Written by rjs, MarketWatch 666
Here are some selected new articles from the week ended 30 June 2018.
This article is a feature every Monday evening on GEI.
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Record highs for oil refining, crude and distillate exports; largest US crude supply drop since Sept 2016, distillate supplies at a 13 year low, et al
Oil prices rose another 8% this week, on top of last Friday’s near 5% jump, and are now pushing $75 a barrel, as oil production disruptions in Canada and Libya along with a bellicose US policy on Iran portended that tighter oil supplies were in the offing, despite OPEC pledges to pump more crude….after closing last week 5.8% higher at $68.58 a barrel, mostly on the Friday news of an OPEC agreement to modestly increase output, contracts for US light sweet crude for August delivery fell 50 cents to $68.08 a barrel on Monday, as oil traders digested the possible outcomes of the OPEC deal and worried about deepening US trade wars…however, US crude prices surged $2.45, or 3.6%, to $70.53 a barrel on Tuesday, after the State Department threatened to slap sanctions on any country, friend or foe, that didn’t cut their oil imports from Iran to “zero” by November…oil prices then continued rising from that level the rest of the week, hitting new 3-and-a-half year highs on each day, as an outage in Canada disrupted oil flow to the US and oil traders bet that the Saudis would not be able to make up the production lost from US sanctions on Iran and Venezuela…the largest move in that rally came on Wednesday, when oil prices rose $2.23, or 3%, to 72.76 a barrel, after the EIA reported the largest weekly drop in US crude supplies since September 2016…U.S. crude then hit another a three-and-a-half year high on Thursday, rising 69 cents to $73.45 a barrel, on continued concerns that Trump’s threats against oil importers could cause a large drop in crude exports from Iran…Friday fretting was much of the same, with concerns linked to Venezuela, Libya and Canada, as well as Iranian exports, as oil rose another 70 cents to $74.15 a barrel to finish the week with a gain of just over 8%, a gain of almost 11% for the month, an increase of over 14% for the second quarter, and an increase of almost 23% for the first half of 2018….
Natural gas prices, on the other hand, ended both the week and the month lower, as higher production offset the impacts of a looming heat wave and an addition to storage that fell short of expectations…US natural gas prices for August rose a penny on Tuesday and 5 cents on Wednesday, and then pushed above $3 per mmBTU on Thursday morning before the natural gas storage report cut prices back to $2.94 per mmBTU at the close…August gas futures then settled 1.6 cents lower on Friday to close the week at $2.924 per mmBTU, down 2.1 cents from the previous Friday’s close…the natural gas storage report for week ending June 22nd from the EIA indicated that natural gas in storage in the US rose by 66 billion cubic feet to 2,074 billion cubic feet over the week, which left our gas supplies 735 billion cubic feet, or 26.2% below the 2,809 billion cubic feet that were in storage on June 23rd of last year, and 501 billion cubic feet, or 19.5% below the five-year average of 2,503 billion cubic feet of natural gas that are typically in storage after the third week of June…the consensus forecast was for an addition of 71 billion cubic feet to gas in underground storage, but this report also revised the prior week’s addition of gas to storage 4 billion cubic feet higher, so the net at the end of the week was fairly close to consensus, and also close to the average 72 billion cubic foot weekly surplus of natural gas that is typically added to storage at this time of year…however, since current natural gas supplies are still 1,724 billion cubic feet below the 3,790 billion cubic feet we had stored after the first week of November last year, this week’s 66 billion cubic foot addition to supplies is well short of the 90 billion cubic feet per week we’ll need to see weekly over the next 19 weeks to get our supplies back to a normal level before the next heating season’s withdrawals begin…
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 22nd, showed that due to a record level of domestic oil refining and record oil exports, we had to pull oil out of our commercial crude supplies for the eleventh time in the past twenty-two weeks….our imports of crude oil rose by an average of 114,000 barrels per day to an average of 8,356,000 barrels per day during the week, after rising by 143,000 barrels per day over the prior week, while our exports of crude oil rose by an average of 626,000 barrels per day to a record average of 3,000,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 5,356,000 barrels of per day during the week ending June 22nd, 512,000 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 was reported as unchanged at 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 16,256,000 barrels per day during the reporting week…
At the same time, US oil refineries were using a record 17,816,000 barrels of crude per day during the week ending June 22nd, 115,000 barrels per day more than they used during the prior week, while at the same time 1,413,000 barrels of oil per day were reportedly being pulled out of oil storage in the US….hence, 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 147,000 fewer barrels per day than what refineries reported they used during the week…to account for that disparity, the EIA needed to insert a (-147,000) 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 8,261,000 barrels per day, which was 2.4% more than the 8,057,000 barrel per day average we imported over the same four-week period last year….the 1,413,000 barrel per day decrease in our total crude inventories came entirely out of our commercially available stocks of crude oil, as the amount of oil in our Strategic Petroleum Reserve was unchanged….this week’s crude oil production was reported as unchanged despite the report of a 100,000 barrel per day increase in oil output from all the wells in the lower 48 states and a 38,000 barrel per day decrease in output from Alaska, because the EIA has recently decided to round the weekly oil production estimates to the nearest 100,000 barrels per day, to more closely reflect their inability to accurately model oil output from all the wells in the lower 48 states, and there was no change in the rounded total…the unrounded US crude oil production for the week ending June 23 2017 was reported at 9,250,000 barrels per day, so this week’s figure is roughly 17.8% above that of a year ago, 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…
Meanwhile, US oil refineries were operating at 97.5% of their capacity in using 17,816,000 barrels of crude per day during the week ending June 22nd, the highest refinery utilization rate since our refineries operated at 97.6% of capacity during the week ending June 1st 2001…the 17,816,000 barrels of oil that were refined this week were the most barrels refined on record, topping the 17,725,000 barrels per day that were being refined during the last full week of August 2017….this week’s refinery throughput was also 5.5% higher than the 16,890,000 barrels of crude per day that were being processed during the week ending June 23rd a year ago, when US refineries were operating at 92.5% of capacity….
With the amount of oil that we’re refining now at a new record high, we’ll take a look at a graph of the recent history of that metric for some perspective…
The graph above of US refinery throughput came from the package of oil graphs that John Kemp, senior energy analyst and columnist with Reuters, emailed out on Wednesday, which is also available as a pdf here; it shows US refinery throughput in thousands of barrels per day by “day of the year” for the past ten years, with the past ten year range of our refinery throughput for any given date shown as a light blue shaded area, and the median of our refinery throughput, 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 oil refined for each week in 2017 traced by a yellow line, with our year to date oil refining for each week of 2018 represented by the red graph…you can clearly see that except for the disruptions to refining caused by last year’s hurricanes, 2017’s refining in yellow had been at the top of the historical range almost all year, and that the pace of refining in 2018 in red has generally been topping that, except for in late April and May…you can also see that the summer is usually when refiners see their seasonal highs, so although this peak in June was earlier than we might have expected, the trend for US refining has been higher, and new records sometime this summer were probably to be expected..
