the cancellation of the Keystone XL pipeline.To reduce civilization’s demands for fossil fuels will require significant social changes to reduce the need for so many products, reduce flights, and reduce the need for so those products to be moved around the world. Only by reducing the demand, can we reduce the supply. There is no need whatsoever for the supply of fossil fuels if it were not for the demands of society, but the public remains unwilling to be mandated and regulated into an inferior lifestyle
Chevron Posts Best Quarter Since 2014, as Oil Industry Rebounds - Chevron, one of the nation’s largest oil companies, reported a fourth consecutive quarterly profit on Friday as oil and natural gas prices continued to recover from the pandemic slump. It was the company’s best financial performance since 2014, reflecting the sharp turnaround for the entire industry. Chevron, along with other major oil companies, has shifted its emphasis from expanding exploration as prices rise to a more disciplined, cautious approach to avoid a new glut and renewed slump in prices. So far that strategy has worked even in the face of growing criticism that the oil industry is not addressing investor concerns about climate change fast enough. Chevron, which is based in San Ramon, Calif., said it made $5.1 billion in the final three months of the year on revenue of $46 billion. The profit compared with a loss of $665 million for the period in 2020 on revenue of $25 billion. The improved results were powered by oil prices that reached a seven-year high in late 2021 and have continued to rise to more than $80 a barrel. For all of 2021, Chevron earned $15.6 billion compared with a loss of $5.5 billion in 2020, one of the most trying years for the industry in modern history as businesses and cities locked down and consumers stayed home. Chevron executives say the slump, and the necessity for the company to cut expenses, ultimately made for a stronger business. The company was able to raise its dividend in 2021, and again this week. Chevron reported higher sales volumes and lower expenses in its exploration and production operations. Most important, its average sale price for a barrel of oil in the fourth quarter was $63 compared with $33 the year before. The price of the natural gas it sold was more than three times as high as the year before, mainly because of weather factors. Chevron’s refinery profits also improved. Its quarterly profit on refining in the United States reached $660 million in the quarter compared with a loss of $174 million a year earlier. As the global economy recovered, Chevron’s U.S. refinery output increased by 9 percent in the quarter from the year before.
Chevron In Talks with Venezuela To Boost Oil Production --Chevron is in talks with the Venezuelan government to gain more control over their joint venture and help Caracas boost oil production.Bloomberg reported that the negotiations are being led by the chief of Chevron’s Venezuelan division, Javier La Rosa, and PDVSA’s president, Asdrubal Chavez, according to unnamed sources in the know.The two had discussed PDVSA giving the U.S. supermajor greater control over the joint operation in exchange for some debt relief. For now, however, the negotiations are informal because Chevron would need a sanctions waiver to make any formal commitments.Chevron and PDVSA operate four oil fields together. Before U.S. sanctions, these produced around 200,000 bpd, according to Bloomberg. Now, they are producing around 140,000 bpd, the report also said.While Chevron has been present in Venezuela for decades and has continued operating in the country under a series of waivers granted by the U.S. federal government, in 2020, the company wrote off its total $2.6-billion investment in the South American country due to the excessive uncertainty around Venezuela’s oil industry.Last year, after President Joe Biden took office, Chevron lobbied for laxer sanctions on Caracas so it could operate in the country with fewer constraints.Venezuela, meanwhile, is ramping up oil production despite the sanctions, largely with the help of Iranian condensate that it uses to dilute its superheavy crude. Last year, PDVSa managed to reverse a decline in oil exports, booking a modest climb of 1% in annual exports, most of which went to China, Reuters reportedlast month.Production also increased, with the average for 2021 at around 600,000 bpd, with the December daily jumping to over 800,000 bpd, with one daily spike to 1 million bpd—the closest PDVSA got to its planned ramp-up to 1.28 million bpd for the full year.It is as part of these production boost efforts that the g overnment in Caracas has become willing to give foreign partners of PDVSA a greater say in the operation of the joint ventures.
Repsol continues cleaning up oil spillage in Peru - Spanish refinery Repsol says it is 48 per cent through the total cleanup of a January 15 oil spill off the coast of the Peruvian capital, Lima. Company spokesman Luis Vasquez said on Monday that the progress is in line with the schedule presented to Peruvian authorities. Nearly 3,000 people are working on the cleanup.
Core Lab Sees 2022 Growth in Americas, Middle East, South Atlantic - Heavily dependent on international oil and gas activity, oilfield services (OFS) firm Core Laboratories NV is engaged in a waiting game as it looks to benefit from improving global market dynamics. Core expects “seasonal declines in activity as we start the new year, and there are still short-term pandemic-related headwinds, as the sharp increase in virus cases in late 2021 has continued into early 2022,” said CEO Larry Bruno. “This has impacted operations through a combination of government-imposed lockdowns, delays in client projects and overtime costs to cover quarantine requirements among Core Lab staff.”Bruno added, however, that recent Covid cases among staff “have largely been mild and of short duration, and we anticipate fewer Covid-related impacts as the year unfolds.”Core divides its operations between its Reservoir Description and Production Enhancement segments. During the fourth quarter and full-year 2021 earnings call with analysts, management said Reservoir Description, with its emphasis on laboratory-based staffing, has been the segment hardest hit by lockdowns and quarantines.The company said the business outlook is improving, though. “As pandemic disruptions abate, the expansion of international developments provides growth opportunities for both segments into 2022 and beyond, with a particular focus on the South Atlantic Margin, Latin America, and the Middle East,” stated Core.
Europe’s newest climate change problem: Russia - Rising natural gas prices and hair-trigger tensions between Russia and Ukraine are forcing Europe to grapple with tough questions about the pace of its energy transition. Europe depends on Russia for more than a third of its gas needs, but Moscow’s aggression toward Ukraine has stoked fears about interruptions in gas deliveries if the military conflict escalates into all-out war. That has forced European leaders to confront the continent’s growing reliance on Russian gas imports to generate electricity, heat homes and power the industrial sector. White House national security adviser Jake Sullivan said yesterday that Russia could invade Ukraine “any day,” launching a conflict that would come at an “enormous human cost.” The crisis arrives as Europe attempts to plot a path toward a greener future. Many European countries have moved to shutter coal plants and build wind and solar facilities in recent years to slow their upward emissions trend. But gas is still needed because there aren’t enough renewable generation sources to replace fossil fuels. “I think Europe is seeing that it’s very hard to shut down coal and in some places nuclear and then not have gas go up,” said Stefan Ulrich, a European gas associate at BloombergNEF. “Even with the strong renewable build-out we’ve seen in Europe, especially during the winter you need that thermal generation to meet your energy demand.” Analysts say the conflict has exposed the volatility of gas imports and punctuated the fuel’s importance in helping Europe move from coal to renewable energy. “It very much puts the issue of European energy security back into this discussion around energy transition,” Ulrich added. The crisis might push European countries to make their transition to clean energy more quickly, some analysts said. And some European officials have doubled down on their support for the shift. “The current situation underlines again that the clean energy transition is the only way forward: the challenges we are facing now are the result of our dependency on fossil fuels — in particular on Russian gas. The answer is more green energy, not less,” Kadri Simson, the European commissioner for energy, said in emailed comments to E&E News. She’ll be in Washington this week to discuss energy cooperation, security and decarbonization during meetings with the U.S.-E.U. Energy Council. In the short term, Europe’s options for ramping up gas production and imports to bolster fuel supplies are limited.
