Oil, Gas, And Fracking News Reads 16June 2018 – Part 1

Written by rjs, MarketWatch 666

Here are some selected new articles from the week ended 16 June 2018.

This article is a feature every Monday evening on GEI.

Please share this article – Go to very top of page, right hand side, for social media buttons.

US gasoline demand hits an all time high; distillates supplies at a 10 year seasonal low; global oil supplies down in May

Oil prices ended lower for the 4th week in a row as Trump ramped up his trade wars against both our allies and against China, and as it became increasingly evident that OPEC would agree to increase oil production when they meet in Vienna next week…after falling just 7 cents to $65.74 a barrel in volatile trading last week, prices for July delivery of WTI, the benchmark US oil reversed a morning slide and rose 36 cents to $66.10 a barrel on Monday, as comments from the Iraqi oil minister cast doubt as to whether OPEC members would actually boost output at their upcoming meeting…against the backdrop of a Saudi and UAE invasion of Yemen, prices then edged up another 26 cents to close at $66.36 a barrel on Tuesday, after the monthly OPEC report warned there’s a high degree of uncertainty still hanging over the global oil markets this year...oil prices then pushed up to a two week high on Wednesday, closing at $66.36 a barrel for a gain of 28 more cents, after the weekly EIA report indicated a larger than expected drop in US crude supplies along with surprise drawdowns of gasoline and distillates inventories…crude prices then rose for a 4th day on Thursday after Saudi oil minister Al Falih said that while “it’s inevitable” that OPEC would agree to boost oil production, the increase in output would be “reasonable”, with oil closing 25 cents higher at $66.89 a barrel…but oil prices then crashed on Friday morning, falling by as much as $2.60 to $64.29 a barrel, after Saudi Arabia and Russia said they have already boosted their production modestly, and would make it official at their meeting next week, and Trump imposed 25% tariffs on $50 billion worth of high tech Chinese imports and the Chinese responded immediately with their own tariffs on $50 billion of US goods, with oil prices steadying that afternoon to end down $1.83 for the day at $65.06 a barrel…US oil prices thus ended the week with a loss of 68 cents, or just over 1%, while the international benchmark Brent crude trading for August oil finished the week $3.02 or nearly 4% lower at $73.44 a barrel, dropping $2.50 a barrel on Friday alone…

meanwhile, natural gas prices ended the week higher, rising daily save for a tenth of cent pullback on Tuesday, and ending the week above $3 for the first time since January on a 5.7 cent increase to $3.022 on Friday, on a forecast for hot weather for much of the country, seen as an impediment to rebuilding underground inventories…the natural gas storage report for week ending June 8th from the EIAindicated that natural gas in storage in the US rose by 96 billion cubic feet to 1,913 billion cubic feet over the week, which left our gas supplies 785 billion cubic feet, or 29.1% below the 2,698 billion cubic feet that were in storage on June 9th of last year, and 507 billion cubic feet, or 21.0% below the five-year average of 2,420 billion cubic feet of natural gas that are typically in storage after the first week of June…a Bloomberg survey had forecast an addition to gas storage in a range of between 82 and 95 billion cubic feet, so this week’s 96 billion cubic foot addition was above all expectations, and was also above the average 91 billion cubic foot weekly surplus of natural gas that is typically added to storage at this time of year….at today’s inventory levels, we’d have to add 1,877 billion cubic feet of natural gas to storage to match the 3,790 billion cubic feet we had stored after the first week of November last year, so figure we need an inventory build averaging over 89 billion cubic feet per week over the next 21 weeks to bring our gas supplies back up to a reasonable level going into winter….

The Latest US Oil Data from the EIA

this week’s US oil data from the US Energy Information Administration, covering the week ending June 8th, indicated that due to a combination of lower oil imports, higher oil exports, and increased refining, we had to pull oil out of our commercial crude supplies for the ninth time in the past twenty weeks….our imports of crude oil fell by an average of 247,000 barrels per day to an average of 8,099,000 barrels per day during the week, after rising by 715,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 316,000 barrels per day to an average of 2,030,000 barrels per day during the week, which meant that our effective trade in oil over the week ending June 8th worked out to a net import average of 6,069,000 barrels of per day during the week, 563,000 barrels per day less than the net of our imports minus exports during the prior week…at the same time, field production of crude oil from US wells rose by 100,000 barrels per day to a record high of 10,900,000 barrels per day, which means that our daily supply of oil from our net imports and from wells totaled an average of 16,969,000 barrels per day during the reporting week…

meanwhile, US oil refineries were using a seasonal high of 17,505,000 barrels of crude per day during the week ending June 8th, 136,000 barrels per day more than they used during the prior week, while at the same time 592,000 barrels of oil per day were reportedly being pulled out of oil storage in the US….hence, we can see that this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from oilfield production, and from storage was 56,000 more barrels per day than what refineries reported they used during the week…to account for that disparity, the EIA needed to insert a (-56,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the data for the supply of oil and the consumption of it balance out, essentially a fudge factor that is labeled in their footnotes as “unaccounted for crude oil”… (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) show that the 4 week average of our oil imports rose to an average of 8,059,000 barrels per day, which was 1.3% less than the 8,161,000 barrel per day average we imported over the same four-week period last year…the 592,000 barrel per day decrease in our total crude inventories all came out of our commercially available stocks of crude oil, as the amount of oil stored in our Strategic Petroleum Reserve was unchanged…this week’s 100,000 barrel per day increase in our crude oil production was due to a 100,000 barrel per day increase in output from wells in the lower 48 states, while an 18,000 barrel per day decrease in oil output from Alaska was not subtracted from the final figures, with no explanation as to why…the 10,900,000 barrels of crude per day that were produced by US wells during the week ending June 8th were again the highest on record, 16.8% more than the 9,330,000 barrels per day that US wells were producing during the week ending June 9th of last year, and 29.3% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

US oil refineries were operating at 95.7% of their capacity in using 17,505,000 barrels of crude per day during the week ending June 8th, up from 95.4% of capacity the prior week, as refineries will usually try to run flat out through the summer driving season…while the 17,505,000 barrels of oil that were refined this week were the most barrels refined this early in any year, they were still down fractionally from the off-season high of 17,608,000 barrels per day that were being refined during the last week of December 2017….this week’s refinery throughput was also 1.4% higher the 17,256,000 barrels of crude per day that were being processed during the same week a year ago, when US refineries were operating at 94.4% of capacity….

with the increase in the amount of oil that was refined this week, gasoline output from our refinerieswas much higher, rising by 793,000 barrels per day to 10,451,000 barrels per day during the week ending June 8th, after our refineries’ gasoline output had decreased by 775,000 barrels per day during the week ending June 1st....that big increase meant our gasoline production was 6.2% higher during the week than the 9,843,000 barrels of gasoline that were being produced daily during the week ending June 9th of last year…meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 213,000 barrels per day to 5,111,000 barrels per day, after rising to a seasonal high the prior week…as a result, this week’s distillates production was fractionally lower than the 5,154,000 barrels of distillates per day than were being produced during the week ending June 9th, 2017….

however, even with the jump in our gasoline production, our supply of gasoline in storage at the end of the week still fell by 2,271,000 barrels to 236,763,000 barrels by June 8th, the ninth decrease in 14 weeks, but just the 10th decrease in 31 weeks, as gasoline inventories, as usual, were being built up over the winter months…..our gasoline supplies decreased because the amount of gasoline supplied to US markets rose by 903,000 barrels per day to a record high of 9,879,000 barrels per day, and because our exports of gasoline rose by 69,000 barrels per day to 607,000 barrels per day, while our imports of gasoline rose by 47,000 barrels per day to 824,000 barrels per day….so after this week’s decrease, our gasoline inventories finished the week 2.4% lower than last June 9th’s level of 242,444,000 barrels, even as they were still roughly 9.7% above the 10 year average of gasoline supplies for this time of the year…

since the amount of gasoline supplied to US markets, seen as a measure of domestic demand and consumption, was at a record high this week, we’ll include a graph of what that looks like, compared to its recent history…

the above graph came from a package of oil graphs on this report that John Kemp of Reuters emailed out on Wednesday (available as a pdf here), and it shows gasoline supplied to US markets in thousands of barrels per day by “day of the year” for the past ten years, with the past ten year range of our domestic gasoline demand for any given date shown in the light blue shaded area, and the median of our gasoline consumption, or the middle of the 10 year daily range, traced by the blue dashes over each day of the year….the graph also shows the number of barrels of gasoline supplied for each week in 2017 traced weekly by a yellow line, and the year to date gasoline supplied for 2018 represented by the red graph…as John headlines at the top, that red line shows that gasoline supplied rose by 903,000 barrels to a record high of 9.88 million barrels per day with this week’s report, which means it rose by more than 10% from the prior week’s level…now, you can see by the red line that “gasoline product supplied” is quite volatile, and during the prior week it had fallen to a 16 week low….if you recall our closing discussion on last week’s report, we noted that all refinery “product supplied” metrics had dropped last week, resulting in what was the largest jump in product inventories in nearly 10 years, which we showed was a fluctuation similar to that of prior Memorial day weeks…so this week’s “record demand” is colored by that drop, as all product supplied metrics bounced back, as wholesalers and retailers rebuilt their own supplies, after the holiday drawdown..

meanwhile, with this this week’s decrease in distillates production, our supplies of distillate fuels fell for the 8th time in 10 weeks, decreasing by 2,101,000 barrels to 114,693,000 barrels during the week ending June 8th…our distillate inventories decreased because the amount of distillates supplied to US markets, a proxy for our domestic consumption, jumped by 902,000 barrels per day to 4,404,000 barrels per day, after decreasing by 817,000 barrels per day the prior week, when distillate wholesalers were drawing on their own supplies, which they’d built in advance of the holiday weekend…meanwhile, our exports of distillates fell by 548,000 barrels per day from last week’s near record to 1,111,000 barrels per day, while our imports of distillates decreased by 42,000 barrels per day to 104,000 barrels per day…since this week’s inventory decrease comes after our distillate supplies fell by 14,452,000 barrels over the six weeks to May 18th, our distillate supplies for the week ending June 8th are now 24.3% below the 148,768,000 barrels that we had stored on June 9th, 2017, and roughly 16.1% lower than the 10 year average of distillates stocks for this time of the year…

with our supplies of distillates now at the lowest they’ve been at this time of year in 10 years, we’ll take a look at a graph of what that looks like, compared to that 10 year history:

again, this graph also comes from that weekly emailed package of oil graphs from John Kemp of Reuters, which is available as a pdf here…it shows US distillate fuels inventories in thousands of barrels by “day of the year” for the past ten years, with the past ten year range of our distillates supplies on any given day of the year shown in the light blue shaded area, and the median of our distillates inventory, or the midpoint of the 10 year daily range, traced by the blue dashes over each day of the year…the graph also shows the number of thousands of barrels of distillates we had stored for each week in 2017 traced weekly by a yellow line, with our 2018 year to date distillates supplies for each week traced in red…notice in the light blue shaded area that there is normally a seasonality to distillates supplies, as they’re normally built up during the summer when refineries are running flat out, and then drawn down and consumed during the winter months, when demand for heat oil is greatest…however, this year, when supplies of distillates should have been increasing during April and May as they typically do, they were falling instead, in part due to decreased production, but mostly because we have been exporting our distillates at near a record pace…thus we come to June 8th with our distillate supplies at a 10 year low for this time of year, after falling almost continuously since hitting an all time high of 170,746,000 barrels on February 3rd, 2017, as you can see above in the yellow graph line for 2017…

finally, with our oil exports rising and our oil imports falling while our refineries were using more oil, our commercial supplies of crude oil decreased for the 11th time in 2018 and for the 34th time in the past year, as our commercial crude supplies fell by 4,143,000 barrels during the week, from 436,584,000 barrels on June 1st to 432,441,000 barrels on June 8th…thus, after falling most of the past year, our oil inventories as of June 8th were 15.5% below the 511,546,000 barrels of oil we had stored on June 9th of 2017, 13.7% below the 500,911,000 barrels of oil that we had in storage on June 10th of 2016, and fractionally below the 435,771,000 barrels of oil we had in storage on June 12th of 2015, during a period when the US glut of oil had already begun to build from the nearly stable supply levels of the prior years…