With the record amount of oil being refined this week, gasoline output from our refineries was a bit higher, rising by 43,000 barrels per day to 10,142,000 barrels per day during the week ending June 22nd, after our refineries’ gasoline output had decreased by 352,000 barrels per day during the week ending June 15th....hence, even with this week’s increase, our gasoline production during the week was 1.9% below the 10,334,000 barrels of gasoline that were being produced daily during the week ending June 23rd of last year…at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 72,000 barrels per day to 5,396,000 barrels per day, after rising by 357,000 barrels per day to a near record high the prior week…as a result, this week’s distillates production was still 2.9% higher than the 5,244,000 barrels of distillates per day than were being produced during the week ending June 23rd, 2017…
With the increase in our gasoline production, our supply of gasoline in storage at the end of the weekrose by 1,156,000 barrels to 241,196,000 barrels by June 22nd, the seventh increase in 16 weeks, but the 23rd increase in 33 weeks, as gasoline inventories, as usual, were being built up over the winter months….that increase was less than last week’s increase of 3,277,000 barrels because the amount of gasoline supplied to US markets rose by 405,000 barrels per day to 9,731,000 barrels per day, while our imports of gasoline rose by 138,000 barrels per day to 988,000 barrels per day, and our exports of gasoline rose by 10,000 barrels per day to 613,000 barrels per day….after this week’s increase, our gasoline inventories finished the week at a seasonal high for this time of year, but just fractionally higher than last June 23rd’s level of 240,972,000 barrels, even as they are now almost 11.6% above the 10 year average of our gasoline supplies for this time of the year…
Meanwhile, with this week’s decrease in distillates production, our supplies of distillate fuels ended the week little changed, increasing by just 15,000 barrels to 117,423,000 barrels during the week ending June 22nd…that was as our exports of distillates rose by 532,000 barrels per day to a record high of 1,836,000 barrels per day, while our imports of distillates rose by 5,000 barrels per day to 54,000 barrels per day and while the amount of distillates supplied to US markets, a proxy for our domestic consumption, fell by 213,000 barrels per day to 3,612,000 barrels per day, after decreasing by 579,000 barrels per day the prior week…since this week’s small inventory increase comes after our distillate supplies had shrunk by 14,452,000 barrels over the six weeks to May 18th, our distillate supplies for the week ending June 22nd are still 22.9% below the 152,272,000 barrels that we had stored on June 23rd, 2017, and roughly 16% lower than the 10 year average of distillates stocks for this time of the year…
Since our distillate supplies have now slipped to a 13 year low for this time of year, we’ll include a graph showing how they got here
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 running 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 at the end of each week in 2017 traced weekly by a yellow line, with our year to date distillates supplies for each week of 2018 traced in red…notice within 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, mostly because we have been exporting our distillates at a record pace…thus we come to June 22nd with our distillate supplies now at a 13 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 at a record high at the same time our refineries were using oil at a record pace, our commercial supplies of crude oil decreased for the 13th time in 2018 and for the 34th time in the past year, as our commercial crude supplies fell by 9,891,000 barrels during the week, from 426,527,000 barrels on June 15th to 416,636,000 barrels on June 22nd, the largest drop in our crude supplies since September 2nd 2016…thus, after falling most of the past year, our oil inventories as of June 22nd were 18.2% below the 509,213,000 barrels of oil we had stored on June 23rd of 2017, 16.0% below the 495,941,000 barrels of oil that we had in storage on June 24th of 2016, and 3.8% below the 433,223,000 barrels of oil we had in storage on June 26th 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…
since our record level of crude oil exports have the major reason for our falling crude supplies, and since this week saw the previous record for oil exports beat by nearly 17%, we’ll include here a graph of those oil exports over the past 22 months..
The Graph above also came from the weekly package of oil graphs that John Kemp of Reuters emailed out on Wednesday, which is also accessible online as a pdf here, and it shows weekly US crude oil exports in thousands of barrels per day from September 2016 to the current week, and also highlights the exact amount of our crude exports in thousands of barrels per day over a few select dates going back to September 1st 2017, the week when our exports had been choked off because Gulf Coast ports were shut down by Hurricane Harvey and fell to 153,000 barrels per day…as you can see, our oil exports had only topped a million barrels per day a few times prior to that date…however, after the price of US crude fell to a 10% discount to the comparable international grade in the wake of the hurricanes, US crude suppliers began to sell as much oil overseas as they could, and as a result our oil exports have stayed above a million barrels per day since, and with those elevated exports, our crude oil supplies have also been falling since…as we’ve noted several times over the past couple of months, the spread between the price of North Sea Brent, the international benchmark, and that of the similar US grade, has widened to as much as $10 or $11 a barrel, so we expected that US oil traders would sell as much US crude into international markets this summer as our port capacity would allow, all the while pulling down large windfall profits even after paying the roughly $2 a barrel trans oceanic transportation costs…while that spread has narrowed to below $6 this week on the Canadian problems, oil being exported in June and through July was more than likely contracted for during that period of the wider price spreads…
To compare this year’s drop in our oil supplies with what has happened in previous years, we’ll include one more graph from that Kemp package..
Again, this graph also came from John Kemp’s weekly package of oil graphs, which is accessible online as a pdf here…as the legend tells us, the bars on the graph show the change in US crude inventories between December 31st and June 22 for each of the last 11 years, with bars for increases above the 0 level, and the lone bar for this year’s decrease showing up as a bar below the 0 level…typically, oil inventories are built up during the first five months of the year, then are drawn down as refineries run flat out to supply additional gasoline during the summer driving season…that normal early year build up of our oil supplies is what the first ten bars on that graph show us, which John identifies in his header as an average 37 million barrels of oil added during this period over the past ten years…this year, however, our oil supplies have fallen by 6.4 million barrels during these first six months, as instead of adding oil to storage, we have been pulleing oil out of our supplies and exporting it…since we built up our oil supplies to abnormal levels during the periods of low prices in 2015 and 2016 as you can see on the graph, our crude supplies are not becoming critically low at this point, but they are now below the 5 year average of our supplies for this time of year…
This Week’s Rig Count
US drilling activity decreased for the third week in a row, after 11 consecutive increases, and was hence down for the 4th time in the last 19 weeks during the week ending June 29th, as both drilling for natural gas and drilling for oil slowed simultaneously for the 2nd week in a row…Baker Hughes reported that the total count of active rotary rigs running in the US decreased by 5 rigs to 1047 rigs over the week ending on Friday, which still left us with 107 more rigs than the 940 rigs that were in use as of the June 30th report of 2017, while that count was down from the recent high of 1929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began their attempt to flood the global oil market…
The count of rigs drilling for oil was down by 4 rigs to 858 rigs this week, which was still 102 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 was down by 1 rig to 187 rigs this week, which was only 3 more gas rigs than the 184 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 was unchanged at 18 rigs this week, which was 3 fewer than the 21 platforms that were deployed in the Gulf of Mexico a year ago…however, the platform that had been idled offshore from Alaska last week was started back up this week, so the total US offshore count of 19 rigs is now down by 2 rigs from the total 21 offshore rigs that were drilling a year ago, when there was no rig drilling off of the Alaskan coast…in addition, the two platforms on inland lakes in southern Louisiana that had been shut down last week were restarted this week, so now there are four ‘inland waters” rigs operating again, the same number of ‘inland waters’ rigs that were operating going into the same weekend a year ago…
The count of active horizontal drilling rigs was down again, for the 3rd week running, decreasing by 4 rigs to 926 horizontal rigs this week, which was still 134 more horizontal rigs than the 792 horizontal rigs that were in use in the US on June 30th 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 4 rigs to 56 vertical rigs this week, which was also down from the 77 vertical rigs that were in use during the same week of last year…on the other hand, the directional rig count increased by 3 rigs to 65 directional rigs this week, which was still down from the 71 directional rigs that were operating on June 30th 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 29th, the second column shows the change in the number of working rigs between last week’s count (June 22nd) and this week’s (June 29th) count, the third column shows last week’s June 22nd 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 30th of June, 2017…
Oil drilling decreased by 2 rigs in both the Eagle Ford of south Texas and the Williston aka Bakken of North Dakota, and while it increased by 2 rigs in Oklahoma’s Cana Woodford, it was also down by two rigs in basins not itemized separately by Baker Hughes…the pace of natural gas drilling, meanwhile, was unchanged in the Utica and the Marcellus, while it was down by 3 rigs in the Haynesville, and up by 2 rigs in those unnamed basins not tracked separately by Baker Hughes…of the states not listed above, Alabama saw both of the rigs that had been operating in the state shut down this week, and now they have none, down from the 3 rigs running in Alabama a year ago, while Mississippi also saw two rigs shut down, and now have just 2 rigs operating in the state, also down from the 3 rigs running in Mississippi a year ago…
While we’ve been expecting that natural gas well drilling would slow with gas prices below $3 per mmBTU, we certainly didn’t anticipate that oil drilling would also be curtailed, especially in light of the price rally we’ve seen over the past year…yet here we are at the end of June with oil prices above $70 a barrel for the second time this year, and the oil rig count is now at the lowest it’s been in six weeks…when we looked at the Dallas Fed survey of oil executives at the end of March this year, we saw that 88% of the oil executives polled said they could be profitable at prices under $66 a barrel, which is roughly the average price we’ve seen throughout the 2nd quarter of this year….even allowing for 3 to 4 months lead time before drilling starts, we’d be talking oil prices that were consistently over $60 a barrel when today’s rigs were contracted for, certainly more profitable than the $44 to $54 barrel oil we saw last year, when oil drillers were increasing their rig deployment by roughly 20%…so why this pullback has arrived at this time is anyone’s guess, especially since the backlog of incomplete wells has nearly stabilized in all areas except the Permian..