IHS Markit report says LNG imports to Europe would be sufficient to overcome shutoff of Russia gas flows through Ukraine - Supplies of Russian gas to Europe via Ukraine have already fallen—and been replaced by LNG imports—to such a degree that shutting off the remaining gas that is still flowing through Ukraine would have a relatively limited additional impact on European supply, according to a new report by IHS Markit, a world leader in critical information, analytics and solutions. The report, entitled Putting Europe’s Security of Gas Supply to the Test by the IHS Markit Global Gas service highlights the reduced role of Ukrainian gas transit in Europe’s gas supply. The report says Russian gas flows through Ukraine fell to historical lows in January—50 million cubic meters per day (Mmcm/d), less than half of levels from a year ago. While flows through the Ukraine have swung back up with the beginning of February, they remain half the levels of the period 2015-2020. “Europe is already experiencing a ‘quasi-curtailment’ of Russia gas flows,” says Michael Stoppard, chief strategist, global gas, IHS Markit. “The result is a European gas import picture that is starkly different from a year ago. One where LNG imports have ramped up to fill the gap.” LNG imports to Europe increased considerably in January 2022 supplying higher volumes (34% of total supply) than Russian pipeline supply, which fell to 17% of supply, the report says. LNG imports from the United States rose to a new record of 245 Mmcm/d, accounting for the largest share of LNG by far. The average total LNG imports in January were 490 MMcm/d, with the upward trend in LNG imports continuing into February. LNG imports for the first three days of February have averaged 605 MMcm/d, with February 3rd reaching 710 MMcm/d. The surge in LNG imports has reduced core Europe’s previously abundant spare regasification capacity, which has gone from 82% in January 2021 to 25% in late January 2022. Nevertheless, enough spare regasification capacity exists to cover the loss of remaining pipeline flows from Ukraine relatively comfortably, the report says. A modest acceleration in storage withdrawal could also feasibly compensate for any lost supply. While the loss of remaining pipeline flows through Ukraine would not present a threat to physical supplies, it would likely put further pressure on prices as LNG volumes are pulled away from other destination markets in an already tight and rattled global market, the report says.
Biden Vows to Halt Russia-to-Germany Gas Pipeline If Russia Invades Ukraine - President Biden said Monday that a Russian-built pipeline to carry natural gas to Germany will be abandoned if Russia invades Ukraine. Biden made the remark during a joint news conference at the White House with Germany’s new chancellor, Olaf Scholz. Scholz did not explicitly state that Germany would suspend the Nord Stream 2 pipeline, though he said the U.S. and Germany were aligned in their positions. In Brussels, European Union Commission President Ursula von der Leyen said the EU was exploring other options for its energy supplies — which would include fracked gas from the United States.Ursula von der Leyen: “We are building a partnership for energy security with the United States, which is primarily about more liquefied natural gas supplies. We are talking to other gas suppliers — for example, Norway — about increasing their supplies to Europe.”Also on Monday, French President Emmanuel Macron met Russian President Vladimir Putin at the Kremlin. Putin said Russia was still working to find a diplomatic solution to the crisis over Ukraine, but warned of a wider, nuclear-armed confrontation if Ukraine is to join the NATO military alliance.
Biden says Nord Stream 2 won’t go forward if Russia invades Ukraine, but German Chancellor demurs - – President Joe Biden and German Chancellor Olaf Scholz had an awkward exchange with a reporter Monday at the White House over the future of the Nord Stream 2 gas pipeline. The discord at a press conference during Scholz's first visit to the White House was brief and civil. But it also represented a rare public show of genuine friction in a relationship that serves as a cornerstone of European security. The Nord Stream 2 natural gas pipeline between Russia and Germany was finished in September of last year, but it has yet to transport any actual gas. Biden said Monday that Nord Stream 2 would be scrapped if Russia launches a military invasion of Ukraine, which Moscow's troop movements strongly suggest is imminent. But Scholz refused to say the same. "If Russia invades -- that means tanks or troops crossing the border of Ukraine, again, then there will be no longer a Nord Stream 2," Biden said at a joint press conference with Scholz. "We will bring an end to it." "But how will you do that exactly, since the project and control of the project is within Germany's control?" asked Andrea Shalal of Reuters, who had posed the original question to Biden about Nord Stream. "We will, I promise you, we'll be able to do it," Biden replied. When the same question was put to Scholz, however, the German leader gave a very different answer. "We have intensively prepared everything to be ready with the necessary sanctions if there is a military aggression against Ukraine," he said, without mentioning Nord Stream. "It is part of the process that we do not spell out everything in public, because Russia should understand that there might be even more to come." "Will you commit today to turning off and pulling the plug on Nord Stream 2?" asked Shalal. But Scholz would not. "As I already said, we are acting together. We are absolutely united and we will not be taking different steps," he replied, ignoring Shalal's question.
US Gas Diplomacy Won't Avert Price Spike If Russian Supplies Interrupted: Kemp - U.S. policymakers are reportedly hunting around the world for alternative sources of gas in the event conflict between Russia and NATO over Ukraine interrupts pipeline supplies to Europe. Top officials have approached rival producer Qatar as well as consuming countries in Asia, including Japan, South Korea and even China, about diverting liquefied natural gas (LNG) cargoes to Europe. The diplomatic effort is likely intended to reassure European policymakers about security of supply and stiffen their resolve to threaten tough economic sanctions. It is also probably meant to signal NATO resolve to Russia as part of an escalate-to-negotiate strategy intended to demonstrate escalation dominance and convince the Russian government to back down. Qatar has already been rewarded with a summit at the White House and formal designation under U.S. law as a major non-NATO ally, which could unlock a variety of economic, diplomatic and military benefits But while the highly publicized hunt for alternative supplies has value as diplomatic theatre it is unlikely to improve Europe’s energy security very much. Energy security depends on prices as much as physical availability and any sustained interruption of Russian supplies would cause a damaging price spike in Europe and the rest of the world.Globally, there is little spare capacity at any stage in the LNG supply chain, as recent record prices have shown, so increased supplies to Europe could only come at the expense of reduced supplies in other regions. Unlike oil, where the consuming countries hold strategic stocks to offset the risk of an embargo, gas stocks are low and designed to deal with seasonal consumption swings rather than politically motivated supply interruptions. There is no equivalent for gas of the U.S. Strategic Petroleum Reserve and the network of other strategic petroleum stocks held by countries in the International Energy Agency.Gas is more difficult and expensive to store than crude oil and liquid fuels, and until now has been treated as less of a national security issue. In the event a NATO/Russia conflict reduced or halted pipeline supplies to Europe for more than a few days, the global production-consumption balance would worsen and prices would surge higher for all consumers outside the United States. Gas prices in Northwest Europe and Northeast Asia are already closely correlated because they both draw on the same suppliers of LNG (https://tmsnrt.rs/3AWT7qn).Moreover, consumers in Asia could only agree to re-route LNG cargoes to Europe at the cost of reducing their own supply security next winter.Short-term swaps in which consumers in Asia agreed to divert LNG to Europe on the understanding they will receive the cargoes back before next winter would only postpone Europe’s supply crunch until later in the year. Longer term swaps that saw consumers in Asia repaid after next winter would leave them facing unacceptably high risks to their own supply security between November 2022 and March 2023.These strategies all emphasize the essentially zero-sum nature of limited gas supplies in the short term would leave all consuming countries as a group with lower gas inventories over the next twelve months.
EXPLAINER: What happens to Europe's energy if Russia acts? - (AP) — Fears are rising about what would happen to Europe’s energy supply if Russia were to invade Ukraine and then shut off natural gas exports in retaliation for U.S. and European sanctions.The tensions show the risk of Europe’s reliance on Russia for energy, which supplies about a third of the continent's natural gas. And Europe's stockpile is already low. While the U.S. has pledged to help by boosting exports of liquefied natural gas, or LNG, there’s only so much it can produce at once.It leaves Europe in a potential crisis, with its gas already sapped by a cold winter last year, a summer with little renewable energy generation and Russia delivering less than usual. Prices have skyrocketed, squeezing households and businesses.Here's what to know about Europe's energy supply if tensions boil over into war and Russia is hit with sanctions: No one knows for sure, but a complete shutoff is seen as unlikely, because it would be mutually destructive. Moscow relies on energy exports, and though it just signed a gas deal with China, Europe is a key source of revenue. Europe is likewise dependent on Russia, so any Western sanctions would likely avoid directly targeting Russian energy supplies.More likely, experts say, would be Russia withholding gas sent through pipelines crossing Ukraine. Russia pumped 175 billion cubic meters of gas into Europe last year, nearly a quarter of it through those pipelines, according to S&P Global Platts. That would leave pipelines under the Baltic Sea and through Poland still operating.“I think in the event of even a less severe Russian attack against Ukraine, the Russians are almost certain to cut off gas transiting Ukraine on the way to Germany,” said former U.S. diplomat Dan Fried, who as State Department coordinator for sanctions policy helped craft 2014 measures against Russia when it invaded and annexed Ukraine’s Crimea peninsula.Russia could then offer to make up the lost gas if Germany approves the contentious new Nord Stream 2 pipeline, whose operators could face potential U.S. sanctions even though a recent vote to that effect failed.U.S. national security adviser Jake Sullivan said Sunday on NBC's “Meet the Press" that the Biden administration has coordinated with its allies and that “if Russia invades Ukraine, one way or another, Nord Stream 2 will not move forward."Interrupting gas supplies beyond the Ukrainian pipelines is less likely: “If they push it too far, they're going to make a breach with Europe irreparable, and they have to sell the oil and gas someplace,” Fried said.