OPEC’s Monthly Oil Market Report

we’re going to take a look at OPEC’s June Oil Market Report (covering May OPEC & global oil data) next, because it’s available as a free download and hence it’s the report we check for monthly global oil supply and demand data, rather than the paywalled report of the IEA that’s widely reported in the media…the first table from this monthly report that we’ll look at is from the page numbered 59 of that report (pdf page 67), 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 an impartial adjudicator as to whether their output quotas and production cuts are being met, to thus resolve any potential disputes that could arise if each member reported their own figures…

as we can see on this table of official oil production data, OPEC’s oil output increased by 35,400 barrels per day in May to 31,869,000 barrels per day, from their April production total of 31,834,000 barrels per day….however, that April figure was originally reported as 31,930,000 barrels per day, so OPEC’s oil production during May was actually 61,000 barrels per day lower than the previously reported April figures (for your reference, here is the table of the official April OPEC output figures as reported a month ago, before this month’s revisions)…as you can tell from the far right column above, an increase of 85,500 barrels per day in the output from Saudi Arabia was the main reason that the cartel’s output rose, with Algeria contributing a 39,000 barrel per day increase and Iraq’s increase of 27,700 barrels per day, together more than offsetting the decreases of 53,500 barrels per day in Nigerian output, 42,500 barrels per day in Venezuelan output, and 24,300 barrels per day in Libyan output…however, with a quota of 10,060,000 barrels per day for the Saudis, and 1,040,000 barrels per day for the Algerians, both of those countries still remain well below their allocations, according to their original pact…and at 31,869,000 barrels per day, OPEC oil output is now 861.000 barrels per day below the 32,730,000 barrels per day revised quota they agreed to at their November 2017 meeting, with only Iraq’s 4,455,000 barrel per day May output above their 4,350,000 barrel per day allocation…

the next graphic we’ll include shows us both OPEC and world oil production monthly on the same graph, over the period from June 2016 to May 2018, and it comes from the page numbered 60 (pdf page 68) of the June OPEC Monthly Oil Market Report…on this graph, the cerulean blue bars represent OPEC 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…

OPEC’s preliminary data indicates that total global oil production rose by a rounded 270,000 barrels per day to a record 97.86 million barrels per day in May, after April’s global output total was revised down by 300,000 barrels per day from the record 97.89 million barrels per day global oil output that was reported a month ago, as non-OPEC oil production rose by 230,000 barrels per day in May….global oil output for May was also 1.74 million barrels per day, or 1.8% higher than the 96.12 million barrels of oil per day that were being produced globally in May a year ago (see the June 2017 OPEC report online (pdf) for the year ago details)… OPEC’s May oil production of 31,869,000 barrels per day thus represented just 32.6% of what was produced globally, the same percentage as in April, as oil output increases by the US, Canada, Brunei, Brazil, Kazakhstan, Azerbaijan, Ghana and Saudi Arabia were only partially offset by decreases in oil output seen in Mexico, Norway, the UK, Australia, Colombia, Egypt, China and Nigeria…OPEC’s May 2017 production was at 32,139,000 barrels per day, which means that the 13 OPEC members who were part of OPEC last year, excluding their new member Equatorial Guinea, are now producing 140,000 fewer barrels per day of oil than they were producing a year ago, during the fifth month that their production quotas were in effect, with the recoveries of oil production in Libya and Nigeria now more than offset by the decrease in output from Venezuela, whose output is now running 571,000 barrels per day below what it was at last May…

however, despite the record global oil output in May, the downward revisions to supply meant that we again saw a deficit in the amount of oil being produced globally during the month, as this next table from the OPEC report will show us…

the table above comes from page 33 of the June OPEC Monthly Oil Market Report (pdf page 41), and it shows regional and total oil demand in millions of barrels per day for 2017 in the first column, and OPEC’s estimate of oil demand by region and globally quarterly over 2018 over the rest of the table…on the “Total world” line of the third column, we’ve circled in blue the figure that’s relevant for May, which is their revised estimate of global oil demand during the second quarter of 2018…

OPEC’s estimate is that during the 2nd quarter of this year, all oil consuming regions of the globe will be using 98.07 million barrels of oil per day, which is a small downward revision from their prior estimate of 98.08 million barrels of oil per day during the 2nd quarter….meanwhile, as OPEC showed us in the oil supply section of this report and the summary supply graph above, after the OPEC and non-OPEC production cuts, the world’s oil producers were only producing 97.86 million barrels per day during May, which means that there was a shortfall of around 220,000 barrels per day in global oil production vis-a vis estimated demand during the month…

at the same time as 2nd quarter global demand was revised 10,000 barrels per day lower, April’s global output total was revised down by 300,000 barrels per day to 97,590,000 barrels per day, so that means that the shortfall for April now works out to 480,000 barrels per day, revised from the 190,000 barrel per day shortfall we had figured on a month ago…but as you see circled in green above, while global oil demand figures for the second quarter were revised slightly lower, global oil demand figures for the first quarter of 2018 were revised 60,000 barrels per day higher, which means that our previously computed oil surplus for the first quarter of 2018 will also have to be recomputed…based on the revisions of a month ago, we had figured a global oil surplus of 240,000 barrels per day for March, a global oil surplus of 420,000 barrels per day for February, and a global oil surplus of 260,000 barrels per day for January…each of those surplus figures thus have to be revised lower based on higher demand, so hence our new figures will show a surplus of 180,000 barrels per day for March, a surplus of 360,000 barrels per day for February, and a surplus of 200,000 barrels per day for January…totaling it all up, that means that for the first five months of 2018, global oil production exceeded demand by just 640,000 barrels, the equivalent of just 9 extra minutes of production at the May rate…

This Week’s Rig Count

US drilling activity decreased for the first time in the past twelve weeks and for just the 2nd time in the past 17 weeks during the week ending June 15th, as drilling for natural gas was curtailed while drilling for oil continued to increase…Baker Hughes reported that the total count of active rotary rigs running in the US decreased by 3 rigs to 1059 rigs over the week ending on Friday, which was still 126 more rigs than the 933 rigs that were in use as of the June 16th report of 2017, while it was down from the recent high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC officially began their attempt to flood the global oil market…

the count of rigs drilling for oil was up by 1 rig to 863 rigs this week, which was also 116 more oil rigs than were running a year ago, while it was still well below the recent high of 1609 rigs that were drilling for oil on October 10, 2014…at the same time, the number of drilling rigs targeting natural gas formations fell by 4 rigs to 194 rigs this week, which was only 8 more gas rigs than the 186 natural gas rigs that were drilling a year ago, and way down from the modern high of 1,606 natural gas rigs that were deployed on August 29th, 2008…in addition, there continues to be two rigs operating that are considered to be “miscellaneous”, in contrast to no such “miscellaneous” rigs in use a year ago….

drilling activity in the Gulf of Mexico and elsewhere in the US offshore was unchanged this week, with 19 platforms deployed in the Gulf and one drilling offshore from Alaska, down from 21 rigs drilling in the Gulf and one offshore from Alaska last June 16th…however, another platform was set up to drill through an inland lake in southern Louisiana this week, so now there are 4 such ‘inland waters” rigs operating, an increase from the 3 inland waters rigs that were operating going into the same weekend a year ago…

in their first pullback in 9 weeks, the count of active horizontal drilling rigs decreased by 2 rigs to 932 horizontal rigs this week, which was 150 more horizontal rigs than the 782 horizontal rigs that were in use in the US on June 16th of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…in addition, the vertical rig count decreased by 1 rig to 60 vertical rigs this week, which was also down from the 82 vertical rigs that were in use during the same week of last year…on the other hand, the directional rig count was unchanged at 67 directional rigs this week, which was still down from the 69 vertical rigs that were deployed on June 16th of 2017…

the details on this week’s changes in drilling activity by state and by shale basin are included in our screenshot below of that part of the rig count summary pdf from Baker Hughes that shows those changes…the first table below shows weekly and year over year rig count changes for the major producing states, and the second table shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of June 15th, the second column shows the change in the number of working rigs between last week’s count (June 8th) and this week’s (June 15th) count, the third column shows last week’s June 8th active rig count, the 4th column shows the change between the number of rigs running on Friday and those of the equivalent weekend report 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 on Friday the 16th of June, 2017…

as you can see from the above table, this week’s small net decrease masked a number of both positive and negative changes in drilling nationally…of particular note was the 4 rig decrease in the Permian basin of west Texas and New Mexico, the largest pullback in the Permian since a similar number of rigs were shut down during the week ending February 2nd…looking at the changes in activity in the individual Texas oil districts in the state data, the core Permian areas appear to show a decrease of 6 rigs, so we can probably figure that two of the New Mexico rig increases were in the western part that basin…for once, the 4 rig decrease in rigs targeting natural gas is easily identifiable, as two rigs were pulled from the Marcellus (one from Pennsylvania and one from West Virginia), a rig targeting gas was pulled out of Oklahoma’s Arkoma Woodford, and another gas rig was shut down in Ohio’s Utica shale…activity in the Utica is now at 23 rigs, down from 28 rigs a year ago, so some Ohioans can be thankful, despite the state’s deterioration otherwise…. also note that in addition to the changes shown in the major producing states in the top table above, this week also saw a rig added in Mississippi, while the only rig that had been operating in Montana was pulled out…Mississippi now has 4 rigs operating, up from 3 rigs a year ago, while the Montana rig appears to have just been moved across the North Dakota border, into another part of the Williston basin…

++++++++++++++++++++++++++++++++++++

Rig Count Holds Steady as Ohio Permitting Slows – The number of oil and gas rigs operating in eastern Ohio’s Utica shale stood at 19 for the week ended June 9, as permit activity trickled to a near stop, according to the latest update from the Ohio Department of Natural Resources.ODNR reported that it awarded just two new permits for horizontal wells in the Utica last week, both to Ascent Resources Utica LLC for wells in Guernsey County.The agency released just one permit the previous week, indicating a slowdown in terms of permit interest over the last several weeks.As of June 9, ODNR has issued 2,837 permits for horizontal wells in the Utica. Of that number, 2,358 wells are drilled and 1,899 are producing. No new permits were issued for the northern tier of the Utica, which includes Mahoning, Trumbull and Columbiana counties, according to ODNR. There were no new permits issued in nearby Lawrence and Mercer counties in western Pennsylvania, according to the Pennsylvania Department of Environmental Protection.

Community leaders cast wary eye on injection wells – Toledo Blade – Fears about the oil and gas industry’s disposal of briny waste fluids in injection wells drilled deep into the ground keep growing, even in areas that historically haven’t had much to worry about because of their karst-prone bedrock.The mere presence of karst – an extremely porous, environmentally sensitive, and relatively soft rock formation near many land surfaces around the world, including southeast Michigan and northwest Ohio – doesn’t necessarily rule out drilling. But it sends warning signals to take extra caution and, thus, often deters such activity. But now, with a global fracking frenzy that began a decade ago in full swing, people who live in places once assumed to be off-limits to drilling and fracking are experiencing new levels of anxiety – especially when it comes to whether more karst-prone areas will soon host deep underground injection wells used to bury waste fluids.New regulatory rules approved this month in Michigan aim to give state officials more control over drilling operations. State Sen. Dale Zorn (R., Ida), who in 2015 tried unsuccessfully to convince the Michigan legislature to pass a statewide ban on injection wells for karst-prone areas, called the Michigan Department of Environmental Quality’s past policies toward karst “very, very weak” and said he believes the new rules will help, but not end threats.“It’s never been an economic issue to me. It’s always been a safety issue,” Mr. Zorn said.Neal Thurber, a LaSalle Township resident who spent years drilling wells in the oil and gas industry, said karst-prone areas that allow injection wells into them are “taking on a very high level of risk for contamination for virtually no benefit.”

