Oil, Gas, And Fracking News Reads: 08March 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 07 March 2020.

This article is a feature every Monday evening on GEI.

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Oil prices crash to 42 mo low on OPEC discord; US oil output at a record high; natural gas rigs at a 40 month low

US oil prices saw their largest daily loss since 2014 on Friday, while international prices were down by the most in 11 years, after this week’s OPEC+ meeting broke up without an agreement…after falling 16% to $44.76 a barrel last week on the economic impact of the coronavirus epidemic, the contract price of US light sweet crude for April delivery opened lower and continued falling early Monday, being at one point down more than 3% at $43.32, before the freefall was halted by expectations that the OPEC+ alliance would deepen output cuts, and then surged to gain $1.99, or 4.5%, to finish at $46.75 per barrel in their best day since September after reassurances from central bankers around the world that they would take stabilization measures…oil prices rallied again on Tuesday and were again up more than 4% after the Fed moved to slash interest rates by half a point, but finished well off the day’s high as the Fed’s rate cut raised worries about the seriousness of the virus’s economic fallout, with US crude ending the session up just 43 cents or less than 1% at $47.18 a barrel…oil’s price rebound extended into a third day on Wednesday after OPEC+ experts recommended deeper production cuts, and held above $48 after the EIA reported a smaller than expected crude inventory build, but then settled 40 cents lower as oil producers meeting in Vienna appeared to struggle to reach an agreement on production cuts…oil prices were initially higher again on Thursday after sources told Reuters that OPEC had agreed to cut production by 1.5 million barrels per day, but then fell after the coronavirus epidemic worsened, prompting a selloff of risky assets such as stocks, with oil ending down 88 cents at $45.90 a barrel…oil moved briefly higher early Friday on hopes that the Saudis would get their 1.5 million barrel per day cut, but then began sliding after Reuters reported that Russia would not agree to the steeper oil output cuts proposed by OPEC, and finally plunged more than 10% to a 42 month low of $41.28 a barrel after the OPEC meeting ended with no mention of production cuts…US crude prices thus ended the week down 7.8% lower at its lowest close since August 2016, as more than 4.58 million front-month U.S. crude contracts changed hands in the busiest trading week on record…

With oil prices thus finishing the week at a 42 month low, we’ll include a 10 year oil price graph so we can see how the current price compares to the historical record:

The graph above is a screenshot of the interactive price chart for the front month 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 the nearest oil futures contract as a vertical bar for each month over the past 10 years….this graph was generated by taking the price quotes for what is called the “front month” oil futures contract, or the contract that is being quoted as “the price of oil” daily, with the each monthly contract price being replaced by the next month’s price when trading in that contract expires on the 4th business day prior to the 25th calendar day of the month preceding the contract month.. you might also note that each bar has two small horizontal appendages: the one on the left is the opening price for the month the bar indicates, while the appendage on the right is the month’s closing price…as you can see, oil prices are now down to a level seen only once in the past ten years, from late 2015 to early 2016, when oil prices crashed after OPEC after flooded the global oil market, causing a collapse in prices which put hundreds of US oil companies into bankruptcy…before that, oil prices had generally tracked between $80 and $110 a barrel for years..

Natural gas prices managed to hold on to a small gain for the week, but remained near historical lows…after falling 12% to a four year low of $1.684 per mmBTU in last week’s market bloodbath, the contract price of natural gas for March delivery rebounded 7.2 cents on Monday, even as the weather outlook remained bearish, and continued 4.4 cents higher on Tuesday and 3.7 cents higher on Wednesday on a slight decline in output, despite weather forecasts confirming it would remain warmer-than-normal over the next two weeks….but prices turned lower Thursday, falling 5.5 cents to $1.772 per mmBTU, on forecasts for lower heating demand over the next two weeks, despite an increase in LNG exports and a EIA report showing a near-normal weekly storage draw…prices gave up most of their remaining gains for the week on Friday, falling 6.4 cents to $1.708 per mmBTU, on the absence of any late season cold in the forecasts, but still ended with a gain of 1.4% on the week…

The natural gas storage report on the week ending February 28th from the EIA indicated that the quantity of natural gas held in underground storage in the US fell by 109 billion cubic feet to 2,091 billion cubic feet by the end of the week, which still left our gas supplies 680 billion cubic feet, or 48.2% higher than the 1,411 billion cubic feet that were in storage on February 28th of last year, and 176 billion cubic feet, or 9.2% above the five-year average of 1,915 billion cubic feet of natural gas that has been in storage as of the 28th of February in recent years….the 109 billion cubic feet that were withdrawn from US natural gas storage this week was a bit more than the consensus estimate for a 105 billion cubic feet withdrawal by analysts polled by Platts, and was also a bit more than the average 106 billion cubic feet of natural gas that have been pulled from natural gas storage during the last week of February over the past 5 years, but it was much less than the 152 billion cubic feet withdrawal reported during the corresponding week of 2019..

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 28th indicated that a increase in our oil exports 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 seventeenth time in the past twenty-five weeks….our imports of crude oil rose by an average of 21,000 barrels per day to an average of 6,238,000 barrels per day, after falling by an average of 330,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 497,000 barrels per day to 4,154,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,084,000 barrels of per day during the week ending February 28th, 476,000 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 rose by 100,000 barrels per day to a record high of 13,100,000 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 15,184,000 barrels per day during this reporting week..

US oil refineries reported they were processing 15,696,000 barrels of crude per day during the week ending February 28th, 312,000 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 112,000 barrels of oil per day were being added to to the supplies of oil stored in the US….so looking at that data, 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 624,000 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 (+624,000) 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…however, 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 6,495,000 barrels per day last week, now 2.5% less than the 6,663,000 barrel per day average that we were importing over the same four-week period last year….the 112,000 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 100,000 barrels per day higher at a record high of 13,100,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day higher at a record high of 12,600,000 barrels per day, while a 1,000 barrel per day increase Alaska’s oil production to 475,000 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 March 1st was rounded to 12,100,000 barrels per day, so this reporting week’s rounded oil production figure was 8.3% above that of a year ago, and 55.4% 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 86.9% of their capacity in using 15,696,000 barrels of crude per day during the week ending February 28th, down from 87.9% of capacity the prior week, but still near the recent average refinery capacity utilization for the end of February, historically the time of year that refineries change blends and undergo maintenance…however, the 15,696,000 barrels per day of oil that were refined this week were 1.8% less than the 15,990,000 barrels of crude that were being processed daily during the week ending March 1st, 2019, when US refineries were operating at 87.5% of capacity….

With the decrease in the amount of oil being refined, gasoline output from our refineries was also lower, decreasing by 40,000 barrels per day to 9,757,000 barrels per day during the week ending February 28th, after our refineries’ gasoline output had increased by 272,000 barrels per day over the prior week… after this week’s decrease in gasoline output, our gasoline production was 1.0% lower than the 9,852,000 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 198,000 barrels per day to 4,648,000 barrels per day, after our distillates output had decreased by 6,000 barrels per day over the prior week…after this week’s drop in distillates output, our distillates’ production for the week was 5.5% less than the 4,919,000 barrels of distillates per day that were being produced during the week ending March 1st, 2019….

Following the decrease in our gasoline production, our supply of gasoline in storage at the end of the week fell for the fifth week in a row, after twelve consecutive increases, but was still down for the 19th time in 37 weeks, falling by 4,339,000 barrels to 252,048,000 barrels during the week ending February 28th, after our gasoline supplies had decreased by 2,691,000 barrels over the prior week….our gasoline supplies decreased by more this week because the amount of gasoline supplied to US markets increased by 151,000 barrels per day to 9,186,000 barrels per day, while our exports of gasoline fell by 30,000 barrels per day to 802,000 barrels per day, while our imports of gasoline rose by 106,000 barrels per day to 511,000 barrels per day…but even after this week’s big inventory decrease, our gasoline supplies were 0.5% higher than last March 1st’s gasoline inventories of 250,714,000 barrels, and 2% above the five year average of our gasoline supplies for the same time of the year…

Similarly, with the decrease in our distillates production, our supplies of distillate fuels decreased for the 17th time in 23 weeks and for 32nd time in the past 48 weeks, falling by 4,008,000 barrels to 134,464,000 barrels during the week ending February 28th, after our distillates supplies had decreased by 2,115,000 barrels over the prior week….our distillates supplies fell by more this week even though the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 200,000 barrels per day to 3,919,000 barrels per day, because our exports of distillates rose by 221,000 barrels per day to 1,427,000 barrels per day while our imports of distillates fell by 52,000 barrels per day to 125,000 barrels per day….after this week’s decrease, our distillate supplies at the end of the week were 1.1% lower than the 135,986,000 barrels of distillates that we had stored on March 1st, 2019, and fell to about 7% below the five year average of distillates stocks for this time of the year…