Ohio bill would relax wind setbacks – and clean energy standards – The bill drew criticism in latest hearings to change Ohio’s clean energy standards after they resumed last year. Ohio lawmakers are considering a bill that would relax the state’s strict wind turbine setbacks rules but again weaken renewable and energy efficiency standards. The Ohio Senate Energy and Natural Resources Committee is scheduled Wednesday to discuss House Bill 114, which threatens to roll back the state’s on-again, off-again clean energy standards, which resumed 18 months ago after a 2014 law suspended them for two years. The bill has drawn criticism from both wind energy opponents and clean energy advocates. It stops short of making renewable energy standards purely voluntary, as in the Ohio House version passed last year. Instead, it would set the top renewable energy standard target at 8.5 percent in 2022, down from the current law’s requirement of 12.5 percent in 2026. The top energy efficiency target would fall from 22.2 percent to 17.2 percent, with more opt-outs and profits for utilities. An attempted trade-off in the bill would also loosen the state’s strict restrictions on wind turbine placement similar to reforms proposed in a stand-alone bill introduced several months ago by Ohio Sen. Matt Dolan (R-Chagrin Falls). HB 114 is the latest in an ongoing, six-year saga of efforts to weaken Ohio’s clean energy standards, all of which “make it difficult to plan for long-term markets and investments,” said Becky Campbell, manager of regulatory and public affairs for First Solar. In her view, “HB 114 represents a step backward,” compared to other states.
Ohio approves 1050 MW, gas-fired power plant in Cadiz – The Ohio Power Siting Board has approved a $900 million natural gas-fired power plant in Harrison County in the heart of the state’s Utica Shale play, Kallanish Energy reports. Texas-based EmberClear Corp and its subsidiary, Harrison Power LLC, plan to construct a 1,050-megawatt, combined-cycle electric generation facility in Cadiz. Construction would begin in October and commercial service would begin by June 2021. The plant would be located on 90 acres in the Harrison County Industrial Park. The plant would be connected by pipeline to MarkWest’s Cadiz natural gas processing plant and to Energy Transfer’s Ohio River pipeline system. The electricity generated would be moved to American Electric Power’s transmission system. The plant would produce enough electricity to power 1 million homes. The project would create 500 construction jobs for about three years and 30 permanent jobs. It is among a dozen gas-fired power plants being developed in Ohio.
Hess unloads Utica shale to fund work in Guyana, Bakken (UPI) — U.S. energy company Hess Corp. said it would use the $400 million from the sale of assets in the Utica shale basin to fund work in Guyana and North Dakota.Hess said Friday it reached an agreement with Ascent Resources to sell off its joint venture interests in the Utica shale basin in eastern Ohio. The divestment of 39,000 net acres is expected to produce an average of 14,000 barrels of oil equivalent per day this year, of which 70 percent is natural gas. CEO John Hess said the funds would support growth across other segments of the company’s portfolio.”Proceeds from this transaction will be used to invest in our higher return growth opportunities in Guyana and the Bakken and to fund the company’s previously announced share repurchase program,” he said in a statement.Exxon Mobil Corp. and partner Hess announced their eighth oil discovery off the coast of Guyana earlier last week. Analysis sent from consultant group Wood Mackenzie to UPI in response to questions found reservoirs offshore Guyana are transformative, even for big companies like Exxon and Hess. Dubbed Longtail, the latest discovery was made near the giant Liza field, which could be producing about 500,000 barrels per day by late 2023. Hess estimated it would cost at least $3.2 billion to fully develop the broader offshore Liza field. North Dakota reported an average crude oil production rate for April, the last full month for which data are available, at 1.22 million barrels per day, just shy of the all-time high from December 2014 of 1.23 million barrels per day. More than 90 percent of that came from the Bakken shale formation, which set a record in April for gas production. Hess reported a net loss of $106 million in the first quarter, compared with a loss of $324 million in the same period in 2017. The company attributed the improvement to higher crude oil prices and lower operating costs.
​Methane-producing microbial communities found in fracking wells – The Ohio State University News – Deep in the rocky earth, in the liquid-filled cracks created by fracking, lives a community of highly interactive microbes – one that could at once have serious implications for energy companies, human health and scientists investigating the potential for life on Mars.New research has uncovered the genetic details of microbes found in fracking wells. Not only do a wide array of bacteria and viruses thrive in these crevices created by hydraulic fracturing – they also have the power to produce methane, according to a study led by scientists at The Ohio State University and published in the journal Proceedings of the National Academy of Sciences. That means it’s possible that the tiny life forms could create more energy – and from a different source – than the fracking companies are going after in the first place.On the other hand, the microbes found in samples from wells in Ohio, West Virginia and Pennsylvania could point to potential problems from an industry standpoint – they could prove corrosive, toxic or otherwise problematic, said the study’s lead author, Kelly Wrighton, an assistant professor of microbiology at Ohio State.“Energy companies spend a lot of money and resources trying to get rid of life in these systems,” she said. . Chemicals, stabilizers and water injected into the wells are undoubtedly contributing to the microbial diversity within them, the researchers said. This was the first study to look at microbes from multiple sites in a controlled environment, and presented a rare scientific opportunity, said study co-author Michael Wilkins, an assistant professor of earth sciences at Ohio State.
Marcellus, Utica Shale Plays Account for 41 Percent of US Natural Gas Output – – The law firm of Babst Calland released its annual energy industry report: The 2018 Babst Calland Report – Appalachian Basin Oil & Gas Industry: Forging Ahead Despite Obstacles; Legal and Regulatory Perspective for Producers and Midstream Operators. This annual review of shale gas development activity in the Appalachian Basin acknowledges an ongoing rebound despite obstacles presented by regulatory agencies, the courts, activists, and the market. According to the U.S. Energy Information Administration’s May 2018 report, the Appalachian Marcellus and Utica shale plays account for more than 40 percent of U.S. natural gas output, compared to only three percent a decade ago. Since then, the Appalachian Basin has become recognized in the U.S. and around the world as a major source of natural gas and natural gas liquids. The industry has been forging ahead amidst relatively low natural gas prices, infrastructure building, acreage rationalization and drilling plans that align with business expectations. The policy landscape continues to evolve with ever-changing federal and state environmental and safety regulations and tax structures along with a patchwork of local government requirements across the multi-state region. Joseph K. Reinhart, shareholder and co-chair of Babst Calland’s Energy and Natural Resources Group, said, “This Report provides perspective on the challenges and opportunities of a shale gas industry in the Appalachian Basin that continues to enjoy a modest rebound. While more business-friendly policies and procedures are emanating from Washington, D.C., threats of trade wars are raising concerns about the U.S. energy industry’s ability to fully capitalize on planned exports to foreign markets.” The 84-page Report contains five sections, highlighted below, each addressing key challenges for oil and gas producers and midstream operators.
CNX Sees Stacked Pay Well Pads as Appalachia’s Next ‘Basin Disruptor’ – The super-sized well pads targeting multiple horizons that CNX Resources Corp. plans to increasingly develop in the coming years will “disrupt” the Appalachian Basin, a company executive said this month at an industry conference in Pittsburgh. In recent years, the company has been focused on building its Utica Shale program in Ohio and Pennsylvania, while the Marcellus Shale has anchored sales volumes. But lately, CNX management has been talking about the “stacked pay factory” it envisions for the future. In particular, CNX has discussed how well pads that target both the Marcellus and Utica, or even the Upper Devonian shales and the Point Pleasant formation in places like southwest Pennsylvania, may redefine field economics and its priorities. While many operators have been promoting Appalachia’s stacked pay potential for years, few have ramped into full development and consistently drilled pads with multiple wells targeting the basin’s various unconventional resource plays. Calling it “key to the southwest Pennsylvania strategy and economics,” COO Tim Dugan told a crowd at Hart Energy’s Dug East Conference and Exhibition that among the benefits of stacked pay development is the ability to blend wet and dry gas to reduce processing costs and enhance returns. “The dry volumes from the Utica, blended with the damp Marcellus, allows us to avoid uneconomic processing of the damp Marcellus gas,” Dugan said. “One Utica well will blend down three to four Marcellus wells, and it’s all within the same gathering system, much more economic than separate wet and dry systems.” The company is applying completion design and spacing lessons from its Utica program in Monroe County, OH, and other results from newer wells in Pennsylvania as it continues to delineate the deep, dry Utica core in the southwest part of the state.
