Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 12 June 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
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Oil and natural gas prices at fresh highs; refinery utilization at a 17 month high; global oil shortage at 1.6 million bpd
Oil prices rose to a new 31 month high for a third consecutive week on forecasts from both the EIA and IEA for higher fuel demand in the second half of this year…after rising 5% to $69.62 a barrel last week on ongoing OPEC+ production restraint and on falling US crude supplies, the contract price of US light sweet crude for July delivery opened lower on Monday and slid more than 1% as traders awaited the outcome of this week’s talks between Iran and the US over a deal that was expected to boost crude supplies, but clawed back part of the early losses to finish 39 cents lower at $69.23 a barrel as increased demand expectations for Europe and the U.S. placed a floor under the market…oil prices extended their loss early Tuesday on profit taking and on a stronger U.S. dollar, but rallied after US Secretary of State Blinken said that hundreds of sanctions targeting Iran are likely to remain in place even if Iran returned to compliance to settle 82 cents higher at $70.05 a barrel, thus closing above $70 for the first time since October 2018….after reaching $70.62 in early trading, oil prices dipped on Wednesday after the EIA reported big increases in gasoline and distillates inventories, and settled 9 cents, or 0.1%, lower at $69.96 a barrel, mostly due to weak fuel demand following the Memorial Day weekend, normally the kickoff of the peak summer driving season…after opening lower Thursday, oil prices drew support from higher-than-forecast U.S. inflation data and a strong demand outlook, and finished 33 cents higher at $70.29 a barrel after the EIA forecast a decline in global oil inventories and higher prices in the second half of 2021.…oil prices rose again Friday after the IEA (International Energy Agency) said that OPEC would need to increase production to meet demand in the 2nd half, and finished up 62 cents at a fresh multi-year high of $70.91 a barrel, thus finishing the week 1.9% higher and posting its third straight weekly rise to the highest settle since mid-October 2018…
Natural gas prices rose for the ninth time in ten weeks and settled at a 7 month high, after a major eastern pipeline annouced pressure and volume restrictions…after rising 3.7% to $3.097 per mmBTU last week on forecasts for hot weather and high AC demand, the contract price of natural gas for July delivery opened higher Monday but faded to close 2.7 cents lower at $3.070 per mmBTU after gas output rose and the eastern US forecast shifted to a little further cooler for the next couple of weeks…but July natural gas prices rose 5.8 cents to a 15-week high of $3.128 per mmBTU on Tuesday after the European weather model projected a larger increase in cooling degree days (CDD) over the next two weeks than was previously expected…natural gas prices held steady despite hotter forecasts on Wednesday and closed just a tenth of cent higher at $3.129 per mmBTU, and then were up a modest 2.0 cents to $3.149 per mmBTU even with a bearish storage report on Thursday as higher temperatures and Appalachian supply concerns kept pressure on prices…but natural gas prices jumped 5% Friday after a major natural gas pipeline warned that pressure restrictions it had in place could last through the end of September and settled 14.7 cents higher at $3.296 per mmBTU, thus ending trading at a 7 month high, and with an increase of 6.4% on the week…
The natural gas storage report from the EIA for the week ending June 4th indicated that the amount of natural gas held in underground storage in the US rose by 98 billion cubic feet to 2,411 billion cubic feet by the end of the week, which still left our gas supplies 383 billion cubic feet, or 13.7% below the 2,794 billion cubic feet that were in storage on June 4th of last year, and 55 billion cubic feet, or 2.2% below the five-year average of 2,466 billion cubic feet of natural gas that have been in storage as of the 4th of June in recent years….the 98 billion cubic feet that were added to US natural gas storage this week was a bit above the average forecast of a 95 billion cubic foot addition from an S&P Global Platts survey of analysts, and was also above the average addition of 92 billion cubic feet of natural gas that have typically been injected into natural gas storage during the first week of June over the past 5 years, as well as just above the 95 billion cubic feet that were added to natural gas storage during the corresponding week of 2020…
The Latest US Oil Supply and Disposition Data from the EIA
US oil data from the US Energy Information Administration for the week ending June 4th showed that despite a big increase in our oil imports and an increase in our crude production, we still needed to withdraw oil from our stored commercial crude supplies for the eighth time in the past sixteen weeks and for the 30th time in the past forty-six weeks….our imports of crude oil rose by an average of 1,007,000 barrels per day to an average of 6,638,000 barrels per day, after falling by an average of 641,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 387,000 barrels per day to an average of 2,931,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,707,000 barrels of per day during the week ending June 4th, 620,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells reportedly rose by 200,000 barrels per day to 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 14,707,000 barrels per day during this reporting week…
Meanwhile, US oil refineries reported they were processing 15,925,000 barrels of crude per day during the week ending June 4th, 327,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 941,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 276,000 barrels per day less than what our oil refineries reported they used during the week…to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just plugged a (+276,000) 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 fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that we have just transcribed…..furthermore, since last week’s EIA fudge factor was at (+892,000) barrels per day, that means there was a 615,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, thus rendering the week over week supply and demand changes we have just transcribed useless….however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be accurate by most everyone in the industry….(for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports rose to an average of 6,238,000 barrels per day last week, which was 1.9% less than the 630,000 barrel per day average that we were importing over the same four-week period last year… the 941,000 barrel per day net withdrawal from our crude inventories included a 749,000 barrel per day withdrawal from our designated commercially available stocks of crude oil, and a 193,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which has been leased for commerical purposes…this week’s crude oil production was reported to be 200,000 barrels per day higher at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 200,000 barrels per day higher at 10,600,000 barrels per day, while an 3,000 barrel per day increase in Alaska’s oil production to 443,000 barrels per day had no impact on the rounded national total….US crude oil production was at a prepandemic record high of 13,100,000 barrels per day during the week ending March 13th 2020, so this week’s reported oil production figure was 16.0% below that of our production peak, yet still 30.5% above the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
US oil refineries were operating at 91.3% of their capacity while using those 15,925,000 barrels of crude per day during the week ending June 4th, up from 88.7% of capacity the prior week, and the highest refinery utilization since January 10th of last year…while the 15,925,000 barrels per day of oil that were refined this week were the most since February 21, 2020 and 18.1% higher than the 13,484,000 barrels of crude that were being processed daily during the pandemic impacted week ending June 5th of last year, they were still 6.7% below the 17,064,000 barrels of crude that were being processed daily during the week ending June 7th, 2019, when US refineries were operating at a close to summertime normal 95.7% of capacity…
Even with this week’s increase in the amount of oil being refined, the gasoline output from our refineries decreased by 135,000 barrels per day to 4,762,000 barrels per day during the week ending June 4th, after our gasoline output had decreased by 182,000 barrels per day over the prior week…while this week’s gasoline production was still 15.9% higher than the 8,139,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 5.4% lower than the March 13th 2020 pre-pandemic high of 9,974,000 barrels per day, and 8.2% below the gasoline production of 10,276,000 barrels per day during the week ending June 7th, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 111,000 barrels per day to 4,918,000 barrels per day, after our distillates output had increased by 142,000 barrels per day over the prior week…while the pandemic pullback of last year didn’t have much of an impact on distillates’ production, this week’s distillates output was still 3.3% more than the 4,762,000 barrels of distillates that were being produced daily during the week ending June 5th, 2020…
Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the eighth time in ten weeks, and for the 22nd time in thirty weeks, rising by 7,046,000 barrels to 241,026,000 barrels during the week ending June 4th, after our gasoline inventories had increased by 1,499,000 barrels over the prior week...our gasoline supplies increased by more this week because the amount of gasoline supplied to US users decreased by 666,000 barrels per day to 8,480,000 barrels per day, even as our exports of gasoline rose by 397,000 barrels per day to 957,000 barrels per day, while our imports of gasoline rose by 117,000 barrels per day to 1,050,000 barrels per day…and even after this week’s inventory increase, our gasoline supplies were 6.8% lower than last June 5th’s gasoline inventories of 258,661,000 barrels, but close to the five year average of our gasoline supplies for this time of the year…
Meanwhile, with the increase in our distillates production, our supplies of distillate fuels increased for the second time in nine weeks and for the 12th time in 25 weeks, rising by 4,412,000 barrels to 132,802,000 barrels during the week ending June 4th, after our distillates supplies had increased by 3,720,000 barrels during the prior week….our distillates supplies rose this again week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 400,000 barrels per day to 3,413,000 barrels per day, even as our imports of distillates fell by 327,000 barrels per day to 189,000 barrels per day while our exports of distillates rose by 85,000 barrels per day to 1,063,000 barrels per day….but after seven inventory decreases over the past 9 weeks, our distillate supplies at the end of the week were still 22.0% below the 175,829,000 barrels of distillates that we had in storage on June 5th, 2020, and about 5% below the five year average of distillates stocks for this time of the year…