Coshocton County group opposes company’s effort to accept more injection-well fluids – Columbus Dispatch – A company operating injection wells in Coshocton County has asked regulators to allow a change in its permitting to accept industrial and other nonhazardous waste fluids instead of just oilfield brine.If Buckeye Brine is successful, it would mark the first time an Ohio Class II injection well was switched to a Class I.Operators say they’ve been pumping oilfield fluids into rock formations deep underground for several years without incident, that the facility was built to exceed injection-well standards and that the permitting change would provide an environmentally friendly alternative for disposing of nonhazardous waste fluids.”We’ve operated flawlessly for five years,” said Steve Mobley, company president. “We’re experienced at this business and we’re doing a good thing for the surface waters of the state and making industrial businesses better able to operate affordably.”But a local environmental group opposes the move, citing continued concerns about toxic fluids being pumped into the ground. Coshocton Environmental and Community Awareness, or CECA (http://www.cecaware.org), and its supporters are posting “No Class I Injection Wells” signs along some roads in the vicinity and urging regulators to reject the application. A billboard with the message is planned along Route 16.”You can’t take this rotten apple and make it good,” said Tim Kettler, a member of the nonprofit advocacy group’s board. “Our position on this is this whole method of wastewater disposal is improper. It’s going to be our legacy, this 7 billion gallons of unknown wastewater … beneath our community for our children and grandchildren.”The signs have prompted debate in Coshocton, about an hour and a half northeast of Columbus. Community groups and some residents have visited the injection well site in recent weeks and been given tours of the operations and explanations of the company’s proposal.

Penn State study: Spraying brine from drilling, fracking on roadways is hazardous – Pittsburgh Post-Gazette – Spreading wastewater from non-shale oil and gas drilling and fracking on unpaved roads is a cheap way for municipalities to suppress dust and melt snow, but a Penn State University study says the practice has potentially high costs for human health and the environment.The study, published in the journal “Environmental Science & Technology” last month, said the wastewater contains salts, radioactivity and organic contaminants “often many times higher than drinking water standards.”The toxicity of the wastewater is a concern because rain can wash heavy metals, oils and radium, a carcinogen, from roads into nearby water sources, the study said. “It’s true that breathing road dust is a health risk,” said William Burgos, a professor in PSU’s Department of Civil & Environmental Engineering and the study’s lead author. “But trading one environmental risk-driver for radium and hydrocarbons, well, I don’t know if that’s the best trade-off.” Mr. Burgos said the study’s analysis of wastewater used on roads in 14 townships found median radium levels between 1,200 and 1,500 picocuries per liter. The federal Safe Drinking Water Act limits radium levels in drinking water to 5 picocuries per liter, and radium in industrial waste discharges must be less than 60 picocuries per liter. “Road spreading of conventional oil and gas wastewater is the single largest source of radium being introduced into the environment in Pennsylvania,” Mr. Burgos said.

​Will Pennsylvania Regulators’ Ties to Fracking Industry Influence Their Decision on the Mariner East pipeline? – Opponents of a controversial Pennsylvania pipeline project are hoping that state regulators will uphold a judge’s decision to suspend the project. But the regulators’ extensive ties to the oil and gas industry raise serious concerns about conflicts of interest that may tilt the regulators toward favoring Sunoco, the pipeline company. As our new report shows, the PPUC’s decision may be tainted by conflicts of interest among commissioners, a majority of whom have ties to Pennsylvania’s oil and gas industry, including to Sunoco. The report, released last Friday, highlights the numerous relationships that 4 of 5 commissioners have to the fracking industry in Pennsylvania and, specifically, to the company behind the Mariner East project. This raises the serious question of how impartial a majority of commissioners – who built careers tied to the interests of the oil and gas industry – can be in regulating that same industry. Among other findings in the report are that Commissioner Norman J . Kennard is the former law partner of one of the attorneys representing Sunoco in the Mariner East case before the PPUC. Kennard was a partner at the firm Hawke, McKeon, Sniscak & Kennard (now called Hawke, McKeon & Sniscak) until around a decade ago. Kennard’s former partner, Thomas Sniscak, is currently representing Sunoco in its Mariner East proceedings. This means that Commissioner Kennard will be ruling on a case brought by his former law partner representing Sunono and the pipeline project.The report also finds that Commissioner David W. Sweet was a registered lobbyist for numerous fossil fuel companies – including EQT, Kinder Morgan, Koch Companies, NRG, and Philadelphia Energy Solutions – until 2015. Sweet is a former senior advisor on economic and energy policy to Governor Wolf, and he was part of the legal team that worked on behalf of the private equity firm Carlyle Group to arrange it acquisition – with Sunoco – of Philadelphia Energy Solutions, the largest oil refining complex on the eastern seaboard. After becoming 2/3 owner of the company with Sweet’s help, Carlyle Group raided PES, throwing it into hundreds of millions of dollars in debt while channelling at least $151 million in payments to itself – all while refusing to pay tens of millions in state taxes.

Pennsylvania allows ETP Mariner East 1 pipeline to resume service (Reuters) – Pennsylvania’s Public Utility Commission (PUC) voted on Thursday to allow Energy Transfer Partners LP’s Sunoco Mariner East 1 natural gas liquids pipeline to return to service, reversing a suspension tied to safety concerns.The PUC stopped flows on Mariner East 1 through West Whiteland Township after sinkholes were discovered near the pipeline, prompting State Senator Andrew Dinniman to ask for an emergency order to suspend service.All five PUC commissioners voted to allow Mariner East 1 to resume service. Three of the five commissioners, however, also voted to prevent ETP from working on the Mariner East 2 and 2X pipelines in West Whiteland Township.The decision overturned the emergency order, which was granted last month by a PUC administrative law judge and stopped ETP from moving liquids through Mariner East 1 and working on Mariner East 2 and 2X in the Chester County town, located about 30 miles (48 kilometers) west of Philadelphia. Dinniman’s district includes West Whiteland Township.It was not the first time Mariner East 1 was shut due to those sinkholes. The state stopped flows of liquids on Mariner East 1 for over eight weeks from March to May after the sinkholes were found, forcing producers like Range Resources Corp to find other ways to get their liquids to market.

Keep standards for gas wells – Pennsylvania has the oldest gas and oil industry in the United States, dating to the nation’s first commercial oil well, drilled in Venango County in 1859.That well, only about 70 feet deep, was the first of more than 300,000 that have been drilled since. They are distinct from the wells that characterize the relatively new gas industry that taps into the Marcellus and Utica shale formations thousands of feet deep. The Marcellus/Utica wells use modern deep-drilling technology and high-pressure “fracturing” to liberate gas trapped in the deep underground rock.Development of the new gas industry over the past 12 years prompted the state, belatedly, to update its laws and regulations covering the economics and environmental impact of large-scale drilling. Updated regulations covered the traditional industry and the new industry because the environmental concerns created by drilling are common even though the scope and techniques of the operations differ.Tuesday, the state House passed a bill, 111-84, that eliminates fundamental environmental regulations for the traditional gas industry.Sponsors complained that many smaller conventional well drillers can’t afford the same level of environmental compliance as the larger companies that dominate the shale industry.But the issue is environmental protection, and the House bill pretty much dispenses with it in several ways. It would allow drillers to spill 210 gallons of crude oil or 630 gallons of wastewater brine without reporting it to the Department of Environmental Protection. It also eliminates a requirement for drillers who damage a water supply to restore it to levels exceeding those of the Clean Water Act. The bill would take the commonwealth backwards by decades, in effect re-establishing standards for conventional wells as they were in 1984 – the last time the state revised drilling law prior to Act 13, the 2012 law that now governs drilling.

Shale Crescent USA Wants To Rebrand Region – Wheeling Intelligencer – The area has been known by many names – the Upper Ohio Valley, Appalachia, the Rust Belt and Coal Country – in the past, but one organization hopes to rebrand the region in a way that will help it capitalize on its natural gas and other petrochemical reserves. Greg Kozera wants residents, community leaders and businesses to start using the term “Shale Crescent” when they refer to our area, which is situated atop some of the largest natural gas fields in the world. He presented his ideas Tuesday during a Wheeling Area Chamber of Commerce event at Wheeling Jesuit University. Development and hydraulic fracturing, or “fracking,” of those fields began about a decade ago, and those involved in mineral exploration have since determined that the Marcellus, Utica, Devonian and Rogersville shales lie layered beneath our feet. Those shales all contain rich petrochemical deposits that Kozera said could attract a broad variety of industrial interests to the region. Kozera is the marketing director for Shale Crescent USA, a nonprofit based in Marietta, Ohio. The group’s primary goal is to attract new, high-paying manufacturing jobs to the area atop those layers of shale, including parts of Ohio, West Virginia and Pennsylvania. With those jobs, organization members believe, will come an array of development and a higher standard of living for all. They also believe it is important to define and promote the geographic region, so it can better compete with areas such as the Gulf Coast, which have been the traditional locations for petrochemical production and related industries.

EXCLUSIVE: WV explosion of TransCanada Leach XPress occurred feet from adjacent NGL pipeline – I’ve been studying the Marshall County, WV explosion of Columbia Pipeline / TransCanada “Leach XPress” pipeline (LXP), on Nixon Ridge, just south of Moundsville WV for the last 4 days. NO NEWS OUTLET is reporting the following facts:

• 1: In addition to the LXP, which was permitted Jan 2017, and went into service Jan 2018, there is another new pipeline was was recently permitted, the Mountaineer XPress (MXP), with a terminus at Nixon Ridge to the LXP. I believe it is now under construction.
• 2: The failure of the LXP occurred mere feet from the Blue Racer Midstream NGL pipeline, in the same ROW.
• 3: Also, from the published drone shots, it looks like there may have been construction activity in the area?

What has frustrated me, is that there is no one single data source to examine. These pipelines are so new (LXP, MXP), they are not yet in NPMS. So I had to assemble these maps painstakingly from a) NPMS, b) Google Earth, c) the EIS or EA of the LXP/MXP pipelines, and d) published photographs. I am beginning to measure the impact radius, but the failure occurred in a valley, so the blast was constrained on two sides by mountains. So while this may not set any records, it was a BIG fire.

US regulators urge better oversight for pipeline cybersecurity – The federal agency now charged with overseeing cybersecurity for U.S. pipelines is ill equipped to do the job, say two top regulators who want the role given to the Energy Department.The Federal Energy Regulatory Commission’s Neil Chatterjee, a Republican, and Richard Glick, a Democrat, wrote in an online article that the Transportation Security Administration can’t keep the pipeline network secure. The two FERC commissioners noted that the TSA has only six full-time workers overseeing more than 2.7 million miles of pipeline, and depends on voluntary cybersecurity standards, rather than mandatory ones. Instead, Congress should give the job to “an agency that fully comprehends the energy sector and has sufficient resources to address this growing threat,” the commissioners wrote.The plea, in an op-ed on the website Axios, follows a cyberattack in late March and early April in which several U.S. pipeline companies said their third-party electronic communications systems were shut down, with five confirming the disruptions were caused by hacking. While the cyberattack didn’t disrupt the supply of gas to homes and businesses, it underscored how energy companies are increasingly vulnerable to cyber threats and how even a minor attack can have ripple effects. “As abundant and affordable natural gas has become a major part of the fuel mix, the cybersecurity threats to that supply have taken on new urgency,”

TransCanada: No natgas flows through Leach Xpress in West Virginia – TransCanada said last Friday it cannot move natural gas until further notice through the section of its Leach Xpress pipeline in West Virginia that ruptured last week, making customers seek other pipelines to ship their gas.The blast that shut the 160-mile pipe did not cause any injuries and was contained on the morning of June 7, TransCanada said.The 1.5 billion cubic feet per day (Bcf/d) capacity Leach Xpress in West Virginia and Ohio, which entered full service at the start of 2018, transports gas from the Marcellus and Utica Shale plays in Pennsylvania, Ohio and West Virginia, to consumers in the U.S. Midwest and Gulf Coast.Leach Xpress is part of the 12,000-mile Columbia Pipeline System, which TransCanada acquired in 2016, serves customers from New York to the Gulf of Mexico.Columbia, which operates the line, declared a force majeure on June 7 and said the damaged section of pipe could affect movement of roughly 1.3 Bcf/d, Kallanish Energy reports. One Bcf/d is enough gas for about 5 million U.S. homes. Alternative pipelines to route production around the outage include Energy Transfer Partners’ Rover, Tallgrass Energy Partners’ Rockies Express, EQT Midstream Partners’ Equitrans and Enbridge’s Texas Eastern Transmission, Reutersreported.