Finally, even with those much higher oil exports, our commercial supplies of crude oil in storage rose for the twentieth time in thirty-seven weeks and for the thirty-first time in the past 52 weeks, increasing by 784,000 barrels, from 443,335,000 barrels on February 21st to 444,119,000 barrels on February 28th….but even after 6 straight increases, our crude oil inventories slipped to roughly 4% below the five-year average of crude oil supplies for this time of year, even while they remained about 34% higher than the prior 5 year (2010 – 2014) average of crude oil stocks at the end 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 28th were 1.9% below the 452,934,000 barrels of oil we had in commercial storage on March 1st of 2019, while still 4.3% above the 425,906,000 barrels of oil that we had in storage on March 2nd of 2018, while at the same time remaining 15.9% below the 520,184,000 barrels of oil we had in commercial storage on March 3rd 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 increased for the 4th time in 27 weeks over the week ending March 6th but still remains down by 26.8% from the end of 2018….Baker Hughes reported that the total count of rotary rigs running in the US increased by three rigs to 793 rigs this past week, which was still down by 234 rigs from the 1027 rigs that were in use as of the March 8th report of 2019, and 1,136 fewer rigs than the shale era high of 1,929 drilling rigs that were deployed on November 21st of 2014, the week before OPEC began to flood the global oil market in an attempt to put US shale out of business…

The number of rigs drilling for oil increased by 4 rigs to 682 oil rigs this week, which was still 152 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 decreased by 1 to 109 natural gas rigs, which was the least number of natural gas rigs active since October 21st of 2016, and hence was a 40 month low for natural gas drilling…natural gas rigs were also down by 84 gas rigs from the 193 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 increased by one rig to 23 rigs this week, with 22 of those Gulf rigs drilling in Louisiana waters and one rig drilling offshore from Texas…that was one more than the 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…with no rigs deployed off other US shores elsewhere at this time, the current Gulf of Mexico rig count is equal to the national offshore rig total, as it was the same week a year ago…however, a drilling rig also began drilling through a lake in McClain country Oklahoma this week, and with another such “inland waters” rig also running in Louisiana, there are now two “inland waters” rigs drilling in the US, up from one a year ago..

The count of active horizontal drilling rigs was unchanged at 706 horizontal rigs this week, which was still 196 fewer horizontal rigs than the 904 horizontal rigs that were in use in the US on March 8th of last year, and also well down from the record of 1372 horizontal rigs that were deployed on November 21st of 2014….at the same time, the directional rig count was up by five rigs to 51 directional rigs this week, but those were down by 16 from the 67 directional rigs that were operating during the same week of last year….on the other hand, the vertical rig count was down by two rigs to 34 vertical rigs this week, and those were also down by 22 from the 56 vertical rigs that were in use on March 8th of 2019…

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of March 6th, the second column shows the change in the number of working rigs between last week’s count (February 28th) and this week’s (March 6th) count, the third column shows last week’s February 28th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 8th of March, 2019…

In the Texas Permian basin, 3 rigs were added in Texas Oil District 8, an area that corresponds to the core Permian Delaware, while there were no changes in Texas Oil Districts 7B, 7C or 8A, the districts that encompass the Permian Midland basin…hence, with a 4 rig increase in the Permian overall, we can figure that the rig that was added in New Mexico had to drilling in the western Permian Delaware…meanwhile, the rig that was added in the Granite Wash basin was also in Texas, as Texas Oil District 10 shows a one rig increase, but the rig that was added in the Haynesville was in northwestern Louisiana, as the rig count in Texas Oil District 6 was unchanged…Louisiana also saw rig increases offshore and in the southern part of the state, where there weren’t any rigs deployed last week….meanwhile, Oklahoma’s rig count was down two with the removal of three oil rigs from the Cana Woodford and the addition of the vertical rig on the lake in McClain county…the rig pulled out of North Dakota has been drilling in the Williston basin, while the rigs pulled out of Wyoming and California, as well at the rig added in Utah, do not correspond to basins that Baker Hughes itemizes…for natural gas rigs, Baker Hughes shows one rig being added in the Haynesville, while one was removed from West Virginia’s Marcellus and another was pulled out of an “other basin” that they don’t track separately…

Ohio’s Utica Shale 4th Quarter Production Totals Released – ODNR – – During the fourth quarter of 2019, Ohio’s horizontal shale wells produced 6,803,057 barrels of oil and 684,771,042 Mcf (685 billion cubic feet) of natural gas, according to the figures released today by the Ohio Department of Natural Resources (ODNR).Compared to a year ago, oil production increased by 17.08% and natural gas production showed a 3.2% increase over the fourth quarter of 2018. The ODNR quarterly report lists 2,523 horizontal shale wells, 2,452 of which reported oil and natural gas production during the quarter. Of the wells reporting oil and natural gas results:

• • The average amount of oil produced per well was 2,774 barrels.
• • The average amount of natural gas produced per well was 279,270 Mcf.
• • The average number of third quarter days in production per well was 90.

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

Ohio natural gas producers meet amid low energy prices – Ohio’s natural gas producers are having their annual meeting in Columbus this week amid concerns about what low natural gas prices mean for their business. Industry experts say it is time for more attention on profit than on production. For the past few years, Ohio’s natural gas producers have been more focused on boosting production in eastern Ohio’s Utica shale deposits than on profit. That’s about to change, the top executive of Ohio’s biggest oil and gas producer said. “Investors are demanding that we put growth aside and manage the business with the idea of making profit,” Jeff Fisher, the CEO of Ascent Resources, told those attending the annual meeting of the Ohio Oil & Gas Association this week in Columbus. Producers have driven the heightened focus on the bottom line, Fisher said; they have done such a good job of producing gas that prices have tumbled this year. The warm winter has contributed as well. “Demand growth has been phenomenal,” he said. “Supply has been a little more phenomenal, and that’s a recipe for not very good returns.” Putting more focus on profit is a good thing for an industry that needs discipline, he said. Already, some of that discipline might be showing up in the state’s production numbers. Natural gas production from Utica shale rose by just 3.2% to 685 billion cubic feet in the final three months of 2019 compared with the same period of 2018, according to new Ohio Department of Natural Resources data.

Gulfport Announces Steep Capex Cuts, Forecasts Production Decline – Gulfport Energy Corp. plans to slash spending to the bone this year and cut annual production in the process as it wrestles with low natural gas prices and a restive shareholder pushing to shake up the board. The company intends to cut year/year capital expenditures (capex) by 50% to a range of $285 million to $310 million, and is guiding for 2020 production of 1.1-1.5 Bcfe/d. That compares to the $602.5 million in capex spent in 2019, when it also cut spending and kept production volumes flat at 1.37 Bcfe/d.The bulk of Gulfport’s volumes come from the Utica Shale in Ohio. It also has operations in the South Central Oklahoma Oil Province (aka SCOOP). All of Appalachia’s leading operators have announced plans to scale back this year in response to historically low gas prices, but Gulfport’s spending plans are among the lowest. Management said the 2020 program would generate positive free cash flow at current strip prices. The company laid out its 2020 plans in its year-end earnings release. Just days later, the company’s largest stockholder, Firefly Value Partners, which holds 13.1% of Gulfport’s shares, nominated two candidates for the board. Firefly has been pushing for change at the company since last year, voicing its dissatisfaction with management’s efforts to create more value. Gulfport responded by noting that five of its eight directors have been replaced in the last three years. Gulfport dumped more than $170 million of noncore assets in 2019 and reduced debt by $50 million through discounted bond repurchases as it has worked to simplify its portfolio and control costs at a time when investors have pressured oil and gas producers for stronger returns. The company plans to run one operated rig in the Utica this year, where it intends to turn 18 wells to sales. It also plans to run 1.5 operated rigs in the SCOOP, where it plans to turn four wells to sales. The Utica accounted for 1.1 Bcfe/d of 2019 production, while the SCOOP accounted for 274 MMcfe/d. Gulfport produced 1.35 Bcfe/d in the fourth quarter, compared to 1.4 Bcfe/d in the year-ago period. Average prices also slipped during the quarter to $2.03/Mcfe, compared to $3.45 in 4Q2018. They were down for the full year too at $2.27, compared to $2.98 in 2018.

