Oil, Gas, And Fracking News Reads 21July 2018 – Part 1

Written by rjs, MarketWatch 666

Here are some selected new articles from the week ended 21 July 2018.

This article is a feature every Monday evening on GEI.

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EIA projects a 10 year low for pre-winter natural gas supplies; oil imports at 16 mo high after biggest jump in 18 months; distillate supplies at a 14 year seasonal low, et al

Oil prices ended lower for the third week in a row, mostly due to a big selloff on Monday….after falling $2.84, or 3.8% to $71.01 a barrel last week on the resumption of Libyan oil exports, US crude for Augustfell another $2.95, or 4.2% to $68.06 a barrel on Monday, as oil traders cut their bets on a supply shortage and reports of rising output from the US and OPEC more than offset concerns about supply disruptions…that selloff continued Tuesday morning, with oil down another $1.03 to $67.03 early, before it reversed in the afternoon and ended up 2 cents for the day at $68.08 s barrel, as news of a new production outage in Libya served as a reminder that supplies remained tight…US oil prices then rose 68 cents to $68.76 a barrel on Wednesday, as the weekly EIA report showed strong demand for gasoline and distillates, overshadowing a surprise build of U.S. crude inventories…oil prices ended higher again on Thursday, after Saudi Arabia’s OPEC governor issued a statement to OPEC that Saudi crude exports would be lower next month in an effort to avoid oversupplying the market, with US crude closing up 70 cents at $69.46 a barrel…then on Friday, as trading in August oil contracts expired, they finished the week with a $1 increase to end at $70.46 a barrel, after Mr Trump said he’s “not thrilled” about the Fed’s plan to raise interest rates, which spooked the markets and sent the US dollar lower, thus making oil higher priced in dollar terms…however, even after rising four days in a row to it’s highest level all week, that August oil contract still ended the week down 55 cents, or 0.8% from last Friday’s finish for a third consecutive weekly loss…meanwhile, US crude for September, which will be quoted as the price of oil next week, rose just 2 cents on Friday to $68.26 a barrel, to finish the week down $1.69, or 2.4%, on far more robust trading than was seen in the expiring August contract…at the same time, Brent crude for September, the international benchmark price, ended the week with a loss of $2.16, or 2.9%, at $73.07 barrel, having dropped $3.49, or 4.5%, on Monday..

Natural gas prices, meanwhile, were little changed this week, ending just a half cent higher at $2.757 per mmBTU for the week, despite an addition to natural gas in storage that was much smaller than analysts had expected….the natural gas storage report for week ending July 13th from the EIA indicated that natural gas in storage in the US rose by 46 billion cubic feet to 2,249 billion cubic feet over the week, which left our gas supplies 710 billion cubic feet, or 24.0% below the 2,959 billion cubic feet that were in storage on July 14th of last year, and 519 billion cubic feet, or 19.2% below the five-year average of 2,784 billion cubic feet of natural gas that are typically in storage after the second week of July…the forecast from the S&P Global Platts’ survey of analysts was for an addition of 59 billion cubic feet to gas in underground storage, so this 46 billion cubic feet increase was somewhat lower than what had been expected, and also quite a bit lower than the 62 billion cubic foot average of weekly surplus natural gas that has typically been added to storage during the second week of July over the past 5 years…as we’ve been pointing out each week that natural gas additions to storage fall short, it’s becoming practically impossible for natural gas supplies to be restored to a normal level before the next heating season’s withdrawals begin, and now the EIA has also admitted as much, as they are now forecasting a 10 year low for natural gas supplies going into this coming winter…the best way to explain their forecast is with the graph they used, so we’ll include that here now…

The above graph comes from this week’s Natural Gas Weekly Update by the EIA, and it shows the weekly quantity of natural gas in storage in billions of cubic feet in the lower 48 states from the beginning of 2018 as a dark brown line, the average of natural gas in storage over the prior 5 years as a heavy grey line, and the range of natural gas in storage over the past five years for any given time of year as a grey shaded background behind those graphs…thus the shaded grey area also shows us the normal range of natural gas in storage as supplies fluctuate from season to season, with natural gas in storage underground normally building to a maximum by the end of October, falling through the winter, and usually bottoming out at the end of March, depending of course on the demand for heating during any given spring ….you might recall thatwe burnt 11.5% of the natural gas we had stored in one weekat the beginning of this year, an unheard of record withdrawal, and hence the dark brown graph for this year’s suppplies started out at the bottom of the normal range…then, with the cool April this year, natural gas was still being used for heating three weeks into April, so supplies of gas were actually falling a bit the first three weeks of the normal injection season…then, as we showed from the EIA report of two weeks ago, even though US natural gas production was up 10% for the first half of this year, consumption of natural gas has been up 11%, leaving that much less surplus to be injected into storage each week…thus we arrive at July 13th with 2,303 billion cubic feet in storage, as shown on the graph above, precariously close to the record low levels of gas supplies we carried through 2014, a year when the polar vortex winter had dropped our April 1st supplies to below one million cubic feet for the first time on record…thus, given what we have stored now, the current rate of natural gas production, and the current rate of consumption, the EIA projects that our natural gas supplies will only rise to 3,470 billion cubic feet by October 31st, which would be 365 billion cubic feet lower than the five-year average for that date, and the lowest start to the heating season since October 2008, when natural gas inventories ended the month at 3,412 billion cubic feet…in a normal winter, that wouldn’t be a problem, but should a winter like 2014 repeat, spot shortages of natural gas in the states with the least storage or the most unseasonable demand are not out of the question…you can get more details on projected natural gas prices and the weather forecasts that accompany this natural gas storage outlook in this week’s Natural Gas Weekly Update…

The Latest US Oil Data from the EIA

This week’s US oil data from the US Energy Information Administration, covering the week ending July 13th, showed that due to a big increase in our oil imports, a drop in our oil exports, and a cutback in our oil refining, we had a surplus of oil to add to our commercial crude supplies for the thirteenth time in the past twenty-five weeks…our imports of crude oil rose by an average of 1,635,000 barrels per day to a 16 month high of 9,066,000 barrels per day, the biggest jump in 18 months, after falling by an average of 1,624,000 barrels per day the prior week, while our exports of crude oil fell by an average of 566,000 barrels per day to an average of 1,461,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 7,605,000 barrels of per day during the week ending July 6th, 2,201,000 barrels per day more than the net of our imports minus exports during the prior week and the highest since August 2017…at the same time, field production of crude oil from US wells was reported to be at a record high of 11,000,000 barrels per day, an increase of 100,000 barrels per day from the previous week, which means that our daily supply of oil from our net imports and from wells totaled an average of 18,606,000 barrels per day during the reporting week…

At the same time, US oil refineries were using 17,239,000 barrels of crude per day during the week ending July 13th, 413,000 barrels per day less than they used during the prior week, while at the same time 834,000 barrels of oil per day were reportedly being added to the oil that’s in 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 and from oilfield production was 532,000 more barrels per day than what was added to storage plus what refineries reported they used during the week…to account for that disparity, the EIA needed to insert a (-532,000) 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 8,477,000 barrels per day, which was 8.1% more than the 7,841,000 barrel per day average we imported over the same four-week period last year….as we’ve mentioned before, the four week average of oil imports is more representative than the volatile weekly totals, which may temporarily get skewed by the the number of 2 million barrel VLCCs that unload in any given week, the size of the various other tankers that unload during the week, and the berthing schedule or the weather at the major import ports…the 834,000 barrel per day increase in our total crude inventories was all added to our commercially available stocks of crude oil, as the amount of oil in our Strategic Petroleum Reserve remained unchanged….this week’s crude oil production was reported 100,000 barrels per day higher on a 50,000 barrel per day increase in output from Alaska, despite a lack of change in posted production figures for the lower 48 states, because the EIA has recently decided to round the weekly oil production estimates to the nearest 100,000 barrels per day to reflect their inability to accurately model oil output from all the wells in the lower 48 states, and the Alaska increase was enough to cause an increase in the rounded total….US crude oil production for the week ending July 14th 2017 was reported at 9,429,000 barrels per day, so this week’s rounded oil production figure is roughly 16.7% above that of a year ago, and 30.5% 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 94.3% of their capacity in using 17,652,000 barrels of crude per day during the week ending July 13th, down from 96.7% of capacity the prior week, but still a refinery capacity utilization rate above historical norms…similarly, the 17,239,000 barrels of oil that were refined this week was still at a seasonal high, more than any previous 2nd week of July, despite the 413,000 barrel per day drop in throughput from the prior week….however, this week’s refinery throughput was only 0.7% higher than the 17,119,000 barrels of crude per day that were being processed during the week ending July 14th a year ago, when US refineries were operating at 94.0% of capacity….

With the drop in amount of oil being refined this week, gasoline output from our refineries fell by a similar quantity, decreasing by 407,000 barrels per day to 10,292,000 barrels per day during the week ending July 13th, after our refineries’ gasoline output had increased by 388,000 barrels per day during the week ending July 6th…but even after this week’s decrease, our gasoline production during the week was still 1.9% more than the 10,096,000 barrels of gasoline that were being produced daily during the week ending July 14th of last year…at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) fell by 268,000 barrels per day to 5,174,000 barrels per day, after falling by 21,000 barrels per day the prior week…however, this week’s distillates production was still near the 2014 seasonal high for mid July, and 4.6% higher than the 4,945,000 barrels of distillates per day that were being produced during the week ending July 14th, 2017…

And with the drop in our gasoline production, our supply of gasoline in storage at the end of the week fell by 3,165,000 barrels to 235,832,000 barrels by July 13th, the twelfth decrease in 19 weeks, but just the 13th decrease in 36 weeks, as gasoline inventories, as usual, were being built up over the winter months….our supplies of gasoline also fell this week because the amount of gasoline supplied to US markets rose by 433,000 barrels per day to 9,708,000 barrels per day, and because our imports of gasoline fell by 196,000 barrels per day to 657,000 barrels per day, while our exports of gasoline fell by 452,000 barrels per day to 734,000 barrels per day….but even after this week’s decrease, our gasoline inventories were still 2.0% higher than last July 14th’s level of 231,211,000 barrels, and roughly 8.8% above the 10 year average of our gasoline supplies for this time of the year…

Smilarly, with our distillates production also much lower, our supplies of distillate fuels decreased by 371,000 barrels to 121,311,000 barrels during the week ending July 13th, in just the 2nd decrease in 8 weeks…that was as the amount of distillates supplied to US markets, a proxy for our domestic consumption, rose by 336,000 barrels per day to 4,141,000 barrels per day, after decreasing by 321,000 barrels per day the prior week, and as our exports of distillates rose by 74,000 barrels per day to 1,226,000 barrels per day, after falling by 258,000 barrels per day the previous week, while our imports of distillates rose by 36,000 barrels per day to 140,000 barrels per day…however, since our distillate supplies had shrunk by 14,452,000 barrels over the six weeks to May 18th on the way to falling to a 13 year seasonal low, this week’s drop meant our distillate supplies for the week ending July 13th were thus at a 14 year low for the time of year, 19.9% below the 151,416,000 barrels that we had stored on July 14th, 2017, and roughly 15.9% lower than the 10 year average of distillates stocks for this time of the year…

Since our distillate supplies have now slipped to a seasonal 14 year low for the second week of July, we’ll include a graph showing how they got here…

The above graph came from a weekly emailed package of oil graphs from John Kemp of Reuters, which is also available as a pdf here, and 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’s 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…this graph also shows the number of thousands of barrels of distillates we had stored at the end of each week in 2017 traced by a yellow line, and our year to date distillates supplies for each week of 2018 traced in red…we can clearly see within the light blue shaded area that there is a seasonality to distillates supplies, as they’re normally built up during the spring and summer when refineries are running flat out, and then drawn down and consumed during the winter months, when demand for heating oil is greatest…however, this year, when supplies of distillates should have been increasing during April and May – days 91 to 151 above – as they normally do, they were falling instead, largely because we had been exporting our distillates production at a record pace…so even as our refineries have started producing distillates at a record pace in the weeks since, and as we slowly started adding back to our supplies, our increases over the past 8 weeks have not kept up with the pace of inventory increase we’d normally see at this time of year….hence we come to July 13th with our distillate supplies at the lowest level in mid-July since July 16th, 2004, which as John headlines is “the lowest seasonal level in more than a decade”….and like the decline in natural gas supplies, this drop in distillate inventories all came about over recent months, because if we follow the yellow graph line for 2017 back to the beginning of that year, we can see that our distillates supplies had hit a wintertime high of 170,746,000 barrels on February 3rd, 2017, and they’ve been falling almost continuously since…

Finally, with our oil production at a record high and our oil imports at a 16 month high while our refineries were pulling back from their recent record pace, our commercial supplies of crude oilincreased for the 14th time in 2018 and for the 20th time in the past year, as our commercial crude supplies rose by 5,836,000 barrels during the week, from 405,248,000 barrels on July 6th to 411,084,000 barrels on July 13th…however, after falling most of last year, our oil inventories as of July 13th were still 16.2% below the 490,623,000 barrels of oil we had stored on July 14th of 2017, 15.9% below the 488,830,000 barrels of oil that we had in storage on July 15th of 2016, and 4.8% below the 431,836,000 barrels of oil we had in storage on July 17th of 2015, when the US glut of oil had already risen above the nearly stable supply levels of under 400 million barrels during the prior years…

This Week’s Rig Count

US drilling activity decreased for the fourth time in six weeks during the week ending July 20th, following 11 consecutive weeks of increases, as the steady increases in drilling for oil we saw with higher oil prices the first half of this year has now stalled…Baker Hughes reported that the total count of active rotary rigs running in the US decreased by 8 rigs to 1046 rigs over the week ending on Friday, which was still 96 more rigs than the 950 rigs that were in use as of the July 21st report of 2017, but was down from the shale era 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 fell by 5 rigs to 858 rigs this week, which was still 94 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 decreased by 2 rigs to 187 rigs this week, which was just one more rig 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, one of the two drilling rigs that were considered to be “miscellaneous” was also shut down this week, which still shows as an increase from the zero such “miscellaneous” rigs in use a year ago….