Finally, with the ongoing increase in our oil refining, our commercial supplies of crude oil in storage fell for the 19th time in the past thirty weeks and for the 25th time in the past year, decreasing by 5,241,000 barrels, from 479,270,000 barrels on May 28th to 474,029,000 barrels on June 4th, after our crude supplies had decreased by 5,079,000 barrels the prior week….after this week’s decrease, our commercial crude oil inventories were about 4% below the most recent five-year average of crude oil supplies for this time of year, but were still about 34% above the average of our crude oil stocks as of the the first week of Junw over the 5 years at the beginning of this decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring, our commercial crude oil supplies as of June 4th were 11.9% less than the 538,065,000 barrels of oil we had in commercial storage on June 5th of 2020, and now 2.4% less than the 485,470,000 barrels of oil that we had in storage on June 7th of 2019, but still 9.6% more than the 432,441,000 barrels of oil we had in commercial storage on June 8th of 2018…
OPEC’s Monthly Oil Market Report
Thursday of this past week saw the release of OPEC’s June Oil Market Report, which covers OPEC & global oil data for May, and hence it gives us a picture of the global oil supply & demand situation for the first month of the modest output easing policy initiated by OPEC and other producers at their early April meeting, which was actually the fourth production quota policy change they’ve made over the past year, all in response to the pandemic-related slowdown and subsquent recovery….but before we start, we want to again caution that the oil demand estimates made by OPEC herein, while the course of the Covid-19 pandemic still remains uncertain in most countries around the globe, 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 check is from the page numbered 47 of this month’s report (pdf page 57), 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 from the above table of their oil production data, OPEC’s oil output increased by a rounded 390,000 barrels per day to 25,463,000 barrels per day during May, up from their revised April production total of 25,073,000 barrels per day…however, that April output figure was originally reported as 25,083,000 barrels per day, which therefore means that OPEC’s April production was revised 10,000 barrels per day lower with this report, and hence OPEC’s May production was, in effect, a 380,000 barrel per day increase from the previously reported OPEC production figure (for your reference, here is the table of the official April OPEC output figures as reported a month ago, before this month’s revision)…
From the table above, we can see that a production increase of 345,000 barrels per day from the Saudis was the major factor in OPEC’s May output increase; the reason for that increase is that the Saudis unilaterally committed to cut their own production by a million barrels per day during February, March and then later during April of this year, and that they are now gradually unwinding that voluntary output decrease… recall that last year’s original oil producer’s agreement was to cut 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, but that agreement had been extended to include July at a meeting between OPEC and other producers on June 6th….then, in a subsequent meeting in July of last 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 and subsequent months, which was thus the agreement that covered OPEC’s output for the rest of 2020…the OPEC+ agreement for January’s 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 7.2 million barrels per day from that original baseline…then, during a difficult meeting on April 1st of this year, OPEC and the other oil producers that are aligned with them agreed to incrimentally adjust their oil production higher over the next three months, which is the agreement which governed OPEC’s May’s production that you see above…
Hence, to see if all the OPEC members continued to adhere to the production cuts they had committed to during May, we’ll include a copy of the production adjustments table that was provided as a downloadable attachment with the OPEC press release following their April 1st meeting with other oil producers…
The table above was included with the press release following the 15th OPEC and non-OPEC Ministerial Meeting on April 1st of this year, and it includes the reference production and expected production levels for the 10 members of OPEC that are expected to make cuts, as well as the same information for the other major oil producers who are party to what the press calls the “OPEC + agreement”….the first column in the above table shows the reference oil production baseline, in thousands of barrel per day, from which each of the oil producers was to cut from, a figure which is based on each of the oil producer’s October 2018 oil output, ie., a date before last year’s and the prior year’s output cuts took effect, and coincidently the highest monthly production of the era for most of the producers who are party to these cuts…the remaining columns show the adjustment, or cut, that each is expected to make from that reference production level, and then the oil output allowed for each producer under the April agreement for the months of May, June and July…
OPEC arrived at these figures by repeatedly adjusting the original 23%, or 9.7 million barrel per day cut from the October 2018 baseline first agreed to for May and June 2020, first to a 7.7 million barrel per day 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 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 this year….under the prior agreement, OPEC’s production cut in April was at 4,564,000 barrels per day from the October 2018 baseline; as you see above, their cut for May was lowered to 4,287,000 barrels per day from the baseline with the latest agreement…
The next graphic from this month’s report that we’ll highlight shows us both OPEC’s and worldwide oil production monthly on the same graph, over the period from June 2019 to May 2021, and it comes from page 48 (pdf page 58) of OPEC’s June Monthly 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 reported 390,000 barrel per day increase in OPEC’s production from what they produced a month earlier, OPEC’s preliminary estimate indicates that total global liquids production increased by a rounded 630,000 barrels per day to average 93.67 million barrels per day in May, a reported increase which apparently came after April’s total global output figure was revised down by 20,000 barrels per day from the 93.06 million barrels per day of global oil output that was reported for April a month ago, as non-OPEC oil production rose by a rounded 240,000 barrels per day in May after that revision, with with increases in the oil output from the US, the UK, Brazil and Guyana accounting for most of the non-OPEC production increase in May…
After that increase in May’s global output, the 93.67 million barrels of oil per day that were produced globally during the month were 4.30 million barrels per day, or 4.8% more than the revised 89.37 million barrels of oil per day that were being produced globally in May a year ago, which was first month of the OPEC + agreement to cut global output by 9.7 million barrels per day (see the June 2020 OPEC report (online pdf) for the originally reported May 2020 details)…with this month’s increase in OPEC’s output, their May oil production of 25,463,000 barrels per day was at 27.2% of what was produced globally during the month, an increase of 0.2% from their 27.0% share of the global total in April….OPEC’s May 2020 production was reported at 24,195,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 1,268,000, or 5.2% more barrels per day of oil this May than what they produced a year earlier, when they accounted for 26.9% of global output…
However, even after the sizable increase in global oil output that we’ve seen in this report, the amount of oil being produced globally during the month again fell short of the expected demand, as this next table from the OPEC report will show us…
The table above came from page 27 of the OPEC June Oil Market Report (pdf page 37), and it shows regional and total oil demand estimates in millions of barrels per day for 2020 in the first column, and OPEC’s estimate of oil demand by region and globally quarterly over 2021 over the rest of the table…on the “Total world” line in the third column, we’ve circled in blue the figure that’s relevant for May, which is their estimate of global oil demand during the second quarter of 2021… OPEC is estimating that during the 2nd quarter of this year, all oil consuming regions of the globe will be using an average of 95.26 million barrels of oil per day, which is a rounded 470,000 barrels per day upward revision from the 94.79 million barrels of oil per day of demand they were estimating for the second quarter a month ago (note that we have encircled this month’s revisions in green), which still reflects quite a bit of coronavirus related demand destruction compared to 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 93.67 million barrels million barrels per day during May, which would imply that there was a shortage of around 1,590,000 barrels per day in global oil production in May when compared to the demand estimated for the month…
In addition to figuring May’s global oil supply shortfall that’s evident in this report, the upward revision of 470,000 barrels per day to second quarter demand that’s shown above, combined with the 20,000 barrel per day downward revision to April’s global oil supplies that’s implied in this report, means that the 1,730,000 barrels per day global oil output shortage we had previously figured for April would now be revised to a shortage of 2,220,000 barrels per day…
Note that in green we have also circled a downward revision of 360,000 barrels per day to OPEC’s previous estimates of first quarter demand…for March, that means that the 80,000 barrels per day global oil output shortage we had previously figured for March would be revised to a surplus of 280,000 barrels per day… similarly, the downward revision to first quarter demand means that the 1,290,000 barrels per day global oil output shortage we had previously figured for February would now be revised to a shortage of 930,000 barrels per day, and that the 70,000 barrels per day global oil output shortage we had previously figured for January would now be revised to a surplus of 290,000 barrels per day, in light of that 360,000 barrel per day downward revision to first quarter demand…
Also note in our green ellipse on the table above that we have circled an upward revision of 120,000 barrels per day to global demand for 2020…on a separate table on page 26 of the OPEC June Oil Market Report (pdf page 36) we can see this includes upward revisions of 190,000 barrels per day, 230,000 barrels per day, and 80,000 barrels per day for 2020’s 2nd, 3rd and 4th quarters respectively, and a downward revision of 20,000 barrels per day to first quarter 2020 demand…while we’re not inclined to go back and recompute the figures for each month of last year in light of those revisions, suffice it to say that the quantities of oil produced globally during the pandemic of 2020 averaged over 3 million barrels per day more than anyone wanted, and that an average 120,000 barrels per day upward revision to global demand is a drop in the bucket in comparison…
This Week’s Rig Count
The US rig count rose for the 34th time over the past 39 weeks during the week ending June 11th, but it’s still down by 41.8% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US was up by 5 to 461 rigs this past week, which was also up by 182 rigs from the pandemic hit 279 rigs that were in use as of the June 12th report of 2020, but was still 1,468 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business….