Utica Shale Academy students head south – Students attending the Utica Shale Academy’s Columbiana satellite branch will now be heading to Southern Local. The board of the Utica Shale Academy held a special meeting on Friday afternoon and following a lengthy executive session passed a resolution to close the Columbiana satellite branch, which opened in 2015. Bill Watson, director of the Utica Shale Academy said this will mean as of Monday, the 17 students who were attending the Columbiana facility will be at Southern. The students will be brought by CARTS and Watson said their coursework will remain the same. The resolution also allows for the possible elimination of an instructor, who will be obsolete due to combining the classroom. Watson said the move will allow the Utica Shale Academy not to be as spread out and allow them to consider moving in other directions by possibly adding other curriculum paths. There were 67 students total at the two locations of Utica Shale Academy for the 2019-20 school year. While allowing the students to obtain their high school diploma, the community school currently focuses on the skills students need to know to work in the oil and gas industry.

Ohio Ethane Cracker Decision Expected Within Months – The developers of a proposed world-scale ethane cracker in southeastern Ohio expect to reach a final investment decision (FID) on the multibillion-dollar project during the first half of this year.In a written statement Friday on the project website, PTT Global Chemical America (PTTGC) noted that site preparation, engineering and design work have been underway since mid-2019 to prepare for the possible petrochemical complex it would develop with Daelim Chemical USA in Belmont County, Ohio. The firm noted that contractors working for the “PTTDLM” co-venturers have completed the first phase of work at the Mead Township site, located along the Ohio River.PTTDLM added that site activity will slow down over the next two to three months as it proceeds to the next pre-FID phase: finalizing project financing and supply agreements.According to the project website, the proposed ethane cracker would enjoy access to feedstocks from the Marcellus and Utica shale formations and links to major highway, rail, pipeline and port infrastructure. PTTGC reportedly has already spent more than $100 million on detailed front-end engineering design. The PTTDLM complex would be capable of producing 1.5 metric tons per annum of ethylene and its derivative, the website notes, adding the project has already secured air and waterways discharge permits from the Ohio Environmental Protection Agency.

Senate committee passes bill with tax credits for petrochemical industry – – A Senate committee approved two bills representing tax credits aimed at West Virginia’s petrochemical industry. HB 4421, called the Natural Gas Liquids Economic Development Act, would provide a credit to businesses that store or transfer natural gas. The goal of the bill is to attract an ethane cracker plant or storage hub.HB 4019, called the Downstream Natural Gas Manufacturing Investment Tax Credit Act of 2020, would allow eligible taxpayers to take a credit against the portion of state income taxes that come from the taxpayer’s investment in a new or expanded downstream natural gas manufacturing facility provided it creates new jobs.The Senate’s Economic Development Committee considered and passed each bill during a session on Saturday. Each bill also has a reference to the Senate Finance Committee.In committee discussion, Senator Eric Tarr, R-Putnam, said incentives already exist but are so stringent they’re hardly used.Senator Bill Ihlenfeld, D-Ohio, wondered what incentives are offered by surrounding, natural gas-producing states.“It’s clear we’re trying to make West Virginia is competitive with our surrounding states when it comes to this kind of economic development,” Ihlenfeld said.Senator Mike Romano, D-Harrison, said he would like to better compare the taxes that apply to natural gas in West Virginia to those in other states.“We do charge a higher severance tax than other states, but there’s all kinds of other taxes on oil and gas production,” he said. For example, he said, Pennsylvania has a lower severance tax but also charges an impact fee.He requested a study resolution to summarize oil and gas taxes in comparison to other states. Tarr and Senator Rollan Roberts, R-Raleigh, said that would be redundant to information requested in previous legislation.Romano’s motion resulted in a 6-6 tie, which defeated it.But the committee’s chairman, Senator Chandler Swope, R-Mercer, had voted with Romano and said he had been wondering about the same issue. Swope said he has already been trying to compile the information.One way or another, Swope said he would get the tax comparison information and share it.

Rally at WV State Capitol Achieves Awareness Goal – NO PTTG or Ethane Hub – Residents from Marshall and Ohio counties, WV, and Belmont County, OH, made a three-hour trek to the WV State Capitol today to meet with legislators to speak about their opposition to an ethane cracker plant that PTT Global Chemical wants to build in Dilles Bottom, OH, across from Moundsville, WV. The cracker plant would impact the air quality of Moundsville and Wheeling, WV, which already have poor air quality. The residents informed lawmakers of their concerns about the PTTG cracker, which is just one component of many that would be part of the Appalachian Storage and Trading Hub (ASH). This is an umbrella name for a proposed petrochemical mega-complex, which primarily would use fracked natural gas liquids to make plastics in the Ohio and Kanawha River valleys. One similar facility, the Shell ethane cracker, is already under construction in Monaca, PA. If built, the petrochemical hub would span more than 400 miles along the rivers. Infrastructure related to the hub could reach into a 500-square-mile area in more than 50 counties in West Virginia, Ohio, Pennsylvania, and Kentucky. The infrastructure would include cracker plants and other types of refineries, underground storage facilities, and thousands of miles of pipelines. The feedstock for the petrochemical factories would come from a massive increase in regional fracking. The residents noted that this proposed petrochemical buildout would exacerbate air and water pollution and threaten the health of the five million residents who depend on the Ohio River as a public water source. West Virginia already has a history of petrochemical-related disasters, including C8 pollution and the 2014 MCHM water crisis. Nonetheless, during the 2020 Legislative Session, many legislators have pushed a pro-petrochemical agenda, often referring to the proposed hub as a “petrochemical renaissance.”

Senate passes investment fund, tax credits for petrochemical industry – – With no discussion, the state Senate overwhelmingly passed a bill that could create a sovereign investment fund for West Virginia.House Bill 4001, creating the West Virginia Impact Fund, passed the Senate 30-3 with one absence.The bill was a priority of House Speaker Roger Hanshaw, who was pleased. “I thank my colleagues in the Senate for their thorough consideration and overwhelming vote to support this bill that will truly revolutionize how we advance and attract economic development in our state,” stated Hanshaw, R-Clay. The same bill passed the House of Delegates on Feb. 21 after two hours of floor discussion and questions.The bill would establish a Mountaineer Impact Fund so West Virginia could serve as an official partner in investment deals.As envisioned, the finances would come from private investors or other sovereign investment funds with minimal West Virginia public dollars – if any – being involved.Major investors might include big corporations, combinations of private investors or the sovereign wealth funds of other countries.West Virginia could be the controlling partner, essentially the sponsor of the projects. In other words, West Virginia would be endorsing the investment with the state’s name. Guiding those decisions would be a board led by an executive director who would need to be hired. An investment committee including the governor and five appointees confirmed by the Senate would also be established. And the state Commerce Secretary would also be on board.

Petrochemical town hall near Pittsburgh spotlights pollution, health worries -Subsidies for the petrochemical industry may bring a boost in construction jobs but could have a negative effect on Pennsylvania’s air quality and public health, according to speakers at a town hall held near Pittsburgh Wednesday. The panel was put together by state Rep. Sara Innamorato, a Democrat from Pittsburgh. Innamorato voted against HB 1100, which passed the House and Senate last month, and would give millions of dollars in tax breaks for companies to build new chemical plants using natural gas from Pennsylvania.“We can be against corporate giveaways like HB 1100 and also be for good union jobs, family-sustaining jobs,” Innamorato said. The House and Senate passed HB 1100 with veto-proof majorities in February. Gov. Wolf has vowed to veto the bill, but it has yet to arrive at his desk. Innamorato said she held the forum for the public to hear from people other than just business and trade unions that would benefit from the law. “Those include impacted residents that live outside of Allegheny County, those include economists that have been studying this issue. It includes medical professionals who know what the public health impacts can be,” she said. “It’s a dialogue that we’re going to have. This is the first conversation that our office facilitated with the public, and it’s not going to be the last.” Shell is building a multi-billion dollar petrochemical plant in Beaver County to turn the region’s ethane, a natural gas byproduct, into plastic. That plant is the beneficiary of a $1.65 billion state tax break. ExxonMobil may be looking to build another plant in the region, according to recent reports.

