Oil, Gas, And Fracking News Reads: 09February 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 08 February 2020.

This article is a feature every Monday evening on GEI.

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

Oil in bear market, posts longest losing streak in 14 months; natural gas rigs at another 39 month low

Oil prices fell for a fifth consecutive week this past week as demand destruction in China overwhelmed OPEC’s attempts to stabilize prices …after falling 4.9% to $51.56 a barrel on fears of a pandemic last week, the benchmark price of US light sweet crude for March delivery opened lower again on Monday and tumbled to its lowest level in more than a year, as the coronavirus outbreak’s impact on Chinese demand further hammered crude prices, with U.S. crude falling 2.8%, or $1.45 per barrel, to settle at $50.11 per barrel, as Chinese oil demand was said to have dropped by about three million barrels a day, or by 20% their of total consumption…prices recovered early on Tuesday, as OPEC was reportedly considering a production cut as large as a million barrels per day, but turned lower late in the day and still ended down 50 cents at $49.61 a barrel, now firmly in bear market territory….oil prices then jumped 4% on Wednesday after reports of coronavirus drug breakthrough and hung on to gain $1.14, or more than 2% to $50.75 a barrel, even as world health experts said treatments for the virus had not yet been found… oil prices moved more than $1 higher again on Thursday after an OPEC+ panel recommended a provisional cut of 600,000 barrels per day in oil output, with traders further encouraged when Russian Foreign Minister Lavrov backed that OPEC+ proposal, but then flattened out to close at $50.95 a barrel, a gain of just 20 cents on the day, as the coronavirus outbreak continued to sap energy demand…oil prices turned lower on Friday after Russian Energy Minister Novak said they needed more time to assess the situation before committing to output cuts and finished down 63 cents at $50.32 a barrel, as traders continued to weigh the expected coronavirus fallout.….oil prices thus ended 2.4% lower for the week in extending their losing streak to the longest since November 2018..

On the other hand, natural gas prices managed a small gain this week on a shift in the forecast to more seasonable weather…after falling 1.6% to $1.841 per mmBTU on mild weather and a supply glut last week, the contract price of natural gas for March delivery fell to another 4 year low on Monday, ending down 2.2 cents at $1.819 per mmBTU, on forecasts for warmer weather through mid-February than was previously expected…but prices jumped 5.3 cents from that 4 year low on Tuesday, as the weather models finally shifted to indicate near-normal temperatures for most of the country in the outlying weeks...however, prices were falling again early on Wednesday, but trimmed those losses on reports of another drop in gas production and ended just 1.1 cents lower at $1.861 per mmBTU….then, even with a larger draw of natural gas from storage than was expected, prices only moved up a tenth of a cent on Thursday, and then fell back four-tenths of a cent on Friday to end the week at $1.858 per mmBTU, a gain of less than 1% on the week..

The natural gas storage report on the week ending January 31st from the EIA indicated that the quantity of natural gas held in storage in the US fell by 137 billion cubic feet to 2,609 billion cubic feet by the end of the week, which left our gas supplies 615 billion cubic feet, or 30.8% higher than the 1,994 billion cubic feet that were in storage on January 31st of last year, and 199 billion cubic feet, or 8.3% above the five-year average of 2,410 billion cubic feet of natural gas that has been in storage as of the 31st of January in recent years….the 137 billion cubic feet that were withdrawn from US natural gas storage this week was more than the average forecast for a 126 billion cubic feet withdrawal by analysts surveyed by S&P Global Platts, but it was way less than the 229 billion cubic feet withdrawal reported during the corresponding week of last year, and also less than the average 143 billion cubic feet of natural gas that have been pulled from natural gas storage during the last week of January over the past 5 years….

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending January 31st showed that because our net oil imports and oil production were little changed while demand for oil from refineries continued to be weak, we had surplus oil to add to our stored commercial supplies for the thirteenth time in the past twenty-one weeks….our imports of crude oil fell by an average of 46,000 barrels per day to an average of 6,615,000 barrels per day, after rising by an average of 229,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 96,000 barrels per day to 3,413,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 3,202,000 barrels of per day during the week ending January 31st, 50,000 more barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was 100,000 barrels per day lower at 12,900,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 16,102,000 barrels per day during this reporting week..

US oil refineries reported they were processing 15,972,000 barrels of crude per day during the week ending January 31st, 48,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that an average of 479,000 barrels of oil per day were being added to to the supplies of oil stored 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 349,000 barrels per day less than what what was added to storage plus what our oil refineries reported they used during the week….to account for that disparity between the apparent supply of oil and the apparent disposition of it, the EIA just inserted a (+349,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in one or more of the oil supply & demand figures we have just transcribed… (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) indicated that the 4 week average of our oil imports fell to an average of 6,565,000 barrels per day last week, now 12.3% less than the 7,487,000 barrel per day average that we were importing over the same four-week period last year….the 479,000 barrel per day net addition to our total crude inventories was all added to our commercially available stocks of crude oil, while the quantity of oil stored in our Strategic Petroleum Reserve was unchanged….this week’s crude oil production was reported to be 100,000 barrels per day lower at 12,900,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 12,400,000 barrels per day, while a 1,000 barrel per day increase Alaska’s oil production to 485,000 barrels per day still added the same rounded 500,000 barrels per day to the rounded national total….last year’s US crude oil production for the week ending February 1st was rounded to 11,900,000 barrels per day, so this reporting week’s rounded oil production figure was 8.4% above that of a year ago, and 53.1% 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 87.4% of their capacity in using 15,972,000 barrels of crude per day during the week ending January 31st, up from 87.2% of capacity the prior week, but still quite a bit below the recent average refinery capacity utilization for the last week of January…as a result, the 15,972,000 barrels per day of oil that were refined this week were 4.0% below the 16,463,000 barrels of crude that were being processed daily during the week ending February 1st, 2019, when US refineries were operating at 90.7% of capacity….

With the small increase in the amount of oil being refined, gasoline output from our refineries was much higher, increasing by 745,000 barrels per day to 9,903,000 barrels per day during the week ending January 31st, after our refineries’ gasoline output had decreased by 377,000 barrels per day over the prior week…but even after this week’s big increase in gasoline output, our gasoline production was only fractionally higher than the 9,856,000 barrels of gasoline that were being produced daily over the same week of last year….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 3,000 barrels per day to 4,976,000 barrels per day, after our distillates output had increased by 25,000 barrels per day over the prior week…after this week’s small change in distillates output, our distillates’ production for the week was still 2.8% below the 5,121,000 barrels of distillates per day that were being produced during the week ending February 1st, 2018….

Even with the big increase in our gasoline production, our supply of gasoline in storage at the end of the week decreased for the first time in thirteen weeks and for the 15th time in 33 weeks, falling by 91,000 barrels to 261,144,000 barrels during the week ending January 31st, after our gasoline supplies had increased by 1,202,000 barrels to a record high over the prior week….our gasoline supplies decreased this week despite the jump in production because our exports of gasoline rose by 337,000 barrels per day to 986,000 barrels per day, while our imports of gasoline rose by 133,000 barrels per day to 676,000 barrels per day and because the amount of gasoline supplied to US markets increased by 140,000 barrels per day to 8,933,000 barrels per day…even after this week’s decrease, our gasoline supplies were 1.3% higher than last February 1st’s gasoline inventories of 257,893,000 barrels, and 4% above the five year average of our gasoline supplies for this time of the year, which historically has been near the annual peak…

Meanwhile, with the decrease in our distillates production, our supplies of distillate fuels decreased for the 13th time in 19 weeks and for 28th time in the past 44 weeks, falling by 1,512,000 barrels to 143,235,000 barrels during the week ending January 31st, after our distillates supplies had decreased by 1,289,000 barrels over the prior week….our distillates supplies fell again this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 310,000 barrels per day to 4,211,000 barrels per day, even as our exports of distillates fell by 208,000 barrels per day to 1,175,000 barrels per day while our imports of distillates rose by 72,000 barrels per day to 19,4000 barrels per day….but even after this week’s decrease, our distillate supplies at the end of the week were still 3.0% more than the 139,013,000 barrels of distillates that we had stored on February 1st, 2019, even as they slipped to about 4% below the five year average of distillates stocks for this time of the year…

Finally, with most of this week’s crude supply and demand metrics little changed, our commercial supplies of crude oil in storage rose for the sixteenth time in thirty-three weeks and for the thirtieth time in the past 52 weeks, increasing by 3,355,000 barrels, from 435,009,000 barrels on January 31st to 431,654,000 barrels on January 24th…even after that increase, our crude oil inventories remained roughly 2% below the five-year average of crude oil supplies for this time of year, but remained more than 34.5% higher than the prior 5 year (2009 – 2013) average of crude oil stocks after the last week of January, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first rose above 400 million barrels….even though our crude oil inventories had generally been rising over the past year, except for during the past summer, after generally falling until then through most of the prior year and a half, our oil supplies as of January 31st were 2.7% below the 447,207,000 barrels of oil we had stored on February 1st of 2018, while still 3.5% above the 420,254,000 barrels of oil that we had in storage on February 2nd of 2017, while at the same time falling to 14.5% below the 508,592,000 barrels of oil we had in commercial storage on February 3rd of 2016, during a period that we were adding 10 million barrels per week to storage…

This Week’s Rig Count

The US rig count was unchanged over the week ending February 7th, after falling 20 out of the 24 prior weeks, and hence remains down by 27% from the end of 2018…..Baker Hughes reported that the total count of rotary rigs running in the US was unchanged at 790 rigs this past week, which was still down by 259 rigs from the 1049 rigs that were in use as of the February 8th report of 2019, and 1,139 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business…

The number of rigs drilling for oil increased by 1 rig to 676 oil rigs this week, which was still 178 fewer oil rigs than were running a year ago, and much less than the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations fell by one to 111 natural gas rigs, the fewest natural gas rigs deployed since October 21st 2016, and hence another 39 month low for natural gas drilling, down by 84 gas rigs from the 195 natural gas rigs that were drilling a year ago, and way down from the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to the rigs drilling for oil & gas, three rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, one in Washoe County, Nevada, and one in Lake County, California, compared to a year ago, when there were no such “miscellaneous” rigs deployed..

Offshore drilling activity in the Gulf of Mexico increased by 2 rigs to 23 rigs this week, as a drilling rig was added offshore from Texas, while another rig concurrently began drilling in Louisiana waters…with 22 rigs now drilling in Louisiana waters in addition to the one offshore from Texas, the Gulf of Mexico count is now up by 4 from from a year ago, when 19 rigs were drilling offshore from Louisiana and none were operating in Texas waters…and since there are no rigs deployed off other US shores elsewhere at this time, nor were there a year ago, the current Gulf of Mexico rig count as well as the count of last year is equal to the national total in both cases..

The count of active horizontal drilling rigs was unchanged at 711 horizontal rigs this week, which was still 212 fewer horizontal rigs than the 923 horizontal rigs that were in use in the US on February 8th of last year, and also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was up by 1 rig to 45 directional rigs this week, but those were also down by 12 from the 58 directional rigs that were operating during the same week of last year…. on the other hand, the vertical rig count was down by 1 rig to 33 vertical rigs this week, and those were down by 35 from the 68 vertical rigs that were in use on February 8th of 2019…

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of February 7th, the second column shows the change in the number of working rigs between last week’s count (January 31st) and this week’s (February 7th) count, the third column shows last week’s January 31st active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 8th of February, 2019…

4 rigs were pulled out of Texas Oil District 8, or the core Permian Delaware while rigs in the other Texas Permian districts were unchanged, so the 3 rigs that were added in New Mexico were in the western reaches of the Permian Delaware…Oklahoma’s changes include the oil rig that was added in the Ardmore Woodford, the natural gas rig that was pulled out of the Arkoma Woodford, and an oil rig that was pulled out of the Cana Woodford, while two more Oklahoma rigs were removed from other Oklahoma basins not tracked separately by Baker Hughes…in addition to the natural gas rig that was pulled out of the Arkoma Woodford, another natural gas rig was pulled out of West Virginia’s Marcellus, while a natural gas rig was added in the Eagle Ford of Texas, where an oil rig was shut down at the same time…the Eagle Ford now has 3 rigs targeting natural gas formations, and 67 rigs drilling for oil..

Utica Shale well activity as of Feb. 1 —

• DRILLED: 154 (154 as of last week)
• DRILLING: 124 (123)
• PERMITTED: 478 (473)
• PRODUCING: 2,434 (2,434)
• TOTAL: 3,190 (3,184)

Six horizontal permits were issued during the week that ended Feb. 1, and 12 rigs were operating in the Utica Shale. Top counties by number of permits:

• 1. BELMONT: 673 (670 as of last week)
• 2. CARROLL: 525 (525)
• 3. HARRISON: 499 (496)
• 4. MONROE: 428 (428)
• 5. GUERNSEY: 280 (280)
• 6. JEFFERSON: 262 (262)
• 7. NOBLE: 227 (227)
• 8. COLUMBIANA: 163 (163)

Column: Anti-protest law serves energy interests, not Ohioans – Ohio’s General Assembly is once again playing fetch for that wonderful group of people who do so much for Ohio: Polluters. An Ohio House committee OK’d Senate Bill 33 last week; the Senate passed it last year. It purports to shield protect “critical infrastructure” – pipelines, fracking rigs, maybe even that telephone pole in front of your house – from those silly Ohioans who want to protect our state’s water, air and land. In committee testimony last year, Jen Miller of the League of Women Voters of Ohio. warned that SB 33 is so broad that “even innocuous acts like … posting flyers on telephone poles could be considered unlawful, because a telephone poll is considered critical infrastructure and the term ‘damage’ is quite vague.” SB 33 does indeed define phone polls as critical infrastructure, but in fairness, only if a pole is fenced or has a warning sign. Still, knowing how utilities slice and dice laws, what’s to stop a pole’s owner from adding a tiny-print “warning” to a pole’s asset or ownership tag – those metal slivers about as big as a stick of Doublemint. So if SB 33 passes, take care before you tape a flyer to a phone pole, hoping someone has found your pal Fido or Kitty, because you might get busted as an eco-terrorist. You’d think Ohio’s current laws against trespassing and vandalism aren’t enough to protect “infrastructure.” But of course SB 33′s real aim to is to shut up Ohioans concerned about the state’s air, water and lands. In the eyes of the state Senate, so far, and maybe soon in the eyes of Ohio’s House, an Ohioan is entitled to free speech only if she or he thinks Ohio’s environment is peachy keen. SB 33 is based on “model” legislation written by the American Legislative Exchange Council. A pithy explainer posted in September by Greenpeace’s Connor Gibson: “[ALEC] is a one-stop -shopping outlet for large companies seeking state legislators to move their agenda through statehouses, coast to coast.” Charles Koch, the right-wing zillionaire, has been a big ALEC booster. Ohio’s General Assembly has long been has been ALEC-friendly, and SB 33 sponsored by Sen. Frank Hoagland, a Republican from Jefferson County’s Adena, is the latest item of ALEC merchandise on display. The Ohio Senate passed the bill 24-8 in May, with Republicans and one Democrat, Sen. Sean O’Brien, of suburban Warren, voting “yes.”

