Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 13 March 2021. Part 2 is available here.
This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.
Please share this article – Go to very top of page, right hand side, for social media buttons.
Record jump in oil refining; distillate exports at 11 year low; Saudi cut and Texas freeze leave oil supply short of demand
Refinery throughput was 5th lowest in 32 years even after a record increase in refinery throughput; distillate exports at 11 year low, domestic distillate demand at a 16 month high; OPEC report shows February oil supplies fell short of demand after the Saudi’s cut and the Texas freeze-off.
Oil prices corrected slightly this week after running up more than 80% over the prior eighteen weeks….after jumping 7.5% to a 22 month high at $66.09 a barrel last week after OPEC and other producers committed to holding their oil output steady through the end of April, the contract price of US light sweet crude for April delivery opened higher on Monday, after Saudi Arabia said its oil facilities had been targeted by missiles and drones on Sunday, and a Houthi military spokesman claimed responsibility for the attacks, with the international benchmark trading as high at $71.38 per barrel, before turning lower after the Saudis said their largest oil export terminal at Ras Tanura was unscathed and tumbling to close down $1.04 at $65.05 a barrel, with a stronger dollar serving to further cool prices….oil prices continued sliding in a choppy session on Tuesday, as fears of a supply disruption in Saudi Arabia receded, countering a pause in the dollar’s rally and prospects for tighter supply due to OPEC+ output curbs. and ended down another $1.04 at $64.01 a barrel as analysts suggested that such a price correction was perhaps inevitable…oil prices continued falling in aftermarket trading Tuesday and opened lower on Wednesday after the API reported a huge oil inventory increase, but reversed to settle 43 cents higher at $64.44 per barrel after the Organisation for Economic Cooperation and Development (OECD) projected the global economy was set to rebound with 5.6% growth this year and expand by 4% more next year…oil prices rose again on Thursday as vaccine rollouts bolstered the economic outlook and U.S. fuel supplies fell sharply and finished $1.58 higher at $66.02 a barrel, as the US dollar fell for a third straight day to its lowest level in a week against a basket of other currencies…April oil traded in a narrow range on Friday, supported by production cuts by major oil producers and optimism about a demand recovery in the second half of the year and settled 41 cents lower at $65.61 a barrel, thus contributing to a 0.7% loss on the week, with oil prices held in check by the presence of substantial global oil inventory that would cushion any short-term imbalances…
Natural gas prices also finished lower this week as weather continued to moderate with the end of the heating season approaching….after falling 2.5% to a 5 week low of $2.701 mmBTU last week on the report that natural gas inventories fell much less than had been expected, the contract price of natural gas for April delivery opened lower on Monday and slid to a 3.7 cent loss at $2.664 per mmBTU amid mild weather, demand uncertainty and steady gas production… prices barely budged all day Tuesday, closing two-tenths of a cent lower at $2.664 per mmBTU, as generally mild March temperatures continued to offer little support for prices…despite continued mild weather and light heating demand, natural gas prices moved 3 cents higher on Wednesday, but gave most of that up in falling back 2.4 cents to $2.668 per mmBTU on Thursday as the EIA’s inventory report disappointed for a second straight week, and forecasts called for easing weather demand...gas traders finally appeared to capitulate on Friday as spring weather appeared to have arrived a few weeks early and natural gas prices fell 6.8 cents to $2.600 per mmBTU, thus ending down 3.7% for the week…
The natural gas storage report from the EIA for the week ending March 5th indicated that the amount of natural gas held in underground storage in the US fell by 52 billion cubic feet to 1,793 billion cubic feet by the end of the week, which left our gas supplies 257 billion cubic feet, or 12.5% below the 2,050 billion cubic feet that were in storage on March 5th of last year, and 141 billion cubic feet, or 7.3% below the five-year average of 1,934 billion cubic feet of natural gas that have been in storage as of the 5th of March in recent years….the 52 billion cubic feet that were drawn out of US natural gas storage this week was less than the average forecast of a 65 billion cubic foot withdrawal from an S&P Global Platts survey of analysts, and was also less than 72 billion cubic foot withdrawal from natural gas storage seen during the corresponding week of a year earlier, and less than the average withdrawal of 89 billion cubic feet of natural gas that have been pulled out of 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 March 5th showed that despite a big rebound in our oil refining, we again had a large surplus of oil on record left to add to our stored commercial crude supplies, which increased for the fifth time in the past sixteen weeks and for the 14th time in the past thirty-eight weeks….our imports of crude oil fell by an average of 636,000 barrels per day to an average of 5,655,000 barrels per day, after jumping by an average of 1,692,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 282,000 barrels per day to 2,633,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,022,000 barrels of per day during the week ending March 5th, 918,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells increased by 900,000 barrels per day to 10,900,000 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 13,922,000 barrels per day during this reporting week…
US oil refineries reported they were processing 12,310,000 barrels of crude per day during the week ending March 5th, a record 2,407,000 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 1,971,000 barrels of oil per day were being added to the supplies of oil stored in the US….so looking at that data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports and from oilfield production was 359,000 barrels per day less than what what was added to storage plus 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 (+359,000) 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 an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…. moreover, since last week’s fudge factor was at (-957,000) barrels per day, there was a 1,316,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, which means the week over week supply and demand changes we have just transcribed are nonsense…however, since most everyone treats these weekly EIA figures 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 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 fell to an average of 5,611,000 barrels per day last week, which was 11.7% less than the 6,354,000 barrel per day average that we were importing over the same four-week period last year…..the 1,971,000 barrel per day addition to our total crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported to be 900,000 barrels per day higher at 19,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 900,000 barrels per day higher at 10,400,000 barrels per day, while a 6,000 barrel per day decrease to 459,000 barrels per day in Alaska’s oil production had no impact on the rounded national total….last year’s US crude oil production for the week ending March 6th was rounded to 13,000,000 barrels per day, so this reporting week’s rounded oil production figure was 17.2% below that of a year ago, yet still 29.3% 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…
Meanwhile, US oil refineries were operating at 69.0% of their capacity while using those 12,310,000 barrels of crude per day during the week ending March 5th, up from the record low 56.0% of capacity during the prior week, but still one of the lowest refinery utilization rates of the last 30 years…hence, the 12,310,000 barrels per day of oil that were refined this week were also among the lowest in thirty years, 21.6% fewer barrels than the 15,701,000 barrels of crude that were being processed daily during the week ending March 6th of last year, when US refineries were operating at a seasonal low 86.4% of capacity…
With the jump in the amount of oil being refined, the gasoline output from our refineries was higher for the 7th time in 17 weeks, increasing by 704,000 barrels per day to 9,005,000 barrels per day during the week ending March 5th, after our gasoline output had increased by 565,000 barrels per day over the prior week…but even with that two week rebound in gasoline production, this week’s gasoline output was still 9.6% lower than the 9,956,000 barrels of gasoline that were being produced daily over the same week of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 806,000 barrels per day to 3,704,000 barrels per day, after our distillates output had decreased by 723,000 barrels per day to an twenty-six year low of 2,898,000 barrels per day over the prior week…with our distillates’ production thus depressed, this week’s output was still 21.3% less than the 4,705,000 barrels of distillates that were being produced daily during the week ending March 6th, 2020…
Even with the increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the fifth time in seventeen weeks, and for 18th time in 34 weeks, falling by 11,869,000 barrels to 231,603,000 barrels during the week ending March 5th, after our gasoline inventories had decreased by a record 13,624,000 barrels over the prior week...our gasoline supplies decreased again this week despite the production jump because the amount of gasoline supplied to US users increased by 578,000 barrels per day to 8,726,000 barrels per day, and because our imports of gasoline fell by 28,000 barrels per day to 577,000 barrels per day, and because our exports of gasoline rose by 184,000 barrels per day to 677,000 barrels per day…after this week’s big inventory decrease, our gasoline supplies were 6.2% lower than last March 6th’s gasoline inventories of 246,999,000 barrels, and about 6% below the five year average of our gasoline supplies for this time of the year…
With only a partial recovery in our distillates production, our supplies of distillate fuels decreased for the 20th time in 28 weeks and for the 29th time in the past year, falling by a 5,504,000 barrels to 137,492,000 barrels during the week ending March 5th, after our distillates supplies had decreased by a near record 9,719,000 barrels during the prior week….our distillates supplies fell again this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, jumped by 699,000 barrels per day to a 16 month high of 4,487,000 barrels per day, while our exports of distillates fell by 345,000 barrels per day to an eleven year low of 475,000 barrels per day, and while our imports of distillates rose by 151,000 barrels per day to 472,000 barrels per day…but even after this week’s big inventory decrease, our distillate supplies at the end of the week were still 7.4% above the 128,060,000 barrels of distillates that we had in storage on March 6th, 2020, even as they fell to about 4% below the five year average of distillates stocks for this time of the year…
