Written by rjs, MarketWatch 666
Here are some selected news articles from the week ended 29 February 2020.
This article is a feature every Monday evening on GEI.
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Oil prices fall 16%, biggest drop since 2008; natural gas prices end at a 4 year low, near a 21 year low
Oil prices fell by more than 2% each day this week and ended down by the most in any week since 2008, as building awareness of the economic impacts of the coronavirus epidemic finally battered financial markets worldwide….after rising 2% to $53.38 a barrel on oil supply cutoffs in Libya and Venezuela last week, the contract price of US light sweet crude for April delivery opened more than 1% lower on Monday and skidded to a 4% loss, as the rapid spread of coronavirus in countries outside China left investors concerned about a big hit to demand, with US crude ending $2.12 lower at $51.26….oil prices continued lower Tuesday, as concerns about the spread of the coronavirus outweighed OPEC talk of output cuts and Libyan supply losses and oil prices settled down $1.53, or 3%, at $49.90 a barrel, the lowest settlement in two weeks…oil prices briefly rose back above $50 a barrel on Wednesday, as both the API and EIA reported smaller than expected crude inventory builds, but then fell to their lowest in more than a year after hundreds of new coronavirus cases in Europe and the Middle East stoked fears that energy demand would drop, with April US crude closing $1.17 lower at $48.73 a barrel…oil prices then fell for a fifth straight day on Thursday as the growing number of new coronavirus cases outside of China fueled fears of a pandemic which would lower crude demand and ended $1.64 lower at $47.09, the lowest close since January 2019…fears that a slowing global economy would hit energy demand continued to push prices lower Friday, with oil prices at one point down almost 7% to $43.85 a barrel, before shaving the day’s losses to end down 5% at $44.76 a barrel, after fears over the outbreak had sent shares on Wall Street down by the most in almost a decade….oil prices thus finished more than 16% lower on the week, the biggest weekly drop since December 2008, with the spread of the COVID-19 epidemic around the world expected to significantly dent demand for crude…
With oil prices seeing such a significant drop, we’ll include a graph of their recent trajectory so you can see how fast and how far they’ve fallen..
The graph above is a screenshot of the interactive daily price chart for the April 2020 oil contract at Barchart.com, “the leading provider of real-time or delayed intraday stock and commodities charts and quotes”, and it shows the range of prices for that April contract as a vertical bar for each day over the past year…you might also note that each bar has two small horizontal appendages: the one on the left is the opening price for the day the bar indicates, while the appendage on the right is the day’s closing price…what you’ll want to notice is that the contract price for April oil hit a 14 month high at $64.05 a barrel on January 6th of this year and has been falling since, and is now more than 30% off that high and is down by 27% since the beginning of the year…
Natural gas prices also finished much lower this week, with the April gas contact ending at an all time low, while the front month price as quoted daily slid to its lowest level in 4 years…after rising 3.7% to $1.905/mmBTU on the strength of a late-winter cold snap last week, the contract price of natural gas for March delivery fell 7.8 cents to $1.827 on Monday, following further warming in the latest weather models….the March contract price then moved up 2.0 cents on Tuesday but fell 2.6 cents on Wednesday as trading in the March contract expired at $1.821 per mmBTU….meanwhile, the price of natural gas contracts for April delivery, which had ended last week at $1.917 per mmBTU, had fallen to $1.837 per mmBTU by the close on Wednesday, then fell 8.5 cents on Thursday to settle at a four year low of $1.752 per mmBTU, on what was called “a paltry draw” of natural gas from storage…the April contract price was then down another 6.8 cents to $1.684 per mmBTU on Friday, as traders brushed off the last fleeting cold spell of the season and like oil, turned their focus to the possible impacts that the coronavirus impact might have on demand…that left the April natural gas down more than 12% on the week at an all time low for the contract, while the quoted “price of natural gas” was at a 4 year low, and closing in on the lowest price since the third quarter of 1998…
With natural gas prices also at significant lows, we’ll also include a pair of charts on their recent trajectory…
The graph above is a screenshot of the interactive monthly price chart for the nearby natural gas futures contract at Barchart.com, and like the oil graph we showed earlier, it shows the range of prices, in dollars per mmBTU, for the nearest natural gas futures contract as a vertical bar for each month over the past 12 years…this graph was compiled by taking quotes for what is called the “front month” natural gas contract, or the contract that is being quoted as “the price of natural gas” daily, with the each monthly contract price being replaced by the next one when trading in that contract expires on the third business day before the end of the preceding month…the lowest natural gas price on this graph is from early March 2016, when the April 2016 contract briefly traded at $1.611 per mmBTU…the lowest price that natural gas saw this past week was on Friday, when April 2020 gas briefly traded at $1.642 per mmBTU, before ending the week at $1.684…
In contrast to that graph, this next graph from the same interactive site shows the monthly price of the April 2020 natural gas contract over the last 12 years, and you can clearly see that the current price for that contract is at a life of contract low…in the futures market, one can lock in a price to buy or sell a commodity 20 years in the future…thus, during the month of March 2016, when natural gas was being quoted at prices ranging between $1.611 and $2.032 per mmBTU, one could enter into a contract to buy or sell natural gas in April 2020 at prices ranging from $2.660 to $2.884 per mmBTU, obviously well above the daily price…thus, when we’ve said in the past that a given natural contract price was at an all time low, it’s this future’s price that we are referring to…spot natural gas prices, or what physical natural gas might trade at on a given day, were as low as $1.50 in the mid-1990’s, even as the long term future prices for gas were $1 higher…
Meanwhile, the natural gas storage report on the week ending February 21st from the EIA indicated that the quantity of natural gas held in storage in the US fell by 143 billion cubic feet to 2,200 billion cubic feet by the end of the week, which left our gas supplies 637 billion cubic feet, or 40.8% higher than the 1563 billion cubic feet that were in storage on February 21st of last year, and 179 billion cubic feet, or 8.9% above the five-year average of 2,121 billion cubic feet of natural gas that has been in storage as of the 21st of February in recent years….the 143 billion cubic feet that were withdrawn from US natural gas storage this week was smaller that the consensus estimate for a 155 billion cubic feet withdrawal, and was also less than the 167 billion cubic feet withdrawal reported during the corresponding week of last year, but was still more than the average 122 billion cubic feet of natural gas that have been pulled from natural gas storage during the third week of February 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 February 21st indicated that a decrease in our oil imports was mostly offset by a decrease in our refinery throughput, again leaving us with a bit of oil left to add to our stored commercial supplies for the sixteenth time in the past twenty-four weeks….our imports of crude oil fell by an average of 330,000 barrels per day to an average of 6,217,000 barrels per day, after falling by an average of 431,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 93,000 barrels per day to 3,657,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,560,000 barrels of per day during the week ending February 21st, 423,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was unchanged at 13,000,000 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 15,560,000 barrels per day during this reporting week..
US oil refineries reported they were processing 16,008,000 barrels of crude per day during the week ending February 21st, 202,000 fewer 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 65,000 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 512,000 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 (+512,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the daily supply of oil and the consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…nonetheless, since the media treats these figures as gospel and since they drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as accurate by most everyone else (for more on how this weekly oil data is gathered, and the possible reasons for that “unaccounted for” oil, see this EIA explainer)….
Further details from the weekly Petroleum Status Report (pdf) indicate that the 4 week average of our oil imports fell to an average of 6,589,000 barrels per day last week, now just 1.6% less than the 6,699,000 barrel per day average that we were importing over the same four-week period last year….the 65,000 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 remained unchanged….this week’s crude oil production was reported to be unchanged at 13,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 12,500,000 barrels per day, while a 8,000 barrel per day decrease Alaska’s oil production to 474,000 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 22nd was rounded to 12,100,000 barrels per day, so this reporting week’s rounded oil production figure was 7.4% above that of a year ago, and 54.2% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…
Meanwhile, US oil refineries were operating at 87.9% of their capacity in using 16,008,000 barrels of crude per day during the week ending February 21st, down from 89.4% of capacity the prior week, but still close to the recent average refinery capacity utilization for the third week of February…nonetheless, the 16,008,000 barrels per day of oil that were refined this week were fractionally more than the 15,890,000 barrels of crude that were being processed daily during the week ending February 22nd, 2019, when US refineries were operating at 87.1% of capacity….
Even with the decrease in the amount of oil being refined, gasoline output from our refineries was somewhat higher, increasing by 272,000 barrels per day to 9,797,000 barrels per day during the week ending February 21st, after our refineries’ gasoline output had increased by 284,000 barrels per day over the prior week… after this week’s increase in gasoline output, our gasoline production was 2.6% higher than the 9,553,000 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 6,000 barrels per day to 4,846,000 barrels per day, after our distillates output had increased by 15,000 barrels per day over the prior week…after this week’s small change in distillates output, our distillates’ production for the week was fractionally above the 4,816,000 barrels of distillates per day that were being produced during the week ending February 22nd, 2018….
Despite the increase in our gasoline production, our supply of gasoline in storage at the end of the week fell for the fourth week in a row, after twelve consecutive increases, but were still down for the 18th time in 36 weeks, falling by 2,691,000 barrels to 256,387,000 barrels during the week ending February 21st, after our gasoline supplies had decreased by 1,971,000 barrels over the prior week….our gasoline supplies decreased by more this week because our exports of gasoline rose by 72,000 barrels per day to 842,000 barrels per day, while our imports of gasoline fell by 16,000 barrels per day to 405,000 barrels per day, and because the amount of gasoline supplied to US markets increased by 117,000 barrels per day to 9,035,000 barrels per day…even after this week’s inventory decrease, our gasoline supplies were 0.6% higher than last February 22nd’s gasoline inventories of 254,941,000 barrels, and 3% above the five year average of our gasoline supplies for this time of the year…
With the decrease in our distillates production, our supplies of distillate fuels decreased for the 16th time in 22 weeks and for 31st time in the past 47 weeks, falling by 2,115,000 barrels to 138,472,000 barrels during the week ending February 21st, after our distillates supplies had decreased by 635,000 barrels over the prior week….our distillates supplies fell by more this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 391,000 barrels per day to 4,119,000 barrels per day, even as our exports of distillates fell by 137,000 barrels per day to 1,206,000 barrels per day while our imports of distillates rose by 50,000 barrels per day to 177,000 barrels per day….nonetheless, after this week’s decrease, our distillate supplies at the end of the week were little changed from the 138,683,000 barrels of distillates that we had stored on February 22nd, 2019, while they slipped to about 5% below the five year average of distillates stocks for this time of the year…
Finally, even with lower oil imports and higher oil exports, our commercial supplies of crude oil in storage rose for the nineteenth time in thirty-six weeks and for the thirty-first time in the past 52 weeks, increasing by 452,000 barrels, from 442,883,000 barrels on February 14th to 443,335,000 barrels on February 21st….but even after 5 straight increases, our crude oil inventories slipped to roughly 3% below the five-year average of crude oil supplies for this time of year, even while they remained 34.6% higher than the prior 5 year (2010 – 2014) average of crude oil stocks after the third week of February, 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 this past summer, after generally falling until then through most of the prior year and a half, our oil supplies as of February 21st were 0.6% below the 445,865,000 barrels of oil we had in commercial storage on February 22nd of 2019, while still 4.7% above the 423,498,000 barrels of oil that we had in storage on February 23rd of 2018, while at the same time remaining 14.8% below the 520,184,000 barrels of oil we had in commercial storage on February 24th of 2017, a week which followed a period when we had been adding 10 million barrels per week to storage…
This Week’s Rig Count
The US rig count was little changed for the 4th week in row over the week ending February 28th, after being down 18 of the prior 22 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 decreased by one rig to 790 rigs this past week, which was also down by 248 rigs from the 1038 rigs that were in use as of the March 1st 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 decreased by 1 rig to 678 oil rigs this week, which was also 165 fewer oil rigs than were running a year ago, and much lower 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 was unchanged at 110 natural gas rigs for the 3rd week in a row, but still down by 85 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, two rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, and one in Lake County, California… a year ago, there were no such “miscellaneous” rigs deployed..
Offshore drilling activity in the Gulf of Mexico was unchanged at 22 rigs this week, with 21 of those Gulf rigs drilling in Louisiana waters and one rig drilling offshore from Texas…that was the same number of rigs that were deployed in the Gulf a year ago, when 19 rigs were drilling offshore from Louisiana and three rigs were operating in Texas waters…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 offshore rig total in both cases..
The count of active horizontal drilling rigs was down by 6 to 706 horizontal rigs this week, which also 203 fewer horizontal rigs than the 911 horizontal rigs that were in use in the US on March 1st of last year, and also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….on the other hand, the vertical rig count was up by 4 rigs to 34 vertical rigs this week, but those were still down by 24 from the 60 vertical rigs that were operating during the same week of last year….at the same time, the directional rig count was up by one rigs to 46 directional rigs this week, but those were also down by 21 from the 67 directional rigs that were in use on March 1st of 2019…
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 28th, the second column shows the change in the number of working rigs between last week’s count (February 21st) and this week’s (February 28th) count, the third column shows last week’s February 21st 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 1st of March, 2019…
The 4 rig increase in Texas includes 2 rigs that were added in Texas Oil District 8, which corresponds to the core Permian Delaware, and another rig that started up in Texas Oil District 7B, while a rig was being pulled out of Texas Oil District 7C, or the southern Permian Midland at the same time…hence, the rig added in District 7B must have been targeting the far eastern Midland basin for the Permian basin to show a 2 rig increase for the week…elsewhere in Texas, rigs were pulled out of Oil Districts 1 and 3 to account for the 2 rig decrease in the Eagle Ford, while 2 rigs were added in Texas Oil District 6, one was added in Texas Oil District 2, and one was added offshore…it appears that the 2 rigs added in Texas Oil District 6 were natural gas rigs in the Haynesville shale, while a Haynesville gas rig was concurrently taken down in adjacent northern Louisiana….other Baker Hughes data shows the Haynesville shale with a one rig increase to 43 rigs this week, so it appears that the above table is wrong on that count…the natural gas rig count still balances because there was also a natural gas rig pulled out of a basin not tracked separately by Baker Hughes….meanwhile, since there was no change in the panhandle Texas Oil District 10, it seems likely that the oil rig pulled out of the Granite Wash had been operating in Oklahoma…other changes in Oklahoma would include the 2 rigs that were added in the Cana Woodford shale, and one rig that was pulled out of the Ardmore Woodford, and hence it seems likely that 3 rigs were also shut down in other Oklahoma basins not shown above…elsewhere, the Denver-Julesburg Niobrara rig addition could have been in either Colorado or in Wyoming, but Colorado seems more likely, since other basins in Wyoming have had more activity lately..