JobsOhio puts $20 million toward possible petrochemical site – The state’s economic development organization has given $20 million for site preparation for a potential petrochemical plant in Belmont County. The grant brings to $70 million the amount the state has invested in the project. Companies expect to announce this summer if they are moving forward with the plant.JobsOhio has invested $20 million in an eastern Ohio site being considered for a massive petrochemical pThe state’s economic development organization said Friday it awarded the grant to Thai chemical company PTT Global Chemical America and its South Korean partner, Daelim Industrial Co. With this award, JobsOhio has committed $70 million in grants and loans to the project, according to JobsOhio records.Economic development officials announced in 2015that PTT was considering the site along the Ohio River near Shadyside in Belmont County for the project. PTT later brought on Daelim as a partner.A similar project is being developed by Royal Dutch Shell in western Pennsylvania.The plant would take ethane, a component of natural gas, and break it down to produce ethylene, which is used in chemical manufacturing. The county is an attractive site because of its proximity to the plentiful, cheap natural gas of the Marcellus and Utica shale formations in Ohio, Pennsylvania and West Virginia. The plant would be built on the site of FirstEnergy’s former R.E. Burger power plant, which closed in 2011. If the companies proceed, it would be an economic boon for eastern Ohio, employing several thousand workers during construction and several hundred once the plant became operational.But critics have complained about potential greenhouse gas emissions from the plant.The companies said Friday that they anticipate making a final decision on whether to proceed by July. The $20 million allows site preparation to continue, said Dan Williamson, a spokesman for the companies.

Montage Slashing Appalachia Spending by 44% — Montage Resources Corp. has joined its Appalachian peers by announcing it will cut capital spending this year by nearly 50% from the midpoint of 2019 guidance.The company issued a 2020 budget this week of $190-210 million, or a 44% decrease at the midpoint of the latest 2019 spending forecast of $357.5 million. Montage has not yet released its year-end financial results. The company was formed early last year after a merger between Appalachian pure-plays Blue Ridge Mountain Resources and Eclipse Resources. Production has increased steadily since, and the company said it likely would remain unchanged this year. Production of 570-590 MMcfe/d is forecast for 2020, an increase of about 6% year/year Appalachia’s leading producers already have announced spending cuts and lower growth rates for 2020 as gas prices have continued to fall since last year. Montage said it has 56% of this year’s natural gas production hedged at a weighted average floor price of $2.64/MMBtu. The strip shows gas well under $2.50 for the remainder of the year.The company also said it would focus primarily on its liquids-rich acreage in Ohio’s Marcellus Shale. This year’s production is still expected to consist of 80% natural gas and 20% oil and liquids.Given the Utica’s performance in the state, operators have focused less on the Marcellus. Only 51 Marcellus wells have been drilled in Ohio, compared to 2,712 Utica wells. Montage started ramping up its activity in the play in 2019.Montage plans to drill 17-20 gross wells and complete 18-22 gross wells this year. The company plans to drill about 65% of its wells in the Marcellus, with the remainder targeting the Utica.

Enbridge prepping to replace pipeline under St. Clair River – Enbridge crews are doing preparation work this week, as the company moves to replace a section of its Line 5 pipeline running beneath the St. Clair River. The 65-year-old line that delivers Canadian crude oil to Michigan and Ontario, crosses the U.S. Canada border at the St. Clair River from Marysville to Sarnia. It’s a 1,000 kilometre-long line stretching from Sarnia all the way to Superior, Wisconsin. The first phase of the project involves getting the area ready for construction activities. Spokesman Ken Hall said the work will take place at their pipeline right-of-way, between St. Clair Parkway and Virgil Ave., and along the south side of Lasalle Line adjacent to the Shell refinery. “We’re going to place construction mats on our easement, and along the side of Lasalle Line where we’ll be stringing the pipe,” said Hall. “Once that’s done, we’ll bring the pipe in and we’ll be welding it all in place. It’s a long string of pipe that we’ll then prepare to pull back to the American side. So, in the next couple of weeks, you’ll see trucks coming in and flatbeds bringing the mats and cranes. There will also be more pick up trucks as our workers start to assemble and weld the pipe.” Hall said there will be 50 to 60 workers on the Canadian shoreline over the next couple of weeks. He said there will be a temporary access ramp off the south shoulder of Lasalle Line. Restrictions will typically be in place between 7 a.m. and 7 p.m. daily for about two weeks. Drivers are encouraged to slow down and be prepared for slow-moving vehicles. Enbridge plans to start horizontal directional drilling under the river in early March, which will bury the pipeline even deeper than before. The project, estimated to cost $20 million, is scheduled to be completed by July.

The well next door: East Pittsburgh and North Braddock diverge on the local impact of proposed fracking – On either side of the invisible border between North Braddock and East Pittsburgh, you can see, hear and sometimes smell the Edgar Thomson Steel Works below. But the prevailing view of a proposal to frack on the mill site is dramatically different on the two sides of that line. East Pittsburgh’s leaders, guided by an environmentalist group, in January tried to hamstring the two-plus-year-old proposal to drill for natural gas on the U.S. Steel mill site. That borough’s five-member council, in 2017, backed drilling with just one dissenting vote. But a council with three first-term members voted Jan. 21 for a one-two punch of zoning-related measures with the potential to knock the site entirely out of East Pittsburgh, potentially forcing the would-be driller back to the beginning of the arduous permitting process. Some North Braddock officials, by contrast, have taken the position that revenue from fracking could help their borough address blight. Nobody yet knows the amount of money the neighboring boroughs could get if fracking was permitted on the mill site, but “if it was a sizeable amount, it would open opportunities: Perhaps go out and borrow some money and tear down some houses,” said North Braddock Borough Manager Doug Marguriet, whose municipality struggles with 400-odd vacant buildings. East Pittsburgh Councilwoman Stacey Simon isn’t swayed by estimates that fracking on the site could bring her borough $60,000 or more. “Our budget is small, but it’s over $1 million and, to me, that’s really not worth it when you think about the long-term impact [fracking] could have,” Simon said. “Nobody wants to buy a house near a fracking well, or most people don’t.” U.S. Steel has argued that having a fuel source right on the Edgar Thomson property, powering its operations, would strengthen the company’s operations in its home region. “Having available clean burning and competitively priced energy resources would provide our Mon Valley facilities, and the many good paying, union jobs they support, with a key advantage in a fiercely competitive global steel market,”

“A Nationwide Fracking Ban Would Be Invaluable for Human Health”: Physicians for Social Responsibility Applauds First Proposed Nationwide Ban on Fracking – – Physicians for Social Responsibility (PSR) applauded the first legislative proposal for a nationwide ban on fracking for natural gas and related operations, including extraction, processing, transport and export. The proposed bill, introduced in the U.S. Senate by Senator Bernie Sanders (D-VT), would greatly benefit health and the climate, the national physician-led organization stated.In light of the bill’s announcement, PSR released the following comment:“Physicians for Social Responsibility applauds the introduction of legislation for a comprehensive fracking ban. A nationwide fracking ban would be invaluable for human health,” said Barbara Gottlieb, Environment and Health Program Director, Physicians for Social Responsibility.“Fracking harms human health, contaminates huge amounts of water, and pollutes the air. It exposes local communities to chemicals known to be toxic to humans and animals.“Scientific studies have documented high levels of serious health impacts among people who live near active fracking sites. Studies have found that living near active fracking wells is associated with increased rates of hospitalization for cardiac, neurological, urological and cancer-related issues. Studies have also linked proximity to active fracking to premature birth, low birth weight and congenital heart defects.“Recent investigations have even documented that fracking wastewater can be radioactive, especially in the Marcellus Shale. Yet we have seen fracking wastewater trucked through communities, used as irrigation water, and even spread as a de-icer on roads.“It’s not only local communities who are at risk. All of us are endangered, because when fracked gas leaks into the atmosphere, it accelerates climate change. And gas leaks into the atmosphere at every step of the way, from the well sites to the processing equipment to the pipelines to the distribution lines that carry gas to our homes. Fracking is speeding up the climate change juggernaut even as we hurtle towards the cliff. “PSR and our colleagues in Concerned Health Professionals of New York have highlighted the scientific evidence of fracking’s harm to health in the encyclopedic fracking science Compendium. Based on the evidence, PSR has supported a total ban on fracking for years and would welcome making that ban nationwide.”

These Southwestern Pa. reps who support fracking have direct sources of income from fracking companies Though natural-gas drilling, aka fracking, only really started in Pennsylvania about 10 years ago, it has gained a political hold on Pennsylvania that any industry would envy. Virtually all statewide elected officials in the Keystone State support fracking. Republicans do so enthusiastically, but even Democrats who are calling for better environmental regulations still defend the industry as a necessary and important source for jobs in rural areas. Despite this widespread support, research shows that fracking has led to well-water contaminations and copious amounts of methane being spewed into the atmosphere. Additionally, the industry failed to deliver on the manufacturing jobs it promised would be created by drilling for natural gas. Only a handful of progressive and environmentally focused politicians have come out in total opposition to fracking. And when criticism of the industry is made public, it often becomes a lightning rod, as when Pittsburgh Mayor Bill Peduto said last year that fracking should be rolled back and future petrochemical plants should be avoided. In response, Democratic Gov. Tom Wolf, Democratic Allegheny County Executive Rich Fitzgerald, and Republican House Speaker Mike Turzai condemned Peduto’s statement. Any high-profile criticism of the industry tends to provoke ardent defense from its supporters, and that goes beyond just words: some area legislators might also personally benefit financially from a more robust natural gas industry and fewer regulations keeping it accountable. Last November, the government-accountability group Eyes on the Ties revealed that three Southwestern Pennsylvania state legislators have direct incomes related to the natural-gas industry, including one that is a part-owner of a company that supplies equipment to fracking companies. All three of them are champions of the fracking industry, and have voted to cut regulations for natural-gas drilling in the state.State Rep. Josh Kail (R-Beaver) owns stake in his brother’s fracking-related company, among other ties to the industry. State Sen. Elder Vogel (R-New Sewickley) invests in two energy companies with ties to Pittsburgh regional fracking. And state Sen. Camera Bartolotta (R-Monongahela) has leased the mineral rights of her property to natural-gas companies.

Some shale gas reserves aren’t what they used to be — A new round of impairments is underway in the oil and gas industry, where companies are forced to recalculate and reduce the value of their assets to reflect a down market. CNX Resources Corp., a Cecil-based exploration and production company, joined the fray Thursday by writing down $446 million in assets in Central Pennsylvania. The drop means the oil and gas reserves in those areas are no longer considered economic and will not be developed in the near future. The reason for the change was continued low natural gas prices, which have been putting a damper on corporate earnings for many months. Next month, Downtown-based EQT Corp., the largest natural gas producer in the country, is expected to write down between $1.4 billion and $1.8 billion in assets, the company said in a public filing earlier this month. That comes on the heels of a blockbuster $10 billion impairment by Chevron Corp. last month, more than half of which was attributed to Appalachian oil and gas assets. Chevron announced it has put its operations here up for sale and will be leaving the basin. A Chevron rig drilling for natural gas in Lawrence County in 2013. Pittsburgh Post-Gazette Chevron plans to leave Appalachia, following the footsteps of other giants In a cyclical commodity business, impairments also come in waves. The last one hit around 2015, after spot natural gas prices fell and stayed below $3 per million British thermal units, where they’ve mostly remained since then. Since the beginning of 2020, prices have been closer to the $2 mark and even dipping below it. This means some prospects that could have made money in a better market are no longer viable. Impairments aren’t necessarily indicators of how well a company is operating. CNX, for example, as well as many of its peers, has consistently driven down the cost of getting its gas out of the ground. It would have turned a profit for the past quarter if not for the impairment charge. Instead, these write-downs have the effect of shrinking the collateral that companies leverage to borrow money. On the ground, it means that some oil and gas leases will be allowed to expire without follow-up and some potential drilling locations are now off the table.

Wolf promises veto on natural gas tax incentive – Gov. Tom Wolf has pledged to veto a bill offering millions of dollars in tax credits to businesses that build new petrochemical or fertilizer production plants in Northeastern Pennsylvania, his spokesman said Monday. The Senate is poised to vote this week on the measure, sponsored by Rep. Aaron Kaufer, R-Luzerne, that the Revenue Department expects will cost Pennsylvania $1 billion in lost revenue over 10 years. Administration spokesman J.J. Abbott confirmed to the Capital-Star on Monday that Wolf would oppose Kaufer’s bill, which requires companies to use Pennsylvania natural gas to produce petrochemicals and fertilizers. “[Wolf] believes such projects should be evaluated on a specific case-by-case basis,” Abbott said in an emailed statement. The Senate on Monday amended Kaufer’s bill to require tax credit recipients to pay workers prevailing wage and to make “a good faith effort” to employ local contractors during construction. The amendment also lowered the amount of money firms are required to invest in construction from $1 billion to $450 million. The bill originated in the Republican-sponsored Energize PA package last year, and was the only component that passed through the House.

Pa. Lawmakers send natural gas tax credit for Wolf, who’s promised veto – Setting the stage for a gubernatorial veto and potential override showdown, state lawmakers have approved a multi-million dollar tax credit designed to bring methane processing plants to northeastern Pennsylvania. The majority-Republican Senate split 39-11 Tuesday on the measure sponsored by Rep. Aaron Kaufer, R-Luzerne, that offers millions of dollars in tax credit to businesses that use Pennsylvania natural gas to produce fertilizer and petrochemicals. The Republican-controlled House passed it hours later on a final vote of 157-35, before sending it to Wolf’s desk. The measure received broad bipartisan support in both chambers. A spokesman for Gov. Tom Wolf told the Capital-Star that the York County Democrat would veto the bill, which faces fierce opposition from environmental advocates. But the General Assembly can override gubernatorial vetoes with two-thirds majority votes in the House and Senate. Both chambers passed that threshold with their votes Tuesday. The bill initially called for businesses to spend $1 billion and create 1,000 jobs to qualify for the tax credits. But an amendment the Senate approved Monday lowered the required capital investment to $450 million and the job creation requirement to 800 positions. The change also requires tax credit recipients to pay workers the prevailing wage and to make “a good faith effort” to hire local firms for construction.