The number of rigs drilling for oil was up by 6 to 365 oil rigs this week, after being unchanged the prior week, and that’s now 166 more oil rigs than were running a year ago, but is still just 22.7% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was down by 1 to 96 natural gas rigs, which was still up by 18 natural gas rigs from the 78 natural gas rigs that were drilling a year ago, and still just 6.0% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….
The Gulf of Mexico rig count was unchanged at 13 rigs this week, with all 13 of those rigs drilling for oil in Louisiana’s offshore waters….that was the same number of Gulf of Mexico rigs that were drilling in the Gulf a year ago, when again all 13 Gulf rigs were drilling for oil offshore from Louisiana….since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig count… however, in addition to those rigs offshore, a rig continued to drill through an inland lake in St Mary parish, Louisiana this week, whereas there were no such “inland waters” rigs running a year ago…
The count of active horizontal drilling rigs was uup by 5 to 420 horizontal rigs this week, which was also up by 174 rigs from the 246 horizontal rigs that were in use in the US on June 12th of last year, but less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….in addition, the vertical rig count was up by one to 17 vertical rigs this week, and those were also up by 6 from the 11 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 24 directional rigs this week, which was still up by 2 from the 22 directional rigs that were in use on June 12th of 2020….
The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of June 11th, the second column shows the change in the number of working rigs between last week’s count (June 4th) and this week’s (June 11th) count, the third column shows last week’s June 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 June, 2020..
In addition to the usual spate of oil rig redeployments, we also have a number of natural gas rig changes this week…checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that two oil rigs were added in Texas Oil District 8, which is the core Permian Delaware, and another oil rig was added in Texas Oil District 7B, which includes the farthest east counties of the Permian Midland, while a rig was pulled out from Texas Oil District 7C, which encompasses the southern counties of the Permian Midland, which thus gives us a net increase of two rigs in the Texas Permian….since the Permian basin saw a four rig increase nationally, that means that the two rigs that were added in New Mexico had to have been set up to drill in the far west reaches of the Permian Delaware, to account for the national Permian basin increase…elsewhere in Texas, we find that a rig was added in Texas Oil District 6, which accounts for this week’s Haynesville shale natural gas rig increase, and that rig counts in all other Texas districts were unchanged…elsewhere, all three rigs added in Wyoming were apparently targeting oil in a basin that Baker Hughes doesn’t track, while an oil rig was pulled out from Alaska, also from an unnamed basin…in addition, we have two natural gas rigs pulled out of Ohio’s Utica shale, and a natural gas rig pulled out of Pennsylvania’s Marcellus, while a natural gas rig added in West Virginia’s Marcellus, thus leaving the Marcellus rig count unchanged and the national natural gas rig count down by one..
Gas waste dangers to be discussed – The Vindicator – Silverio Caggiano, newly retired Youngstown Fire Department battalion chief, will discuss hazards involved in the transport and disposal of waste products from the oil and gas industry. The Wednesday program is titled, “The Oil and Gas Industry: A Dangerous Game of Hide and Seek.” Caggiano, a retired Youngstown Fire Department Battalion Chief with 40 years of experience, graduated from the Canton Aultman paramedic program in 1985 and attended many other classes, including the Ohio Fire Academy for firefighter training, fire instructor and hazardous materials technician and instructor. He has taken classes on subjects such as incident command, terrorism, threat credibility assessment, nuclear, explosives, rail car incidents, bioterrorism, evidence collection and forensic epidemiology – to name a few. Caggiano said he got into HazMat in 1991. HazMat teams started in 1986 as a result of the Superfund Amendments and Reauthorization Act, also known as the Emergency Planning and Community Right-to-Know law. He went on to become a specialist and consultant in hazardous materials, serving as an active member of the Ohio HazMat Weapons of Mass Destruction Advisory Committee.With a lifetime of knowledge under his belt, Caggiano is able to address several issues of concern, such as the oil and gas waste products that come into the area.“Since Pennsylvania and New York have restricted their waste sites, Ohio has become the dumping ground for well drilling done in those states as well as our own,” he said. “The injection wells and above-ground dumps seem to pop up in low-income areas – places that can ill afford lawyers to fight the companies … “He said most of the waste travels by truck, which brings on its own problems.“These trucks have drivers that are not HazMat trained and have no idea what they are hauling,” Caggiano said. “If you or I owned a trucking company and we had a 55-gallon drum of what is inside their trucks, we would have to have certifications and drivers trained to HAZWOPER standards. Free pass to the oil and gas industry on all that.” Looking at the issue from the fire department’s perspective, there are even more problems. “That’s the kicker, you cannot prepare for what you don’t know about,” he said. “I would say the major concern with the frack waste is nuclear, but there is also a chemical contamination issue. And if you don’t know what the 11 secret herbs and spices are in the recipe, you’re flying blind.”He said he got into learning about fracking while attending an informational meeting at YSU on legislation working its way through Ohio in 2012. “My HazMat chief and I wanted to attend that meeting to show a presence for the community and to find out if it was true that first responders and local area planning committees were not entitled to material safety data sheets on what chemicals were at the well sites,” Caggiano said. “That was a huge departure from the norm. Unfortunately the rumors were true. “That’s when I jumped down the rabbit hole and the learning began as I met all the characters … hidden reports, untrained truck drivers, secret chemicals, bought and paid for Ohio legislators and much, much more.”
Columbiana County, OH Sees Uptick in Utica Drilling Interest – Columbiana County, Ohio, located in the northern part of the Utica Shale play in the state, was an early target for Aubrey McClendon (then-CEO of Chesapeake Energy). Aubrey was right about the Utica being “the biggest thing to hit Ohio since the plow.” But he was wrong about where the most productive wells would be located, which is further south in the play. Still, there’s money to be made in the northern Utica, and companies like Encino Energy (which now owns Chesapeake’s Ohio assets) and Hilcorp continue to drill in Columbiana.MDN did a quick check and found that since January 1 of this year, 14 permits to drill new shale wells in Columbiana have been issued. Two permits were issued to Encino for the same well pad in February, and 12 permits were issued to Hilcorp, also in February, all for the same well pad. And that’s been it for this year.We spotted a story appearing in the Youngstown Business Journal which says Encino has applied for (not yet awarded) permits to drill another four wells in Columbiana County. Hilcorp has been awarded a permit to “drill deeper” for one of its previously-drilled wells. We take this recent uptick in activity as a good sign that there’s a spark of life for Utica drilling in Columbiana. EAP Ohio LLC, a division of Encino Acquisition Partners, Houston, has submitted permit applications to drill four new horizontal wells in Washington Township in Columbiana County, according to data from the Ohio Department of Natural Resources.According to ODNR, the company plans to drill four new horizontal wells at its Sevek-18 pad. The permit applications are pending before the agency.Meanwhile, Houston-based Hilcorp Energy Co. was awarded a permit to drill deeper and build out a horizontal leg at its 10H well at the Tarka pad in Fairfield Township in Columbiana County, according to ODNR.Since January, ODNR has awarded 14 permits to the two oil and gas companies, which target the natural-gas rich Utica-Point Pleasant shale formation.So far this year, EAP has been awarded two permits to drill wells in Washington Township, while Hilcorp has been awarded 12 permits for new horizontal wells in Fairfield Township, according to ODNR.Natural gas production across the Utica-Point Pleasant and the Marcellus shale formation in Appalachia is expected to be lower in June compared to May, according to the U.S. Energy Information Administration’s latest drilling productivity report.According to EIA, natural gas production across Appalachia is projected to decline in June by 52 million cubic feet per day. Oil production, however, is expected to increase by 1,000 barrels per day, EIA reported.*
While we languish, the General Assembly’s biased energy agenda flourishes: Tracy Freeman, Nature Conservancy— While most Ohioans are reeling from the damaging effects of the pandemic – a mental state that The New York Times has recently labeled as languishing – our very own General Assembly has wasted no time in moving forward merciless personal agendas that favor fossil fuels. Specifically, there are several energy bills and provisions in the state budget bill that encourage the expansion of fossil fuels while decreasing opportunities for renewable energy.For example:
- · Senate Bill 52 creates yet another obstacle for wind energy and solar development in Ohio by burdening counties, the Ohio Power Siting Board and renewable energy developers with unprecedented requirements to approve and site wind and solar projects. These new steps in the siting process do not apply to any other energy source. As of yesterday afternoon, SB 52 had passed the Senate and is being considered by the House.