Utica Shale well activity as of Feb. 22:
- DRILLED: 157 (157 as of last week)
- DRILLING: 111 (109)
- PERMITTED: 481 (475)
- PRODUCING: 2,451 (2,451)
- TOTAL: 3,200 (3,192)
Eight horizontal permits were issued during the week that ended Feb. 22, and 11 rigs were operating in the Utica Shale.
Ohio oil production totals increase – Horizontal shale wells in the state produced 6.8 million barrels of oil and 685 billion cubic feet of natural gas during the fourth quarter of last year, the Ohio Department of Natural Resources announced Friday. Oil production grew 17 percent compared to the last quarter of 2018, while natural gas production rose 3 percent.ODNR reported production from 2,452 wells, most of them tapping the Utica Shale. Those wells averaged:
- • 2,774 barrels of oil
- • 279 million cubic feet of natural gas
- • 90 days of production
Horizontal wells also produced 26 million barrels of brine, a salty wastewater often found in underground oil and natural gas deposits, during the fourth quarter.
Plant plans reason for encouragement – Residents of our region received some positive news Wednesday when it was learned that a local company has plans to build a gas-to-liquids facility in Saline Township in northern Jefferson County. Hammondsville-based Orin Holdings and county officials see a big potential for the facility, which would be located on 500 acres of ground that has sat idle for more than 30 years. According to the plan that was released Wednesday, Orin would construct on the property two state-of-the-art plants that would convert natural gas into a product that would be shipped to other plants where it would be further refined into commercial-grade diesel fuel. The twin plants will likely provide a big boost to the region’s economy. According to Trustee Danny Householder, the project will create as many as 500 jobs and will provide a significant increase to the tax base of the township. . Orin officials said the land where the proposed facility would be built sits in a sweet spot – right in the heart of the Marcellus and Utica shale plays. It also is located close to Norfolk Southern’s rail line, which runs next to the Ohio River; is close to the river itself; and is close enough to the Columbiana County Port Authority’s inter-modal terminal in Wellsville that it will have easy access to barge transportation. Plus, its proximity to Shell’s Falcon Pipeline means the facility will have easy and economical access to natural gas – the plant’s raw material. Orin said the potential exists to build an underground storage facility for natural gas in a salt cavern below the property. Company officials explained that the facility will be one of the most modern, efficient and environmentally compliant alternative fuel plants in the world. The oil and gas industry has played an important role in our region’s economy for many years now, and it’s likely that role will expand. Construction is continuing on Shell’s ethane cracker in Monaca, and it’s expected the official announcement about a cracker in Dilles Bottom planned by PTT Global Chemical and Daelim Industrial Co. LLC will come soon. It’s not known how soon the Orin facility can get up and running. The permitting process is expected to take more than a year to complete before construction can begin.
Should county, state welcome giant petrochemical project? – The Columbus Dispatch – Plans for the Ohio River’s petrochemical buildout, including multibillion dollar “cracker” plastic plants, were laid between 2010 and 2017 when there was reason for them. “Fracking” opened two of the world’s largest natural gas deposits. The U.S. became the world’s leading oil and gas producer for the first time ever and global plastic production surged. “The world demand for plastic will triple by 2030,” gasmen quote a DuPont vice president. But since 2017, everything has changed. And so are those plans. Buckling after being assessed the largest-ever EPA fine, DuPont, the Ohio River-based Teflon plastic manufacturer, joined its competition in 2017. A staggering 32 oil and gas companies went bankrupt in 2019. National fracking leaders Eagle Ford and Halliburton ended 2019 bankrupt, losing $1.6 billion; Murray Energy, bankrupt; Parkersburg, West Virginia’s plastic cracker, scrapped. Because most of all, since the petrochemical buildout was planned the global “plastic crisis” hit. And it hit hard. In 2017 China stopped importing the world’s supply of used, “recycled,” plastic. Cities from Pittsburgh to San Diego have canceled their plastic recycling programs – or just started stockpiling it – because in practice plastic is no longer recyclable. Plastic is trash. Ninety percent of all plastic has not been recycled. It makes up the Great Pacific Garbage Patch, a floating plastic “island” 14 times the size of Ohio, and is already on track to outweigh fish in the sea by 2050. Now with no scale plastic recycling system, expect all new plastic to end up polluting either our water (as floating trash), our air (as toxic burnt plastic) or our land (as nonbiodegradable fill). But it’s not all bad. The world is responding boldly to the plastic crisis by banning plastic, especially single-use plastic, i.e. throwaway bags, bottles and packaging. Compared with 2016, the global market for plastic has lost close to 3.5 billion people, nearly cut in half, most just this past year. And companies such as Kroger, Giant Eagle and even McDonald’s are following suit. This industry promises jobs. But jobs for companies that return to us pennies in wages on every dollar in profit they take from us, that openly pass their enormous environmental and community health bills to us, that are propped up by Big Government and that will only keep going bankrupt, are not worth it. We lost nearly 10 times more jobs than this cracker plant promises when three of our local hospitals closed last year; combined they only needed about 100th the investment.Let’s build up our health, not destroy it.
Gulfport Energy writes down value of oil, gas assets in 2019, report shows An expensive write-down contributed to big losses on the year for Gulfport Energy. After markets closed Thursday, the company issued a report stating it lost about $2.02 billion, or $12.49 per share, on total revenues of about $1.35 billion for the entire year. Gulfport wrote down the value of its oil and natural gas assets by $2 billion in 2019. As part of that, the company took an impairment charge on the value of its oil and gas assets of about $2.04 billion. The Oklahoma City-based company, which owns and operates wells in Ohio’s Utica Shale and Oklahoma’s SCOOP play of the Anadarko Basin, also announced it’s cutting the amount of money it expects to spend to drill and complete wells in 2020 to between $285 million and $310 million. In 2018, the company spent $602.5 million. In 2018, the company had earned a profit of about $430.6 million, or $2.46 a share, on total revenues of about $1.36 billion. David M. Wood, Gulfport’s CEO, said the company halved its capital expenditures budget for 2020 because of continued low pricing for natural gas – mostly what the company produces. “At current strip pricing, our 2020 drilling program will be funded within cash flow, ensuring a very strong liquidity position … with a relatively low amount of revolver draw,” Wood said. “The large decline in spending during 2020 also allows us to retain our high value inventory for a better gas price environment in the future.” In the Utica Shale in 2019, Gulfport drilled 16 wells and turned 47 wells to sales. Average daily production from its operations there averaged about 1.01 billion cubic feet (equivalent, officials said). This year, Gulfport intends to run one rig in the play with plans for it to drill 16 wells. In the SCOOP play of the Anadarko Basin, the company drilled 10 wells and brought 14 wells to sales.
Lawmakers Pass Bills To Lure Petrochemical Industry To W.Va. – The West Virginia House of Delegates on Tuesday passed two bills that would provide tax cuts to the natural gas industry in an effort to boost petrochemical and plastics manufacturing. House Bill 4421 the “Natural Gas Liquids Economic Development Act” would provide tax credits to companies that transport or store natural gas liquids. These by-products of natural gas drilling include propane and ethane, which are feedstocks for chemical and plastics production. Del. Bill Anderson, a R-Wood County, speaking on HB 4421, said the measure would promote natural gas storage and pipelines in an effort to boost development of downstream manufacturing in the state. “We must develop manufacturing of these liquids in this state,” he said. “Our alternative is simply this: Are we going to put them in a pipeline and send them to the Gulf Coast and create jobs there? Or are we going to encourage development in this state, a natural gas storage hub?” State officials, including Gov. Jim Justice, have pushed for the development of a petrochemical industry in West Virginia. In late January, Justice told natural gas producers, currently facing record low prices, he would do “anything” to help the state’s struggling oil and natural gas industry. Last fall, Justice signed an executive order creating a task force aimed at bringing petrochemical manufacturers to the state. Some lawmakers worried the proposed tax cuts could shoot a hole in the state’s already precarious budget. The Legislature at the time was debating other measures that could radically change the state’s tax code. “These things cost $200, $300, $400 million a year and we’re giving away something for $1 million,” said Del. Isaac Sponaugle, D-Pendleton County. “That’s not going to drive the needle one way or another whether we’re going to get those investments, but that $1 million is gone and you’re wasting it.” The fiscal note attached to HB 4421 finds the state could lose up to $500,000 in revenue in fiscal year 2022, but if and as the storage and transportation sectors grow, “local property taxes on associated machinery and inventory will likely increase significantly with revenue gains to local governments along with the potential loss in State General revenue associated with the tax credits for local taxes paid.” HB 4421 passed 85 in favor, 14 against and 1 member not voting. The lower chamber Tuesday also passed House Bill 4019 the “Downstream Natural Gas Manufacturing Investment Tax Credit Act of 2020.” It seeks to encourage investment in downstream natural gas manufacturing, such as the building of ethane cracker plants, by giving businesses up to an 80 percent tax credit on personal or corporate net income taxes for new investment that creates jobs.
EQT, EQM sign gas gathering pact – Independent producer EQT Corp. and EQM Midstream Partners LP (EQM) said Wednesday they’ve executed a 15-year gas gathering agreement covering Pennsylvania and West Virginia both sides call a win-win deal. The minimum volume commitment (MVC) between EQT and EQM rises to 3.0 billion cubic feet per day (Bcf/d) from 2 Bcf/d, and incremental MVC increases begin with the completion of the Mountain Valley Pipeline (MVP), Kallanish Energy reports. The MVP project is a natural gas line system that spans roughly 303 miles from northwestern West Virginia to southern Virginia, and will flow up to 2 billion cubic feet per day (Bcf/d) Marcellus and Utica Shale play gas to the south. The MVP will be constructed and owned by Mountain Valley Pipeline, LLC, a joint venture of EQM, NextEra Capital Holdings, Con Edison Transmission, WGL Midstream, and RGC Midstream LLC. EQM will operate the pipeline. The deal consolidates nearly all of EQT’s existing Pennsylvania and West Virginia gathering contracts with EQM into one new consolidated agreement, the partners said. The new deal will provide EQT with gathering and compression fee relief, effective upon the MVP’s in-service date, currently expected to be Jan. 1, 2021. Gathering fee relief is estimated to impact cash flow by roughly $125 million, $140 million, and $35 million, in the three years following MVP’s in-service, respectively. Also part of the new pact, EQT dedicated over 100,000 additional acres in West Virginia to EQM and extended its contractual obligations with EQM to 2035. EQM has also agreed to defer approximately $250 million in current credit assurance posting requirements. Present value, using 10% discount rate (PV10), of MVC revenue is roughly $2.1 billion higher under the new 15-year gathering pact than under prior MVCs with EQT.
Pa. approves $200,000 fine and orders ‘remaining life’ study of leaky 89-year-old Sunoco pipeline – State regulators on Thursday finalized a settlement with Sunoco Pipeline to atone for a 2017 leak from the aging Mariner East 1 pipeline that includes a $200,000 fine and a promise to conduct a “remaining life” study of the nearly 90-year-old pipeline. The Pennsylvania Public Utility Commission unanimously adopted a recommended decision by Administrative Law Judge Elizabeth H. Barnes, which requires the study be completed six months after an independent expert is selected to conduct it. A redacted summary of the study will be released to the public. The PUC cited Sunoco in 2018 for the April 2017 leak, during which 840 gallons, or 20 barrels, of highly volatile natural gas liquids escaped from a small hole that formed in the eight-inch diameter steel pipeline in New Morgan, Berks County. The PUC cited Sunoco for having inadequate cathodic protection of the pipeline, which allowed it to corrode and to leak ethane and propane. The material bubbled to the surface and evaporated without causing injury or explosion, but the episode heightened concerns about what might happen if the 300-mile pipeline experienced a larger failure.
DOJ is building a criminal case around Energy Transfer’s Revolution pipeline explosion — The U.S. Department of Justice has launched a criminal investigation into the 2018 natural gas pipeline explosion in Beaver County, adding to a growing list of state and federal probes into Energy Transfer’s pipeline projects in Pennsylvania. The investigation has been going on since at least November, according to a disclosure in the Texas-based pipeline company’s financial filings. Energy Transfer said the U.S. attorney for the Western District of Pennsylvania “issued a federal grand jury subpoena for documents relevant to the incident,” which is also being examined by the Pennsylvania attorney general’s office. “The scope of these investigations is not further known at this time,” Energy Transfer wrote in its annual report earlier this month. Energy Transfer disclosed Attorney General Josh Shapiro’s investigation into the Revolution pipeline’s failure in a financial filing in August 2019. The Revolution pipeline – a 40-mile link between shale gas wells in Beaver and Butler counties and a processing plant in Washington County – slid down a steep hill one rainy September morning in 2018, bursting into flames, burning down one family’s home and prompting an early morning evacuation of the Center Township neighborhood. The landslide and resulting blast occurred just days after Energy Transfer began moving gas through the pipeline. Events and decisions surrounding the routing, design and construction of the Revolution pipeline already have been the subject of other investigations, such as by the Pennsylvania Department of Environmental Protection. DEP stopped reviewing any new permits for Energy Transfer across the state for nearly a year and last month announced a settlement with a historic $30.6 million fine for the Revolution explosion. DEP focused on Energy Transfer’s record of landslides and slope destabilization during the engineering and construction of the pipeline, finding that the company knew it was building in erosion-prone terrain but did not take enough precautions to avoid the problem or bolster the land. Meanwhile, the Pennsylvania Public Utility Commission’s investigation into the Revolution pipeline is still ongoing, spokesman Nils Hagen-Frederiksen said. The PUC’s jurisdiction over the line, categorized as a gathering facility, revolves around enforcing federal pipeline safety regulations. It’s not known what documents the federal Justice Department is seeking or what criminal acts are being investigated. One aspect that could fall under federal law and hasn’t been addressed publicly by Pennsylvania regulators is the possibility that a bad weld might have contributed to the blast. This suspicion was highlighted in a lengthy document filed by the creditors of EdgeMarc Energy Corp. after they’d reviewed 24,000 documents and taken five depositions of Energy Transfer witnesses.