Appalachian producers finally fulfilled: Pipelines a comin’ — It finally happens by 2022: The Appalachian Basin, whose Marcellus and Utica Shale producers have been begging for more pipeline capacity to get their product to market for years, will get their wish.However, as is the case when trying to match production with takeaway capacity, pipeline owners will offer more capacity than producers are producing – at least for a period of time.“By the end of 2022, the Northeast will have experienced 71% growth in takeaway capacity – 17.3 billion cubic feet per day (Bcf/d) increase,” according to Glenn Koch, vice president, Engineering and Construction, for pipeline giant Williams.Speaking as part of a pipeline development panel during Day Two of the Northeast U.S. Petrochemical Construction conference last week in Pittsburgh, Koch said despite the mind-boggling production leap in the Northeast, new capacity and regional demand for natural gas and natural gas liquids will increase over the same timeframe by 18.2 Bcf/d.The conference was presented for the third consecutive year by Petrochemical Update. Kallanish Energy was in attendance.Production of natural gas liquids, NGLs, will jump by 57% by 2022, to 840,000 barrels per day, from 535,000 BPD, Koch projects.Another pipeline panelist, Doug Scott, projects manager for Shell Pipeline, said the Falcon Pipeline, a 97-mile, primarily 12-inch line that will connect three major ethane source points: Houston, Pa., Scio, Ohio and Cadiz, Ohio, in the rich gas portions of the Marcellus and Utica shale plays, to Shell Polymers under-construction ethane cracker in Monaca, Beaver County, Pa.Scott said the ethane provider line in on time and, provided all needed regulatory permits are secured, right-of-way preparation will start in the winter of 2018-19, with mainline construction next spring.
Still Searching for New York Water Permit, Constitution Pipeline Delays Completion Until 2020 — New York state’s denial of a Clean Water Act (CWA) permit for the proposed Constitution Pipeline has killed any chance of the project meeting it’s scheduled Dec. 2, 2018 construction deadline, the company said in a filing at FERC Monday.Constitution Pipeline Co. LLC asked for an extension until Dec. 2, 2020 for construction of the project.Constitution filed at the Federal Energy Regulatory Commission for its project five years ago, and received a FERC certificate authorizing the project in 2014. The 125-mile pipeline would carry Marcellus Shale gas from Susquehanna County, PA, interconnecting with the Iroquois Gas Transmission and Tennessee Gas Pipeline (TGP) systems in Schoharie County, NY. Besides Williams, the project is backed by Cabot Oil & Gas Corp., Piedmont Natural Gas Co. Inc. and WGL Holdings Inc. The project’s sponsors have battled the New York State Department of Environmental Conservation (DEC) since 2016, when after nearly three years of regulatory review the agency denied the pipeline’s application for a section 401 water quality certificate (WQC) required under the CWA. Eight weeks ago, the U.S. Supreme Court denied a petition filed by Constitution to challenge New York’s regulatory authority and let stand an appeals court ruling that upheld the state’s decision to deny the project a WQC.
ETP investigating pipelines for possible leak in Philadelphia area (Reuters) – Energy Transfer Partners LP is investigating one of its Philadelphia-area product pipelines after gasoline was discovered last week in a nearby creek, ETP said on Tuesday. ETP on Friday shut the 12-inch pipeline, in addition to an eight-inch pipeline in the area, as a precaution. The lines help carry refined products from the region’s refineries to New York Harbor and Western Pennsylvania. The company reopened the eight-inch line on Monday, but the larger line remained shut. “We have determined that the source of the petroleum products identified in the area is not our 8-inch line,” Lisa Dillinger, an ETP spokeswoman, said in an email to Reuters. “The integrity of that line was verified and has been returned to service.” The investigation has shifted to the 12-inch line, she added. Deliveries from Point Breeze in Philadelphia to Montello, Pennsylvania, may be affected, the company said in a customer notice seen by Reuters. The Pennsylvania Department of Environmental Protection issued an emergency permit to ETP to excavate ground around the lines in the area, a DEP spokesman said on Monday. The Pennsylvania Public Utility Commission is investigating the source of the leak, said Nils Hagen-Frederiksen, a spokesman for the Pennsylvania Public Utility Commission.
As Trump Doubles Down on Coal, West Virginia Lawmakers Are Eyeing Natural Gas; Massive storage and trading hub could be on state’s horizon if Manchin and Capito get their way — As President Donald Trump readies a strategy to bail out coal and nuclear power plants in part to help reinvigorate Appalachia’s struggling coal industry, West Virginia lawmakers are working to up the state’s participation in the natural gas business.Their effort to clear a path for the federal government’s financial participation in a massive storage and trading hub for liquids extracted from natural gas could bring more than 100,000 jobs to the state, advocates say. Those liquids are used as feedstock for plastic manufacturing, so it could also turn the state into a major chemical and industrial center as manufacturers look for a steady supply of low-cost raw materials.To achieve that, the lawmakers have launched a series of bills and administration lobbying to protect a Department of Energy loan guarantee program primed for the chopping block by conservatives who want to get the federal government out of the energy financing game. But there’s no small irony in the approach: Such a hub is likely to bolster an industry that has been a source of woe for West Virginia coal miners. But jobs are jobs, and for West Virginia, natural gas would represent a new chapter in its storied energy resource production history. “When natural gas development started, there was a lot of competition [with] coal. But you know they are both energy resources,” said Republican Sen. Shelley Moore Capito. “We know how to do energy in our state. And natural gas is more versatile than coal obviously, so all those rivalries have gone by the wayside.”The proposed $3.3 billion Appalachian Storage and Trading Hub would centralize the burgeoning natural gas liquid extraction industry in the Utica and Marcellus shale formations. A network of pipelines extending into southeastern Ohio and Pennsylvania would lead to a central storage center at a to-be-determined location in the four-state area.
$83 Billion West Virginia Petrochemical Deal with China on Skids Due to Trade War, Corruption Probe – Steve Horn – Last November, China and West Virginia signed an $83.7 billion dollar, 20-year agreement to build a massive petrochemical hub in the state but that deal may be on hiatus in the midst of a de facto trade war spurred by President Donald Trump and a corruption investigation unfolding in the Mountain State. The deal would be worth more than the total gross domestic product of West Virginia, which was $76.8 billion in 2017. China’s sizable investment would create a sprawling petrochemical center in West Virginia, focused on storing and refining natural gas obtained via hydraulic fracturing (“fracking”) in the Marcellus Shale. Full details are sealed in a yet-to-be-released Memorandum of Understanding (MOU), which was inked during a trade mission attended by Trump and Chinese President Xi Jinping last fall in Beijing, China. While the Chinese side has cited the billions in trade tariffs imposed by Trump as the impetus for at least temporarily stepping away from the deal, in West Virginia an ongoing state- and federal-level official corruption investigation involving individuals who were part of the MOU signing has also slowed progress. Some of those individuals were named in a February investigation DeSmog published on the petrochemical hub. In total, China had pledged to invest $250 billion in the U.S. market at the November summit. Several fossil fuel industry executives attended the Chinese trade mission, including the CEOs of liquefied natural gas (LNG) exporting companies Cheniere, Delfin, and Texas LNG. The first domino to fall in the investigation surrounding the MOU was Woody Thrasher, West Virginia’s Secretary of Commerce. As the main regulator and promoter of business in the state, Thrasher was tasked by Governor Jim Justice with oversight of the China-West Virginia deal. (Thrasher is a former Democrat with a business background who converted to a Republican at an August 2017 Trump rally.) However, Thrasher was forced to resign on June 14 at the governor’s request for reported mishandling and misreporting of money for a state flood recovery program. But these incriminating details only came to light as a result of a broader investigation by Justice’s office, when it discovered what it considered ethically dubious activities, centering around self-dealing, related to the MOU, according to the publication MetroNews.