- · House Bill 201, House Bill 192, and Senate Bill 127: In stark contrast to SB 52, these bills would disallow local decision-making by prohibiting municipalities from limiting the use of fossil fuels and gas pipelines. This further adds to the regulatory bias toward fossil fuels. As of yesterday afternoon, HB 201 had passed the House and is pending in the Senate Energy and Public Utilities Committee.
- · Change in language for Ohio Oil & Gas Leasing Commission in budget bill: In keeping with this trend, a provision added by the Ohio House to House Bill 110, the biennial budget bill, makes it the state policy to “promote” oil and gas drilling, but, notably, no other sources of energy on state lands. This provision also reduces the transparency in this process and authorizes every state agency to bypass the Oil & Gas Leasing Commission to lease state land for exploration, development and production of oil and gas at terms established by the oil and gas companies. As of yesterday afternoon, HB 110 had passed the Senate and was before the House-Senate conference committee before being sent back to each legislative chamber for concurrence on changes and then to Gov. Mike DeWine for his signature.
In conflict with these regulatory trends is the will of the people. Polling over the last four years has increasingly shown that Ohioans want more renewable energy – an outcome that most believe would benefit the state economy, improve health, and reduce our reliance on foreign oil. These energy policies being considered and passed by our state legislature promote the opposite. This chasm should alarm us all.
Ascent Resources Floats $400M in New IOUs to Pay Down Older Debt – Ascent Resources, originally founded as American Energy Partners by gas legend Aubrey McClendon, is a privately-held company that focuses 100% on the Ohio Utica Shale. Ascent is Ohio’s largest natural gas producer and the 8th largest natural gas producer in the U.S. The company announced yesterday it is floating new “senior notes” (we call them IOUs) to retire or pay off other notes coming due. This business of issuing new notes to pay off old notes is routine. We’ve seen it dozens (maybe hundreds) of times over the years. This latest note swapping by Ascent follows a typical pattern. The company issues a press release announcing new notes will be floated for $X amount of money. Shortly after the first press release, the company issues a second release announcing the offering has been “upsized” for even more money. In the case of Ascent, the original announcement was an offering of $350 million in new notes. Soon after the number was upsized to $400 million.The first press release from yesterday: Ascent Resources Utica Holdings, LLC (together with its subsidiaries, “Ascent”) announced today that it, with its wholly-owned subsidiary, ARU Finance Corporation, intends to offer $350 million in aggregate principal amount of senior unsecured notes due 2029 (the “2029 Notes”) in a private placement to eligible purchasers under Rule 144A and Regulation S of the Securities Act of 1933, as amended (the “Securities Act”). Ascent intends to use the proceeds of the 2029 Notes offering to pay down a portion of the outstanding borrowings under its revolving credit facility. The second press release issued a short time later: Ascent Resources Utica Holdings, LLC (together with its subsidiaries, “Ascent”) announced today that it, with its wholly-owned subsidiary, ARU Finance Corporation, has priced an upsized private offering of $400 million in aggregate principal amount of 5.875% senior unsecured notes due 2029 (the “2029 Notes”) at par. Ascent will use the proceeds of the 2029 Notes offering to pay down a portion of the outstanding borrowings under its revolving credit facility.Debt financing like this is a fact of business life, at least in the upstream oil and gas business.
Weekly Shale Drilling Permits for PA, OH, WV: May 31-Jun 6 – Two of three Marcellus/Utica states received permits to drill new shale wells last week. Pennsylvania issued 13 new permits, almost all of them in the dry gas northeastern part of the state. Ohio issued 11 new permits, in the center of the Utica play. West Virginia’s shale industry got skunked last week – no new permits. It’s been quite a while since that’s happened in WV. PA table: https://marcellusdrilling.com/wp-content/uploads/2021/06/Weekly-Permits-Report-PA-0531-0606.pdf Ohio table: https://marcellusdrilling.com/wp-content/uploads/2021/06/Weekly-Permits-Report-OH-0531-0606.pdf
Tioga County Landowners Appeal UGI Takings Case to PA Supremes — Just coming to light for us now is a long-running lawsuit in Tioga County, PA by landowners who claim that UGI has taken their mineral rights as part of operating the Meeker Storage Field, an underground natural gas storage facility. The landowners lost the lawsuit in the Court of Common Pleas of Tioga County (trial court) in March 2019 (although the case began in 2016). The landowners appealed to Commonwealth Court and lost there too, in November 2020. The landowners appealed again, to the Pennsylvania Supreme Court. The Supremes have just accepted the case.
Philadelphia Gas Works to Reduce Methane Emissions 80% by 2050 – Philadelphia Gas Works announced a plan to replace decades-old pipes buried across the city to stop harmful methane gas from bleeding into the air. PGW, the nation’s largest municipally-owned gas utility, plans to cut methane emissions 80% by 2050 by modernizing infrastructure and implementing new technology, according to a news release. Methane is a powerful greenhouse gas that contributes to global warming at a rate more than 80 times that of carbon dioxide.The Intergovernmental Panel on Climate Change and the City of Philadelphia have committed to reaching carbon neutrality by 2050 to keep warming below 1.5 degrees centigrade.This will require PGW to offset their remaining emissions through planting trees or other measures, “Eighty percent is certainly better than nothing, but that remaining 20% of emissions is going to fall on somebody else to get rid of,” The company plans to replace 30 miles of natural gas mains with new, modern pipes, bringing emissions along the new mains to near zero.The Methane Reduction Program will also include accelerating the company’s leak reduction program to track, monitor, repair and reduce the amount of methane leaks. Since Philadelphia is an old city, he predicts that there are currently a high number of leaks in the old, cast iron pipes.The old distribution system, much of which is buried underground, could make it difficult to control the leaks, Altenburg said. It likely will require shutting down streets and tearing up sidewalks to perform the necessary updates.A 2015 report by the Pennsylvania Public Utilities Commission found 7,600 total leaks across PGW’s system with more than half being classified as hazardous. PGW has the highest percentage of at-risk pipe statewide, the report said.Scientists have found that emissions are significantly higher in urban areas, such as Philadelphia, although there is little information available about the local effects of greenhouse gases,
Natural gas flaring in Veazie –If you see flames shooting into the air in Veazie this week, don’t be alarmed. M & N Operating Company operates interstate natural gas pipeline facilities. Officials say they will be cleaning and inspecting a segment of a pipeline that runs from Eddington to Veazie. It requires a a safe and routine procedure called natural gas flaring. That will take place near the Shore Road in Veazie next to the power plant… They say personnel will be there during the entire operation. A smell of natural gas and a noticeable rushing sound may be present but they say there will be no danger to anyone in the area.