Russia expands China ties with new gas deal -Russia and China have clinched a new gas supply deal, as Moscow doubles down on its pivot towards Beijing against a backdrop of heightened tensions with the West over Ukraine. Russia’s national gas company Gazprom announced on February 4 that it had agreed on the annual sale of 10bn cubic metres per year of natural gas to China’s CNPC over a 30-year period. The agreement underpins the development of a new export route for Russian gas to China in the Far East. Russia already pumps gas to China via the Power of Siberia pipeline, which was opened in late 2019. These supplies are sent under a $400bn deal the two countries reached in 2014, not long after ties between Russia and the West collapsed following Moscow’s annexation of Crimea. While Power of Siberia is filled with gas from onshore fields in Eastern Siberia, the latest contract is for supplies from the South-Kirinskoye field off the east coast of Sakhalin Island. The deal was signed on the same day as Russian President Vladimir Putin’s arrival in Beijing to attend the 2022 Winter Olympics. Moscow and Beijing are eager to stress their close ties in the face of worsening relations with the US. According to the Kremlin, up to 15 agreements could be signed between the two countries during Putin’s visit. Russia has been steadily expanding its economic, and more recently, its political ties with China over the past decade, and energy trade has played a main role in this shift. While the EU is still Russia’s top export market, China is in second place, with its imports totalling $79.3bn in value in 2021, according to the Chinese customs agency. Oil and gas accounted for $44.6n of this sum. Russia has jostled in recent years with Saudi Arabia for the position of China’s biggest oil supplier. Last year, it delivered 1.59mn barrels per day (bpd) of crude, accounting for 15.5% of Chinese imports. These supplies are sent via the Eastern Siberia Pacific Ocean (ESPO). Chinese investors also have a position in Russia’s upstream, LNG and petrochemicals sectors, most notably at Novatek’s Yamal LNG and upcoming Arctic LNG-2 plants in the Russian Arctic. Russia is also China’s third-largest gas supplier, sending 16.5 bcm of the fuel in 2021, via pipeline and in LNG form, covering around 5% of Chinese gas demand. Gazprom launched Power of Siberia in December 2019, establishing piped gas exports to China for the first time.
Hunter Biden Tried To Broker Energy Deal With China's State-Owned Oil Company: Emails - The Chinese oil company alleged to be part of the deal, the State China National Offshore Oil Corporation (CNOOC), is not any ordinary firm. Last year, the U.S. Commerce Department identified the company as posing a threat to U.S. national security and added it to a trade blacklist called the “Entity List.” The Pentagon named CNOOC as one of Beijing’s “military companies” in December 2020. That same month, the U.S. State Department asked U.S. investors (pdf) to steer away from investing in stock and bond indices having “malign PRC companies” on their portfolios, with CNOOC being one of the many companies named. The People’s Republic of China is the official title of China. The Daily Mail obtained the emails from what is alleged to be Hunter Biden’s abandoned laptop, showing him travel to Beijing and Kazakhstan in an effort to broker the oil deal in the two-year period. At that time, he tried to negotiate the deal on behalf of a Ukrainian energy firm named Burisma where he was a board member, according to the outlet. According to the emails, the plan was for the Kazakh government to award drilling rights to CNOOC, while Burisma would operate rigs and wells in the Central Asian country. Kazakhstan, once a part of the Soviet Union, is rich in oil and natural gas, sitting on one of the largest oil reserves in the world. Currently, an oil pipeline runs from Atasu, a town in Kazakhstan, to Alashankou, a border city in China’s far-western Xinjiang region. Hunter Biden apparently tried to team up with Karim Massimov, who was Kazakh prime minister from 2007 to 2012 and from 2014 to 2016, to make the deal happen. In the emails, Hunter described Massimov as a “close friend” and his son as a “very good friend.” Massimov also headed Kazakhstan’s intelligence agency—the National Security Committee (KNB) that succeeds the Soviet-era KGB—until he was sacked in early January this year. Soon after, he was detained on suspicion of treason. According to the Daily Mail, there is no indication that the treason charge against Massimov is connected to the oil deal.
Saudi Arabia's natural gas aspirations: The domestic outlook | Middle East Institute - With the recent announcement of the Jafurah Field, a massive unconventional, non-associated gas play, the Kingdom of Saudi Arabia is looking to enter the global gas sector. The field’s estimated reserves, while substantial, are insufficient to meet current domestic needs and, in the future, displace dirty heavy fuel oil used in power generation and satisfy international export goals. The kingdom thus faces difficult decisions regarding the allocation of the Jafurah gas — to either domestic or international markets — and both options have significant challenges.For more than 20 years Saudi Arabia has studied its gas resources and their potential impact on domestic fuel needs. Beginning in 2019, it launched a renewed effort to utilize domestic gas resources to displace heavy fuel oils for power supply and to provide expanded fuel supply to meet growing domestic demand, especially in the hot summer months. According to a December 2019 report from the King Abdullah Petroleum Studies and Research Center (KAPSARC), domestic demand for natural gas is expected to increase by 3.7% annually from 2017 to 2030. However, according to an analysis of the role natural gas will play in the Saudi Vision 2030 development plan, Jadwa Investment estimated that gas output will need to rise by as much as 6.6% on average per year in the decade to 2030 to meet domestic demand driven by growing power and industrial needs. The challenges facing gas supply growth include the following:
- Resource base
- Capability and skill set
- Capital
- Supply chain
- Infrastructure, and
- The domestic gas conundrum
These challenges must be addressed and overcome for domestic natural gas to play a more significant role in the kingdom’s energy supply. With the recent announcement of the Jafurah development plan, the country and its operating company, Saudi Aramco (Aramco), are now moving into the implementation phase. The country, and specifically Aramco, will need to address key issues before the Jafurah play can achieve commerciality. Aramco has technical skills that can be applied and utilized in the development of Jafurah. However, the company’s technical focus has been oil production in carbonate reservoirs. It deploys modern technology to manage these expansive fields. Additionally, Aramco has delivered major capital projects such as natural gas and crude oil treatment plants. That said, most of the natural gas produced in the kingdom is associated gas, which is reinjected for pressure maintenance of the all-important oil reservoirs to ensure production and cash flow. Aramco has minimal experience in tight gas play delineation or development and is woefully understaffed with technical specialists in this sector. U.S. gas production is the culmination of decades of experience and the development of a multigenerational workforce with expertise in geology, geophysics, drilling, petrophysics, completion, and production. Aramco plans to start production from Jafurah in 2024 and to reach 2.2 billion cubic feet (bcf) per day of gas by 2036. The company has limited experience in manufacturing-style resource exploitation and has yet to climb the learning curve, which will add expense and consume capital.