Bill potentially allocating billions in subsidies to future petrochemical facilities clears Pa. legislature – After a highly publicized disagreement between Pittsburgh Mayor Bill Peduto and Allegheny County ExecutiveRich Fitzgerald over the future of the petrochemical industry in the region, many elected officials in Allegheny County stayed silent. Peduto argued against new petrochemical facilities, aka cracker plants, coming to the Pittsburgh region. He supported winding down fracking in the area and instead focusing on thearea’s tech and corporate sector. Fitzgerald voiced support for the industry and said it was important for the economies of counties outside of Allegheny. Pittsburgh City Paper sought to get area politicians’ thoughts on the disagreement over the region’s economic direction, but the majority of politicians didn’t indicate which way they landed on the support for future cracker plants and the continuation of fracking.Today, a bill that passed through Pennsylvania’s General Assembly sheds light on that support. And more than a dozen that were silent before, supported a bill that, if enacted, will provide potentially billions to companies looking to build out the petrochemical industry in Pennsylvania. HB 1100 passed through the state House and Senate with broad bipartisan support, by a vote of 157-35 in the House and 39-11 in the Senate. Only five out of Allegheny County’s 28 state legislators voted against the bill; 16 backed it and two didn’t vote.The bill would provide tax breaks to petrochemical companies that produce a capital investment of $450 million or more, and at least 800 jobs. Originally, the requirements were higher, but they were amended by state Sen. John Yudichak (I-Luzerne) to allow more businesses to apply for the tax credits. The Pennsylvania Department of Revenue estimates that the tax credit program will cost the state approximately $22 million per plant per year, until 2050. Before the bill was amended, the estimated cost of the bill was more than $1 billion over 10 years.

Philly refinery’s former owner, Sunoco, files formal objection ahead of bankruptcy sale – Several key parties, including former owner Sunoco Inc., filed protests Monday of the proposed Philadelphia Energy Solutions bankruptcy reorganization, complicating a scheduled Thursday confirmation hearing that could include the sale of the refinery complex, shut down since a devastating June fire.Sunoco, which owned the refinery before 2012 and is responsible for remediating the contaminated property, objected to the efforts of PES to remove restrictive covenants added to the property’s deed in 2012 that limit the ability of a potential buyer to reuse the property for a nonrefining use. Sunoco says that PES’s attempt to remove the language, which was added to protect Sunoco’s interests, “is in direct violation of Pennsylvania law and the Bankruptcy Code.” Sunoco’s objections are just one of several protests filed by a deadline Monday to a proposed reorganization plan for PES, which agreed to sell its 1,300-acre refinery complex for $240 million to Hilco Redevelopment Partners, a Chicago company that reuses industrial properties.“Hilco indicated to Sunoco that it intends to redevelop the land where the refinery is located for a use or uses unrelated to the refinery, which Sunoco contends may not be permitted by the covenants and restrictions contained in the deeds,” Sunoco said in its filing. The deed restrictions, first reported by The Inquirer on Thursday, provide that the land can be used only for nonresidential commercial or industrial activity, and also limit disturbances of its soil – contaminated after 150 years of oil processing – to only uses related to refining, chemical production, or the energy industry.

This Philadelphia Refinery Is the Country’s Worst Benzene Polluter. Trump Wants To Keep It Open – Before it exploded last June, Philadelphia Energy Solutions (PES) – the largest crude oil refinery on the East Coast – was processing 335,000 barrels of oil each day. It was also producing some of the highest levels of benzene pollution of any refinery in the country, according to a new reportby nonprofit watchdog group the Environmental Integrity Project. The report, which follows a recent investigation of PES’s benzene pollution by NBC News, found that 10 refineries across the U.S. were releasing cancer-causing benzene into nearby communities at concentrations above the federal maximum in the year ending in September 2019. Under 2015 EPA rules, facilities are required to investigate where their toxic emissions are coming from, then take immediate action to reduce impacts – both of which PES failed to do. The refinery had an annual average net benzene concentration that was more than five times the EPA standard, beating a long line of refineries in the oil-friendly state of Texas. Out of the 114 refineries that the group examined across the country over the course of a year, PES emitted the highest levels of benzene. That includes the period after the refinery was shut down following the explosion. Rather than make repairs and clean up the mess after the June incident, PES shut down the facility and filed for bankruptcy. The company put the 1,300-acre waterfront property up for sale, either to be maintained as a refinery or to be turned into housing or mixed-use development. And last month, after a closed-door auction in New York City, Hilco Redevelopment Partners, a Chicago-based real estate company, was the selected winner. But just when it seemed the PES refinery complex would shut down for good, the Trump administration got involved, offering its help last week to spurned bidders who are challenging Hilco’s victory because they want to keep the property processing crude oil. The idea of keeping the refinery active doesn’t sit well with some environmental activists, especially in light of the new benzene report. More than 5,100 people live in the area within a one-mile radius of the PES refinery. Most of the residents are black, and 70 percent of the residents live below the poverty line. These residents also suffer from disproportionately high rates of asthma and cancer. In a letter sent to the City of Philadelphia Refinery Advisory Group – a group the city created in wake of the June 21 explosion – at the end of October 2019, Drexel University researchers summarized the health impacts of living near the PES refinery based on data they’d gathered. They listed negative birth outcomes, cancer, liver malfunction, asthma, and other respiratory illnesses. They also included mental health impacts such as stress, anxiety, and depression that come with living near a large industrial site like PES. “Because the PES refinery is immediately surrounded by several neighborhoods, communities near the refinery will be disproportionately affected by compounds released by it,” Kathleen Escoto, a graduate student at the Dornsife School of Public Health at Drexel who was one of the authors of the letter, told Grist. “If the refinery released the highest levels of benzene in the country, especially considering its proximity to densely-populated areas, then the burden of disease that the refinery has on the surrounding communities is even worse than we thought.”

10 US oil refineries exceeding limits for cancer-causing benzene, report finds – At least 10 US oil refineries have been emitting cancer-causing benzene above the federal government’s limits, according to a new report from the Environmental Integrity Project. The group reviewed a year of air monitoring data recorded at the fence lines of 114 refineries, as reported to the Environmental Protection Agency. The facilities are not breaking the law, but they are required by EPA to analyze the causes of the emissions and try to reduce them. Eric Schaeffer, the executive director of the Environmental Integrity Project, said while some refineries have made improvements, others are still releasing benzene at harmful rates. “Benzene comes with elevated cancer risk but also lots of non-cancer issues that are harder to quantify,” Schaeffer said. People can get sick from low levels in the long term or high levels in the short term. Benzene is just one of multiple dangerous pollutants emitted by refineries – which turn oil into gasoline and other products. Studies have shown the populations living around refineries – often people of color and low-income families – to have worse asthma and other respiratory problems. Benzene harms cell processes. It can keep bone marrow from producing enough red blood cells and can damage the immune system and increase the risk of infection, according to the Centers for Disease Control. Over the long term, benzene exposure causes other problems, including cancer, according to the Department of Human Health and Services.

PennEast Makes Clear It’s Digging In Despite Roadblocks to Controversial Pipeline – Throughout its long fight to win approval for a 120-mile-long new natural gas pipeline through parts of Pennsylvania and New Jersey, PennEast Pipeline LLC has repeatedly demonstrated its commitment to be in it for the long haul. The past several days underlined that steadfastness with a flurry of moves by the company, some of which may have bolstered its five-year quest to win approval for the controversial project, and others that guaranteed new delays in its efforts. Late last week, PennEast filed amendments to its $1 billion project, proposing to build it in two phases. Initially, it would focus on 68 miles in Pennsylvania where it has won most of the approvals it needs to begin construction, targeting completion by November of next year. The other portion in New Jersey would be set to deliver gas in 2023, pending more complicated permit approvals in the state. In a press release, Anthony Cox, chair of the company’s Board of Managers, said the action “again proves the PennEast partners are fully committed to the entire project and meeting the needs of its customers for safe, clean, reliable and affordable energy.’’ Meanwhile, the Federal Energy Regulatory Commission sided with PennEast last week in seeking to overturn an adverse federal appeals court ruling that threatens to block the project from moving forward in New Jersey. The agency issued an order saying the decision could disrupt the natural gas sector’s ability to construct interstate pipelines. Company wants to withdraw one application In addition, PennEast asked the Delaware River Basin Commission to withdraw the company’s applications for a water withdrawal permit for the original route of its project in Pennsylvania. The project, widely opposed by local groups and environmentalists on both sides of the Delaware River, aims to deliver cheap natural gas to customers in both states. New Jersey’s Division of Rate Counsel, however, argues the proponents have failed to demonstrate a need for the project. Finally, PennEast won an extension until March 4 to appeal the U.S. Court of Appeals decision saying the company could not exercise eminent domain over 40 state-owned lands. The extension could push a hearing by the Supreme Court, if it decides to review the case, until next fall, according to opponents.

Regional LNG Finds Growing Demand off the Pipeline Grid | Rigzone – While massive world-scale liquefied natural gas (LNG) projects around the coast of North America have dominated headlines, smaller-scale regional LNG is also growing quickly. There are at least five operations, four fixed facilities in various stages of commercialization, and one using truck-mounted Cryobox liquefaction units to monetize stranded gas. World-scale liquefaction trains load into large specialized tanker ships. Regional LNG liquefaction plants ship LNG in intermodal tank containers, also known as ISO tanks. Some also have facilities for loading tank trucks and rail cars, and one also does direct bunkering of LNG for ship fuel. Most recently Edge Gathering Virtual Pipelines signed a new development deal late in January with one of the largest producers to station Cryobox in the Marcellus. Mark Casaday, CEO of Edge, says the new deal is the firm’s second in the Marcellus. It is actively pursuing similar projects in the Bakken and Permian where the flaring of stranded gas has become a serious problem for the industry. The tenured small-scale operation is Fortis, which has been shipping LNG in tank containers to China since late 2017. Jax LNG recently went into operation in Jacksonville, Fla., with 15 million cubic feet per day at the inlet. Jax is a partnership of Pivotal LNG, a wholly owned subsidiary of Southern Company Gas, and NorthStar Midstream. The latter is backed by Oaktree Capital Management, and Clean Marine Energy. Nearby, the $500-million Jacksonville Eagle operation has two LNG operations going: ISO-tank loading and a ship bunkering. The company tells Rigzone that it is approaching final investment decision for an LNG export facility. And the major midstream and utility company Dominion Energy began construction late in 2019 on modular LNG project in north central Pennsylvania, a joint venture with Rev LNG called Niche LNG, not too far from Edge’s latest installation. Edge was barred from naming its Marcellus client, but Casaday said the initial installation is for two Cryoboxes in Tioga County. Each unit takes 1 million cubic feet a day of gas at the inlet, and loads 75% of it into the tank; the balance is used as fuel. The output is between 9,000 and 10,000 gallons of LNG. “Over the next year we expect to add three or four more locations, each with two to four Cryoboxes.”

US Natural Gas Prices Continue Freefall This Winter – After the lowest summer U.S. natural gas prices since 1998, the market has continued to fall this winter 2019-2020. The cold weather has simply not arrived. In fact, after the second warmest November on record, nine of the ten weeks ending November 23 to January 25 were all “warmer” than normal, as recorded by Heating Degree Days. In turn, the storage withdrawals to meet winter’s collision of heating and power demand have been much lower than normal (see Figure). By the close of January, U.S. gas inventories stood almost 25 percent above the same time last year and 10 percent above the five-year average. On January 21, Henry Hub spot prices crashed below $2 per MMBtu for the first time since the end of May 2016. Beyond just very mild winter weather, U.S. gas prices have remained at historic lows due to record domestic supply that seemingly will not stop. After rising some 13-15 percent in 2018 output rose another 10-12 percent in 2019 to almost 93 Bcf/d. This has led to a 3-4 Bcf/d oversupply in terms of U.S. gas production rising above consumption. Not even a booming export complex that in 2019 averaged 5.8 Bcf/d of LNG feedgas and 5.1 Bcf/d of piped supply to Mexico has been able to slow the fall in pricing. The main problem for U.S. overproduction has been that activity in the Permian basin – a West Texas play that now accounts for 20 percent of the country’s gas supply – is not being driven by price signals. The light, tight oil revolution in the Permian continues to yield an oversupply of basically “free” associated gas. So much so that prices at the local Waha gas hub have often been drifting into the negatives, meaning that producers are actually paying companies to take the gas away to allow for more crude extraction. Yet, with such extreme low prices combined with some well freeze-offs, U.S. gas production dipped to 89 Bcf/d to close January, the lowest since summer. For sure, the key gas market question this year will not just be the expanding LNG export boom but also domestic production. The obvious assumption is that production growth will slow down, but the bigger question remains: will output actually decline in the absolute sense?

US natural gas falls to four-year low – US natural gas futures fell to their lowest in almost four-years on Monday on forecasts for warmer weather through mid-February than previously expected. “There is not yet enough expectations for significant late-winter weather to get the market really excited,” Daniel Myers, market analyst at Gelber & Associates in Houston, said in a report. Traders also said the gas market was weighed down by a sharp drop in crude futures, which fell to their lowest since January 2019 due to worries the coronavirus will reduce global oil demand. Front-month gas futures for March delivery on the New York Mercantile Exchange (NYMEX) fell 2.2 cents, or 1.2%, to settle at $1.819 per million British thermal units (mmBtu), their lowest since March 2016. Since hitting an eight-month high of $2.905 per mmBtu in early November, futures have collapsed 37%. Record production and mild weather have enabled utilities to leave more gas in storage, making shortages and winter price spikes less likely. Lack of supply concerns caused speculators last week to boost short positions on the NYMEX by the most since October 2018 to an all-time high. But an increase in speculative longs on the NYMEX to their highest since April helped trim net shorts on the NYMEX and Intercontinental Exchange for the first time in four weeks, according to US Commodity Futures Trading Commission data going back to 2010. Meteorologists projected the weather in the US Lower 48 states will remain near- to warmer-than-normal through February 18. That is warmer than Friday’s outlook, which called for cold from February 11-15. Refinitiv projected average demand in the Lower 48 states, including exports, would rise from 117.0 billion cubic feet per day (bcfd) this week to 122.3 bcfd next week. That is lower than Refinitiv’s estimates on Friday of 117.6 bcfd for this week and 126.9 bcfd for next week due to lower heating demand forecasts. The amount of gas flowing to US LNG export plants held at 9.3 bcfd Sunday, the same as Saturday, according to Refinitiv data. That compares with an average of 9.3 bcfd last week and an all-time daily high of 9.5 bcfd on January 31. Gas output in the Lower 48 states edged up to 94.4 bcfd Sunday from 94.1 bcfd Saturday, according to Refinitiv. That compares with an average of 94.1 bcfd last week and an all-time high of 96.8 bcfd on November 30.