Supply disruptions and rising demand boosted East Coast petroleum product imports in March -Imports of petroleum products – gasoline, distillate, and other products – into the East Coast region of the United States increased in March 2021. Rising imports resulted from lower domestic supply, higher demand, and higher domestic petroleum product prices compared with prices in Europe. In March, East Coast petroleum product imports averaged 1.4 million barrels per day (b/d). In addition, East Coast gasoline imports averaged 737,000 b/d, the highest March level since 2009, and East Coast distillate imports averaged 421,000 b/d, the highest March level since 2003.Petroleum product imports into the East Coast region increased primarily for three reasons.First, domestic supply was reduced, due in part to the extreme winter weather in February 2021, which disrupted operations at several refineries in the U.S. Gulf Coast region, where more than half of U.S. refinery capacity is located. Because significantly more petroleum products are consumed in the East Coast region than its regional refineries produce, the region relies on imports and pipeline supplies from the U.S. Gulf Coast region.When production is disrupted in the U.S. Gulf Coast region (as was the case in February and March 2021), the East Coast region relies more on imports to meet its petroleum product demand. Lower supply, particularly in the East Coast region, has also been due, in part, to lower East Coast refining capacity after the 335,000 b/d Philadelphia Energy Solutions (PES) refinery closed in June 2019. We estimate that closing the Philadelphia refinery reduced East Coast gasoline supplies by approximately 160,000 b/d and distillate supplies by approximately 100,000 b/d.Second, domestic demand for petroleum products increased. U.S. gasoline consumption increased to 8.6 million b/d in March, the highest level since February 2020, and distillate consumption increased to 4.0 million b/d, the highest level since November 2019.Third, the prices of U.S. petroleum products have been higher than in Europe. In March, the New York Harbor gasoline spot price averaged 30 cents per gallon (gal) more than gasoline in Europe, the widest spot price spread between these markets in the past 10 years (2012 – 2021).
Foes of Line 5 debut ads with Jeff Daniels saying pipeline needs to go – Environmental opponents of Line 5 on Tuesday unveiled ads on TV and radio featuring actor and Michigan native Jeff Daniels lambasting it as “an aging, dangerous pipeline” that needs to be shut down for good. The six-figure statewide ads, sponsored by the National Wildlife Federation, are a direct response to the numerous ads run for months by Line 5 owner Enbridge warning of the public of dire consequences if the pipeline is shut down at the behest of Gov. Gretchen Whitmer. In a Zoom call with reporters, National Wildlife Federation officials said Enbridge is flouting the law, given that the governor has revoked the easement, and the misinformation campaign waged by the company has to be answered. “Jeff Daniels is a strong believer in our Pure Michigan way of life … we know our Pure Michigan way of life is at risk because of the threat Line 5 poses to the Great Lakes,” said Mike Shriberg, Great Lakes regional executive director for the federation. “NWF has been at the forefront of exposing the risks of Line 5 right from the very beginning.” Federation officials said the first run of the ads would be two weeks but more time and other ads are expected. “This is part of a comprehensive effort to set the record straight on this so it’s not just paid media and advertising,” Shriberg said. “We know we won’t match Enbridge dollar for dollar, but we also know that we’ve got the truth on our side.” Shriberg said the 68-year-old dual pipeline along the bottom of the Straits of Mackinac is a “ticking time bomb.” “It is possible, perhaps even probable, that we’d have catastrophic consequences for our drinking water, our wildlife and our economy if it were to happen,” he said. “The pipeline is decades past its original lifespan.”
Nicor natural gas pipeline in Black farming community in Kankakee County approved by Illinois Legislature, awaits Gov. J.B. Pritzker’s signature – With a big push from the Rev. Jesse Jackson, a Nicor natural gas pipeline proposed for a Black farming community in Kankakee County has moved a step closer even as some who live in the area and environmentalists continue to fight the project. In the final hours of the legislative session that ended early on June 1, Illinois legislators approved a package to help fund Nicor’s proposed gas line to the village of Hopkins Park in Pembroke Township. If Gov. J.B. Pritzker’s signs the measure into law – he hasn’t said whether he will – it would move the community into a decades-long fossil fuel commitment at the same time Illinois political leaders promise they’re working toward a clean energy future. The pipeline is opposed by a small group of farmers who say they are worried about the environmental impacts and have safety concerns. The farmers found support from environmentalists in opposing the $10 million plan, which needed legislative approval for taxpayer and gas customer subsidies. But the bill was passed with overwhelming support by lawmakers, many who say they were swayed by the argument that natural gas will spur economic development in the poor, rural community. “There’s been gross misrepresentation here,” Dr. Jifunza Wright-Carter, a farmer and pipeline opponent, told state legislators at a hearing in May.
Coast Guard, partner agencies, finish cleanup of oil spill in Norfolk creek – It took two weeks for crews to complete the cleanup of an oil spill in Norfolk.The cleanup efforts started after an on-shore waste oil tank overflowed into Steamboat Creek on Monday, May 24.The unnamed property owner is facing charges, Virginia Department of Health officials confirmed a couple days after the spill.Coast Guard Sector Virginia pollution responders, Virginia Department of Environmental Quality, Virginia Department of Emergency Management, and the Norfolk Fire Marshal’s Office worked with additional federal, state, and local agencies to coordinate cleanup operations and assess impacts, which concluded on June 7.Pollution teams removed approximately 250 bags of oiled debris and approximately 200 gallons of oil from the water. In total, teams used approximately 10,000 feet of sorbent material during the 14-day cleanup effort. This incident remains under investigation.
State lawmakers cut big oil a big break – Two weeks after the formal close of the Tennessee legislative season, a committee of lawmakers agreed to give the state’s petroleum companies a big break. The Joint Government Operations Committee approved new rules that shift the financial burden of cleaning up toxic spills at gas stations and truck stops from business owners to taxpayers for the next five years. The new rules will save Pilot Flying J, Chevron, Exxon and other companies, large and small, $2 million each year by eliminating environmental fees, while taxpayers will remain on the hook for roughly $14 million annually through a four-tenths-of-a-cent, per-gallon gas tax. The fees and gas tax, for decades, have been earmarked for a state fund used to pay for the clean-up of toxic spills from company-owned underground storage tanks used for petroleum reserves. When those tanks leak, they can spill dangerous levels of hazardous waste into soil and groundwater. A pin-prick sized hole in an underground storage tank can leak 400 gallons of fuel containing carcinogens and heavy metals that can contaminate a community’s drinking water, according to the Sierra Club. Cleaning up those leaks is an expensive undertaking that – up till now – has been shared by taxpayers and industry. The new rules, for the first time, also give company owners with a history of environmental violations access to the state’s clean-up fund for leaking tanks. Previously, companies who failed to comply with state environmental rules were barred from accessing state funding.
ENVIRONMENTAL JUSTICE: Memphis pipeline rekindles eminent domain fight — Monday, June 7, 2021 — – It’s four words that Wyatt Price probably wishes he could take back.Explaining why a planned oil pipeline was taking a roundabout path around Memphis through a Black neighborhood, Price, a land agent for the Byhalia Connection pipeline, last year told a gathering it was the “point of least resistance.”To those fighting the Byhalia project, it was a moment of unguarded candor that revealed a strategy to bulldoze the project through a low-income Black community with little clout.That’s a natural consequence of handing over condemnation powers to a private company with next to no regulatory scrutiny, property rights advocates say. The oil and gas industry says condemnation powers are essential to building needed pipelines. But its critics say “blank check” powers in the hands of private interests are ripe for abuse.”They go right where the land is cheapest, and that’s the poorest neighborhoods,” said David Bookbinder, chief counsel at the Niskanen Center, a think tank that takes a libertarian approach to eminent domain and environmental issues. “That’s absolutely ridiculous.”The companies behind the Byhalia project, Plains All American Pipeline LP and Valero Energy Corp., have used eminent domain, or the threat of it, to get about 97% of the land they need to lay 50 miles of pipe from one side of Memphis to the other. That includes land in predominantly white, wealthy areas in Mississippi.”The route was not driven by race, class, gender or any other demographic type – it wasn’t a choice to affect one group of people over another,” Brad Leone, Plains’ director of communications and public affairs, told E&E News in a statement.The company has disowned the remarks of Price, a Byhalia contractor who could not be reached for comment. At a meeting in the southwest Memphis community last fall, Plains spokesperson Katie Martin said he should have explained that the company had picked a path with the “least community impacts.”Private companies have used the power of eminent domain to get land for many of the pipes moving the products of the fracking-driven oil and gas boom to markets and refineries.Such authority, industry advocates say, is vital to building pipelines, which are in turn vital for the economy. Without eminent domain, a few landowners – or even just one – could block a project.”The benefit to the many outweighs the objections of a small minority,” said John Stoody, vice president of government and public relations at the Association of Oil Pipe Lines. “Everyone depends on energy.”What’s ridiculous, he said, is to think that pipeline planners would go out of their way to find cheap land. Changing a pipeline’s path might save thousands of dollars upfront, he said. But if it makes the line longer, construction could cost millions more.The route Plains and Valero chose cuts through 7 miles of predominantly Black southwest Memphis, heading south from a Valero refinery. It then sweeps 43 miles around the edges of the Memphis suburbs in northern Mississippi to a point near Byhalia, Miss., where it would connect to an existing north-south pipeline called Capline.Construction has not yet started on the project, but it’s under siege by community activists who say it would dump more industrial activity and pollution on the city’s Black community. They’ve joined with environmentalists who say it would jeopardize the aquifer that supplies the city’s drinking water (Energywire, May 3).