Department of Energy Publishes Natural Gas Liquids Primer – Today, the U.S. Department of Energy (DOE) published the 2018 Natural Gas Liquids (NGLs) primer that highlights the resource potential of NGLs, with a focus on the Appalachian region. This publication provides an important update of a previous version from 2017, reporting even larger projections for ethane production from the Marcellus and Utica shale plays than previously estimated. The 2018 primer includes new data from the reference case for the U.S. Energy Information Administration’s (EIA) 2018 Annual Energy Outlook as well as forecasts from a recent EIA Short-term Energy Outlook. The new data includes updated information regarding infrastructure developments in the Appalachian region, and a new section identifying research and development opportunities related to natural gas and NGLs production, conversion, and storage. This primer shows that the Appalachian region has experienced near-exponential growth in natural gas production, and that production is expected to increase for decades to come. EIA now projects that natural gas production in the East region, where the Appalachian Basin is the principal contributor, will quadruple from 2013 to 2050. Natural gas produced in Appalachia contains valuable resources in the form of NGLs, including ethane and propane. The region is endowed with significant NGL resources projected to be economically recoverable over the next three decades. Specifically, Appalachian NGLs production is projected to increase over 700 percent from 2013 to 2023. To access the primer in full click here.
America’s “Shale Crescent” Is Enjoying A Permian-Like Energy Boom Of Its Own –The energy segment of the U.S. news media has dedicated a lot of time in recent months to discussing the current boom in oil and natural gas production, exports and consumption, and the benefits the country derives from these crucial natural energy resources. All too often, though, we completely miss the third leg of this petroleum-based stool, which is our equally amazing abundance of natural gas liquids (NGLs) and the similar boom taking place in that segment of the industry.A new report published yesterday by the U.S. Department of Energy (DOE) puts the scale of this boom in somewhat amazing detail. But before we get into those details, let’s review what NGLs – the component petroleum liquids that are separated out of most natural gas production streams – actually are. Put simply, there are five such liquid components contained in any typical “wet” natural gas stream: Ethane, Propane, Normal Butane, Iso-Butane and Natural GasolineThese NGLs are separated out at natural gas processing plants and then moved to various markets centers where they are applied to a broad variety of energy and manufacturing uses, including:
- Plastics
- Synthetic Rubber
- Home heating
- Cooking
- Fertilizers
This list could go on and on. Once the liquids are removed from a gas stream, what remains is a pure Methane stream, and that is the “natural gas” that is commonly used for power generation and home heating in communities that have local pipeline distribution infrastructure.As the DOE report unsurprisingly details, the major driver behind the current boom in natural gas and NGLs is the mammoth Marcellus Shale resource located across much of Pennsylvania, West Virginia and Ohio. (The Marcellus also lies underneath a broad swath of Southwestern New York, but the Cuomo Administration continues to prevent its citizens from sharing the massive economic wealth and lower utility bills this resource is bringing to these other states.)
Court Orders Controversial Pipeline to Halt Construction Over West Virginia Streams and Wetlands – In a reprieve for the waterways of West Virginia and the communities that depend on them, the U.S. Federal Energy Regulatory Commission (FERC) said in a document on Monday that EQT Midstream Partners would halt work on the parts of its controversial Mountain Valley Pipeline (MVP) that cross 591 streams and wetlands in the state, Reuters reported.In December, the Army Corps of Engineers had issued the 303 mile pipeline, which would carry frackednatural gas through West Virginia and Virginia, a Nationwide Permit 12, a general permit for waterway disruption by utility line construction that does not require environmental review.But on Thursday, the 4th U.S. Court of Appeals sided with environmental groups including the Sierra Clubwho had argued for a halt in construction, saying that the construction timelines proposed by the pipeline’s makers went beyond the time allowed by the general permit, West Virginia Public Broadcasting reported.”Putting the breaks on in-stream construction activity for the Mountain Valley Pipeline while the court performs its full review not only makes sense, it is also the only just outcome for communities directly impacted by this destructive project,” Appalachian Voices Virginia Program Manager Peter Anderson said in a statement published by the Sierra ClubThursday.Environmentalists also challenged the legitimacy of issuing sweeping permits like Nationwide Permit 12 to projects like the MVP. “Today’s decision shows once again that the Nationwide Permit 12 cannot be used as a one size fits all approach for dirty and dangerous pipelines that pose serious threats to our communities and clean water,” Sierra Club Beyond Dirty Fuels Campaign Director Kelly Martin said Thursday. Under section 404 of the Clean Air Act, general permits like Nationwide permit 12 can be granted, but states can also add additional regulations to those permits. The West Virginia Department of Environmental Protection requires that pipelines finishing building across streams within 72 hours. However, environmental groups argued that MVP’s documents showed that construction over the Elk, Gauley, Greenbrier and Meadow rivers would take 4-6 weeks.
U.S. court order stops some work on Mountain Valley natural gas pipeline in West Virginia (Reuters) – EQT Midstream Partners will stop construction in West Virginia of parts of its $3.5 billion Mountain Valley natural gas pipeline after a U.S. federal appeals court issued an order last week against a permit, a U.S. regulator and the company said. The pipeline company will not proceed with construction in waters affected by the stay order in West Virginia, the U.S. Federal Energy Regulatory Commission said in a document on Monday. Mountain Valley Pipeline (MVP) told FERC it was consulting on the implications of the stay by the U.S. Court of Appeals for the Fourth Circuit with the U.S. Army Corps, which issued the permit in December 2017, FERC said in the notice. In May, the U.S. Army Corp of Engineers pulled a permit for the Mountain Valley natural gas pipeline from West Virginia to Virginia. In a statement on Friday EQT Midstream said it looking at options to have the permit reinstated. The Sierra Club and four other environmental groups had challenged permits the Army Corps of Engineers had issued for construction of the pipeline across streams in West Virginia. The order stops construction in 591 streams and wetlands in the state and “it may affect construction along the entire route of the pipeline,” the Sierra Club said in a statement. Katie Bays, energy analyst at Height Capital Markets in Washington, said in a commentary on Friday that if court rulings go against MVP, its in-service date could be pushed back to mid-2019 or require re-routing around three rivers. The 303-mile (488-kilometer) pipeline had been expected to be in service by late 2018. It was designed to deliver up to 2 billion cubic feet per day of gas from the Marcellus and Utica shale formations in Pennsylvania, West Virginia and Ohio to meet growing demand for power generation and other uses in the U.S. Southeast and Mid-Atlantic.
Environmental advocates ask FERC to revoke mountain valley pipeline approval – Appalachian Mountain Advocates, on behalf of a coalition of environmental and citizen groups, sent a letter Tuesday to the Federal Energy Regulatory Commission (FERC) requesting the federal agency revoke its approval of the MVP.The 303-mile pipeline’s route crosses state lines as it travels from northern West Virginia down to Virginia, which gives FERC partial jurisdiction over construction activities.The request comes just days after the 4th U.S. Circuit Court of Appeals halted some construction of the natural gas pipeline in West Virginia, siding with conservation groups who challenged the pipeline’s water-crossings permit issued by the U.S. Army Corps of Engineers.Specifically, the court stayed the pipeline’s federal Clean Water Act Section 404 permit that was issued by the Army Corps. The Corps granted the MVP a Nationwide Permit 12, a broader permit under the law. It covers nearly 600 stream and wetland disruptions planned by the pipeline in the agency’s Huntington district, which covers all planned construction activity in West Virginia. Environmental groups argued the MVP’s own planning documents showed river crossing for the Elk, Gauley, Greenbrier and Meadow rivers would take 4-6 weeks to complete and could not comply with the permit’s 72-hour deadline. The federal appeals court agreed. In the letter to FERC, Appalachian Mountain Advocates stated that because of the federal appeals court decision last week, the pipeline no longer has all of the federal authorizations it needs and thus FERC’s approval, known as a Certificate Order, should be suspended.