Two of the platforms which had been operating in the Gulf of Mexico were shut down this week, leaving 17 still drilling offshore, which was 6 fewer than the 23 platforms that were deployed in the Gulf of Mexico a year ago…since there is no other offshore activity in other US waters at this time, nor was there a year ago, those Gulf of Mexico rig totals are identical to the total national offshore count…

The count of active horizontal drilling rigs fell by 8 rigs to 922 horizontal rigs this week, which was still 119 more horizontal rigs than the 803 horizontal rigs that were in use in the US on July 21st of last year, but down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014…in addition, the directional rig count decreased by 1 rig to 67 directional rigs this week, which was also down from the 75 directional rigs that were in use during the same week of last year…on the other hand, the vertical rig count increased by 1 rig to 57 vertical rigs this week, which was still down from the 72 vertical rigs that were operating on July 21st 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 July 20th, the second column shows the change in the number of working rigs between last week’s count (July 13th) and this week’s (July 20th) count, the third column shows last week’s July 13th 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 21st of July, 2017…

As you can see, pullbacks in drilling activity in Texas and Oklahoma by themselves accounted for this week’s rig count decrease, with New Mexico showing a corresponding 4 rig increase; however, where the Texas and Oklahoma decreases were is not apparent in the basin count….for Texas, we can check the Texas Oil and Gas District counts, which shows a net decrease of 6 rigs in the 2 core Permian basin districts, and a 2 rig increase in fringe Permian areas…so by that, we’d judge that Texas saw a net decrease of 4 rigs in the Permian basin, while 4 Permian rigs were simultaneously deployed on the New Mexican side of the state line…then including the single rig decrease in the Barnett around Dallas-Ft Worth would account for the state’s minus 5 total…meanwhile, Oklahoma’s count decreased by 3 despite the 2 rig increase in the core Cana Woodford basin because the Arkoma-Woodford was down a rig and 3 Granite Wash shutdowns appear to have been on the Oklahoma side of the Texas panhandle border…the Granite Wash rig count, by the way, included a natural gas rig startup and 4 oil rig shutdowns…but natural gas drilling was still down by 2 rigs despite that increase and the increase of a natural gas rig in Ohio’s Utica, because natural gas rigs were simultaneously shut down in the Marcellus of West Virginia, the Barnett of Texas, the Arkoma-Woodford of Oklahoma, and one “other” basin that Baker Hughes does not name…we should also note that outside of the major producing states shown above, Nevada also saw a rig shut down this week, leaving just one rig operating in the state, which is still more than a year ago, when there was no activity state-wide…

Rig Count Drops in Ohio Utica as Production Rises – The rig count across eastern Ohio’s Utica shale dropped to 16 during the week ended July 14, down from 18 recorded the previous week, according to the Ohio Department of Natural Resources.Permitting activity was also light in the Utica, as just one permit for a single horizontal well was issued during the week. Ascent Resources Utica LLC, based in Oklahoma City, secured a permit for a new horizontal well in Jefferson County.As of July 14, there are 2,483 permits issued for horizontal wells across the Utica in eastern Ohio. Of that number, 2,372 wells are drilled and 1,929 wells are in production.There were no new horizontal well permits for wells in the northern tier of the Utica play, which includes Mahoning, Trumbull and Columbiana counties.There were no new permits issued in neighboring Lawrence and Mercer counties in western Pennsylvania, according to the Pennsylvania Department of Environmental Protection. However, natural gas output from the Utica and Marcellus shale plays in the Appalachian Basin continues to rise, according to the U.S. Energy Information Administration’s drilling productivity report. The EIA estimates that natural gas production in August from wells in the Utica and Marcellus should increase at a rate of 328 million cubic feet per day compared to July. Oil production should also increase by 4,000 barrels per day compared to the same period.

Utica Shale production report released for Ohio – During the first quarter of 2018, Ohio’s horizontal shale wells produced 3,942,251 barrels of oil and 531,291,017 Mcf (531 billion cubic feet) of natural gas, according to the figures released today by the Ohio Department of Natural Resources.Natural gas production from the first quarter of 2018 showed a 42.85 percent increase over the first quarter of 2017, while oil production decreased by 3.6 percent for the same period. ODNR reports 3,942,251 bbl barrels of oil were produced during the first quarter of 2018, down from 4,090,500 bbl in 2017. The natural gas production was 531,291,017 mcf, up 42.85 percent from 371,921,659 mcf a year ago. The ODNR quarterly report lists 1,949 horizontal shale wells, 1,909 of which reported oil and natural gas production during the quarter. Of the wells reporting oil and natural gas results:

• • The average amount of oil produced was 2,066 barrels.
• • The average amount of natural gas produced was 278,454 Mcf.
• • The average number of third quarter days in production was 86.

All horizontal production reports can be accessed at oilandgas.ohiodnr.gov/production. Ohio law does not require the separate reporting of Natural Gas Liquids or condensate. Oil and gas reporting totals listed on the report include NGLs and condensate.

Natural-gas production keeps growing in eastern Ohio, despite low prices – Natural-gas production from shale deposits in eastern Ohio is surging, helped by the increase in pipelines in the area that get the gas to markets, and by greater efficiency by producers. Production from the Utica shale region jumped 43 percent from the first three months of 2018 from the same period of 2017, with production totaling 531.3 million cubic feet, according to Ohio Department of Natural Resources data released this week. The jump follows a 38 percent increase in production in the final three months of 2017. The jump in production comes even as prices for natural gas remain low. “There are more and more advances in technology and efficiencies,” said Jackie Stewart, state director of Energy In Depth, a research and education organization financed by the oil and gas industry. “That’s really the name of the game.” At the same time, producers are learning more about the region and where the best resources are, Stewart said. “There is some good data and core sampling,” she said. “There is a better handle of the geography.” When the Utica was first being developed, the region didn’t have the pipeline capacity to handle the growing production. In the several years since, the pipeline system in the region has expanded as demand for gas has grown. Power companies are depending more on gas to generate electricity, and more gas-fired power plants are being developed in the state to use that gas. Last month, the Ohio Power Siting Board approved construction of a natural-gas plant in Cadiz in eastern Ohio. Construction by Harrison Power is expected to start in October, with operation to begin by June 2021. It is the 10th natural-gas power plant approved by the board in the past five years. Also, Thai chemical company PTT Global Chemical is considering building a similar plant in Belmont County in eastern Ohio. Those plants will depend more on natural-gas liquids being produced in the Utica.

Fracking opponents blast Loudonville’s sale of water to Cabot – – A dozen foes of the Cabot Gas & Oil drilling projects in the area assailed Mayor Steve Stricklen and members of Loudonville Village Council on their appearance of support for the company at the council meeting Monday.The focal point of the comments was the village’s sale of water to the company, which is drilling a horizontal deep well in northern Green Township and which has sited two other projects, one at U.S. 30 and Ohio 511 in Vermillion Township and the other south of Jeromesville in Mohican Township.Village Administrator Curt Young confirmed that to date the village has sold 650,000 gallons of water to Cabot, earning $4,358 in sales revenue. As with all water customers, Cabot is paying 0.65 cents per gallon of water, the highest amount the village will sell water for in its tiered billing process.Asked by resident Dee Hinkle if the village could refuse sale of water to Cabot, Council Member Traci Cooper said “we can’t discriminate on who we sell water to. If we sell to one entity, we have to sell to all.”The opponents to the drilling projects disagreed. “You could require a buyer to disclose how they will use the water, and refuse service for fracking projects,” Annette McCormick said.”My fear is that they will take the waste from this water, which is contaminated by chemicals used in the fracking process, and pour it in to Charles Mill Lake,” Shelly Hootman of Jeromesville said. Stricklen said “the village’s water supply would be monitored closely, and if the inventory gets critically low, we can halt sales, but it will have to be all sales.” Young said the village’s treats 10 to 12 million gallons of water a month, “so I seriously doubt if our levels will get critically low.” “You don’t know,” Teresa Clark said. “Estimates are that it takes 4-7 million gallons to drill a well, and supplemental water is needed for ongoing fracking operations.”

Evacuation Lifted in Ohio After Chemical Spill from OFS Truck –Local authorities in Northeast Ohio were forced to evacuate about 75 residents and more than 20 homes for a few hours on Monday after hydrochloric acid leaked from an oilfield services (OFS) semitruck. A rusty valve is thought to be the cause of the leak, authorities said. A passerby called authorities around 7:30 a.m. on Monday after a vapor plume was spotted. Firefighters responded and called in a hazardous materials team at Predator Trucking Co. on U.S. Route 422 in Girard, about five miles north of Youngstown. Part of the road was closed, but reopened later in the morning when the evacuation was lifted.Ohio Environmental Protection Agency spokesman Anthony Chenault confirmed that the truck is owned by Texas-based ProFrac Services, which has operated in the Appalachian Basin for about two years. While authorities estimated that more than 2,000 gallons leaked from the truck, Chenault said regulators don’t expect to have an actual number until later this week. There were no injuries. Chenault said firefighters and the hazardous materials team contained the release with sand dikes. An environmental contractor was still at the site cleaning the spill on Tuesday. The acid is used commonly during well stimulation. It’s highly corrosive and mixed with water to dissolve contaminants such as scale and rust to clear the well and help oil and natural gas flow.

Roads open, evacuation ended after Weathersfield chemical leak — Route 422 and Tibbets Wick Road are open to traffic again. However, it could take four to five hours to clean up a chemical spill that forced an evacuation in Weathersfield Township. People who were evacuated from their homes in the area at around 7:30 a.m. Monday were allowed to return at around 11 a.m. Fire Cheif Ken Boring tells 21 News that 23 homes, the McDonalds, and Scenna Family Restaurant were evacuated after hydrochloric acid was found leaking from a tank at Predator Trucking North State Street.However, it is now known that the truck that was leaking is not owned by Predator Trucking, it is owned by Pro Frac, a company operating out of Texas.According to Pro Frac’s website, they have been operating in the Marcellus and Utica Shale areas since October 2016. Traffic was blocked off on Route 422 from Tibbets Wick Road to the Golf Dome as Hazmat worked to contain the leak using sandbags. Boring says about 1,000 gallons of acid leaked from a corroded valve on the 5,000-gallon tank. Cleanup crews from Cleveland and Pittsburgh have been dispatched to the scene. It’s expected to take four to five hours to clean up the spill, according to the chief. According to the EPA, hydrochloric acid is corrosive to the eyes, skin, and mucous membranes. Acute inhalation exposure may cause coughing, hoarseness, inflammation, and ulceration of the respiratory tract, chest pain, and pulmonary edema in humans. Acute oral exposure may cause corrosion of the mucous membranes, esophagus, and stomach, with nausea, vomiting, and diarrhea reported in humans. Dermal contact may produce severe burns, ulceration, and scarring.

Oil and Gas Wastewater Wells Disproportionately Located in Lower Income Communities in Ohio – Hydraulic fracturing or “fracking” wells used to procure natural gas produce large amounts of wastewater, which may contain toxic and radioactive compounds. The wastewater per well, ranging from 2 million to14 million liters, is most commonly injected underground where it has the potential to contaminate water supplies used by people and animals. A new study in Ohio led by researchers at the Yale School of Public Health finds that these oil and gas waste disposal wells are disproportionately located in communities that have lower per capita incomes and lower population density compared to areas without these waste sites, after controlling for other sociodemographic and geographic variables. Specifically, the odds of a census block group containing an injection well were 16 percent lower for each $10,000 increase in median income, and 97 percent lower per 1,000 people/mi2 increase. Race, age, education and voter turnout were not significant predictors of injection well presence. “Our findings suggest a pattern of environmental inequity and are consistent with findings from a Texas study reporting a greater proportion of disposal wells in high poverty block groups,” said Assistant Professor Nicole Deziel, Ph.D., the paper’s senior author. “Further research is needed to determine whether residents in census blocks with injection wells face increased risk of chemical exposures or adverse health outcomes.” Our findings suggest a pattern of environmental inequity. Potential pathways of water contamination include spills at the surface during the transport or initial injection of the wastewater or underground leakage. In the United States, there is a significant history of disproportionate placement of hazardous facilities, particularly waste disposal facilities, in communities with a lower average income and a higher proportion of minority residents; however, little is known about the characteristics of populations living near injection wells used in fracking. The findings are published in the journal Environmental Health Perspectives.

The Surprising Way Fracking’s Microbes Could Illuminate Heart Health – The heart is one of the most studied, yet mysterious, organs of our body. The rise in cardiovascular disease means that it’s received endless scrutiny, its arteries and veins extensively mapped out. But we still don’t quite understand how it works, and why or how heart disease occurs.Researchers have found an unexpected place for inspiration: the inside of hydraulically fractured – or fracked – oil and gas fissures within rocks..“What we learn about these fracking microbes could have the potential to help answer questions about human health – including how plaque forms in our arteries when we have cardiovascular disease,” according toMikayla Borton, Ohio State University environmental scientist and lead author of a recent study about microbe survival.It’s becoming increasingly clear that microbe interactions have a serious role in the formation of the microbes that dwell deep in the gut, where their network either keeps people well or makes them sick. “The microbes found in the fracking mines have parallels with microbes found in other protein-rich ecosystems, including the human gut, and soil,” Borton explained in a press release. Amicrobiome contains the genes of all of a person’s microbes, just as a liver is packed with all of a person’s liver cells. “It’s really important to know what these organisms can do – to grasp their (genetic) potential and metabolic interactions – and figure out what impact that might have on the ecosystem,” Borton said.