Appalachian producers finding alternate markets for natural gas liquids – Given the continued closure of the Energy Transfer Partners Mariner East 1 natural gas liquids pipeline by Pennsylvania officials, Appalachian gas producers who hold capacity on the line are finding alternatives to get their ethane and other NGLs to market. But exploration-and-production companies and market observers have expressed concern that continued closure of Mariner East 1 — part of a system of pipelines to carry NGLs from plants in western Pennsylvania, Ohio and West Virginia to the export terminal at Marcus Hook, Pennsylvania — could slow the growth of gas production in the region. In a notice to investors, Range Resources said it has “already executed agreements for some of the Mariner East ethane volume to be sold in alternate markets.” The producer added that another option would be for the company to simply leave the ethane in the gas stream.In addition to Range’s Mariner East 1 ethane capacity, the company said it has transportation or sales arrangements covering about 41,000 b/d of the NGL. For its propane production, Range said it has access to another NGL pipeline as well as to railcars, which will allow it to move the product to various domestic markets as well as to international export markets through the Marcus Hook terminal. Another Appalachian producer, EQT, also downplayed the impact of the shutdown of Mariner East 1 on its operations. In an email statement, an EQT spokeswoman said in regard to the Mariner East 1 shutdown, “our gas continues to move as planned without complication.” Mariner East 1, a project of ETP’s Sunoco Pipeline, remains offline following a decision last month by Pennsylvania Public Utilities Commission Administrative Law Judge Elizabeth Barnes, which prohibited the reopening of the line pending a final PUC order. The wide-ranging order also called for the stoppage of all operation, drilling and construction activities on Mariner East 2 and 2X pipelines. ETP is hoping that the ALJ’s order will be overturned at the PUC’s regular meeting Thursday, spokeswoman Lisa Dillinger said in an email Monday. “Many letters of support to overturn have been submitted to the PUC in advance of the meeting — including from legislators, labor unions, and local townships,” Dillinger said.

TransCanada working on Leach Xpress pipeline after West Virginia blast — TransCanada Corp’s Columbia Gas Transmission (TCO) unit said it was working on a section of the Leach Xpress natural gas pipeline downstream of a pipe blast in West Virginia last week. That work will enable the Stagecoach-Leach Xpress meter in southeast Ohio to return to service, according to a notice to customers late Tuesday. The Stagecoach meter in Monroe County on the Ohio-West Virginia border connects to EQT Midstream Partners LP’s Strike Force South gathering fields in Monroe and Belmont counties in Ohio. Strike Force can also deliver to Energy Transfer Partners LP’s Rover and Enbridge Inc’s Texas Eastern Transmission (Tetco) pipelines. Columbia Gas said all other meters affected by the blast will remain at zero until the pipeline returns to service. The company said did not say when the full pipe would return to service, noting the site of the incident is in the restoration process. Columbia Gas told customers it will provide an update on the status of the pipe on June 18. The shutdown of Leach Xpress forced producers using the line to find other pipes to ship their gas out of the Marcellus and Utica shale regions of Pennsylvania, West Virginia and Ohio. Alternative pipelines include ETP’s Rover, Tallgrass Energy Partners LP’s Rockies Express (REX), EQT Midstream Partners LP’s Equitrans and Enbridge’s Tetco, according to analysts at S&P Global Platts. Columbia Gas, which declared a force majeure after the blast, said the damaged section of pipe could affect movement of about 1.3 billion cubic feet per day (bcfd). One billion cubic feet of gas is enough to fuel about 5 million U.S. homes for a day. Energy analysts said overall output in the Appalachian region was little changed by the blast as producers, like Range Resources Corp and Southwestern Energy Co, found other pipes.

Natural gas pipeline agrees to pay $430,000 penalty for water pollution violations – Rover Pipeline LLC has agreed to pay the West Virginia Department of Environmental Protection $430,000 for water pollution violations in the state, according to a consent order made public Tuesday. The natural gas pipeline project and the DEP made the deal May 15, documents show, but the public comment period for the consent order ends July 13. The agreement is in response to notices of violation and cease-and-desist orders issued to Rover Pipeline dating back to April 2017, said Jake Glance, spokesman for the DEP. In all, the pipeline has received 18 notices of violation and two cease-and-desist orders, the most recent of which was issued on March 5, when the regulators said crews left trash and construction partially buried on site and failed to clean the roads around the construction site.The DEP also issued a cease-and-desist order in July 2017 for similar violations.The consent order references violations dating back to April 2017, including failing to control erosion and keeping sediment water from leaving construction sites.“The good news that I see is that [the] DEP was on top of it, that they did a good job documenting multiple violations and it shows the importance of oversight of these projects because this company did not appear to be acting in good faith,” said Angie Rosser, executive director of the West Virginia Rivers Coalition.Energy Transfer Partners, Rover Pipeline’s owner, also owns the Dakota Access Pipeline – the subject of protests and heightened attention over its being built in North Dakota. The 713-mile-long Rover Pipeline will move natural gas from processing plants in West Virginia, Ohio and Pennsylvania. Crews are building the pipeline in Doddridge, Tyler and Wetzel counties in West Virginia

Panel won’t reconsider Mountain Valley Pipeline approval (AP) – A divided panel of federal regulators has denied requests from individuals and public interest groups to reconsider its approval of the Mountain Valley Pipeline. The Federal Energy Regulatory Commission on Friday issued an order turning down the requests. Two of the five commissioners dissented. Construction is currently underway on the approximately $3.5 billion, 300-mile natural gas pipeline, which will run through West Virginia and Virginia. The pipeline is scheduled to be in service by the end of the year. A number of legal challenges against it are pending. A pipeline spokeswoman said Friday that the commission’s decision reaffirms its previous findings that there is a public need for the project. Whether there is true demand for the gas is something environmental groups and other opponents dispute. The dissenting commissioners raised questions about need and the impacts of climate change, among other things.

Dominion Energy’s Atlantic Coast Pipeline Suffers Setback – Dominion Energy, Inc.’s Atlantic Coast Pipeline recently hit a regulatory roadblock, as a few environmental groups filed a petition with the Federal Energy Regulatory Commission (FERC) to halt the natural gas pipeline’s construction. Three environmental groups namely Sierra Club, the Defenders of Wildlife and the Virginia Wilderness Committee are the ones to oppose. They want construction work of the pipeline in West Virginia – which was authorized by FERC last month – to be stalled due to violation of the Endangered Species Act. The opponents claim that the federal appeals court refuted a required permit from the U.S. Fish and Wildlife Service and allowed construction to proceed anyway. The environmental groups allege that the pipeline’s developer did not have a valid Incidental Take Statement, as the federal agency did not set specific limits on damage that can be done to endangered species during construction and operation of the pipeline. While the owners of the pipeline project deny that the court rulings debunk the Fish and Wildlife Service’s approval, the environmentalists demand the construction to be suspended until a revised Incidental Take Statement is issued. Making good on his campaign promises to rev up infrastructure spending, President Trump signed an executive order in January 2017 to accelerate the environment review process and approvals for the Atlantic Coast Pipeline. While the FERC greenlighted the pipeline project last November, it has been facing opposition on environmental, health and safety concerns.

Are the feds cherry-picking data to force pipelines through vulnerable communities? – The government’s energy regulator is facing allegations of cherry-picking data to approve pipeline projects that would disproportionately harm communities of color.According to academics, attorneys, and non-governmental organizations, the Federal Energy Regulatory Commission used unreliable statistical methods in its analysis of the proposed Atlantic Coast Pipeline, masking its high cost to African-American and Native-American communities.While the Commission concluded that the pipeline poses no environmental justice concerns, these minority groups say that their environment, health, and culture will be disproportionately imperiled if the development goes ahead as planned. FERC faced similar accusations over the Sabal Trail pipeline in 2016, indicating a pattern in how the federal government manages to force unwelcome energy infrastructure through vulnerable communities.The ACP is a 600-mile underground infrastructure project that will transport gas from hydraulic fracturing facilities in West Virginia down to Robeson County in North Carolina. The project includes three compressor stations. Dominion Energy is the lead developer on the pipeline, and President Donald Trump has labeled it a “priority” project. FERC conditionally approved the ACP in October of 2017, after its Environment Impact Statement concluded that there would be “no disproportionately high and adverse impacts on environmental justice populations.” Duke Energy has claimed that the pipeline will benefit economically distressed communities by attracting jobs and development.Many people living in the area disagree. “It’s going to be a lot of pollution in our community,” says Robie Goins, a Lumbee Native American who lives in the evacuation zone of the pipeline’s proposed route. “The people who are in low-income, poverty-stricken areas are targets for these types of projects. It’s like we’re being targeted by the big corporations. It’s like they want to kill us all.”

MEI projects Marcellus, Utica and Permian to supply 55% of US gas by 2030 — McKinsey Energy Insights (MEI), the data and analytics specialist that provides distinctive insight to the global energy industry, forecasts that the Marcellus, Utica, and Permian shale plays will supply 55% of the North American gas market by 2030. The findings are reported in MEI’s latest North America Gas Outlook to 2030, which explores gas supply and demand projections to 2030.Yasmine Zhu, senior analyst at MEI, comments: “Continued improvements in technology have sustained North American gas production. Improved drilling and completions technology have led to enhanced recovery rates and efficiency, while innovations in water procurement and disposal are allowing operators to realize where additional savings can be made. We anticipate that further technical breakthroughs will continue to boost shale gas production and drive down costs, particularly over the next two to five years in marginal plays like the Haynesville.”Operators are also expected to target secondary plays from existing wells. These developments have substantially lowered breakeven costs, and MEI estimates that approximately 650 Tcf of gas – enough to meet over 25 years of North American demand – has a breakeven point below $2.8/MMBtu. Should recovering oil prices drive a boom in drilling, increasing oilfield services costs could influence the break-even price. By 2030, MEI expects that the Marcellus, Utica, and Permian shale plays will supply ~55% of the North American market. The Marcellus and Utica currently account for 27% of total US and Canadian supply, and MEI projects that percentage will grow to 40% by 2030. Of the anticipated associated gas growth, approximately 60% will come from the Permian, adding 14 Bcfd in 2030. However, additional infrastructure will be needed to keep pace with the rapid production growth and enable operators to capitalize on a higher wellhead price for export markets.