Chevron Launching Layoffs in April – Chevron Corp. will be launching a round of layoffs beginning April 6 as it sells its Appalachian natural gas operations, according to a WARN notice the company sent to the Pennsylvania Department of Labor & Industry earlier this month. According to the notice the potential number of people affected totals 288 employees at its regional headquarters at 700 Cherrington Parkway in Moon Township, PA.The notice indicated that an unspecified number of layoffs would occur April 6 and added that some employees will be offered temporary assignments, with extended layoff dates potentially through the end of this year, according to the Pittsburgh Business Times.”We are taking active steps to reduce job loss and will facilitate the placement of as many impacted employees as we can with other Chevron business units,” the letter stated, according to the Pittsburgh Business Times. Chevron also indicated that any employees who are laid off would receive severance and outplacement services.Rigzone reached out to Chevron directly for comment on the matter and received the following statement via email on Feb. 24: “The WARN Act is a regulatory requirement intended to give employees advance notice before potential layoffs at a plant or facility. It’s too soon to know how many employees will be affected on or after the April 6 date indicated in the WARN letter.”At the end of 2019 the company announced a $20 billion CAPEX budget for 2020 and that it was considering strategic alternatives, including divestment, for “gas-related opportunities including Appalachia shale, Kitimat LNG, and other international projects”. During 4Q 2019 the company took a hefty write-down due to ongoing depressed natural gas prices.
Report: Pa. natural gas production grew in 2019 but at lower rate –Total natural gas production in Pennsylvania grew by 7.6% in the fourth quarter of 2019 compared to the same period in 2018 – the lowest growth rate in more than two years, a report by the Pennsylvania Independent Fiscal Office said.Pennsylvania remains the second-highest natural gas producing state after Texas, with 6.9 trillion cubic feet of natural gas produced in 2019, the Natural Gas Production Report said.“Through November 2019, nationwide (natural gas) production grew by 10.2% compared to the prior year, largely driven by significant gains in Texas and Pennsylvania,” the report said.Production volume for horizontal wells in the fourth quarter of 2019 reached 1,775 billion cubic feet, the report said. All of the production growth for the quarter was from unconventional wells – i.e., wells requiring horizontal drilling into deep formations and fracturing with fluids.Horizontal well production in Pennsylvania has grown for 14 consecutive quarters, but average production-per-well growth moderated in 2019, the report said.There were 9,319 producing horizontal wells in the state in the fourth quarter of 2019 – an 8.3% increase over the previous year. Since the fourth quarter of 2017, total producing wells increased by 18.2%, the report said.Southwestern Pennsylvania has four of the top 10 natural gas producing counties in the state – Washington (No. 2), Greene (No. 3), Butler (No. 8) and Allegheny (No. 10), the report said.Allegheny County, although representing only 2.1% of the production volume in the state, had the highest rate of production growth – 34.4% – from 2018 to 2019, the report said. The IFO report is based on data from the state Department of Environmental Protection.
Voters divided on fracking – – Voters in Pennsylvania – the second-largest natural-gas producing state in the country – are closely divided over whether they support a ban on fracking, a process used in natural gas drilling that spurred a surge in production here over the last decade. That’s according to a new statewide Morning Call/Muhlenberg College poll, which found 42% of Pennsylvanians oppose a ban on fracking and 38% support a moratorium, with 20% undecided. The finding comes as Democratic presidential candidates Bernie Sanders and Elizabeth Warren are calling for a halt to fracking, arguing its effects on the environment are greater than the economic benefits. The new poll showed Pennsylvania voters are split on whether fracking has more positive than negative: 38% said they strongly or somewhat agree that it has had more positive effects, 37% strongly or somewhat disagreed, and 24% were not sure. On the economic effects, half of respondents said the industry has been “a major boost” to Pennsylvania’s economy. Another 26% disagreed, and 25% weren’t sure. Asked whether natural gas drilling poses a major health risk to state residents, 44% agreed and 36% disagreed, with 20% who were not sure. With Pennsylvania a critical battleground state in this year’s presidential election, some Democrats have concerns that having a nominee at the top of the ticket who supports a fracking ban could be politically risky in a state where gas drilling has boomed. “This could be something that poses some challenges to Sen. Sanders,”
DEP fines landfill near Pittsburgh for problems tied to fracking waste – The Pennsylvania Department of Envirommental Protection has fined a Westmoreland County landfill that had been passing pollution from oil and gas drilling waste into a local sewage treatment plant. The fine is part of a consent agreement with Westmoreland Sanitary Landfill to find a solution for the plant’s leachate, the liquid waste formed when rain and moisture percolates through the landfill. As part of the settlement, the landfill will pay a $24,000 fine and reduce the amount of waste it generates by closing up part of the landfill’s open area and installing an evaporator and other treatment equipment for the liquid waste. Ro Rozier, a spokeswoman for the landfill, said the company was “committed to investing substantial amounts of capital to purchase and install technology and equipment capable of treating and evaporating the leachate generated from the landfill on site. We are confident that our plan for onsite treatment and evaporation will resolve the landfill’s recent leachate disposal issues.”In May, a Fayette County judge ordered the landfill to stop sending its liquid waste to the Belle Vernon Municipal Authority’s sewage treatment plant, which had reported problems meeting water quality standards for its treated sewage. The sewage plant sought the injunction because the leachate it was receiving from the landfill was high in salts and radioactive materials found in drilling waste, which the landfill had been taking for several years. The landfill’s own waste reports showed the leachate it was sending the treatment plant had an “oil like” or “petroleum sheen.” The agency says it wants the landfill to find a local disposal site for the waste to cut down on truck traffic from the landfill. For now, the waste will be sent to sewage plants in Ohio and Pennsylvania.
Natural gas synthesis plant proposed – An effort has been underway for 16 months to explore the development of a natural gas synthesis plant in western Clinton County by Frontier Natural Resources and a new company formed for the purpose called, ‘KeyState Agri’, both of Bellefonte.Perry Babb, spokesman for the KeyState stopped at The Express on Thursday to informally introduce the proposed $500,000,000 project that could potentially generate 600 to 800 jobs during construction and 150 to 200 permanent jobs.A natural gas synthesis plant uses the methane in natural gas as a feedstock to produce a range of products used in agriculture, industry, medicines and transportation. A synthesis plant is not a ‘cracker plant’. The majority of CO2 generated in gas synthesis processes is captured and used in the making of other products. More than a dozen similar plants have been built and safely operated across the US in the last 30 years.“The economic development impact would be profound and generational,” Babb said. “Commercial and other activity generated would go beyond Clinton County, impacting areas of Cameron, Centre and Clearfield, local rail siding and road upgrades, housing for the construction workforce proposed to be converted to permanent affordable housing, coordination of workforce development programs with the surrounding county high schools, vo-tech schools as well as Lock Haven, Penn College and Penn State University, substantial research activities with the surrounding universities and major wildlife habitat enhancement in reclaimed mining and other areas funded,” he continued.
Op-Ed: PennEast Has a Pipeline to Sell You -You’ve heard the saying, “If you believe that, I’ve got a bridge to sell you.” The pipeline that PennEast has tried to sell us for the past five years is a lot like that bridge. Now, adding insult to injury, they want to sell us half a bridge. Do they think we’re suckers? Faced with a court decision barring PennEast from seizing state-preserved land in New Jersey, and iron-clad evidence from gas experts and the NJ Ratepayer Advocate that the pipeline isn’t needed, PennEast is desperately trying to build something – anything – to gain the excessive profits the federal government guarantees for such projects, needed or not. PennEast recently asked the Federal Energy Regulatory Commission (FERC) for approval to build the pipeline in two phases, constructing in Pennsylvania by 2021, then crossing the Delaware River into New Jersey by 2023. Maybe they think a half-loaf is better than none, but leaders in both states should reject this faulty premise.PennEast says it has contracts for only half of the gas that would be delivered by phase one of the project and has provided no information about who the customers would be. That doesn’t even meet FERC’s weak test of public need. FERC should put the brakes on this scheme and treat PennEast’s new proposal as an entirely new project requiring intense scrutiny. PennEast also claims the Delaware River Basin Commission (DRBC) no longer has authority over phase one of the project. That’s an end run around the agency charged with protecting water quality in the area, supplying drinking water to over seven million people. The DRBC shouldn’t let them get away with it. This all smacks of desperation for PennEast. The state Department of Environmental Protection rejected the company’s application for the permits needed to build the pipeline. A federal court ruled that PennEast can’t use eminent domain to take land owned by the state. And now PennEast says it will appeal that decision to the U.S. Supreme Court in hopes of a ruling that could pave the way for construction of a pipeline that no one needs but PennEast.
Energy giant drops proposed Constitution Pipeline – Williams Companies, the Oklahoma energy giant, confirmed Friday that it has shelved the Constitution Pipeline, a proposed interstate natural gas pipeline that triggered a prolonged battle between environmental activists and pro-development advocates.“Williams – with support from its partners, Duke, Cabot and AltaGas – has halted investment in the proposed Constitution project,” the company said in response to questions from CNHI.“While Constitution did receive positive outcomes in recent court proceedings and permit applications, the underlying risk adjusted return for this greenfield pipeline project has diminished in such a way that further development is no longer supported,” Williams added.Anne Marie Garti, an environmental lawyer who helped form the opposition group Stop the Pipeline, said the group “fought this epic 8-year battle with courage, conviction and intelligence, adding: “Perseverance pays off.”Williams disclosed this week in a financial report that the investors in the Constitution Pipeline took a $345 million “impairment,” suggesting that the investment in the mammoth 124-mile pipeline was being written off.“Impairment” is an accounting term meaning a reduction in the recoverable amount of a fixed asset.Despite being approved by the Federal Energy Regulatory Commission, the project skidded into trouble when New York regulators refused to issue water-crossing permits, citing environmental concerns.Constitution’s footprint would have crossed hundreds of real estate parcels in Chenango, Delaware and Schoharie counties. Garti said Stop the Pipeline’s next mission is to ensure easements acquired by Constitution are removed from landowners’ deeds.
Scrapped pipe project for New York a dire sign for other Northeast gas proposals – The cancellation of a proposed natural gas pipeline into New York may be a sign of challenges ahead for other projects, both at the grassroots level and in Washington, D.C., according to energy analysts. Anti-fossil-fuel activists have grown more successful in recent years, but Williams Cos. Inc.’s move to scrap the Constitution Pipeline Co. LLC project earned a rare designation in the history of energy infrastructure, according to Katie Bays, co-founder of energy consultancy Sandhill Strategy. “It does take a lot to kill a pipeline project,” Bays said. “There’s really only a handful that have been killed by public policy. I think that was certainly a milestone.” Williams announced it would shelve the project after years of opposition from New York and environmentalists. The proposed line from Pennsylvania’s shale gas fields became a symbol of the movement to keep fossil fuels in the ground and a trend of Northeast states with ambitious clean energy goals denying key water permits to pipeline projects. SNL Image After Constitution won a favorable ruling at the Federal Energy Regulatory Commission, Bays suspected Williams would have to choose between building it and another pipeline, the Northeast Supply Enhancement project. Constitution became so mired in acrimonious politics that continuing to do battle with New York over the project likely would have closed the door to other plans, Bays said. New York has also opposed the Northeast Supply Enhancement proposal, and the line continues to face headwinds, analysts said. Gov. Andrew Cuomo’s administration has refused to grant a water permit to that project as well, as the state uses all policy options to achieve its clean energy goals.
US NRC checks review of gas pipeline at New York nuclear plant after report – The chairman of the US Nuclear Regulatory Commission has ordered a review of the agency’s safety analysis of a natural gas pipeline near the Indian Point nuclear plant in New York after NRC’s inspector general said in a report made public Wednesday the staff review was flawed and might need to be redone. The NRC IG’s report also said NRC missed an opportunity to correct those flaws when it rejected a subsequent petition from consultants for the town of Cortlandt, New York seeking to reverse the agency’s conclusions.The NRC’s 2014 review of the 42-inch-diameter Algonquin Incremental Market pipeline, designed to ease gas constraints in New England, was the basis for US Federal Energy Regulatory Commission approval of that project in 2015. The pipeline, which has a capacity of 342 MMcf/d, went into service in January 2017. NRC Chairman Kristine Svinicki directed agency staff Monday to promptly examine whether any immediate action should be taken in response to the report, and determine within 45 days whether the original analysis or the response to the petition should be changed. She also told staff to study whether any modifications to agency practice or procedures are needed.
Hotly Contested Proposal to Build Gas Pipeline Into NYC and LI Returns – A hotly contested proposal to build a pipeline to take natural gas to customers in New York City and Long Island is back before New Jersey regulators.The Northeast Supply Enhancement Project would add to the existing Transco pipeline and would carry enough gas to heat 2.3 million homes. It would take gas from Pennsylvania through New Jersey and its Raritan Bay to New York.Oklahoma-based Williams Companies plans to spend $926 million on the project, saying that it is needed to ensure adequate heating and energy supplies to New York City and Long Island, and that it can be built safely with minimal environmental disruption. But opponents say it is unneeded and will encourage the burning of fossil fuels at a time when climate change is causing serious harm.Williams filed its latest application with the New Jersey Department of Environmental Protection on Jan, 21, a filing made public Thursday by the state. It is at least the fourth time the Tulsa company has applied for permission to build the project, which includes more than 23 miles of pipeline through Raritan Bay into New York, and a compressor station to be built in Franklin Township in Somerset County, New Jersey.The company withdrew its application twice before, and New Jersey regulators denied it once. “Nasty NESE is back for an unbelievable fourth time, and the environmental impacts of this unnecessary, climate-changing project will still be severe and devastating,” said Cindy Zipf, Clean Ocean Action’s executive director. “They’re trying to wear us down. We will not give up. We have too much to lose: our ocean, bay, air, and coastal economy and communities.”