ESC takes steps to sell land back to authority – The Jefferson County Educational Service Center took formal steps at its July meeting to sell land, intended for use for a new office building, back to the Jefferson County Port Authority. The ESC had spent 2016 working on plans and obtaining acreage in the Jefferson County Industrial Park for a planned two-story, 10,000-square-foot building. The property cost $38,500. The building would have been the headquarters of the ESC, the Virtual Learning Academy and the Jefferson Health Plan. The funding plan didn’t hold, indicated ESC Governing Board President Larry George. The Jefferson County Port Authority has the repurchase on its agenda for its July meeting, scheduled for Friday afternoon. ESC Superintendent Chuck Kokiko offered an update on site visits that take place before the opening of the upcoming school year. He said an implementation plan for the Ohio Department of Education was submitted with the final report due in August. The site visits include checking on school occupancy and food permits more than 10 days ahead of the opening of the school year. Kokiko offered an update on the Utica Shale Academy and the Mahoning Unlimited Classroom. The shale academy graduated 18 students and served its first year as a dropout recovery school, meaning the majority of students are facing obstacles to graduation. He noted the school had 70 students on average last year and added a welding program at the New Castle School of Trades in East Liverpool. Kokiko said the online schools are facing new struggles with recording student hours in the wake of the ECOT failure. He said the state and auditors are evolving the rules for attendance hours. Students need 420 hours of instruction that have to be documented. If not, the school received reduced funding. He noted the Mahoning Unlimited Classroom was unable to document hours for all 160 students and is receiving funding for only 80 and faces a significant budget reduction.

CNX Cancels Plans for Pipeline to Gather Natural Gas from Deep Utica Test Pad — CNX Resources Corp. has stopped construction and canceled plans for a pipeline that would have served a multi-well pad in Indiana County, PA, where the company was testing a deep Utica Shale well to delineate the formation in the western part of the state.The company told the Pennsylvania Department of Environmental Protection (DEP) in May that it no longer intends to build and operate the Marchand 3 Pipeline to gather gas from the pad, raising questions about the test well in the area, which is near other prolific deep Utica wells, but still further north of successes in Westmoreland, Greene and Washington counties.In late March a DEP inspection of the Marchand pipeline construction revealed that earth disturbance activities had caused sediment laden water from unstabilized construction areas to escape erosion and sediment controls, leading to a discharge into what are state-designated high quality waters. CNX agreed to pay a $250,000 fine and has corrected the violations. The company has focused on building its Utica program in Ohio and Pennsylvania in recent years, while the Marcellus Shale has anchored sales volumes. CNX has applied completion designs from its Ohio Utica program and other lessons from newer wells in Pennsylvania to delineate the deep, dry Utica core in the southwest part of the state, where it’s been increasingly focused on stacked pay potential.

Environmental groups pressure Allegheny County officials to crack down harder on polluters – More than 50 protesters gathered outside the Allegheny County Courthouse on Friday to pressure county officials to crack down harder on air polluters. The group unraveled a scroll of complaints made through Carnegie Mellon University’s ‘Smell Pittsburgh’ app collected from September 2016 through June. It wrapped around the courthouse fountain nearly twice. Rita Botts, of Squirrel Hill, held a sign that said, “Mr. Fitzgerald: If we can’t survive in this air, then how can Amazon?” “I think the county is willing to use taxpayer funds to subsidize Amazon coming to our area, but not air quality,” Botts said. The protesters did not want the county to encourage new sources of pollution. The Shenango Coke Works plant on Neville Island was demolished earlier this year. The group is asking DTE Energy to develop the site into a solar energy farm, and wants Allegheny County Chief Executive Rich Fitzgerald to support the effort. “We’re asking Fitzgerald not to provide financial incentives to another polluter on the site,” said Angelo Taranto, co-founder of Allegheny County Clean Air Now. The group plans to attend the county’s Board of Health meetings starting Wednesday until they read all of the more than 11,000 complaints made through the app from September 2016 through June of this year, said Mark Dixon, a local environmental activist and filmmaker. With public comments at those meetings limited to three minutes, it could take a while. “It could take nine years to give less than two years of complaints,” Dixon said. On Monday, two organizations sued the county over its health department’s plans to use more than $10 million from the Clean Air Fund and Title V Fund on a project to renovate its office space in Lawrenceville. In April, an American Lung Association report ranked Pittsburgh is the nation’s 10th-worst region for short-term particle pollution.

Water Contamination May Well be Widespread Due to Drilling & Fracking – A State College-based fracking company recently paid $159,000 to settle water contamination claims brought by a group of families in Butler County. Rex Energy revealed the settlements in bankruptcy documents filed this month. The documents were part of the company’s Chapter 11 bankruptcy, which it filed in May. In its “Statement of Financial Affairs,” the company listed the settlements, of between $11,750 and $27,125, which were paid out on April 17. The settlements went to eight families in the Woodlands, a section of Connoquenessing Township, who began complaining about their water quality in early 2011, shortly after Rex began drilling gas wells near their homes. Several sued Rex. One couple, Janet and Fred McIntyre, claimed in their lawsuit that they experienced severe “vomiting, headaches, and diarrhea,” and said their water “had a strong smell and bad taste, as well as an oily sheen” shortly after Rex began operating in the neighborhood. Federal and state regulators did not think Rex Energy’s activities were the cause of the problem. Both the Department of Environmental Protection and the U.S. EPA examined water tests from before and after drilling, and concluded that oil and gas activities hadn’t damaged the water supplies. But the residents still complained. For a time, Rex provided them with water, but the company stopped in 2012. Many of the families buy their own water or receive it from a local church that runs a “water-drive” for the local community. John Stolz, an environmental microbiologist at Duquesne University, tested the water at 150 households in the Woodlands. He found 50 families had “significant changes” either in water quality or quantity since drilling began there. He was retained by the families that sued Rex as an expert witness, but the case never went to court. He said the water in the Woodlands is still bad. “It hasn’t changed – they’re still dependent on the volunteer water drive,” he said. “The other families that weren’t part of the case of course didn’t get any compensation whatsoever.”

ETP Mariner Liquids Pipe Racks Up More Pennsylvania Violations (Reuters) – Pennsylvania environmental regulators this week issued another notice of violation to Energy Transfer Partners LP’s Sunoco Mariner East 2 natural gas liquids pipeline for spilling drilling fluid in a wetland.It was the 65th notice of violation the Pennsylvania Department of Environmental Protection (DEP) issued the project since construction began in February 2017.As with other recent notices of violations, the DEP said ETP must provide a report describing how it will clean the spill, among other things, before it will allow the company to restart drilling at the site.Pipeline companies use horizontal drilling to cross under obstacles like highways and rivers.Those work stoppages, among other things, have significantly slowed progress on the $2.5 billion Mariner East 2 project, which ETP had planned to complete in the third quarter of 2017 but now expects to put in service in the third quarter of 2018. Those delays have forced some gas producers, like Range Resources Corp, to find another home for their liquids.The Mariner East project transports liquids from the Marcellus and Utica shale fields in western Pennsylvania to customers in the state and elsewhere, including international exports from ETP’s Marcus Hook complex near Philadelphia.The latest notice of violation was for a spill of about 3,500 gallons of drilling fluid into a wetland associated with horizontal drilling on July 11 in Jackson Township in Cambria County about 70 miles (110 km) east of Pittsburgh.Analysts have noted the state was citing ETP for some spills as small as 1 gallon likely due to increased scrutiny the Mariner project has received as it racks up a large volume of permit violations. Overall, the company has reported 111 spills into waters in the state and 91 spills in upland regions, according to the DEP, which included some of the same spills on both waters and upland reports.

New Mariner East troubles: Spill in western Pa., exposed pipeline outside Philadelphia — Sunoco is facing more challenges to its troubled Mariner East pipelines with a major spill of drilling fluids into a Cambria County wetland and the exposure of a section of the existing Mariner East 1 line in Chester County near Philadelphia. The company spilled about 3,500 gallons of drilling fluid into a wetland in Jackson Township, Cambria County during construction of Mariner East 2, according to the Department of Environmental Protection, which said it was informed of the incident on July 11. The spill prompted the DEP on Monday to issue its 65th notice of violation to Sunoco since it began building the natural gas liquids pipeline in February 2017. On Wednesday, the DEP issued yet another violation for a spill of only three ounces in Washington County.The new line’s continuing technical problems have led to three forced shutdowns, but Sunoco says it will begin operating by the end of September, thanks to the redeployment of an older line that will be temporarily used in sections of Delaware and Chester counties where the new pipe is unfinished.In Chester County, Mariner East 1 was recently exposed in a residential area of Uwchlan Township, renewing concerns about public safety and raising questions about why the pipeline hasn’t been re-buried almost three weeks after its operator, Sunoco, reported it to the Public Utility Commission.The 1930s-era pipeline, which carries natural gas liquids, was exposed in a creek at least 18 days ago, but township officials knew nothing about it until they were informed on Tuesday by the owner of the land where it’s exposed, said Mayme Baumann, a township supervisor. The township engineer found the exposed section in a creek that runs through the Marchwood neighborhood, and confirmed that the pipeline is Mariner East 1, Baumann said. The section, of about four feet, is “visibly corroded,” she said.

Mama Bears’ arrests signal new frustration of Delco pipeline protesters — Members of the Middletown Coalition for Community Safety were arrested and charged with trespassing during a protest on July 10. Members of the coalition say these “Mama Bears” are mothers and grandmothers who are fed up with a lack of response from state and local officials over their concerns about the Mariner East 2 pipeline. Allyson Galloway remembers the first time she heard about the pipeline running across the street from her home in Middletown Township. “To me, it seemed akin to living close to a gas station,” she said. “At least, that’s what we thought at the time.” That was before she and her neighbors caught wind of Mariner East 2, another planned pipeline along the same route that would carry 675,000 barrels a day of propane and other highly volatile gas liquids. Before they became amateur experts in pipeline safety. Before their organization into the Middletown Coalition for Community Safety. Before more than two years of attending meetings with politicians locally and in Harrisburg. And before two members of the coalition, part of a subset of mothers and grandmothers calling themselves “Mama Bear Brigade,” were arrested July 10 during a sit-in at a pipeline construction site a few yards from her front door. Members of the group, frustrated with what they call a lack of transparency from Gov. Wolf and Sunoco Logistics, the pipeline’s operator, say the demonstration is a turning point for their activism, one borne out of frustration. It represents a shift for them, they say, to a more active approach to having their voices heard.

Hydrocarbon Hypocrisy – Governor Andrew Cuomo and activist/actress Cynthia Nixon, opponents in September’s New York gubernatorial primary, don’t agree on much – but they are hell on hydrocarbons. Cuomo has outlawed natural-gas hydraulic fracturing, or fracking, in the Empire State, while Nixon wants to ban fracked gas from even entering the state. Never mind that the revolutionary energy-extraction method has over the past decade transformed America from a net hydrocarbon importer to the world’s leading energy producer. Both candidates promise to block new gas pipelines in New York, too.The two arrived at their identical positions from opposite directions. Nixon is a provocateur, not a policy macher. Her views are as otherworldly as her prescriptions. Cuomo, meanwhile, is unencumbered by ideals. His positions are calibrated for maximum political benefit – he polled for almost two years before imposing his fracking ban, for example.Cuomo knows that hydrocarbons fuel our civilization. They certainly power New York, an energy-gobbling giant; it leads American states in commercial consumptionof natural gas and is near the top in most other categories as well. But because of Cuomo’s ban, the state produces virtually no natural gas, despite vast hydrocarbon reserves in the Marcellus Shaleformation, located in the state’s needlessly impoverished Southern Tier. Neither Cuomo nor Nixon proposes substantive energy alternatives. Like all New Yorkers, the governor, a two-term Democrat, and Nixon, of Sex and the City fame, rely heavily on hydrocarbons themselves. Cuomo flits about the state in a helicopter, and he commands a massive, natural-gas-heated government complex in Albany. And what would Sex and the City have been without the energy-sucking bright lights of Broadway? (Nixon’s NoHo building uses gas heat – small beer, to be sure, but shouldn’t prohibitionists be held to a higher standard?)

Ethane is about to crack in Appalachia. Now it needs a market – The United States has been in the throes of a shale boom and bust for over a decade. The rocks are loaded with natural gas liquids – ethane, propane and other chemical cousins that are mingled in the more common methane heating gas. These more complex hydrocarbons are raw materials for a host of chemical and plastic products that are seeding dreams of a manufacturing renaissance in economically downcast Appalachia that would have been unimaginable 10 years ago. Like parents of prodigies amazed at their children’s unexpected gifts, many in the three-state region have been counting blessings in advance. The Mid-Atlantic Technology, Research & Innovation Center (MATRIC) in South Charleston, W.Va., has published an estimate that a full exploitation of Marcellus and Utica resources could in time create 25,000 jobs in chemical and plastics manufacturing. “Ethane is to the chemical industry what flour is to bakers,” said Steven Hedrick, MATRIC’s chief executive, at an energy conference last month. “Allow yourself to be inspired by what is about to happen in Appalachia.” “The shale gas is very wet and rich and very low-cost,” says Robinson, president of PLG Consulting, whose research work includes the Appalachian gas resources. In some parts of the region, the natural gas contains up to 65 percent ethane and other gas liquids, and 40 percent is common, Robinson said, creating a fertile building block for plastic products. But today, just a small part of the region’s potential ethane production moves by pipeline to Philadelphia, Canada and the Gulf Coast because there’s little else to do with it. “There’s a lot of trapped ethane in that region that needs a home,” Robinson said. Now the first home is under construction by Shell Chemicals along the Ohio River in Beaver County, Pa., 30 miles northwest of Pittsburgh. Shell’s steam cracking plant will break ethane apart and reconstitute it as ethylene gas. Three production units will then link ethylene molecules to create polyethylene plastic pellets, a ubiquitous component of packaging and housewares products. Through the same process, propane winds up as polypropylene fibers and resins, turned into carpets and high-performance plastics. Ohio hopes the next cracker is on its turf. In March, Gov. John Kasich (R) announced a stepped-up investment commitment by Thailand’s PTT Global Chemical and South Korea-based Daelim Industrial Co. Ltd. for a proposed cracking plant in Belmont County, in the heart of Utica’s “wet” shale gas area. Kasich said he is hoping for a go decision by the end of this year on a project that could be worth up to $10 billion.