Marcellus, Permian Rig Counts Down as BHI’s US Tally Falls by Three – A drop in natural gas-directed drilling, included a net declines in the Marcellus and Utica shales, drove the U.S. rig count lower for the week ended Friday, according to data from Baker Hughes Inc. (BHI). The domestic tally fell by three week/week (w/w) to 1,059 from 933 active units a year ago. Four natural gas rigs exited the patch to offset a net gain of one oil-directed unit. Directional units finished flat w/w, while two horizontal units and one vertical unit packed up, according to BHI. All of the week’s U.S. net declines occurred on land, as Gulf of Mexico activity held steady at 19 rigs and one rig returned to inland waters. In Canada, 27 rigs returned for the week, including 18 oil-directed rigs and nine gas-directed, leaving the Canadian tally at 139, down from 159 a year ago. The North American rig count climbed by 24 w/w to end at 1,198 units from 1,092 rigs at this time last year. Among plays, the Permian Basin saw the largest net change for the week, dropping four units to finish at 476 (368 a year ago). A more detailed breakdown of BHI data by NGI’s Shale Daily shows the declines focused in the “Other” portion of the Permian, with the Midland sub-basin dropping one unit w/w as the Delaware sub-basin added one. Meanwhile, the Marcellus Shale saw two rigs dropped for the week to finish at 54, putting it even with its gas-focused competitor in the Gulf Coast region, the Haynesville Shale. Other declines were in the Arkoma Woodford, the Cana Woodford and the Utica Shale, which each dropped one rig. Gainers among plays included the Williston Basin and the Eagle Ford Shale, which each added two units, while one rig returned in the Granite Wash, according to BHI. Among states, North Dakota and New Mexico each added three rigs for the week, while Louisiana picked up a rig to end at 60 active units. Texas posted the largest weekly net decline among states, dropping four units to finish at 534. Alaska dropped two rigs overall, while Colorado, Ohio, Pennsylvania and West Virginia dropped a rig a piece.

Gap seen widening between US Northeast gas pipeline capacity, production – Natural gas pipeline takeaway capacity additions in the US Northeast production area have yet to spur the level of further output the market was expecting, making it difficult to fill the infrastructure during certain periods, according to S&P Global Platts Analytics.The perspective, offered during the first day of the LDC Gas Forum Northeast conference in Boston, comes as industry leaders analyze Appalachian Basin supply, demand and pricing fundamentals heading into the next decade.At issue is whether easing pipeline constraints are only temporary and the extent to which LNG export growth will encourage Marcellus and Utica shale producers to drill more. “New production is not there to fill these projects, and this is only going to get worse,” Luke Jackson, a Platts Analytics senior energy analyst, told attendees at the conference. “On the surface, you’d say the Northeast is evolving. I would argue, ‘Not so fast.'” Total Northeast production reached 27.3 Bcf/d on several days towards the end of December. Since then, TransCanada’s Leach XPress brought online its 1.5 Bcf/d of capacity while Energy Transfer Partners’ Rover Pipeline has added about 1.5 Bcf/d of capacity as well. Despite those increases, total Northeast gasproduction averaged 27.2 Bcf/d in May and is averaging 27.3 Bcf/d thus far in June, data compiled by Platts Analytics show.Rather than spurring regional production growth, additional pipeline capacity has reshuffled production volumes among existing Northeast takeaway pipelines. Jackson said the gap between Northeast capacity and production could be as wide as 10 Bcf/d by late 2019.

Republicans propose penalties for states that oppose offshore drilling | TheHill: House Republicans unveiled a draft proposal this week that would place fines on states that block offshore gas and oil drilling. The Republican draft proposal, first reported by The Washington Post, will be discussed at the Natural Resources Committee on Thursday. It would allow states to disapprove of offshore drilling for gas and oil in half of its lease blocks without facing any penalties. However, states with proposed lease sales that disapprove of drilling in more than 50 percent of the blocks would have to pay a fee equal to at least one-tenth the estimated revenue the government would have made if it had leased the blocks. The proposal also sets up a revenue-sharing scheme for states that allow drilling. The move would help pressure local politicians to fall in line with President Trump Donald John TrumpTrump suggested that North Korean TV anchor should get a job in US: report AT&T announces it has completed acquisition of Time Warner Classified Israeli report raises questions about Trump-Kim summit: report MORE ’s plan to increase offshore leasing. Earlier this year, Trump called for offshore drilling in nearly all U.S. coastal waters, negating a drilling ban former-President Obama imposed near the end of his term. Many Democrats and some Republicans in coastal areas have resisted Trump’s plan, and some have pledged to keep the federal government from allowing offshore leasing in their states. The pushback led Trump’s interior secretary, Ryan Zinke to tell Congress he would scale back Trump’s plan. Democrats are opposed to the proposal, arguing it could cost states millions or billions in fees if they choose to oppose drilling.

GOP offshore drilling proposal triggers debate –Republicans used a Natural Resources hearing Thursday to tout newly proposed legislation that would give states a larger share of royalties to incentivize them to back expanded offshore drilling. States that do not agree to allow offshore drilling, or that propose moratoriums on it, would see their share of revenue from federal drilling drop. Rep. Paul Gosar (R-Ariz.) touted the bill as a way to give states more authority, while saying they should not be able to veto lease sales. “While states are highly involved in the offshore lease planning process they do not have a veto over lease sales,” Gosar said at a Thursday House Natural Resources subcommittee on energy and mineral resources hearing. “It’s an acknowledgment that such an attempt to strand federal assets comes at the expense of the American taxpayer,” said Gosar, the subcommittee’s chairman. Rep. Rob Bishop (R-Utah), chairman of the House Natural Resources Committee, said the bill would be an example of federalism at its best. The bill, which was proposed this week, would take away management of offshore drilling from the Interior Department’s Bureau of Land Management and place it in the hands of states. If a coastal state chooses to expand drilling and increase production of fossil fuels, they’d get a larger portion – 60 percent – of the royalties from the lease sale.

Supporters of new Enbridge pipeline deliver petitions to Gov. Mark Dayton’s office – Supporters of a proposed new pipeline across northern Minnesota dropped off postcards and petitions containing 1,200 signatures at Gov. Mark Dayton’s office on Friday, the latest move in a drawn-out battle that is weeks away from a regulatory denouement.The Minnesota Public Utilities Commission is set to decide the fate of the controversial Line 3 project by Enbridge Inc. later this month after three years and several legal fights.Enbridge Inc. is seeking approval from state regulators to drain and seal up its aging crude oil Line 3 and construct a larger pipeline across a new, more southerly route.Petitions were signed by “a broad coalition” of supporters that include chambers of commerce, representatives of corn and soybean growers and construction trade unions, said a spokesman for Minnesotans for Line 3, which collected signatures during a five-month statewide canvassing effort.The group is led by United Piping Inc. CEO Bob Schoneberger, a former Enbridge employee whose company specializes in pipe construction for the oil and gas industry.Schoneberger did not respond to a request for comment.Mark Salmon, a retired member of Roofer’s Local 96 in Sturgeon Lake, Minn., said the project will add jobs and update aging infrastructure. He signed a card to show his support for what he called “a no-brainer.”“You’ve got old pipes and new technology that’s safer,” said Salmon, whose property is not affected by the proposed new route. “If you’re worried about the environment, why wouldn’t you want something that’s safer than something that’s been there for however many years and could bust?”The original Line 3 pipeline was laid in the 1960s. Enbridge says it is aging, corroding and operating at just over half capacity because of safety concerns. The new pipeline – which would begin in northern Alberta and end in Superior, Wis. – would restore the full flow of oil from Canada.

Staff members recommend state regulators approve controversial Enbridge pipeline project — Allowing Enbridge to build a controversial new oil pipeline across northern Minnesota would be better for the environment than to continue relying on the aging, corroding pipeline that it would replace, according to staff for the Minnesota Public Utilities Commission.The PUC staff comments are a recommendation for a new Line 3, but they are not the final decision in regard to the project.After conducting four public meetings this month, the PUC is expected to determine whether the proposed $2.6 billion Line 3 project should get a “certificate of need” and, if so, what route the pipeline should take.As is common before PUC meetings, the commission’s staff files briefing papers that sum up the issues. They often include PUC staff analysis and recommendations.In briefing papers filed Friday, PUC staff wrote: “A fair reading of the record would support the conclusion that, with respect to effects of the [Line 3] project on the natural environment, the consequences of granting a certificate of need for the project are more beneficial than denying it because of the risk of catastrophic failure of the existing line, despite it being operated at reduced pressure.” The 1960s-vintage Line 3, one of six Enbridge pipelines that ferry Canadian oil across Minnesota, runs at only 51 percent capacity due to safety concerns. Enbridge said a new pipeline would be safer and would restore the full flow of oil. If a new Line 3 is denied, Enbridge plans to keep operating – and regularly repairing – the old one.

US EIA lowers 2018 Henry Hub spot gas price forecast by 2 cents to $2.99/MMBtu – The US Energy Information Administration Tuesday raised by 1.17 Bcf/d to 87.35 Bcf/d its second-quarter natural gas marketed production estimate for the US. EIA, in its June Short-Term Energy Outlook, also raised its Q3 marketed production forecast by 1.09 Bcf/d to 88.22 Bcf/d. The agency raised its natural gas consumption estimates by 0.83 Bcf/d to 69.95 Bcf/d for Q2, and by 0.36 Bcf/d to 69.54 Bcf/d for Q3. EIA lowered its forecast for Q2 Henry Hub natural gas spot prices 1 cent to $2.84/MMBtu. The Q3 forecast also dropped 1 cent from the previous month to $3.01/MMBtu. The agency projected Henry Hub natural gas prices would average $2.99/MMBtu for the full year and $3.08/MMBtu in 2019.

Soaring NGL Supplies May Soon Overwhelm Mont Belvieu Fractionation Capacity – The NGL sector is firing on all cylinders. Natural gas liquids production in the Permian, the SCOOP/STACK and other key basins is up, up, up. A number of new, ethane-consuming steam crackers are coming online along the Texas and Louisiana coast, most conveniently close to the NGL storage and fractionation hub in Mont Belvieu, TX. The export market for liquefied petroleum gases – propane and normal butane – is through the roof, averaging more than 1 MMb/d in the first five months of 2018 (almost all of it being shipped out of Gulf Coast ports), and ethane exports are strong too. What’s not to like? Well, NGLs don’t do anyone much good until they are fractionated into “purity products” like ethane, propane, normal butane etc., and the rapid run-up in U.S. NGL production – combined with the reluctance of producers to commit to new fractionation capacity – has the existing fractionation plants in Mont Belvieu running flat-out to keep up. Today, we begin a review of the NGL Capital of the Western World and considers why Mont Belvieu – as big as it is – is getting bigger.

US feedstocks imports climb above 300,000 b/d on ExxonMobil cargo: Census data – Feedstocks imports to the US from Europe, Africa and other sources rose back above 300,000 b/d in the first 10 days of June with support from a 410,000-barrel cargo shipped by BP and signed for by ExxonMobil, according to US Census Bureau data made public Monday. The Eagle Turin docked at Baton Rouge, Louisiana, June 6 with BP-sourced straight-run fuel oil that had been in storage in the Gulf of Mexico, according to data compiled by S&P Global Platts Analytics. Since late April, the Eagle Turin has been offloading oil from Gulf Coast floating storage for delivery across the region, according to S&P Global Platts’ cFlow trade flow software. In the June 1-10 period, the US brought in 312,000 b/d of vacuum gasoil and straight run fuel oil, compared with imports of 198,000 b/d in the previous 10-day period — May 22-31, the data show. US refiners typically are short 300,000-400,000 b/d of feedstocks and fill that need from sources in Northwest Europe, the Baltics, Russia, the Black Sea and Algeria. Companies signing for feedstocks imports June 1-10 included Marathon, Lukoil, Trafigura, Chevron, Statoil, Vitol, Repsol and Valero, the data show.