Colonial Pipeline CEO: ‘One of the toughest decisions I have had to make’ to pay a $4.4M ransom – – The CEO of Colonial Pipeline, which underwent a ransomware attack in early May that led to massive shutdowns of gas stations across the Southeast, said during a U.S. Senate hearing on Tuesday that it was his decision to pay a ransom to restore the company’s operations. “It was one of the toughest decisions I have had to make in my life,” Joseph A. Blount Jr. said in his opening statement. “But I believe that restoring critical infrastructure as quickly as possible, in this situation, was the right thing to do for the country.” Georgia-based Colonial Pipeline paid the $4.4 million ransom to hackers, part of a cyber criminal group called DarkSide, in order to obtain a key to unlock their pipelines. Senate Homeland Security & Governmental Affairs Committee Chairman Gary Peters said in his opening statement that the “federal government must develop a comprehensive, all-of-government approach to not only defend against cyberattacks, but punish foreign adversaries who continue to perpetuate them or harbor criminal organizations that target American systems.” Peters, a Michigan Democrat, then asked Blount how the federal government could help companies defend themselves from cyberattacks. Blount said that the federal government should designate a person of contact to help private companies that are experiencing cyberattacks. Blount testified before the committee about his company’s coordination with the Cybersecurity and Infrastructure Security Agency, also known as CISA, and what role the federal government should play in helping protect private companies from cyberattacks. Blount said that Colonial Pipeline did not reach out to CISA, but first asked for assistance from the FBI on May 7, the day of the attack, and that the FBI coordinated a meeting that included CISA. CISA is a standalone federal agency that operates under Department of Homeland Security oversight. It works with various agencies and private partners to evaluate cybersecurity threats and vulnerabilities and provides assessments to help safeguard those networks. “Private industry alone can’t do everything on their own,” Blount, who was the only witness, said during his testimony.
How bankruptcy lets oil and gas companies evade cleanup rules – A battle over who is responsible for cleaning up hundreds of oil and gas rigs in the Gulf of Mexico is quietly playing out in a bankruptcy court in southern Texas. The contestants in this game of fossil fuel infrastructure hot potato: Fieldwood Energy, an offshore drilling company attempting to offload more than $7 billion in environmental cleanup responsibilities; a group of oil majors including Chevron, Marathon Oil, and BP; and the Department of the Interior.* Fieldwood has declared bankruptcy, and a court is considering the company’s plan to split its assets, moving older legacy wells and drilling rigs that are expensive to clean up into two entities while creating a new company – appropriately named NewCo – to purchase the more profitable assets. The company proposes outright abandoning a fourth bucket of assets consisting of more than 1,170 wells, 280 pipelines, and 270 drilling platforms. Aging wells and drilling platforms pose multiple risks to the environment and human safety, including oil and gas leaks and explosions. A quirk in the regulations that govern offshore drilling allows the Interior Department to hold companies that previously operated on Fieldwood leases accountable for the cleanup. The department is charged with protecting public lands – both on land and offshore – and issues leases to more than 12 million acres of seabed, including in the Gulf. A single lease can contain multiple wells, and many of the leases that Fieldwood is proposing to abandon or “return” to predecessor companies could end up the responsibility of oil majors, such as Chevron and BP. Unsurprisingly, both companies have zealously objected to the company’s bankruptcy plan. While the oil companies attempt to dodge responsibility for cleanup, the Interior Department, has been filing objections to Fieldwood’s plan to transfer leases to other companies and abandon wells, stating that its environmental obligations are “nondischargeable” and that leases cannot be sold or transferred without sign-off from the federal government. Fieldwood is one of more than 260 oil and gas companies that has filed for bankruptcy in the last six years. With low prices and suppressed demand for oil and gas over the last year, operators have struggled to stay afloat. Many have been turning to bankruptcy in an attempt to shed their debts, reorganize their assets, and, in some cases, offload their environmental obligations. Utilizing limitations and loopholes in bankruptcy law, these companies are employing a playbook perfected by coal companies to shed their environmental and labor liabilities.
Why Plastic Pollution Is Even Worse Than You Think — Why Plastic Pollution Is Even Worse Than You Think – YouTube Along the banks of the Mississippi River, right before it spills out past New Orleans into the sea lies Cancer Alley. An 85 mile strip of shoreline where residents are contracting cancer at astronomical rates. But this isn’t a phenomenon based in genetics or some cruel twist of fate. Cancer Alley is the product of environmental pollution. And today we’re going to figure out exactly where this pollution is coming from. This is the story of plastics, the harm they cause, the industries that create them, and how that 85 mile strip of Mississippi shoreline and other areas like it are suffering because of them.If you walk into your kitchen, pretty much everything, in some way or another, has encountered plastic. The plastic bags you stuff into a drawer, your favorite cup and even the package keeping those blueberries fresh. But despite plastic’s ubiquity, we often forget where it comes from. Indeed, when it comes to plastic our efforts seem to be much more focused on what happens after we use it than before we use it. So first, let’s understand how plastic gets made. It all starts in an oil refinery or a fracking site. That’s right, plastics are basically just fossil fuels in solid form. In fact, 99% of plastics are made from chemicals rooted in fossil fuels. The plastic creation process begins with crude oil, coal, or natural gas, which is then refined and distilled or “cracked” into usable chemical compounds such as Ethylene or Benzene. Of course there are certain plastics that are the product of recycled goods, but I’ll get into that much more in the video above. The key thing here is that the plastic that we use so heavily is really the same as the petroleum we put in our cars or the natural gas we use to heat our homes. Which is one of the reasons why the fossil fuel industry loves plastics.
U.S. natgas futures slip on less hot forecasts, rising output (Reuters) – U.S. natural gas futures slipped on Monday on forecasts for less hot weather and a reduction in the amount of gas power generators will burn to keep air conditioners humming next week than previously expected. Traders also noted prices were down on rising output and lower liquefied natural gas (LNG) exports despite near-record pipeline deliveries to Mexico. Front-month gas futures fell 2.7 cents, or 0.9%, to settle at $3.070 per million British thermal units (mmBtu). But with gas prices in Europe near their highest since September 2018 and prices in Asia over $10 per mmBtu, U.S. speculators boosted their net long futures and options positions on the New York Mercantile and Intercontinental Exchanges last week for the fourth time in five weeks. Traders expect global buyers will keep buying all the LNG the United States can produce. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 91.8 billion cubic feet per day (bcfd) so far in June, up from 91.0 bcfd in May but still well below the monthly record high of 95.4 bcfd in November 2019. With warmer weather coming, Refinitiv projected average gas demand, including exports, would rise from 88.2 bcfd this week to 88.9 bcfd next week. The forecast for next week was lower than Refinitiv predicted on Friday as a slightly less hot forecast will reduce air conditioning use. The amount of gas flowing to U.S. LNG export plants averaged 10.2 bcfd so far in June, down from 10.8 bcfd in May and the all-time high of 11.5 bcfd in April. Traders noted LNG feedgas was down due to short maintenance work at Gulf Coast export plants and the pipelines that provide them with fuel. U.S. pipeline exports to Mexico, meanwhile, averaged 6.54 bcfd so far in June, which would top the 6.11-bcfd average in May and the all-time high of 6.14 bcfd in April, according to Refinitiv data.