After clash with Cuomo, National Grid warns of widening NY gas shortage – Downstate New York’s growing demand for natural gas will begin outstripping supply next winter, creating a gap that will continue to grow for at least the next decade absent a long-term solution, National Grid USA forecast in a new report. Possible solutions include new pipelines and other large-scale projects, smaller-scale infrastructure or energy efficiency programs, and other workarounds, the gas and electric power utility operator said. Without some combination of those fixes, undersupply reaching 265,000 Dth/d by the onset of winter 2032-2033 in a low-demand scenario, or 415,000 Dth/d in the winter of 2034-2035 in a high-demand scenario. “National Grid’s current capacity of 2,888 MDth/day is challenged to meet existing peak demand during cold winter days, leaving our network with little room for error,” the company said. “And looking ahead, our existing and planned expansion capacity to supply natural gas is not sufficient to meet forecast demand.” National Grid presented its outlook in a 116-page report, part of a $36 million settlement with its New York state regulator, the Public Service Commission, over the utility’s six-month moratorium on new downstate gas hookups. The standoff reached a climax in November 2019, when New York Gov. Andrew Cuomo gave National Grid two weeks to present a remedy or else lose its license to deliver gas to 1.9 million customers of subsidiaries KeySpan Gas East Corp. and Brooklyn Union Gas Co. across Brooklyn, Queens, Staten Island and Long Island.
National Grid offers options to meet projected gas supply constraints –Options to meet long-term natural gas supply constraints for the downstate region include a deep-water liquefied natural gas port for the waters off Long Island, two barges that could deliver liquefied gas during peak demand times and a pipeline that National Grid has long proposed, according to a company report.The report was released Monday in response to a state settlement last year over its controversial moratorium on new gas hookups, In it, National Grid laid out the pros and cons of seven different large-scale and so-called distributed solutions to its gas supply constraints, along with green-energy options to help further curtail use.Growth in natural gas usage across the downstate region is expected to increase in coming years, the company said, but at a slower rate than the historic annual jump of 2.4%. The company cited growth in electrification and the anticipated jump in electric heat pumps, along with efficiency measures, efficient appliances and demand-reducing programs, in projecting that demand could slow to 0.8% to 1.1% per year through 2035. But National Grid said increased demand continues to strain the system. To handle short-term supply worries, National Grid had 42 trucks last winter and 108 this winter at the ready to deliver compressed national gas into the system, when needed, on peak demand days. Earlier this year the company had said warming weather meant the company didn’t need to deploy those planned short-term measures this year. .”Among three large-scale infrastructure options to meet the increased demand is an offshore LNG deep-water port for the waters off New York that would take six to eight years to complete, the company said. “There is a potential location in Long Island Sound that would enable delivery of up to 400 million dekatherms per day to Commack, NY, or Hunts Point, NY,” the report says. “An alternative location exists off the South Shore in the Atlantic Ocean” with an underwater connection to an existing subsea pipeline.
NEW YORK: Utility warns of gas shortages in Cuomo pipeline fight — Wednesday, February 26, 2020 — Fresh off a high-profile battle with New York’s governor over natural gas supplies, National Grid PLC is warning once again it might have to refuse gas customers if the state doesn’t allow construction of new pipelines.
How New York City plans to end natural gas, oil use in buildings – New York City’s path to limiting natural gas in buildings could look very different than the course that California towns and cities have charted – and, as a result, could go farther than other measures already in the works. Mayor Bill de Blasio recently announced his administration will aim to end the use of natural gas and fuel oil in buildings by 2040, following a wave of gas bans and building electrification codes in California, the Boston area and Seattle. The announcement on Feb. 6 signaled that the nation’s most populous city could soon set about electrifying a portion of its more than 1 million buildings. “One of the reasons why the mayor is so strongly stating this kind of goal in the State of the City is that we have to take very comprehensive action,” Mark Chambers, director of the mayor’s Office of Sustainability, said. “And so I think that we are very committed to being more aggressive, more thoughtful and intentional … and moving forward as quickly as possible because the urgency of the climate crisis demands it.” City officials do not envision a swift prohibition on gas hookups in new buildings as Berkeley, Calif., pioneered, and instead are considering building on previous legislation and existing city programs in ways that could create a new template for other cities. The transition would likely challenge Consolidated Edison Inc. and National Grid USA to accelerate plans to evolve their local gas distribution companies’ New York operations. The de Blasio plan is short on details for now as the administration embarks on the earliest stages of shaping the policy, Chambers told S&P Global Market Intelligence. To date, the administration has said its goal is to stop using gas and other fossil fuels in “large building systems” by 2040. It also said it would start with government buildings and work with City Council to “ensure new permits for building systems are aligned with our goal of carbon neutrality by 2050.” That language would seem to indicate the city is at least contemplating the California model: deny building permits to new buildings or renovations that include gas hookups, or else use the permitting process to incentivize all-electric systems.
The Perfect Storm Sends Natural Gas Crashing – If you’re waiting for natural gas prices to recover, you might be in for a considerable wait, as inventories are expected to hover well above their five year average for the remainder of the year, the EIA has forecast, painting a rather sour picture for the industry that has seen investments stifled due to the lower prices. In fact, inventories later this year will reach levels never seen before if forecasts prove accurate. According to the Energy Information Administration Short-Term Energy Outlook (STEO), working natural gas in storage in the Lower 48 will end the current heating season – which ends on March 31 – at 1,935 billion cubic feet. This is 12% above the previous five-year average. Now, we’re about to head into what the industry refers to as “the refill season”. Normally, the end of the heating season is when inventories are at their lowest. Now, we’re heading into this stockpiling season with inventories that are high. So we will be amassing even more nat gas in inventory as heating demand falls off. The EIA estimates that we will end the refill season, which runs until the end of October, with 4,029 billion cubic feet. This would be the largest monthly level of nat gas we’ve ever had in storage. At the end of January, inventories had already reached 2.6 trillion cubic feet. The COVID-19 outbreak – likely soon to be pandemic – might be the obvious target on which to lay blame for the increasing inventories. After all, it is responsible for demand in crude oil. But that is only a piece of the puzzle, with weather, weather, weather topping the list of critical factors that are affecting natural gas inventories. January 2020 was the fifth warmest January on record – that’s out of over 125 years of data. January 2020 saw average temperatures of 35.5 degrees F across the United States. This is 5.4 degrees more than the 20th Century average, according to the US Department of Commerce’s National Oceanic and Atmospheric Administration. The problem? It’s just been so warm that the need for heating has been reduced, depressing demand. And while production has not fallen with demand, inventories have bloomed. Add to that unfavorable price scenario the fact that COVID-19 is spooking the market and further denting demand, and you have a perfect storm for lower nat gas prices.
US natural gas futures fall to four years low – US natural gas futures plunged over 4% to a near four years low on Thursday on a smaller-than-expected weekly storage draw, forecasts for milder weather over the next two weeks and a drop in oil futures to their lowest in over a year. “A trend to milder weather and reduced storage withdrawals going into March are exacerbating bearishness and price impacts,” Daniel Myers, market analyst at Gelber & Associates in Houston, said in a report, noting last week’s storage withdrawal “was a bit of a letdown as it likely contained the last relatively strong cold shot of the winter season.” The US Energy Information Administration (EIA) said utilities pulled 143 billion cubic feet (bcf) of gas from storage during the week ended February 21. That is much less than the 158-bcf decline analysts forecast in a Reuters poll and compares with a decline of 167 bcf during the same week last year and a five-year (2015-19) average reduction of 122 bcf for the period. The decrease for the week ended February 21 cut stockpiles to 2.200 trillion cubic feet (tcf), 8.9% above the five-year average of 2.021 tcf for this time of year. On its first day as the front-month, gas futures for the most active contract for April delivery on the New York Mercantile Exchange fell 8.5 cents, or 4.6%, to settle at $1.752 per million British thermal units (mmBtu), their lowest close since March 2016. US crude futures dropped over 3% to their lowest since January 2019 as a rise in new coronavirus cases outside China fueled fears of a pandemic that could slow the global economy and dent oil demand. Since hitting an eight-month high of $2.905 per mmBtu in early November, gas futures have collapsed 40% as record production and mild winter weather enabled utilities to leave more gas in storage, making fuel shortages and price spikes unlikely. Meteorologists projected weather in the Lower 48 US states will fluctuate between warmer and cooler than normal over the next two weeks, with the most cold weather expected between February 27-29 and March 6-10. That forecast was milder than Wednesday’s outlook. With the weather warming with the coming of spring, data provider Refinitiv projected average demand in the Lower 48, including exports, would ease from 117.7 billion cubic feet per day (bcfd) this week to 114.0 bcfd next week. That forecast for next week is lower than Refinitiv’s 114.8-bcfd projection on Wednesday. The amount of gas flowing to US liquefied natural gas (LNG) export plants edged up to 8.9 bcfd on Wednesday from 8.8 bcfd on Tuesday, according to Refinitiv. That compares with an average of 8.5 bcfd last week and an all-time daily high of 9.5 bcfd on January 31.
Covid-19 Fears Combine with Warmer Weather Forecasts to Send Natural Gas Futures Below $1.70 –After being driven sharply lower by an increasingly mild weather forecast, natural gas futures sustained even more damage on Friday as global fears of the coronavirus continued to hammer stocks and energy commodities. The April Nymex gas futures contract plunged to an intraday low of $1.642/MMBtu before going on to settle at $1.684, down 6.8 cents from Thursday’s close. May also fell 6.8 cents to land at $1.732. Spot gas, which traded Friday for delivery on Sunday and Monday, also moved lower as any remnants of the blustery conditions that hit the United States in the final days of February were set to dissipate. NGI’s Spot Gas National Avg. dropped 10.5 cents to $1.525. The latest weather data, already fairly warm, trended further milder overnight Thursday as the American model lost more than 10 heating degree days (HDD) and the already warmer European model lost three to four more HDD, according to NatGasWeather. The midday Global Forecast System continued to trim demand from its outlook, losing another four HDD, the firm said. However, while the warmer weather trends undoubtedly aided Friday’s selling, the move lower also was likely influenced by major moves in commodity and equity markets because of the coronavirus fears, according to NatGasWeather. Stocks continued to plunge on Friday, and energy commodities went along for the ride. West Texas Intermediate front month futures dropped below $44/bbl early Friday before recovering a bit, while Brent crude broke below $50. The global markets were poised to extend the worst losing streak since the 2008 financial crisis, with the virus, officially dubbed Covid-19, forecast to pound productivity levels this year. “Our current assessment forecasts that Covid-19 could result in global E&P investments falling by around $30 billion in 2020 – a significant hit to the industry,“ said Rystad Energy’s Audun Martinsen, head of oilfield service research. Some of the investments are likely to come back in 2021, he said, but the situation is expected to worsen in March, slamming the global services industry well beyond Asia.
Columbia Gas to plead guilty in Merrimack disaster, pay $53 million fine; parent company must leave Mass. – The Boston Globe – The utility company responsible for the 2018 gas pipeline disaster in the Merrimack Valley has agreed to plead guilty to violating federal regulations and will sell off its operations in Massachusetts, helping to bring closure to a community that has remained rattled since fires and explosions forced residents to evacuate their homes.Columbia Gas of Massachusetts also agreed to pay a $53 million criminal fine, which federal prosecutors called the largest-ever for a pipeline safety violation. And its parent company, NiSource, would turn over to a federal victims’ fund any profits it reaps from the sale of the Massachusetts property, according to an agreement reached with prosecutors.Wednesday evening, Eversource Energy announced that it had agreed to purchase Columbia Gas’s natural gas assets in Massachusetts for $1.1 billion from NiSource.“This disaster was caused by a wholesale management failure at Columbia Gas,” US Attorney Andrew Lelling said Wednesday in announcing the penalties.He said no one person could be held responsible for the disaster, which killed one person and injured more than 20 others, but instead blamed it on a series of systemic failures.“The company as a whole had simply failed to do what it was supposed to do to ensure public safety,” Lelling said. Company representatives are slated to plead guilty in federal court in Boston on March 9. The agreement was welcomed by Merrimack Valley residents, who say they have lost trust in the area’s gas distributor, because of both the disaster and its botched response. Federal investigators have said the event, which set fire to more than 130 homes across Lawrence, Andover, and North Andover, would not have occurred had proper mechanisms been in place.
Miles-long oil slick from leaking equipment spotted on Midland-area rivers – Anyone walking along the Pine or Tittabawassee rivers around Midland may see and smell oil.Residents notified Midland city officials about the oil slick on Tuesday. Investigators found oil on about four to five miles of the Pine River.The Michigan Department of Energy, Great Lakes and Environment sent investigators to search for the source. They found a piece of heavy equipment leaking in a yard near St. Louis, according to Midland officials.The oil was entering the Pine River and flowing into the Tittabawassee River. Residents along the rivers may continue to notice oil as it continues flowing through the watershed.State environmental officials could not be reached for comment Tuesday evening about the amount of oil that spilled and whether any cleanup activities were taking place. Anyone with concerns or more information about the spill can call the Michigan Pollution Emergency Alerting System hotline at 1-800-292-4706.