US natural gas futures flat for colder weather US natural gas futures were little changed on Thursday as forecasts for cooler weather, higher heating demand and slowing output offset a bigger-than-expected storage draw last week and a collapse in global liquefied natural gas (LNG) prices. That keeps prices within a nickel of a near four-year low. The US Energy Information Administration (EIA) said utilities pulled 137 billion cubic feet (bcf) of gas from storage during the week ended Jan. 31. That was higher than the 129-bcf draw analysts forecast in a Reuters poll and compares with a decline of 228 bcf during the same week last year and a five-year (2015-19) average reduction of 143 bcf for the period. The decrease for the week ended Jan. 31 cut stockpiles to 2.609 trillion cubic feet (tcf), 8.3% above the five-year average of 2.410 tcf for this time of year. Front-month gas futures for March delivery on the New York Mercantile Exchange rose 0.1 cent, or 0.1%, to settle at $1.862 per million British thermal units (mmBtu). On Monday, the contract closed at $1.819, its lowest settle since March 2016. Since hitting an eight-month high of $2.905 per mmBtu in early November, futures have collapsed 36%. Record production and mild weather have enabled utilities to leave more gas in storage, making shortages and winter price spikes unlikely. Shares of US LNG companies tumbled as China’s biggest importer of the fuel suspended some purchases amid weaker demand and a global glut that has driven prices to record lows. In Texas, meanwhile, forward gas prices at the Waha hub in the Permian basin fell into negative territory for March-June on expectations there will not be enough pipelines to transport all the gas associated with the region’s record oil production. Gas output in the US Lower 48 states fell from 93.7 billion cubic feet per day (bcfd) on Tuesday to a near five-month low of 92.5 bcfd on Wednesday due primarily to temporary well freeze-offs in Texas during a snowstorm, according to traders and Refinitiv data. That compares with an average of 94.1 bcfd last week and an all-time high of 96.8 bcfd on November 30.

US working gas in storage falls by larger-than-expected 137 Bcf: EIA – US working gas in storage dropped at a higher-than-expected rate last week, but still less than normal, as volumes pushed to 30% over this time last year, and futures remain flat. Storage inventories fell 137 Bcf to 2.609 Tcf for the week ended January 31, the US Energy Information Administration reported Thursday morning. The pull was more than an S&P Global Platts’ survey of analysts calling for a 126 Bcf withdrawal. It was even outside the range of those polled as the largest draw expected was 136 Bcf. But it was still weaker than the 228 Bcf pull reported during the corresponding week in 2019 and the five-year average draw of 143 Bcf, according to EIA data. Massive storage volumes now tower 615 Bcf, or 30.8%, above the year-ago level of 2.222 Tcf and 199 Bcf, or 8.3%, more than the five-year average of 2.41 Tcf. Storage levels in the EIA’s Midwest and South Central regions are now 36% and 34%, respectively, more than this date in 2019. US level residential and commercial demand for the week ended January 31 fell 10.6 Bcf/d compared with the week prior, according to S&P Global Platts Analytics data. The warmer-than-normal winter has dramatically weakened residential and commercial demand year on year throughout the season. Winter-to-date residential and commercial demand has averaged 38.9 Bcf/d, down 3.7 Bcf/d winter on winter, according to Platts Analytics. The NYMEX Henry Hub March contract was static at $1.861/MMBtu in trading following the weekly storage report. Barring any major forecast changes, as weather across major demand regions looks to disappoint in February, there appears to be little upside for balance-of-winter prices. Notably, the price curve is fully upward-sloping over the next 12 months, rising from $1.89 in March to $2.56 next January, before tapering down slightly in February 2021. Platts Analytics’ supply-and-demand model forecasts an 88 Bcf draw for the week ending February 7, which is 43 Bcf below the five-year average. The following week also shows a potential draw of less than 100 Bcf. The week in progress has seen fundamentals continue to widen, with demand falling amid a measurable recovery in onshore production. Total demand is down 3.4 Bcf/d week on week to an average 109 Bcf/d, with declines spread across most downstream sectors, but with residential and commercial driving the largest share of the drop. Upstream, total supplies are up 0.7 Bcf/d at an average 96.2 Bcf/d, led by a roughly 0.5 Bcf/d increase in onshore production volumes.

A Seven-Mile Gas Pipeline Outside Albany Has Activists up in Arms – Back in February 2019, National Grid, a natural gas and electric utility, applied for a permit to build a small 7.3-mile natural gas pipeline across several towns in New York’s Upper Hudson River Valley. It would make it easier to transfer gas in the Albany area between two large interstate pipelines. Anticipating quick approval by state regulators, the utility – which also services New York City and Long Island – expected to begin construction by fall 2019. Already into January 2020, however, the pipeline – dubbed the E37 Reliability and Resiliency Project – has yet to get approval, and could become the latest casualty in the escalating fight over the future of New York’s energy economy. Facing resistance from residents who don’t want a pipeline crossing their land under any conditions, and state lawmakers who have made ambitious climate pledges to reduce New York’s reliance on fossil fuels, utility companies appear to be struggling to get even the smallest projects built. Climate activists, meanwhile, say utilities are using a “segmentation” strategy to enhance profits and expand the capacity of large interstate pipelines through small local segments like E37. They want the Federal Energy Regulatory Commission, which typically gets involved only in interstate pipelines, to regulate them. A protest is planned for Thursday in Albany, at which activists say they will present Gov. Andrew Cuomo with a petition opposing the pipeline.

Compressor station foes to meet with regulators Friday – News – – Residents fighting the construction of a natural gas compressor station on the banks of the Fore River say they are finally sitting down with regulators to voice their concerns, including that crews working to excavate contaminated fill at the site are allowing hazardous materials to spread. Alice Arena, of the Fore River Residents Against the Compressor Station, said she and several other members will meet Friday with Millie Garcia-Serrano, regional director of the state Department of Environmental Protection’s southeast office, and other officials to discuss their concerns about ongoing work at the site, including what they see as blatant violations and shortcomings in regulator oversight. “We have a lot of questions about the lack of oversight, and violations of the (release abatement measure) plan that we’ve been asking for three months,” Arena said. “Hopefully, we’ll be able to get to the beginning of a conversation and to get them engaged in actual oversight.” The compressor station is being built by Algonquin, a subsidiary of Enbridge, and is part of the Atlantic Bridge project, which would expand the Houston company’s pipelines from New Jersey into Canada. Algonquin got the final go-ahead from the Federal Energy Regulatory Commission in November and started cleanup of existing contamination at the site shortly after. The company also needed several state permits, all of which were granted by regulators despite vehement and organized opposition from local officials and residents. The town of Weymouth alone filed two dozen lawsuits attempting to stop the project.

Exeter voters to weigh in on proposed Granite Bridge pipeline – — A citizen’s petition on the March 10 Town Meeting ballot calls for residents to oppose the Granite Bridge pipeline project, currently under review by the state’s Public Utilities Commission. Granite Bridge is the proposed $414 million, 27-mile, 16-inch natural gas pipeline from Exeter to Manchester to be constructed by Liberty Utilities within the Route 101 right of way, designated by law as a state Energy Infrastructure Corridor. The project, which includes constructing a liquefied natural gas (LNG) storage tank in an abandoned quarry in Epping, is more than a year into the PUC review process. If approved by the PUC, the pipeline application is then reviewed by the state Site Evaluation Committee, which can take upwards of another year-plus before construction could begin. The petition, appearing on the March ballot as Article 25, states in part, “the scope of the project vastly exceeds the current and future energy needs of New Hampshire. The likely changes in energy production could result in ratepayers paying for technology that will be obsolete before it’s operational.” “We’re not going to get rid of fossil fuels overnight, but we’re not in a position to ramp up fossil fuel infrastructure either,” said resident Sherri Nixon, the lead petitioner. “By the time this pipeline is up and running, we should be well on our way towards being reliant on renewable energy.”

Fight to stop gas-powered generation plant may be futile – A coalition of activists is waging war against a gas-fired electric power plant to be built in Killingly, a forested town nestled along the Rhode Island border. The climate change protesters have held rallies and demanded a moratorium on gas-fueled plants, including this one. They have warned that new fossil fuel-powered plants will doom global efforts to keep temperature hikes at a sustainable level. And they called on Gov. Ned Lamont to stop the plant – although it’s not clear he has that power. Despite the uprising, the plant is close to construction, its developer said, and there is likely nothing anyone can do to stop it. The owner, NTE Energy, has obtained Connecticut Siting Council approval to build the 650-megawatt facility capable of powering 500,000 homes. NTE earlier received permission from the state Department of Energy and Environmental Protection. A crucial air permit is in hand and only a few routine permits are still needed. .

Racism and ecological injustice combine in ‘reckless, racist’ Atlantic Coast Pipeline fight – The Rev. Dr. William Barber, co-chair of the Poor People’s Campaign – Nearly four decades since the birth of the environmental justice movement in the 1980s, we face a new Goliath of ecological injustice. The Atlantic Coast Pipeline – a project that starts in West Virginia and cuts through Virginia and North Carolina – is poised to threaten poor, rural, black and indigenous communities across those states, forcing us to recognize and respond to the fact that marginalized communities still bear the bulk of our nation’s environmental burden. As we stand with those around the country who are joining with the Poor People’s Campaign and organize toward the Mass Poor People’s Assembly in Washington, D.C., on June 20, we have borne witness to poor people and communities of color who are burdened with industrial pollution. We see the intersections of poverty, ecological devastation and systemic racism. We cannot address one without being conscious of the other. We continue to encounter communities caught in a vise grip between the Trump administration’s efforts to weaken health-based regulations and companies with little regard for the people who live in the shadow of industrial pollution. If it is built, the 600-mile natural gas pipeline would cut through some of the best preserved forests in Virginia, through rural areas predominantly populated by people of color and low-income households, and end in a predominantly Lumbee Indian community in southern North Carolina. Dominion Energy and Duke Energy – the chief owners of both the project and the utilities that would buy the bulk of the gas for power plants – have not demonstrated that we need this pipeline costing more than $7 billion to meet our energy needs. Nevertheless, their utility customers will be asked to pay for it. The Atlantic Coast Pipeline would have three compressor stations, poisoning the air in each of the surrounding communities. Compressor stations that use gas-fired turbines emit toxins and fine particle pollution that increase the risk and severity of respiratory illnesses for nearby residents. Unsurprisingly, no posh suburbs or gated communities will have to suffer from this pollution. Instead, these compressor stations were slated for rural areas with above-average rates of poverty and, in North Carolina and Virginia, predominantly African American neighborhoods.

Virginia lawmakers vote to block offshore drilling in rebuke to Trump plan – (Reuters) – Virginia Democratic-led lawmakers on Tuesday passed a bill to block future oil and gas development off the state’s coastline, reflecting opposition to the Republican Trump administration’s efforts to open Atlantic waters to fossil fuel exploration. Democrats control both chambers of Virginia’s state legislature, and the governor is also a Democrat. The bill passed by the state House of Delegates prohibits infrastructure such as pipelines or gathering systems in state waters that could be used to transport oil and gas drilled in federal waters to Virginia’s shores. It also repeals a state policy to support U.S. efforts to explore for offshore oil and gas. A companion bill was approved in the state’s Senate last week, and the legislation is expected to be sent to Governor Ralph Northam shortly. A representative for Northam said he supports the bill. “Governor Northam has long been opposed to offshore drilling off Virginia’s coast,” spokeswoman Alena Yarmosky said in an email. California has also banned new oil and gas infrastructure in state waters since President Donald Trump’s administration proposed in 2018 to open up the Atlantic, Pacific and new parts of the Arctic oceans to offshore drilling. The offshore drilling plan was part of a broader effort by the administration to maximize domestic energy production, but has drawn vehement opposition from nearly every coastal state over concerns related to potential oil spills that could spoil beaches and hurt their lucrative tourism industries. The proposal has since been put on hold due to a court ruling, though the administration is still processing permit requests for seismic testing in the Atlantic. ADVERTISEMENT The text of the Virginia bill and the outcome of the vote were posted on a state legislative website. Democrats have made huge political gains in Virginia in recent years, buoyed by a backlash against Trump, particularly in suburban areas.

Low US gas prices a spur for new LNG export projects: executives – Low US gas prices are bolstering the prospects of companies looking to develop new LNG export projects, as customers increasingly expect those domestic prices to remain low or fall further, executives at an LNG forum in Florence, Italy, said Monday. Speaking at the Baker Hughes AM2020 conference, the heads of Venture Global and NextDecade voiced optimism about the growth in worldwide demand for natural gas, and played down the weakness of global LNG spot prices as a short-term issue. Both companies have projects on the table, although not yet developed. Their comments echoed the bullish view on LNG exports of US assistant secretary for fossil fuels, Steven Winberg, who told S&P Global Platts this week that US LNG exports could rise by 50% over the next three to four years. “Our customers view the long-term gas prices in the US as very stable and maybe even trending down.” “There’s massive demand for LNG. It’s growing extremely well and we think that will continue for a long time. From our perspective a lot of people in the market continue to underestimate what that growth is going to be, so there’s huge opportunities to innovate,” he said. Sabel said one disadvantage for US LNG developers was a difficult regulatory approval regime for new projects, saying the regime right now was relatively good, but the future unpredictable. “It can be a meaningful disadvantage relative to other markets,” he said. However, NextDecade CEO Matt Schatzman, whose company is developing projects in Texas, was similarly bullish overall on the prospects for US LNG exports, saying domestic gas prices of around $2/MMBtu or lower were “very helpful to exporters.” “The spot prices for LNG are very low right now, probably $4/MMBtu or less into Asia. That’s not sustainable and doesn’t help the development of LNG projects, but we think the short-term indications in the LNG market are not indicative of the long-term requirements,” he said. With LNG buyers seeking to eliminate price risk, the risk for US gas exports would be borne not by LNG exporters, but by US upstream gas producers, Schatzman said. He went on to say that major economies, such as India, had already decided on the switch to gas, based not only on concerns about global warming, but the need to improve local air quality.