Finally, even with the recovery in our refinery throughput, our commercial supplies of crude oil in storage (not including the commercial oil being stored in the SPR) ended the week higher for the 11th time in the past thirty-three weeks, and for the 29th time in the past year, increasing by 13,798,000 barrels, from 484,605,000 barrels on February 26th to 498,403,000 barrels on March 5th, after our commercial oil inventories had increased by a record 21,563,000 the prior week…after that two week record increase, our commercial crude oil inventories rose to 6% above the five-year average of crude oil supplies for this time of year, and to about 44% above the prior 5 year (2011 – 2015) average of our crude oil stocks as of the first week of March, 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 spring lockdowns of last year after generally rising over the prior two years, except for during the 10 weeks prior to the Texas freeze and except for during the past two summers, after generally falling over the year and a half prior to September of 2018, our commercial crude oil supplies as of March 5th were 10.3% more than the 451,783,000 barrels of oil we had in commercial storage on March 6th of 2020, 11.0% more than the 449,072,000 barrels of oil that we had in storage on March 8th of 2019, and also 15.7% more than the 430,928,000 barrels of oil we had in commercial storage on March 9th of 2018…
OPEC’s Monthly Oil Market Report
Thursday of this past week saw the release of OPEC’s March Oil Market Report, which covers OPEC & global oil data for February, and hence it gives us a picture of the global oil supply & demand situation for the 2nd month after OPEC, the Russians, and other oil producers agreed to increase their oil production by 500,000 barrels per day starting January, from their prior commitment to cut production by 7.7 million barrels a day from an October 2018 peak, which had been earlier reduced from the 9.7 million barrels a day cuts they had imposed on themselves during May, June and July, and after the Saudis unilaterally decided to cut their own production by a million barrels per day during February and March….once again, before we look at what this month’s report shows us, we want to caution that estimating oil demand while the course of the Covid-19 pandemic remains uncertain is pretty speculative, and hence the demand estimates we’ll be reporting this month should again 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 49 of this month’s report (pdf page 59), 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 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 decreased by 647,000 barrels per day to 24.848,000 barrels per day during February, down from their revised but unchanged January production total of 25,496,000 barrels per day…from that table we can also see that a 930,000 barrels per day decrease in the Saudi’s production was the major factor in OPEC’s output decrease, and that most of the OPEC members increased their output in February, led by the Nigerian’s 161,000 barrel per day production increase, not surprising since several OPEC members had failed to take advantage of the new agreement to increase production in January…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, 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’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…however, note that war torn Libya and US sanctioned OPEC members Iran and Venezuela have been exempt from the production cuts imposed by these agreements, and as we can see above, they all posted production increases this month…
Since there had never seemed to be a published table or listing available of how much each OPEC member was expected to produce under the eased production cuts of August through December, or the new ones starting January 2021, we had been including the table that shows the original October 2018 reference production for each of the OPEC members (as well as other producers party to the mid-April agreement), as well as the production level each of those producers was expected to cut their output to during May, June, and July…we’ll include that table once again now, though with two modifications to that agreement since, it becomes more difficult to compute the production quotas that each of the OPEC members was expected to hold to in February:
The first column in the above table shows the 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 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 second column shows how much each participant had originally committed to cut during May and June 2020 in thousands of barrel per day, which was 23% of the October 2018 baseline for all participants except for Mexico, who had their production hedged to profit from lower prices, while the last column shows the production level each participant had agreed to after that cut…the producer’s agreement for August through December of last year amended the figures shown above such that each member would be allowed to reduce their production cut shown above (ie, the “voluntary adjustment” shown above) by 20%…for example, Algeria’s “cut” was expected to be 241,000 barrels per day from May thru July, which would reduce their oil production to 816,000 barrels per day over that period…under the agreement for August through December of last year, Algeria would reduce their “cut” by 20%, or to 193,000 barrels per day, thus allowing them to produce 864,000 barrels per day during those months…with the agreement for January and February, which was recently extended, Algeria would be able to reduce their production cut by another 5% from the “voluntary adjustment” figure shown above, or to 181,000 barrels per day, thus allowing them to produce 876,000 barrels per day during February….offhand, by comparing the above table’s voluntary allocation less 25% from the initial OPEC production cut, it appears that Iraq, Gabon and Kuwait all exceeded their revised allocation during February, but that with the Saudi’s additional cuts, the group as a whole still remained below the quota they would have been allowed to produce for the month…
The next graphic from this month’s report that we’ll highlight shows us both OPEC and world oil production monthly on the same graph, over the period from March 2019 to February 2021, and it comes from page 50 (pdf page 60) of OPEC’s March 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….
After the reported 647,000 barrel per day decrease in OPEC’s production from what they produced a month earlier, OPEC’s preliminary estimate indicates that total global liquids production decreased by a rounded 1,310,000 barrels per day to average 92.28 million barrels per day in February, a reported decrease which apparently came after January’s total global output figure was revised up by 470,000 barrels per day from the 93.12 million barrels per day of global oil output that was reported a month ago, as non-OPEC oil production fell by a rounded 670,000 barrels per day in February after that revision, with a freeze-related oil production decrease of 600,000 barrels per day in the US alone accounting for most of the non-OPEC production decrease in February…
After that decrease in February’s global output, the 92.28 million barrels of oil per day that were produced globally in February were 7.62 million barrels per day, or 7.6% less than the revised 99.90 million barrels of oil per day that were being produced globally in February a year ago, which was the second month of additional production cuts of 500,000 barrels per day in an attempt to support prices (see the March 2020 OPEC report (online pdf) for the originally reported February 2020 details)…with this month’s increase in OPEC’s output, their February oil production of 24,848,000 barrels per day was at 26.9% of what was produced globally during the month, a decrease of 0.3% from their revised 27.2% share of the global total in January….OPEC’s February 2020 production was reported at 27,772,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year produced 2,924,000, or 10.5% fewer barrels per day of oil in February 2021 than what they produced a year earlier, when they accounted for 27.8% of global output…
After the decreases in both OPEC’s and global oil output that we’ve seen in this report, the amount of oil being produced globally during the month 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 March 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 second column, we’ve circled in blue the figure that’s relevant for February, which is their estimate of global oil demand during the first quarter of 2020… OPEC is estimating that during the 1st quarter of this year, all oil consuming regions of the globe will be using an average of 93.04 million barrels of oil per day, which is a 180,000 barrels per day downward revision from the 93.22 million barrels of oil per day of demand they were estimating for the first quarter a month ago (note that we have encircled this month’s revisions in green), still reflecting 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 producing 92.28 million barrels million barrels per day during February, which would imply that there was a shortage of around 760,000 barrels per day in global oil production in February when compared to the demand estimated for the month..
In addition to figuring February‘s global oil supply shortfall that’s evident in this report, the upward revision of 470,000 barrels per day to January’s global oil output that’s implied in this report, partly offset by the 180,000 barrels per day downward revision to first quarter demand noted above, means that the 100,000 barrels per day global oil output shortage we had previously figured for January would now be revised to a surplus of 190,000 barrels per day...
Note that in green we’ve also circled an upward revision of 120,000 barrels per day to 2020’s demand, which also means that the supply shortfalls or surpluses that we previously reported for last year’s months would need to be revised….a separate table on page 26 of the March Oil Market Report (pdf page 36) indicates the revisions to 2020 demand included an an upward revision of 240,000 barrels per day to 4th quarter demand, an upward revision of 20,000 barrels per day to 3rd quarter demand, and an upward revision of 250,000 barrels per day to 2nd quarter demand…
A month ago we estimated a revised global shortfall of around 940,000 barrels per day in global oil production during December, a global shortfall of around 1,540,000 barrels per day during November, and a global shortfall of around 2,840,000 barrels per day during October, based on the figures that were published at that time…hence, the upward revision of 240,000 barrels per day to 4th quarter demand would revise those estimated oil shortfalls to 1,180,000 barrels per day for December, 1,780,000 barrels per day for November, and 3,080,000 barrels per day for October…then, in like manner, the global oil supply shortfalls we had previously estimated for the each of the third quarter months would have to be revised higher by 20,000 barrels per day, while the large global oil surpluses we had previously estimated for the second quarter months would have to be revised lower by 250,000 barrels per day….however, despite the upward revision to 2020’s demand and OPEC’s deep production cuts beginning in May, the quanities of oil produced globally in 2020 still averaged well over 3 million barrels per day more than anyone wanted…
This Week’s Rig Count
The US rig count fell for just the 2nd time over the past 26 weeks during the week ending March 12th, but it still remains down by 49.2% from what it was a year ago….Baker Hughes reported that the total count of rotary rigs running in the US was down by 1 to 402 rigs this past week, which was still down by 390 rigs from the 792 rigs that were in use as of the March 13th report of 2020, and was also still two fewer rigs than the all time low rig count prior to 2020, and 1,527 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in their first attempt to put US shale out of business….