Feds Say Land Shift Likely Caused Explosion, Pipeline Still at Risk – A natural gas pipeline explosion that occurred last month in Marshall County was likely caused by land subsidence, or movement, according to federal regulators. In a notice of proposed safety order, issued to TransCanada Corp. this week, the Pipeline and Hazardous Materials Safety Administration (PHMSA) said shifting land likely triggered the explosion of the Leach Xpress pipeline. “The preliminary investigation suggests that the failure was the result of land subsidence causing stress on a girth weld,” PHMSA said. The explosion occurred during the early hours of June 7 near Moundsville, West Virginia. No injuries or damage to private property were reported, but a fireball burned for several hours after an 83-foot section of the pipeline burst into flames, releasing more than $430,000 worth of natural gas. TransCanada’s own incident report released this week states the pipeline failed due to a landslide, but not one caused by heavy rainfall. The full federal investigation is still ongoing, but PHMSA’s proposed safety order states TransCanada should conduct extra surveillance and analysis on a 50-mile section of the pipeline that is buried in terrain geologically similar to where the explosion took place.TransCanada is the parent company of Columbia Gas Transmission LLC, which operates the 130-mile pipeline that runs from Majorsville, West Virginia to Crawford, Ohio. The pipeline went into operation in January and was not running at full capacity when the explosion occurred.In the order, the federal safety agency also said it identified six other locations where similar geography could cause the pipeline to fail. It outlines a series of additional corrective actions the company should undertake. TransCanada has 30 days to review the order and request consultation with PHMSA regarding the proposed suggestions.

Report: Pipeline That Exploded in Marshall County Remains At Risk – The federal agency in charge of investigating a recent pipeline explosion has notified its owner that six other areas on the same pipeline have issues that could cause another catastrophic event if they are not repaired. The Pipeline and Hazardous Materials Safety Administration issued July 9 a 13-step Notice of Proposed Safety Order to lower the risk of future explosions like the one that occurred June 7 on Nixon Ridge. The notice gives companies an opportunity to respond to a proposed correction plan before finalizing an order, which then makes the steps involved mandatory. PHMSA Eastern Region Director Robert Burrough sent the notice to TransCanada Corp. and its subsidiary, Columbia Gas Transmission LLC, which owns the 130-mile Leach Express pipeline. Burrough said in the notice that completing the steps outlined in the notice is necessary for the safety of the people and property near the 36-inch gas transmission line. “It appears that the continued operation of the Affected Segment, without corrective measures, poses a pipeline integrity risk to public safety, property, and the environment,” Burrough wrote. TransCanada did not return a call seeking comment by presstime. Several people who live or own property near the site of the June explosion declined to comment. TransCanada filed an incident report June 27 with the PHMSA regarding the June 7 explosion. In it, the company said it had sent the damaged pipeline to a metallurgy lab, but it had not determined the cause of the pipeline’s failure as of the time of the report.PHMSA said its preliminary findings suggest the failure was the result of land subsidence that caused stress on a girth weld. However, it also said the investigation is ongoing and the cause of the failure remains unknown. PMHSA’s preliminary findings indicated that the Leach Express pipeline was operating at approximately 86 percent to 89 percent of its maximum capacity of gas when the failure was reported around 4:55 a.m. June 7. That’s when a drop in pressure was discovered by a gas controller. The section of the pipeline was manually closed down by 5:20 a.m.In its incident report, TransCanada said $437,250 worth of natural gas was burned off in a fireball that could be seen as far as 50 miles away. Because Nixon Ridge – about 7 miles south of Moundsville – is isolated, no fatalities, injuries or property damage were reported as a result of the blast. Damage was limited to about 1,100 feet around the site.However, the company did say in the report that the property damage, not including the loss of the gas, came to $10 million. The Leach Express pipeline runs approximately 130 miles between Majorsville, Pennsylvania, to Crawford, Ohio.

TransCanada’s blast-damaged Leach natgas pipe returns to service (Reuters) – TransCanada Corp’s Columbia Gas Transmission said the section of its Leach Xpress natural gas pipeline damaged in a blast in West Virginia in early June returned to service on July 15, boosting gas output in the Appalachian region. Production in the region was expected to rise to 28.7 billion cubic feet per day on Monday from 28.1 bcfd on Friday, according to Thomson Reuters data. Before the June 7 blast, output in the region was about 27.5 bcfd. One billion cubic feet of gas can fuel about 5 million U.S. homes for a day. The Leach shutdown forced producers using the line to find other pipes to ship gas out of the Marcellus and Utica shale regions of Pennsylvania, West Virginia and Ohio. But traders noted that overall output was little changed after the blast as producers, such as Range Resources Corp and Southwestern Energy Co, found other pipes to ship their gas. Alternative pipelines include Dominion Energy Inc’s transmission system, Energy Transfer Partners LP’s Rover, Tallgrass Energy LP’s Rockies Express, Enbridge Inc’s Texas Eastern Transmission and Kinder Morgan Inc’s Tennessee Gas, according to analysts at S&P Global Platts. The 1.5-bcfd Leach pipeline in West Virginia and Ohio, whichentered full service at the start of 2018, transportsMarcellus and Utica shale gas to consumers in the U.S. Midwestand Gulf Coast. Last week, Columbia said it expected to return the damaged section of pipe on July 15 after gaining approval from the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA gave Columbia 30 days to respond to a list of corrective actions the agency proposed to improve the safety of the Leach pipe. Those actions included mechanical and metallurgical testing and enhanced surveillance and monitoring, according to the federal report, made available on Thursday. Since the blast, Columbia has identified six other points along the pipeline that PHMSA said are “areas of concern” based on soil conditions and steep slopes or indications of slips.

Pipelines, Birds and Coal Ash: A Look at Environmental Coverage Inside Appalachia (podcast) The Atlantic Coast Pipeline (ACP) and the Mountain Valley Pipeline (MVP) are two major interstate projects to move gas from the Utica and Marcellus shale formations to market, to another line that runs up and down the eastern seaboard, and to export terminals on the East Coast. Pipelines are considered the safest way to transport natural gas, crude oil, gasoline and other volatile substances that would otherwise have to be taken by rail or truck, which pose a far greater safety risk.The projects will create jobs through 2019. According to WorkForce West Virginia, as of July 2018, 2,745 people have been hired in West Virginia in the past year within the sectors of oil and gas pipeline, related structures construction, and support activities for oil and gas operations.But some landowners are concerned that the pipelines could damage the environment and upend their way of life. Environmental and citizen groups have brought half a dozen lawsuits collectively against both projects. Most challenge the legality of water quality permits issued on both the state and federal level. In late June, the 4th U.S. Circuit Court of Appeals halted some construction of the Mountain Valley pipeline in West Virginia, finding that the pipeline developer’s own documents showed the company could not complete construction quickly enough to comply with a federal water quality permit.Earlier this year, some protestors in Virginia and West Virginia took more extreme measures by sitting in trees to prevent construction crews from tearing down trees to build the Mountain Valley pipeline. We’ll talk with Virginia journalist, Mason Adams, who’s covered the tensionsamong protesters, law enforcement officials and the pipeline company this spring, as pipeline protesters began scaling trees to block the Mountain Valley pipeline.

Pipeline explosion in W.Va. cited by opponents of Mountain Valley Pipeline – An explosion of a natural gas pipeline in West Virginia was triggered by the same conditions – steep slopes prone to landslides – that exist along the route of the Mountain Valley Pipeline, a conservation group is warning. Work on the Mountain Valley project, which is cutting a swath through the mountains of Southwest Virginia, should be suspended pending a review of the potential danger of a similar explosion, the Indian Creek Watershed Association wrote in a request filed Tuesday with the Federal Energy Regulatory Commission. On June 7, the newly constructed Leach Xpress pipeline in Marshall County, West Virginia, ruptured and exploded into a ball of flames that could be seen for miles. A preliminary investigation by federal officials found that dirt and rocks from a landslide exerted pressure on the 36-inch diameter buried pipe, causing a weld to give way, according to a filing from the West Virginia-based watershed association. “The similarities of terrain – particularly the prevalence of steep slopes and landslide-prone areas along MVP’s 300-mile route through West Virginia and Virginia – make the Leach XPress explosion yet another wake-up call about the dangers of MVP’s selected route,” the request stated. Although pipeline opponents have been raising environmental concerns about erosion from construction sites in recent months, they say it’s time to address issues of public safety before the project begins to ship natural gas at high pressure by year’s end. “It’s an accident waiting to happen,”

US FERC chair sees plan on LNG permitting in days; LaFleur hopes for middle ground on pipes – US Federal Energy Regulatory Commission Chairman Kevin McIntyre said Tuesday that a formal agreement is likely “in the coming days” with other agencies to streamline permitting and trim LNG project review timelines. His comments come as industry and lawmakers have aired concerns that staff shortfalls at FERC could slow reviews even as US LNG export terminal developers are racing to line up offtake agreements and trade tensions are adding to their worries. “In just the last few days we have made truly significant strides in reforming the permitting process with our federal partners, eliminating duplicative efforts and instituting a streamlined procedure that will significantly reduce our LNG permitting timelines,” McIntyre said in a podcast released by the commission. “The details are still being hammered out, but we expect to have a formalized agreement in place in the coming days.” He denied a news report that FERC had told developers there would be delays of 12 to 18 months in LNG application reviews, saying FERC has issued no such letters. While he did not release details of the upcoming process changes, he said FERC is working with the departments of Energy and Transportation to improve coordination, in line with the administration’s memorandum of understanding encouraging one federal decision on permits. FERC is also taking a hard look at its own processes to find efficiencies, he said, and is working to hire more LNG engineers and to farm more out to third-party contractors. Pushing back on the notion that FERC has been slow to release environmental review schedules for projects, he said FERC will not issue schedules until it has all the needed facts and has implemented its improved processes. “FERC staff is very cognizant of the financial market impacts of its LNG project schedules,” McIntyre said. The timing can be affected by such factors as project complexity, completeness of initial applications, and timeliness of response to requests, and FERC does not give preference for one project over another, he said. With FERC soon faced with an even split of two Democrats and two Republicans, once Commissioner Robert Powelson leaves the agency in mid-August, it may also be experiencing pressure to act quickly on major policy questions before it, such as electric grid resiliency, review of the 1999 natural gas pipeline certificate policy and implementation of the Public Utility Regulatory Policies Act.

Pipeline Builders Abuse Eminent Domain – WSJ – Across the country activists are speaking out against the use of eminent domain to construct natural-gas pipelines. Some have climbed trees and refused to come down. The agency in charge of approving these pipelines – the Federal Energy Regulatory Commission, or FERC – is reconsidering how eminent domain, by which the government legally expropriates private property for public purposes, is used. While we stand with those who stand for individual rights – and enjoy a good tree-climb – protests like these can only go so far. The U.S. is a country of laws, and if a court rules that eminent domain can be used to construct a pipeline, then Americans must respect that ruling. But judges haven’t actually issued many such rulings. Right now FERC presides over a system that strips property owners of their rights without courts getting involved. When FERC approves the use of eminent domain to build a pipeline, landowners have the right to appeal to a federal court only after they have asked the agency to reconsider its decision and had their request denied. But FERC has developed the habit of granting these requests so that it can draw out the time it spends “thinking” about them. While FERC dawdles, the pipeline companies use eminent domain to snatch thousands of landowners’ properties free from judicial review. Furthermore, FERC’s approval comes with eminent domain authority, allowing pipeline companies to seize property before seeking other necessary approvals. In one instance, a company seized part of a Pennsylvania family’s property to build a FERC-authorized pipeline only to have the project fall apart when officials in New York refused to grant a permit to build another part of the pipeline. The taking, which also involved cutting down more than 500 of the family’s trees, was ultimately for nothing. As rotten as these procedural shenanigans are, FERC is guilty of a more consequential deception. Under current law, the agency can approve a pipeline without telling property owners that decisions will be effectively unreviewable unless they file an immediate appeal. When states have behaved this way, federal courts have deemed it unconstitutional. Yet FERC continues to harm eminent-domain victims by failing to inform them how to protect their rights. No one’s property should be taken without a real chance at judicial review. Property owners who go to court don’t always win, but some do. Property owners in both Pennsylvania and Texas have persuaded state judges to reject pipeline-related property seizures in recent years. Perhaps property owners who’ve been subject to eminent domain expropriations by FERC-approved pipelines would find similar success. The agency should afford them the chance to find out.

US pipeline builders brace for higher costs after Plains loses steel tariff case – US oil and natural gas pipeline builders are bracing for higher costs and potential delays after Plains All American lost its bid for an exemption from US steel tariffs for its 585,000 b/d Cactus II crude pipeline. Cactus II is one of three major oil pipelines starting up in the second half of 2019 that are expected to relieve a botteneck currently holding back Permian production and depressing Midland wellhead prices. It was the first major energy project to receive a ruling since the 25% steel and aluminum tariffs took effect. Plains said the $1.1 billion project would “move forward as planned,” but did not say whether the decision altered the Q3 2019 in-service target. The Commerce Department’s Bureau of Industry and Security recommended denying Plains’ request for relief from the 25% steel tariff after determining that 26-inch steel pipe needed for the project is produced in the US “in a sufficient and reasonably available amount and of a satisfactory quality.” Matthew Borman, deputy assistant secretary of export administration, denied the exclusion request July 13, according to a document made public Monday. In March, Commerce said companies would be allowed to seek exemptions if the steel or aluminum products are found not to be made in the US in satisfactory quality or “in a sufficient and reasonably available amount.” Plains said it was unfair to enact tariffs on steel orders placed months earlier. It bought steel pipe from a Greek mill in late 2017, and tariffs were announced in March. “Collecting a tariff on steel pipe orders for projects like this constitutes a tax on the construction of critical US energy infrastructure, which is a significant unintended consequence of current trade policy and risks US energy security and American jobs,” a Plains spokesman said in a statement. “We are reviewing our options to challenge this decision.” Plains had argued that while some US mills make 26-inch pipe, none use the “high-frequency welded” manufacturing technique the company requires.