Virus Has US Gas Exporters Fearing Production Cuts— A grim situation for U.S. natural gas exporters has gotten even worse as the coronavirus outbreak sends global prices plunging on concern that China’s demand for the fuel will collapse. Suppliers of American liquefied natural gas were already under pressure from depressed prices arising from a global glut and an unusually mild domestic winter. Now, with the virus threatening to disrupt industrial production across China, Asian spot LNG prices have hit a record low. Faced with prospect of being unable to even cover their shipping costs, customers such as commodity trading houses may simply refuse to load U.S. cargoes. Those cancellations could force LNG export terminal operators to cap, or “shut in,” production of the fuel as their storage tanks fill up. “Forward prices for summer are now at levels where U.S. LNG shut-ins begin to seem viable,” said Edmund Siau, a Singapore-based analyst with energy consultant FGE. “There is usually a lead time before a cargo can be canceled, and we expect actual supply curtailments to start happening in summer.” Such an outcome would be a blow to the young and fast-expanding U.S. LNG industry. New export terminals from Maryland to Texas have sprung up to make the country one of the world’s top suppliers, while also providing a crucial outlet for soaring production from shale basins. China hasn’t directly imported LNG from the U.S. in a year amid trade tensions and tariffs on the fuel. But it’s the world’s fastest-growing buyer, and a slowdown or decline in demand there will have an effect that ripples right across the market. China’s big state-owned LNG importers are said to be considering force majeure declarations on contracted cargo deliveries, which would further burden an oversupplied market. Brimming global gas stockpiles are increasing the risk that cargoes will be curtailed, according to Nina Fahy, head of North American natural gas for Energy Aspects Ltd., and Madeline Jowdy, senior director of global gas and LNG for S&P Global Platts. “The full impact of the coronavirus on global gas markets is yet to be felt as lower LNG demand expectations for the Lunar New Year were already built into most forecasts,” Jowdy wrote in an email.“The global LNG outlook is going from bad to worse for suppliers.”

The new normal for crude oil exports – The latest Energy Information Administration weekly data shows that U.S. crude oil exports have averaged above – usually well above – 3 million barrels per day for 12 consecutive weeks. The weekly data that runs through the end of January is a sign that 3 million-plus is the new normal for U.S. crude exports. The growth has been enabled by booming shale production that produces light oil that many refineries are not optimized to run. That has created a spillover effect as companies are building new pipeline and port infrastructure to handle the rise. The intrigue: Politically, it raises the stakes of the White House race. Bernie Sanders and Elizabeth Warren have both called for ending U.S. oil exports as part of their climate platforms. The weekly data is noisy, but on a multiweek basis it is consistent with more complete monthly data, which arrives after a lag. Exports averaged over 3 million barrels per day in November, the most recent period in the monthly tallies, as well as October and September. Flashback: Legislation to remove heavy export restrictions was enacted at the end of 2015.

Despite the U.S. becoming a net petroleum exporter, most regions are still net importers – (EIA) In November 2019, the United States exported 772,000 barrels per day (b/d) more petroleum (crude oil and petroleum products) than it imported, marking the third consecutive month in which the United States was a net petroleum exporter. Although the United States is a net petroleum exporter as a whole, most regions other than the U.S. Gulf Coast region remain net petroleum importers. Net petroleum trade is calculated as the total imports of crude oil and petroleum products minus the total exports of crude oil and petroleum products. In September 2019, the United States became a net petroleum exporter for the first time since monthly records began in 1973. The United States is a net importer of crude oil. In November 2019, the latest monthly data, it imported 5.8 million b/d of crude oil and exported 3.0 million b/d of crude oil. The United States is a net exporter of petroleum products (such as distillate fuel, motor gasoline, and jet fuel). In November 2019, the United States exported 5.8 million b/d of petroleum products and imported 2.2 million b/d of petroleum products. Regional petroleum trade patterns are still determined by geographical factors, existing infrastructure, regional balances of supply and demand, and other constraints – factors that often change slowly. In recent years, significant growth in crude oil output and infrastructure changes to refineries, pipelines, and terminals in the U.S. Gulf Coast region have led to most of the changes in U.S. petroleum trade patterns. monthly regional net crude oil trade. Of the five regions (also referred to as Petroleum Administration for Defense Districts), only the U.S. Gulf Coast currently exports more crude oil than it imports: 2.9 million b/d of exports compared with 1.2 million b/d of imports in November. The Gulf Coast continues to import primarily heavy, high-sulfur crude oil, which most Gulf Coast refineries are configured to process. Imports from Mexico and Canada are nearly tied as the largest sources of Gulf Coast crude oil imports. Canada is also the largest source of crude oil imports for the Midwest, which is now the largest crude oil importing region; crude oil net imports totaled 2.5 million b/d in November. In other regions, crude oil trade patterns are relatively unchanged.

BP oil spill cash rebuilds eroded Louisiana pelican island (AP) – A Louisiana island that provides a crucial nesting ground for pelicans and other seabirds is being restored to nearly its former size after decades of coastal erosion and a devastating offshore oil spill 10 years ago. Gov. John Bel Edwards visited the island Monday, unveiling a sign dedicating it as a wildlife refuge. “The walk we just made wouldn’t have been possible a few weeks ago,” the governor said after crossing an expanse of sand bearing tread marks from heavy equipment used to create and grade new land. He spoke at a podium set up before waist-high mangroves, which contractors left untouched for pelicans to nest on. About 6,500 brown pelicans and 3,000 smaller seabirds cram their nests every summer onto Queen Bess Island, which shrank from 45 acres (18 hectares) in 1956 to about 15 acres (6 hectares) of marsh by 2010, when the Deepwater Horizon spill fouled its beaches with oily gunk. Until the restoration, only about 5 acres (2 hectares) – most of it along the island’s edges and the outlines left by short-lived restorations in the 1990s – was high enough for pelicans to nest, said Todd Baker, a biologist supervising restoration for the Louisiana Department of Wildlife and Fisheries. Once a mere strip of land, the island now covers 37 acres (15 hectares), with most of it for the increasingly cramped birds. Edwards said the $18.7 million project to enlarge and maintain the island is part of $550 million that that has restored more than 4,200 acres (1,700 hectares) of Louisiana’s coast and islands. More than $800 million in additional work is expected across Louisiana this year, he said. Though barely a blip of an island off the Gulf of Mexico in Barataria Bay, Queen Bess plays an outsize role as one of Louisiana’s largest rookeries for brown pelicans, supplying real estate for up to a fifth of the state’s nests. It’s also where the pelican, Louisiana’s state bird, was reintroduced in the 1960s after pesticides had killed off the state’s entire population.

Louisiana seeking $150M grant to elevate oil and gas highway (AP) – Louisiana is making a pitch for millions of dollars in federal financing it hopes will help elevate a state highway leading to a critical national oil and gas hub. Gov. John Bel Edwards and state lawmakers pledged $150 million in oil spill recovery money for improvements to LA Highway 1 in Lafourche Parish heading to Port Fourchon. Louisiana’s leaders want the federal government to match that with another $150 million. Jefferson Parish U.S. Rep. Steve Scalise, who is the No. 2 House Republican, said he met with Transportation Secretary Elaine Chao on Wednesday to talk of the state’s request. Chao’s department is overseeing a $900 million infrastructure grant program that Louisiana has targeted to provide the $150 million in federal financing, to help elevate an 8.3 mile stretch of Highway 1 from Golden Meadow to Leeville. Scalise said he stressed not only the highway’s use as a key hurricane evacuation route, but also its importance to the national energy infrastructure at Port Fourchon. “It will be an aggressive competition, but I think we have an incredibly strong story,” he said.

630 gallons of crude oil spills in Tabbs Bay near Baytown – – The Coast Guard responded Saturday to a crude oil spill in Tabbs Bay near Baytown.Coast Guard Sector Houston-Galveston watchstanders received a report of a the discharge via an oil wellhead. Officials estimate 630 gallons of diesel fuel was spilled.The Coast Guard said the source of the r elease has been secured, and the spill has been contained.

Oil spill contained in bay on eastern outskirts of Houston (AP) – A 630-gallon (2,385-liter) oil spill in a bay on the eastern outskirts of Houston has been contained and is being cleaned from the water, the U.S. Coast Guard said Monday. Coast Guard Petty Officer Paige Hause said the mile-long (1.6-kilometer-long) spill occurred Saturday at Baytown from a wellhead that was closed and abandoned in 1980s, but it is unclear who the current owner is. “That’s still part of the investigation … to determine who the responsible party is,” Hause said. Hause said the spill is not considered large, but the health and environmental impact has not been determined, with surveys of the area now underway. Hause said an absorbent material has been spread along the shoreline of the bay and oil is being vacuumed from the water. The efforts seek to keep oil out of the Houston Ship Channel, which was closed nearly a year ago after flammable chemicals from a petrochemical storage facility seeped into what is one of America’s busiest shipping lanes. Environmental officials with Harris County, the state of Texas and the U.S. Environmental Protection Agency did not immediately return phone calls for comment.

Texas oil spill restarts after previous containment – (Reuters) – A crude oil spill near Baytown, Texas, has restarted after earlier being contained, U.S. Coast Guard officials said in an updated statement on Sunday.About 630 gallons of diesel fuel spilled in Tabbs Bay and approximately one mile (1.6 km) of shoreline has been affected, officials said.The cause of the spill is under investigation.“The source of the release was initially secured but has since begun to leak again,” they said. “Personnel on-scene are developing mitigation plans and strategies to re-plug and secure the wellhead.” Emergency responders had placed roughly 700 feet (213 meters) of floating boom lines as of Sunday night to contain the spill and prevent damage to the Houston Ship Channel, the nation’s largest petroleum export port. About 2,000 feet (610 meters) of absorbent material was placed along the shoreline.

Ignition of natural gas blamed in fatal oil well accident – A second worker has died from injuries suffered in a Burleson County oil well fire, which authorities suspect was caused by the ignition of natural gas rising to the surface.The worker, who was not identified, died two days after the fire broke out at the well operated by Chesapeake Energy of Oklahoma City, according to the company. The other worker killed in the explosion was identified in a court filing as Windell Beddingfield, 38, of Tyler. Beddingfield, an employee of Eagle Pressure Control, a Fort Worth oil field services company, died at the scene Wednesday. His mother, Linda Milanovich, filed a request for an injunction before a state District Court in Caldwell on Friday afternoon to preserve evidence in advance of a potential lawsuit. Officials from Eagle Pressure Control could not immediately be reached for comment. Milanovich is seeking a hearing as soon as Monday or Tuesday, said her lawyer, Eric Allen with the Houston office of the law firm Zehl & Associates.“Distraught is the best way to explain what the family is going through right now,” Allen said.Fatal Accident: One dead, three burned in fire at Chesapeake Energy wellCrews were working on upgrading a wellhead at the surface when an unexpected amount of natural gas entered the 8,500-foot-deep well and ignited around 3:30 p.m. Wednesday, a preliminary inspection report from the Railroad Commission of Texas shows. The cause of the ignition is not clear and remains under investigation by state and local authorities.Eleven people from Chesapeake, Eagle Pressure Control and Alice oil field services company C.C. Forbes were working on the well pad at the time of the accident, the Railroad Commission report said.Beddingfield died at the scene, and three other men were transported by helicopter to hospitals in Houston and Austin.Beddingfield, nicknamed “Bubba” by family members, is survived by a wife and a 16-year-old daughter.Chesapeake officials said the crews were performing workover operations at the time of the accident. In the oil and natural gas industry, workover crews are typically called to perform maintenance or other types of work to improve a well’s sagging productivity. Chesapeake said none of its employees were injured.

3rd man dies after gas blast at Chesapeake Energy oil well near Bryan – A third man has died after a gas explosion Wednesday at a Chesapeake Energy oil well in Burleson County, according to media reports.Oil field worker Brian Maldonado, 25, of San Diego, Texas, died on Saturday, the Alice Echo News-Journal reported.Company officials could not immediately be reached for comment, but Maldonado was part of a crew working at a Chesapeake Energy oil well west of Bryan, Texas, when natural gas in the well ignited at about 3:30 p.m. Wednesday. The blast killed 38-year-old Windell Beddingfield of Tyler at the scene; Maldonado and two other men were taken by helicopters to hospitals in Houston and Austin.A second worker, who has yet to be identified by authorities or company officials, died Thursday.Maldonado was flown to the Dell Seton Medical Center at the University of Texas in Austin, where he underwent surgery Thursday afternoon, the Alice Echo-News Journalreported. Eleven people from Chesapeake, Fort Worth oil field service company Eagle Pressure Control and Alice oil field service company C.C. Forbes were working at the well at the time of the incident, a report from the Railroad Commission of Texas shows. Investigators believe that an unexpected amount of natural gas entered the well and ignited. What caused the ignition remains under investigation.Officials from Chesapeake and C.C. Forbes could not immediately be reached for comment but said in previous statements that they are cooperating with regulators and investigators.

Fatal oil well accident investigation widens – Federal officials are now joining an investigation into a fatal Chesapeake Energy accident that left three men dead and another in the hospital.The U.S. Chemical Safety and Hazard Investigation Board has deployed a team to investigate the Burleson County accident.The federal investigation will run alongside ones being conducted by state and local authorities.Known as CSB, the federal agency was launched in 1998 to investigate accidents and to determine the conditions and circumstances that led up to them.As part of its work, the agency identifies the cause or causes of accidents so that similar events might be prevented.The well fire occurred about two years after a well explosion in Oklahoma killed five workers. The board also investigated that accident, finding blame not only with the company that owned and operated the rig, but also the entire energy sector and government for a woeful lack of regulation and supervision of onshore oil and gas drilling. We’ll see where theinvestigation into the Chesapeake Energy accident leads.

Chesapeake Energy, others sued for $1 million in fatal Texas oil-well blast – (Reuters) – Chesapeake Energy Corp and three oilfield service firms were sued by the daughter of a worker who suffered fatal injuries when a Texas oil well exploded in flames last month. The wrongful death suit seeks at least $1 million from Chesapeake Energy, Forbes Energy Services, Eagle Pressure Control and Halliburton Co. It was filed this week in Harris County District Court by Madison Hendrix, whose father, Brad Hendrix, died in a hospital days after the blast. Hendrix alleged that Chesapeake, the well owner, and the oilfield service companies were negligent, failed to provide a safe work environment or adequate medical care to the workers. Chesapeake declined to comment and Eagle Pressure Control did not immediately respond to a request for comment. Forbes Energy Services said it was “beyond saddened that three fatalities have been confirmed” and offered its “deepest sympathy and condolences” to families affected by the incident. Attorneys representing Hendrix did not respond to a request for comment. Halliburton said it was not performing any services on the rig when the well-control incident occurred. Its well-control unit, Boots & Coots, was hired to handle the post-incident well intervention work, a spokeswoman for the company said.