Bethlehem Commissioners voice displeasure with amended PennEast plan –A proposal from PennEast Pipeline amending plans for its natural gas line is now being met with opposition from the Bethlehem Township Board of Commissioners. On Monday, commissioners authorized Township Manager Doug Bruce along with solicitor Lisa Ferrera to draft a letter to Federal Energy Regulatory Commission (FERC) opposing PennEast’s new plans which call for a two-phase project. PennEast’s revised plan calls for a natural gas line connecting through Pennsylvania and New Jersey. Phase one of that plan includes the construction of a 68-mile natural gas line from another connection in Luzerne County that would terminate on Church Road and Route 33 in Bethlehem Township. According to a January press release from PennEast, “the new interconnections, which will be located south of Route 22 and Route 33, will be constructed on property already owned by PennEast Pipeline.” Construction would be complete by November 2021. But township officials say, that plan no longer calls for an underground pipeline. Instead, it calls for a metering and regulating mouth station. “This really seems to be a new application by separating the two phases,” Commissioner John Gallagher said. Commissioners say they were not aware of the amended application to FERC that has a public input deadline of March 4. According to Commissioner Malissa Davis, the newest proposal will connect the pipeline to the Adelphia Gateway and the Columbia Gas Transmission pipelines. In May 2019, the township approved a right-of-way for PennEast to construct 1,900 feet of pipeline through the municipality. The approval required them to construct the pipeline at least four feet underground and moved about 100 feet west of Hope Ridge Drive. Also, the township required that additional trees in the area be constructed and increase the number of pipeline inspections during and after construction. Gallagher said he is concerned because the newest proposal will be placed near homes and Farmersville Elementary School and Notre Dame High School. “The thing that concerned me is that the main difference was that part of the pipeline was just passing through the township,” he said. “Now, they are going to have a facility.” “It’s a far bigger project than we thought we were getting,” Gallagher said. “It’s bad enough to have the pipe,” Commissioner John Merhottein said.

How to Gain Approval for an Out-Dated Leaking Pipeline in Penna. – 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. Sunoco replaced an 83-foot section of pipe. The pipeline, built by Atlantic Refining in 1931 to deliver motor fuel and heating oil from its Philadelphia refinery to Western Pennsylvania, was acquired by Sunoco in 1988. Sunoco Pipeline in 2014 patched up and converted the pipeline, now renamed Mariner East, to carry gas liquids from the Marcellus Shale fields to a terminal in Marcus Hook. Sunoco, a subsidiary of Energy Transfer LP of Dallas, is building two new Mariner East pipelines along roughly the same path as the older pipeline to carry additional gas liquids to its Delaware County terminal. The contentious project, much delayed by construction mishaps, is nearing completion this year. But it is still being litigated in several venues, including the PUC. The agreement allows Sunoco to recommend three independent experts to conduct the remaining life study, from which the PUC’s Bureau of Investigation and Enforcement will choose one. The remaining life study, first publicly suggested by Gov. Tom Wolf a year ago, will assess the longevity of the Mariner East 1, including risks.

‘We need to make a profit first’: What’s at stake in proposed gas tax credit for Pa. –For chemical industry executive Michel Goldschneider, the decision on whether to build a new plant in the Keystone State is all about the bottom line.“I don’t know if you’ve ever worked in the capitalist system, but it’s about dollars and cents,” Goldschneider, the CEO of Connecticut-based Elis Energy told the Capital-Star recently.Goldschneider’s company is looking to build its first plant to produce methanol, an alternative fuel that can be burned to power cars and ships. Breaking ground in the Keystone States already has its perks. The state is home to an abundant supply of natural gas and it’s close to the markets for methanol. There’s also a family connection. Goldschneider’s wife and business partner is a Hazleton native. But the final decision could come down to the success or failure of a proposed $22 million annual tax credit now pending before the General Assembly.Goldschneider’s decision is the scenario lawmakers imagined when they passed the credit last month. Part of a natural gas-based energy plan from House Republicans, it has garnered bipartisan support, buoyed by the backing of Pennsylvania’s construction trade unions. The proposal sponsored by Rep. Aaron Kaufer, R-Luzerne, passed the House and Senatewith a veto-proof majority Feb. 4. But Gov. Tom Wolf has promised to veto the bill, saying incentives should be considered on a case-by-case basis. The veto promise has drawn stern words from state trade unions. “Let’s call a veto … what it really is – an attack on Pennsylvania’s blue-collar workers,” Tony Seiwell, Business Manager of the Eastern Pennsylvania Laborers’ District Council, said in a press release last month. Republicans in the General Assembly have meanwhile held off from sending the bill to Wolf’s desk, which could buy time to garner support for a potential override.

Driller pulls out of talks in $5M suit — One of Pennsylvania’s largest gas drillers pulled out of settlement talks aimed at resolving its $5 million lawsuit against a resident whose drinking water was contaminated and who has spent years bashing the energy industry.Houston-based Cabot Oil & Gas Corp. sued Dimock resident Ray Kemble and his former lawyers in 2017, claiming they tried to extort the company through frivolous litigation. Cabot also claims Kemble violated a 2012 settlement agreement by repeatedly “spouting lies” about the company in public.Kemble, a high-profile fracking opponent who has traveled the country talking about his experiences with the gas industry, charges that Cabot is trying to shut him up.The company, which has drilled hundreds of wells in the Marcellus Shale natural gas formation, pulled out of a settlement conference scheduled for Friday because the parties have made “no progress” toward resolution, Cabot said in a legal filing.Kemble’s former lawyers, in turn, accused the driller of failing to negotiate in good faith, calling its withdrawal from talks “an indication that this action was not intended to seek compensatory damages, but instead an attempt to harass, embarrass and annoy the defendants.”

Criminal investigations target shale gas industry – Pennsylvania Attorney General Josh Shapiro said he is expending significant investigative resources in pursuit of more than a dozen criminal cases involving the shale gas industry. In a phone interview Tuesday afternoon, Mr. Shapiro cited the protections for clean air and pure water in the state Constitution as justifications for pursuing the criminal cases. “I can confirm that my office has more than a dozen ongoing criminal investigations into fracking and pipeline companies,” Mr. Shapiro said. “You can expect some will result in criminal charges in the near future.” He said Pennsylvania is one of two states to have protections for environmental values in its Constitution, and he takes enforcement of those values seriously. As an example he noted the criminal charges filed in November against Inflection Energy, a Denver gas drilling company, and Double D Construction of Montoursville, Lycoming County, for the 2017 discharge of 63,000 gallons of treated brine water into a tributary of Loyalsock Creek. “We are putting enormous resources of the attorney general’s office into these investigations,” he said. “I am deeply concerned with protecting our constitutional rights to clean air and pure water, and anything that harms that gets our attention.” David Spigelmyer, president of the Marcellus Shale Coalition, a Robinson-based trade organization representing the shale gas industry, said he couldn’t comment on the “broad, ongoing investigations,” but added that “protecting and enhancing public health, safety and our shared environment comes first.” . Mr. Shapiro declined to talk about or even confirm the existence of a criminal grand jury focused on environmental crimes that the attorney general’s office has operated. However the Pittsburgh Post-Gazette reported in January 2019 that based on information from multiple independent sources a state investigative grand jury was taking testimony in Pittsburgh. Two Washington County residents, June Chappel of Hopewell, and Stephanie Hallowich, a one-time vocal critic of the shale gas drilling around her then home in Mount Pleasant, testified at the grand jury early in 2019. Also in January, the newspaper reported that in August 2018 the attorney general’s office had contacted attorneys in a Washington County civil case involving alleged problems at a shale gas operation that it had “assumed jurisdiction over several criminal investigations involving environmental crimes in Washington County,” and one of those investigations “involves your respective clients.” In that civil case, Stacey Haney and her neighbors in Amwell claimed toxic spills, leaks and air pollutants at Range Resources Appalachia LLC’s Yeager shale gas well had damaged their health, and that the state Department of Environmental Protection faked and reported incomplete air test results that under-reported pollution levels at the well site and nearby homes.

US natural gas futures edge up on decline in output – US natural gas futures edged up for a third day in a row on Wednesday due to a slight decline in output, despite weather forecasts confirming the previous warmer-than-normal forecast for the next two weeks. After rising about 7% earlier this week, front-month gas futures for April delivery on the New York Mercantile Exchange rose 2.7 cents, or 1.5%, to settle at $1.827 per million British thermal units (mmBtu). That is the first time the front-month increased for three days in a row since early January. Despite this week’s gains, gas prices were still down 37% since hitting an eight-month high of $2.905 per mmBtu in early November because record production and mild winter weather enabled utilities to leave more gas in storage, making fuel shortages and price spikes unlikely. In Texas, next-day gas prices at the Waha hub in the Permian basin remained in negative territory for a second day in a row for the first time since August as pipeline constraints returned to the region and mild weather cut heating demand. Gas output in the US Lower 48 states eased to 93.5 billion cubic feet per day (bcfd) on Tuesday from 94.0 bcfd on Monday, according to Refinitiv. That compares with an average of 94.1 bcfd last week and a daily record high of 96.6 bcfd on November 30. With the coming of spring-like weather, Refinitiv, a data provider, projected average demand in the Lower 48 states, including exports, would ease from 109.2 bcfd this week to 105.0 bcfd next week. That is similar to Refinitiv’s forecast on Tuesday. The amount of gas flowing to US LNG export plants, meanwhile, fell to a seven-week low of 7.0 bcfd on Tuesday due mostly to a decline at Cheniere Energy Inc’s Sabine Pass in Louisiana, down from 7.9 bcfd on Monday, according to Refinitiv.