It’s Time to Stop Investing in New Oil and Gas Pipelines – Last week the now-former head of the Environmental Protection Agency, Scott Pruitt, resigned amid a series of ethical breaches, including his cozy relationship with fossil fuel lobbyists. Government ethics experts said Pruitt’s connection to lobbyists working for the Canadian energy company Enbridge, at the time when the EPA approved expansion of an Enbridge pipeline, raised red flags. So-called environmental regulators like Scott Pruitt certainly can’t be trusted to uphold environmental laws. Last month Minnesota regulators approved Line 3, another controversial Enbridge pipeline that would cross lakes on Ojibwe treaty lands, affecting indigenous wild rice harvest, hunting and fishing. Following the news, Honor the Earth Executive Director and activist Winona LaDuke said “They have gotten their Standing Rock. We will do everything that is needed to stop this pipeline.” Resistance to pipelines like Line 3 is growing because pipeline spills are so common – much more common than you would think. Indigenous and environmental groups will continue to resist new pipelines because spills jeopardize land and livelihoods, especially when the pipeline crosses ecologically and culturally important places. Since 1986 there have been over 8,000 “significant” oil and gas spills reported by the Pipeline and Hazardous Materials Safety Administration(PHMSA) of the U.S. Department of Transportation. That’s equivalent to a major spill every two day for the past 32 years. “Significant” spills have a very specific definition – they either caused a fire, left someone injured, involved a large volume of oil or gas release or resulted in over $50,000 in damages. PHMSA classifies over 1,500 of these incidents as “serious,” meaning the spill resulted in a fatality or injury requiring in-patient hospitalization. Our interactive U.S. Climate Justice Map visualizes these spills alongside other data and stories. New pipelines are also being resisted because they make no sense in the context of climate change. Take the now iconic Keystone XL, a pipeline that would carry tar sands, some of the most carbon-intensive oil. According to a 2015 study funded by the Department of Energy, Canadian tar sands emits 18 percent more greenhouse gases when processed into gasoline compared to conventional crude. In November of last year TransCanada’s existing Keystone pipeline spilled 9,700 barrels of crude oil in rural South Dakota making it the 7th largest oil spill in the US since 2010.

Pence family’s failed gas stations cost taxpayers $20M+ (AP) – Vice President Mike Pence turns nostalgic when he talks about growing up in small-town Columbus, Indiana, where his father helped build a Midwestern empire of more than 200 gas stations that provided an upbringing on the “front row of the American dream.”The collapse of Kiel Bros. Oil Co. in 2004 was widely publicized. Less known is that the state of Indiana – and, to a smaller extent, Kentucky and Illinois – are still on the hook for millions of dollars to clean up more than 85 contaminated sites across the three states, including underground tanks that leaked toxic chemicals into soil, streams and wells.Indiana alone has spent at least $21 million on the cleanup thus far, or an average of about $500,000 per site, according to an analysis of records by The Associated Press. And the work is nowhere near complete. The federal government, meanwhile, plans to clean up a plume of cancer-causing solvent discovered beneath a former Kiel Bros. station that threatens drinking water near the Pence family’s hometown. To assess the pollution costs, the AP reviewed thousands of pages of court documents, tax statements, business filings and federal financial disclosures, as well as federal and state environmental records for Indiana, Kentucky and Illinois. The total financial impact isn’t clear because Indiana officials have yet to release cost figures for 12 contaminated areas. Other records are incomplete, redacted or missing.The public cleanup of more than 25 former Kiel Bros. sites in Kentucky and Illinois – where officials have done a better job keeping costs down – has been much less expensive, totaling about $1.7 million, according to an analysis of records obtained under each state’s public records law.Kiel Bros. has paid for only a fraction of the overall effort. In court documents , the company cited payment of $8.8 million in “indemnity and defense costs,” but also noted that $5 million of that amount came from the states.

Minnesota Pipeline Replacement Threatens a Repeat of ‘Standing Rock’ — Weeks after Minnesota regulators approved the replacement of an oil pipeline that crosses the state, Native American and environmental groups are starting to oppose the project with a similar playbook to a failed effort to stop the Dakota Access pipeline. Winona LaDuke, who lives 30 miles from the pipeline’s route on the White Earth reservation of the Ojibwe tribe, said three small protest camps have sprung up. To draw more protesters, she is planning a public campaign that includes a concert with the Indigo Girls in Duluth later this month, followed by a ride on horseback along the pipeline’s route. “All of us were at Standing Rock,” the site of the Dakota Access pipeline protests, said Ms. LaDuke, a co-founder of Honor the Earth, a Native American environmental group. “They’re a long ways from getting a pipe.” But the fight against the Enbridge Inc. pipeline known as Line 3 is different from efforts to stop the $3.8 billion Dakota Access one. The Line 3 project, which would carry crude oil from Alberta, Canada, across Minnesota to a terminal in Wisconsin on Lake Superior, is a replacement of a pipeline built in the 1960s. Enbridge said the existing pipeline requires as many as 900 repairs over six years. It has reduced capacity on the current line to 390,000 barrels a day, from 760,000 barrels a day, out of safety concerns. Opponents are focused on stopping the replacement, but many want the existing line shut as well. At the end of June, Minnesota utility regulators approved the project, which will diverge from the old route. Dan Lipschultz, a state utility commissioner, said the existing “highly corroded” line poses a danger to the environment and culturally sensitive areas. Supporters say they believe the new pipeline will be safer. “Our view is that we need this thing to be built to safely provide steady, reliable product downstream to the refineries,” said Bob Schoneberger, CEO of United Piping Inc., a pipeline contractor in Duluth that hopes to work on the project. Mr. Schoneberger started a group called Minnesotans for Line 3 that he said has several hundred supporters.

U.S. refinery capacity virtually unchanged between 2017 and 2018 – As of January 1, 2018, U.S. operable atmospheric crude distillation capacity totaled 18.6 million barrels per calendar day (b/cd), a slight decrease of 0.1% since the beginning of 2017 according to EIA’s annual Refinery Capacity Report. .The Refinery Capacity Report also includes information about secondary units – downstream refinery units that are used to process the products coming from the atmospheric crude distillation unit into ultra-low sulfur diesel and gasoline, as well as other products. Secondary refining capacity, including thermal cracking (coking), catalytic hydrocracking, and hydrotreating and desulfurization, increased slightly, up 1% from year-ago levels. These downstream capacity increases are primarily the result of changing processes that can increase refinery throughput rather than building new refining units. The number of operating refineries decreased from 141 on January 1, 2017, to 135 on January 1, 2018, largely reflecting classification changes in EIA’s survey: four refineries previously considered separate in survey data were merged into two, and two refineries were reclassified from idle to shut down. Consequently, the decrease in number of operating refineries does not necessarily represent a meaningful change in U.S. refinery operating capacity. Record refinery runs have helped accommodate increases in U.S. crude oil production, which averaged 9.4 million barrels per day (b/d) in 2017, an increase of 4.0 million b/d from the level in 2009. Gross crude oil inputs to refineries averaged 16.6 million b/d in 2017 compared with 14.3 million b/d in 2009. Over that period, operable refinery crude distillation capacity increased 945,000 b/cd, and utilization rose from 83% in 2009 to 91% in 2017, resulting in the 2.3 million b/d increase in gross crude oil inputs. Over the same period, U.S. crude oil imports decreased by 1.1 million b/d, and U.S. crude oil exports increased by 1.1 million b/d.

Texas fractionation capacity beyond the Mont Belvieu Hub, part 5. — Mont Belvieu may be the epicenter of NGL storage, fractionation and distribution along the Gulf Coast, but the rest of Texas offers almost half as much fractionation capacity – about 1 MMb/d of it – and a good bit of storage and pipeline connectivity too. These are particularly important facts in the summer of 2018, when demand for fractionation services in Mont Belvieu is at or near an all-time high and increasing volumes of NGLs are headed toward the hub. So what else has the Lone Star State got on the fractionation and NGL storage front? And are these assets experiencing the same strong demand as their counterparts in Mont Belvieu? Today, we continue our review of fractionators and key NGL-related infrastructure. With 2.1 MMb/d of existing fractionation capacity, more than 250 MMbbl of salt-cavern storage, a spaghetti bowl of incoming and outgoing pipelines, and ethane and LPG export terminals nearby, Mont Belvieu is the undisputed king to NGLs. And Mont Belvieu keeps growing; another 465 Mb/d of fractionators are under development and scheduled to come online over the next couple of years. But NGL production has been rising fast, and so has the need for more fractionation capacity – the mixed NGLs that come out of gas processing plants aren’t of use to anyone until they are fractionated into purity products (ethane, propane, normal butane, isobutane and natural gasoline). The problem is, new fractionators in Mont Belvieu haven’t been coming online as quickly as the need for them. Until recently, producers had been reluctant to commit to building new fractionation capacity, so existing plants have been running flat out to keep pace.

Houston company plans massive offshore terminal to export Permian oil – As more of the nation’s oil production flows to the Texas Gulf Coast, one Houston firm aims to build a massive offshore terminal to ship much of the nation’s record crude volumes overseas. Enterprise Products Partners said Tuesday it plans to construct an oil export terminal and dock miles off the Texas coastline that can accommodate the world’s largest crude-carrying vessels. Energy analysts estimated the project cost at $1 billion to $2 billion. Putting the terminal out to sea solves a critical problem for very large crude carriers, or VLCCs, more of which have been heading to Texas since the recent widening of the Panama Canal. Despite ongoing dredging efforts, water depths at Texas ports aren’t deep enough for these giant ships to fill to capacity. So Enterprise plans to build pipelines to run about 80 miles from its Houston-area network to the offshore terminal where the water is naturally deeper.The project could be years in the making. Enterprise expects the state and federal permitting processes alone to take roughly a year before it can commence construction.The plans come as rising U.S. oil production outpaces relatively stagnant domestic consumption, requiring more of the oil to be shipped overseas to developing markets in Asia and elsewhere.With Houston known as the world’s energy capital for its dealmaking and a cluster of corporate headquarters, the city is increasingly becoming the destination for much of the oil itself. Buoyed by West Texas’ booming Permian Basin, Enterprise believes the nation’s already record-high crude production will grow by another one-third from 2018 to 2022 to more than 13 million barrels a day, with most of that new oil leaving the country via the Gulf Coast. Pipelines are sending much of the crude to refining and port hubs near Houston and Corpus Christi.

Houston To Overtake Cushing As Key Hub – Houston is emerging as one of the great oil hubs in the world, and pretty soon it will be outfitted with an oil futures contract, which could cement its position.Intercontinental Exchange Inc. (ICE) announced plans to launch an oil futures with physical delivery in Houston, and the contract could launch as soon as this quarter, subject to regulatory review. “The Houston delivery point has become the pricing center for U.S. crude oil production and exports, and the new flat price futures contract is designed to serve hedging and trading opportunities in this growing market,” ICE said in a statement.Houston is now the “central delivery point for U.S. crude,” with proximity to upstream production in Texas, abundant refining and storage capacity along the Gulf Coast, and coastal facilities that have allowed a crude oil export boom over the past two years. The ICE Permian WTI futures contract will provide price discovery, settlement and delivery at Magellan Midstream Partners, L.P.’s terminal in East Houston, ICE said.“The recent price divergence between Cushing-based WTI and Brent is a reminder that although Cushing is a marker for local crude fundamentals in the midcontinent, it diverges for pricing waterborne U.S. crude,” Jeff Barbuto, Vice President of Oil Markets at ICE, said in a statement.For decades, Cushing, Oklahoma has served as the main delivery point for U.S. crude. Cushing is often referred to as the “pipeline crossroads of the world,” and was the designated point of delivery for the WTI contract on the New York Mercantile Exchange. Cushing also has the ability to store around 90 million barrels of crude oil, and indeed, the weekly change in inventory figures have become a closely watched metric since the market downturn began in 2014, with specific emphasis on Cushing’s figures. But the explosion of production from the Permian basin, and especially the lifting of the crude oil export ban by the U.S. Congress a few years ago, has undercut the importance of Cushing as an oil hub. West Texas oil can be funneled to the Gulf Coast and either refined or exported, all without the need to be routed through or stored in Cushing.

Texas set to pass Iraq, Iran as world’s third-largest oil producer | TheHill: Texas’s oil industry is set to surpass Iraq and Iran to become the third-largest oil producing region in the world, behind only Russia and Saudi Arabia. CNN Money reports that HSBC Bank predicted in a recent report that the state’s explosive growth in oil production over the last two years could result in Texas passing the two Organization of the Petroleum Exporting Countries (OPEC) members as oil prices rise around the world.”It’s remarkable. The [Permian Basin oil field] is nothing less than a blessing for the global economy,” Bob McNally, president of Rapidan Energy Group, told CNN. The surge in production comes just two years after the oil fields in Texas were seeing much lower production levels at the tail end of the Obama administration, according to CNN.”In 2014, it was amazing. 2016 was down in the dumps. Two years later, it’s back to crazy,” Texas railroad commissioner Ryan Sitton told the news network.Production cutbacks in Russia and OPEC nations have also led to a rise in U.S. oil prices, a boon for the economy as companies in Texas struggle to find qualified workers and the infrastructure required to support the surge.”To say there’s a shortage of bodies is an understatement,” Jeff Bush, president of CSI Recruiting president, told CNN. He said lower production under the Obama administration had left companies struggling to adjust to the economic boom in time.”These service companies took it on the chin the last few years. They’re trying to make hay while the sun shines, but you can’t do that if you don’t have people,” he said. “Right now, everything’s an issue: Water, sand, buildings, transportation. You name it,” Sitton added.