Exploded Nigerian oil storage vessel had up to 60,000 barrels before incident - An oil storage vessel that exploded off the coast of Nigeria this week was holding around 50,000 to 60,000 barrels of crude oil at the time of the incident, Minister of Environment Sharon Ikeazor said on Saturday. Nigeria's Shebah Exploration & Production Company Ltd (SEPCOL) said on Thursday that flames had engulfed the Trinity Spirit floating production, storage and offloading (FPSO) vessel following a blast a day earlier. Ikeazor said the National Oil Spill Detection and Response Agency has called the oil industry operators and the Clean Nigeria Associates, a co-operative responding to oil spill incidents for support. SEPCOL, in receivership, said it was working with authorities to inspect the vessel after the fire burnt out and an investigation team has been launched to establish the cause of the explosion. It reported no casualties and is investigating the whereabouts and safety of 10 crew members who were on board the vessel prior to the incident, SEPCOL said in a statement. An industry source with knowledge of operations of the Trinity Spirit FPSO said until five years ago other companies, including large oil traders, stored their crude on the vessel, which had capacity to produce 22,000 barrels per day and could store 2 million barrels. The Trinity Spirit is the primary production facility for OML 108, which covers 750 square km (290 square miles) of water off the Niger Delta, ranging from a depth of 30 metres to 213 metres, SEPCOL's website said.
Nigerian parliament urges probe into oil vessel fire (Xinhua) -- Nigeria's House of Representatives on Wednesday urged the federal government to probe into a recent deadly fire at an oil vessel. The aim of the probe "was to unearth the remote and immediate causes of the explosion to prevent a recurrence," the parliament said. The vessel, operated by Nigeria's Shebah Exploration and Production Company, suddenly caught fire at a port in the southwestern state of Ondo last week, leaving at least three people dead. The country's economy was impacted by the explosion of the vessel, which had about 50,000 barrels in storage, and it may take a long time to recover, the parliament said, noting the surrounding coastal communities may feel the repercussions as well, including water pollution, death of aquatic animals, and dispersal of surviving fish. On Monday, Nigeria's Minister of State for the Environment Sharon Ikeazor said in a statement that the National Oil Spill Detection and Response Agency had launched an overflight to monitor the situation of a crude oil spill in the affected area.
State of emergency over Thailand oil spill A province in eastern Thailand has declared a state of emergency after crude oil reached its beaches following an oil spill from a ruptured pipeline late last month. Approximately 47,000 litres of oil are estimated to have leaked into the Gulf of Thailand from an underwater hose used to load tankers at an offshore single point mooring (SPM) owned by Star Petroleum Refining Company (SPRC), in which US supermajor Chevron is the majority shareholder. SPRC said that divers have been able to inspect the subsea equipment around the SPM and had identified a failure on one of the subsea flexible hoses. “We have a long history as a safe, reliable and caring operator. We take full responsibility for our operations [and] are deeply saddened and disappointed by the impact of this spill,” SPRC chief executive Robert Joseph Dobrik told a media briefing on Friday. “SPRC will undertake a thorough investigation of the incident and get to the root cause of the failure,” he said. The company is continuing to evaluate and monitor the impact of the crude spill on the environment and communities, and it will continue with its clean-up operations.
OPEC+ falls further behind its oil output quotas, hampered by disruptions: Platts survey - OPEC and its allies continue to underperform their increasingly lofty oil production targets, with the group falling a record 700,000 b/d short of its collective quotas in January, according to the latest S&P Global Platts survey. OPEC's 13 countries raised output by 150,000 b/d from December, pumping 28.19 million b/d of crude, while the nine non-OPEC partners, led by Russia, only managed to add a meager 10,000 b/d, producing 13.99 million b/d, the survey found. In all, 14 out of the 18 members with quotas underproduced their targets, pushing OPEC+ compliance to 120.8%, the highest since the group instituted record output cuts in spring 2020 to pull the oil market out of its pandemic crash, according to Platts calculations. Despite strong gains from the group's core Gulf members and Russia, along with a resurgent Nigeria, disruptions in several OPEC+ countries, including Venezuela, Kazakhstan, Libya and Iraq, limited the bloc's growth. The coalition's struggles to keep pace with its monthly 400,000 b/d quota hikes have drawn a chorus of criticism from its key crude customers, including the US and India, who say the group should tap its shrinking spare production capacity to bring oil prices down from recent seven-year highs. However, OPEC+ officials, who are next scheduled to meet March 2 to determine April output targets, say prices have overshot levels that current market fundamentals would indicate, driven by rising geopolitical risks in the Ukraine and elsewhere. And they say that many underperforming countries face only temporary setbacks that can quickly be reversed. Nigeria, plagued by numerous operational and technical problems over the past year, is one such example, posting the largest increase among OPEC+ members in January to hit a nine-month high, according to the Platts survey. Africa's largest oil producer pumped 1.57 million b/d, up by 190,000 b/d from December, aided by a recovery in key export grade Forcados. Even so, it was well under its quota of 1.683 million b/d. OPEC+ co-leaders Russia and Saudi Arabia both pumped 10.08 million b/d in January, also failing to hit their quotas of 10.122 million b/d. Platts Analytics estimates about 325,000 b/d of additional upside in Russian output by the end of 2022, which would leave it well short of its final target of 11 million b/d under the OPEC+ agreement. Russia's "production growth in 2022 will not keep pace with its quota increases under the current framework deal," Platts Analytics said in a recent note. Meanwhile, Saudi Arabia saw its crude exports rise modestly in January, while domestic refining runs appeared to pick up. The kingdom boosted output by 130,000 b/d, the survey found. Neighboring UAE, which has often chafed at the production restraints imposed by the OPEC+ agreement, slightly exceeded its quota in January, pumping 2.93 million b/d. Venezuela, which is exempt from a quota under the OPEC+ deal, had a major slowdown, as reduced supplies of diluents dragged down production from its extra heavy oil fields. It produced 630,000 b/d in January, the survey found, down 120,000 b/d.Imports of Iranian condensate, which it uses to blend its extra-heavy crude, had helped the Latin American country recover its output in recent months. But an expected cargo for January did not arrive, sources said, forcing Venezuela to shut in production.Another exempt member, Libya, slipped under 1 million b/d for the first time since October 2020 due to issues at its southwestern and eastern oil fields. Production did rebound sharply in the second half of January, but rough weather also resulted in lower exports.
Libya's daily oil production drops by 100,000 barrels per day (Xinhua) -- The state-owned Libyan National Oil Corporation (NOC) announced on Friday that the country's daily oil production has dropped by 100,000 barrels per day due to its inability to maintain oil tanks damaged by armed conflicts. "The National Oil Corporation expresses deep concern about having to reduce daily oil production as a result of the inability to carry out maintenance of tanks damaged by wars, as well as the disruption of some emergency projects," the NOC said in a statement. Currently, 11 out of the 19 oil tanks are out of service, making it impossible to maintain oil production, according to NOC Chairman Mustafa Sanalla. Waha Oil Company, a Tripoli-based company engaged in the exploration and production of crude oil and natural gas, "was forced to reduce its production by about 100,000 barrels per day as a result of the lack of storage capacities, because of the suspension of maritime traffic in the ports of the Sirte Gulf," Sanalla said. The NOC statement said bad weather caused the closure of most oil ports in the Sirte Gulf, but the closure could have been averted if proper infrastructure had been in place. Oil and gas are a primary source of revenue for Libya. Nonetheless, armed conflict and the shutdown of oil fields and ports have hurt the sector in recent years. Last month, Sanalla announced plans to carry out extensive maintenance work on a number of oilfields that had been damaged by armed conflicts and terrorist attacks, in order to maintain the average daily production of 1.2 million barrels. In January, the daily oil production in Libya was about 946,000 barrels.