Permian oil will outpace all OPEC nations except Saudi Arabia — The Permian Basin in West Texas is on track to produce more oil within five years than any OPEC nation except Saudi Arabia, positioning the Texas Gulf Coast to rival the Persian Gulf when it comes to oil and gas activity. Crude volumes from the Permian will more than double by 2023, making the region the world’s third-largest producer after Russia and Saudi Arabia, according to the research and consulting firm IHS Markit. Most of that oil is headed to refineries and ports near Houston and Corpus Christi, as U.S. crude exports are expected to surge to nearly 5 million barrels a day by 2023, up from more than 2 million today.“In the past 24 months, production from just this one region – the Permian – has grown far more than any other entire country in world,” said Daniel Yergin, IHS Markit vice chairman.The comeback of the Permian, which today accounts for more than half the nation’s active oil drilling rigs, is among the the most remarkable stories in the industry’s history. At the beginning of the decade, the aging oil field was struggling with declining production. But advances in hydraulic fracturing, or fracking, and horizontal drilling pioneered by Houston companies such as EOG Resources, have tapped massive reserves of previously inaccessible oil and gas.By 2023, the shortage of pipelines to move oil, gas and natural gas liquids to Gulf Coast markets and beyond is expected to be alleviated by multibillion-dollar projects now underway or planned. Oil, petrochemical and liquefied natural gas companies are investing billions of dollars to process and export petroleum from the Permian and other shale plays, which, according to the International Energy Agency, has made the Gulf Coast a global trading center as vital to world’s energy needs as the Straits of Hormuz, through which tankers filled with Middle Eastern crude travel to the world’s markets.Near Corpus Christi, for example, the Houston exploration and production company Occidental Petroleum, is continuing to expand its crude export terminal at Ingleside. In 2017, Texas accounted for three-fourths of U.S. crude exports, which recently hit a weekly record in May of 2.6 million barrels a day. IHS Markit estimates that $308 billion in new spending is required to drill more than 40,000 new wells in the Permian needed to meet its projections. That’s more than double the $150 billion invested there from 2012 to 2017. The report also assumes that oil prices will continue to average at least $60 a barrel.

Permian Boom Jeopardized By Pipeline Troubles – The Permania, as someone called the oil industry and private equity rush to West Texas and New Mexico, has begun to take its toll on all those investors that saw it as the next huge thing. With production booming, pipeline capacity has become tight, and producers are forced to sell their crude at a painful discount to benchmarks. They are also losing billions in market capitalization. A recent story from Bloomberg estimated that over the last two weeks, eight of the biggest oil producers with a presence in the Permian have shed a collective US$15.6 billion in market value, or over US$1 billion per day, with some of the shares booking double-digit drops. It is an impressive turning of the tables. Just a year ago, everyone who had acreage in the Permian was a magnet for investors. The U.S. Geological Survey had upgraded the reserve estimates for the basin, especially thanks to a major upward revision of the Wolfcamp area. Producers boasted of being able to produce crude at ridiculously low production cost levels. And produce it they did, at a fast-increasing pace, which eventually clogged the pipes. The current pipeline capacity in the Permian is 3.1 million barrels daily. Railway capacity, according to S&P Platts, is around 315,000 bpd. However, the railway is mostly used to supply frac sand for the ever-hungrier wells. Production, as estimated by the Energy Information Administration, should this month reach 3.277 million bpd. And it will continue to rise. No wonder investors are worried. Some are so worried, in fact, that they are dropping their holdings in Permian players, even big names such as Concho Resources and Pioneer Resources. They are moving to producers with more diverse asset portfolios, Bloomberg reports, citing analysts. Pure-play Permian is no longer a stamp of guaranteed success. There is, of course, a solution to this problem, which has seen Midland crude trade at a discount of US$19 a barrel to international Brent. The solution is more pipeline capacity, and although it has been slow in coming, it is coming.

Exxon Mobil, Plains partner on Permian pipeline project – Exxon Mobil is joining the race to build out pipeline networks that stretch hundreds of miles across Texas to deliver crude oil from the booming Permian Basin to refining and port hubs near Houston.Exxon Mobil said Tuesday it plans to create a joint venture with Houston’s Plains All American Pipeline to construct a multibillion-dollar pipeline stretching from west of Midland to the Houston and Beaumont areas that would carry oil and condensate. Plains and Oklahoma-based Magellan Midstream Partners recently expanded their BridgeTex oil pipeline, which has served as the major artery from West Texas to the Houston region. Permian oil production, however, is at a record high and rapidly rising and the lack of pipelines are creating bottlenecks that hamper the pace of growth and create discounts to Permian-produced oil.

Permian Basin Pipeline Will Carry Out 1 M Barrels of Crude Oil Per Day – ExxonMobil and Plains All American Pipeline announced Tuesday a joint pursuit to construct a multi-billion dollar pipeline that will transport more than 1 million barrels of crude oil and condensate per day from the oil-rich Permian Basinto the Texas Gulf Coast, the Houston Chronicle reported. The proposed pipeline will stretch hundreds of miles from both Wink and Midland, Texas to delivery points in Webster, Baytown and Beaumont, Texas, a news release from the companies stated.Despite governments around the world enacting measures to reduce carbon emissions to help fight climate change, the latest oil market forecast from the International Energy Agency (IEA) makes it clear that the world is yet to turn its back on fossil fuels.Production in the Permian shale field in western Texas has been booming. According IEA’s Oil 2018forecast, global oil production capacity is expected to grow by 6.4 million barrels a day (mb/d) to reach 107 mb/d by 2023. Much of that growth is led by the U.S. due to oil produced from fracking the Permian, where output is expected to double by 2023.However, there is currently not enough pipeline capacity to retrieve Permian oil, causing regional oil prices to deflate.But that bottleneck has opened up opportunities for pipeline developers in the region. Exxon said in January it plans triple Permian production to 600,000 oil-equivalent barrels by 2025, and spend more than $2 billion on transportation infrastructure to support its Permian operations. Houston-based Plains All American Pipeline is investing $1.6 billion in Permian expansions, but other pipelines are also in the works, according to Motley Fool. Epic Midstream has proposed a 440,000 barrel-per-day (bpd) crude oil pipeline in the region, so has Magellan Midstream Partners, which has proposed a 600,000 bpd pipeline.

The El Encino-To-Topolobampo Pipeline Nears Completion, And What It Means For Waha –Mexico has been slowly increasing import volumes of natural gas from the U.S., utilizing spare capacity in the newest pipelines south of the border that access supply from the Permian Basin’s Waha Hub. The recent increases have been muted somewhat by delays in completing other infrastructure inside of Mexico, but one of those big delays is about to be resolved. TransCanada’s long-awaited El Encino-Topolobampo Pipeline is finally nearing completion, and once it’s online there may be a surprisingly big gain in gas export volumes to Mexico. As most of this gas will be supplied directly from Waha, Mexico’s impact on Permian gas balances is likely to jump materially in the weeks ahead. Today, we examine the latest development in Mexico’s natural gas pipeline buildout and its effects north of the border. We last looked at the buildout of Mexico’s natural gas pipeline infrastructure in our Closer blog, where we took a deep dive into the most recent developments in Northwest Mexico, focusing on the Fermaca-built pipeline network. Prior to that, we wrote Welcome to the Future, in which we evaluated the evolving structure of Mexico’s pipeline transportation capacity market and its implications for flows and pricing of gas within the U.S.’s southern neighbor. That blog also discussed the role of Comisión Federal de Electricidad’s (CFE) marketing affiliate, CFEnerg’a, in marketing and trading gas and other fuels within Mexico. In today’s blog, we shift focus to the El Encino-Topolobampo Pipeline, which will link demand along the west coast of Mexico to the Permian, and the plan by CFEnerg’a to provide Permian-sourced gas to power plants along the new pipe.

Side Effect of Rising Oil Drilling: Indigestion for Gas Frackers – Higher oil prices are helping many American shale drillers. But they are hurting companies that frack for natural gas. As companies respond to rising oil prices by drilling more for it, they often unearth gas as a byproduct. That has further weighed on already low gas prices, pressuring shale frackers in regions that primarily produce gas. The average share price for the five top companies focused on the oil-rich Permian Basin in Texas and New Mexico are up more than 16% over the past year. Share prices for the top five producers focused on the Marcellus Shale in Appalachia, the country’s largest deposit of natural gas, are down more than 9%. “It’s going to be tough for the Marcellus for a while,” said Brian Lidsky, managing director at oil-and-gas research firm PLS Inc. “There is just a tidal wave of gas coming out of the Permian.” Like most shale drillers, those focused on natural gas in the Marcellus – a group that includes Cabot Oil & Gas, EQT Corp, Range Resources, Antero Resources, and Southwestern Energy have been under investor pressure to live within their means, curtail excessive spending and improve returns. And they have come closer to doing that. As a group, those companies spent about $106 million more than they made in the first quarter of 2018, according to a Wall Street Journal analysis of S&P Global Market Intelligence data. That is down from outspending cash flow by more than $274 million in the previous quarter and more than $735 million in first quarter of 2017. .Still, investors have been reluctant to put more money into gas drillers, and the reason is simple: Gas has been cheap for years and doesn’t look primed to go up soon. Demand for natural gas is predicted to rise globally over the next decade as many countries switch from coal-fired power plants to gas-powered ones. However, that isn’t expected to solve gas drillers’ problems in the short term.

Another fracking boom to beget another fracking bust; or will it? | TheHill: – Employers and community leaders in Midland, Texas are in a scramble to keep essential services operating as restaurant workers and school bus drivers are leaving their jobs for much more lucrative work in the oil patch.It’s another fracking boom reminiscent of the 2013 boom in South Texas’ Eagle Ford Shale. Such is life in the oil industry, characterized by boom-bust cycles ever since Edwin Drake discovered oil in western Pennsylvania in 1859. So why this latest oil and gas boom? Most people know that hydraulic fracturing (fracking) has stimulated steady growth in domestic oil and gas production (and exports). But fossil fuel consumption has been growing as well. Indeed, natural gas and coal still dominate the electric generation mix nationally and retain large market shares in places like New England (49 percent) and New York (29 percent) that seem to want to decarbonize. Economic factors drive energy consumption decisions. While coal is losing market share because it can’t compete on price, oil and gas still can. Oil and gas frequently beat their competitors on price in the transportation and electric generation sectors, respectively, notwithstanding growing demand for electric cars and newly inexpensive wind and solar power. This boom has all the earmarks of past oil and gas booms: rapid and drastic increases in salaries and prices in host communities and concerns about the ability of local communities to manage the consequent social and economic disruptions, truck traffic, environmental impacts, etc. For every boom, there comes a bust. But some hypothesize that this boom might be different – longer lasting, because of the enormous size of the resource and international geopolitical factors that could keep the price of oil higher for longer.

Natural gas pipeline explosion rocks rural Kansas – A Southern Star Central Natural Gas pipeline exploded outside Hesston, Kansas, early Friday morning, sending flames shooting 75 to 100 feet into the sky, CBS Wichita affiliate KWCH reports.Southern Star spokesman Rob Southard said that the pipeline was shut off, with the fire burning up what was left. He said finding a cause could take weeks.Capt. Andy Wray, with Hesston Fire & EMS, told KWCH that the fire had spread from the pipeline to the surrounding wheat stubble field and grass, though fire crews were eventually able to contain it. He said support was requested from the American Red Cross and the Harvey County Emergency Response Team due to the heat and the high demand on firefighters. No injuries were reported. Residents were asked to steer clear of the affected area.

In possible roadblock for Keystone XL, pipeline opponents gift land to Ponca – For five years, opponents of the Keystone XL pipeline and members of the Ponca Indian Tribe have sown native tribal corn in the path of the controversial project as a form of resistance. Now they’ve planted another potential roadblock. Last weekend, Art and Helen Tanderup, who farm north of Neligh, Nebraska, deeded the 1.6-acre plot of native corn to the native inhabitants of the land, the Ponca. Selling the land to the Ponca means that TransCanada will have to negotiate with a new landowner, one that has special legal status as a tribe – a tribe that is opposed to the pipeline. The plot becomes the only tribally owned plot of land on the XL pipeline route in the U.S. “We want to protect this land. We don’t want to see a pipeline go through,” said Larry Wright Jr., the chairman of the Ponca Tribe of Nebraska. “If this adds another layer (of opposition) to that issue, we’re happy to be part of that.” TransCanada officials did not respond to requests for comment on Wednesday. The company has recently been holding meetings with landowners along the pipeline route across Nebraska that was recently approved by the State Public Service Commission.