Report: Oil and Gas Production Is Making People Sick in Rural Texas – Reeves County, population 14,732, sits atop the Permian Basin and has been the site of some of the most frenzied hydraulic fracturing in the state. Though the fracking boom started in 2011, it didn’t reach the Franklins’ 10-acre plot of land until early 2017. That year, four wells were drilled nearby, some within a half-mile of their home. In the spring, Sue’s nose started bleeding and she began having breathing problems.Sue takes allergy medicine and uses nasal spray to help her breathe, as recommended by her doctor. Jim said he started experiencing “debilitating” headaches and respiratory problems around the same time from exposure to the emissions, which can include volatile chemicals like methane. “Now every morning we get up coughing and hacking… It makes us sick. We’ve both missed days of work because of being sick,” Jim said. The Franklins are one of five case studies included in a new report by two environmental advocacy groups on the health dangers faced by people who live near active oil and gas operations. Earthworks and Clean Air Task Force conclude that concentrated energy development activity in rural America is inundating nearby communities with greenhouse gases and volatile chemicals, making people sick and spurring climate change. One other Texan (a military veteran in frack-happy Karnes County) is featured in the report, along with people in rural areas of Utah, Pennsylvania and Ohio. Air pollution in Texas’ population centers is well-documented. But thanks to oil and gas development in broad swaths of sparsely populated areas across the state, the people who live in some small communities are also gasping for breath, said Alan Septoff, an Earthworks spokesperson. “There’s a general impression that air pollution is a problem in urban areas, that there’s dirty air in urban areas and clean air in rural areas,” he said. “But the oil and gas industry turns rural areas into urban areas in terms of air pollution.”

Lotteries, Shippers And Trends In Midland Price Differentials –Since early this year, the Midland crude differential has continued to widen, trading one day last week at a discount of $15.75/bbl to West Texas Intermediate (WTI) at Cushing, the widest spread since August 2014 before settling back to $11.25/bbl on Monday. The wide price differential is a result of fast-growing production in the Permian and bottlenecked takeaway pipelines. But the trajectory of this increasing price spread has been anything but smooth. Lately, we have seen a blip in the price differentials right around the 19th or 20th of the month. In each of the last three months, for a short-lived 24 to 48 hours, the Midland-Cushing price differential has narrowed by $2/bbl or more as Permian shippers have gone on feeding frenzies. Today, we look at these brief upticks in pricing and the pipeline and trader mechanics behind them. As we discussed in our All Dressed Up With No Where to Go series, Midland crude prices have taken an increasingly steep dive since the start of February 2018. After averaging a meager $0.34/bbl discount to WTI at Cushing in 2017, the Midland discount to WTI has increased to as much as $15.75/bbl in recent days and has averaged $12.80/bbl since the start of July 2018. But in the last few months, as pipelines have been consistently full, we’ve seen brief spikes in the Midland-Cushing differential around the middle of the month in April, May and June.

Union Pacific positions to move Permian crude in tank cars: executive – A shortage of pipeline takeaway capacity from the Permian Basin in West Texas is creating opportunities for Union Pacific to move crude oil in tank cars, a railroad official said Thursday. “The [Permian] is an interesting place and we’re definitely seeing some reduction in crude production due to the lack of pipelines,” Chief Marketing Officer Beth Whited said on an earnings webcast. “We have some capacity in our network and expect to see some results in the third and fourth quarter.” UP officials did not respond to queries on their targeted volumes. Loading terminals in Texas and New Mexico have a capacity of 300,000 b/d. But roughly 100,000 b/d of that capacity can be used to load crude as those facilities serve the needs for frac sands, Bernstein said in a report last month. Frac sands is used extensively by shale producers that utilize the hydraulic fracking process. A fast pace of growth in the Permian — currently projected to reach 3.690 million b/d by S&P Global Platts Analytics to be 3.5 million b/d — has resulted in producers seeking alternate market access like railorads and trucks to move their barrels from that land-locked basin to the US Gulf Coast. In the Western Canadian Sedimentary Basin — another land-locked basin — Canadian Pacific Railway sees the “potential” to double the volume of crude it hauls to refineries in the US Midwest and the US East Coast by 2019, as it hires more staff and adds additional locomotives, Chief Marketing Officer John Brooks said in an earnings call Wednesday. The railroad moved 20,000 car loads, or roughly 134,000 b/d, by operating 60 units trains each month in the second quarter, Brooks said. But CP now sees a potential to increase that run rate to some 266,000 b/d by late 2018 or early 2019, Brooks said, as no new pipelines get built out of the WCSB and oil sands producers still add new production. A rail car can typically move about 600 barrels and in the first quarter CP moved 17,000 cars.

Permian region natural gas prices fall as production continues to grow – The natural gas spot price spread between the Permian Basin, as priced at the Waha Hub in western Texas, and the U.S. national benchmark Henry Hub in Louisiana has grown considerably in the past year. Natural gas prices at Waha are nearly a dollar per million British thermal units (MMBtu) lower than Henry Hub prices. This spread widened as the ability to transport the increased natural gas production in the Permian Basin in western Texas and southeastern New Mexico was constrained by existing pipeline capacity. Based on estimates in EIA’s most recent Drilling Productivity Report, production of natural gas in the Permian Basin averaged 10.4 billion cubic feet per day (Bcf/d) in June 2018, which was 2.1 Bcf/d more than in June 2017. Much of this increase in production is associated natural gas, or natural gas produced as a byproduct of the increase in oil production from oil-directed rigs. As a result, the increase in natural gas production closely correlated with the increase in crude oil production in the Permian Basin, which averaged 3.3 million barrels per day (b/d) in June 2018, up 0.9 million b/d from the June 2017 level. The widening price differential between Waha and Henry Hub indicates pipeline capacity is already somewhat constrained. Producers may flare or vent the natural gas, although these disposal methods are regulated in Texas and New Mexico. Both states allow flaring from wells during drilling and immediately after completion. However, after a certain amount of time, producers can only flare natural gas after receiving exemptions from a state agency. If natural gas production continues to grow, and natural gas prices continue to fall, some producers in the area may cease oil production to avoid producing associated natural gas. Two pipelines – Comanche Trail and Pecos Trail – were completed in 2017 to export Permian natural gas to Mexico. Although these pipelines have a combined takeaway capacity of 2.6 Bcf/d, they are not expected to see significant flows until late 2018 or early 2019 when downstream pipeline infrastructure in Mexico enters service. The only other project expected to come online in 2018 is the combined expansion of the North Texas Pipeline and resumption of service on the Old Ocean Pipeline, which collectively will increase pipeline capacity out of the Permian by 0.15 Bcf/d.

Cooler Weather Helps Drag Down Natural Gas Futures as Production Keeping Bears in Control – Natural gas futures continued their recent slide Tuesday as strong production and cooler weather trends conspired to help drag down prices. In the spot market, more volatility in Southern California and retreating prices in the Northeast headlined a day of generally small adjustments; the NGI National Spot Gas Average gave back a penny to finish at $2.74/MMBtu. The August Nymex futures contract settled at $2.740 Tuesday, down 1.9 cents, after marking out a higher high ($2.788) and a lower low ($2.731) versus the previous day’s action. September dropped 2.3 cents to $2.707, while January settled at $2.968, down 2.1 cents on the day. The latest guidance issued on Tuesday showed slightly above-average cooling load overall the next two weeks but with “decent cooler risks” for the last week of July, and weather patterns appear unlikely to produce the kind of record-level demand that has been needed to drive prices higher this summer, according to Bespoke Weather Services. Prices initially climbed “on indications that production has declined more than expected from recent highs,” Bespoke said. “However, production still remained high enough that when combined with looser burns the last couple of days and especially significantly cooler medium- and long-range weather trends natural gas prices were forced to reverse, moving steadily lower through much of the morning before finding a low midday.” The Energy Information Administration (EIA) released its latest Drilling Productivity Report (DPR) this week and is forecasting month/month (m/m) production growth from the United States’ seven most prolific onshore oil and gas plays to continue in August. Total gas production production in August for seven key regions — the Anadarko, Appalachian and Permian basins, and the Bakken, Eagle Ford, Haynesville and Niobrara formations — is expected to reach 70.53 Bcf/d, compared to 69.47 Bcf/d in July, according to EIA. Total oil production from the same plays is forecast to increase to 7.47 million b/d from 7.33 million b/d in July.

Similar Themes from Forecasts Overnight as August Natural Gas Seen Near Even -August natural gas futures were set to open Wednesday near even at around $2.746/MMBtu as forecasters noted generally minor adjustments to the weather outlook overnight. The major weather models overnight carried a mix of changes but maintained the overall pattern of “mostly comfortable” temperatures sweeping through the Midwest and east-central United States over the next two weeks, according to NatGasWeather.“We continue to look toward the last couple days of July into early August for the next opportunity for more intimidating heat to return across the east-central U.S., which more data would still need to come on board with if the markets are to believe it,” the firm said. “…To our view, today will be an interesting day to see if prices are able to hold recent support” before Thursday’s Energy Information Administration (EIA) storage report, “where deficits are likely to increase slightly to near 525 Bcf as it’s favored to come in just under the five-year average of 62 Bcf. To illustrate how strong production has become, the same weather pattern last year would have resulted in a build nearly 30 Bcf lighter” than the injection expected in the report. Radiant Solutions reported similar themes in both its six- to 10-day and 11-15 day forecasts Wednesday.The six- to 10-day period trended “only slightly cooler in the Rockies. Otherwise, anomalous heat remains favored from the West toward Texas, where the more intense heat is focused in the early half and only fading slightly in intensity late,” Radiant said. “A pair of disturbances deepen a trough over the Great Lakes as the period progresses, with the feature helping to pull down a cooler Canadian air mass toward the Midwest during the second half of the period.” In the 11-15 day period, “near normal temperatures are expected in the Eastern Half, while aboves remain the favored solution from the West toward Texas,” the firm said.

Excess natural gas keeps pricing for Oklahoma producers discounted – Power producers across the nation continue to add natural gas generation to their fleets, the U.S. Energy Information Administration reports. Locally, Oklahoma Gas and Electric recently spent about $400 million to upgrade its Mustang power plant in Oklahoma City to include 462-megawatts of new generating capacity supplied by seven natural gas-fired turbines. You can’t burn natural gas fast enough to help Oklahoma producers, it seems.Despite the fuel’s increased use to generate electricity and an exponential growth in exports, a growing supply of gas continues to outpace demand and market pricing for it remains under $3 per thousand cubic feet. The catalyst behind that growth is new, “associated gas” production from shale wells, particularly ones targeting oil that are being drilled in the Permian Basin.Associated gas from wells in Oklahoma’s SCOOP and STACK fields also are a contributor, as are production increases involving natural gas wells being completed in the Utica and Marcellus shale fields in Ohio and Pennsylvania.On the demand side, the U.S. Energy Information Administration reports the nation:

• • Exported about 3.2 trillion cubic feet of natural gas in 2017, about double what it exported in 2013.
• • Is expected to use natural gas to generate 37 percent of the electricity needed to power homes and businesses domestically during this summer’s cooling season of June, July and August, nearing a record percentage that previously was set in 2016.
• • Is expected to export about 10 billion cubic feet per day of natural gas and natural gas liquids this year, and will export about 13 billion cubic feet per day of the product in 2019.

The myth of clean natural gas — Natural gas in particular has gotten wide attention, in part because it is much more carbon-efficient than coal when burned to produce electricity. The slogan was that it could serve as a “bridge fuel” between dirty coal and clean renewables – and thus fight climate change, at least relative to continuing reliance on coal.It’s increasingly clear, however, that natural gas is already nearly past its point of maximum usefulness. It should simply be phased out as soon as possible – as soon as coal is gone, it should be next on the chopping block, if not right beside. The first and biggest problem with natural gas is leaks. The fuel is largely composed of methane, and the smaller greenhouse gas footprint of the fuel relies on all that methane actually getting burned. If there are leaks at the wellhead, or the pipelines, or at the power plant, it cuts into the climate change benefit very quickly, because methane is tremendously effective at capturing heat. Measured over 20 years, a given quantity of methane captures about 86 times as much heat as the same amount of carbon dioxide. It turns out there are a ton of such leaks. Comprehensive leak data hasn’t been assembled, largely because the energy industry – and now the United States government, but I repeat myself – doesn’t want it to be. However, it’s a fairly simple procedure to fly a plane over the big drilling fields, test for methane concentrations, figure out a reasonable model of gas dispersal, and calculate a leak rate. Lo and behold, a recent study found (yet again) that leaks are so bad they basically cancel out the climate advantages of natural gas compared to coal (though natural gas still produces fewer poisonous fumes and heavy metals).

Minn. Supreme Court allows pipeline protesters to use climate ‘necessity defense’ – Climate change protesters are claiming victory in their effort to present an unusual “necessity defense” against felony charges stemming from efforts to shut down oil pipelines.The Minnesota Supreme Court declined Wednesday to review a ruling by the Minnesota Court of Appeals that backed the protesters, who will still face an uphill legal battle when their case goes to trial this fall. Emily Johnston and Annette Klapstein acknowledge turning the emergency shut-off valves on two pipelines in 2016 in Clearwater County of northwestern Minnesota as part of a coordinated nationwide action. Eleven activists were charged in all. The Court of Appeals ruled in April the two Seattle-area women can argue that they believe the threat of climate change from Canadian tar sands crude is so imminent that they were justified.

Colorado to accelerate cleanup of ‘orphaned’ oil, gas wells (AP) – Colorado’s governor ordered state regulators on Wednesday to accelerate the cleanup of inactive oil and gas wells whose owners have walked away.Gov. John Hickenlooper also told regulators to study whether the state requires companies to post a big enough bond before they start drilling. The bonds are designed to cover the cost of plugging inactive wells and cleaning up the sites if the company fails to do it.Colorado has about 260 wells considered “orphans” because no owner can be found, or the owner is unwilling or unable to deal with them. About 110 other oil and gas sites without wells on them are also orphaned.Hickenlooper, a Democrat, said that number will increase because some energy companies go out of business and previously unknown orphaned wells are being discovered.He signed an executive order directing the Colorado Oil and Gas Conservation Commission to categorize each orphaned well and site as high, medium or low priority and aim to clean up the high and medium priority sites by July 2023.The priority will be based on how many people live nearby, the environmental impacts of the site, how many spills the site has had and other factors.Hickenlooper told the commission to produce the list by Aug. 1 and update it yearly. Newly added sites should be cleaned up within two years if they are high or medium priority, he said. Hickenlooper said it could cost around $25 million to plug and clean up the known orphaned wells and sites.