Buttigieg tweets opposition to Line 5 ⋆ Michigan Advance – In a tweet Monday evening, former South Bend, Ind., Mayor Pete Buttigieg became the second Democratic presidential contender currently in the race to call for Enbridge’s controversial Line 5 oil pipeline to be decommissioned. “With such a high risk of an oil spill under the Great Lakes, Michigan can’t afford to keep the Line 5 pipeline in operation. In every community, we need new clean energy solutions to meet our climate crisis,” Buttigieg wrote. The tweet links to a Michigan Radio article from earlier this month about Enbridge’s replacement of a Line 5 segment under the St. Clair River. Washington Gov. Jay Inslee, who dropped out of the race in August, was the first presidential contender to publicly oppose Line 5. Inslee called the Line 5 tunnel project “a clear and present threat” in early July 2019. U.S. Sen. Bernie Sanders (I-Vt.) tweeted his opposition to Line 5 later that month, on the nine-year anniversary of Enbridge’s Line 6B oil spill in the Kalamazoo River. Attorney General Dana Nessel has been fighting the pipeline in court and praised Sanders earlier for his support. On Monday, she tweeted her thanks to Buttigieg, as well.* Nessel told the Advance again Monday that she is not planning to endorse in the Democratic primary, reiterating that she will campaign “as hard as I can” for the party’s nominee.* As the Advance has reported, the fierce Line 5 debate in Michigan (and ensuing legal battles) is just one example of oil pipelines becoming a more important national issue for the presidential cycle, as the debate on how to regulate fossil fuels in the era of climate change activism rages on.
Elizabeth Warren calls to shut down Enbridge Line 5 oil pipeline across Michigan, joining Sanders and Buttigieg – mlive.comDemocratic presidential hopeful Elizabeth Warren joined calls to shut down a controversial oil pipeline running across Michigan through the Straits of Mackinac.With less than two weeks before Michigan holds its March 10 primary, Warren said the pipeline is “a threat to millions who rely on the Great Lakes for clean water and a healthy economy” in a statement on Twitter. Warren voiced her opposition the day after Democratic opponent Pete Buttigieg made a similar statement, while Bernie Sanders called for the pipeline to be shut down last summer.Warren also touted her “Green New Deal” agenda to address climate change and create a new clean energy economy. The Massachusetts senator seeks to transition the United States to 100% clean energy within a decade while spurring new investments in renewable energy technology to create new jobs and alleviate fossil fuel dependence.Enbridge Energy’s Line 5 pipeline spans 645 miles between Superior, Wisconsin, and Sarnia, Ontario, carrying 23 million gallons of crude oil and natural gas liquids per day. Environmentalists are particularly concerned about the impact of an oil spill in a four-mile segment divided into dual pipes that extend across the Straits of Mackinac, linking Lake Huron and Lake Michigan.Enbridge reached a deal in 2018 with then-Republican Gov. Rick Snyder to decommission the twin underwater pipes and replace them with a single pipe housed in a tunnel built in bedrock beneath the straits. The idea remains controversial for environmentalists and some Democrats in the state Legislature, who would prefer no oil be transported across the straits at all. Republican lawmakers say there is no other alternative to satisfy the demand for energy, and closing the pipeline would cost thousands of jobs. Democratic Gov. Gretchen Whitmer has tried to block the Snyder-Enbridge deal, but the Michigan courts have backed Enbridge so far, the latest being a Michigan Court of Appeals ruling last month. Washington Gov. Jay Inslee called the pipeline and a proposed replacement tunnel a “clear and present threat” to the environment last year while he was running for president. Inslee since suspended his campaign.
Democratic candidates’ drilling ban would cost U.S. economy $7 trillion: oil group –(Reuters) – Banning hydraulic fracturing and halting new drilling on federal land would cost the U.S. economy $7 trillion in the next decade and kill millions of jobs, the U.S. oil industry’s main lobby group said on Thursday in a report targeting the climate plans of top Democratic presidential candidates. The report from the American Petroleum Institute underscores mounting concern in the U.S. drilling industry over the possibility a candidate in favor of rapidly ending the fossil fuel economy to fight global warming will win the Democratic Party’s nomination to face Republican President Donald Trump in the November election. U.S. Senator Bernie Sanders, a democratic socialist who is the current front-runner to win the nomination, and Senator Elizabeth Warren, who is also in the race, have vowed to ban hydraulic fracturing style-drilling nationwide, stop offering drilling leases on public land, and re-impose a moratorium on crude oil exports if elected. Other Democratic presidential candidates have offered more moderate plans here “The U.S. energy revolution … is dynamic and game-changing for the U.S. economy and energy security. Yet, banning fracking and halting federal natural gas and oil leasing has been proposed,” API said, without mentioning the presidential race. The group said its modeling showed that proposals to ban fracking and end public drilling leases would lead to a $7.1 trillion reduction in cumulative gross domestic product by 2030, and cut millions of jobs in places like Texas, California, Florida, Pennsylvania and Ohio. It added that it expected such proposals would increase U.S. reliance on foreign energy sources, and boost costs for homeowners and farmers.
East Chicago train derailment: Freight train carrying crude oil derails near Euclid Avenue – A freight train carrying crude oil derailed Wednesday in East Chicago, Indiana.The CSX train derailed about 5:20 p.m. in the 4600 block of Euclid Avenue, East Chicago and CSX police said. About 18 tankers containing crude oil came off the tracks, CSX police said. Hazmat crews were called to the scene. No injuries were reported, officials said. None of the tankers spilled any oil. Euclid Avenue is closed between 144th Street and Chicago Avenue, and police are asking drivers to avoid the area.The cause of the derailment remains under investigation.
EQT Corp sells half its stake in pipeline operator, strikes rate relief deal(Reuters) – EQT Corp said on Thursday it renegotiated its gas transportation rates and sold half its stake in pipeline company Equitrans Midstream Corp as the largest U.S. natural gas producer tries to cope with low fuel prices. U.S. natural gas prices are trading at their lowest in nearly two decades, hurting producers, many of whom have disclosed asset writedowns in the last few months. EQT recorded $1.6 billion non-cash impairment charge in the fourth quarter. Shares of EQT were down 3.3% at $4.79 amid a broader 4% drop in the S&P Energy index .SPNY. The Pittsburgh-based company has been looking to sell assets to pay down debt and said on Thursday that it had refined its hedging strategy and cut annual capital expenditure. The company expects 2020 capital expenditure between $1.15 billion and $1.25 billion, compared with a prior outlook of between $1.25 billion and $1.35 billion. It has hedged 87% for 2020 and 26% for 2021, assuming flat production. The company, which focuses on production from the Marcellus and Utica shale basins in Pennsylvania, Ohio and West Virginia, said it expects 2020 sales volumes in the range of 1,450-1,500 billion cubic feet equivalent (bcfe).
Oil spill under investigation in Baltimore Harbor – A fuel oil spill in Baltimore’s Inner Harbor covered the water into an eerie red sheen Saturday, prompting a big environmental emergency response.The Maryland Department of the Environment (MDE) estimates 50 gallons of red-dyed #2 heating fuel oil spilled into the outfall of the Jones Falls at President and Pratt Streets. The Baltimore Fire Department worked with MDE and a U.S. Coast Guard contractor to help contain the spill. On Saturday the Coast Guard contractor used a vacuum truck in an attempt to recover some of the fuel. MDE deployed a 100-foot-long piece of floating sorbent material to the spot where the Jones Falls emerges from underground, near Port Discovery and Power Plant Live. That should “help determine whether there is additional oil coming down the falls,” MDE spokesman Jay Apperson tells Bay Bulletin. MDE says it doesn’t know the source of the spill.
Coast Guard continues to search for source of oil in Baltimore’s Inner Harbor; spill might be growing – U.S. Coast Guard crews are continuing to search for the source of an oil spill in Baltimore’s Inner Harbor as photos from the scene Sunday appeared to show the spill possibly growing in size. Petty Officer 3rd Class Isaac Cross, a spokesman for the U.S. Coast Guard, said crews have still not located the source of an oil spill where the Jones Falls meets the Inner Harbor. The spill of red-dyed No. 2 fuel oil was first spotted Saturday morning near the Port Discovery Children’s Museum, where a U.S. Coast Guard contractor attempted to recover fuel at the site using a vacuum truck. Maryland environmental officials estimated about 50 gallons of oil were deposited into the harbor. Jay Apperson, spokesman for the Maryland Department of the Environment, said the department has “no indication this is an ongoing release.” “We do not know the source. We have checked some storm drain systems but the Jones Falls outfall services a massive area, making it difficult to trace back for a potential source without a report of a spill,” Apperson wrote in an email. He added that people should avoid contact with the water and that the vacuum truck is continuing to try to recover the fuel from the scene. As of Sunday afternoon, the spill had yet to be contained, said Cross, who added that crews are still trying to locate the source of the original spill and make sure there is not a second source adding to the problem. He said that while the maximum estimate for the spill would be 200 to 300 gallons of oil, he could not estimate how much had spilled into the water Sunday. Alex Volpitta, Baltimore Harbor Waterkeeper at Blue Water Baltimore, said images from the scene might show there are two separate oil spills. She said some of the spill “is really globular” while, in other areas, the substances “is almost like gasoline.”
With Inner Harbor Oil Spill Mostly Cleaned Up, Officials Turn Focus To Finding Source – CBS Baltimore – The U.S. Coast Guard is still trying to find the source of an oil spill that was first spotted in the Inner Harbor over the weekend. Coast Guard officials said they’ve been vacuuming the oil out of the water but there is still a little bit left. Now their concern is getting the smell of oil out of the air. “I smell the oil, and I walk here frequently, like almost every day,” Baltimore resident Lelle O’Connor said., “Yeah, I can smell it.” In total, officials believe around 50 gallons of red-dyed number two fuel oil seeped into the harbor over the weekend. “(The fuel is) very similar to a diesel fuel that you might put inside your car but the most common use is oil you use in your home to burn for heat,” said Lt. Justin Valentino with the Coast Guard. The oil was first found Saturday morning near Port Discovery. The trash wheel and boomers helped keep it contained until crews could vacuum the majority out of the water. “It’s very concerning; the water is already very dirty to begin with,” said Baltimore resident Summer Rahe. Officials are now focused on finding the source of the oil. “There’s more than a thousand miles of drains under the city that lead there,” Valentino said. “We have been working with the Maryland Department of the Environment and Baltimore City Fire Department popping open manholes and trying to investigate where that flow goes.” The remaining oil left in the water is expected to evaporate on its own. While there’s no threat to the public, officials warn people to stay away from the water.
Bill aims to answer pipeline question: ‘Is this necessary?’ (AP) – As Dominion Energy spearheads the $8 billion Atlantic Coast Pipeline, Virginia lawmakers are advancing legislation sponsored by a Republican who says he wants to protect the company’s captive ratepayers from possible overcharges. Under legislation from Del. Lee Ware, Dominion’s Virginia electric utility would have to demonstrate the need for a new fuel source and show that it “objectively studied” other options, among other conditions, before the State Corporation Commission could approve passing along costs from the natural gas pipeline. Ware said his bill “makes very clear the question that I’ve always wanted answered: Is this necessary for the ratepayers … or is this entrepreneurial on Dominion’s part?” The legislation has passed the House and is scheduled for a hearing Monday in a Senate committee stacked with Dominion-friendly lawmakers. Richmond-based Dominion, the lead developer of the project that would run from West Virginia through Virginia and into North Carolina, is a giant energy company heavily invested in natural gas infrastructure with customers in 18 states. Dominion’s electric utility is Virginia’s largest and covers about two-thirds of the state. The company is developing the pipeline with partner Duke Energy. Southern Company recently sold its small stake in the project to Dominion. Electric and gas utilities owned by those three companies have signed up to receive about 96% of the the pipeline’s gas once it’s built. Critics say that setup raises questions about whether the gas is truly needed and whether customers could be on the hook for costs that have soared as the project faced numerous delays. Ware said he wants to make sure Dominion customers don’t overpay. The SCC previously rejected a bid by environmentalists to weigh in on the prudency of the pipeline before it goes into service.
Atlantic Coast Pipeline Appalachian Trail Case Heads to Supreme Court | West Virginia Public Broadcasting –A battle over the Atlantic Coast Pipeline is headed to the U.S. Supreme Court Monday, Feb. 24. Oral arguments are scheduled in the case U.S. Forest Service v. Cowpasture River Preservation Association for Monday, Feb. 24. At the heart of the case is whether the U.S. Forest Service has the authority to grant the Atlantic Coast Pipeline a permit to cross under the Appalachian Trail, federal land, that is a unit of the National Park Service. The ruling could have big impacts for the route of the 600-mile natural gas project, which begins in West Virginia and crosses through Virginia and North Carolina. In December 2018, the Fourth U.S. Circuit Court of Appeals ruled that the U.S. Forest Service improperly granted the pipeline a permit to cross under the Appalachian Trail, a popular 2,200-mile hiking route that goes from Georgia to Maine. Ahead of the case being argued in the high court, both the pipeline’s supporters and opponents say they are cautiously optimistic. Federal Barrier? “We think that the Fourth Circuit clearly erred,” said Republican West Virginia Attorney General Patrick Morrisey, speaking at a recent press conference at the capitol in Charleston. Morrisey led a group of 18 state attorneys general who filed an amicus brief urging the Supreme Court to overturn the lower court’s ruling. “You cannot set up literally an impenetrable federal barrier to economic development, not only under our constitution or a law, but under the statutes, the Mineral Leasing Act,” he said. Pipeline spokesperson Ann Nallo said more than 50 other pipelines cross under the Appalachian Trail. In court briefs, pipeline developer Dominion Energy argues if the lower court’s ruling is upheld, that would upend decades of precedent and permits. “So, where the Atlantic Coast Pipeline is currently routed, is underneath one-tenth of a mile stretch about 600 feet below the surface of the Appalachian Trail,” she said. “If it’s now going to be understood that it’s National Park Service land, where a pipeline can’t cross without congressional approval, that essentially turns it into a 2,200-mile barrier.” Other Obstacles But environmental groups say this case is different. Greg Buppert is an attorney with the Southern Environmental Law Center, one of the groups that will defend the lower court’s decision. “Yes, to be sure other pipelines cross the Appalachian Trail. What’s different here is that the crossing is proposed on federal land,” he said. “There’s never been a new right of way for a pipeline on federal land in the last 50 years.”