IRAQ DATA: Federal oil exports in Jan drop 2% despite higher OPEC+ quota | S&P Global Platts -- Iraq's federal oil exports, excluding flows from the semi-autonomous Kurdistan region, fell more than 2% in January from December, the oil ministry said Feb. 1, despite a higher OPEC+ quota for the month. Federal oil exports in January dropped to 3.203 million b/d from 3.277 million b/d in December, according to the ministry figures. Iraq's OPEC+ quota rose to 4.281 million b/d in January from 4.237 million b/d in December as members of the 23-member coalition continued to ease their production curbs by 400,000 b/d a month. The quota covers production, and not exports. The ministry did not disclose volumes of internal crude consumption nor inventory changes. Iraq's February quota is 4.325 million b/d. Iraq has not yet released the production figures for January. OPEC+ ministers, who are convening monthly, are set to meet virtually on Feb. 2 to decide on March production levels. Federal Iraq's central and southern exports fell 2% to 3.111 million b/d in January from a month earlier, while its exports of Kirkuk crude via the Turkish Port of Ceyhan declined 5.7% to 82,118 b/d. Iraq's exports of Kirkuk were briefly disrupted on Jan. 18-19 after flows from the Kirkuk-Ceyhan pipeline stopped following an explosion in southern Turkey which temporarily shut the key export route. OPEC's second largest producer raked in January $8.27 billion by selling its crude at $83.246/b, compared with $7.39 billion in exports at $72,768/b in December.
Iran heads to become gasoline importer, ready to boost oil output - Iran will become a gasoline and gas oil importer in the next two or three years due to strong domestic consumption, oil minister Javad Owji said, the oil ministry's news service Shana reported on Feb 6. Domestic refinery capacity is set to increase by around 200,000 b/d within two or three years, he said. "We have signed contracts for an additional 1.46 million b/d to be implemented in a period of four to six years for refineries that produce feedstock for petrochemical plants," the oil minister added. He pointed out that $2.5 billion to $3 billion is needed to add every 100,000 b/d of refining capacity, and funding will be arranged. Iran is capable of exporting 2.5 million b/d of oil, with capacity at about 4 million b/d, he said. Gas output is 840 million cm/day. If US sanctions against Iran's oil exports are removed, the country is able to raise output back to 2018 levels, Farrokh Alikhani, deputy managing director of National Iranian Oil Co., said, according to a a Feb. 6 report by news agency Naftkhabar that was posted to the NIOC website. "We believe that there are requirements to reach 4 million b/d of oil production and we are seriously endeavoring to reach it in the next year (2022-2023)," Alikhani said. Eventual US sanctions relief for Iran could ease oil market tightness, with a Biden administration official saying Jan. 31 that the six-month negotiations over the nuclear deal were entering their "final stretch," though a full agreement that leads to unimpeded Iranian oil exports may not be implemented for months. Iran's production was 2.5 million b/d in December, according to a monthly S&P Global Platts survey. Dated Brent assessed by Platts finished last week at a seven-year high of $93.55/b. Owji said that the country is looking into major foreign investments from China and Russia. "In the next eight years, we allocate $15 billion-$20 billion to develop oil and gas fields. Under the 25-year agreement with the Chinese, about the same amount will be invested... We try to reach the same deal with the Russians," he said. "Within two-three months, we will hopefully sign contracts with Russian companies for the transfer of technology, manufacturing equipment and production increase," he said.
Crude oil tests $95 per barrel; Saudi Arabia increases oil prices -Saudi Arabia raised oil prices for customers in Asia, the US and Europe after crude’s surge to almost $95 a barrel. State firm Saudi Aramco increased all grades for its main market of Asia in March. The company raised its key Arab Light oil for the region by 60 cents from February to $2.80 per barrel above the benchmark it uses. Other Asian grades jumped by between 40 and 70 cents a barrel. US prices were increased by 30 cents. Brent crude has climbed around 20% in 2022 to more than $93 a barrel. Its rise has come as global consumption remains strong despite the spread of omicron variant of the virus. In addition, oil stockpiles have plummeted in the past year and many major producers are struggling to pump more. Aramco’s decision came days after Opec+ opted to increase its daily crude production by 400,000 barrels a day next month, in line with traders’ expectations. Many energy analysts doubt the group, led by Saudi Arabia and Russia, will add that much back to the market because of the supply problems among some of its members. Saudi Aramco is the world’s biggest oil exporter. More than 60% of its shipments go to Asia, with China, Japan, South Korea and India being the biggest buyers. Aramco’s pricing moves often set the tone for other producers in the Middle East.
Oil falls on positive signals from U.S.-Iran talks - Oil prices fell on Monday as signs of a progress in the U.S.-Iran nuclear talks that could lead to removal of U.S. sanctions on Iranian oil sales offset concerns about the tight supplies. Brent crude declined 58 cents, or 0.62%, to end the day at $92.69 per barrel, after earlier touching $94.00, its highest level since October 2014. U.S. West Texas Intermediate crude fell 99 cents, or 1.07%, to settle at $91.32 per barrel. U.S. President Joe Biden's administration on Friday restored sanctions waivers to Iran to allow international nuclear cooperation projects, as the talks on the 2015 international nuclear deal enter the final stretch. Although the sanctions relief will have limited impacts on Iran's struggling economy, they were perceived by the markets as positive signal that both sides are determined to reach a deal. If the United States lifts sanctions on Iran, the country could boost oil shipments, adding to global supply. "Investors expect more twists and turns in the U.S.-Iranian talks and no agreement to be reached anytime soon," said Kazuhiko Saito, chief analyst at Fujitomi Securities Co Ltd. Commerzbank analyst Carsten Fritsch said: "If the oil sanctions were also to be relaxed, this could help ease the oil market." Crude prices, which have already rallied about 20% this year, are likely to surpass $100 per barrel because of strong global demand, analysts have said. The Organization of the Petroleum Exporting Countries (OPEC) and allies led by Russia, together known as OPEC+, are struggling to meet targets despite pressure from top consumers to raise production more quickly. Fuelling supply concerns, tensions remain high in Eastern Europe, with White House national security adviser Jake Sullivan saying on Sunday that Russia could invade Ukraine within days or weeks but might still opt for a diplomatic path.
WTI, Brent Extend Losses as Iranian Nuclear Talks Advance (DTN) -- New York Mercantile Exchange oil futures and Brent crude traded on the Intercontinental Exchange extended Monday's losses into early trading Tuesday, sending the international crude benchmark below $91 per barrel (bbl) on a combination of easing geopolitical risks, including partial lifting of Iranian sanctions on civilian nuclear projects ahead of the final stretch in multinational talks in Vienna this week, and potential for deescalating tensions between Russia and the West following France President Emmanuel Macron's visit to Moscow. After marathon meetings in Moscow and Kiev, Macron told journalists he was able to receive assurances from Russia's President Vladimir Putin that the situation in Ukraine would not deteriorate any further, adding that "there is no security for the Europeans if there is no security for Russia." Putin signaled negotiations that lasted more than five hours were productive, saying "a number of Macron's ideas are a possible basis for further steps. We will do everything to find compromise that suits everyone." Moscow has demanded North Atlantic Treaty Organization forces be withdrawn from Eastern Europe and Ukraine, Russia's immediate neighbor on its western border, and that Ukraine would never be granted membership in the alliance. United States and NATO rebuked the demands, citing NATO's policy of "open doors" and principle of "self-determination." For the energy markets, the winter's escalation of tensions along the Russian-Ukrainian border fueled concerns over interrupted gas flow from Russia to the European Union, sending EU gas prices to record highs. Russia supplies between 40% and 50% of Europe's gas consumption, about 200 billion cubic meters (bcm) a year, of which around 100,000 bcm goes via the central and northern pipeline routes, which includes the Ukrainian network. Separately, oil traders are watching for signs of progress in Iranian nuclear talks that have appeared to reach their final stage this week after U.S. President Joe Biden renewed waivers for Iranian nuclear projects designated for civilian use. Representatives from Moscow and Tehran have suggested the new deal could be imminent now that the Biden administration is ready to negotiate. White House has come under intense scrutiny for rising gasoline prices that have rallied to seven-year highs, with the energy index expected to be the largest contributor of inflation in January. The headline inflation figure likely climbed above 7% last month -- the highest since 1982. Out of all items that are part of U.S. consumer price index, gasoline prices posted the single largest increase last year, surging 49.8% in the 12 months ending in December. In Eurozone, inflation for January came in at a record-high 5.1%, also driven by the energy index, despite easing costs for manufactured goods. Lifting sanctions on Iranian crude oil exports could offer much-needed relief for dwindling oil inventories across countries that are part of the Organization for Economic Cooperation and Development. A S&P Platts analysis suggests Iran could immediately boost crude oil exports by 700,000 barrels per day (bpd), bringing them back to pre-sanctions era of 2 million bpd. The country currently produces around 2.476 million bpd, 1.5 million bpd below 2017 level, a year before Trump withdrew from the nuclear arrangement known as the Joint Comprehensive Plan of Action. Near 7:30 a.m. ET, March West Texas Intermediate futures fell below $90 bbl, shedding $1.64 in overnight trading, and Brent crude for April delivery declined $1.87 to $90.83 bbl. NYMEX March RBOB futures plummeted more than 5 cents or 1.9% to $2.6354 gallon and the front-month ULSD contract slumped 6.16 cents to $2.7938 gallon.