The Colorado valley at stake in Trump’s oil boom – Ten thousand feet up, it’s possible to see the whole North Fork Valley from Dan Stucker’s plane. As the aircraft glides over sloping mesas with snow-dusted mountains, the land below resembles a vintage pioneer landscape.If President Donald Trump has his way, a new feature could arrive on this vista: oil and gas pumps. His administration is opening vast stretches of public land to energy companies, and among the forests and fields under Stucker’s plane, up to 95 percent of the valley could be available to drillers.The administration’s new policies would bring sweeping changes to this Rocky Mountain landscape, facilitated by a growing bond between federal officials and the oil and gas industry. Emails and other communications between government employees obtained by E&E News reveal directives and orders by Trump officials to shelve environmental policies to speed energy development. In one instance, Interior Secretary Ryan Zinke courted oil and gas drillers in private by assuring them that changes to federal land policy would make their companies more profitable. Documents show that some career employees in the Bureau of Land Management questioned whether drillers were being penalized adequately for major violations of environmental regulations. Interior Department staffers also pushed back on efforts by political appointees to put federal land up for auction before scientific assessments on the potential damage drilling could inflict on wildlife were finished. At other times, federal officials voiced concern that Trump’s drilling goals were more aggressive than oil industry wishes. One federal official was asked whether it would be possible to rejigger data to make it look like the government would sell more leases because she was worried about how companies’ lack of interest in drilling would look to administration bigwigs, according to an email E&E News obtained. These policies will set the nation on a future course of reliance on fossil fuels that cause climate change, more air and water pollution in rural areas, and new threats to endangered species. In return, the government charges oil companies as little as $2 per acre to lease the land for drilling.

Groups sue North Dakota over oil refinery near national park – Three environmental groups are suing North Dakota over an air quality permit that allows construction of an $800 million oil refinery about 3 miles (5 kilometers) from Theodore Roosevelt National Park. National Parks Conservation Association, the Environmental Law and Policy Center and the Dakota Resource Council filed the lawsuit in state court on Thursday, asserting that the state erred when it concluded the proposed Davis Refinery wouldn’t be a major source of pollution and wouldn’t negatively impact the park. The lawsuit asks a judge to declare the permit invalid and send the case back to North Dakota’s Health Department for further review. “We must protect the air quality in the national park, which visitors and surrounding community members breathe, and on which the stunning views and fragile ecosystems depend,” said Stephanie Kodish, clean air program director for National Parks Conservation Association. “This polluting oil refinery betrays the conservation values of the park’s namesake.” The 30,000-acre (12,000-hectare) park is named for the former U.S. president who ranched in the region in the 1880s and is revered for his advocacy of land and wildlife conservation. It’s a rugged and breathtaking area of hills, ridges, buttes and bluffs where millions of years of erosion have exposed colorful sedimentary rock layers, and is home to a variety of wildlife including prairie dogs, wild horses and bison. The park is the state’s top tourist attraction, drawing more than 700,000 visitors annually. Meridian Energy Group is developing the refinery to initially process about 27,500 barrels of oil daily, with room for expansion. The company maintains that the plant with modern technology will be “the cleanest refinery on the planet.” The lawsuit comes about two weeks after the Environmental Law and Policy Center and the Dakota Resource Council filed a separate complaint with North Dakota regulators requesting a study of the refinery’s location. The Public Service Commission is reviewing the complaint. The refinery also will need state water and wastewater permits, but it can begin building before receiving them. O’Clair said that, in light of the lawsuit, the company would be proceeding at its own risk.

ND oilfields set three new state records – North Dakota’s daily oil production in My broke the previous all-time high set in 2014, but that wasn’t the only new record set. As oil production hit 1.24 million barrels per day in May, natural gas production hit almost 2.32 billion cubic feet per day, with producing wells at 14,755 for the month – all new state records. Lynn Helms, director of the state Department of Mineral Resources, said Friday that May’s numbers “really shattered the old record” set in December 2014, by about 17,000 daily barrels, or about a 1.4 percent increase. North Dakota’s gas production in May also surpassed 70 billion cubic feet – a first in state history for a month, according to Helms. But for the first time since October 2017, state gas production missed its flaring goal of 85 percent gas capture, notching 83 percent, which Helms said was largely due to the Robinson Lake gas plant in Mountrail County being down in May for maintenance and upgrades. “We’re seeing natural gas increase at twice the pace of oil production, in terms of a percentage increase, and back in 2014, that wasn’t the case,” Helms said. “Today when you see a 1.6 percent increase in oil, you’re seeing twice that in gas production increases, and so it’s really straining the infrastructure.” Justin Kringstad, director of the North Dakota Pipeline Authority, also noted natural gas capacity and processing were strained by production growth. “It has narrowed from what it was in the previous months, but again, just challenges out there keeping up with this increasing drilling activity, new wells coming online, has been proving challenging for the industry as well, as once you get them connected, the network today just simply doesn’t have enough capacity to handle all that gas,” he said.

Tribal Chairman Sends Ominous 4-Word Letter to Keystone XL Pipeline Developer – The hotly contested Keystone XL Pipeline set to bring crude oil from Canada into the U.S. is chugging along. Developer TransCanada is preparing for construction in Montana and South Dakota, and the company decided it would give the Cheyenne River Sioux Tribe a heads up in a letter on Wednesday. On Thursday, Tribal Chairman Harold Frazier offered just four ominous words in response. “We will be waiting.” Native American tribes in the Midwest have been opposing the 1,179-mile long pipeline since 2008, and they’re not letting up. They nearly won the fight in 2015, when former President Barack Obama rejected a key permit. Then Trump came along and reversed that decision. Opponents worry what an oil spill could mean for their water, their land, and their health. And they have reason to worry. Keystone XL’s sister pipeline, Keystone, suffered a spill last year in South Dakota.Anyway, TransCanada wants to begin construction in Montana and South Dakota come 2019, so it’s getting ready. That means delivering construction materials and clearing out trees and plants to lay the groundwork for pipe installation. The project is still wrapped up in the courts, though. Tribes arechallenging its approval, and landowners are arguing to keep their land, so it’s not a done deal. That’s not stopping the company from doing what it can, though.

Zinke’s Real Estate Deal With Halliburton Chair to Be Investigated — The Department of Interior’s (DOI) inspector general wrote to Congressional Democrats Wednesday saying the office had opened an investigation into a real estate deal involving Interior Sec. Ryan Zinke and Halliburton Chair David Lesar, POLITICO reported.”You expressed special concern about the reported funding by a top executive at Halliburton and assuring decisions that affect the nation’s welfare are not compromised by individual self enrichment,” Deputy Inspector General Mary Kendall wrote to Democratic Representative Raúl Grijalva of Arizona, the ranking member of the House Natural Resources Committee, and other Democrats, POLITICO reported. “My office opened an investigation into this matter on July 16.”The investigation will asses whether the deal, uncovered last month, violated conflict of interest law.In June, POLITICO reported that a foundation started by Zinke and currently run by his wife granted a real-estate development backed by Lesar permission to build a parking lot on land originally donated to the foundation for a Veteran’s Peace Park that has yet to be built. The development, in the Zinke’s hometown of Whitefish, Montana, could increase the value of the land owned by their foundation.”Secretary Zinke doesn’t seem to take his responsibility to the public seriously,” Grijalva said in a statement reported by POLITICO. “He’s turned it into the Ryan Zinke show, which is more about waving his own flag above the building and doing personal business deals with his friends instead of protecting public lands and improving our environmental quality. This formal investigation is one of many he’s managed to pile up in his short and undistinguished tenure, and I join my Democratic colleagues in seeking the transparency and accountability that Republicans have so far not provided.” The DOI investigation comes little over a week after the U.S. Office of Special Counsel started a case file on whether Zinke violated the Hatch Act when he tweeted a picture of himself wearing socks embroidered with Trump’s face and “Make America Great Again” campaign slogan, CNN reported.

US unconventional oil production seen rising 143,000 b/d in August to 7.470 million b/d – US unconventional oil production is projected to rise 143,000 b/d in August to 7.470 million b/d, the US Energy Information Administration said, the second-highest month-to-month growth increase since the agency has kept such records. The EIA predicted an all-time high 144,000 b/d jump in output only a few months ago in a build from May to June. The agency said in its latest Drilling Productivity Report released Monday domestic unconventional natural gas production is forecasted to increase by 1.066 Bcf/d to 70.532 Bcf/d, a record-high and nearly twice the volume produced at end-2013 of around 36.5 Bcf/d.Moreover, Permian Basin drilled but uncompleted (DUC) wells rose 164 in June to 3,368, one of the largest recent monthly well builds. By comparison, the DUC build in was 169 in May and 133 in April.Total US DUCs rose by 193 on month to 7,943 in June.But the EIA said its DUC and production figures are sketchy since information is difficult to obtain now as little specific data is provided by E&Ps or midstream providers. “We may overestimate production due to constraints” in oil and gas takeaway capacity, EIA analyst Jozef Lieskovsky said. “We have watched [well completions] filings coming in and they are disappointing over the last few weeks. Lieskovsky and other industry sources are confident more information will be forthcoming during the round of second-quarter conference calls in the next several weeks. Until then, all eyes are on the Permian Basin of West Texas and southeast New Mexico, which EIA sees as far outdistancing other shale basins in unconventional oil production growth during August – up 73,000 b/d to 3.406 million b/d. Production in the Eagle Ford Shale of South Texas is forecasted to grow 35,000 b/d in August to 1.436 million b/d, while the Bakken Shale of North Dakota and Montana is pegged to grow 15,000 b/d to 1.297 million b/d. The Anadarko Basin of Oklahoma and the Texas Panhandle, is predicted to grow 10,000 b/d to 559,000 b/d, while the Niobrara Shale in Colorado and Wyoming is pegged to increase by 6,000 b/d to 611,000 b/d. The Appalachian Basin in Pennsylvania, Ohio and West Virginia is forecast at 4,000 b/d of oil growth in August to 118,000 b/d. The Haynesville Shale, in northeast Louisiana and east Texas, is targeted to remain flat in oil output in August at 43,000 b/d. The Appalachian and Haynesville plays are largely natural gas-prone basins with small crude outputs.

US Crude Oil Output Hits 11 Million bpd For First Time Ever (Reuters) – U.S. crude oil production last week hit 11 million barrels per day (bpd) for the first time in the nation’s history, the Energy Department said on Wednesday, as the ongoing boom in shale production continues to drive output. The gains represent a rapid increase in output, as the data, if confirmed by monthly figures, puts the United States as the second largest producer of crude oil, just behind Russia, which was producing 11.2 million bpd in early July, according to sources. “Eleven million would have made us the biggest producer in the world; but actually Russian production in June was above 11 million. So, this is kind of like the space race,” said Sandy Fielden, director of research in commodities and energy at Morningstar. The United States has added nearly 1 million bpd in production since November, thanks to rapid increases in shale drilling. “I don’t think production is plateauing at 11. It’s fully expected to grow beyond 11 – we won’t be topping out there,” said Scott Shelton, a broker at ICAP in Durham, North Carolina. Crude inventories increased 5.8 million barrels in the week to July 13, compared with analysts’ expectations for a decrease of 3.6 million barrels. Crude futures edged down on the data. U.S. crude was down 55 cents to $67.51 a barrel, while Brent dropped 39 cents to $71.77 a barrel. The benchmarks have gained steadily since bottoming out below $30 a barrel in early 2016; U.S. crude is up nearly 12 percent this year. Weekly production figures from the U.S. Energy Information Administration are notorious for revisions, as monthly data, released on a lag, shows U.S. production at 10.5 million bpd as of April. In the last several weeks, the EIA has rounded off U.S. production to the nearest hundred thousand barrels, so that figure had been stuck at 10.9 million bpd for over a month. This report comes amidst worries that infrastructure bottlenecks, which make it difficult for producers to get their oil to market, could soon start curtailing output.

Record Oil Output Does Not End US Import Dependence – In the first week of July, US net imports of petroleum products fell to just 1.67 million barrels per day, the lowest weekly total on record in at least three decades. The decline of net imports comes as the US has ramped up oil production in the last few years, which affects the net import figure in two ways. A steady increase in exports also pushes down the net import figure, Oil Price reported. Crude oil exports hit a high of 3 million bpd in the third week of June. However, the net import figure has been falling for years and a large part of that is the fact that the US has been scaling up exports of refined products, including gasoline, distillate fuel oil and propane, among others. This trend dates back longer than the recent rally in crude exports. In 2005, weekly net imports peaked, routinely topping 13 million bbd. This figure has currently plunged to less than 2 million bpd. While the US may not need oil and refined product imports as in the past, but the US is still completely enmeshed with the global market. In fact, as output of oil and refined products dramatically increased over the past few years, the volume of trade also rose sharply. When adding imports and exports, the total US trade in petroleum products hit 10.8 million bpd in June, the highest monthly total since 2005, dating back to when the US import dependence peaked.