Appeals Court Stays Crucial MVP Permit in West Virginia, Putting 2018 Startup in Jeopardy — The U.S. Court of Appeals for the Fourth Circuit granted a motion to stay the Nationwide Permit (NWP) 12 issued by the Army Corps pending a ruling on a legal challenge brought by a coalition of environmental groups including the Sierra Club. The NWP 12 is issued under Section 404 of the U.S. Clean Water Act (CWA) and allows contractors to trench through the bottom of streams and rivers. The Sierra Club earlier this yearchallenged the validity of MVP’s NWP 12 permit, arguing that the project could not meet a special condition in West Virginia requiring all stream crossings be constructed within 72 hours.In response to the groups’ challenge, the Army Corps voluntarily issued a limited suspension of the NWP 12 for four river crossings in the state. But the Sierra Club and others successfully argued to the court that under Army Corps regulations, all portions of the NWP 12 permit must be stayed, putting nearly 600 MVP waterbody crossings in regulatory limbo.As part of its rationale for waiving a state-issued CWA Section 401 water quality certification, the West Virginia Department of Environmental Protection (WVDEP) had cited special state-specific conditions that had been added to the NWP 12 permit. WVDEP had earlier withdrawn the CWA 401 it issued to MVP after facing a court challenge.MVP spokeswoman Natalie Cox told NGI Friday that both the developers and WVDEP interpreted the 72-hour requirement included in the West Virginia-specific conditions of the NWP 12 permit as only applying to “wet-cut” crossings. “The Sierra Club argues that MVP cannot comply with the permit condition to complete four waterbody crossings (Elk, Gauley, Greenbrier, and Meadow Rivers) within 72 hours; however, this provision is intended to apply to water crossings that are constructed in an open trench while the river is flowing (wet-cut),” Cox said. “MVP plans to utilize a ‘dry-ditch’ coffer dam method to cross these four rivers as this technique is more protective of the environment because construction activity is not performed in a flowing river.“This crossing technique has been approved by both the FERC and the WVDEP,” Cox said. “While significantly more environmentally protective, the ‘dry-ditch’ technique also requires a longer completion time as compared to traditional ‘wet’ crossing methods to which the time limitation provision applies,”
Mountain Valley Pipeline foes file new legal challenge following last week’s win – One week after an appeals court slowed down construction of a natural gas pipeline in West Virginia, it is being asked to do the same for the project’s path through Virginia.The request was made Tuesday in a petition filed with the 4th U.S. Circuit Court of Appeals by the Sierra Club and three other conservation groups.Last week, the appeals court issued a stay that prohibits developers of the Mountain Valley Pipeline from moving forward with plans to run the massive pipeline across rivers and streams in West Virginia. The stay put such work on hold pending a challenge of a key stream-crossing permit issued by the U.S. Army Corps of Engineers for the pipeline’s route through southern West Virginia.A similar permit – granted by the Army Corps for a section of the 303-mile pipeline that runs through the New River and Roanoke valleys – is now being questioned by a petition for review filed Tuesday. Joining the Sierra Club in the case are the New River Conservancy, Appalachian Voices and the Chesapeake Climate Action Network. In what was the first major court victory for pipeline opponents, a similar coalition persuaded a three-judge panel of the 4th Circuit last week to issue a stay that lawyers for Mountain Valley had strongly opposed, saying it would delay completion of the pipeline by up to eight months. The conservation groups are arguing that the Army Corps permit is deficient because it allowed the crossings of four rivers in West Virginia even though the work cannot be completed within the 72 hours required by that state’s environmental regulators.
TransCanada urges US to help gas pipelines beat green critics (Reuters) – The United States should help the natural gas industry overcome environmental challenges to new pipeline projects by adjusting regulations or adopting new laws favoring infrastructure, an executive at TransCanada Corp said at a conference this week. Suppliers in the United States, the world’s biggest natural gas producer, have had a harder time getting shipments to market as more environmental lawsuits by U.S. states, green groups and property owners have tied up pipeline construction. “It’s definitely not getting easier to build a new pipeline,” Stanley Chapman, executive vice president and president of U.S. natural gas pipelines at TransCanada Corp, told Reuters on the sidelines at the World Gas Conference in Washington. “I’m seeing more already-approved pipeline projects that are under construction get held up by a judge in lawsuits and this has to be addressed either by FERC or with legislation,” he said. FERC, or the U.S. Federal Energy Regulatory Commission, oversees construction of new pipelines. TransCanada owns about 30,000 miles of gas pipeline in the United States, making it one of the country’s biggest operators. It has been trying for more than a decade to build its Keystone XL oil pipeline project linking Canada’s oil sands to U.S. refineries amid ongoing environmental delays.
TransCanada, Whose Pipeline Just Exploded, Wants Feds’ Help to Beat Green Groups — Facing mounting protests and lawsuits from environmental groups and property owners, backers of the natural gas pipeline industry are seeking help from the U.S. government to help push their projects through,Reutersreported. “It’s definitely not getting easier to build a new pipeline,” Stanley Chapman, executive vice president and president of U.S. natural gas pipelines at TransCanada Corp, told the news service at the World Gas Conference in Washington. “I’m seeing more already-approved pipeline projects that are under construction get held up by a judge in lawsuits and this has to be addressed either by FERC or with legislation,” he added, referring to the U.S. Federal Energy Regulatory Commission, which oversees construction of new pipelines. Followers of the Keep It In The Ground movement would say that the best means of fossil fuel transportation is none. Environmentalists oppose oil and natural gas pipelines over fears of air and water pollution, as well as its impact on climate-warming emissions. Reuters further reported:In recent weeks, environmental groups like the Sierra Club have won court orders delaying construction on EQT Midstream Partners LP’s Mountain Valley pipeline at several locations in West Virginia, and are now seeking a court order to also stop construction in Virginia. “We don’t need these pipelines to meet our energy needs, so it makes no sense to lock us into generations of dependence on dirty fossil fuels,” said Joan Walker, who helps lead the Sierra Club’s Beyond Dirty Fuels Campaign.
Old growth forest in Bath to become encampment in pipeline fight – Opponents of the Atlantic Coast Pipeline are setting up camp in the shadow of an old-growth forest in Bath County that could become a major battleground in the path of the pending $5.5 billion natural gas pipeline. Bill and Lynn Limpert, owners of a 120-acre property in Bath’s Little Valley, have invited the public to visit and camp on their land this summer to put a public spotlight on what they call “Miracle Ridge,” a 3,000-foot-long Allegheny Mountain ridge lined with trees up to 300 years old. “The pipeline would turn Miracle Ridge into a pile of rubble,” Bill Limpert said in a telephone news conference on Monday with the Chesapeake Climate Action Network, an environmental group that opposes the pipeline and the transportation of natural gas produced through fracking in the West Virginia shale fields. However, the Limperts and their allies stopped short of promising a stand in the treetops to stop the project, as Theresa “Red” Terry and other opponents did earlier this year in Roanoke and Franklin counties in a long standoff with construction crews for the Mountain Valley Pipeline that ended with their eventual surrender. “We’re peaceful folks,” said Limpert, a retired environmental regulator from Maryland. “We believe in the rule of law. We’ll cross that bridge when we come to it.” Bath County is west of Staunton along the state line with West Virginia. The earliest potential confrontation with tree-cutting crews would be mid-September, when the regulatory window reopens for the felling of trees in the 125-foot-wide corridor that Dominion Energy and its partners plan to create for the pipeline from West Virginia to the North Carolina border more than 300 miles away.