The number of rigs drilling for oil decreased by 1 rig to 309 oil rigs this week, after rising by 1 oil rig the prior week, leaving us with 374 fewer oil rigs than were running a year ago, and less than a fifth 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 unchanged at 92 natural gas rigs, which was still down by 15 natural gas rigs from the 107 natural gas rigs that were drilling a year ago, and just 5.7% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil or gas, one rig classified as ‘miscellaneous’ continued to drill in Lake County, California this week, while a year ago there were two such “miscellaneous” rigs deployed…
The Gulf of Mexico rig count decreased by 1 to 13 rigs this week, with 11 of those rigs now drilling for oil in Louisiana’s offshore waters and 2 drilling for oil in Alaminos Canyon offshore from Texas…that was 6 fewer Gulf of Mexico rigs than the 19 rigs drilling in the Gulf a year ago, when 17 Gulf rigs were drilling for oil offshore from Louisiana, one rig was drilling for natural gas in the West Delta field offshore from Louisiana, and one rig was drilling for oil offshore from Texas…since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig counts…..
The count of active horizontal drilling rigs was unchanged at 362 horizontal rigs this week, which was still down by 351 rigs from the 713 horizontal rigs that were in use in the US on March 13th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the directional rig count was down by 1 rigs to 15 directional rigs this week, and those were also down by 33 from the 48 directional rigs that were operating during the same week a year ago….meanwhile, the vertical rig count was unchanged at 25 vertical rigs this week, and those were also down by 6 from the 31 vertical rigs that were in use on March 6th 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 March 12th, the second column shows the change in the number of working rigs between last week’s count (March 5th) and this week’s (March 12th) count, the third column shows last week’s March 5th 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 13th of March, 2020..
Obviously, there was a bit more activity this week than the decrease of one rig nationally would account for….checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that there were 2 new rigs added in Texas Oil District 7C, which includes the southern counties of the Permian Midland basin, and another rig added in in Texas Oil District 8, which corresponds to the core Permian Delaware, while one rig was pulled out of Texas Oil District 8A, which includes the northern counties of the Permian Midland basin, which together means there was a net increase of 2 rigs in the Texas Permian….since the national Permian rig count was only up by 1, that means that the rig that was removed in New Mexico must have been pulled out of the farthest west reaches of the Permian Delaware, to balance the national Permian total….elsewhere in Texas, there was a rig pulled out of Texas Oil District 1 while there was a rig added in Texas Oil District 2, which could have been offsetting changes in the Eagle Ford shale that would net to no change and hence not show up in the table above…there was also a rig pulled out of Texas Oil District 6, which had been drilling for natural gas in the western part of the Haynesville shale….outside of Texas, there were two oil rigs added in Oklahoma’s Cana Woodford, while an oil rig was pulled out of North Dakota’s Williston basin at the same time…for rigs targetting natural gas, we had two rigs added in Ohio’s Utica shale, and another rig added in West Virginia’s Marcellus, which were in turn offset by the removal of two natural gas rigs from Pennsylvania’s Marcellus and the natural gas rig removed from the Texas Haynesville shale which we mentioned previously…
Court Blocks Oil, Gas Extraction on Ohio’s Only National Forest – Center for Biological Diversity ― A federal judge blocked new oil and gas leasing and fracking in Ohio’s Wayne National Forest late Monday, following a ruling last year rebuking the Bureau of Land Management and U.S. Forest Service for failing to consider threats to public health, endangered species and watersheds before opening more than 40,000 acres of the forest to fracking. Pending completion of new environmental reviews, Monday’s order blocks new leases on the Wayne, prohibits new drilling permits and surface disturbance on existing leases, and prohibits water withdrawals from the Little Muskingum River for already-approved drilling. “This is great news for the future of Ohio’s only national forest,” said Taylor McKinnon, a senior campaigner at the Center for Biological Diversity. “We’re grateful the judge recognized the damage fracking could do to this spectacular forest. The order will protect our climate, endangered wildlife and drinking water for millions of people.” U.S. District Judge Michael Watson said the Forest Service and Bureau of Land Management had “demonstrated a disregard for the different types of impacts caused by fracking in the Forest. The agencies made decisions premised on a faulty foundation.” “The Wayne is a public forest that we all own. Keeping its air and water clean, as well as its views intact, is a win that we can all celebrate.” In May 2017 conservation groups sued the agencies over plans to permit fracking in the Wayne, saying federal officials had relied on an outdated plan and ignored significant environmental threats before approving the fracking.”This victory, like the Wayne National Forest, belongs to all of us,” said Becca Pollard with the Sierra Club. “Permitting fracking anywhere is a threat to our health and clean air and water, and we’re relieved to see the judge rule in favor of protecting the forest. We look forward to working together to ensure that this decision is made permanent and we may continue to enjoy and explore Wayne National Forest.”
Court stalls fracking leases in Ohio’s only national forest — Ironton Tribune ― Late on Monday, a federal judge stalled oil and gas leasing in Ohio’s Wayne National Forest, ruling that the Trump administration failed to consider threats to public health, endangered species and watersheds before opening more than 40,000 acres of the forest for fracking.U.S. District Judge Michael Watson said the U.S. Forest Service and U.S. Bureau of Land Management “demonstrated a disregard for the different types of impacts caused by fracking in the Forest. The agencies made decisions premised on a faulty foundation.”Watson’s ruling requires the agencies to redo their environmental analysis of the potential harms from fracking in the Wayne.”Fracking is a dirty, dangerous business,” said Wendy Park, an attorney at the Center for Biological Diversity. “This ruling helps ensure the health of this spectacular forest and its endangered animals and protects the water source for millions of people.”In May 2017 conservation groups sued the Forest Service and the BLM over plans to permit fracking in the Wayne, saying federal officials had relied on an outdated plan and ignored significant environmental threats before approving fracking in the forest. The lawsuit also aimed to void two BLM lease sales. The court will decide later whether to void those existing leases, but a planned March sale will likely be postponed. In today’s ruling the judge said the agencies ignored potential harm from fracking to endangered Indiana bats, the waters of the Little Muskingum River and the region’s air quality.
Federal Judge Deals Another Setback to Oil, Natural Gas Development in Ohio National Forest – -A federal judge has halted oil and gas development in Ohio’s Wayne National Forest (WNF) after a ruling last year found the Bureau of Land Management (BLM) and the U.S. Forest Service (USFS) failed to adequately consider the impact of unconventional development when they opened the land for drilling. The U.S. District Court for the Southern District of Ohio ordered the agencies to further review their authorizations under the National Environmental Policy Act (NEPA). Pending review, this week’s order blocks new leases in the WNF, prohibits new drilling permits and surface disturbance on existing leases, and prohibits water withdrawals from the Little Muskingum River.Judge Michael Watson said the USFS and BLM “demonstrated a disregard for the different types of impacts” caused by unconventional development in the forest. He added that “the agencies made decisions premised on a faulty foundation.” The court found last year that federal regulators specifically failed to consider surface area disturbance, impacts on the Indiana Bat, the Little Muskingum River and regional air quality related to horizontal wells completed with hydraulic fracturing.The decision was another flash point in a long-running battle over whether exploration and production companies should be allowed to operate in the WNF, the state’s only national forest. Last year’s decision threw the future of WNF leasing into doubt when the case proceeded to determine if lease sales should be voided.Four environmental groups, led by the Center for Biological Diversity, filed a lawsuit against BLM and USFS in 2017 to void oil and gas leases and stop unconventional development in the forest.The BLM in 2015 proposed to lease parcels across 40,000 acres in the forest’s Marietta Unit in Monroe, Noble and Washington counties that were nominated by the industry for unconventional development. The Eastern States Office began auctioning parcels shortly thereafter, and more than 2,000 acres in the forest have since been leased for Utica Shale development.The court acknowledged this week, however, that the federal agencies did not completely abandon their duties under NEPA and indicated that remanding the environmental review would likely remedy the case.
Shell targeting 2022 for start of Pennsylvania PE resin unit – Royal Dutch Shell plc is citing 2022 as the likely start date of its massive petrochemicals plant under construction near Pittsburgh.
Pennsylvania agrees to settle gas drilling royalties lawsuit – Pennsylvania reached a settlement in a lawsuit against natural gas driller Chesapeake Energy Corp. for its handling of royalty payments to property owners, state Attorney General Josh Shapiro announced Monday. Speaking in Tunkhannock, a northeastern Pennsylvania town in the heart of heavy Marcellus Shale natural gas production, Shapiro said the agreement called for $5.3 million in restitution and improved royalty payments going forward. “It is the beginning of a new day and new protections for landowners,” said Shapiro, a Democrat, touting terms that include appointment of a mutually agreeable ombudsman to investigate landowners’ complaints. The lawsuit was filed more than five years ago against Oklahoma City-based Chesapeake, which filed for bankruptcy protection in Texas in June. Chesapeake communications and investor relations director Gordon Pennoyer noted the agreement still requires the bankruptcy judge’s approval. “Chesapeake greatly values its relationships with Pennsylvania royalty owners and is pleased to have reached a global resolution with them and the attorney general that addresses royalty owners’ concerns,” Pennoyer said in an email. “The company looks forward to working collaboratively with Pennsylvania royalty owners going forward..” The lawsuit, filed in December 2015 and amended in 2016 to include Anadarko Petroleum, claimed the two companies split up markets, keeping landowners from getting better deals by seeking competitive offers. An appeal in the litigation involving Anadarko about whether the state’s consumer protection law applies is pending before the Pennsylvania Supreme Court.