U.S. oil fields flared and vented more natural gas again in 2019: data – (Reuters) – The U.S. drilling industry flared or vented more natural gas in 2019 for the third year in a row, as soaring production in Texas, New Mexico, and North Dakota overwhelmed regulatory efforts to curb the practice, according to state data and independent research estimates. Flaring, or deliberately burning gas produced as a byproduct to oil, can worsen climate change by releasing carbon dioxide. Venting releases unburned methane, which is many times more potent than carbon dioxide as a greenhouse gas. Oil drillers tend to flare or vent gas when they lack pipelines to move it to market, or prices are too low to make transporting it worthwhile. “You’ve got a real waste issue,” said Colin Leyden, a policy advocate for the Environmental Defense Fund, which tracks flaring. “And everyone should be concerned about that.” In the Permian Basin underlying Texas and New Mexico, the largest U.S. shale basin, flaring and venting totaled about 293.2 billion cubic feet last year, according to state regulatory data compiled by independent energy researcher Rystad – up about 7% from 2018. In North Dakota’s huge Bakken oil field, meanwhile, the volume was just over 200 Bcf, up 36% from 2018, Rystad said. Combined, that would put volumes of flared and vented gas from America’s two biggest oil fields at 493.2 Bcf, more than 5% above the national 2018 total of 468.3 Bcf reported here by the U.S. government’s Energy Information Administration (EIA). That volume of gas, if released directly to the atmosphere, would have the climate impact of about seven coal-fired power plants, according to the Environmental Protection Agency’s Greenhouse Gas Equivalencies Calculator. Texas, New Mexico, and North Dakota led a 66% nationwide increase in flaring and venting in 2018, and represented 90% of the national total that year, according to the EIA. The agency will not release its 2019 flaring and venting estimates until late this year.

Texas Regulator Readies First Flaring Report Amid Backlash – A Republican defending his seat on Texas’s all-powerful energy regulator is preparing a first-of-its-kind report on natural gas flaring, a practice that’s come under fire from environmental groups and even some producers. The report will showcase flaring trends, its proportion to surging oil production and potentially a list of the best and worst operators, said Ryan Sitton, a member of the Texas Railroad Commission, which actually oversees the oil and gas industry in the state despite its name. His office has been working for the last six months to aggregate data reported by oil and gas operators

Six Texas oil refineries spewing cancer-causing pollutant above threshold Eight years ago, two environmental nonprofits sued the U.S. Environmental Protection Agency. The agency was a decade overdue in updating limits on how much hazardous air pollution the country’s oil refineries could emit; the groups hoped a lawsuit would force it to act. The result was a regulation that required more than 100 refineries to monitor – and report – levels of cancer-causing benzene along the perimeters of their facilities and to make fixes when concentrations exceed a certain threshold. On Thursday, the Washington, D.C.-based Environmental Integrity Project – one of the two nonprofits that sued the EPA in 2012 – released an analysis of the publicly available monitoring data refineries began sending to the EPA in January 2018. It found that 10 of them had reported benzene levels above the established threshold over a one-year period that ended in September. Six of those refineries are in Texas, including three in the Houston metro area. The Texas refinery that reported the highest concentrations of the hazardous pollutant at its fence line was Total Port Arthur Refinery in Port Arthur, with levels 148% greater than limit, according to the report. “These results highlight refineries that need to do a better job of installing pollution controls and implementing safer workplace practices to reduce the leakage of this cancer-causing pollutant into local communities,” Eric Schaeffer, executive director of the Environmental Integrity Project, said in a statement. “EPA in 2015 imposed regulations to better monitor benzene and protect people living near refineries, often in working-class neighborhoods. Now, EPA needs to enforce these rules.” The EPA didn’t immediately respond to a request for comment.

Ten U.S. refineries emitted excessive cancer-causing benzene in 2019: report – (Reuters) – Ten U.S. oil refineries, including six in Texas, released the cancer-causing chemical benzene in concentrations that exceeded federal limits last year, according to government data published by the green group Environmental Integrity Project on Thursday. The study is based on the first full year of data reported by U.S. refineries since a U.S. Environmental Protection Agency rule was implemented in 2018. The rule requires continuous monitoring of air pollutants around plants to protect nearby communities, many of which are disproportionately poor, black and Hispanic. “These results highlight refineries that need to do a better job of installing pollution controls and implementing safer workplace practices,” EIP Executive Director Eric Schaeffer said in a statement. “Now, EPA needs to enforce these rules.” In an emailed statement, the EPA said that “it is important to note that benzene concentration levels monitored at the perimeter of a refinery do not reflect benzene levels in the community.” The agency added that its limits are stringent “in order to provide ample opportunity for early action.” EPA said it would not comment on ongoing or potential enforcement actions. Long-term exposure to benzene can cause blood disorders and leukemia, according to the agency. Monitoring for benzene is meant to be a tool that allows for “early detection of potential problems,” But the EPA’s data “is not intended as a measure of community exposure or health risk and could inadvertently provide misleading results to the public,”

Enterprise Products Partners Wins Court Appeal – Enterprise Products Partners LP has won in its appeal against Energy Transfer Partners in the Supreme Court of Texas. The appeal stems from a 2014 Dallas jury verdict against Enterprise in a lawsuit filed by Energy Transfer over a proposed pipeline project that was cancelled due to a lack of customer support. A panel of the Dallas Court of Appeals reversed the trial court’s judgment for all ETP’s claims against Enterprise, and the Supreme Court of Texas unanimously supported the ruling. In April of 2011, Enterprise and Energy Transfer signed agreements disclaiming any partnership or joint venture without documents and board approvals of the two companies. Definitive agreements were never executed, and board approval was never obtained. The parties signed these disclaiming agreements precisely to avoid this type of lawsuit, Enterprise said in a written statement. Enterprise Products Partners is a North American provider of midstream energy services to producers and consumers of natural gas, NGLs, crude oil, refined products and petrochemicals. Its services include natural gas gathering, treating, processing, transportation and storage; NGL transportation, fractionation, storage and export and import terminals; crude oil gathering, transportation, storage and export and import terminals; petrochemical and refined products transportation, storage, export and import terminals and related services; and a marine transportation business that operates primarily on the United States inland and Intracoastal Waterway systems.

Permian Proves to be Double-Edged Sword for Exxon, Chevron – Exxon Mobil Corp. and Chevron Corp. are discovering that the vaunted Permian Basin is a double-edged sword: surging shale supplies there are driving down global energy prices. North America’s largest oil explorers posted their weakest results in years on Friday, bedeviled by poor performances in almost all of their business lines. The main culprit: excess supplies of everything from gas to motor fuels and polyethylene. Exxon, which in recent years positioned the Permian as a linchpin of its global growth strategy, on Friday disappointed some analysts by saying output in the world’s biggest shale patch won’t expand in a smooth, uninterrupted fashion. Cash flow failed to cover its dividend for the eighth quarter in the last ten as the company boosted spending on new projects. For Chevron, while Permian wells helped lift worldwide production to an all-time high, that wasn’t enough to patch over a massive writedown in the value of gas fields and the deepest quarterly loss in a decade. Analysts questioned whether the company has enough in the tank to keep growing beyond the mid-2020s. Just to cover project spending and dividend payouts without borrowing, Exxon would have needed international crude prices around $100 a barrel, according to Citigroup Inc. analyst Alastair Syme. That’s well above the $62 fourth-quarter average. “Shareholder returns are poor, and debt is rising in a way that suggests that attractive dividends yields are unsustainable,” veteran oil-industry analyst Paul Sankey of Mizuho Securities USA LLC said in a note to clients. “What is so concerning about these mega-oil results is that they come in a quarter that featured an average $62/bbl Brent price.” Investor Backlash Exxon shares fell so much on Friday that the decline wiped out $12 billion in market value in less than three hours. The last time the stock traded this low was in late 2010, when Chief Executive Officer Darren Woods was a freshly minted vice president of supply and transportation, still several promotions away from the top job. Chevron also slumped, dropping as much as 4.5% for one of the day’s worst showing on the Dow Jones Industrial Average. The weak results were presaged by Shell’s gloomy earnings report on Thursday that prompted the European supermajor to slow share buybacks. The pain is far from over: Woods warned that conditions in its chemical business will continue to be “challenging” through 2020 and predicted the worldwide gas glut will take some time to burn off. Years of high spending on new projects will position the Exxon to “capture the eventual upswing” in prices, he said.

US oil, gas rig count drops 16 to 838 on the week amid disciplined early 2020 outlooks – The total US oil and natural gas rig count dropped by 16 to 838 on the week, drilling data provider Enverus said Thursday, with the biggest in-basin changes coming from Appalachia amid persistently lower gas prices, and the Permian Basin. Each of the two basins lost five rigs, bringing the number in the Permian down to 418 rigs and to 46 in Appalachia, a largely gas-prone region, as dismal gas prices stayed largely well below $2/MMBtu. Appalachia includes both the Marcellus Shale and the Utica Shale plays. The Marcellus lost four rigs, leaving a total 36, while the Utica lost one rig, leaving 10. The total US rig count has largely bobbed at or below 840 since late December. Those levels were last seen in February 2017 when the domestic count was rapidly rising in response to oil prices that were then breaking through stalemated levels of below-$50/b the year before. Crude oil was trading just above $50/b on Thursday. Intra-basin rig counts largely stayed the same or were up or down by one or two rigs against last week. Outlooks from North American land drillers this week show a needle that isn’t moving much this year compared to 2019, even with a relative bright spot of the Permian Basin, sited in West Texas and New Mexico. “Capital discipline [by E&P companies] will remain a prevailing theme” for 2020, John Lindsay, CEO of driller Helmerich & Payne, said on his company’s earnings call earlier this week. “We expect industry activity to look similar to the average level experienced during the second half of calendar 2019, which implies a modest increase from current levels,” Lindsay said. Permian/Bakken Shale producer Oasis Petroleum said its capital spending would be $700 million-$730 million for 2020 — 5% less than its earlier projected $750 million capital budget. Rigs in the Bakken remained flat this past week at 54. Cabot Oil & Gas has pared its 2020 capex substantially year on year to $575 million, down 29% from projected spending last year.

Indianapolis-based Miller Pipeline sold as part of $850M deal – CenterPoint Energy Inc. has agreed to sell two subsidiaries, including Indianapolis-based Miller Pipeline, for $850 million to infrastructure services provider PowerTeam Services LLC, the companies announced Monday. Houston-based CenterPoint acquired Miller Pipeline, which employs more than 3,500 people, when it purchased Evansville-based gas and electric utility Vectren Corp. in early 2019. In addition to Miller Pipeline, Atlanta-based PowerTeam will receive Big Lake, Minnesota-based Minnesota Limited, which CenterPoint also acquired in the Vectren deal. Minnesota Limited has more than 1,400 employees. Miller Pipeline and Minnesota Limited are two of the county’s leading natural gas distribution and transmission pipeline contractors, providing services to customers in 35 states. The two companies are collectively known as MVerge. The deal is expected close in this year’s second quarter. CenterPoint said it will use proceeds from the sale to extinguish outstanding debt.

In Iowa, Candidates Slam DAPL as Documents Show Expansion Tied to Exports –Steve Horn – Ed Fallon, a long time progressive political activist in Iowa and founder of the grassroots organization Bold Iowa, has dogged presidential candidates before the state’s first in the nation primary caucuses for more than two decades.A member of the Iowa legislature from 1993-2006, Fallon has worked on issues such as opposing war, sustainable agriculture, and in more recent years, the climate crisis. This year, Fallon and others at Bold Iowa confronted every Democratic Party candidate about their position on the Dakota Access Pipeline (DAPL) and other climate change issues. DAPL brings oil extracted in North Dakota diagonally across Iowa and eventually into Illinois where it connects with the Energy Transfer Crude Oil Pipeline (ETCO). ETCO then brings the oil down to Gulf of Mexico refineries, and soon perhaps increasingly to the global export market.Fallon’s most recent encounter, one with former Vice President Joe Biden on January 26, ended with Biden gently pushing him away and telling him to “go vote for somebody else.” Though a supporter of Tom Steyer, Biden assumed Fallon supported Bernie Sanders. For Bold Iowa, a central part of their organizing strategy in the months leading up to the caucuses was confronting candidates in person. “We’ve got over 250 people statewide, who early last year agreed to birddog candidates on climate and most of them have been to at least one and some of them a dozen or more events,” Fallon said. “I mean, several people have been to probably 50 events.” They also asked candidates questions on issues such as their stances on the Green New Deal and how they will respond to the climate crisis if they become president. But it is Dakota Access, the pipeline owned by the Dallas-based company Energy Transfer Partners, that has taken center stage. The pipeline was subject to the most prolonged and largest mobilization against a pipeline proposal in U.S. history near the Standing Rock Sioux Reservation in North Dakota. “In terms of local connections to climate change, it’s the biggest issue here in Iowa,” Fallon said.

Minnesota utility regulators give key approvals to Line 3 pipeline project – Months after a court decision threw its future into question, the Line 3 pipeline replacement project is moving closer to regaining the permits it needs to begin construction. The Minnesota Public Utilities Commission voted 3 to 1 Monday on three key approvals for the project: a revised environmentalreview, a certificate of need and a route permit. The PUC originally voted to approve the controversial oil pipeline project in June 2018. Calgary-based Enbridge Energy is proposing to build the new line, which would replace an aging crude oil pipeline that stretches across northern Minnesota. The new line would be built along a different route, and would have the capacity to transport about twice as much oil as the current pipeline is allowed to carry. But last summer, the Minnesota Court of Appeals rejected an environmental study that was originally prepared for the project because it failed to assess the impacts of a hypothetical oil spill in the Lake Superior basin. The Minnesota Department of Commerce revised that study, known as an environmental impact statement, to include an analysis of a potential spill into Little Otter Creek. The creek flows into the St. Louis River, which forms the headwaters of Lake Superior. Matt Schuerger was the only commissioner to reject the revised environmental study – and the only commissioner to vote against the project’s certificate of need and route permit. He said he agreed with several pipeline opponents – including the groups Honor the Earth and Friends of the Headwaters – that the selection of Little Otter Creek as a spot to model a potential spill did not adequately represent the risks of a potential spill to the St. Louis River estuary, the Duluth-Superior harbor and Lake Superior.

State regulators approve Enbridge Line 3 oil pipeline replacement – Minnesota regulators gave Enbridge Energy the green light to replace its 1960s-era Line 3 pipeline. The Public Utilities Commission (PUC) voted 3-1 Monday to approve an updated environmental review for the $2.6 billion project after finding it adequately assessed for potential oil spills. The PUC also voted 3-1 to approve Enbridge’s certificate of need and route permit for the pipeline. The PUC previously approved the above permits, which the Minnesota Court of Appeals vacated in June, saying that the Minnesota Department of Commerce (DOC) didn’t adequately assess the effects of a possible oil spill near the Lake Superior watershed. The DOC later said there isn’t much likelihood of a potential oil spill reaching Lake Superior. The Enbridge project would replace Line 3’s 337-mile long, 34-inch pipeline in Minnesota, which is operating at 51 percent capacity due to corrosion, with a new 36-inch pipeline. The replacement would boost average oil flow to 760,000 barrels per day. Supporters claim the project will create 8,600 jobs. Enbridge says the company would pay around $65 million in Minnesota property taxes in the project’s first functional year. Critics point to past harmful crude oil spills that contaminated water sources. Commissioner Matt Schuerger cast the lone vote against Enbridge, citing climate-change concerns and long-term lower demand for crude oil due to electric vehicles.