US working natural gas in underground storage decreases by 109 Bcf: EIA | S&P Global Platts – US working gas stocks fell by 109 Bcf last week, likely marking the final triple-digit draw of the season, as volumes surge to nearly 50% more gas in storage than this time last year. Storage inventories fell to 2.091 Tcf for the week ended February 28, the US Energy Information Administration reported Thursday morning. The pull was slightly more than an S&P Global Platts’ survey of analysts calling for a 105 Bcf withdrawal. It was less than the 152 Bcf pull reported during the corresponding week in 2019 but more than the five-year average draw of 106 Bcf, according to EIA data. Storage volumes now stand 680 Bcf, or 48%, more than the year-ago level of 1.411 Tcf and 176 Bcf, or 9%, more than the five-year average of 1.915 Tcf. US working gas stocks have reported stronger than average declines for most of February, but warmer temperatures for the last week of month saw residential and commercial demand slashed 7.4 Bcf/d, according to S&P Global Platts Analytics. US-level, population-weighted temperatures increased 3 degrees week over week, led by the Midwest, which gained 8 degrees week over week.The NYMEX Henry Hub April contract slipped 1 cent to $1.817/MMBtu in trading following the release of the weekly storage report. The entire 12-month contract strip edged lower by about 3 cents this morning to an average $2.13, with much of the sell-off weighted towards the front of the curve. With winter officially in the books and April taking the prompt month position, the next ten months are each priced higher than the one before, which puts the price of gas higher in October than the higher-demand months of July and August.Platts Analytics’ supply and demand model currently expects a 40 Bcf draw compared to the five-year average pull of 99 Bcf for the week ending March 6. This would further expand the storage surplus with only about three more weeks of withdrawals remaining before the flip to net injections. Demand once again took a tumble, averaging 102 Bcf/d this week. Notably, the Northeast and Midwest have not been the largest contributors to the drop, and instead the Southeast and Texas regions are driving significant losses in demand, falling by 2.2 Bcf/d and 1.5 Bcf/d, respectively, on a combination of LNG feedgas losses, joined by lower power and residential and commercial as well. Upstream, supplies have also softened, falling 0.5 Bcf/d compared with the week prior, after a slight increase in LNG sendout was outdone by a more than 0.6 Bcf/d drop in Canadian imports and a 0.1 Bcf/d drop in onshore production.

US natural gas falls on lower heating demand — US natural gas futures on Thursday fell on forecasts for warmer weather and lower heating demand over the next two weeks, despite an increase in liquefied natural gas (LNG) exports and a report showing a near-normal weekly storage draw. The US Energy Information Administration (EIA) said utilities pulled 109 billion cubic feet (bcf) of gas from storage during the week ended February 28. That was in line with the 108-bcf draw analysts forecast in a Reuters poll and compares with a decline of 152 bcf during the same week last year and a five-year (2015-19) average reduction of 106 bcf for the period. The decrease for the week ended February 28 cut stockpiles to 2.091 trillion cubic feet (tcf), 9.2% above the five-year average of 1.915 tcf for this time of year. After rising over 8% earlier this week, front-month gas futures for April delivery on the New York Mercantile Exchange fell 5.5 cents, or 3.0%, to settle at $1.772 per million British thermal units. Despite gains earlier this week, gas prices were still down 39% since hitting an eight-month high of $2.905 per mmBtu in early November because record production and mild winter weather enabled utilities to leave more gas in storage, making fuel shortages and price spikes unlikely. The amount of gas flowing to US LNG export plants, meanwhile, was on track to rise from 7.3 bcfd on Wednesday to 7.7 bcfd on Thursday, according to preliminary data from Refinitiv, as gas flow to Cheniere Energy Inc’s Sabine Pass facility in Louisiana increases as fog cleared and vessels started to enter the terminal for the first time since Sunday. Traders are watching gas flows to US LNG export plants for declines after customers canceled a couple of cargoes for April as low prices in Europe and Asia – because of record-high storage in Europe and lower demand in China due to the coronavirus – made it uneconomical for some European customers to lift cargoes.

Democrats could field an anti-fracking candidate in 2020. Can they win in Pennsylvania? – On the site of what will be Shell’s multibillion-dollar petrochemical plant, 6,000 union workers are putting together an ethane cracker, which will turn a natural gas byproduct into plastic. “Right now, the biggest trades here are the operating engineers and steamfitters, because a lot of the piping work is being done now,” said Jeff Nobers, executive director of the Builders Guild of Western Pennsylvania, which includes many of the unions working on the site. “There’s a lot of overtime. So you have people making well over six figures.” Nobers says if Democrats nominate someone who wants to ban fracking, they’d have a tough time winning over some of his members. Presidential candidates Sens. Bernie Sanders and Elizabeth Warren have both said they want to move away from fossil fuels, and they support a ban on fracking for natural gas or oil. Though natural gas is pushing dirtier coal off the electric grid, scientists warn we need to phase out all carbon emissions from fossil fuels in the next few decades. And fracking can release the powerful greenhouse gas methane. Some political observers think an anti-fracking message could hurt a candidate in Pennsylvania, where 30,000 people work in oil and gas, according to the U.S. Department of Labor, and thousands more work in related industries. “Do you lose some moderate Democrats or independents who have interest in the natural gas industry if you call for shutting it down?” said Chris Borick, a political scientist at Muhlenberg College who’s studied public opinion on the topic. “I think the answer is probably ‘Yes.’”Recent polls find Pennsylvania voters are roughly split on whether to ban fracking.A January Franklin & Marshall College poll found that 48 percent of Pennsylvania voters favored a ban on fracking, while 39 percent were opposed. A Morning Call/Muhlenberg College poll conducted in February found 42 percent of voters in the state opposed a fracking ban, with 38 percent in favor.That same poll found Sanders leading Trump 49-46 percent and Warren tied with Trump 47-47 percent in hypothetical head-to-head matchups.The Franklin & Marshall poll found support for a ban was strongest in the state’s two big cities, Philadelphia and Pittsburgh.

Chevron offering U.S. workers buyouts to trim staffing: sources – (Reuters) – Chevron Corp is offering buyouts to reduce its U.S. oil exploration and production workforce, three sources told Reuters, as the oil major moves to cut costs in the face of sharply lower oil and gas prices. The No. 2 U.S. oil producer decided to reduce staff after reviewing operations late last year as energy prices fell, the sources said. Chevron confirmed that it was offering buyouts to workers in its shale gas business in the eastern United States but did not comment on any other U.S. job cuts. Other oil and gas producers and service companies have begun cutting workers as prices have dived on soaring production and tepid demand, which has been made worse by the coronavirus outbreak. One of the sources said some employees who accept Chevron’s buyout offer could remain until October. Another source said the company hopes to open spots for people who currently work for its shale gas operation in the Appalachian region of the United States, which is on the auction block. Chevron notified Pennsylvania state officials last month that it planned to cut up to 320 jobs in the state, which includes the shale gas business.

Hearing on LNG Terminal Plan for South Jersey Will Give Critics Another Chance to Object – The Delaware River Basin Commission has set up a quasi-judicial hearing on a controversial plan to build New Jersey’s first liquefied natural gas export terminal on the Delaware River, giving opponents a high-profile opportunity to reargue their case almost a year after the project was approved by the interstate water regulator.On Monday, the DRBC said the hearing, due to start on April 15 in Mercerville, will include testimony by the project’s developer, Delaware River Partners (DRP) as well as commission staff, and the environmental group Delaware Riverkeeper Network (DRN), which opposes the project and called last July for a rehearing. “This announcement is a stunning admission that the DRBC failed to provide a full or fair opportunity for public comment before approving the Gibbstown Logistics LNG export facility,” said Delaware Riverkeeper Network leader Maya van Rossum, in a statement.The “adjudicatory hearing,” a trial-like proceeding that will include direct- and cross-examination of witnesses by all sides, will take place before a hearing officer – an official from the Pennsylvania Department of State – who will later recommend to the commission whether to uphold or reject its approval of the project last June. The commission will be under no obligation to accept the recommendation. Some seats will be made available for the public to attend the hearing but the public will not be allowed to speak, the DRBC said. Delaware Riverkeeper Network previously argued that the commission didn’t allow nearly enough time for the public to comment on the proposal, which would build a 43-feet deep berth on a former DuPont site at Gibbstown on the Delaware River in Gloucester County. The project would make space for two oceangoing tankers to ship LNG that would be carried by rail from the gas-rich reserves of the Marcellus Shale in northeastern Pennsylvania.