A Pennsylvania county went from bust to boom times with natural gas. Now, it’s nearly broke. – Greene County is going broke. Despite receiving millions in payouts from the natural gas industry to compensate such counties as Greene that host natural gas wells, it is struggling to balance its more than $40 million budget. This year, amid a pandemic, commissioners raised property taxes for the first time since 2010. Without major changes, county budget office projections show that Greene may not have the revenue or reserves to cover its costs by 2023. It’s a financial predicament that seemed all but guaranteed as the coal mining industry here has nearly disappeared, hollowing out the backbone of the local economy. That was, until the natural gas boom – and a massive influx of money that came with it – offered a different path.The windfall seemed to buy Greene County, which is in the southwest corner of the state, time to figure out how it would survive without coal. But nearly 10 years and more than 1,000 natural gas wells later, the county appears to be no better off financially than where it started, having spent through $37.2 million in impact fees without setting aside money to plan for the day the work would inevitably slow. “I quickly came to realize there was no fiscal planning,” said Mike Belding, one of two new county commissioners on the three-seat governing body. “They were just spending money as it came in.” Greene, home to 36,000 residents, is one of 31 counties statewide receiving “impact fee” payouts through a state program initiated in 2012, called Act 13. The funds are distributed yearly, and payouts are based on such factors as the number of wells in an area and population. Only three other counties – Bradford, Susquehanna, and Washington – have received more money than Greene from the impact fees over the lifetime of the program, according to reports filed with the Pennsylvania Public Utility Commission. But unlike others that set the money aside and saved it for future investments, budget reports show Greene has used about $17.5 million to balance its budget since 2015. The other half went to projects that the newest commissioners say were shortsighted and wasteful, such as commissioning a $400,000 comprehensive plan that was never used and a $550,000 business loan program that yielded no returns for the county.
Biden DOJ Backs PennEast Gas Pipeline in Supreme Court Fight — The Biden administration is throwing its legal weight behind the PennEast pipeline in a high-stakes Supreme Court case that could affect natural gas projects across the U.S.The Justice Department urged the high court to overturn a ruling that blocked PennEast from using federal eminent domain authority to take New Jersey land along the $1 billion project’s route. The filing comes as environmental advocates press the Biden administration to shut down or thwart development of other oil and natural gas pipelines.”The right of eminent domain was well-known at the Founding. As the Court has long recognized, the Constitution conferred that authority on the federal government, including the authority to take State-owned land, for projects within the government’s enumerated powers,” Acting Solicitor General Elizabeth B. Prelogar wrote in the brief.She added that the authority extends to private parties building projects deemed to be in the public interest, and said the lower court handling the case lacked jurisdiction over the appeal in the first place.The Monday brief comes as a disappointment to some environmental advocates who hoped the Biden administration would withdraw support for the PennEast pipeline. The Federal Energy Regulatory Commission and the Justice Department first backed the company’s legal arguments during the Trump administration.Ron Morano, executive director of Affordable Energy for New Jersey, said he hopes “this will be indicative of this administration’s future positions on our energy independence.”Environmentalists were dismayed by the Biden administration’s move. Maya K. van Rossum, head of the Delaware Riverkeeper Network, said the Justice Department’s decision to support PennEast in the case “is an abuse of power and trust and a failure of the current administration to do its duty to protect people and our environment.” Backed by Enbridge Inc., Southern Co., and other companies, PennEast would stretch 116 miles across Pennsylvania and New Jersey, as part of a broader buildout of East Coast gas infrastructure. Construction hasn’t started.
NJ Doesn’t Need Gas Infrastructure Projects Like NESE – –Fossil fuel industry groups that continue to push natural gas as a clean-energy solution do the public a profound disservice. Strictly speaking, natural gas is cleaner than coal, but they are both dirty fossil fuels and coal today accounts for barely 2% of New Jersey’s energy. The relevant comparison is between gas and wind or solar. And, here, there is no comparison. Methane, the main component of natural gas, is not “clean.” It’s a potent greenhouse gas, and rising natural gas production is one of the biggest drivers of climate change. The state’s Energy Master Plan recognizes this and calls for transitioning to 100% clean energy by 2050. New Jersey is no outlier in its aggressive climate and clean-energy policies. When New York State denied permits for the controversial Northeast Supply Enhancement (NESE) pipeline project earlier this year, it said, “the continued long-term use of fossil fuels is inconsistent with … the actions necessary to prevent the most severe impacts from climate change … ” NESE would have carried fracked gas from Pennsylvania through sensitive environmental areas of New Jersey and across Raritan Bay into New York. Nevertheless, in paid sponsored content that appeared in this publication, a group calling itself “Affordable Energy for New Jersey” bemoaned the NESE decision and made several false claims calculated to drum up public support for new natural gas infrastructure projects in New Jersey. Let’s set the record straight. It’s absurd for AENJ to suggest that NESE would have provided “affordable energy for New Jersey.” NESE was designed to supply natural gas to customers in New York. New Jersey already has abundant pipeline capacity to meet in-state demand on even the coldest days. AENJ claimed that, without NESE, the only long-term option is a “virtual pipeline” of trucks carrying compressed natural gas (CNG) from Pennsylvania to New York, and that an average of 75 CNG trucks made that trip every day since May 20, 2020. That is false. There was zero CNG trucking during the summer of 2020, and none last winter except for a test using six trucks. National Grid, the utility company that wanted NESE, has no plans to use CNG trucking other than on extremely rare days when the average temperature falls below 10 degrees and brief annual tests of fewer than six trucks. AENJ’s assertion is like claiming that trucks are plowing the streets every night of the year because we might get a huge blizzard this winter.
Foes of South Jersey LNG plan say new frack ban might help their cause – NJ Spotlight News –A historic decision to ban fracking for natural gas in the Delaware River Basin is raising new questions about plans for a South Jersey dock where fracked gas would be exported in liquid form. On Feb. 25, Gov. Phil Murphy and the governors of Pennsylvania, New York and Delaware voted at the Delaware River Basin Commission to formally block the controversial process of harvesting natural gas, on the grounds that it would endanger water supplies for some 15 million people in the basin. Murphy’s vote on that ban is prompting opponents of the dock to ask whether they now have a better chance of stopping the project that he has so far supported. Critics argue that building the dock at Gibbstown in Gloucester County would be at odds with the new policy made explicit in that vote because it would stimulate the production of fracked gas that could contaminate drinking water and add to greenhouse gas emissions even though the gas would be coming from northeastern Pennsylvania outside the Delaware River Basin. And the fracked gas would be transported in a round-the-clock procession of trucks or trains in a region that has finally rejected the technique of harvesting natural gas, which has been blamed for tainting water with toxic drilling chemicals, and industrializing many rural areas where gas wells are built. If successful, the port project would provide new global market access for the abundant gas reserves of Pennsylvania’s Marcellus Shale, one of the richest gas fields in the world, whose development since the mid-2000s has been hindered by low prices and a shortage of pipelines. The Pennsylvania gas would be sold in liquid form to overseas markets, especially in Asia, where prices are much higher than in the U.S. The price of U.S. liquefied natural gas exports was near a five-year high in December but was still at less than half its level during the years 2009-2014, according to the U.S. Energy Information Administration.
The Delaware River Basin Commission Bans Fracking – The Delaware River Basin, a 13,539-square-mile watershed that cuts through Delaware, New Jersey, New York, and Pennsylvania is now off-limits to fracking. In late February, the five-member Delaware River Basin Commission-the interstate government agency that oversees the basin-voted 4-0 to permanently ban the extraction of methane gas in the region. The decision comes a decade after the commission authorized a de facto moratorium on well construction and follows other fracking bans across the East Coast, marking a historic win for anti-fracking activists. The state commissioners-the governors of each state-all voted in favor of the ban. The federal commissioner abstained.After reviewing various studies and research reports on the potential impacts of fracking on the basin, the commission determined that fracking carries too high of a risk of contaminating drinking water. Fracking fluids are likely to leak into the groundwater, it found, and the Marcellus and Utica shale formations that sit below the river basin contain faults and fissures that may provide additional pathways for methane to migrate upward once the drilling occurs.”This ban will protect billions of gallons of drinking water and thousands of acres of forest from fracking wells,” said Jeff Tittel, director of the Sierra Club’s New Jersey Chapter. “It also means that there won’t be pipelines built to take that gas to the market, protecting even more land and water.”The decision to ban fracking permanently in the Delaware Basin has been more than 10 years in the making. The commission began its discussions on regulating the gas industry in response to Pennsylvania’s shale gas boom in 2008 and proposed regulations to halt drilling as early as 2010. The proposal was controversial, resulting in tense public hearings, and the vote was put on hold after former Delaware governor Jack Markell announced that he would vote no. During the stalemate, landowners in Wayne County sued the commission, arguing that it lacked the authority to ban drilling. The lawsuit was dismissed, and in 2017 the commission updated draft regulations that authorized a permanent ban on fracking in the basin. The fracking ban, however, did not prohibit external natural gas companies from dumping their fracking wastewater into the basin, nor from taking water from the basin for fracking.