Blockade by Pipeline Opponents Disrupts Work Day at FERC — Security at the Federal Energy Regulatory Commission seemed caught unawares Monday morning when anti-pipeline activists blockaded the staff parking garage at the agency headquarters. In the middle of First Street, two people climbed up and perched high on bamboo structures made to resemble hydraulic fracking well derricks. FERC is responsible for approving or denying proposed interstate gas pipelines, most of them supplied by fracking wells. “FERC greenlights all energy projects, paying no mind to how dirty or unsafe they are to the climate or community,” said derrick-sitter Jessica Sunflower Rechtschaffer of New York City. “We erected these towers in front of FERC to show how these towers are being placed all over the USA, disrupting people, their homes livelihoods and environment.”The FERC critics from Beyond Extreme Energy (BXE) and other groups, numbering about two dozen, also unfurled a long banner in front of the main entrance, blocking it as well. They say FERC should no longer be “a rubber stamping agency” and instead dedicate itself to facilitating “a just transition off fossil fuels.”FERC has long been accused of having a “cozy relationship” with industry with commissioners and staff enjoying a revolving door to and from gas industry jobs. Critics also say that it assists gas companies in breaking up projects into smaller ones which will more easily obtain approval, a practice known as segmentation. Meanwhile, communities must grapple with a complex and time-consuming permit process directed toward what seems like a predetermined outcome. FERC has also been accused of “cherry-picking” data to force pipelines through low-income areas and communities of color. There has been a sustained initiative to draw attention to the broad impact of the agency’s work, as gas companies seize private property and dig up forests, streams and mountaintops with a massive expansion of pipeline networks. For more than four years, BXE has held similar protests at FERC headquarters and disrupted the Commission’s monthly public meetings. Their efforts may be paying off.
Company plans to finish Louisiana oil pipeline by October – A company building a crude oil pipeline in Louisiana expects to complete the construction project by October if a federal appeals court doesn’t order another halt to the work. Bayou Bridge Pipeline LLC’s attorneys said in a court filing Wednesday that construction of the entire 163-mile (260-kilometer) pipeline was nearly 76 percent complete as of Sunday. A three-judge panel of the 5th U.S. Circuit Court of Appeals is considering whether the company can continue building the pipeline through the environmentally fragile Atchafalaya Basin swamp. Last Friday, the panel asked for an update on the work. In February, U.S. District Judge Shelly Dick issued a preliminary injunction stopping pipeline construction in the basin until environmental groups’ lawsuit over the project is resolved. In March, however, a different 5th Circuit panel agreed to suspend Dick’s order pending a final decision by the appeals court. That ruling allowed the company to resume construction. During a hearing in April, company lawyers urged the New Orleans-based appeals court to throw out Dick’s order. The panel hasn’t ruled yet. In the meantime, workers are still cutting down trees in the basin to clear a path for the pipeline. As of Sunday, the company had cleared approximately 164 acres of trees (out of a total of 262 acres) and estimated it will finish that work by Aug. 8, according to Wednesday’s court filing.
Big Oil eyes U.S. minority groups to build offshore drilling support (Reuters) – The largest U.S. oil and gas lobby group is seeking to convince Hispanic and black communities to support the Trump administration’s proposed expansion of offshore drilling, arguing it would create high paying jobs, including for storm-displaced Puerto Ricans. The American Petroleum Institute (API) launched its “Explore Offshore” campaign earlier this month to counter offshore drilling foes in coastal southeast states from Virginia to Florida, where lawmakers and governors on both sides of the aisle have expressed fear an oil spill could ruin tourism. “We want to build support in minority communities because the message that increasing the supply of affordable energy and good paying jobs will resonate,” said Erik Milito, API’s director of Upstream and Industry Operations. As part of the campaign, API has partnered with a number of black and Hispanic business groups, including the Virginia, Florida and North Carolina Hispanic Chambers of Commerce and the Florida Black Chamber of Commerce and South Carolina African American Chamber of Commerce. A Pew Research poll published in January showed that 56 percent of Hispanics and 54 percent of blacks opposed offshore drilling, compared to 48 percent of white people. The Interior Department in January announced a proposal to open up nearly all U.S. offshore waters to drilling, triggering a backlash from coastal states that rely on tourism. Interior Secretary Ryan Zinke told a Senate panel in April that he is likely to scale back the proposal following meetings with coastal governors. Shortly after he unveiled his offshore drilling proposal, Zinke offered an exemption for Florida after he held a private meeting with Republican Governor Rick Scott. The oil and gas industry is keen to pursue seismic testing in areas they believe hold the largest reserves along the southern Atlantic coast and to Florida’s eastern Gulf shorelines. The API campaign published op-eds in local newspapers this week, including one by Stephen Gilchrist, chair of South Carolina’s African American Chamber of Commerce. In it he touts API’s major talking point that oil and gas exploration jobs offer locals an average salary of $116,000 without requiring a college degree.
Gulf Of Mexico Production Expected To Hit Record High — While the U.S. shale production in the Permian has been grabbing most of the market and media attention over the past two years, the Gulf of Mexico has been quietly staging a comeback. Big Oil firms, the main operators in the Gulf of Mexico, have been cutting costs and simplifying designs to make offshore projects viable in the lower-for-longer oil price world. Chevron, Shell, and BP continue with their deepwater developments offshore Louisiana and Texas and have brought down breakeven costs to $40 a barrel or less – comparable with the breakevens at some shale formations onshore. Now operators are vying for new exploration acreage close to existing production platforms that would bring development and production costs down even further. While the market and media have focused on the record Permian production, the Gulf of Mexico’s production is also expected to hit a record high this year. But there’s one huge difference between onshore and offshore in terms of resource development – for shale wells, production peaks in several months, while vast deepwater resources can pump oil for decades. Big Oil continues to bet on resources and projects that will last for decades, but companies have drastically changed their approach to development. Gone are the days in which the race was to have ‘the biggest, the most complex and most expensive’ bespoke project the industry has seen. It may have worked at oil prices at $100, but at half that price of oil, the focus is on leaner projects and more collaborative work to bring costs down.
Environmentalists sue for report on how Gulf drilling affects endangered species — Three conservation groups said in a lawsuit filed Thursday that federal wildlife agencies have failed for years to complete required consultations and reporting on the effects that oil drilling in the Gulf of Mexico could have on endangered species. The suit comes more than a decade since the last such report was done, and more than eight years since the huge 2010 BP oil spill, the groups said. The Gulf Restoration Network, the Sierra Club and the Center for Biological Diversity released a copy of their lawsuit as it was being filed in U.S. District Court in Florida. Defendants named are the National Marine Fisheries Service and the U.S. Fish and Wildlife Service. The suit says the Endangered Species Act requires those agencies since 2007 to consult with the agencies overseeing Gulf drilling and to publish an opinion on the possible effects of such drilling on endangered species, including various species of whales and sea turtles. Such consultations and reporting haven’t been conducted since well before the 2010 explosion of the BP-operated Deepwater Horizon drilling rig, a disaster that spilled millions of gallons into the Gulf, the lawsuit says. It added that the result is that hundreds of offshore oil and gas projects have been approved based on outdated information. . “It is now nearly eight years later, and the Fisheries Service and FWS have not completed consultation,” the lawsuit says. “This despite the Fisheries Service’s earlier assurance to a federal court that consultation would be completed by Oct. 31, 2014.”
U.S. hydrocarbon gas liquids consumption increases as prices, expenditures decrease — Consumption of hydrocarbon gas liquids (HGL) in the United States totaled 928 million barrels in 2016, up about 12% since 2010. During the same time, total U.S. HGL prices fell by 47% and, consequently, expenditures decreased by about 41%. In 2016, total U.S. HGL expenditures were $32 billion, the lowest since 2003. The Texas and Louisiana industrial sectors dominate HGL consumption, expenditures, and price formation in the United States. The two states combined to account for about 75% of total U.S. HGL consumption and 58% of total U.S. HGL expenditures in 2016, almost all of which was in the industrial sector. The HGL pricing hub in Mont Belvieu, Texas, heavily influences the prices of HGL products across the nation. EIA’s State Energy Data System (SEDS) recently published a new categorization of petroleum products with annual state-level estimates of HGL consumption, prices, and expenditures by end-use sector for 1960 through 2016. HGLs include natural gas liquids (ethane, propane, normal butane, isobutane, and natural gasoline) and refinery olefins (ethylene, propylene, normal butylene, and isobutylene). Almost all HGLs not used as refinery and blender inputs are consumed exclusively in the industrial sector, with the exception of propane, which is consumed in all sectors.