Supreme Court hears battle over Atlantic Coast Pipeline – The Supreme Court on Monday appeared ready to remove an obstacle to construction of the Atlantic Coast Pipeline, with a majority of justices expressing skepticism about a lower court ruling that tossed out a key permit needed for the natural gas pipeline to cross under the Appalachian Trail. Justices on the court grilled a lawyer for environmental groups who sued and won a 2018 ruling from the Richmond-based 4th U.S. Circuit Court of Appeal throwing out a special-use permit for the 605-mile (974-kilometer) natural gas pipeline. The 4th Circuit found the U.S. Forest Service did not have the authority to grant a right-of-way to allow the pipeline to cross beneath the Appalachian Trail in the George Washington National Forest. But conservative justices, who hold a 5-4 majority on the Supreme Court, expressed reservations about the ruling, with Chief Justice John Roberts at one point saying the lower court’s finding would “erect an impermeable barrier” to any pipeline from areas where natural gas is located to areas where it is needed. “Absolutely incorrect,” attorney Michael Kellogg, representing the environmental groups, responded. Kellogg said there are currently 55 pipelines that run under the Appalachian Trail, 19 of them on federal land with easements granted before the Appalachian Trail was designated as a national scenic trail under the 1968 National Trails System Act. The remaining pipelines are on state and private land, he said. But Justice Brett Kavanaugh told Kellogg that the environmental groups’ position has “significant consequences to it, enormous consequences.” The 4th Circuit found that the 1920 Mineral Leasing Act allows rights-of-way for pipelines on federal land, except for land in the National Park System. The court found that the trail is considered a unit of the National Park System, so the Forest Service doesn’t have the authority to approve a right-of-way.
Justices grapple with $8 billion pipeline that would cross Appalachian Trail – The Supreme Court on Monday heard arguments in a high-profile case that could block construction of an $8 billion gas pipeline seeking to cross the Appalachian Trail. The proposed Atlantic Coast Pipeline (ACP) would carry natural gas 604 miles from West Virginia to North Carolina and would tunnel below the famed trail that runs more than 2,000 miles from Georgia to Maine. At issue is whether jurisdiction over the affected land belongs to the U.S. Forest Service or the National Park Service (NPS). The case presents the justices with a complex tangle of federal laws that will determine if the land is open to energy development or must be preserved for recreational use under the park service’s mandate. The Forest Service issued a permit that would allow the pipeline to cross the trail, but that decision was challenged in the courts by a number of environmental groups. They argue that because the National Park Service oversees all of the federal lands that make up the trail, other agencies don’t have authority to issue a permit. And because the park service’s mandate is focused on conservation, only an act of Congress could allow the pipeline to cross the trail. The 4th Circuit Court of Appeals agreed, revoking the Forest Service permit. The government and the Atlantic Coast Pipeline – on the same side in this case – appealed the decision to the high court. The federal government’s lawyer on Monday argued that the Forest Service had the right to issue a permit. “If a tree falls on Forest lands over the trail, it’s the Forest Service that’s responsible for it. You don’t call the nine Park Service employees at Harpers Ferry and ask them to come out and fix the tree,” argued Anthony Yang with the Office of the Solicitor General, referring to one of the main park service outposts along the trail. In the lower court, lawyers for the Southern Environmental Law Center (SELC) argued the permit to cross the Appalachian Trail was only secured due to a change in administration, the first in the trail’s roughly 50-year history. That permit, they argued, threatened pipeline construction over steep and sensitive terrain before tunneling 600 feet below the trail, creating a “scar” on the landscape. “ACP developers should be playing by the rules, but instead they used political pressure to push a risky project through that, in the end, would harm our public lands,” SELC lawyer DJ Gerken said in a press conference after the hearing. The Atlantic Coast Pipeline is already tied up in a number of other legal challenges and lacks several other required permits, but the Supreme Court case could determine the fate not only of this pipeline, but others that seek to cross Appalachia. In a 2018 decision, the U.S. Court of Appeals for the 4th Circuit sided with the environmental activists based on its interpretations of several interconnected federal laws. The court determined that a 1968 statute called the National Trails Act transferred control over the Appalachian Trail to the National Park Service. And a separate law, the Mineral Leasing Act, prevents the NPS from granting land access, known as a right-of-way, for energy development. But lawyers advocating for the pipeline construction say the lower court misread the law. They argue the National Trails Act did not wrest control of the Appalachian Trail from the Forest Service, which, unlike the NPS, does have the power to grant rights-of-way.
Supreme Court seems ready to back pipeline across Appalachian Trail – New York Times – A challenge from environmental groups to an $8 billion natural gas pipeline that would cross the Appalachian Trail seemed to falter at the Supreme Court on Monday, with even some of the court’s more liberal members expressing skepticism about the breadth of the groups’ legal theory.The case concerns the Atlantic Coast Pipeline, which would deliver gas from West Virginia through Virginia, where it crosses the famous hiking trail, to North Carolina.The legal question for the justices is whether the U.S. Forest Service was entitled to grant a right of way to the pipeline. The United States Court of Appeals for the Fourth Circuit, in Richmond, Va., said no, citing a federal law that bars agencies from authorizing pipelines in “lands in the National Park System.”Monday’s argument was by turns metaphysical and practical.Anthony A. Yang, a lawyer for the federal government, arguing in support of the pipeline’s developers, said the trail, administered by the National Park Service, was distinct from the land underneath it.Justice Elena Kagan said that was “a difficult distinction to wrap one’s head around.”“When you walk on the trail, when you bike on the trail, when you backpack on the trail, you’re backpacking and biking and walking on land, aren’t you?” she asked. “It’s like you’re imagining some thing that goes on top of it somehow.”Justice Samuel A. Alito Jr. proposed a different distinction, one that would allow the pipeline but avoid the more difficult question.“When I think of a trail, I think of something that is on top of the earth,” he said. “And when I think of a pipeline that is 600 feet below the surface, that doesn’t seem like a trail. So instead of having to draw this distinction between the trail and the land, why can’t we just say that the trail is on the surface and something that happens 600 feet below the surface is not the trail?”That solution seemed to intrigue Justice Stephen G. Breyer, and Paul D. Clement, a lawyer for the project’s developers, said he was willing to prevail on that basis. “I represent the Atlantic Coast Pipeline,” Mr. Clement said. “It’s not my job to resist winning this case on a narrow ground.”Chief Justice John G. Roberts Jr. asked about the practical consequences of a broad ruling against the pipeline in the case, U.S. Forest Service v. Cowpasture River Preservation Association, No. 18-1587.“It really does erect an impermeable barrier,” he said of the trail, “to any pipeline from the area where the natural gas, those resources, are located and to the area east of it where there’s more of a need for them.”Michael K. Kellogg, a lawyer for the environmental groups, disputed that, saying there are 55 pipelines running under the Appalachian Trail, including some on federal land built before the federal law and others on state and local land. But he conceded that, under his theory, the trail would act as a barrier on federal land.Justice Sonia Sotomayor suggested that Mr. Kellogg’s argument may have been too sweeping and thus unlikely to satisfy her more skeptical colleagues.Justice Alito said that “there may be all sorts of very good environmental reasons why this pipeline shouldn’t be built,” adding that a lower court was still considering them. “But do you,” he asked Mr. Kellogg, “have more than a ‘gotcha’ argument?”
Virginia proposal would take a new look at Dominion Energy’s surplus profits – The Fair Energy Bills Act would give state regulators power to order refunds when the utility collects excessive revenue. Virginia environmental advocates expect Dominion Energy’s planned investments in solar, offshore wind, and coal ash dump cleanup will lead to some justifiable rate increases for customers in the coming years. The problem, they argue: Right now, the utility’s rates are excessively high. Five years after the General Assembly voted to let Dominion keep excess profits in exchange for freezing base rates for seven years, a bill advancing in the legislature would revisit that position ahead of the company’s next rate case. The Fair Energy Bills Act would empower state regulators to examine Dominion’s earnings, decide how much is fair, then direct the utility to refund the surplus to customers. The legislation sailed out of the House of Delegates this month on a 77-23 vote. It’s now in the Senate Commerce and Labor Committee. “Dominion opposes it and still it got out of House,” said Will Cleveland, a senior attorney with the Southern Environmental Law Center. “But it faces strong headwinds in the Senate.” HB 1132 has support from green groups, social justice organizations, and the manufacturing sector. If passed, the oversight measure would apply to Dominion’s 2021 rate case, when utility regulators will examine four years of records – from 2017 to 2020 – and set Dominion’s next base rate and allowed profit level. Dominion has overcharged customers by more than $1.3 billion since 2015, according to State Corporation Commission figures. Two sets of calculations by regulators estimate refunds would be between $7 and $9 a month for a typical residential customer.
Wetland bank won’t halt gas pipeline – A months-long dispute that pitted a proposed wetlands mitigation bank against an expanded natural gas pipeline is over. The pipeline won, but owners of the Fauquier farm on which the pipeline will be built say the result is a “win, win, win” for all involved. Shannon Jensen, one of the owners of the Catlett property impacted by the expansion of Transco’s natural gas pipeline, said the company made an offer to settle that works for everyone. “The settlement will still allow Virginia Waters and Wetlands to undertake other conservation projects on the property and will also help them to be able to expand their conservation efforts throughout the area,” Jensen said Tuesday, Feb. 18. “I believe this worked out to be a win, win, win for all involved.” The proposed, 30-acre wetland bank, called the Miller Stream Bank Phase II, would have restored 6,700 linear feet of stream channel and 30 acres of wetlands and associated riparian and upland buffers on the Catlett property. The firm estimated the value of the proposed wetland bank at $5 million. Prior to the agreement, Virginia Waters and Wetlands Vice President Andrew Hindman likened Transco’s actions to “bullying.” The firm’s President Joseph Ivers said Transco was attempting to intimidate the firm into accepting “pennies-on-the-dollar” for a deal that would kill the wetland mitigation project. Now, it appears the parties have reached an agreement. The details of the settlement have not been disclosed, however, because both Virginia Waters and Wetlands and Jensen have signed non-disclosure agreements with Transco.
Takoma Park works to eliminate gas by the year 2045 – The proposal would ban all gas appliances, close fossil fuel pipelines, and move gas stations outside city limits by 2045. – Takoma Park – deemed the ‘Berkeley of the East’ – is working toward a total reduction of greenhouse gas emissions by 2035, which includes phasing out such things as heating, water heating, lawn care equipment and cooking equipment that are fossil-fuel based. The city of nearly 17,000 in Montgomery County that voted back in 1983 to become a ‘nuclear-free zone’ is considering an overall ban on fossil fuels, all originating from a nationwide effort by local governments to address what they see as a lack of federal action on climate change.The resolution, which was first raised in a new climate resolution, would ban all gas appliances, close fossil fuel pipelines, and even move gas stations outside the Takoma Park city limits by 2045. The new plans are spelled out in resolution proposed by the Takoma Park City Council, which officials say are not mandatory. The resolution, which is expected to be adopted on March 4, lays out how Takoma Park plans to move toward the elimination of all fossil fuels – including adding to the tree canopy, making current houses and all new structures more energy-efficient and even convincing residents to walk and use public transportation rather than purchase or use cars.Additionally, Takoma Park is aiming to set up a Sustainability Assistance Reserve Fund that will be used to help pay for improvements and updates by low or middle-income residents and business owners.
EIA forecasts natural gas inventories will reach record levels later this year – In the U.S. Energy Information Administration’s (EIA) February Short-Term Energy Outlook (STEO), EIA forecasts that the Lower 48 states’ working natural gas in storage will end the 2019 – 20 winter heating season (November 1 – March 31) at 1,935 billion cubic feet (Bcf), with 12% more inventory than the previous five-year average. This increase is the result of mild winter temperatures and continuing strong production. EIA forecasts that net injections during the refill season (April 1 – October 31) will bring the total working gas in storage to 4,029 Bcf, which, if realized, would be the largest monthly inventory level on record.Mild winter temperatures for the current winter have put downward pressure on natural gas prices and led to smaller withdrawals from natural gas into storage. Year-over-year growth in dry natural gas production and natural gas exports – especially liquefied natural gas (LNG) – throughout 2019 also affected natural gas storage levels. On October 11, 2019, the total natural gas in storage surpassed the previous five-year average – an indicator of typical storage levels – for the first time since mid-2017. The total natural gas in storage at the start of this heating season was 3,725 Bcf on October 31, 2019. EIA expects withdrawals from working natural gas storage to total 1,790 Bcf at the end of March 2020. If realized, this would be the least natural gas withdrawn during a heating season since the winter of 2015 – 16, when temperatures were also mild.Injections into and withdrawals from natural gas storage balance seasonal and other fluctuations in consumption. Natural gas demand is greatest in the winter months, when residential and commercial demand for natural gas for space heating increases. Natural gas consumption in the power sector is greatest in summer months, when overall electricity demand is relatively high because of air conditioning.