Industry study claims Initiative 97 would cost Colorado billions; measure’s proponents push back — The Colorado Alliance of Mineral and Royalty Owners released a new study showing that if Initiative 97 is passed by voters, it would cost Coloradans roughly $26 billion in lawsuits, and its president says its passage would put an end to oil and gas development in Colorado. But the measure’s proponents say that’s not the case. “It basically shuts down the oil and gas development in the area,” said CAMRO President Neil Ray. Initiative 97 is a proposed ballot initiative that would prohibit oil and gas developments that aren’t on federal land from operating near occupied buildings less than 2,500 feet away. Ray is a mineral and royalty owner himself who says owners will be probably fight back the initiative if it becomes a law.“Mineral and royalty owners would be denied their private property and wouldn’t be able to develop their private property, which would lead to regulatory takings law suits and that would bankrupt the state,” he said.Grassroots organization Colorado Rising, which drafted the initiative, released a lengthy statement disputing the study and its president’s claims:

South Dakota High Court Blocks Bid to Halt Keystone XL — The South Dakota Supreme Court disappointed an attempt by Native American tribes and state activists to block the Keystone XL pipeline on Wednesday, ruling that the lower court lacked jurisdiction to hear their appeal, The Associated Pressreported.The Cheyenne River Sioux Tribe, Yankton Sioux Tribe and conservation and family agriculture group Dakota Rural Action had appealed a decision by a judge last year to uphold the Public Utilities Commission’s decision to let the controversial pipeline cross the state.Dakota Rural Action attorney Robin Martinez called the decision “disappointing” on Thursday but affirmed that “fight is not over,” The Associated Press reported further.Terry Cunha, the spokesperson for TransCanada Corp., the company behind the pipeline, told The Associated Press in an email that the company was pleased with the court’s decision. TransCanada was in the news just last week when one of its natural gas pipelines exploded in West Virginia.

Bakken oil field barrel differential reaches all-time high – The Bakken shale crude differential in Williston, North Dakota, climbed to its highest recorded level Thursday despite a narrowed Brent-WTI spread, with Clearbrook barrels climbing to an eight-month high. Close to the Bakken oil fields, Williston barrels climbed 15 cents day on day to be assessed at NYMEX light sweet crude calendar-month average (WTI CMA) plus $1.75/b, on the back of a Dakota Access Pipeline trade heard and talked rebid 5 cents lower. This was the highest field barrel differential since S&P Global Platts began assessing Bakken in Williston in April 2014. Williston-origin Bakken for FOB transport on BNSF trains was heard traded at NYMEX WTI CMA plus $1.95/b. In the Midwest, Bakken crude in the Clearbrook, Minnesota, hub jumped 45 cents to be assessed at NYMEX WTI CMA plus $3.30 on a trade heard at that level. That was the highest Clearbrook differential since October 2017, when Midwest refiners had increased crude runs to cover production losses from Gulf Coast refineries damaged in the aftermath of Hurricane Harvey. “It is getting out of hand,” a Bakken source said about the crude’s continued rise. Bakken differentials have been rising amid Brent-WTI spreads remaining wide, making crude grades priced off of WTI more attractive to both domestic and international buyers than their Brent-linked counterparts. Despite a narrowed Brent-WTI spread during the day, Bakken maintained its rally. Platts assessed the front-month spread at $9.07/b, down 38 cents day on day. The spread peaked at $11.15/b last week, the widest in more than three years.

Canada acquires key pipeline link to Washington refineries – The Canadian government is purchasing a vital link in Washington’s oil network – a nearly 70-mile pipeline spur running through Whatcom and Skagit counties that feeds crude oil to four refineries, according to financial-disclosure documents.This is a piece of the much larger acquisition of the Trans Mountain Pipeline – announced May 29 – that runs more than 700 miles from Edmonton, Alberta, to tidewater at Burnaby, British Columbia.The sale by Houston-based Kinder Morgan to the Canadian government is expected to improve the prospects for a $5.4 billion pipeline expansion strongly supported in Alberta but fiercely opposed in British Columbia and Washington state due to the risks of oil spills and the broader climate impacts of boosting production of crude extracted from oil sands. The sale is expected to close in August. The expansion would nearly triple the flow capacity through the Canadian mainline pipeline so that oil could be exported from Burnaby to California and Asia. But there also is an option – noted earlier this year in a Kinder Morgan financial-disclosure document – to more than double the capacity of the small Washington spur line. That would create the potential for exports from Washington, where tankers have a more direct path to the open ocean than those departing from Burnaby. But any move to export oil from an expanded pipeline through Washington would face huge pushback from tribes, environmentalists and their political allies.

Kinder Morgan Pipeline Leak Two Days Before Trudeau Buyout Was 48 Times Larger Than First Reported – Just two days before Canadian Prime Minister Justin Trudeau announced that his government would purchase Kinder Morgan’s faltering and widely opposed Trans Mountain pipeline, British Columbia’s Ministry of Environment said 100 liters of crude oil had leaked at a Kinder Morgan pipeline pump station north of Kamloops – but the company initially refused to confirm the severity of the spill.On Saturday, with its bailout from the Canadian taxpayer confirmed by Trudeau, Kinder Morgan declared after an investigation that, actually, 4,800 liters of crude oil had leaked during the May 27 spill – 48 times more crude than first reported.While the Ministry of Environment said no waterways were affected by the leak, environmentalists and Canadian members of parliament highlighted the leak as a telling example of the dangers pipelines pose to people and the environment and continued denouncing Trudeau’s buyout. .As Common Dreams reported, Trudeau announced late last month that his government would buy the Trans Mountain pipeline for $4.5 billion, a move environmentalists and Indigenous leaders denounced as an act of “immense moral cowardice” that betrayed the prime minister’s rhetorical commitments to bold climate action. Trudeau’s decision has since sparked opposition rallies nationwide, with green groups arguing that the billions of taxpayer money being used to rescue a leak-prone, “climate-destroying” pipeline should be spent on healthcare, education, and a just transition to a sustainable energy system.

First Nations offer to buy equity in pipeline to have say project’s future – After Justin Trudeau’s surprise announcement that the Canadian government would nationalize a contentious pipeline, indigenous protesters have been among the most vocal in their opposition to the Trans Mountain pipeline expansion project, arguing that the project trespasses on their territory and poses a risk to the environment. Protests led by First Nations have amplified public unease of over the mega project – which will triple the flow of bitumen from Alberta to the coastal waters of British Columbia – as the country attempts to balance its fight against climate change with an economy driven largely by the energy industry. But the project may soon find an unlikely group of investors: both the Athabasca Tribal Council and the Athabasca River Métis Council – a consortium of 10 communities – have offered to buy equity in the pipeline.“This is not the indigenous community coming out and saying: ‘We’re pro pipeline.’ We’re pro Trans Mountain. We see the value in it,” said Ron Quintal, president of the Athabasca River Métis. “The only way we’re able to mitigate the environmental impacts is through ownership and having a say in these projects.” The two councils recently met with federal officials, including the infrastructure minister, Amarjeet Sohi, to discuss their proposal. This will not be the first time Canada’s First Nations have invested in the fossil fuel industries that have encroached on their land and disrupted traditional ways of life. Last year, the Fort McKay First Nation and Mikisew Cree First Nation in Alberta purchased 49% of an oil storage facility – a deal worth more than half a billion dollars. Frog Lake Energy Resources Corp, an indigenous-run company, produces 3,000 barrels of oil a day. A large source of tension around Trans Mountain project centres on the idea of unceded lands: few formal treaties were ever signed between British Columbia’s colonial settlers and the indigenous population – whose descendants argue that they retain the right to control any development.

The legal fight to leave the dirtiest fossil fuels in the ground — Tar sands are the dirtiest fossil fuels. These are low-quality heavy tar-like oils that are mined from sand or rock. Much of the mining occurs in Alberta Canada, but it is also mined elsewhere, in lesser quantities. Tar sands are the worst. Not only are they really hard to get out of the ground, requiring enormous amounts of energy; not only are they difficult to transport and to refine; not only are they more polluting than regular oils; they even have a by-product called “petcoke” that’s used in power plants, but is dirtier than regular coal.This stuff is worse than regular oil, worse than coal, worse than anything. Anyone who is serious about climate change cannot agree to mine and burn tar sands. To maintain climate change below critical thresholds, tar sands need to be left in the ground.This fact is what motivated me to testify to the Minnesota Public Utilities Commission last November, to inform my state’s ruling commission about the impact of tar sands on the climate. Canadian energy company Enbridge has petitioned to put a pipeline through my state to carry this dirty tar to refining sites on the coast. The proposed pipeline is called “Line 3.” The pipeline would carry approximately 760,000 barrels per day – the new pipeline would make it easier and cheaper for the oil companies to transport tar sands and consequently, would boost their bottom line. We already move over two million barrels per day through Minnesota in Enbridge pipelines. This new pipeline would encourage them to extract and sell more tar sands. So, how much pollution would this pipeline carry? 170bn kilograms of carbon dioxide each year. The emissions are equal to approximately 50 coal power plants. These are huge numbers, but more importantly, approval of pipelines like this make it more likely that all of the tar sands in Alberta will be extracted. If that happens, global temperatures will increase by approximately 0.65°F (0.36°C). An astonishing number – approximately 3 decades worth of global warming.

Will Petronas’s Stake Finally Make The LNG Canada Export Project A Reality? – Natural gas producers in Western Canada, with their share of U.S. and Eastern Canadian markets threatened by competition from producers in the Marcellus/Utica and other shale plays south of the international border, for years have seen prospective LNG exports to Asian markets as a panacea. But efforts to develop liquefaction “trains” and export terminals in British Columbia failed to advance earlier this decade – for starters, their economics weren’t nearly as favorable as those for U.S. projects like Sabine Pass LNG. Then, by 2016-17, global markets were awash in LNG as new Australian and U.S. liquefaction trains came online, and the BC LNG projects still alive were either delayed further or scrapped. Now, with LNG demand on the upswing and the need for additional LNG capacity in the early-to-mid 2020s apparent, the co-developers of LNG Canada – Shell, PetroChina, Korea Gas and Mitsubishi – have attracted a new and significant investor: Petronas, Malaysia’s state-owned oil and gas company and owner of Progress Energy Canada, which has vast gas reserves in Western Canada. Today, we continue our review of efforts to send natural gas and crude oil to Asian markets with a fresh look at the LNG project and TransCanada’s planned Coastal GasLink pipeline, which will deliver gas to it.

Oil Companies in Alaska Refreeze Melting Permafrost to Keep Drilling – A new industry is taking off in Alaska, as innovators help oil companies compensate for the irony that climate change is making oil exploration harder on the increasingly less frozen permafrost, NPR reported Monday.Ed Yarmak, for example, heads a company called Arctic Foundations that makes metal tubes filled with a refrigerant called thermosyphons. These are then partly buried in permafrost, where they pull heat from the ground.”To be honest, climate change is pretty good business for our company,” Yarmak told NPR. “We’re in the business of making things colder.”Yarmak said he had been selling the tubes to oil companies since the 1970s, but that business has only picked up with global warming, which is moving at double the speed in Alaska as it is in the rest of the country, according to NPR.Josh Kindred, who worked representing oil companies for the Alaska Oil and Gas Association, acknowledged the contradictions of the oil companies’ predicament, victims of a problem their actions helped to cause.”It is ironic, and it’s challenging for a state that is so dependent on resource extraction but is also really feeling the impacts of climate change,” Kindred said. Kindred said Alaska was too reliant on oil revenue to consider stopping operations.But many oil companies are hesitant to admit that climate change is posing problems. Companies NPR reached out to for comment chose not to be interviewed.