High Volume Fracking Banned In Delaware River Basin Due To Health Risks – — A commission that oversees the safety and purity of water in the Delaware River basin has banned high volume hydraulic fracturing activities along the river, citing growing concerns over pollution and health risks from “fracking” operations that extract oil and gas.On February 25, the Delaware River Basin Commission, based in New Jersey, announced the approval of a final rule prohibiting high volume hydraulic fracturing (HVHF), according to a press release issued late last month. The prohibition has been added to the commission’s Comprehensive Plan and Water Code.Hydraulic fracturing, more commonly known as “fracking” involves drilling and fracturing shale rock to release oil and gas. The operations involve the injection of water, sand and chemicals into wells at high pressures to crack the surrounding rock, thus releasing the natural gas underground and allowing it to flow to the head of the well.Problems from fracking have previously been linked to negative environmental effects to the surrounding communities, due the impact on drinking water, as well as increased dust and exhaust from drilling rigs, compressors and the transportation of the water, sand and chemicals. The process has also been linked to increased earthquake activity, and the extent of potential harm to humans living close to these operations has remained an open question.The prohibition, Resolution No. 2021-01, gives several reasons for putting the high volume fracking ban in place. It predicts that the practice could lead to spills and releases of fracking chemicals, fluids and wastewater, which would adversely impact surface and ground water. This may eventually impair drinking water sources, and pose widespread health concerns. In addition, the Resolution warns the fluids released by fracking contain pollutants such as salts, metals, radioactive materials, organic compounds, endocrine disruptors and toxic chemicals whose toxicity has yet to be determined.”High-volume hydraulic fracturing and related activities pose significant, immediate and long-term risks to the development, conservation, utilization, management, and preservation of the water resources of the Delaware River Basin and to the Special Protection Waters of the Basin, considered by the Commission to have exceptionally high scenic, recreational, ecological, and/or water supply values,” the Resolution states. “Controlling future pollution by prohibiting high volume hydraulic fracturing in the Basin is required to effectuate the Commission’s Comprehensive Plan, avoid injury to the waters of the Basin as contemplated by the Comprehensive Plan and protect the public health and preserve the waters of the Basin for uses in accordance with the Comprehensive Plan.” In testimony filed with the commission on February 25, the National Resource Defense Council (NRDC), an environmental protection group, called for a ban on all fracking procedures in the Basin, noting that the river provided drinking water to 17 million people. The NRDC testimony (PDF) says the new rules do not go far enough.
House energy committee OKs bill changing how oil and gas wells would be valued for property taxes -The state House Energy and Manufacturing Committee approved referring a bill to the House Finance Committee Tuesday that would change how the State Tax Department values producing oil and gas wells for property tax purposes and the appeals process for all property taxes in the state. This would provide a more expansive definition of operating expenses for gas and oil producers in another industry-friendly move by the committee.House Bill 2581‘s provisions include allowing expenses from lifting, processing, transportation and other industry activities to be subtracted from wells’ income and require the tax department to resurvey well expenses every three years unless natural gas contracts or the average oil price traded on the New York Mercantile Exchange changes more than 20% from the last year a survey was completed, meaning state administrative costs would increase in unstable markets.The bill would expand the jurisdiction of the Office of Tax Appeals to include property tax valuation, classification and taxability, allow petitioners to appeal to a county Board of Equalization and Review or the Office of Tax Appeals and eliminate the Board of Assessment Appeals. “It’s a fairly complicated statute, but right now you’ve got two chances at the county level, so you’re making the same argument to the same body a few months apart wanting a different result, and if you don’t get the result under the current system, you go to the circuit court,” committee counsel Robert Akers said. “So the new system will take you through the Office of Tax Appeals on the way to circuit court.”State Tax Department attorney Steve Stockton said the bill adds another layer to the tax appeal process but doesn’t necessarily make it more complicated.”So more government?” Delegate Kayla Young, D-Kanawha, asked Stockton.”You could look at it that way, yes,” Stockton replied.A fiscal note from the Office of Tax Appeals accompanying the bill estimates it would significantly increase the caseload at the office and envisions the hiring of two more administrative law judges to add to the current two, two staff attorneys and four additional support staff, an increase in staff that the office’s current leased space would not support. The fiscal note, which did not factor in estimated cost of leasing larger office space, estimates the other additional expenses would cost an annual $425,000 to $475,000.
Energy analysis nonprofit says changing gas markets have diminished need for Mountain Valley Pipeline —A study published Monday by an energy analysis nonprofit suggests that changes in natural gas markets since the Mountain Valley Pipeline was conceived have undercut the economic case for the long-delayed pipeline project.First announced in 2014, the 42-inch-diameter, 303-mile Mountain Valley Pipeline is slated to provide up to 2 billion cubic feet per day of natural gas from the Marcellus and Utica shale formations to markets in the Mid-Atlantic and Southeastern regions of the United States, traveling from Northwestern West Virginia to Southern Virginia.But legal and regulatory challenges have set back the pipeline, which originally was scheduled for completion by the end of 2018 but is now slated for service by the end of 2021. Its price tag has ballooned to at least $5.8 billion, over 50% more than its original cost estimate.Monday’s analysis by the Institute for Energy Economics and Financial Analysis, a nonprofit that supports transitioning to sustainable energy, concludes that lower gas demand and risks to liquefied natural gas exports have lessened the need for the Mountain Valley Pipeline.In addition to citing the project’s cost overruns and unknown cost effects of the project sponsors’ recent decision to start a new individual water permit application process, the IEEFA report notes that natural gas demand in the Southeast and Mid-Atlantic is projected to be much lower than projections anticipated when pipeline developers sought approval from federal regulators for the project in 2015.”Pipeline capacity out of the Appalachian Basin exceeds production. Growth in Appalachian natural gas production is increasingly dependent on a growing export market for Appalachian gas, a prospect that faces significant risks. Thus, Mountain Valley Pipeline faces a significant risk that its capacity will be underutilized,” the report argues. The report also posits that the potential cancellation of the Southgate extension of the pipeline, which would span 75 miles from Southern Virginia into Central North Carolina, weakens the case for the pipeline.The IEEFA report criticizes the Federal Energy Regulatory Commission’s process for evaluating pipeline need, arguing that it does not consider a rapidly changing domestic natural gas market or risks associated with growing liquefied natural gas exports on the domestic gas market.
Report questions business case for Mountain Valley Pipeline – A study released Monday by an analysis firm calls into question the business case for the Mountain Valley Pipeline, which will bring local Marcellus and Utica shale natural gas to markets in the southeast. MVP, which is being built and will be operated by Canonsburg-based Equitrans Midstream Corp. (NYSE: ETRN), is closer than it ever has been to completion since the project was announced in 2014. Most but not all of the legal challenges have been settled and Equitrans told analysts in a conference call last month that it expects to have all the permits in hand within the next six months and MVP in service by the end of the year. The pipeline’s cost has nearly doubled over the years from $3.7 billion to $6 billion. The Institute for Energy Economics and Financial Analysis, which is dedicated to a sustainable energy future, wrote in a report Monday that the pipeline was conceived in a very different gas market and that there’s too much pipeline capacity for the natural gas demand that there is now. “Significant pipeline capacity has been added to take gas out of the Appalachian Basin, even as the outlook for domestic natural gas demand and exports has grown more uncertain,” IEEFA wrote. The report said that natural gas consumption in the Southeast is likely to drop through 2030 and there will be fewer natural gas powered electricity plants built than forecast in 2014. And a potential lift from liquified natural gas production, which would be sent overseas, hasn’t yet materialized, IEEFA said. MVP and Equitrans blasted the report, saying that IEEFA’s conclusions were incorrect “and are in alignment with the group’s specific policy agenda.” “MVP’s 2 Bcf/d (billion cubic feet/day) capacity has been and remains fully subscribed and MVP Southgate has a firm commitment from PSNC/Dominion Energy for 300 MMcf/day, (million cubic feet/day),” spokeswoman Natalie Cox said. “Furthermore, MVP retains strong support from shippers whose need has grown since cancellation of the Atlantic Coast Pipeline last summer. The need for an abundant, reliable energy supply is real, and the unnecessary project delays are affecting consumers.” The report said if the extension of MVP called Southgate isn’t approved in North Carolina, then it would likely take out more demand for natural gas.
Pittsylvania NAACP asks DEQ to refer MVP air permit to Air Pollution Control Board – The Pittsylvania County Branch of the NAACP, the National Association for the Advancement of Colored People, passed a resolution March 2 opposing immediate approval of an air permit requested by the Mountain Valley Pipeline (MVP) for its proposed Lambert Compressor Station, currently sited approximately two and a half miles east of Chatham. The group also approved a written comment to DEQ on the draft air permit.The resolution and comment request that Virginia’s Department of Environmental Quality refer the draft air permit to the citizen Air Pollution Control Board. The referral would allow time for further consideration of air quality issues and concerns regarding environmental justice. According to the group’s written comment to DEQ, “Despite MVP and DEQ having acknowledged that the Lambert Compressor Station has the potential to affect communities of color, MVP’s environmental justice consultant did not contact us, the local Pittsylvania Branch NAACP, at all, and neither MVP nor DEQ contacted us until December 2020. We strongly hold that affected and vulnerable community residents of Pittsylvania County have not had access and opportunities to participate in the full cycle of the decision-making process about the MVP Southgate project, including the Lambert Compressor Station.”