Buyer Cancels LNG Cargoes From Cheniere— A buyer of liquefied natural gas has canceled two cargoes from Cheniere Energy Inc., the biggest U.S. exporter, as a global glut pummels prices for the fuel and threatens to shut a key outlet for shale production. Spanish utility owner Naturgy Energy Group SA has decided not to take delivery of two shipments from Cheniere, according to people with direct knowledge of the matter. The cargoes, one of which was scheduled for April delivery, were rejected by Naturgy’s clients Repsol SA and Endesa SA, who had originally purchased the volumes from Naturgy and will now pay a contractual fixed fee, the people said. Cancellations of U.S. cargoes were closely watched and highly anticipated amid a grim outlook on global prices. It could be an early sign that global oversupply is poised to hammer the U.S. gas market, which is already straining under the weight of a domestic glut. Prices in Europe and Asia collapsed as storage levels rose during a mild winter, making it tougher for LNG buyers to make a profit reselling U.S. cargoes abroad. The coronavirus outbreak in China is stifling LNG demand from the world’s fastest-growing importer. While the Asian nation hasn’t directly imported any U.S. cargoes in more than a year amid trade tensions, the virus has contributed to the global price rout. The virus has wreaked havoc on commodity markets from LNG to copper while disrupting global industrial production, travel and supply chains. As Chinese demand for the fuel declined, PetroChina Co. is said to have delayed discharge of multiple cargoes. Qatar and the world’s biggest LNG trader, Royal Dutch Shell Plc, said they’re working with customers to reschedule or reroute deliveries. While lower prices are opening up demand in places such as India and Turkey, they’re also testing Europe’s ability to absorb extra supply in a weak market.
Time Will Tell – Sagging Supply and Rising Demand for Jones Act Ships to Send Rates Higher –This year marks the 100th anniversary of the Merchant Marine Act of 1920, a federal law whose section 27 is better known as the Jones Act for its author, Senator Wesley Jones of Washington state. As we said in The Sea and Mr. Jones, the Jones Act requires that all goods transported by water between U.S. ports be carried in U.S.-flagged ships constructed in the U.S., owned by U.S. citizens, crewed by U.S. citizens, and registered in the U.S. As it applies to the energy sector, the Jones Act fleet consists of five main categories of vessels: smaller inland barges that typically carry either 10 Mbbl or 30 Mbbl of crude or refined products and operate on inland waterways as well as coastal canals; regional offshore tank barges (e.g. New York Harbor) with capacities of 50 MMbbl to 135 Mbbl; coastal barges, including larger articulated tug barges (ATBs) with capacities of 142 Mbbl to over 320 Mbbl; tankers that operate in both coastal and international waters and generally carry ~330 Mbbl of crude oil or refined products; and large crude oil tankers in the Alaskan trade. In Flirtin’ With Disaster, we explained that the maritime industry is well known for its boom-and-bust shipping cycles, when periods of strong charter rates lead to overbuilding and subsequent rate collapses. A boom in charter rates for ATBs and tankers last occurred in 2013-14, when sharp increases in U.S. crude and condensate production spurred extraordinary demand for Jones Act vessels. Back in 2013-14, a run-up in demand for Jones Act tankers and large articulated tug barges – – and a spike in time charter rates – spurred orders for a flotilla of new vessels. By the time the new tankers and ATBs were built and launched, however, demand for them had fallen off. That decline was mostly due to the mid-decade slump in U.S. crude oil production and, with the lifting of the ban on most U.S. crude exports, the drop in crude shipments from one U.S. port to another. Term charter rates plummeted and ship owners stopped ordering new tankers and large ATBs. Now, for the first time in more than five years, there are barely enough Jones Act vessels to go around, and charter rates are on the rise. Today, we discuss recent trends and how they’re impacting crude oil and refined products transportation costs. The “shot heard ‘round the world” for those in the Jones Act trade was Koch Industries’ re-letting (or sub-chartering) of the Jones Act product tanker American Phoenix for $120,000/day in the spring of 2014; there were also several other charters of $100,000/day or more that same year. The combination of high demand for Jones Act vessels and soaring charter rates prompted a flood of orders at U.S. shipyards. The capacity of U.S. shipbuilders to construct new vessels is limited, though. There are only two U.S. shipyards currently able to build Jones Act tankers: General Dynamic’s NASSCO in San Diego, CA, and the Philly Shipyard in the City of Brotherly Love. It now takes about three years for new-order product tankers and large ATBs to be contracted, built and delivered. And, as everyone in the energy and shipping businesses knows, a lot can happen in three years.
Senator Rubio confident Trump administration will extend Florida offshore drilling ban – (Reuters) – U.S. Senator Marco Rubio on Tuesday said he was confident the administration of President Donald Trump will extend a ban on oil and gas drilling off Florida, despite its enthusiasm for opening much of the country’s coasts to petroleum development. “I expect that the Trump Administration will not act to oppose or defeat my efforts to extend the offshore drilling moratorium in the Eastern Gulf of Mexico beyond its current expiration in 2022,” Rubio, a Florida Republican, said in a statement. In December, Rubio lifted a hold he had placed on the confirmation of Katharine MacGregor as deputy secretary of the Interior Department. He had voiced concern that MacGregor, a proponent of Trump’s expansive oil and gas production policy, would work to lift the ban off Florida. Florida Senator Rick Scott, Rubio’s fellow Republican, also opposes drilling off the state. Not extending the ban would face fierce opposition by coastal tourism, real estate and environmental interests in Florida. The U.S. Senate will not likely pass a permanent moratorium on the drilling, Rubio believes, so he has sponsored a bill to extend the ban through 2027. Trump’s offshore drilling plan, which MacGregor helped develop, was sidelined after a court ruling blocked drilling in the Arctic and Atlantic, but it could resurface after November’s U.S. presidential elections.
Evacuations in order following gas leak in Yazoo County – (WJTV) – Several agencies are responding to a gas leak along Highway 433 and Highway 3 in Yazoo County.Corporal Kervin Stewart with Mississippi Highway Patrol said multiple people were transported to the hospital, while others have been treated near the evacuation area.According to Vicksburg News, Yazoo County authorities notified Warren County of a toxic chemical release in the Satartia area around 7:35 p.m. on Saturday.Yazoo Emergency Management Director Jack Willingham said that they may be dealing with a carbon dioxide gas leak. Authorities are asking people to stay out of the State Highway 3 and Highway 433 area until further notice.The Yazoo Co. Emergency Management Agency released the following statement:“To all residents of Satartia, if you are located within 1/4 mile of Satartia hill you need to take one of the following actions: If you are in a solid structure as a house or sturdy trailer you can shelter in place. Cut off all heaters and air conditioners. If you can smell a noxious odor in your home, whether trailer or house, you need to evacuate.”
48 hospitalized after gas leak in Yazoo County (WJTV) – Authorities said weather may have contributed to a gas leak in Sataria on Saturday. They said the ground may have shifted due to the recent rain.The pipeline was transporting carbon dioxide used by Denbury Resources for oilfield operations.At least 48 people were taken to the hospital because of the leak. 300 neighbors were evacuated from the area near MS 3 and MS 433. The Mississippi Department of Transportation reopened the roads Sunday morning.Officials said homes were inspected, and environmental specialists escorted neighbors to their houses on Sunday.Denbury released a statement about the leak:At approximately 7:00 p.m. on Saturday, February 22nd, a leak was detected on a carbon dioxide pipeline operated by Denbury Onshore in Yazoo County, MS near the town of Satartia. The affected area of the pipeline was isolated within minutes, and the leak site was evacuated as a precaution. Denbury has been working closely with state and local officials in the response and evacuation efforts to ensure the safety and welfare of the community, its residents and the environment, which is Denbury’s top priority. It is important to note that no injuries have been reported, the area is secure and poses no threat to the public, and local authorities lifted the evacuation at 8:00 a.m. Sunday morning permitting residents to return to their homes. Company and local officials are available to assist residents as they return. The cause of the release is under investigation.
Gas Pipeline Rupture Injures 46, Forces 300 to Evacuate in Mississippi – More than 300 people were forced to evacuate and 46 were sent to the hospital after a gas pipeline ruptured in Mississippi Saturday.The pipeline was used by the company Denbury Enterprises to transport carbon dioxide and hydrogen sulfide for oilfield operations, according to The Yazoo Herald. It ruptured around 8 p.m. near the town of Satartia in Yazoo County, according to the Mississippi Emergency Management Agency (MEMA).”Residents in the area complained of green gas and a noxious odor,” MEMA said.People near the leak experienced headaches and dizziness, and some lost consciousness, the Vicksburg Daily News reported. The leak overwhelmed Yazoo County emergency rooms and at least five of those injured had to be transferred to Warren County. Among the injured were three people discovered non-responsive in a vehicle near the leak site by emergency workers just before 10 p.m.Those taken to the hospital were expected to recover, and evacuees were allowed to return to their homes after 9:30 a.m. Sunday, The Weather Channel Reported.Denbury shut off the gas as soon as it learned of the rupture, according to The Weather Channel.”[T]he affected area of the pipeline was isolated within minutes, and the leak site was evacuated as a precaution,” the company said in a statement reported by TIME.An initial investigation suggests the rupture was a result of recent heavy rainfall in Mississippi.”It appears the ground caved into a ravine damaging the 24-inch pipe,” MEMA said. Parts of the state near the rupture have seen 23 inches of rain since Jan. 1, the Weather Channel reported. Jackson, the state’s capital, has had its wettest start to the year on record as of Feb. 22. Its Pearl River crested at 37 feet Feb. 17, its third highest water level in recorded history, The New York Times reported. More than 2,400 structures are likely to have been damaged by the flooding, authorities estimate.
U.S. crude oil production increases; imports remain strong to support refinery operations –United States refineries are some of the most complex in the world and can process a wide range of crude oil qualities. Although U.S crude oil production has grown significantly since 2009, having access to imports from oil producers around the world provides refiners with the range of crude oil quality that is optimum for each refinery’s configuration, maximizes profitability, and enables the refinery to either supply petroleum products for domestic consumption or export at competitive prices.In general, domestically produced crude oil is light when compared with imported oil. For example, in 2018, 56% of the oil produced in Texas, the largest crude oil-producing state, was relatively light with an API gravity between 40 and 50 degrees. At the same time, 58% of imported crude oil was relatively heavy with an API gravity of less than 25 degrees. By augmenting the relatively light domestic crude oil production with relatively heavy crude oil imports, the United States has significantly increased its ability to export refined product. Because of higher domestic production, the United States has exported more oil and petroleum products, combined, than it has imported since September 2019.U.S. refineries rely on imports as feedstock to optimize production and maximize profits. For example, as of January 2019, U.S. refineries had more than 3 million barrels per day of coking capacity. This capacity is used to process heavy and medium crude oils efficiently and would likely be underutilized if a refinery chose to only run domestically produced light crude oil because coking units are designed to convert heavy, low-value intermediates into high-value naphthas and distillates.In addition to the differences in crude oil quality, the refiner acquisition cost of crude oil can be different for domestic and imported barrels. The refiner acquisition cost is the total amount that a refiner can expect to pay for crude oil, including freight costs and other transportation fees. Traditionally, heavy and medium crude oils trade at a discountto light, sweet crude oils. Since 2012, the increase in the share of imported crude oils with lower API gravity (heavier oil) has resulted in a lower refiner acquisition cost for imported crude oil when compared with the domestically produced higher API gravity (lighter oil) volumes.
Proposed Settlement Seeks To Offset Emissions From Refinery Explosion – Husky Energy will have to upgrade safety and install solar panels to offset emissions from the2018 explosion at its Superior refinery. The projects are part of a proposed settlement filed Friday in federal court. Husky, which does business as Superior Refining Co. in Wisconsin, will make safety upgrades to its hydrofluoric acid (HF) tank under the agreement with state and federal justice officials. Concerns about an HF release prompted a temporary evacuation for some of the city’s 27,000 residents during the aftermath of the explosion April 26, 2018. While no release occurred, Husky has already said it will make safety improvements to its HF unit as part of its $400 million rebuild. The improvements include installation of a rapid acid transfer system that can move hydrofluoric acid to an emergency holding vessel in the event of a release. Planned upgrades also include enhanced leak detection with a laser detection system and cameras, as well as additional layers of water protection. “Superior Refining shall retain a qualified, third-party consultant or consultants with knowledge in refinery processes and operations relevant to the HF Unit to assist Superior Refining’s development and implementation of each of the upgrades,” states the proposed settlement. The agreement also includes a study of physical barriers or other measures that could mitigate the effects of an HF release. . “This is a refinery in the middle of an urban area. Increasing safety, mitigating risk is an ongoing permanent effort. Having a major energy producer in your community always carries with it some level of risk,” Superior Mayor Jim Paine said. “We always have to be assessing that and making that refinery and the community that surrounds it safer.”The proposed settlement also requires Husky to spend at least $290,000 to replace or retrofit inefficient wood-burning stoves or furnaces at homes, churches or schools spanning a seven-county region and several reservations in northern Wisconsin. At least 12 percent of the funding must be dedicated to rebates or discounts for low-income households. The work must be completed within four years.
Exxon Baton Rouge, Louisiana, refinery aims to restart CDU this week: sources – (Reuters) – Exxon Mobil Corp plans to restart the large crude distillation unit (CDU) and a coker this week at its 502,500 barrel-per-day (bpd) Baton Rouge, Louisiana, refinery this week, sources familiar with plant operations said on Monday. The 240,000 bpd PSLA 10 CDU and the 50,000 bpd coker were shut on Feb. 12 following a natural gas pipeline fire that idled most of the production units at the refinery, the sources said. Exxon spokesman Jeremy Eikenberry said on Monday operations were continuing at the Baton Rouge refinery and adjoining chemical plant. He declined to discuss the status of individual units. m PSLA 10 and the coker could restart as early as the middle of this week, if all goes as planned, the sources said. Three of the four CDUs at the refinery were shut by the fire. The pipeline that caught on fire supplies natural gas that fuels boilers on the units, the sources said. The CDUs do the primary breakdown of crude oil into the hydrocarbon feedstocks, from which motor fuels like gasoline and diesel and plastics are made in other production units at the refinery.