Trump vows to continue fight against New York’s rejection of new pipelines – – New York’s efforts to block new natural-gas pipelines are “unfair to the rest of the country,” President Donald Trump said Tuesday. The president’s comments come just days after the gas company Williams LP scrapped plans to build the 124-mile long Constitution pipeline that would have run through the Southern Tier to just outside of Albany. “We’re unable to build a pipeline through New York state, where they’d love the jobs of doing the pipeline. And because of that, New England has very, very high energy prices,” Trump said while speaking to the National Association of Counties in Washington on Tuesday. New York has moved to block a number of natural-gas pipelines over environmental concerns in recent years, including the Constitution pipeline and the so-called Williams pipeline that would bring natural gas into the New York City-area. Trump vowed to fight back, arguing the state’s decision is driving up energy costs and impacting neighboring states. “And we’re fighting them very hard, and I think we’ll be successful,” he said. “But if they’d allow a pipeline to go through, we would cut the prices of energy down by half, and even more so than that. It’s a terrible thing. It’s a very unfair thing to the rest of the country.”

Oil spill reported near Fairhaven Shipyard – Cleanup crews responded to an oil spill Sunday morning near the Fairhaven Shipyard, but authorities say they don’t know what caused it. At 7:22 a.m. the Fairhaven Fire Department received notification of an oil spill in the area of 50 Fort Street, the address of the Fairhaven Shipyard and Marina. On arrival, “they encountered a large oil spill of unknown quantity but estimated to be over 200 gallons,” according to a statement from Lt. Paul Correia, public information officer for the fire department. The spill was “predominately located from Fairhaven Shipyard north to Linberg Marine,” Correia wrote. The Fairhaven Harbormaster responded along with the Massachusetts Department of Environmental Protection and the U.S. Coast Guard. The fire department and harbormaster deployed absorbent and sweep booms to collect “the initial product that could be recovered.” MassDEP contacted the Frank Corporation, a New Bedford-based environmental cleanup firm, to complete the mitigation work. The work by Frank Corp. was overseen by the Coast Guard. “The source was unknown at this time,” Correia wrote.

Falmouth company fined for oil spill prevention violations – A Falmouth company has been ordered to pay a penalty after a settlement with the Environmental Protection Agency. Lawrence Lynch Corp. in Falmouth must pay $3,000 in penalties and correct violations of oil pollution prevention regulations under the federal Clean Water Act, the EPA announced Wednesday. The EPA and Lawrence Lynch Corp agreed to the settlement, along with a company in Dedham that also will pay $3,000 in penalties. The EPA investigated Lawrence Lynch on Sept. 10 and found noncompliance with the regulations, said John Senn, public affairs specialist with EPA. The facility’s “spill prevention control and countermeasure” plan was inadequate and needed updating, and there was inadequate containment in one area of the facility, he said. Lawrence Lynch, a construction company located at 396 Gifford St., has large enough oil storage capacity that it is required to put in place plans to prevent spills under federal regulations, according to the statement. Lawrence Lynch Corp. agreed to submit an amended spill prevention plan that addresses those deficiencies and plans to construct any necessary containment, such as asphalt cement tanks.

Gas pipelines part of the fight against climate change, Williams’ Armstrong says – Governments in the U.S. Northeast have denied pipeline permits and moved to eliminate natural gas use in the New York City and Boston areas in an effort to get away from the fossil fuels that contribute to global warming. But to achieve immediate emissions reductions, Williams Cos. Inc.’s CEO said the region needs to embrace gas pipelines. “We have to find a way to continue to utilize natural gas,” the pipeline company’s President, CEO and Director Alan Armstrong told S&P Global Market Intelligence. Natural gas fuels the majority of power generation in the Northeast, whereas wind and solar provide only a fraction, and the region keeps seeing demand increase that the renewables have not matched, Armstrong said. With roughly a quarter of heating in New York state coming from heating oil and refinery gas, which have heavier content than natural gas, the state still has room to lower emissions by switching in natural gas, Armstrong said. “Why we wouldn’t take advantage of that, and why we wouldn’t build infrastructure to take advantage of that, makes no sense to me,” the CEO said. “Other than the fact that it has become politically popular – and almost religious – to say ‘no fossil fuels’ despite the amount of emissions reductions” that could be achieved by switching to gas. On Feb. 21, Williams was forced to cancel its Constitution Pipeline Co. LLC project between the Marcellus Shale in Pennsylvania and pipeline connections in New York after years of fighting over permits with New York and environmental groups, even though the pipe had received approval from the Federal Energy Regulatory Commission. The company has another pipeline project near New York City, the Northeast Supply Enhancement project, or NESE, which New York has also opposed. For Williams, the economic situation around the Constitution pipeline changed in the years that it was in limbo, as New York made things harder and states and customers to the south of the Marcellus Shale asked for gas. “We developed three other [larger] projects while Constitution was being blocked,” Armstrong told attendees. “So the Southeast states will enjoy that low-cost fuel supply. The Northeast states and New England will continue to be deprived of it and pay three to four times more for their gas supply.”

How a dirt path is challenging a 600-mile pipeline – I live in Appalachia, and on Sunday mornings I hike the Appalachian Trail across the mountains I call home. It is my church. I drink from its springs and rest in the shade of its ancient forests. For decades, the trail has been my refuge. I have run for miles through tunnels of rhododendron, crossed paths with bears and camped with my children beneath starry skies.A few years ago, however, the 600-mile Atlantic Coast Pipeline broke ground, and crews began clear-cutting a scar across the mountains to move fracked natural gas from West Virginia to customers in Virginia and North Carolina. On my trail treks in Virginia, I watched the bulldozers creep closer.Then suddenly, on a crisp fall morning in 2018, the bulldozers stopped. The U.S. Court of Appeals for the Fourth Circuit vacated a permit allowing the pipeline to cross the trail deep beneath the ground. The Supreme Court heard arguments last Monday on what will happen to the $8 billion project. It’s a showdown between some of the country’s leading fossil fuel utilities and an environmental group, the Cowpasture River Preservation Association.The outcome could upend pipeline construction here and elsewhere in the country, should a planned pipeline cross one of the nation’s 11 national scenic trails.Stretching 2,192 miles from Maine to Georgia, the Appalachian National Scenic Trail is the longest and most popular hiking-only footpath in the world. Quite unexpectedly, it also has become a formidable and possibly final dirt line of defense against the Atlantic Coast Pipeline.The Supreme Court case boils down to this: Energy companies received a permit from the U.S. Forest Service allowing pipeline construction through national forests that the agency oversees. But the Appalachian Trail is a unit of the national park system, which the Forest Service does not manage. The National Park Service does. Moreover, federal law prohibits any federal agency from authorizing a pipeline in the national park system. The Atlantic Coast Pipeline won’t be the only natural gas pipeline affected by this case. The Mountain Valley Pipeline, already under construction, would cross underneath the trail and then parallel for some 90 miles, with deep cuts visible in the wooded mountainside. At least 10 other proposed pipelines also plan to cross the trail.

This Pipeline Case Could Gut 100 Years of Safeguards for Federal Parks – When is a hiking trail not the same as the land it sits on? That’s a question before the Supreme Court, which last week heard oral arguments concerning the siting of the Atlantic Coast Pipeline, a $5.1 billion project that, if completed, would transport over a billion cubic feet of gas each day from West Virginia to North Carolina. As proposed, the 3-foot diameter Atlantic Coast Pipeline, co-owned by Dominion and Duke Energies, would span approximately 600 miles, 21 miles of which would cross the Monongahela and George Washington National Forests. This route would also require the pipeline to cross the 2,100-mile Appalachian National Scenic Trail, which bisects much of the George Washington Forest. Under the proposal approved by the U.S. Forest Service, the pipeline would cross the trail by way of a half-mile-long tunnel 600 feet below the trail. Oral arguments on February 24 asked the court whether the Forest Service had the authority to grant this right-of-way access for the pipeline. At issue is the federal Mineral Leasing Act. Passed by Congress in 1920 as a response to the Teapot Dome scandal, the Mineral Leasing Act was intended to protect federal lands from private interests and to ensure fair use of the natural resources those lands contain. The act also stipulates that lands administered by the National Park Service are exempt from uses such as mineral exploration, drilling and the locating of pipelines. Environmental groups fear that a ruling in favor of the energy companies behind the project could ultimately open up millions of acres of federal land – national monuments and historic places, wild and scenic rivers and other wilderness areas – to uses ranging from energy exploration and timber harvesting to highway construction and mining. Doing so, they say, would upend over a century of what was once considered inviolable protection.