Equitrans wins round in circuit court over North Carolina pipeline – An extension of the Mountain Valley Pipeline into North Carolina planned by Equitrans Midstream Corp. won a round in federal court as judges ordered North Carolina regulators to better explain why they denied a key water permit for the project. The Fourth Circuit Court of Appeals vacated the rejection of water quality certification by the North Carolina Department of Environmental Quality, which is a win for the Southgate pipeline that would bring natural gas from the Marcellus and Utica shale through the Mountain Valley Pipeline and then into North Carolina 75-miles via Southgate Pipeline. Neither MVP nor Southgate are yet completed, as they have been stuck in the permitting process and various challenges. MVP could be in-service by the end of the year but Southgate still needs permits to even begin the work. The court sent the issue back for more explanation as to the reasons why it was denied. The agency would be able to reject it again but with more details, according to parties involved. Mountain Valley Pipeline and Equitrans are based in Canonsburg. MVP Southgate spokesman Shawn Day hailed the decision. “MVP Southgate’s design has minimized impacts to surface waters and wetlands to the greatest extent practicable, and the project would comply with all state water quality standards,” Day said. “We look forward to working with the NDEQ to satisfy any concerns that it may have, and we remain committed to building this important infrastructure project to meet North Carolinians’ demand for cleaner and more reliable, affordable natural gas.” A statement from the North Carolina Department of Environmental Quality said the Fourth Circuit ruling had vindicated its concerns. “The ruling upholds the state’s authority to determine that building the Southgate extension at this time poses unnecessary risk to North Carolina’s streams, lakes and wetlands,” the agency said in a statement to WFAE-FM. The agency didn’t immediately respond to a request from the Pittsburgh Business Times. One of the case litigants, Appalachian Voices, which opposes the pipeline, said the ruling was a “false victory” for MVP. “The court specifically noted that North Carolina regulators’ denial of the permit aligned with federal and state water quality standards, they just didn’t explain it well,” said Amy Adams, North Carolina program manager at Appalachian Voices. “We do expect the agency to correct this quickly enough, and in the meantime, the half-finished MVP mainline remains an over-budget boondoggle mired in legal setbacks.”
Denial of Mountain Valley Pipeline permit reversed by federal appeals court –An extension of the Mountain Valley Pipeline, threatened by the denial of a key permit from North Carolina, gained new life Thursday. The 4th U.S. Circuit Court of Appeals threw out a decision by the state’s Department of Environmental Quality, ruling that it did not properly explain the reasons why it had denied a water quality certification for a portion of the natural gas pipeline Called MVP Southgate, the extension would start at the main pipeline’s terminus in Pittsylvania County and run for 75 miles into North Carolina. In sending the case back to North Carolina regulators, the 4th Circuit ordered them to address two things: inconsistent statements from a hearing officer who at one point found that the project had lessened its impact on water bodies “to the greatest extent possible,” and why it chose to deny the certification outright rather than give it conditional approval. “On appeal, we hold that the Department’s denial is consistent with the state’s regulations and the Clean Water Act,” Chief Judge Roger Gregory wrote in a decision from a three-judge panel. “Nevertheless, the Department did not adequately explain its decision in light of the administrative record.” The denial was based, in large part, on uncertainty over whether the main portion of the pipeline – a 303-stretch in West Virginia and Southwest Virginia that is currently under construction – would ever be completed.
Biden Can Protect Communities, Halt Mountain Valley Pipeline | NRDC –We have new leadership in Washington under President Biden, and his administration should take action to send the Mountain Valley Pipeline right where it belongs-into the dustbin of history.I recently blogged about 5 key reasons to stop the Mountain Valley Pipeline (MVP), which would transport dirty fracked gas across Appalachia. Unfortunately, despite the science, the imperative to stop global warming, and legal obligations to protect clean water, national forest land, and endangered species habitat, the prior administration-no friend of the environment-kept issuing illegal permits to move this dirty and destructive project forward.But there is still time to change the outcome. In January, President Biden issued an executive order aimed at tackling the climate crisis, protecting public health and the environment, and restoring science in federal decisions. Executive Order 13990 directs federal agencies to review the former administration’s decisions that conflict with the principles of environmental protection, reducing climate change, and using the best available science. The EO also directs agencies to take action to address these inconsistencies where appropriate.What does that mean for MVP? It means that the Biden Administration can reverse anti-environmental actions taken under Trump that greased the skids for the fracked gas MVP. The new administration has already rescinded approval for copper mining at an Apache sacred site in Arizona and cattle grazing on public lands permitted in Oregon without full public input. MVP decisions that Biden should reverse:
- The December 2020 U.S. Forest Service Final Supplemental Environmental Impact Statement and Record of Decision to amend the Jefferson National Forest Land and Resource Management Plan;
- The January 2021 Bureau of Land Management right-of-way and temporary use permit; and,
- The September 2020 U.S. Fish and Wildlife Service Biological Opinion and Incidental Take Statement.
MVP has already harmed landscapes and clean water: West Virginia and Virginia have assessed MVP more than $2 million in penalties for more than 350 environmental violations. And there is more high-risk construction planned: MVP still has to cross hundreds of water bodies along the pipeline route. The Biden Administration can stop future risks to water quality by ensuring that the Assistant Secretary of the Army for Civil Works review the pipeline’s new application for a Clean Water Act permit with stringent consideration of whether it can comply with water quality standards.
NTSB opens public docket for Danville, Kentucky pipeline rupture investigation – The National Transportation Safety Board (NTSB) opened the public docket on Thursday as part of its ongoing investigation of the fatal, 1 August 2019 natural gas transmission pipeline rupture and fire near Danville, Kentucky. NTSB opens public docket for Danville, Kentucky pipeline rupture investigation The docket for this investigation includes more than 3600 pages of factual information, including reports on pipeline operations, integrity management, metallurgical testing, and emergency response efforts. The docket also includes interview transcripts, photographs, employee training records, and other investigative materials. The docket contains only factual information collected by NTSB investigators; it does not provide the final report, nor does it contain analysis, findings, recommendations, or probable cause determinations. As such, no conclusions about how or why the rupture occurred should be drawn from the information within the docket. Analysis, findings, recommendations, and probable cause determinations related to the rupture will be issued by the NTSB in a final report at a later date. A 30 in. pipeline owned and operated by Enbridge Inc., ruptured and released natural gas that ignited. One person was fatally injured in the accident that destroyed five residences, damaged 14 other residences, and burned about 30 acres of land, including railroad tracks. The public docket for this investigation is available online here.
Absent Demand Drivers, April Natural Gas Futures Falter Fourth Consecutive Day; Cash Prices Fall – Natural gas futures on Monday tumbled for a fourth straight day amid mild weather, demand uncertainty and steady production. The April Nymex contract settled at $2.664/MMBtu, down 3.7 cents day/day. May fell 4.1 cents to $2.698. Weak near-term weather demand also weighed on cash prices. NGI’s Spot Gas National Avg. shed 25.5 cents to $2.500. Bespoke Weather Services said that its mid-range forecast on Monday had shifted a tad cooler from a previous outlook on Friday, with the potential for colder air next week. But the current week looks to be exceptionally warm and, overall, conditions are expected to prove mild over the balance of March, minimizing heating demand. “We still have plenty of warmth this week … including a couple of days near daily record levels in terms of national” gas-weighted degree days, Bespoke said. “This skews the 15-day period as a whole warmer than normal, despite the cooler look next week.” Production, which had recovered from the freeze-offs caused by the Arctic blast that derailed Texas’ energy system in February, held steady on Monday near 90 Bcf. Against that backdrop, traders fretted about supply/demand uncertainty created by the weather outlook and punctuated by last week’s bearish Energy Information Administration (EIA) inventory report, Bespoke said.
US gas storage draw measures well below normal for second straight week | S&P Global Platts –US natural gas storage volumes declined less than the market expected for the second consecutive week, weighing again on prices as only three net draws likely remain before injection season begins. Stay up to date with the latest commodity content. Sign up for our free daily Commodities Bulletin. Sign Up Storage inventories decreased by 52 Bcf to 1.793 Tcf for the week ended March 5, the US Energy Information Administration reported the morning of March 11. The withdrawal was weaker than the 65 Bcf draw expected by an S&P Global Platts survey of analysts. It was also less than the 72 Bcf draw reported during the same week last year and the five-year average withdrawal of 89 Bcf. The draw was well below the 98 Bcf pull reported for the week prior as production rebounded 5.5 Bcf/d week over week, according to S&P Global Platts Analytics. Higher US production and softening demand pushed back on other sources of supply, with Canadian imports falling 1.5 Bcf/d. US demand came down sharply on the week alongside a warm-up in temperatures. Total demand dropped more than 6 Bcf/d week over week, with residential and commercial losses accounting for almost all the decline. After last week’s massive storage miss, uncertainty was high heading into the March 11 EIA report. Survey responses ranged from a draw of 42 to 86 Bcf. This uncertainty led to gas prices trading in a relatively tight range over the course of the week, with the April NYMEX shifting between $2.60/MMBtu and $2.70/MMBtu. The Henry Hub April contract slipped 3 cents to $2.65/MMBtu in trading following the release of the weekly storage report. Outside of the uncertainty created by last week’s EIA report, benign weather forecasts and sizeable wind generation also kept a lid on pricing. Storage volumes now stand 257 Bcf, or 12.5%, less than the year-ago level of 2.050 Tcf and 141 Bcf, or 7.3%, less than the five-year average of 1.934 Tcf. Platts Analytics’ supply and demand model currently forecasts a 22 Bcf withdrawal for the week ending March 12, which would measure 37 Bcf weaker than the five-year average, as the withdrawal season enters its final month.