In second Line 3 approval, state regulators take up safety, spills – and climate change – Minnesota utility regulators have once again given their blessing to Line 3, the oil pipeline replacement project Enbridge Energy has proposed for northern Minnesota – but not before having a sometimes heated discussion about the project’s impact on climate change.About a year and a half ago, the Minnesota Public Utilities Commission first approved Line 3. But after the state appeals court threw out the project’s environmental review, the project was back in front of commissioners.They were faced with three decisions:First, whether to approve the revised environmental study – which had been updated to include analysis of a potential oil spill in the Lake Superior basin.Then, whether to reissue the project’s certificate of need – essentially, a declaration that the state needs the project.And last, whether to reapprove the project’s route.The last time Line 3 came before the commission – in June 2018 – the commissioners approved the need for Line 3 and the environmental impact study unanimously.But Monday, Commissioner Matt Schuerger said several things had changed since 2018 that caused him to change his vote on all three questions before the PUC. He said it was no longer clear whether there was proven demand for the extra oil the pipeline would carry – nearly twice the capacity of the current Line 3. And he said the science of climate change has become even clearer in the last year and a half.”We will not flip the switch and stop using oil, I don’t contend that,” he said during deliberations, “but I do understand that there are actions being taken by jurisdictions around the world, around the country and especially in this state, to act and change the way we use energy.” Groups opposing the Line 3 project have argued that building a new pipeline undermines efforts the state is making to address climate change: The extra crude oil the expanded pipeline would carry would eventually be burned, creating more greenhouse gas emissions, which contribute to climate change.

The long, exhausting battle against Enbridge for our lands and water – – Winona LaDuke – Enbridge’s 7-year battle for a new pipe line has worn us all thin. We have poured out by the thousands, over 68,000 people went to testify against the Enbridge tar sands pipeline. We have driven thousands of miles. We have cried, talked about how much we love our water, and we have faced gauntlets of police. We’ve been turned away by state officials. We’ve seen our prayers for a system (which is supposed to work for the people, not the corporations) trampled. That’s Enbridge’s Line 3 Battle. Here we are in 2020 and the Minnesota Public Utilities Commission (PUC) and Enbridge are still trying to shove a pipe down our throats – through 44 wild rice watersheds, crossing the Mississippi, and all to bring the dirtiest oil in the world to some tankers and sell this stuff overseas. It’s called regulatory exhaustion. In early February, PUC will again review the Environmental Impact Statement (EIS) it has modified. This is supposed to talk about the actual impact of putting the equivalent of 50 new coal-fired power plants on line, using 400 more megawatts of power to move some sludge across the north, and poisoning the fragile social graces of the north, by encouraging racism, Indian hating, and threats. The PUC was court-ordered last June to fix this EIS by including the impact of a possible oil spill on Lake Superior and the Lake Superior Watershed. The company and PUC have come back with a very light-handed statement. More people testified last month in Duluth about why this supplemental environmental impact statement was faulty. Then in January, the Appeals Court also told the PUC that it must do an environmental impact statement for the Nemadji Trail Energy Center, a core part of new power needs for the new pipeline. It would appear that the PUC perceives it can just approve projects without a rigorous environmental assessment, because this is the third time that PUC has been court ordered to do a statement prior to approving a project: It failed to prepare an EIS for the proposed Sandpiper crude oil pipeline; it failed to prepare an adequate EIS for Line 3; and it failed to conduct an environmental review for Nemadji Trail Energy Center.

Trump Moves to Open Utah Monuments for Mining and Drilling – The Trump administration on Thursday implemented plans to downsize two national monuments in Utah, ensuring the lands previously off-limits to energy development will be open to mining and drilling. The action comes despite lawsuits by by conservation, tribal and paleontology groups seeking to restore the original boundaries. The lands have generated little interest from energy companies in the two years since President Donald Trump cut the size of Bears Ears National Monument by 85% and Grand Staircase-Escalante National Monument by nearly half, said Casey Hammond, acting Assistant Secretary for Land and Minerals Management with the U. S. Department of the Interior. Hammond said the department had a duty to work on the management plans after Trump signed his proclamations in December 2017, despite the pending lawsuits. “If we stopped and waited for every piece of litigation to be resolved we would never be able to do much of anything around here,” he said. Conservation groups that have called the decision the largest elimination of protected land in American history criticized the administration on Thursday for spending time on management plans they believe will become moot. They contend Trump misused the Antiquities Act to reverse decisions by previous presidents. A federal judge last year rejected the administration’s bid to dismiss the lawsuits. In a recent court filing, tribal groups said the Bears Ears lands are “a living and vital place where ancestors passed from one world to the next, often leaving their mark in petroglyphs or painted handprints, and where modern day tribal members can still visit them.”

Elk Creek Pipeline, Demicks Lake Gas plant completed – Oneok bought into the Bakken in 2008 with the Grasslands plant in Sidney, Mont., a plant that at the time could process 50 million cubic feet per day of natural gas. Twelve years and $10 billion dollars later, it will soon reach its goal of processing 1.4 billion cubic feet of the Bakken’s natural gas per day. “That is billion with a ‘B,’” Lt. Gov. Brent Sanford noted in recent remarks to a crowd of dignitaries gathered to mark completion of the Elk Creek Pipeline and the Demicks Lake Gas plant, which was mothballed during the downturn amid a drastic drop in oil prices. “I don’t know how many times I asked (Oneok officials), ‘When that is coming back?'” Sanford said, adding he had followed media coverage of the plant’s fate when the plant was put back on the drawing board two years ago. “It took two years from that point to get something like this built,” Sanford said, adding that flaring then was 284 million cubic feet per day. “Now it’s 546 million,” Sanford said. “It’s doubled in that two years, and we wish we lived in a fantasy land that the 400 this plant represents is going to take all of it. But we know it won’t. We don’t know how much is covered under exemptions, but we know that this has to take a good chunk of that flaring down.” “At one point in the summer, we had more than 12,000 contractors working across our locations in our footprint,” Burdick said. “And we did it all in a safe and environmental way. The goal is obviously, now that these assets are in place, let’s go put out the flares.”

Radioactive oilfield waste topic of study following Williams County landfill denial – Officials in oil patch counties hope a study on radioactive waste will offer guidance on how to handle applications from companies seeking to store the material in landfills. The study commissioned by the Western Dakota Energy Association comes after Williams County in December denied a request from Secure Energy Services to begin disposing of the waste at the company’s landfill north of Williston. The process of reviewing that application prompted a lot of questions from the public and among county officials, including Williams County Commissioner David Montgomery. “My concern was once we open that window of opportunity, if we did for one facility, how many more are we going to get?” he said. “If we approve one, it’s pretty hard to deny any more.” The study seeks to collect and consolidate a significant amount of information from the state, counties and the oil and gas industry about radioactive waste to try to answer officials’ questions and help them plan, “What I’m trying to do is help the counties gather this information and put it into a format that is understandable for them and for them to share with their constituents, the public,” he said.

Pipeline CEO ‘scared to death’ of fracking ban — Thursday, February 6, 2020 — – The CEO of the company known for the Dakota Access pipeline said yesterday he’s terrified of the risk from politicians who want to end hydraulic fracturing – a position that’s supported by some Democrats running for president.

Saltwater spill near Sherwood larger than initially reported – A saltwater spill in Renville County initially reported more than two weeks ago as 200 barrels is larger and could have contaminated as much as 400,000 square feet of soil. “We know it’s bigger, we know it’s impacting a very large area,” said Bill Suess, spill investigation program manager for the North Dakota Department of Environmental Quality. Officials do not yet have an updated spill volume. The initial 200-barrel amount reported by operator Cobra Oil & Gas on Jan. 13 is equivalent to 8,400 gallons. The fluid that spilled, commonly known as brine, is highly saturated saltwater that comes up alongside oil and gas at well sites. It’s typically injected back underground at disposal wells for permanent storage. When it spills and is not contained to a well pad, it can render farmland infertile. The brine leaked from a pipeline and contaminated a field north of Sherwood near the Canadian border. A number of pipelines exist in the area, and it’s possible the leak could have come from more than one, Suess said. Workers at the site are trying to determine the scope of the spill — how far contamination has extended horizontally and vertically from the site of the leak, he said. “This is an older pipeline that was probably leaking for a period of time,” he said. “We’ve got to find out exactly how far it’s gone.” A summary of the incident maintained by the state says the contamination is 8 feet deep in some areas.The landowner, Sherwood resident Allan Engh, said people involved in the cleanup of the site told him the brine could have contaminated as much as 400,000 square feet of soil, which is about 9 acres. Suess said that estimate could be accurate but the official number is not yet known.So far, the reclamation effort has involved digging up the soil around the pipeline to expose part of the line, and crews have been hauling away brine and groundwater. “It’s that initial scramble to contain as much as they can to keep it from spreading,” Suess said.

California’s multibillion-dollar problem: the toxic legacy of old oil wells – Center for Public Integrity – Across much of California, fossil fuel companies are leaving thousands of oil and gas wells unplugged and idle, potentially threatening the health of people living nearby and handing taxpayers a multibillion-dollar bill for the environmental cleanup. From Kern County to Los Angeles, companies haven’t set aside anywhere near enough money to ensure these drilling sites are cleaned up and made safe for future generations, according to a months-long data analysis and investigation by the Los Angeles Times and the Center for Public Integrity. Of particular concern are about 35,000 wells sitting idle, with production suspended, half of them for more than a decade. Though California recently toughened its regulations to ensure more cleanup funds are available, those measures don’t go far enough, according to a recent state report and the Times/Public Integrity analysis. California’s oil industry is in decline, which increases the chances that companies will go out of business. That in turn could leave the state with the costs for cleaning up their drilling sites, which if left unremediated can contaminate water supplies and waft fumes into people’s homes. Under federal, state and local laws, fossil fuel companies are required to post funds, called bonds, to ensure that wells are ultimately plugged and remediated. Industry representatives say they are doing their part to pay for cleanup in California, but their bonds are woefully inadequate to meet the expected costs. The Times/Public Integrity investigation found that bonds posted to the state by California’s seven largest drillers, which account for more than 75% of oil and gas wells, amount to about $230 on average for every well they must decommission.. By contrast, the average per-well cost for capping wells and dismantling associated surface infrastructure in California is between $40,000 and $152,000, depending on whether a well is in a rural or urban area, according to a study released in January by the California Council on Science and Technology. The result is a yawning gap between what the industry has provided and what ultimately will be needed. Companies have given the state only $110 million to clean up the state’s onshore oil and gas wells, the council found. By contrast, it could cost roughly $6 billion for that cleanup, according to a Times/Public Integrity analysis of state data provided to the science and technology council. Decommissioning offshore oil wells and platforms, which is not included in those figures, will cost several billion dollars more.

Shell Divests California Refinery – Shell Oil Products US (Shell) has formally closed on the sale of the Martinez Refinery in California to PBF Energy, Inc., Royal Dutch Shell plc reported Saturday. PBF acquired the Bay Area refinery and the facility’s inventory for $1.2 billion, and the deal includes crude oil supply, product offtake agreements and other adjustments, Shell added. As a June 12, 2019, Rigzone article announcing the transaction points out, the Martinez facility was Shell’s only refinery in the Golden State. The deal gives PBF its second refinery on the West Coast. “The acquisition of Martinez is a significant strategic step for PBF as we expand our West Coast operations,” commented PBF Chairman and CEO Tom Nimbley in a separate written statement. “Martinez is a top-tier asset, is a perfect complement to our existing assets and provides increased opportunities for PBF’s West Coast to deliver value.” Located 30 miles (48 kilometers) northeast of San Francisco, the 157,000-barrel-per-day high-conversion Martinez Refinery boasts a Nelson Complexity Index of 16.1, noted PBF, which also owns a former Exxon Mobil Corp. refinery in Los Angeles County. PBF and Shell stated that they have agreed to jointly move forward with reviewing the feasibility of building a proposed renewable diesel project at Martinez that would repurpose existing idled equipment. According to Shell, crude supply and product offtake agreements from the sale will enable PBF to supply Shell-branded businesses with Shell-branded fuels. The supermajor added that the deal excludes its associated branded fuel businesses, aviation terminal and Catalysts business in the area. Shell stated that its presence in California will focus on Upstream and New Energies business investments. It also noted that local employees providing dedicated support to the Martinez facility were all offered employment with PBF.

Belugas Are Dying off in Alaska and Oil and Gas Operations Are to Blame, Says Lawsuit – Two environmental groups made a formal announcement that they will file a lawsuit to protect endangered belugawhales whose numbers have plummeted recently, as the AP reported.The suit aims to void permits allowed by the National Oceanic and Atmospheric Administration (NOAA) that opened up oil and gas exploration in Cook Inlet in southern Alaska. The suit alleges that NOAA violated theEndangered Species Act by issuing the permits without protecting Cook Island belugas. The law requires the formal 60-day notice before the agency can be sued, according to The Associated Press.The Center for Biological Diversity and Cook Inletkeeper teamed up to send notice that they will sue NOAA.NOAA’s National Marine Fisheries Service (NMFS) released a disturbing new population estimate last week that showed whale numbers are far lower than previous estimates and their numbers are dropping rapidly, asReutersreported.The NMFS report estimated that only 279 beluga whales remain in Cook Inlet, a steep decline from the nearly 1,300 that lived there in 1979. The population decline has accelerated to an annual rate of 2.3 percent over the last decade, which is four times faster than previous estimates, according to NMFS, as Reuters reported.Cook Inlet runs almost 200 miles from Anchorage to the Gulf of Alaska. It supplies energy for the south-central part of the state. The industrial activities there threaten beluga whales, which swim there and feast on salmon and other fish, according to The Independent. The Center for Biological Diversity said these “daunting” numbers mean exploration planned by Hillcorp Alaska needs to stop immediately, as The Independent reported.

Democratic senators ask banks to prohibit funding Arctic drilling – A group of 15 Democratic senators wrote to 11 major banks last week asking them to ban funding oil and gas drilling or exploration in the Arctic National Wildlife Refuge. “The scale of your banks’ assets individually, let alone together, give you the ability to drive change in protecting the Arctic National Wildlife Refuge and in shifting towards a U.S. financial sector that effectively analyzes and plans for climate risks,” the senators wrote. “We respectfully urge you to reassess your current environmental and climate policies and update them to include a prohibition on funding for oil and gas drilling or exploration in the Arctic National Wildlife Refuge,” they continued. Their letter follows a December announcement by Goldman Sachs that it would prohibit financing for new drilling or exploration in the Arctic, including in the refuge. “As one of the largest banks operating in the United States, we write to ask that you join your peers in the U.S. and abroad and commit to stop financing of oil and gas drilling and exploration in the Arctic National Wildlife Refuge,” the letter stated. “Protection of the Arctic National Wildlife Refuge is not only intrinsically important, it is also critical in the broader context of wilderness protection, Indigenous rights, working to combat climate change, and preparing the U.S. economy to weather the growing impacts of the climate crisis.” Their letters were addressed to executives atJPMorgan Chase & Co., Bank of America Corporation, Citigroup Inc., Wells Fargo & Co., Morgan Stanley, U.S. Bancorp, PNC Financial Services Group, Inc., TD Bank, Capital One Financial Corp., Citizens Financial Group, Inc., and HSBC North America Holdings Inc.