Environmental groups will hold meeting on new gas pipelines in Fauquier County – Piedmont Environmental Council will co-host a community information session about two natural gas projects planned for Fauquier and Prince William counties Wednesday, March 4, at 6:30 p.m. at its office in Warrenton. The organization is partnering with environmental groups Food and Water Watch, the Virginia chapter of the Sierra Club and Fauquier Climate Change Group for the event. Food and Water Watch organizer Jolene Mafnas will be presenting information about these projects at the meeting. Piedmont Environmental Council Communications Advisor Cindy Sabato said the goal of the meeting is to give county residents the opportunity to learn more about what’s being proposed. The construction of an 8-mile natural gas pipeline expansion, called the Southeastern Trail Expansion project, is already underway in Fauquier and Prince William counties. The project will increase the capacity of the existing Transcontinental Pipeline, which runs from Texas to New York City. The new pipeline route runs adjacent to Va. 28 in Fauquier and Prince William. The project includes upgrades to an existing natural gas compressor station in Manassas, Virginia in addition to the new section of pipeline. Work on the project began in early February and is expected to be completed and in service by November 2020. A separate natural gas pipeline project in Fauquier and Prince William is in the early stages of planning. Virginia Natural Gas pipeline is aiming to connect its existing pipeline to the expanded Transco pipeline in Prince William County to bring natural gas to a new power plant in Charles City County, outside Richmond. The new section of pipeline will add 9.5 miles of pipeline that will stretch from its existing pipeline in Fauquier County to the Transco pipeline in Prince William County, just outside Nokesville. The new line includes plans for a new compressor station in the Nokesville area.

Jim Beam Wanted More Gas, But Didn’t Want To Pay For Bullitt Pipeline – The makers of Jim Beam bourbon asked Louisville Gas and Electric to supply additional natural gas to expand operations at its flagship site in Clermont, but didn’t want to pay for a new gas pipeline, according to subpoenaed records from the bourbon maker. A year later Louisville Gas and Electric went before utility regulators to ask for ratepayers to shoulder an estimated $27.6 million for the 12-mile-long natural gas pipeline. Jim Beam was not mentioned in that request. The distillery’s role in the pipeline saga appeared in an eminent domain case Tuesday as LG&E attempts to acquire the remaining land necessary to build the underground pipeline through Bernheim Forest and local farms. Attorney John Cox, who represents a landowner in the path of the pipeline, said the new details undermine LG&E’s claim that there is a public need for the new pipeline. As a result, Cox asked Bullitt County Circuit Court to dismiss the condemnation suit that would allow LG&E to seize a portion of his client’s property. “When you have a singular customer who has the idea for the project, the question becomes is this for a public purpose or is this for a private purpose?” said Cox.

As Michigan battle rages on Line 5, Enbridge quietly buys land for tunnel | Bridge Magazine – As court battles persist over Enbridge Energy Inc.’s plan to build an underground tunnel for its Line 5 oil pipeline, Enbridge is quietly shelling out millions for modest properties on the south shore of the Straits of Mackinac. According to local property records, an Enbridge subsidiary has scooped up 16 residential parcels since November 2018 in a township west of the Mackinac Bridge, apparently betting that the tunnel plan will survive legal challenges. The most recent purchase by the subsidiary, Tri-State Holdings, was on Jan. 17 for a pair of residential parcels in Wawatam Township that sold for more than $1 million, according to township records. That’s many times what local records show as their market value of roughly $280,000. Tri-State also paid $3.25 million in March 2019 for six nearby parcels – more than eight times their combined market value of $370,000.Wawatam Township Supervisor Roger Moore noted that the parcels are where preliminary Enbridge plans show the tunnel would emerge from the Straits and link with the company’s underground pipeline that continues on a southeast path through lower Michigan to Sarnia, Ontario. It’s critical land as the Canadian energy company seeks to replace 67-year-old, dual pipelines that currently rest on the bottom of the Straits. “I think that’s why they paid so much for that property,” Moore told Bridge Magazine. This now-deserted residential neighborhood is dotted here and there by yellow no-trespassing signs that mark the Enbridge purchases, just a few hundred feet from an Enbridge Line 5 pumping station.

Coalition looks to end gas bill surcharge in Illinois – A 2013 state law allowing utilities to tack natural gas surcharges onto consumer bills for the purpose of funding infrastructure improvements is under scrutiny at the Capitol. At a Statehouse news conference Tuesday, lawmakers and consumer advocates called for ending that state law on Jan. 1, 2021, three years earlier than its Dec. 31, 2023, statutory sunset date. They claim allowing the surcharges “helps major utilities sidestep the regulatory process, automatically raise heating bills, and force many customers into financial crisis to cover billions of dollars in reckless utility spending.” Sen. Ram Villivalam, D-Chicago, said his Senate Bill 3497 and its companion House Bill 5247 are aimed at starting “a conversation centered on the accountability, the safety, and the affordability of utility bill increases that our families are facing in the state of Illinois.” The coalition criticized a 2013 state law that allowed for Qualified Infrastructure Plant, or QIP, surcharges to be applied to consumer bills. The measure was written to allow utility companies to replace outdated pipes, including cast iron piping that was an explosion risk. “Seven years ago, the Illinois Legislature gave gas utilities permission to charge their customers more in order to make urgent repairs, such as replacing old cast iron pipes – repairs that were needed to keep us all safe,” Mason said. “Unfortunately, instead of just making the necessary safety repairs, the utilities are now spending money on things like installing new meters and replacing perfectly safe pipes and we’re all getting stuck with this bill.”

How a Pipeline Is Dividing Minnesota’s Democrats Ahead of Super Tuesday – – The planned route for this pipeline runs past small Northwoods towns populated with union laborers. It cuts across one Native American reservation, while steering around another. And it slices through the fragile coalition that has delivered Minnesota to Democrats in 11 consecutive presidential elections. Influential Democrats have been among the loudest voices on both sides of a debate over whether to replace an aging pipeline, known as Line 3, which carries Canadian crude oil through the evergreen forests and pristine waters of northern Minnesota. Politicians in the state’s big cities of Minneapolis and St. Paul, environmentalists, and many Native Americans, worried about the possibility of a spill and about climate change, have protested the replacement plan and held it up. Rural lawmakers and labor unions, seeing the potential for high-paying construction jobs, mostly supported it. Over generations, the strength of Democrats in Minnesota was based on uniting the state’s city-dwellers and its rural residents in common political cause. But as Democrats prepare to vote in the Super Tuesday presidential primary, that alliance is frayed and in flux. “There are a lot of Democrats in Minnesota that think ‘Well, the rural area is gone, and the future for us is in the suburbs,’” “People out here can feel how the party has kind of moved away from them.” In a state where even the longstanding, official name of the party – the Democratic-Farmer-Labor Party – pays homage to rural-urban bonds, the signs of change are all around. In 2018, Democrats flipped two congressional seats in the Minneapolis and St. Paul suburbs, but they also lost two rural-based seats.Union members who work in mining and construction, long a cornerstone of the party, have grown frustrated by the influence of environmentalists. And those environmentalists, alarmed by climate change and frustrated with politicians’ response, have become increasingly impatient about demanding limits on the use of fossil fuels.“It’s like smoking cigarettes: We’re sitting here smoking every day, but eventually we’re going to have to stop because we’re going to die from it,” said Chairman Michael Fairbanks of the White Earth Band of Ojibwe, who opposes Line 3, the pipeline that would run just north and east of his tribe’s reservation. He said he feared the impact a pipeline spill might have on the waters where his tribe gathers wild rice.“Frankly, the Republicans have done a very good job of framing you’re either for jobs or you’re for the environment, and you can’t have both,” said Mike Simpkins, a Democrat from Bemidji, a college town in the state’s north, who has worked on political campaigns and in pipeline construction. “I don’t believe that.”

Enbridge gets three draft state permits for Line 3 pipeline – A Minnesota regulatory agency has issued three draft permits for Enbridge’s Line 3 oil pipeline replacement, Kallanish Energy reports. The permits were released last week by the Minnesota Pollution Control Agency. The permits included a water-quality certification, which must be approved before the U.S. Army Corps of Engineers can issue a federal water permit, along with a draft wastewater permit and an air-quality permit. The agency has kicked off a one-month public comment period and three public hearings will be held in northern Minnesota on the three draft permits that must be approved before construction can begin. Last month, the Minnesota Public Utilities Commission approved a revised environmental review, a certificate of need and a route permit for the $8.2 billion pipeline project, although other approvals are required. The company has said it hopes to begin construction later this year. The commission had approved the Enbridge project in June 2018. But last summer, the Minnesota Court of Appeals rejected an environmental study because it failed to assess the impacts of a potential oil spill in the Lake Superior basin. The Minnesota Department of Commerce revised the plan to include an analysis of the impacts of such a spill. New computer modeling shows that spills would not pose a threat to Lake Superior. Enbridge has said that the old line is corroding and its capacity has been cut in half. Its maintenance is costly, the company has said. It was built from 1962 to 1967. The new Line 3 would be 1,031 miles in length in three states and Canada. At present, Line 3 runs from Hardisty, Alberta, to Superior, Wisconsin. The Canadian portion runs from Hardisty to Gretna, Manitoba, and the U.S. portion runs from Neche, North Dakota, to Superior, Wisconsin. It is a key part of Enbridge’s Mainline System for transporting tar sands crude oil to refineries and markets in the United States and eastern Canada.