April Natural Gas Futures Flounder Following Bearish Storage Report – Natural Gas Intelligence – Natural gas futures on Thursday lost ground for the sixth time in seven sessions after the latest federal inventory report disappointed for a second straight week and forecasts called for easing weather demand. The April Nymex contract settled at $2.668/MMBtu, down 2.4 cents day/day. May shed 2.5 cents to $2.703. NGI’s Spot Gas National Avg. clawed out a modest gain for the second straight day, rising 1.0 cent to $2.495. [Brighter Days Ahead: Listen in as Price & Markets Editor Leticia Gonzales looks forward at the North American natural gas market as it recovers from the historic freeze that crippled Texas on NGI’s Hub & Flow podcast.] The U.S. Energy Information Administration (EIA) on Thursday reported a withdrawal of 52 Bcf from natural gas storage for the week ended March 5. The result was notably shy of expectations set by analysts ahead of the report. A Bloomberg survey showed respondents predicting a median 78 Bcf withdrawal, while a Reuters poll landed at a median decline in stocks of 76 Bcf. NGI’s model predicted a 104 Bcf pull. A year earlier, EIA recorded a 72 Bcf withdrawal for the period, and the five-year average is a pull of 89 Bcf. “It was warmer than normal over much of the U.S.” during the covered week, hindering heating demand, NatGasWeather said. Still, the firm noted that colder temperatures in the Northeast and parts of the West, coupled with stronger liquefied natural gas (LNG) exports, were expected to fuel enough demand to muster a storage pull in the 70s Bcf. The latest report follows a “stunning” miss a week earlier, the firm noted. Utilities pulled 98 Bcf from storage in the week ended Feb. 26, well off market expectations for a withdrawal in the 130s-140s Bcf. “This week’s bearish miss confirmed weaker demand that carried over from last week’s report instead of prospects for a correction to it,” NatGasWeather added. “This suggests next week’s draw will be near 20-25 Bcf, if not lower and closer to 10 Bcf.” While production and LNG feed gas “have recovered to pre-Arctic blast levels, demand hasn’t.”
Natural Gas Forward Prices Slip as Market Eyeing Near-Term Bottom – Natural gas prices trimmed about a nickel or so from the forward curve as spring appears to have sprung a couple of weeks early. The April contract was down 6 cents on average for the March 4-10 period, while the summer strip (April-October) was down 4.0 cents, according to NGI’s Forward Look. Similar losses were seen further out the curve as the storage picture has improved a bit in recent weeks. An increase in oil prices also is seen as potentially driving some modest increases in associated gas production later this year. The winter 2021-2022 strip fell an average 5.0 cents for the trading period ending Wednesday, while summer 2022 slipped a penny on average, Forward Look data showed. Only New England points registered any notable deviation from other U.S. markets, and even then, losses were not extraordinary. Algonquin Citygates April prices fell 12.0 cents from May 4-10 to reach $2.858, according to Forward Look. The summer strip was down only 2.0 cents to $2.460 as was the winter 2021-2022 strip, which averaged $5.840. Similar declines were seen at Tennessee Zone 6 200L. Technicals continue to point in a bearish direction for benchmark Henry Hub prices, and by extension other U.S. markets, according to EBW Analytics Group. Closing below $2.68/MMBtu early in the period took out key support for the April contract. Friday’s trading was expected to “test further whether futures are forming a near-term bottom.” Some changes in the background state support that theory. EBW analysts noted that weather forecasts had cooled a bit for the coming few days, but then they warm again by the end of the week. Production also has recovered from some maintenance-induced disruptions over the past week, while LNG demand remained strong, according to EBW. Bespoke Weather Services said the weather models were pointing to a possible weak trough swinging into the eastern United States toward days 14-15, though it’s not expected to be a “significant player” in the overall pattern. Any cooling was expected to be short-lived, with the bias of the pattern staying to the warmer side into early April. Power burns also remained weak, even adjusted for weather, according to Bespoke. The firm said the market’s reluctance to send prices even lower indicated there was an expectation that data would improve soon. “It better, given how weak recent supply/demand balances have been, but we simply do not see this showing up yet.”
Judges press FERC on its level of scrutiny into demand for Spire gas pipeline project – – The US Federal Energy Regulatory Commission faced stiff questioning from appeals court justices over whether it too readily accepted a pipeline company’s assurances about the need for a natural gas pipeline project backed only by an affiliate. A decision in the case could have implications for the level of scrutiny the commission must use to assess the market need for future gas projects. At issue is the 65-mile Spire STL project, approved by FERC in August 2018 and entered into service in November 2019, moving 400,000 Dt/d of gas from the Rockies Express Pipeline system into the St. Louis Area. The project faced objections from the Environmental Defense Fund, which argued FERC should have looked beyond the project’s contract for 88% of capacity with affiliate Spire Missouri to assess the need. Enable Mississippi River Transmission (MRT) and the Missouri Public Service Commission also raised objections during the FERC review that the project was unneeded and would negatively impact St. Louis gas market competition. Of note, then-Commissioner Richard Glick, who now chairs the commission, dissented on FERC’s November 21, 2019, rehearing order (CP17-040), contending neither Spire STL not Spire Missouri had explained why capacity on the preexisting pipeline owned by MRT was not sufficient to meet Spire Missouri’s needs. He said the order turned the needs demonstration requirement into “a meaningless check-the-box exercise.” During oral argument March 8, all three judges on a panel of the DC Circuit Court of Appeals pressed FERC on whether under the circumstances of the Spire case there wasn’t a greater burden on the regulator to examine whether there was self-dealing between the pipeline company and its affiliate (Environmental Defense Fund v. FERC, 20-1016). “What more do you need than constructing a pipeline for an affiliate where it’s not serving new market and [is] providing no price benefit to customers? That just leaves the obvious red flag that it’s for the benefit of the shareholders, not the customer,” Judge David Tatel said. “What else do you need that would be more dramatic than this?” And Judge Harry Edwards continued to press the point. “Judge Tatel is asking you very pointedly in this situation where there are no new needs and no cost savings, is it enough for us to accept your argument that in this situation [Spire] offered what they claimed were business reasons and, ‘we had no reason to go behind it’. That’s strange argument,” he said. Defending the decisions, FERC attorney Anand Viswanathan said the commission on rehearing pointed to rationales offered by Spire as being sufficient to overcome concerns raised about overbuilding. Those included enhancing reliability and supply security, reducing reliance on older pipelines and mature basins, and eliminating reliance on propane peak-shaving infrastructure. “Based on that record, FERC found no reason to second-guess the business judgments of the pipeline, Viswanathan said. “Based on that record, I don’t think it’s fair to say that the commission relied exclusively on the affiliate agreements here.” But the judges appeared skeptical of FERC’s decision to accept the business judgments. If FERC commissioners are “saying nothing more than there’s no reason to second-guess what has been offered, that’s really not an agency doing its own independent analysis of the factors that would justify this proposal,
USA Sells 10+ Million Barrels of SPR Oil – The U.S. Department of Energy’s (DOE) Office of Fossil Energy has announced that contracts have been awarded from a recent Congressionally directed Strategic Petroleum Reserve (SPR) crude oil sale. The DOE said it had awarded contracts to seven entities, comprising Glencore Ltd., Marathon Petroleum Supply and Trading LLC, Motiva Enterprises LLC, Phillips 66 Company, Shell Trading (US) Company, Valero Marketing and Supply Company, and the Government of Australia. The awarded contracts represent a total sale of 10.1 million barrels of crude oil, the DOE noted, adding that, of this amount, 4.1 million barrels will be sold from the Bryan Mound site, 3.3 million barrels from the West Hackberry site, and 2.7 million barrels from the Big Hill site. The SPR will schedule deliveries to take place in April and May this year, with early deliveries available in March 2021, the DOE revealed. A total of ten companies responded to the notice of sale, which was issued on February 11, submitting 60 bids for evaluation. The Congressionally directed sale fulfills requirements of Section 403(a)(4) of the Bipartisan Budget Act of 2015 and the Consolidated Appropriations Act of 2018, the DOE outlined. Proceeds of the sale will be deposited in the U.S. Treasury by the end of Fiscal Year 2021. The SPR is the world’s largest supply of emergency crude oil and was established primarily to reduce the impact of disruptions in supplies of petroleum products and to carry out obligations of the United States under the international energy program, according to the DOE’s website. The federally owned oil stocks are stored in underground salt caverns at four sites – Bryan Mound, Big Hill, West Hackberry, and Bayou Choctaw – along the coastline of the Gulf of Mexico. The SPR is said to have an authorized storage capacity of 714 million barrels.