Natural Gas Futures Rally as Euro Model Posts Large CDD Increase — Rising cooling demand expectations in recent weather model runs had natural gas futures rebounding sharply in early trading Tuesday. The July Nymex contract was up 9.2 cents to $3.162/MMBtu at around 8:50 a.m. ET. After settling 2.7 cents lower at $3.070 in Monday’s session, the July contract “quickly rebounded” in after hours trading following a run of the European weather model that showed a large increase in projected cooling degree days (CDD), analysts at EBW Analytics Group said. The CDD increase resulted from projections for weaker cooling in the Midwest and East next week, according to the firm. “Overnight, the European model kept its late-day gains, and the American, while still cooler, posted its own large gain,” the EBW analysts said. “With both models now warmer than during the regular trading session yesterday, the July contract is poised to rise further this morning.” According to NatGasWeather, the American weather model added 7 CDD in its overnight run. However, the model showed a pattern that “still wasn’t quite hot enough June 15-20 due to a barrage of weather systems tracking across the Great Lakes and East,” the firm said. “…It’s this rather comfortable pattern over the Great Lakes and eastern third of the U.S. June 15-20 that makes the pattern not as impressive as needed to be considered solidly bullish. But it’s apparently hot enough to satisfy, with prices at multi-week highs.” Production and liquefied natural gas feed gas demand levels are “the most bearish they’ve been in more than a month,” NatGasWeather said. After this week’s heat it’s “debatable” whether the temperature outlook is “hot enough” given the cooler projections from the American model starting around mid-June.
US working natural gas volumes in underground storage increase by 98 Bcf: EIA | S&P Global Platts -Storage inventories increased 98 Bcf to 2.411 Tcf for the week-ended June 4 the US Energy Information Administration reported June 10. The build was more than the 95 Bcf addition expected by an S&P Global Platts’ survey of analysts, as well as the five-year average build of 92 Bcf, according to EIA data. Storage volumes now stand 383 Bcf, or 13.7%, less than the year-ago level of 2.794 Tcf and 55 Bcf, or 2.2%, less than the five-year average of 2.466 Tcf. The injection matched the 98 Bcf added to inventories for the week prior. Month-to-date total feedgas deliveries have averaged 10.1 Bcf/d, slightly below the June forecast of 10.4 Bcf/d, according to S&P Global Platts Analytics. When available, US LNG export facilities are expected to run at full utilization, about 11 Bcf/d, as netbacks into JKM and TTF remain wide open at $5/MMBtu and $4/MMBtu, respectively, through the end of the year. The NYMEX Henry Hub July contract added 2 cents to $3.147/MMBtu in trading following the release of the weekly storage report on June 10. The balance-of-summer contract strip was trading higher by roughly 3 cents/MMBtu for an average of $3.175/MMBtu, while the winter 2021-22 strip was up 2 cents on the day, trading at $3.323/MMBtu. Platts Analytics’ supply and demand model currently forecasts a 56 Bcf injection for the week ending June 11, which would measure 31 Bcf less than the five-year average as gas-fired power generation draws on supply. Summer appears to be fully underway during the week in progress, with power burn demand rising by more than 7 Bcf/d on the week. The effects of that were dulled by a 2.4 Bcf/d drop in residential and commercial demand, and a 1.7 Bcf/d drop in LNG feedgas demand thought to be linked to annual maintenance taking place at certain liquefaction plants on the Gulf Coast. Amid fairly substantial changes in the various demand sectors, total US demand has seen a net increase of about 2.6 Bcf/d week over week. Supply, on the other hand, has been mostly stagnant, with nearly all of the week’s 900 MMcf/d increase in total US supplies the result of an increase in imports from Canada. Sample storage fields across the Lower 48 injected 20% less gas into storage for the week ending June 11, falling from an injection of 47 to 37 Bcf. Temperatures in the East and Midwest climbed by more than 13 degrees degrees week over week, pushing up local power burn demand and cutting into the volumes available for storage. The tighter injections in major demand regions were partially offset by small gains in the West, which saw a bit of a reprieve from the ongoing heat wave
Temps, Appalachian Supply Worries Keep Heat on Natural Gas Forwards – Big basis moves in Appalachia and on the West Coast highlighted natural gas forwards trading during the June 3-9 period, while a sufficiently hot forecast helped propel a broader move higher for the Lower 48 overall, according to NGI’s Forward Look. Fixed prices for July delivery were higher week/week by around 10-15 cents at numerous locations, with benchmark Henry Hub gaining 8.8 cents to average $3.130/MMBtu. Forecasts teasing June heat, along with the prospect of Appalachian supply disruptions, helped stoke the fire that saw July Nymex futures rise during the period. On Thursday, the front month continued to nudge higher, going on to settle at $3.149, up 2.0 cents day/day. The potential duration of a pressure reduction on the Texas Eastern Transmission Co. (Tetco) system required by the Pipeline and Hazardous Materials Administration (aka PHMSA) remained unclear, EBW Analytics Group analysts told clients in a research note earlier in the week. According to the firm, the Tetco restrictions stood to constrain regional exports out of Appalachia by as much as 1.0 Bcf/d. “If new information suggests it is likely that outages may last for several months, natural gas could quickly move higher,” the EBW analysts said. Energy Aspects in a recent note said rerouting options for Northeast-to-Gulf Coast volumes implied “minimal impact to production” from the Tetco constraints. However, maintaining 0.9-1.0 Bcf/d of capacity between the Tetco M-2 and M-1 zones, compared to 2.1 Bcf/d design capacity, will be “critical to prevent any future production curtailments.” This presents “a real risk of Appalachia production curtailments this month if M-2 to M-1 capacity falls below this critical level,” Energy Aspects said. Meanwhile, Wood Mackenzie observed a “significant” 1.2 Bcf/d decline in Northeast production from Monday (June 7) to Tuesday (June 8) in its daily pipe estimates, attributable to pigging on the Columbia Gas Transmission system and compressor station maintenance on Equitrans Gas Transmission.
Natural Gas Futures Prices Go ‘Bonkers’ as Tetco Restrictions Seen Lasting Through Summer – After a week of only modest changes along the Nymex futures curve, price action on Friday was anything but, as a major natural gas pipeline warned that restrictions it has in place could last through the end of September. The July Nymex gas futures contract started climbing overnight and continued to surge throughout the day, closing the week at $3.296, up 14.7 cents from Thursday’s close. August prices rose 14.5 cents to $3.311. Spot gas action was just as significant. Stout gains across much of the country overshadowed losses in the Northeast amid a return of cool weather. NGI’s Spot Gas National Avg. climbed 16.0 cents to $3.060. Nymex gas prices had maintained the $3.00 handle for more than a week even as summer heat failed thus far to be sustained across the country for more than a few days. However, market observers said prices would struggle to gain much ground without more hot weather, or some other supportive factor like a recovery in liquefied natural gas (LNG) demand. Instead, Texas Eastern Transmission Co. (Tetco) delivered the bullish catalyst. In a posting to its electronic bulletin board shortly before 6 p.m. ET Thursday, Tetco said a 20% pressure reduction that began this month on part of its 30-inch diameter system – required by a Pipeline and Hazardous Material Safety Administration (PHMSA) order – could last until late in the third quarter. The restrictions were put in place after Tetco reported an anomaly that was identified during recent inspections. PHMSA is working to further evaluate the findings of inspections and how they could impact other Line 10 and Line 15 segments along the system. Tetco said it is continuing to meet regularly with PHMSA and is in the process of conducting an engineering analysis to support a return to service. The pipeline said it “understands the importance of returning its system back to full service as soon as possible, and endeavors to provide a more exact timeframe and potential scope of work by the end of the month.” In a Friday note to clients, Bespoke Weather Services said as soon as the Tetco news was issued, things went “bonkers in the natural gas market.” Based on market chatter that some of the gas may be rerouted, Bespoke questioned whether the rally was an “overreaction, especially in light of supply/demand balances not being impressive of late.” The market was shrugging off the looseness, even before the Tetco issues first surfaced, “but it is honestly difficult to have much of an edge here, given that this issue is not clear cut yet,” according to Bespoke. “Weather remains generally hot,” with some risk of cooler weather for a brief period in the next few days. However, the market is “definitely pricing in a lot of bullish news up here,” Bespoke said. “Obviously, if the Tetco issue winds up less significant than what the market currently expects, we will fall.”