The U.S. and Canada Are Preparing for a New Standing Rock Over the Trans Mountain Tar Sands Pipeline –In British Columbia’s southern interior, on unceded land of the Secwepemc Nation, Kanahus Manuel stands alongside a 7-by-12-foot “tiny house” mounted on a trailer. Her uncle screws a two-by-four into a floor panel while her brother-in-law paints a mural on the exterior walls depicting a moose, birds, forests, and rivers – images of the terrain through which the Trans Mountain pipeline expansion will pass, if it can get through the Tiny House Warriors’ roving blockade. The project would place a new pipeline alongside the existing Trans Mountain line, tripling the system’s capacity to 890,000 barrels of tar sands bitumen flowing daily from Alberta through British Columbia to an endpoint outside Vancouver. On May 29, the Canadian government announced that it would nationalize the Trans Mountain pipeline to assure the expansion would be built, putting up 4.5 billion Canadian dollars ($3.5 billion) to acquire the pipeline and other assets from the Texas-based energy giant Kinder Morgan. The purchase has dramatically raised the stakes of the fight for both the administration of Prime Minister Justin Trudeau and pipeline opponents like Manuel. Should construction begin as scheduled in August, the Tiny House Warriors expect waves of allies from Indigenous nations inside Canada and beyond to join them as they wheel 10 of the houses into the pipeline’s path. Near the pipeline’s terminus outside Vancouver, members of the Tsleil-Waututh Nation have constructed a traditional “watch house” from which to monitor the progress of construction. Resistance to the pipeline is already escalating: On July 3, seven pipeline opponents rappelled from Vancouver’s Ironworkers Memorial Bridge in a daylong blockade of tanker traffic associated with the existing Trans Mountain line. Last week, the Tiny House Warriors wheeled the homes into a provincial park that sits on the site of a historic village near Clearwater, British Columbia, in an assertion of their title to the land. On Saturday, the Royal Canadian Mounted Police singled out and arrested Manuel, whose livestream of the incident has garnered more than 500,000 views on Facebook.

Canada LNG Exports — Both West and East — Facing Global Cost Pressures, Says CERI – Formidable cost obstacles confront British Columbia (BC) plans to break into global liquefied natural gas (LNG) markets, while Nova Scotia export proposals face even higher hurdles, according to the Canadian Energy Research Institute (CERI).Supply costs exceed Asian and European spot market prices, a CERI study released Thursday said. The Competitive Analysis of Canadian LNG offers a sobering 125-page statistical portrait of the outlook for projects on the northern Pacific and Atlantic coasts.Even in long-term contracts that formerly placed high premiums on internationally traded gas, reductions of energy value indexes now make overseas export projects depend on oil price increases to make LNG from Canada profitable, CERI researchers said.CERI, an industry and government-supported independent agency, painted its Canadian LNG portrait with economic modeling. No inside knowledge is revealed about projects that lately aroused BC and Alberta industry optimism by attracting Asian participation and awarding construction contracts ahead of a final investment decision, LNG Canada and the associated Coastal GasLink pipeline.In CERI’s model as of May, the cost of landing LNG from BC and Alberta tight gas and shale formations on the benchmark Asian spot market in Japan would have been US$8.35/MMBtu — or US80 cents more than the going price at the time. Export projects on Canada’s east coast would sink far deeper into the red because bans against tapping unconventional gas with horizontal drilling and hydraulic fracturing in Nova Scotia, New Brunswick and Quebec eliminated potential nearby supplies,said CERI.

TransCanada celebrates Mexico pipeline start-up – TransCanada Corp. announced earlier this week that its Topolobampo natural gas pipeline in northern Mexico is complete and has been placed into service. The approximately $1.2 billion, 348-mile (560-kilometer) 30-inch diameter pipeline extends from El Encino in Chihuahua state to Topolobampo, located near the city of Los Mochis in Sinaloa state, according to a TransCanada press release. The Topolobampo Pipeline can deliver up to 670 million cubic feet of natural gas per day to markets in Chihuahua and Sinaloa, the company noted. Moreover, the company added that Topolobampo serves as an upstream interconnection with its Mazatlan Pipeline to form a combined 540-mile (870-kilometer) gas pipeline system in northwestern Mexico. “The completion of the Topolobampo and Mazatlan pipeline system is an important milestone for TransCanada as we continued to expand our portfolio to deliver natural gas to serve Mexico’s electric generation needs,” Robert Jones, president of TransCanada Mexico, said in a written statement. “We are developing the infrastructure to feed new power plants and convert existing fuel oil and diesel power plants, thereby reducing both the cost of electricity and greenhouse gas emissions. We are proud of the way we overcame technical challenges and completed this difficult project safely.” According to TransCanada, the pipeline route’s geography made constructing Topolobampo particularly challenging. The pipeline crosses the Tarahumara mountain range near Chihuahua’s famed Copper Canyon, and TransCanada pointed out that it used novel techniques such as a raised bore to cross “extreme steep cliff faces.” Moreover, the company said that construction called for the use of air cranes to transport pipes to remote locations. Nearly 3,500 employees and contractors worked on the Topolobampo project, which TransCanada noted was one of the first projects in Mexico to include federal government-led Indigenous consultations with impacted communities. The Topolobampo-Mazatlan system represents more than one-quarter of the gas pipeline mileage that TransCanada either operates or is building in Mexico.

TransCanada pipeline in Mexico expected to help displace fuel oil with US gas – TransCanada said Monday its 670 MMcf/d Topolobampo Pipeline has begun commercial service, part of an effort to move more US natural gas to northwest Mexico to serve power generation demand. The $1.2 billion project, which provides the upstream interconnection with the company’s Mazatlan Pipeline, is expected to reduce fuel oil consumption in the power markets in the Mexican states of Sinaloa and Sonora.While TransCanada is focused on its significant pipeline interests in its home country and the eastern US, it also has been seeking to leverage its footprint in Mexico to take advantage of the shifting market dynamics resulting from energy reforms there. Mexico continues to be a major importer of US LNG, but that demand will decrease over time as other pipeline projects in the country come online.”We are developing the infrastructure to feed new power plants and convert existing fuel oil and diesel power plants, thereby reducing both the cost of electricity and greenhouse gas emissions,” Robert Jones, president of TransCanada’s Mexico unit, said in a statement.The project involved the construction of approximately 348 miles of 30-inch diameter pipeline from El Encino, near the city of Chihuahua, to Topolobampo, near the city of Los Mochis, Sinaloa. Combined, the Topolobampo and Mazatlan pipelines form a system that adds over 540 miles of energy infrastructure that provide natural gas to power plants and industrial and urban markets in Mexico.Data from TransCanada Mexico show that Topolobampo Pipeline began taking intermittent receipts of gas on June 18, and since July 2 flows have increased to an average of 65 MMcf/d. Supply gas for the Topolobampo Pipeline is coming from interconnections with the Tarahumara pipeline in Chihuahua, which is itself taking gas from Oneok’s Roadrunner pipeline in West Texas. Topolobampo Pipeline also delivers gas to interconnection systems in Sinaloa, which supply IEnova’s 510 MMcf/d Guaymas-El Oro pipeline that serves the Mexican state of Sonora. While near-term utilizations are expected to be well below capacity, Topolobampo Pipeline remains a much needed outlet for Permian Basin associated gas production, which is itself nearing takeaway capacity constraints.

EIA’s Big Bullish Storage Miss Shakes Up Natural Gas Market Lulled by Production – A bullish surprise from the Energy Information Administration’s (EIA) weekly natural gas inventory report served up a clear reminder that even as production growth has dominated the market’s thinking as of late, it hasn’t made a dent in storage deficits — yet. EIA reported a 46 Bcf injection into Lower 48 gas stocks for the week ended July 13, roughly 10 Bcf below consensus estimates based on major surveys. The build also fell below the five-year average 62 Bcf injection. Last year, EIA recorded a 31 Bcf build for the period. With Thursday’s report marking the second straight week that injections have lagged the five-year average by a wide margin, the bears — firmly in control heading into the session largely because of surging production — seemed to concede that they had gone too far given the risks posed by large inventory deficits. The number, released at 10:30 a.m. ET, immediately sparked a rally for the prompt month, with prices popping to $2.750-2.760 after languishing down around $2.710 earlier in the morning. By 11 a.m. ET, the August Nymex futures contract was trading around $2.770, up about a nickel from Wednesday’s settle. Prior to the report, surveys showed the market looking for a build closer to 55 Bcf. A Bloomberg survey of traders and analysts had produced a median 56 Bcf build, with a range of 44 Bcf to 65 Bcf. Intercontinental Exchange EIA Financial Weekly Index futures had settled Wednesday at an injection of 54 Bcf. Bespoke Weather Services said this week’s figure came in “a whopping 15 Bcf below our expectation. This indicates that there was significantly more holiday in the print last week than expected, and that the natural gas market is materially tighter” than previously thought.

Analysis: Bullish build in US gas storage leads to price gains as deficit widens – Despite a drop in gas-fired power demand, natural gas storage inventories increased at a much lower volume than the market expected last week, which expanded the deficit to historical levels and provided uplift to prompt-month futures for the first time in weeks. US natural gas in storage increased by 46 Bcf to 2.249 Tcf for the week ended July 13, the US Energy Information Administration reported Thursday morning. The build was much less than an S&P Global Platts’ survey of analysts calling for a 59 Bcf addition. The injection was more than the 31 Bcf build reported during the corresponding week in 2017 but below the five-year average addition of 62 Bcf, according to EIA data. As a result, stocks were 710 Bcf, or 24%, less than the year-ago level of 2.959 Tcf and 535 Bcf, or 19%, less than the five-year average of 2.784 Tcf. The injection was smaller than the 51 Bcf build reported the week prior, even though cooler weather prompted a drop in gas-fired power demand by 1.1 Bcf/d, according to data from Platts Analytics. However, this was somewhat offset by a 400 MMcf/d drop in Canadian imports and a 200 MMcf/d dip in domestic production. The report featured net withdrawals in two of the EIA’s five storage regions, including a 5 Bcf pull in the South Central region and a 1 Bcf draw from the Pacific. NYMEX August Henry Hub natural gas futures climbed 5 cents to $2.77/MMBtu following the storage announcement. Prompt month futures have dipped steadily for the past several weeks. The gas market has been in a downturn since mid-to-late June, whereby much of the 2018 strip is approaching or is at year-to-date lows. However, from a fundamental perspective, the market is trending more bullish. The week ending July 20 looks to feature an even smaller build of only 36 Bcf, according to Platts Analytics. Searing temperatures across the Northeast, Southeast and especially in Texas boosted power burn by 2.5 Bcf/d from the week prior. On Tuesday, power burn struck a year-to-date high of 40.3 Bcf/d. Also, with relatively hot weather forecasts spanning the remainder of the month, it is likely that total July power burn will top the current record of 36.6 Bcf/d realized during July 2016. It is currently averaging 37.3 Bcf/d month to date, according to Platts Analytics, which is 3.3 Bcf/d more than last July. Texas alone makes up 400 MMcf/d of the increase.

End-of-season natural gas storage inventories are forecast to be the lowest since 2008 – The U.S. Energy Information Administration’s (EIA) Short-Term Energy Outlook (STEO) forecasts working natural gas inventories on October 31 will be 3,470 billion cubic feet (Bcf), 365 Bcf (10%) lower than the five-year average and 346 Bcf (9%) lower than last year’s level. This forecast inventory level would be the lowest end-of-October storage level since 2008, when inventories ended the month at 3,412 Bcf. The natural gas storage refill season is traditionally April 1 – October 31, when natural gas is typically put into underground storage facilities to prepare for increased winter demand for space heating, particularly in the residential and commercial sectors – although injections into storage often occur in the first few weeks of November. Current New York Mercantile Exchange (Nymex) winter strip futures prices – the average price for November through March futures contracts – for this coming winter have remained relatively unchanged since January 2018 and are similar to the last 3 years’ winter strip futures prices in July. The winter strip price can reflect expectations of meeting peak winter demand based on factors such as natural gas inventories heading into the winter or production expectations. Because inventories are forecast to remain lower than the five-year average, which would put upward pressure on the futures price, other factors are contributing to downward pressure on winter-strip prices:

• Expectations of continued production growth: The STEO forecasts total U.S. dry natural gas production for November 2018 – March 2019 will average about 84 Bcf per day (Bcf/d), up 6 Bcf/d from the winter period last year.
• Expectations of average injection levels for the remainder of the refill season: Net injections reported since April 27 have generally followed the five-year average, with the forecasted end-of-season level 3% lower than the five-year minimum.

A key uncertainty for end-of-season inventory levels is weather-driven demand from the electric power sector. Natural gas demand for electricity generation tends to peak in the summer months with demand for air conditioning. The current temperature outlook for August – October is for above-normal temperatures throughout the Lower 48 states. The STEO is currently forecasting natural gas use in the electric power sector for August – October to average about 31 Bcf/d, up 2 Bcf/d from last year for the same time period. While production is largely forecasted to keep up with growing sector demand and exports, more extreme weather could lead to higher demand for natural gas-fired generation and, subsequently, a lower inventory level by October 31.

Senate to consider bill boosting U.S. LNG exports to Europe, taking aim at Russian gas– Two days after President Donald Trump’s controversial summit with Russian President Vladimir Putin, some Senate Republicans are looking to hit Russia where it hurts – it’s energy sector. Sen. John Barrasso, R-Wyo., introduced legislation Wednesday calling for the Department of Energy to speed up approval of LNG exports to Europe, where Russia has long had a strangle hold on natural gas supplies. Likewise, the bill would authorize U.S. sanctions on Russian energy projects, including the planned Nordstream 2 pipeline, which would run across the Baltic Sea from Russia to Germany.”It is in the national security interests of our country to help our allies reduce their dependence on Russian energy,” Barrasso said on the senate floor. “”Where those countries don’t see it for themselves, we need to show them how important it is for their own security.” With Republicans anxious to prove their anti-Russian bonafides, Congress is expected to consider in the weeks ahead numerous pieces of legislation designed to punish Russia for its meddling in the 2016 presidential election.That follows a summit in Helsinki Monday in which Trump, standing alongside Putin, said the Russian president had made a “strong and powerful” case that his country had not interfered in the election. He also questioned unanimous consensus among U.S. intelligence officials that Russia had in fact interfered – a statement the president attempted to walk back Tuesday. Under the legislation, U.S. Permanent Representative to NATO Kay Bailey Hutchinson, the former Texas senator, would be directed to encourage members of the North Atlantic Treaty Organization to work with the United States to “achieve energy security for its members and partners in Europe and Eurasia.”