Analysis: Power burn set to break monthly gas-fired power generation demand record in Midwest — Gas-fired power generation demand across the Midwest is on track to set a new high this month as warm weather and two coal retirements have offset an uptick in cash prices in the region. Strong power burn is likely to continue through the end of June with hot weather in the forecast. The higher demand is also causing storage fields in the region to refill at a sluggish rate. However, the futures market is predicting Chicago prices will fall throughout the summer. Midwest power burn demand has averaged 2.6 Bcf/d over the past 30 days, up 60% from the five-year average of 1.5 Bcf/d for this time, and 0.6 Bcf/d higher than this time last year, according to data from S&P Global Platts Analytics. The primary driver is warm weather. Population-weighted temperatures in the Midwest have been approximately 6 degrees above normal over the past 30 days, including eight days more than 10 degrees above normal and several days reaching almost 20 degrees above normal. Temperatures are expected to fall more in line with seasonal averages through the end of June but remain about even with the past 30 days. Platts Analytics is expecting strong demand to continue through the end of the month. If the forecast holds, total June power demand will average 2.4 Bcf/d, which would be a new record, topping both June 2016’s record high of 2.36 Bcf/d and the June five-year average of 1.6 Bcf/d.
Factbox: Key natural gas supply/demand projections from IEA’s Gas 2018 report – The International Energy Agency on Tuesday published its latest medium-term gas outlook containing forecasts for gas supply and demand to 2023.
- Global gas demand to reach 4.1 Tcm by 2023
- US gas production to soar to 922 Bcm
- Chinese gas production set for big increase
Below are some of the key projections. (see tables)
What a summer scorcher means for natural-gas prices – Low supplies of natural gas could lead to higher prices this summer, as Americans begin to flip on their air-conditioning units, boosting demand for the energy source. Stockpiles of natural gas – made plentiful by the U.S. shale boom – have become depleted after an extended winter this year increased demand for heating homes. Booming U.S. exports of gas also have absorbed excess inventories, and analysts say cheap prices have made it more popular for power generation, compared with more expensive sources like coal. Natural gas consumption generally rises in the summer months as cooling needs drive energy demand. But this year, the amount of natural gas in storage started June at the lowest level since 2014 for that time of year, and the second lowest level in a decade. .Now, with weather forecasts into July showing hotter-than-average temperatures across the U.S., consumers could see a pop in prices. Already, a significantly hot month of June has pushed natural gas futures near the closely watched level of $3 a million British thermal units, recently hitting the highest price since January. Extreme cold in January led to record natural gas consumption and withdrawals from storage extended into April due to unseasonably cool weather. Now the amount of energy required to cool buildings in June is on track for its second highest level since 1981, according to Bespoke Weather Services. It’s a far cry from two years ago when the relentless growth of U.S. shale and mild weather produced a glut that sent gas prices tumbling to a 17-year low. Traders are betting that the summer will end with significantly less natural gas in stock. On London’s Intercontinental Exchange, EIA end-of-storage index futures indicate bets that October will end with about 3.525 trillion cubic feet of natural gas, which would be the lowest for that time since 2008, before shale flooded the U.S. with cheap energy.
Natgas CEOs say product can help curb climate change (Reuters) – Natural gas can be a permanent solution to reducing greenhouse gas emissions and curbing climate change, and not just a step toward full utilization of renewable energy technologies, industry executives said on Tuesday. Once thought of as a clean alternative to crude oil, natural gas has come under attack by environmentalists who want to curb the use of all fossil fuels in a bid to hasten the adoption of solar, wind and other green energies. “This idea of natural gas as a transition fuel to renewables is strange,” Total SA Chief Executive Patrick Pouyanne said Tuesday at the World Gas Conference in Washington. “Natural gas is a solution (to climate change). It’s been scientifically proven.” Pouyanne’s views were echoed by others who joined him on industry panel, including executives from ConocoPhillips, BP Plc, Equinor Asa and Qatar Petroleum. “We don’t believe the existential threat to our business is right around the corner,” Conoco CEO Ryan Lance said. “We see rising usage of natural gas.” Qatar Petroleum, which is undertaking a major project to expand its natural gas output by a third over the next decade, said it sees demand only growing for its product. “Human beings need energy. Gas should be seen as a destination fuel not just as a transport fuel or bridge fuel,” QP Chief Executive Saad Sherida Al-Kaabi said at the conference. Bob Dudley, the CEO of BP Plc, which is rapidly expanding its U.S. shale gas production, said the fuel is the best alternative to coal-fired power generation in many locations, with improving technologies helping to curb methane emissions. A study released last week from the Environmental Defense Fund found that oil and gas drilling gives off far more of the powerful greenhouse gas methane than the U.S. government estimates as leaky wells go unnoticed by federal regulators. Dudley acknowledged the industry should and is doing more to use better technologies to bolster methane collection.
The argument for fracking as a climate solution just went down in flames — A new, comprehensive study of methane leaks in the oil and gas industry is the final piece of evidence that natural gas is not part of the climate solution. “Natural gas could warm the planet as much as coal in the short term,” as the journal Science itself summed up the 24-author study it just published. But that headline – and virtually all of the media coverage of the study – tells only a piece of the story: The findings confirm if a coal-fired plant is replaced with a gas-fired plant there is no net climate benefit for at least two decades. The missing piece in both the study and the coverage, though, is that countless studies have made clear that natural gas does not just displace dirty coal in the power system – it displaces many carbon-free sources of power, including nuclear and renewables. Let’s briefly step back from this study to look the three essential reasons natural gas is not a “bridge” fuel to a carbon-free future. First, natural gas is mostly methane (CH4), a super-potent greenhouse gas, which traps 86 times as much heat as CO2 over a 20-year period. That’s why many studies find that even a very small leakage rate of methane from the natural gas supply chain (production to delivery to combustion) can have a large climate impact – enough to gut the entire benefit of switching from coal-fired power to gas for a long, long time. Second, a great many studies have found that leakage rates are not small at all, especially as fracking has become more popular. “A review of more than 200 earlier studies confirms that U.S. emissions of methane are considerably higher than official estimates,” as one 2014 Stanford review research on methane leaks explained. The study found methane emissions are so large, they “produce radiative forcing over a 20-year time horizon comparable to the CO2 from natural gas combustion.” That means the total warming from natural gas plants (leaks plus burning the gas) over a 20-year period is comparable to the total warming from coal plants over 20 year period. And that brings us to the third crucial point about why natural gas isn’t a bridge fuel. Many other studies find that natural gas plants don’t replace only high-carbon coal plants. Gas plants commonly replace very low carbon power sources like solar, wind, nuclear, and even energy efficiency, which is often overlooked as a major alternative to fossil fuels.
A New Report Tying U.S. Natural Gas And Global LNG Markets — As U.S. LNG exports play an increasing role in the global market, the U.S. will not only be exporting its vast natural gas supplies but also to a degree its market realities – namely, the risks, opportunities and, at times, volatility of a highly liquid, fungible and economically-driven spot market. The global LNG market also has shifted toward more flexible and spot-oriented trade, opening the window for some ad lib wheeling and dealing based on the prevailing economic conditions at any given time. These two factors together will come with significant implications across the supply chain – from the producing basins to the pipeline transport routes and from the export terminals to the destination markets they are serving. This month, with feedgas receipts at Sabine Pass LNG down and an explosion on a key supply route from Appalachia to Louisiana, we are starting to see how this integration of the U.S. and global markets is likely to play out. To help you keep up with this complicated dynamic and extrapolate the big-picture impacts, today we introduce RBN’s new LNG Voyager Report,featuring a comprehensive, pipe-to-port-to-destination approach to understanding how U.S. LNG fits into the global market. In the past three years, U.S. LNG exports have gone from being non-existent to an average of 3.0 Bcf/d. In that time, the new demand source – currently from just five liquefaction trains, four at Cheniere Energy’s Sabine Pass LNG (SPL) in Cameron Parish, LA, and one at Dominion’s Cove Point LNG in Maryland – already has reconfigured pipeline flows all the way from the Northeast and Midwest to the Gulf Coast, as Appalachian and other gas suppliers look for ways to get their gas south, where the lion’s share of the export demand is happening (see Toe Bone Connected to the Foot Bone, and our latest Drill Down report, Down Louisiana Way). In fact, gas flows along entire corridors of pipeline routes that used to flow south-to-north have flipped direction and are flowing gas north-to-south.