Gulf of Mexico- HWCG, Helix extend fast oil spill — Helix Energy Solutions Group has entered into a new agreement for offshore oil spill response resources with HWCG, a consortium of deepwater oil and gas companies in the Gulf of Mexico who have come together with the shared goal of quickly responding to offshore oil spills. Under the agreement, HWCG’s members are given the opportunity to identify the Helix Fast Response System as a response resource in permit applications to U.S. federal and state agencies, and to deploy the Helix Fast Response System to respond to a well control incident in the U.S. Gulf of Mexico. Developed in 2011, based on Helix’s experience as a responder in the 2010 Macondo well control and containment efforts – the Deepwater Horizon disaster – the Helix Fast Response System consists of the Helix Producer I floating production unit, Q4000 or Q5000 vessels, subsea intervention systems, crude transfer systems, and other well control equipment. Under the terms of the agreement, HWCG will pay Helix an annual retention fee. HWCG’s members will receive a credit against the annual retention fee for every day that a member utilizes the Q4000 or Q5000. The agreement replaces the parties’ prior agreement and is effective April 1, 2021, for an initial two-year term.
Coastal authority backs proposal to boost Louisiana’s share of offshore oil, gas revenue –A planned U.S. Senate bill to increase the amount of federal offshore oil revenue shared with Louisiana and other Gulf Coast states, and to set up a similar revenue sharing program for wind energy generated in federal waters, got a vote of support from the Louisiana Coastal Protection and Restoration Authority. The proposed Reinvesting in America’s Shoreline Economies and Ecosystems Act would fulfill promises that Sens. Bill Cassidy, R-La., and Sheldon Whitehouse, D-R.I., made last summer to expand revenue sharing for coastal states under the Gulf of Mexico Energy Security Act when it became clear that such an expansion would not be included in the wildly popular Great American Outdoors Act. The senators have not yet introduced the revenue sharing bill. The outdoors act diverts a greater share of outer continental shelf energy revenue – mostly from Gulf of Mexico oil and gas production – to guarantee $900 million a year for improvements to national and local parks and wildlife refuges. It also provides $11.9 billion over five years to chip away at an enormous backlog of deferred maintenance on public lands. While the details of the planned revenue sharing bill won’t be known until it is introduced the letter that the coastal authority agreed Wednesday to send to Cassidy and Whitehouse says it would change the 2006 Gulf of Mexico Energy Security Act to increase revenue shared with Gulf Coast states. The states now receive 37 percent of the revenue that is paid to the federal government for some wells drilled or developed in federal Gulf waters since 2017, and a much smaller share for wells developed between 2007 and 2016. The Louisiana Constitution requires that money be used for coastal levees or restoration projects.
Tribes worry Line 5 tunnel construction could bring sex trafficking, violence to Native communities — When oil and gas companies employ hundreds of out-of-town, typically male workers to work on pipeline projects, an uptick in that area’s rates of sexual violence and sex trafficking usually follows. That’s becoming a concern for Michigan’s Indigenous people, who cite Canadian oil company Enbridge’s impending Line 5 pipeline tunnel project in the Mackinac Straits as a reason to worry for their already-vulnerable tribal communities nearby. The correlation between extractive industry construction like pipeline projects and sex trafficking is well-documented. Temporary housing communities for the labor force building the pipelines, often called “man camps,” result in a temporary population boom in often-rural areas. These create a strain on the area’s social infrastructure and can stretch police services thin if crimes occur. There’s also a lot of documentation of Native women and children experiencing disproportionately high rates of violence, kidnappings and murder. According to research from the National Instutute for Justice, Native American women face a murder rate 10 times higher than the national average. About 84% experience some form of violence in their lifetimes. In Michigan, about 25.5% of all murders of Native Americans go unreported to the FBI. There is no state or national database of missing and murdered Indigenous women.The combination of these realities results in hotbeds of violence for Indigenous populations when an oil construction project comes to town – like one will in the Straits of Mackinac once Enbridge begins work on its Line 5 replacement pipeline. And members of nearby tribes are raising concerns.”I can see that happening to us, no doubt. I think it’s already happening here in northern Michigan,” said Stacey Ettawageshik, a member of the Little Traverse Bay Bands of Odawa Indians (LTBB) and lead advocate for the tribe’s Survivor Outreach Services.”As far as sex trafficking goes, as Indigenous people we are way more at risk than the general population. And although we don’t make up a lot of the population here … there are definitely high rates of violence, sexual violence, especially against Native women,” Ettawageshik said.
Canadian minister: Straits of Mackinac oil pipeline ‘nonnegotiable’ – Canada isn’t taking “no” for an answer when it comes to the Line 5 oil and gas pipeline. Gov. Gretchen Whitmer in November announced plans to revoke the 1953 easementallowing the controversial, 68-year-old twin pipelines to operate on the Straits of Mackinac lake bottom. Canadian oil transport giant Enbridge, which owns and operates Line 5, then announced its intention to defy Whitmer’s order to cease operation by May.On Thursday, Canada’s natural resources minister told a committee of the House of Commons he believes Line 5 will remain operating over Whitmer’s order.”We are fighting for Line 5 on every front and we are confident in that fight,” Seamus O’Regan told a special House of Commons committee on Canadian-U.S. relations, as quoted by the Canadian Press.”We are fighting on the diplomatic front, and we are preparing to invoke whatever measures we need to in order to make sure that Line 5 remains operational. The operation of Line 5 is nonnegotiable.”O’Regan called Line 5 “very different” from the Keystone XL pipeline in the U.S. Plains states that President Joe Biden shut down on his first day in office. But he didn’t elaborate on the differences.O’Regan said he discussed both Line 5 and Keystone XL with new U.S. Energy Secretary – and former Michigan governor – Jennifer Granholm during their initial conversation last week.Line 5 moves 23 million gallons – about 540,000 barrels – of oil and natural gas liquids per day east through the Upper Peninsula, splitting into twin underwater pipelines through the Straits, before returning to a single transmission pipeline through the Lower Peninsula that runs south to Sarnia, Ontario.The pipeline, and particularly its more than 4-mile underwater section in the Straits, have for years been a source of contention.Enbridge was responsible for one of the largest inland oil spills in U.S. history – a major leak on one of its large oil transmission lines near Marshall in July 2010. That spill fouled more than 38 miles of the Kalamazoo River and took four years and more than $1 billion to clean up. Enbridge in 2016 agreed to a $177-million settlement with the U.S. Justice Department and Environmental Protection Agency, including $62 million in penalties, over the Marshall spill and a 2010 spill on another of its pipelines in Romeoville, Illinois. A similar spill disaster on Line 5 in the Straits would devastate the Great Lakes, shoreline communities and the Michigan economy, critics of the pipeline have long contended. Enbridge officials have countered that Line 5 is safe – despite findings of anchor strikes, missing supports and lost protective coating over recent years.
Some Michigan propane suppliers switching to rail cars in anticipation of Line 5 closure – Propane suppliers reliant on Enbridge’s Line 5 are transitioning to railroad cars to get their products in anticipation of the oil pipeline shutting down in May.Several suppliers in Michigan began exploring alternatives when Gov. Gretchen Whitmer announced the end of an easement that allows the controversial 67-year-old pipeline to run beneath the Straits of Mackinac. From Superior, Wisconsin, Line 5 runs east to the Upper Peninsula then southeast to a Rapid River township refinery, near Escanaba, where natural gas liquids from Line 5 are stripped for propane. On Nov. 13, Whitmer gave Enbridge until May to decommission Line 5 after announcing the easement revocation following a yearlong DNR compliance review. Enbridge says the aging pipeline is safe, but opponents have been arguing for years that the risk posed by an oil spill where Lakes Michigan and Huron connect is too great. Enbridge pushed back on Whitmer’s order, filing a lawsuit and saying it won’t comply with the shutdown absent a court order. Canadian officials have also been vocal against the shutdown, with Seamus O’Regan, Canada’s natural resource minister, telling a special House of Commons committee on Canadian-U.S. relations the country is “fighting for Line 5 on every front and we are confident in that fight.” Some suppliers have already transitioned to railroad cars while others await the result of a legal battle between state attorneys and Enbridge. Still, if the pipeline is shut down, Michigan propane suppliers in the Upper Peninsula will have a few months to figure out an alternate solution to meet their high demands during the fall and winter seasons. Experts and state officials are still identifying alternative energy options if the pipeline is shut down, and Whitmer’s U.P. Energy Task Force is expected to present a report on options at the end of March. Reports from the task force identify trucking and using railroad cars as alternatives to deliver propane, both would require significant infrastructure investment to support demands. Enbridge has plans to build a tunnel to house the pipeline and has received initial approval for permits from the state for the project.
.