Momentum Builds to Monitor Cancer Alley Air Pollution in Real Time After Exxon Refinery Fire in Louisiana – A large fire at ExxonMobil’s Baton Rouge oil refinery late on February 11 lit up the sky for miles and continued until dawn. The night of the fire, ExxonMobil representatives claimed that air monitoring inside the plant and in surrounding neighborhoods did not detect the release of harmful concentrations of chemicals, a claim echoed by first responders and state regulators. What unfolded, however, reinforced a growing community movement to require real-time independent air pollution monitoring at industrial facilities.A week after the incident, Exxon filed a required “seven-day report” to the Louisiana Department of Environmental Quality (LDEQ) indicating the plant released four toxic chemicals during the incident, including benzene, butadiene, and sulfuric acid in quantities above allowable limits, and sulfur dioxide. Exxon said in its report that thousands of pounds of unspecified flammable vapor released in the incident were burned off by the fire and that little, if any, escaped the refinery in concentrations that could have posed a risk to nearby residents. However, many in the community were outraged about how much time passed before they were notified of potential hazards and expressed doubt that the fire had no significant effect on the air quality around the plant.The incident reignited calls from environmental advocates for more real-time monitoring of a class of potentially toxic chemicals known as volatile organic compounds (VOCs) at chemical plants and refineries. They say that with this kind of publicly available monitoring, residents near such facilities won’t have to rely on industry for health warnings in case of an emergency. “Everyone in the community has the right to be safe and secure in your homes,” Louisiana Senator Cleo Fields, a Democrat representing Baton Rouge, said at a community meeting he organized a week after the fire. Flares were visible from the Star of Bethlehem Baptist Church’s parking lot where the meeting was held, near Exxon’s 2,100-acre complex that includes the refinery and multiple chemical plants. At the meeting, Fields promised to craft legislation aimed at improving emergency notifications, implementing 24/7 real-time air monitoring, upgrading the current supply of safety devices, and establishing a clear and transparent emergency plan for chemical facilities and refiners statewide. For residents near Exxon’ refinery and adjacent chemical plants in Baton Rouge, a sense of safety and access to clean air are not a given. The plants lie at the northern end of Louisiana’s Cancer Alley, an 80-mile stretch along the Mississippi River with more than a hundred petrochemical plants and refineries woven among the river’s communities.
The market for hydraulic fracturing is expected to grow at a CAGR of approximately 8.55% during the forecast period of 2019. – Reportlinker.com announces the release of the report “Hydraulic Fracturing Market – Growth, Trends, and Forecast (2019 – 2024)” –On the flip side, environmental concerns and lack of capital market & incentives are restraining the market growth.
– Horizontal well type is expected to be the fastest growing well type. The majority of the wells active in the Permian Basin are horizontal wells (more than 2,000). As of April 2019, the total number of drilled wells in the Permian basin reached 555, repressing an increase of around 4.7% compared to the previous year value in the same month.
– The economic viability of using CO2 and nitrogen-based ‘foam’ fluids, capable of providing waterless fracking, presents a growth opportunity for the companies.
– North America to dominate the market across the globe in the future, with the majority of the demand coming from the US and Canada.
– New technique of horizontal drilling and combined it with the pre-existing hydraulic fracturing techniques making it favorable for drilling in shale gas regions.
– The United States can be considered as the country, which has benefited the most from the combination of horizontal drilling and hydraulic fracturing. The shift from vertical to horizontal wells is the most important change to occur over the last decade, allowing for greater formation access, while only incrementally increasing the cost of the well.
– The country’s natural gas production increases since 2005 have mainly been the result of horizontal drilling and hydraulic fracturing techniques, notably in shale, sandstone, carbonate, and other tight geological formations.
– Since 2010, horizontal good drilling activity has dominated and currently accounts for the vast majority of drilling activity in the Western Canada Sedimentary Basin (WCSB). Therefore, an increase in horizontal well drilling activities propels the demand for the hydraulic fracturing market.
Yale study finds link between STIs and fracking – Yale Daily News – Increased rates of sexually transmitted infections in Texas are associated with high levels of shale drilling activity, according to findings in a recent Yale study. In early January, researchers at the School of Public Health published a study on the reported rates of STIs and the number of active shale wells in Texas, North Dakota and Colorado. Investigators found increased rates of chlamydia and gonorrhea in Texas counties during years of high drilling activity. Still, the study shows no statistically significant relationship between the prevalence of STIs and drilling in North Dakota or Colorado. This was the first multi-state, multi-region analysis of shale drilling activity and STI rates in the United States. “Previous studies have examined the relationship between shale drilling activity and rates of gonorrhea, chlamydia and syphilis in counties throughout the eastern [United States]. Our intent was to assess whether this phenomenon could be observed in other geographies,” said lead author Nicholaus Johnson SPH ’19. “I think this [is] important because [it] demonstrates the often unexpected ways in which resource extractive processes can impact human health.” As the leading global producer of crude oil and natural gas, the United States is home to many specialized workers that often migrate across state lines to meet the demands of fracking companies installing new drilling rigs. The temporary workcamps house a labor force that is 80 percent male and, according to the study, serve as cradles for “masculinized culture,” hot spots for sex workers and breeding grounds for STIs. Researchers analyzed data provided by the Centers for Disease Control on STIs in the three states. The authors obtained information on the number of active shale wells from the online database Enverus. Counties with high rates of shale drilling activity were classified as those with 50 operational hydraulic fracking wells. Data spanned the time frame from 2006 to 2016, to provide a comparison of STI rates before and after the start of drilling activity in the areas of interest. The analysis showed increased rates of chlamydia as high as 10 percent and increased rates of gonorrhea as high as 15 percent in Texas counties during years of high drilling activity, with no notable difference in STI rates associated with drilling in North Dakota or Colorado counties. Deziel speculated that the incongruous findings between the three states “may reflect the higher level of [Texas] drilling activity and a greater number of densely populated metropolitan areas compared to other regions.”
To Many’s Dismay, Permian Produces More Gas and Condensate Instead of Oil and Profits – 0As oil prices plummet, oil bankruptcies mount, and investors shun the shale industry, America’s top oil field – the Permian shale that straddles Texas and New Mexico – faces many new challenges that make profits appear more elusive than ever for the financially failing shale oil industry. Many of those problems can be traced to two issues for the Permian Basin: The quality of its oil and the sheer volume of natural gas coming from its oil wells. The latter issue comes as natural gas fetches record low prices in both U.S. and global markets. Prices for natural gas in Texas are often negative – meaning oil producers have to pay someone to take their natural gas, or, without any infrastructure to capture and process it, they burn (flare) or vent (directly release) the gas. As DeSmog has detailed, much of the best oil-producing shale in the Permian already has been drilled and fracked over the past decade. And so operators have moved on to drill in less productive areas, one of which is the Delaware sub-basin of the Permian. Taking a close look at the Delaware Basin highlights many of the current challenges facing Permian oil producers. The Delaware Basin is where most of the new oil production is coming out of the Permian. As a Bloomberg Wire story reported in December, “in recent years investments have shifted to the Delaware, where output is much gassier than in the historic Midland portion of the Permian.” The last thing a Permian oil producer wants is to have natural gas coming out of the ground with the oil because, as Bloomberg notes, this persistent “nuisance” is “undercutting profits for explorers.” That’s a generous assessment because many explorers have no profits to undercut, only losses to grow. Shale wells become “gassier,” or produce more natural gas, as they age and oil production falls. And this problem hasn’t improved for wells in the Delaware that are drilled closer together, compounding the Permian’s gas problem. With natural gas prices often going negative in Texas, producers are turning to flaring and venting more of the gas, which is mostly the powerful greenhouse gas methane. Fracking CEOs have been publicly noting that this issue U.S. shale industry can’t flare or vent its excess methane, those companies will likely be forced to shut down oil production due to cost.
‘It’s A Joke’: Flaring Expert Finds Big Problems In Report From Texas Oil And Gas Regulator — The amount of natural gas that oil companies burn off in Texas as a waste product could power every home in the state. It’s an industry practice known as “flaring,” and as it grows, so does pollution and waste associated with oil extraction. So, last week, a top state oil and gas regulator produced a report on it.The Railroad Commission of Texas regulates the oil and gas industry in the state. It’s run by three commissioners who are elected statewide. Commissioner Ryan Sitton wrote that he produced the paper “to evaluate the nature of potential changes to regulation [around flaring] and the potential impacts of those changes.”The report was notable for naming names. Sitton ranked different oil producers by how much they flare. It also provides some historical context for flaring. The commissioner also argued the state is actually flaring less than it did decades ago.Industry groups applauded the effort, but a leading flaring researcher has found plenty to criticize. “It’s not a report,” Gunnar Schade, an associate professor of atmospheric sciences at Texas A&M University, said. “It looks more like a political manifesto to me” because it relies so heavily on pro-industry talking points. Schade also said the report is misleading.In the paper, Sitton wrote that he “established a metric that relates the amount of gas flared to the amount of oil produced, referred to herein as flaring intensity.”When Schade reads that, it makes him think Sitton is trying to take credit for creating a metric that is nothing new and often used to downplay the impact of natural gas flaring.Sitton “would receive an F for this report at A&M [his alma mater] for blatant plagiarism” of a well-known research metric, Schade wrote in an email.“The industry has been promoting this flaring intensity metric for a very long time,” he said. “One of the reasons the industry likes this type of metric is that it lets them compare themselves against others in terms of efficiency.”It’s a way for the industry to brag about how efficient it is, he said, while downplaying the amount of gas being burned off. “The metric itself is not too useful from an environmental point of view,” he added, “because what matters to the environment is the total amount of flaring that you have in the region.”
Apache Ditches Alpine High After $3B Writedown — Apache Corp. is officially calling it quits on a highly publicized but disappointing shale discovery in West Texas after vehemently defending the play’s prospects for about three years. The Houston-based company posted a roughly $3 billion writedown on its Alpine High project, a find from 2016 that fizzled when it turned out to hold more natural gas than oil. Apache will instead focus on offshore riches in Suriname, where the explorer recently struck crude and enlisted French oil titan Total SA as a partner. “Apache has no current plans for future drilling at Alpine High,” Clay Bretches, chief executive officer of Apache’s pipeline spinoff, Altus Midstream Co., said in a statement. The discovery was announced in September 2016 to much fanfare and claims the field held 3 billion barrels of crude and 75 trillion cubic feet of gas. But it quickly became apparent that that corner of the prolific Permian Basin was far richer in natural gas and its byproducts than more-valuable oil. The Alpine High became even more worrisome for investors as gas supplies in the region ballooned and prices cratered. Until recently, Apache executives defended the Alpine High, saying in May that investors didn’t yet “have an appreciation for the potential cash flow generation from the liquids play at Alpine High.” But roughly five months later, the star Apache geologist who led discovery of the field abruptly left. At the time, the departure of Steven Keenan, Apache’s senior vice president of worldwide exploration, raised red flags for the company’s other high-profile prospect — offshore Suriname. Apache calmed investors who were nervous Suriname would be a bust last month when it disclosed a major discovery. The announcement came shortly after Apache brought Total aboard to help develop the project on Suriname’s Block 58. The company will now shift its capital spending to focus on Suriname rather than on “near-term growth opportunities,” Christmann said. Altus Midstream, meanwhile, will look for new customers to fill its pipes. “We are aggressively pursuing third-party volumes to replace declining production from Alpine High and maximize throughput at our Diamond processing facility,” Bretches said in Altus’ fourth-quarter earnings statement.
Williams seeks to raise $5B in pipeline sale – Williams Companies Inc is seeking a partner to invest in a network of its pipelines in the western United States, a deal that could raise close to $5 billion for the Tulsa, Oklahoma-based company, people familiar with the matter said, as reported by Reuters. Contract.jpg The investment would be larger than the joint venture that Williams clinched last year with the Canada Pension Plan Investment Board (CPPIB) in the Marcellus and Utica shale basins of Appalachia, which gave the pension fund a 35% stake in the assets for $1.33 billion. The deal would underscore how pipeline operators are cashing out on some of their assets, so that they can pay down debt and put money into new projects, which have the potential to give them better returns. The latest collection of pipelines that Williams is offering a stake in transfers hydrocarbons away from oil and gas drilling sites, usually to larger pipelines which reach storage facilities or customers – known in the energy industry as gathering and processing (G&P) assets. It generates 12-month earnings before interest, tax, depreciation and amortization of around $1 billion, according to the sources. As with the CPPIB deal, Williams is seeking to remain the operator of the pipelines, the sources added. The sources spoke on condition of anonymity as the information is not public.
Ducey Signs Bill Banning Local Bans on Natural Gas Into Law –Governor Doug Ducey has signed into law a bill that will prevent cities and towns in Arizona from banning natural gas, despite clear opposition from major cities. Spokesperson Patrick Ptak said that Ducey signed House Bill 2686, which was fast-tracked through the State Legislature this month with companion bills in the House and Senate, on Friday. On its face, the new pre-emption law prevents municipalities from discriminating against different utilities in issuing building permits and making zoning decisions. They cannot “deny a permit application based on the utility provider proposed,” the bill reads, and they cannot pass codes or ordinances that could “have the effect of restricting a person’s or entity’s ability to use the services of a utility provider.” But the new law is expected to benefit, in particular, the gas industry. The bill was pushed by Southwest Gas, a major gas company in Arizona, where more than half of its some 2 million customers live. It is backed by others in the industry and its business-minded allies. Last year, its sponsors in the Legislature received their largest donations from Southwest Gas. Southwest Gas has said that the legislation would ensure “homeowners, builders, or business owners have access to balanced energy solutions that are efficient, affordable, and clean.” The legislation was proposed just as the gas industry nationwide began looking to undercut efforts by a growing number of cities to curb or end the use of natural gas, which leaks methane and produces carbon dioxide, in an attempt to mitigate climate change at a local level. Now, with the help of a new law preserving its customer base and protecting its profits, the gas industry doesn’t have to worry about such bans happening here in Arizona. Before it became law, major cities in Arizona registered opposition to the bill, for other reasons. Mayor Kate Gallego of Phoenix has criticized the legislation as undermining local authority. “City government is the branch of government closest to the people it serves,” she said in a statement earlier this month. “We think pre-emption of local control in any form sets a bad precedent.” Regina Romero, the mayor of Tucson, voiced similar concerns. “I will always be against state legislation that needlessly micromanages cities and tells us what we can and cannot do. Tucsonans know what is best for our community, not the State Legislature,”
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