Oil Down 2% on Easing Geopolitical Risk Ahead of Stock Data -- Oil futures nearest delivery posted across-the-board losses Tuesday. Both U.S. and international crude benchmarks settled the session 2% lower amid a one-two punch of easing geopolitical tensions across the Ukraine-Russian border and reported progress in Iranian nuclear talks in Vienna, where diplomats signaled the deal could be imminent after negotiations entered their final stage this week. Further weighing on the oil complex, U.S. commercial crude oil inventories are expected to have increased 500,000 barrels (bbl) in the week ended Feb. 4, with estimates ranging from a decrease of 2.2 million bbl to an increase of 3.5 million bbl. If realized, this would mark the second consecutive weekly build for nationwide crude oil inventories following a largely sustained destocking pattern since late November 2021. Widespread winter storms across the United States likely weighed on fuel consumption but demand also softened in regions spared from inclement weather which might signal inflationary headwinds from higher oil prices. In its Short-term Energy Outlook released Tuesday afternoon, EIA estimated oil inventories in countries that are part of the Organization for Economic Cooperation and Development again fell in January and now stand at their lowest level since mid-2014. The agency expects global inventories will continue to draw in February, with an average Brent spot price of $90 bbl. However, the recent destocking pattern will reverse around March, April, and continue throughout the forecast period said EIA, which would likely result in lower crude oil prices. EIA doesn't forecast OECD commercial inventories to return to their five-year average until mid-2023. The oil complex came under selling pressure Tuesday following media reports of an apparent breakthrough in Russian-Ukrainian disagreements over the border dispute and Ukraine's bid to become a member of the North Atlantic Treaty Organization. French President Emmanuel Macron told journalists he was able to receive assurances from Russian President Vladimir Putin that the situation in Ukraine would not deteriorate any further, adding, "There is no security for the Europeans if there is no security for Russia." On the session, March West Texas Intermediate futures fell $1.96 to $89.36 bbl, and Brent crude for April delivery declined $1.91 for a $90.78 bbl settlement. NYMEX March RBOB futures plummeted more than 6 cents to $2.6251 gallon and the front-month ULSD contract slumped 6.28 cents to $2.7926 gallon.
WTI Falls Below $89 as Traders Eye Iran Talks, Stock Data -- Oil futures extended lower in early trade Wednesday as investors increasingly price in the return of Iranian crude oil exports following an apparent breakthrough in multilateral nuclear talks in Vienna, where diplomats are trying to revive the 2015 Joint Comprehensive Plan of Action, with a deal likely easing pressure on low oil inventory levels in countries that are part of the Organization for Economic Cooperation and Development. U.S. Energy Information Administration estimates industry stockpiles held by the industrialized nations in Europe, Asia and North America declined again in January to the lowest level since mid-2014. Demand has exceeded supply growth since mid-2020, according to EIA estimates, leading to six consecutive quarters of global oil inventory draws. What's more, even as a destocking pattern reverses around March-April, OECD stockpiles are unlikely to return to five-year average levels until roughly mid-2023, leaving the market vulnerable to supply disruptions and geopolitical tensions. Against this backdrop, traders anxiously watch the latest round of talks in Vienna on Iran's nuclear program, where diplomats returned to the negotiating table on Tuesday after a weeklong break of consultations at their respective capitals. The potential deal with Tehran could lift sanctions on as much as 2 million barrels (bbl) in daily crude oil shipments, which would be a welcome development for a rapidly dwindling crude stockpiles held by OECD countries. It is debatable how much Iran was able to export in recent months, with China a major buyer of Iranian barrels that are being sold through third party intermediaries. The country currently produces around 2.476 million bpd, still 1.5 million bpd below the 2017 output rate, a year before then President Donald Trump withdrew from the JCPOA nuclear arrangement. Separately, the American Petroleum Institute reported late Tuesday U.S. commercial crude oil inventories dropped 2.025 million bbl last week, missing calls for a 500,00 bbl build. The report also showed stocks at the Cushing, Oklahoma, hub down 2.502 million bbl. Gasoline stockpiles fell 1.138 million bbl in the week through Feb. 4 versus an estimated 1.4 million bbl build. API data show distillate inventories dropped 2.203 million bbl last week compared with an expected draw of 2.1 million bbl. Near 7:30 a.m. ET, March West Texas Intermediate futures fell $0.22 to $89.12 bbl, and Brent crude for April delivery slipped to $90.63 bbl. NYMEX March RBOB futures edged higher to $2.6320 gallon and the front-month ULSD contract traded lower near $2.7896 gallon.
WTI Surges Back Above $90 After Across-The-Board Inventory Draw, Gasoline Demand Rebound --Oil prices have stabilized today after sliding yesterday with WTI bouncing back up towards $90 after last night's across-the-board inventory draws reported by API. “Oil markets are walking a tight rope today as the specter of the Omicron variant appears to be waning in many parts of the world, encouraging countries to relax restrictions and boosting crude demand as a result,” said Louise Dickson, Rystad Energy’s senior oil markets analyst. “Rising demand often comes hand-in-hand with upward price movements, but a long-awaited supply relief could be around the corner, helping to narrow the imbalance and cool market sentiment. Inventories are now in the crosshairs for signs of demand revival amid ever tightening supply. API
- Crude -2.025mm (+100k exp)
- Cushing -2.502mm
- Gasoline -1.138mm (+1.4mm exp)
- Distillates -2.203mm (-600k exp)
DOE
- Crude -4.756mm (+100k exp)
- Cushing -2.801mm
- Gasoline -1.644mm (+1.4mm exp)
- Distillates -930k (-600k exp)
Official DOE data confirmed API's reported inventory draws across the board with a notably large crude draw (and drop in stocks at Cushing). gasoline stocks drewdown for the first time in 7 weeks...US Crude inventories (ex SPR) fell to their lowest since 2018... Source: Bloomberg Gasoline demand is rebounding from its Omicron crushing. Pre-storm stockpiling at retail stations could have spurred gasoline demand. In a few weeks, fuel suppliers will be turning over some diesel tanks in preparation for the transition from winter to summer grade gasoline.