Rise in U.S. exports of jet fuel driven by Latin American and Caribbean countries –The United States exported 186,000 barrels per day (b/d) of jet fuel in 2017, the eleventh consecutive year of increasing gross jet fuel exports. Almost two-thirds (62%) of U.S. jet fuel exports went to countries in Latin America and the Caribbean, especially Mexico. Relatively high domestic production and a growing international aviation industry have established the United States as a net exporter of jet fuel for the seventh straight year. The United States exported jet fuel to 54 destinations in 2017, with 22% of these exports going to Mexico. U.S. exports of jet fuel to Mexico increased from 4,000 b/d in 2010 to 40,000 b/d in 2017 because of factors such as the liberalization of Mexico’s energy markets, increased air traffic, and low utilization at Mexico’s refineries. Many Caribbean and Central America countries have increased their imports of U.S. jet fuel because of a lack of sufficient refining capacity to meet domestic jet fuel demand. U.S. refineries operated at record levels during 2017, working to produce enough jet fuel to support the growing export market. Petroleum products are typically exported from U.S. Gulf Coast ports, primarily Houston and New Orleans. About 80% of all U.S. jet fuel exports were shipped from the Gulf Coast in 2017. The East Coast and West Coast regions of the United States remain net importers of jet fuel because of demand in metropolitan areas that host some of the busiest airports in the world. In particular, the West Coast has become increasingly reliant on jet fuel imports from Asian countries because regional consumption has outpaced production.

Venezuela crude oil output careens toward 1 million b/d – Venezuelan crude oil production is on the verge of sinking to 1 million b/d, and factors playing out this month will determine whether that level is reached early next year or within a few months. The Energy Information Administration projects Venezuela will hit 1 million b/d in second-quarter 2019, said analyst Lejla Villar, who develops projections for the monthly Short-Term Energy Outlook. “However, I am eagerly awaiting to see what the actual June production number falls to, which may very well accelerate the decline in production through 2019, pushing up this time line,” she said. “If the worst-case scenario for June production comes true, then we could see Venezuela’s production fall to 1 million b/d sooner.” EIA’s latest STEO report estimated Venezuelan output at 1.43 million b/d for May, down from 1.46 million b/d a month earlier and from 1.98 million b/d in May 2017. The International Energy Agency put May production at 1.36 million b/d and said it could fall to 800,000 b/d or even lower next year. S&P Global Platts estimated the country’s May output at 1.36 million b/d, down from 1.41 million b/d in April, according to a survey of industry officials, analysts and shipping data.

Venezuela Won’t Have Enough Oil To Export By 2019 – On May 21st President Donald Trump signed a new executive order prohibiting certain oil-related transactions with Venezuela. GlobalData, a leading data and analytics company, argues that the new sanctions are symbolic in comparison to the more targeted sanctions previously considered that would limit exports of Venezuelan crude oil to the U.S. Adrian Lara, Oil & Gas Analyst at GlobalData stated: “Crude oil production in Venezuela is practically falling at an average of 10% every quarter and has been since mid-2017. A scenario with oil production in the country losing at least another 500,000 barrels per day by the end of the year is not unrealistic. Having full additional sanctions imposed would certainly send a strong geopolitical message from the U.S. at the risk of generating more instability in the world supply markets.”GlobalData also forecast that Venezuelan crude oil production would fall to around one million barrels per day by the end of 2018. This is a steep decline from the three million barrels per day that Venezuela produced in 2011. Platts reported this week that Venezuela has already warned eight international customers that it wouldn’t be able to meet its crude oil commitments to them in June. Venezuela’s state oil company PDVSA is contractually obligated to supply 1.495 million barrels per day to those customers in June, but only has 694,000 barrels per day available for export. Impacted U.S. oil companies reportedly include Chevron, “Conoco” and Valero. I suspect “Conoco” is really Phillips 66, the refining arm spun out of ConocoPhillips in 2012.Venezuela also reportedly has a severe backlog of crude deliveries at its main terminals, and this could temporarily halt PDVSA’s supply contracts if they are not cleared soon. The company has told some customers it may declare force majeure if they do not accept new delivery terms, including higher-cost and riskier seaborne transfers. Brent crude prices moved higher on the news. But if the GlobalData forecast is correct, then the temporary interruption of Venezuela’s exports may be permanent, as they will be plunging toward zero by the end of the year.

New study examines impacts of fracking on water supplies worldwide — Using hydraulic fracturing to extract oil and natural gas from shale is a common technique used worldwide. Because the technique requires large amounts of water, however, it raises the question of whether it could lead to water shortages or competition with other water uses, especially agriculture. In a new paper in the AGU journal Earth’s Future, Lorenzo Rosa and his colleagues evaluated the impacts of hydraulic fracturing on local availability for food production and other human and environmental needs globally.They found that 30 percent of shale deposits are located in arid regions where aquifers are already being heavily tapped for irrigating crops and 31 percent to 40 percent of shale deposits are in areas where water-stress would emerge or be exacerbated by fracking.The researchers conclude that in such places water management plans would be needed to ensure that fracking would not affect other human and environmental water needs. The map below shows water stress within shale deposits. In water stressed areas, water is consumed at greater rates than the local water supply is replenished. Green, yellow, orange or red pixels represent areas where there are shale deposits and where freshwater is already being used at unsustainable rates. Areas with water stress indexes greater than one are where water consumption for human activities is unsustainable.

Pope Urges Oil Companies to Lead Clean Energy Transition in Unprecedented Vatican Conference – Pope Francis urged the leaders of big oil companies to see the light on climate change at a first-of-its kind conference held at the Vatican with oil executives, investors and Vatican experts, The Guardian reported Saturday.”Civilisation requires energy, but energy use must not destroy civilisation,” the pope said during remarks at the end of the conference, according to The Guardian.The current pope, who has emerged as a leader in the fight against climate change following his groundbreaking 2015 encyclical, urged the companies to lead the transition towards renewable energy and away from fossil fuels.He said they should strive “to be the core of a group of leaders who envision the global energy transition in a way that will take into account all the peoples of the earth, as well as future generations and all species and ecosystems,” The New York Times reported.The pope also spoke with a great sense of urgency about the coming crisis. “There is no time to lose,” he said, according to The New York Times.”Will we turn the corner in time? No one can answer that with certainty,” the pope said. “But with each month that passes, the challenge of energy transition becomes more pressing.” The meeting, held Saturday behind closed doors at the Pontifical Academy of Sciences, included big names in the oil industry like the chairman of Exxon Mobil, the chief executive of BP, the chief executive of the Italian energy company Eni and representatives of Royal Dutch Shell, Norway’s Equinor and Mexico’s Pemex, according to The New York Times and the BBC.

Europe Is Awash With Oil Stored On Ships – While many analysts and agencies have already called the end of the global oil glut, oil held in floating storage in Europe is at an at least 18-month-high, also due to the booming U.S. oil exports that have displaced some of the traditional crude oil routes in the world. Oil in ships around European shores was 12.9 million barrels on average in May, accounting for 26 percent of all global floating storage, and more than Asia-Pacific’s 9.7 million barrels of oil stored, according to estimates by oil analytics company Vortexa, as carried by Reuters. In the two preceding months, March and April, the share of oil in floating storage in Europe accounted for 10 percent of the global storage, compared to 40 percent stored in the Asia-Pacific region. But in May, the volumes of oil held in Europe – including in the Mediterranean – exceeded the oil held off the Asia Pacific coasts for the first time since at least early 2015, according to Vortexa. Consultant Kpler has estimated that there are some 17 million barrels of oil stored on ships in northwest Europe – the highest since at least the beginning of 2016.Soaring U.S. exports have upended some traditional buying patterns, as China, India, and Indonesia have purchased more U.S. crude at the expense of African crude grades from OPEC members Nigeria and Angola, and of some Middle Eastern crudes.On the other hand, U.S. crude oil exports to Europe have also been rising lately, as U.S. oil is increasing in popularity with European refiners, often at the expense of oil cargoes from OPEC nations and Russia.The surge in U.S. production to record levels and the bottlenecks in parts of its biggest producing region, the Permian, have widened the WTI discount to Brent to more than $10 a barrel, up from $5 just two months ago. U.S. exports have also started to eatinto OPEC’s market share on the prized Asian market.This has left Nigerian and Angolan crudes sitting in storage off European coasts. According to Kpler, Nigerian crude oil floating in the North Sea is a particularly unusual occurrence.

Dutch minister proposes faster Groningen output cuts – The Netherland’s Groningen gas field, once the largest onshore gas field in Europe, will produce less than 12 billion cubic meters per year (Bcm/y) by October 2020, the country’s economic affairs minister said Thursday.Eric Wiebes said in a letter to parliament the purchase of nitrogen to mixed with imported gas could lead to a reduction in gas extraction of between 1-1.5 Bcm beginning in October 2020. Construction of a new nitrogen plant in Zuiderbroek is underway. Once this plant is operational, around early 2022, gas production in Groningen could drop by another 7 Bcm, Wiebes said. A reduction of gas exports from Groningen would further enable lower production, bringing forward the target of 12 Bcm/y by two years, Kallanish Energy reports.Following a series of earthquakes and seismic activity in the region due to gas extraction, the government has placed a cap on production of 21.6 Bcm this current gas year. From October, when the next gas year starts, a new cap will be effective. The previous plan was to shut the field by 2030.Wiebes said a draft plan for the next gas year will be published by the end of August. Groningen is operated by NAM – a 50-50 joint venture between Shell and ExxonMobil. The companies are said to be considering compensation claims for an early shutdown of operations.

European Natural Gas War Heats Up As Prices Rise — Europe’s liquefied natural gas imports have surged sixteen percent (from 40.9 bcm in 2016 to 47.4 bcm in 2017) to become the third largest source of gas supply after Russia and Norway. The re-emergence of Europe as a major LNG market came after years of coal and nuclear power plant retirements as well as steep declines in Europe. In global gas markets, Europe looks like a bright star in terms of commercial opportunities over the next few years, as growing demand coincides with rising prices and strong imports. The United States, with four new LNG projects under construction, is in excellent position to seize the opportunity as a supplier in this dynamic market and assert the strategic role as it challenges Russia’s dominance as the region’s top gas supplier. Europe’s energy market is undergoing structural changes that allowed natural gas to gain a larger share in the total energy mix over the last two years. After almost a decade of lackluster demand, market expectations for gas were tempered. Yet, contrary to this bearish outlook, gas consumption across the EU grew by 52 bcm (11%) between 2014 and 2016 and was called “one of the biggest surprises” by Venture Global LNG, Inc. The driving factor behind the recovery was the coal- to- gas move in the power sector that reduced Europe’s coal fired capacity to 156.6 GW in 2017 compared to 190 GW in 2010. National public policies and market forced the retirement of most remaining coal plants by 2030. As Europe’s need for gas increased, production from the North Sea and Groningen field in the Netherlands has been steadily declining. Groningen’s output, in particular, was slashed from 45 bcm in 2015 to 12 bcm in 2017. Dutch regulators expect to completely shut down Groningen production by 2030. This in turn will create a significant supply gap within the European gas market. As Europe’s gas demand grew in 2017 it turned first and foremost to Russia. Despite concerns over Russian dominance over supply, its export of “blue fuel” to Europe has grown to reach a record high 193.9 Bcf in 2017 – eight percent higher than its previous record set in 2016.

European natural gas injections show strength after record drawdown– Platts video – Despite European natural gas stocks being drawn down to record low levels at the end of the past winter and concern over storage economics this summer, injections have been strong, with stocks almost back to the same level as in 2017. Stuart Elliott, senior writer for European gas at S&P Global Platts, looks at the drivers of the European storage recovery and what to expect ahead of the coming winter.