New infrastructure connects West Texas natural gas-producing areas to demand markets – (EIA) Recently completed pipeline projects in Texas and Mexico have increased natural gas transportation capacity from the Waha Hub – located near Permian Basin production activities in West Texas – to the U.S. Gulf Coast and Mexico. Since October 2020, two completed projects in Texas and two completed projects in Mexico have increased the Waha Hub’s connectivity to demand markets and, in turn, reduced the price difference between natural gas at the Waha Hub and the Henry Hub.Recently completed projects include:
- Kinder Morgan’s 2.1 billion cubic feet per day (Bcf/d) Permian Highway Pipeline (PHP) entered service in January. It delivers natural gas from the Waha Hub to Katy, Texas, located near the Texas Gulf Coast, and also connects to Mexico.
- Whitewater/MPLX’s Agua Blanca Expansion Project entered service in late January. It connects to nearly 20 natural gas processing sites in the Delaware Basin and can move 1.8 Bcf/d of natural gas to the Waha Hub. By the third quarter of 2021, the project will likely expand to connect with the Whistler Pipeline to move an additional 2.0 Bcf/d of natural gas from the Permian Basin to the Texas Gulf Coast.
- Fermaca’s 0.9 Bcf/d Villa de Reyes-Aguascalientes-Guadalajara pipeline began commercial operations in October 2020. The pipeline, located in Central Mexico, is the final segment of the Wahalajara system, which connects the Waha Hub to Guadalajara and other population centers in west-central Mexico.
- Carso Energy’s 0.5 Bcf/d Samalayuca-Sflsabe pipeline began commercial flows of natural gas in late January. The pipeline provides a more direct route for natural gas from the Permian Basin to northwest Mexico.
The additional takeaway capacity from these recently completed projects has contributed to a nearly 10% increase in U.S. pipeline exports to Mexico since last March. According to the latest Natural Gas Monthly, exports to Mexico totaled 5.9 Bcf/d in March 2021. Additional takeaway capacity has also helped increase the natural gas price at the Waha Hub, narrowing its price difference (also known as the basis) to the Henry Hub. Over the past few years, constrained takeaway capacity in the Permian Basin kept Waha prices consistently at $1 per million British thermal units (MMBtu) or more below the Henry Hub price. The Waha-Henry Hub basis began narrowing in late October 2020. From March through May of this year, the Waha Hub price averaged $0.22/MMBtu less than the Henry Hub price, following a February cold snap in Texas that temporarily sent Waha prices to a record high.
Small Number of Permian Oil and Gas Sites Are Releasing Large Amounts of Methane A relatively tiny number of Permian oil and gas sites are responsible for a wildly disproportionate amount of methane pollution, a new study from Methane Source Finder found.The research, a joint project of NASA, the University of Arizona and Arizona State University, revealed just 123 of the 60,000 sites (0.205%) surveyed in the month-long study accounted for 29% of the region’s methane pollution – largely from leaks that are typically easy to repair.Methane traps 80 times more heat in the atmosphere than CO2 over a 20 year period, and the research echoes an analysis of EPA data released last week that found the 195 smallest U.S. oil and gas extractors were responsible for 22% of total emissions, despite only accounting for 9% of production.The Trump administration weakened methane leak detection and repair requirements in its final months and the Senate, though not the House, has taken action to reinstate the Obama-era protections.
U.S. regulator tells pipeline operators to prepare methane curbs (Reuters) – The U.S. Department of Transportation’s pipeline regulator on Monday sent an advisory to oil and gas pipeline operators directing them to update their inspection and maintenance plans for curbing the release of potent greenhouse gas methane, as part of the Biden administration’s broader effort to combat climate change. The DOT’s Pipeline and Hazardous Materials Safety Administration (PHMSA) submitted the advisory bulletin to prod companies to begin to comply with the PIPES Act, a law signed at the end of 2020, that created dozens of new regulatory mandates for the agency including the oversight of methane leaks by natural gas pipelines and transmission systems. “Minimizing methane emissions from pipelines will help improve safety and combat climate change, while creating jobs for pipeline workers,” said PHMSA Acting Administrator Tristan Brown. “Pipeline operators have an obligation to protect the public and the environment by identifying and addressing methane leaks.” Methane has a much higher heat-trapping potential than carbon dioxide and its concentrations in the atmosphere have been rising rapidly in recent years, alarming world governments seeking to cap global warming under the 2015 Paris Agreement on climate change.Since the requirements enshrined in the PIPES Act are new and will not be enforced until the end of the year, the bulletin takes the first step of delineating what is expected of the operators, a Biden administration official said. The bulletin tells operators that they must have inspection and maintenance plans in place by the Dec. 27 to minimize methane emission releases and repair or replace outdated leaking pipes, and makes clear that the agency will enforce these requirements in January 2022.
El Paso Electric’s Newman 6 project to go before judge – An administrative law judge ruled Thursday that the Sierra Club and a citizen group from Chaparral, N.M., can move forward to challenge the state of Texas’ pending approval of a permit for El Paso Electric’s proposed gas plant. The Chaparral Community Coalition For Helping the Environment includes people who live within two miles of the proposed plant in New Mexico and oppose the expansion of the power plant, citing health concerns for an area that’s already under scrutiny for air pollution. The contested hearing has not been scheduled yet, but is required by state law to occur before a 180-day deadline on Nov. 30. The hearing before the State Office of Administrative Hearings stems from the Texas Commision on Environmental Quality’s decision to approve the application by El Paso Electric to build the natural gas plant in Northeast El Paso. On Thursday, Administrative Law Judge Rebecca Smith ruled that the Chaparral Community Coalition For Helping the Environment and the Sierra Club had standing to continue as parties, while local environmental nonprofit Eco El Paso did not. She allowed all the attorneys for all parties to work on negotiating a schedule for the upcoming hearings.
Oil commission approves rule change forbidding spills –The Oil Conservation Commission approved a rule change Thursday that will forbid drillers from spilling oil and toxic liquids – an amendment that activists and affected residents said would help prevent the pollution from occurring. The rule will be adopted July 8. The state Oil Conservation Division, which regulates oil and gas activity, partnered with the environmental group WildEarth Guardians to propose the rule change. Conservationists, community activists, regulators and industry groups all backed it. New Mexico had no rule barring operators from spilling oil or “produced water,” the toxic liquid byproduct from hydraulic fracturing. Instead, companies were required to report a spill and then work with regulators to clean it up. Critics called the system grossly inadequate – especially in a state with one of the nation’s largest fossil fuel industries – saying it was reactive rather than preventive. “This is a big, big deal,” said Jeremy Nichols, WildEarth Guardian’s climate and energy program director. “We want to make sure there’s an incentive for industry to keep these releases from happening in the first place.” The new rule will give the division more authority to impose penalties on violators. “We hope the Oil Conservation Division will use this new authority to benefit the citizens and environment of New Mexico,” said Joe Zupan, executive director of Amigos Bravos, a Taos-based water advocacy group. But during a public hearing Wednesday, some people called for adding language that explicitly gives the agency enforcement power and specifies fines and other punishments for spills. Some expressed concern the rule says the agency may take enforcement action rather than it shall. “Prohibiting something without enforcing that rule is meaningless,” said Gail Evans, an attorney at the New Mexico Environmental Law Center. But Nichols said how the agency will penalize polluters is a question for another day.
Oil Patch Lifts US Rig Count Once Again as Natural Gas Activity Eases Lower More rigs flocked to the oil patch during the week ended Friday (June 11), offsetting a small decrease in natural gas-directed drilling to lift the combined U.S. count five units to 461, according to the latest data published by Baker Hughes Co. (BKR). Oil-directed drilling increased by six units in the United States for the week, while the total number of domestic natural gas rigs decreased by one. The combined 461 U.S. rigs active as of Friday compares with 279 rigs running in the year-ago period, according to the BKR numbers, which are based partly on data from Enverus. Land drilling increased by five rigs domestically for the week, while the Gulf of Mexico remained unchanged with 13 rigs. Horizontal drilling increased by five units for the week; vertical units increased by one, while directional rigs declined by one overall. The Canadian rig count increased by 16 rigs week/week – all oil-directed – to reach 93 as of Friday. That’s up sharply from 21 active rigs at this time last year. Broken down by play, the Permian Basin saw the largest net increase for the week, adding four rigs to raise its total to 236, up from 137 in the year-ago period. Elsewhere, the Haynesville Shale added one rig. The Utica Shale saw two rigs exit. Broken down by state, Texas and Wyoming each added three rigs, while New Mexico picked up two rigs during the period. One rig was added in West Virginia. Meanwhile, two rigs departed Ohio for the week, while Alaska and Pennsylvania each saw one rig exit overall, according to the BKR numbers.
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