Trump State of the Union’s brief environmental interlude: more oil, more trees – The reality TV president delivered a reality TV State of the Union Tuesday night. Over the course of 80 sometimes raucous minutes, he awarded a school voucher to a Philadelphia 4th grader, had the first lady present conservative shock jock Rush Limbaugh with the Presidential Medal of Freedom, and reunited a military service member with his family.Along the way, he ticked off a checklist of statistics, claims, and promises designed to galvanize his colleagues on the right side of the aisle. The most prominent parts of the speech touted the strong economy, celebrated the administration’s crackdown on immigration, and decried an alleged Democratic attempt to engineer a socialist takeover of healthcare.One phrase that didn’t pass the president’s lips – to nobody’s surprise – was climate change.Trump devoted just a few seconds of his address to energy and environmental issues: first by celebrating the massive oil and gas boom that has made the U.S. a net exporter of oil, and later by reiterating his commitment to joining an international initiative to plant one trillion trees worldwide.The president took credit for the recent increase in domestic fossil fuel production, suggesting that it was his administration’s “bold regulatory reduction campaign” that made the U.S. the top producer of oil and natural gas in the world. But the U.S. actually reached that milestone under the Obama administration. Thanks to the explosion in fracking beginning in 2008, the U.S. became the top producer of natural gas in 2009 and of oil in 2013, according to the Energy Information Administration.The president then went further, claiming that the boom has made the U.S. “energy independent” – ignoring the fact that the country is still subject to the global oil market, and that turbulence in the Middle East and elsewhere has the ability to affect gas prices in the U.S.The dramatic increase in stateside oil and gas extraction has also generated environmental and public health consequences that went unacknowledged in Tuesday’s address. Though U.S. emissions likely fell by about two percent last year, those reductions are nowhere close to the cuts required to meet the targets set under the international Paris Agreement, which scientists say are essential to avoiding the most catastrophic effects of climate change. Research also suggests that increased pollution from the oil and gas boom could reverse that fragile progress.

Shale pioneer John Hess says key U.S. fields starting to plateau (Reuters) – Shale pioneer John Hess said on Tuesday that key U.S. shale fields are starting to plateau, calling shale “important but not the next Saudi Arabia.” Over the past decade, the shale revolution turned the United States into the world’s largest crude producer and a force in energy exports. Yet that did not translate to higher stock prices or returns for investors, with the S&P 500 Energy sector only gaining 6% in a decade, far less than the 180% return for the broader stock market. Companies remain under pressure to trim budgets and produce enough free cash flow to pay investors higher dividends or buy back shares. The biggest industry challenge is the lack of long-term investment, Hess said. Production in the Eagle Ford Shale in South Texas is starting to plateau, while the Bakken field in North Dakota where Hess is a major producer will hit its peak production levels within the next two years, said Hess, who spoke Tuesday in Houston at the Argus Americas Crude Summit. The Permian Basin, the top U.S. shale field in Texas and New Mexico, will plateau in mid-decade and is already facing well interference issues, Hess said. That means the Organization of the Petroleum Exporting Countries will continue to act as the “Federal Reserve of oil,” he said. Hess plans to use cash flow from the Bakken to invest in longer-term offshore investments. The company is relying on offshore Guyana, one of the world’s most important oil and gas discoveries in the last decade, which is being developed by a consortium led by oil major Exxon Mobil Corp (XOM.N). In the Bakken, Hess said the company expects to reach 200,000 barrels per day of production next year. It would then sideline two of its six drilling rigs in the field for several years to hold production steady. In the short term, “the oil market is awash in oil right now, in part because of panic created by the coronavirus,” Hess said. “It’s a major headwind.” The industry also has to respond to the threat of climate change, Hess said.

Jim Cramer, ‘Mad Money’ host, declares fossil fuels dead —ExxonMobil and Chevron stocks sank Friday morning after both oil companiesreported disappointing fourth quarter earnings. How does influential TV financial analyst Jim Cramer make sense of that? The Mad Money host thinks it’s time to ditch oil companies – and not just because they’re currently a drag on the Dow.On Friday’s Squawk Box, a pre-market morning show, the TV host and former hedge fund manager stunned CNBC anchor Rebecca Quick by saying that oil companies are in the “death knell phase.”“I’m done with fossil fuels. They’re done,” he said. “We’re starting to see divestment all over the world. We’re starting to see … big pension funds saying, ‘Listen, we’re not gonna own them anymore.’” “The world’s changed,” Cramer added later. “This has to do with new kinds of money managers who frankly just want to appease younger people who believe that you can’t ever make a fossil fuel company sustainable.”

Oil Sands Spending Set for First Jump Since 2014 Crash — Investment in Canada’s oil-sands is forecast to grow for the first time since prices crashed in 2014. Capital spending in the the world’s third-largest crude reserves is projected to rise 8.4% to C$11.6 billion ($8.8 billion) this year, according to the Canadian Association of Petroleum Producers, the industry’s main lobbying group. The forecast signals a tentative return of optimism to the oil sands, where pipeline bottlenecks and environmental opposition made expansion difficult even after oil prices rebounded in recent years. CAPP attributes the expected gain to tax cuts implemented by Alberta’s new government and an easing of the province’s output limits. “The increase in capital investment is a very positive sign for the upstream sector, and there is a lot more work to be done to keep this momentum,” CAPP Chief Executive Officer Tim McMillan said in a statement. That work includes Alberta’s plans to reduce red tape, as well as reforms to municipal taxes, he said. Even with this year’s increase, the industry is still a long way from its headiest days. The projected oil-sands spending for 2020 is about a third of the peak of C$33.9 billion in 2014, according to CAPP figures. Expenditures for Canada’s oil and natural gas sector as a whole may increase 5.4% to C$37 billion. Outside the oil sands, spending is projected to rise 4.1% to C$25.4 billion. The additional C$2 billion in capital spending this year will create or sustain about 11,800 direct and indirect jobs across Canada, the organization projected.

Trudeau’s Oil Pipeline Gets a Win in Court– The Canadian government’s plan to expand a major oil pipeline cleared a key legal hurdle, providing optimism that the project may proceed and sending a lifeline to the country’s ailing energy industry. The Federal Court of Appeals in Ottawa ruled that Prime Minister Justin Trudeau’s government adequately consulted with indigenous communities along the line’s route and that the regulatory review of the project included all necessary elements. The ruling signals that one of the final remaining major legal challenges to the project may be overcome, which would help keep construction from being interrupted and allow the expanded line to start shipping oil by its 2022 target. However, the ruling is almost certain to be appealed to Canada’s Supreme Court, “The final judicial review rests at the Supreme Court of Canada level, and until it’s weighed in, the process is not over.” The Trans Mountain project has been highly anticipated by Canada’s oil producers, which have suffered from a lack of pipeline capacity that has weighed on local crude prices and stymied plans to expand output. The project would boost daily shipping capacity by 590,000 barrels, to a total of 890,000 barrels. Expanding the line, which runs from Edmonton to a shipping terminal near Vancouver, also would open the possibility of developing new markets for Canadian crude in Asia and reducing dependence on U.S. refiners. The Trans Mountain expansion has had a long and troubled history. Amid mounting opposition, original owner Kinder Morgan Inc. threatened to walk away from the project, prompting Trudeau’s government to agree to buy the existing line for about C$4.5 billion ($3.4 billion) in 2018 to salvage the project. Before that deal had even closed, the appeals court nullified the Trans Mountain expansion’s approval in August 2018, ruling that the project’s regulatory review was flawed because it didn’t examine the effects of additional tanker traffic. The court also said Trudeau’s government hadn’t consulted enough with First Nations along the route. The Federal Court of Appeals ruled on Tuesday that the government’s additional consultation was “a genuine effort in ascertaining and taking into account the key concerns of the applicants, considering them, engaging in two-way communication, and considering and sometimes agreeing to accommodations.”

Canadian court upholds Trans Mountain pipeline expansion approval – Canada’s federal court of appeal has dismissed legal objections to the contentious Trans Mountain pipeline expansion that would nearly triple the flow of oil from the Alberta oil sands to the Pacific coast. In a 3-0 decision, the court rejected four challenges from First Nations in British Columbia to the federal government’s approval of the project. That means construction can continue on the project, though the First Nations have 60 days to appeal to the supreme court. The natural resources minister, Seamus O’Regan, said the ruling proves that if consultations and reviews are done properly, major projects can be built in Canada. “The courts have acknowledged that we listened and that we want to do things right,” O’Regan said. The pipeline expansion would triple the capacity of an existing line to carry oil extracted from the oil sands in Alberta across the snow-capped peaks of the Canadian Rockies. It would end at a terminal outside Vancouver, resulting in a sevenfold increase in the number of tankers in the shared waters between Canada and Washington state. Tanker traffic is projected to balloon from about 60 to more than 400 vessels annually as the pipeline flow increases from 300,000 to 890,000 barrels a day. The decision is a blow for indigenous leaders and environmentalists, who have pledged to do whatever necessary to thwart the pipeline, including chaining themselves to construction equipment What if Canada had spent $200bn on wind energy instead of oil? Read more Chief Lee Spahan of the Coldwater Indian Band said in a statement an appeal to the supreme court is under consideration. Many indigenous people see the 620 miles (1,000km) of new pipeline as a threat to their lands, echoing concerns raised by Native Americans about the Keystone XL project in the US. Many in Canada say it also raises broader environmental concerns by enabling increased development of the carbon-heavy oil sands. Justin Trudeau’s government bought the existing pipeline and the expansion plan in 2018 after political opposition to the project from the British Columbia government caused Kinder Morgan Canada to pull out from building the expansion

Enbridge Says Mainline Opponents are Stalling for Time | Rigzone — Enbridge Inc. said opponents of its plan to convert the Mainline oil pipeline network to a contract system may be stalling for time, hoping to see what happens on other lines that are in the works before making long-term commitments on its system. Opponents of Enbridge’s proposal, including Canadian Natural Resources Ltd. and the Explorers & Producers Association of Canada, have asked that the Canada Energy Regulator split the approval process for the plan into two. The first part would address whether the conversion should even be allowed. That scenario would be unique, and would likely make the entire regulatory process longer, said Vern Yu, the head of Enbridge’s liquids pipelines business. Pipeline projects including the Trans Mountain expansion, TC Energy Corp.’s Keystone XL and Enbridge’s Line 3 expansion face key obstacles this year that could affect their timelines or even their ultimate fate. “It might be strategic from some of these shippers because it would help them gain more clarity on what’s happening on some of the other pipelines that are under development,” Yu said in an interview. “It would be a way for them to gain an advantage as they make decisions going forward.” Yu reiterated that Enbridge’s plan to lock shippers on the Mainline into contracts of as long as 20 years — a change from the current system, in which space is allocated on a monthly basis — has the support of customers accounting for more than 70% of the volume on the system. The plan will provide shippers with certainty on tolls and market access. Oil-sands producer Cenovus Energy Inc. and LyondellBasell Industries NV, which owns a Houston refinery that receives crude from the Mainline, were among companies noting their support of the change in filings on Thursday. The Mainline is Canada’s largest oil pipeline network, with the capacity to ship about 2.85 million barrels a day.

Canadian Town Evacuated After Another Oil Train Derails and Burns – Early in the morning of Feb. 6, an oil train derailed and caught fire near Guernsey, Saskatchewan, resulting in the Canadian village’s evacuation. This is the second oil train to derail and burn near Guernsey, following one in December that resulted in a fire and oil spill of 400,000 gallons.According to the CBC, eyewitness Kyle Brown reported that “he saw a huge fire after the train derailed.””It looks like an inferno,” said Brown. “Like a war zone, really. It is pretty bad.”The Canadian Pacific (CP) train was carrying crude oil and reportedly derailed approximately 2.5 kilometers (1.5 miles) from town. News reports indicate that the train crew escaped without harm.Local resident Blaine Weber spoke to the Global News after this second derailment and expressed frustration that Canadian Pacific Railway, the rail company operating the trains, has not been forthcoming with answersabout the derailments.“CP doesn’t seem to be answering any questions from either the public or the authorities,” Weber said. Canadian Pacific also is under scrutiny over a potential cover up of the details surrounding a runaway freight train accident in 2019 that resulted in the death of all three crew members. A month ago I wrote that the forecast for oil by rail for 2020 would include more trains, fires, and spills. The Canadian oil industry is moving record volumes of oil by rail to the U.S. and with that increase, expect to see more accidents. Last week, Reuters reported that the CEO of Imperial Oil, a Canadian subsidiary of ExxonMobil, which lobbied against new oil-by-rail regulations in the U.S., was eager to ship more oil by train. “We see with the current differentials and arbitrage, it makes good economic sense for us to ship barrels on the rail,” said Brad Corson, CEO of Imperial. As DeSmog has reported in detail, these trains are currently unsafe to operate. The new tank cars that regulators and the rail industry promised were a safety improvement for reducing oil spills and explosions have now failed in five out of five major derailments. U.S. regulations requiring oil trains to have modern braking systems, known as electronically controlled pneumatic (ECP) brakes – which Canadian operators would have had to comply with as well – were repealed in 2017.

BP full-year net profit falls 21% on weak oil and gas prices – Energy giant BP reported better-than-expected full-year net profit on Tuesday, outperforming analyst expectations despite lower oil and gas prices. The U.K.-based oil and gas company posted full-year underlying replacement cost profit, used as a proxy for net profit, of $10 billion in 2019. That compared with $12.7 billion full-year net profit in 2018, reflecting a year-on-year fall of 21%. Analysts had expected full-year net profit to come in at $9.7 billion in 2019, according to data from Refinitiv. Shares of BP were up more than 4%. “BP is performing well, with safe and reliable operations, continued strategic progress and strong cash delivery,” Bob Dudley, CEO of BP, said in a statement. Underlying replacement cost profit for the fourth quarter and full-year 2019 was $2.6 billion and $10.0 billion respectively, compared to $3.5 billion and $12.7 billion for the same periods a year earlier. Gulf of Mexico oil spill payments for the year totaled $2.4 billion on a post-tax basis, and are expected to be less than $1 billion in 2020. A dividend of 10.5 cents per share was announced for the quarter, an increase of 2.4% on a year earlier. The energy giant’s full-year results follow disappointing earnings from oil and gas companies on both sides of the Atlantic.

.