Oil Ends Higher on Supportive Inventory Data, Softer USD - Following choppy trading for most of the session, crude and refined products futures pushed higher in market-on-close trade Wednesday, finding support from a bullish drop in U.S. petroleum stockpiles last week and a softening dollar index as traders positioned ahead of the release of U.S. inflation data for January that could reveal the fastest rise in the consumer price index in 40 years. The weekly inventory report from the Energy Information Administration was surprisingly bullish for the oil complex, showing across-the-board draws from U.S. petroleum stockpiles and stronger fuel demand for the week ended Feb. 4 despite winter weather, including icy conditions in some states from Texas to Maine, that made driving hazardous. Total crude and oil products stockpiles fell by 8.1 million barrels (bbl) to 1.171 billion bbl -- the lowest inventory level since mid-2014, and nearly 8% below the five-year average. Commercial crude oil inventories declined 4.8 million bbl from the previous week to about 10% below the five-year average at 410.4 million bbl compared with expectations for a 500,000 bbl build. Globally, industry stocks held by countries that are part of the Organization for Economic Cooperation and Development also stand at their lowest since mid-2014, according to EIA estimates released Tuesday. What's more, even as a destocking pattern is seen reversing around March-April, OECD stockpiles are unlikely to return to five-year average levels until roughly mid-2023, leaving the market vulnerable to supply disruptions and domestic and geopolitical tensions. Wednesday's inventory report was also supportive for the gasoline complex, showing domestic inventories unexpectedly fell by 1.6 million bbl to 248.4 million bbl compared with analyst expectations for inventories to have increased by 1.4 million bbl last week. Demand for motor gasoline shot up 900,000 barrels per day (bpd) to 9.126 million bbl -- the highest implied demand rate since the week of Dec. 24. Distillate stocks fell 930,000 bbl to 121.8 million bbl, and remain about 19% below the five-year average, the EIA said. Analysts estimated distillate inventories would fall by 2.1 million bbl from the previous week. Demand for distillates climbed 373,000 bpd from the previous week to 4.296 million bpd. In outside markets, U.S. Dollar Index weakened against a basket of global currencies to finish the session at 95.494, while also lending limited support to front-month West Texas Intermediate. At settlement, March WTI futures gained $0.30 to $89.66 bbl, and Brent crude for April delivery advanced to $91.55 bbl, adding $0.77 on the session. NYMEX March RBOB futures moved 2.83 cents higher to $2.6534 gallon, and the front-month ULSD contract rallied 3.23 cents to $2.8249 gallon.
Oil steady amid prospects of aggressive US Fed Reserve rate hike – Brent above $91/bbl -After rising more than 1% in early trade, Brent crude futures settled down 14 cents, or 0.2%, at $91.41 a barrel. U.S. Texas Intermediate crude, which rose more than $2 earlier in the day, settled up 22 cents, or 0.3% to $89.88 a barrel. After U.S. inflation data came in on Thursday at its hottest in 40 years, St. Louis Federal Reserve Bank President James Bullard said he wanted a full percentage point of interest rate hikes by July 1. Interest rates futures showed a 60% chance of a 50-basis-point hike in March after Bullard`s comments, and U.S. stock markets fell. The dollar gave up some of its earlier losses. A stronger greenback makes oil and other commodities more expensive for those holding other currencies. "Prices are confused between what appears to be strong inventory statistics and signs that the Fed is going to raise rates quicker than expected in 2022," said Scott Shelton, energy specialist at United ICAP. On Wednesday, oil prices rallied after data showed crude inventories fell unexpectedly last week to their lowest since October 2018, while fuel demand hit a record high. After the data, oil prices reversed a slide spurred by the resumption of indirect U.S.-Iran nuclear talks a day earlier. A deal could lift U.S. sanctions on Iranian oil and ease global supply tightness. Earlier this week, crude benchmarks hit seven-year highs on political concerns, and as a robust demand recovery from the coronavirus pandemic has kept inventories at fuel hubs globally at multi-year lows. On Thursday, the Organization of Petroleum Exporting Countries said world oil demand might rise even more steeply this year as the global economy posts a strong recovery. The report also showed OPEC undershot a pledged oil output rise in January under its pact with allies to gradually unwind record output cuts put in place in 2020. Overall, thin supplies of crude oil, low storage and global output that is nearing a maximum are driving up prices,
Oil Prices Spike After U.S. Officials Say Ukraine Invasion Expected Next Week - Oil prices spiked Friday, with Brent hitting $95 a barrel and U.S. crude almost matching that on White House concerns that Russia will invade Ukraine soon. Even so, WTI settled below the day's highs and slightly down for the week after the White House walked back some of its own saber-rattling on the Russia-Ukraine conflict. US National Security Adviser Jake Sullivan told a White House media briefing that a Russian attack on Ukraine could happen by next week and would likely begin with an air assault. Sullivan, however, added that the White House did not claim that Russian leader Vladimir Putin has made a final decision on the matter. That caused oil prices to pull back from their earlier highs. New York-traded West Texas Intermediate settled up $3.22, or 3.6%, at $93.10 a barrel. WTI hit an intraday high of $94.65 earlier. For the week though, WTI was down 37 cents, or 0.3%, registering its first decline after seven straight week of gains. London-traded Brent, the global benchmark for oil, hit a session high of $95.65 before settling at $94.44, up $2.98, or 3.3%. That put Brent up 1.3% for the week, giving it an eight straight week of gains. Aside from the Russia-Ukraine conflict, the International Energy Agency also rattled energy markets by warning that global oil supplies might be dangerously short of demand. The Paris-based IEA in a monthly report on Friday, lifted its forecast for this year’s global oil demand by 800,000 barrels a day to 3.2 million barrels. What’s more, it estimated there could be a billion barrels shortfall by the end of last year between what the Organization of the Petroleum Exporting Countries and its allies — known as OPEC+ — were supposed to have pumped versus actual deliveries to the market since the start of 2021. “The oil market is incredibly tight,” Toril Bosoni, head of the IEA’s markets and industry division, said in a Bloomberg television interview on Friday. “Prices continue to surge and are now reaching levels that are uncomfortable for consumers across the world.” Prior to the Russia-Ukraine brouhaha and the IEA warning, oil prices had lost more than 3% on the week -- first on concerns that Iranian oil supplies could legitimately return to the market through a Tehran-West nuclear deal and later on fears that the Federal Reserve could impose rate hikes of as much as 0.5% a month over several months to curb runaway U.S. inflation.
Oil soars 3% to 7- year highs on Ukraine jitters, tight supplies Oil prices ended 3 per cent higher on Friday at fresh seven-year highs as escalating fears of an invasion of Ukraine by Russia, a top energy producer, added to concerns over tight global crude supplies. Russia has massed enough troops near Ukraine to launch a major invasion, Washington said, as it urged all U.S. citizens to leave the country within 48 hours. Britain also advised its nationals to leave Ukraine as Prime Minister Boris Johnson impressed the need for NATO allies to make it absolutely clear that there will be a heavy package of economic sanctions ready to go, should Russia invade Ukraine. Brent crude futures settled US$3.03, or 3.3per cent, higher at US$94.44 a barrel, while U.S. West Texas Intermediate crude rose US$3.22, or 3.6per cent, to US$93.10 a barrel. Both benchmarks touched their highest since late 2014, surpassing the highs hit on Monday, and posted their eighth consecutive week of gains on growing concerns about global supplies as demand recovers from the coronavirus pandemic. Trading volumes spiked in the last hour of trading, with volumes for global benchmark Brent climbing to their highest in more than two months. "The market doesn't want to be short going into the weekend ... if an invasion appears to be imminent and you know that there will be retaliatory sanction that will result in a disruption in natural gas and oil supplies," Andrew Lipow, president of Lipow Oil Associates in Houston. The International Energy Agency raised its 2022 demand forecast and expects global demand to expand by 3.2 million barrels per day (bpd) this year, reaching an all-time record 100.6 million bpd. [IEA/M] The energy watchdog's report follows the Organization of the Petroleum Exporting Countries' warning earlier this week that world oil demand might rise even more steeply this year on a strong post-pandemic economic recovery. [OPEC/M] The IEA added that Saudi Arabia and the United Arab Emirates could help to calm volatile oil markets if they pumped more crude, adding that the OPEC+ alliance produced 900,000 bpd below target in January. The two OPEC producers have the most spare production capacity and could help to relieve dwindling global oil inventories that have been among factors pushing prices towards US$100 a barrel, deepening inflation worldwide. The Biden administration responded to high prices by again stating this week that it has been talking with large producers about more output, as well as the possibility of additional strategic releases from large consumers, as it did late last year. Indirect U.S.-Iran nuclear talks resumed this week after a 10-day break. A deal could see the lifting of sanctions on Iranian oil and ease supply tightness. In the United States, drillers added the most oil rigs in a week in four years, with the rig count, an indicator of future production, rising 19 to 516, its highest since April 2020, energy services firm Baker Hughes Co said.
New nuclear deal ‘in sight,’ US says as senators vow to block it - A revived agreement to curb Iran’s nuclear program is “in sight,” the US said on Tuesday as international talks resumed in Vienna. Negotiators from Iran, Britain, China, France, Germany, and Russia returned to the luxury Palais Coburg hotel in the Austrian capital after a break last month for consultations with their governments. The US is involved in the talks indirectly. The aim is to restore the 2015 Joint Comprehensive Plan of Action, which collapsed in 2018 when the US pulled out. The JCPOA restricted Iran’s nuclear development in return for the lifting of economic sanctions. “A deal that addresses all sides’ core concerns is in sight, but if it is not reached in the coming weeks, Iran’s ongoing nuclear advances will make it impossible for us to return to the JCPOA,” the US State Department said. Iranian Foreign Ministry spokesman Saeed Khatibzadeh said that answers that “the US brings to Vienna will determine when we can reach an agreement. We have made significant progress in various areas.” Eric Brewer of the US nonproliferation watchdog Nuclear Threat Initiative said there remained “a combination of issues that require resolution,” including the scope of sanctions relief and what to do with nuclear equipment Iran had installed. “They are the final sticking points for a reason — they are contentious and require concessions that neither side has been willing to make so far,” he said. Russian negotiator Mikhail Ulyanov said the negotiating teams were “five minutes away from the finish line. A draft of the final document has been crafted. There are several points there that need more work, but that document is already on the table.” German Chancellor Olaf Scholz said the talks were at “the decisive moment.” However, a powerful group of 33 Republican US senators warned President Joe Biden that they would work to thwart any new deal unless Congress reviewed it and voted on its terms. Led by Sen. Ted Cruz, a long-time opponent of the 2015 nuclear deal, the senators told Biden they would use “the full range of options and leverage available.” The senators said any nuclear agreement with Iran was of “such gravity for US national security” that it would by definition be a treaty requiring the advice and consent of two-thirds of the Senate. Any deal that fell short of a Senate-ratified treaty would probably be “torn up in the early days of the next presidential administration,” they said.
Houthis renege on new deal to prevent Red Sea oil spill disaster - The Iran-backed Houthi militia in Yemen on Sunday reneged on a deal to head off an environmental disaster in the Red Sea, only hours after reaching an agreement with the UN. The Houthis first said they supported a new plan by UN officials to pump one million barrels of oil out of the decaying oil storage vessel Safer, which is moored off the port of Hodeidah. But as the UN’s Yemen coordinator David Gressly hailed “constructive” talks on the plan, which is also supported by Yemen’s government, the Houthis backtracked. They said the UN was guilty of “continued disregard of its obligations” over the tanker and accused the UN mission of wasting funds allocated for maintaining the vessel. The rusting storage tanker is more than 40 years old and has not been maintained since early 2015, when international experts fled as the Houthis took control of swaths of Yemen in a coup. The Safer crisis erupted again as the top US military officer in the Middle East arrived in the UAE for defense talks after a series of Houthi missile attacks on Abu Dhabi. Environmentalists have issued a series of warnings about the danger. The Safer has neither power nor a functioning fire-fighting system, and volatile gases are thought to be building up inside. “The risk of imminent catastrophe is very real,” Gressly said. “We need … action as soon as possible.” Greenpeace said last week that the Safer posed a “grave threat.” An oil spill would prevent access to Yemen’s main ports of Hodeidah and Salif, affecting food aid supplies for up to 8.4 million people. The environmental group said desalination plants on the coast could be affected, which would interrupt the drinking water supply for about 10 million people. Yemeni fisheries would probably shut down and ecosystems in the Red Sea would be destroyed, it said, with the impact reaching Saudi Arabia, Djibouti and Eritrea. The Safer crisis erupted again as the top US military officer in the Middle East arrived in the UAE for defense talks after a series of Houthi missile attacks on Abu Dhabi. Gen. Frank McKenzie, head of Central Command, said: “I think it’s a very worrisome time for the UAE. They’re looking for support. We’re here to help provide that support.” Last week the Pentagon deployed advanced F-22 fighter jets and the guided missile destroyer USS Cole to the UAE. McKenzie blamed Iran for the attacks on Abu Dhabi. “Medium-range ballistic missiles that were fired from Yemen and entered the UAE were not invented, built, designed in Yemen,” he said. “All that happened somewhere else. So I think we certainly see the Iranian connection to this.”
War threat escalates as Israel strikes Syrian army targets - In a dramatic escalation of US and NATO provocations against Russia, Israel launched multiple strikes on Syrian army targets near Damascus early Wednesday morning, killing one soldier and wounding five more. The attack brought a rare and sharp denunciation from Russia. It confirms the warning issued by the World Socialist Web Site in its statement “US-NATO escalate war threats against Russia: Are you ready for World War Three?” that irrespective of Washington’s plans or expectations, “The unleashing of a war with Russia would within weeks—if not days—drag in Iran, Israel, China and Taiwan.” Syria’s news agency SANA reported that some of the strikes came from fighter jets flying over southeast Lebanon and others from surface-to-surface missiles fired from the Golan Heights, which Israel has illegally occupied and annexed since capturing the territory during the 1967 war with its Arab neighbours. Syrian air defences had brought down some of the missiles, but the Israeli attack had caused serious damage to civilian buildings in Qudsaya city, northwest of Damascus. The Israel Defense Forces (IDF) claimed it had attacked targets in Syria, including a radar facility and anti-tank batteries, in response to an earlier anti-aircraft missile fired Tuesday into northern Israel that exploded in the air without causing any injuries or damage. While the rocket had not been intercepted by Israeli air defences, it activated warning sirens in Umm al-Fahm, a Palestinian city in northern Israel. The Syrian-launched rocket followed a series of strikes launched over the last 10 days by the IDF against targets in the Damascus area that Israel claims are Iranian weapons dumps or military outposts belonging to Hezbollah. Israel has launched hundreds of airstrikes on Syria, attacking government positions as well as fighters and facilities belonging to Lebanon’s Hezbollah and Iranian forces. According to the London-based Syrian Observatory for Human Rights, Israel had struck at least 29 targets in Syria in 2021, down from 39 strikes in 2020 which it said was highest since 2011. Israeli attacks had killed 130 people, including five civilians. Nearly half of those killed were affiliated with Iranian-backed militias.
Syria oil sector losses top $100bn since start of war - Syria's petroleum sector has incurred losses of more than $100bn since the start of the civil war more than a decade ago, the country's oil ministry said yesterday. Losses since the start of the civil war in 2011 have come to $100.5bn, the ministry said without elaborating on whether this was in terms of lost hydrocarbon revenues, losses due to damaged infrastructure or both. The last decade of war has brought about a collapse in Syria's oil and gas production to just a fraction of what it was, and seen the country make the switch from a net crude oil exporter to an importer. The ministry said oil production in 2021 averaged 85,900 b/d — well below the 383,000 b/d Syria was producing in 2010, before the start of the war. Of this, only around 16,000 b/d is being produced in fields under the government's control and therefore reaching Syria's two operational refineries, the 110,000 b/d Homs and 140,000 Banias refineries. The remaining 70,000 b/d comes from the fields on the east bank — an area that continues to be controlled by the Kurdish-led Syrian Democratic Forces and the US military. Syrian oil production peaked at just over 600,000 b/d in the mid-1990s and has been on the decline ever since. The ongoing unrest and dwindling domestic crude output have forced the country to rely on imports of crude and oil products from its sanctions-hit ally Iran to meet domestic demand. This has also forced the country's two refineries to operate well under capacity for much of the past few years. The ministry estimated that the Homs and Banias refineries, together, produced around 5.7mn t of oil products in the past year. That included 944,000t (21,800 b/d) of premium and 11,000t of regular gasoline, as well as 1.519mn t (31,000 b/d) of diesel, 2.734mn t (48,300 b/d) of fuel oil and 77,000t of asphalt. The ministry also put Syria's gas production at 12.5mn m3/d in 2021 — a little more than a third of what it was in the first quarter of 2011. Of this, around 79pc was delivered to the country's ministry of electricity, 6pc to the ministry of industry and 15pc to the oil ministry.
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