10 Years After Deepwater Horizon, Oil Spills and Accidents Are on the Rise – On April 20, 2010, an explosion and fire on the offshore drilling rig Deepwater Horizon killed 11 men and injured 17 other crew members. Over the next 87 days, an estimated 210 million gallons of oil spilled into the Gulf of Mexico, poisoning fish and wildlife, forcing the closure of beaches and fisheries, and causing billions of dollars in damage to coastal communities along the Gulf. After this catastrophic spill, the Obama administration enacted a series of reforms to improve oil rig safety – reforms that the Trump administration has since rolled back. A Center for American Progress review of government data finds that oil spills, injuries, and accidents from offshore drilling are now on the rise, threatening to erase the progress made in the 10 years since the Deepwater Horizon disaster. During its first months, the Trump administration placed the Bureau of Safety and Environmental Enforcement (BSEE) – an agency created after Deepwater Horizon to regulate offshore drilling – under the leadership of Scott Angelle, a former Louisiana secretary of natural resources who served for years on the board of an oil and gas pipeline company. During the Obama administration, Angelle helped lead the oil and gas industry’s fight against reforms to offshore drilling safety. Following Angelle’s arrival in 2017, the number of inspections and enforcement actions undertaken by BSEE declined. According to agency data, BSEE inspectors conducted 13 percent fewer inspection visits to rigs, platforms, pipelines, and other facilities in the first three years of the Trump administration (2017 – 2019) than they did during the last three years of the Obama administration (2014 – 2016). These data conflict with Director Angelle’s public claims that inspections have been rising under the Trump administration. A spokesperson for BSEE clarified to CAP that Angelle was referring to the total number of “types of inspections” – or inspection procedures – that BSEE has been performing, as inspectors sometimes conduct multiple inspection procedures during a single inspection visit. However, agency data also show that BSEE inspectors took 38 percent fewer enforcement actions – through the issuance of so-called incidents of noncompliance – against offshore oil and gas operators from 2017 to 2019 than they did from 2014 to 2016. It is difficult to explain this precipitous decline in enforcement actions with a theory that oil and gas companies suddenly awakened to the merits of voluntary compliance with safety guidelines. Furthermore, a Politico investigation found that BSEE granted nearly 1,700 waivers that allowed companies to sidestep compliance with stronger safety standards for blowout preventers – a critical piece of safety equipment that can serve as a last line of defense against well blowouts, oil spills, and other disasters.

Offshore oil and gas accidents, deaths spike amid Trump administration’s regulatory rollbacks While President Donald Trump’s administration was working to relax offshore drilling regulations, there was a spike in offshore accidents and a decrease in safety inspections, according an analysis by the Center for American Progress, a liberal think tank.The Bureau of Safety and Environmental Enforcement – the federal agency tasked with regulating offshore drilling – has not yet released a tally of offshore incident statistics for 2019. But the Center for American Progress dug through the agency’s budget documents to find the number of injuries per hour worked on oil and gas facilities on the federal Outer Continental Shelf.American Progress found that the rate of injuries increased 21% in 2018 and 2019 compared with the previous two-year period of 2016 and 2017. The data includes injuries that require medical treatment beyond first aid. It excludes those stemming from natural causes, illness or that are self-inflicted, according to the budget documents.”At worst, this is an unraveling of safety gains made after Deepwater Horizon,” the catastrophic BP spill of 2010, said Matt Lee-Ashley, a senior fellow at American Progress.Last month, the Wall Street Journal reported that BSEE Director Scott Angelle – a former Louisiana state official and 2015 gubernatorial candidate – asked his staff to make changes to the Well Control Rule, a new protocol imposed after the 2010 disaster aimed at reducing the likelihood of a recurrence. Angelle’s changes were meant to cut down on the cost of compliance for the energy industry, and he made them despite advice from BSEE engineers that the changes were unsafe. The rate of offshore injuries was trending downward between 2015 and 2017. But there was a sharp uptick in accidents in 2018. The injury rate is calculated based on the number of injuries per 200,000 hours worked, which includes operator and contractor hours worked for production, construction and drilling operations on the Outer Continental Shelf, an area that includes the Gulf of Mexico.While there were fewer accidents in 2019 than in 2018, the incidents in 2019 may have been more serious. In February, the BSEE reported that there was one fatality in 2018. While the agency has not released the number of fatalities in 2019, local media reports indicate there were at least nine offshore oil worker deaths, according to an analysis by The Times-Picayune. That would mean at least 8% of the injuries reported in 2019 were fatalities.

Months after major oil spill, Bahamas could permit offshore drilling – The Bahamas looks poised to greenlight drilling for oil in waters about 150 miles from South Florida just months after Hurricane Dorian ravaged the island nation and caused a major spill on Grand Bahama island. The Bahamas Petroleum Company (BPC) hopes to drill its first exploratory well in an area 100 miles southwest of the nation’s Andros Island as early as next month, the company said in a recent regulatory filing. The Perseverance #1 venture would coincide with the 10-year anniversary of the Deepwater Horizon oil spill, which started in April 2010 and released more than 200 million gallons of crude oil into the Gulf of Mexico. There is currently no offshore drilling in Bahamian waters. “Perseverance #1 has the potential to open a world-class, new-frontier basin offshore Bahamas, less than 200 miles from the world’s largest hydrocarbon market/infrastructure,” Simon Potter, the chief executive officer of BPC, said in a statement accompanying the regulatory filing. He called the planned well “one of the premier prospects that could be drilled globally this year” with the potential to “transform the revenue-generating capacity of the Bahamian economy.”The nation and its tourism-dependent economy took a major hit last September when Hurricane Dorian, a powerful Category 5 storm that scientists say was strengthened by planetary warming, slammed into the Abaco Islands and then stalled over Grand Bahama for 30 hours. The storm killed at least 67 people, left hundreds more unaccounted for and caused an estimated $3.4 billion in damage. Last year’s hurricane disaster offered a fresh reminder of the threat that climate change poses to coastal fossil fuel infrastructure around the globe, much of which is not built to withstand storms of Dorian’s magnitude. On the island of Grand Bahama, Dorian’s winds ripped the dome roofs off storage tanks at an oil terminal owned by Norwegian energy giant Equinor, causing some 55,000 barrels ― 2.31 million gallons of oil ― to spill onto the ground.

Analysis: Haynesville glimpses new Gulf Coast market access in 2021, 2023 – Producers operating in the Haynesville Shale should see improved access to US Gulf Coast markets following the recent announcement of a final investment decision on the CJ Express project. Last week, Midcoast Energy said it would proceed with the addition of up to 150 miles of 36-inch diameter greenfield pipeline at multiple locations along the operator’s existing East Texas system. The expansion will increase gathering capacity in the Shelby Trough area of the Haynesville and boost transmission capacity on Midcoast’s Clarity Pipeline system by 1 Bcf/d – improving deliverability to export and industrial markets along the Texas and Louisiana Gulf Coast. In conjunction with its FID announcement, MidCoast said it had reached definitive, long-term anchor shipper agreements in support of the proposed expansion. The completed project is expected to enter service by early 2021. A separate announcement from Enable Midstream Partners Monday offered more promising news for Haynesville producers as the company applied for regulatory approval to build its own 1.65 Bcf/d interstate pipeline from the Louisiana shale basin to the Golden Pass LNG terminal. Enable’s Gulf Run Pipeline is seeking authorization from the Federal Energy Regulatory Commission to begin construction by early 2021 with a proposed January 1, 2023 in-service date. Incremental capacity from the Haynesville to US Gulf Coast markets will help relieve area gas producers battered by discounted prices at Carthage, the basin’s nearest delivery point. Year to date, cash prices at the East Texas hub have averaged an 11-cent/MMBtu discount to benchmark Henry Hub gas, or $1.82/MMBtu, S&P Global Platts data shows. The basis discount at Carthage, though, is likely to widen during the coming spring and autumn shoulder seasons as utilization rates on southbound transmission corridors to Henry Hub and Houston Ship Channel rise.

Ragley residents voice opinions on LNG project changes – Ragley residents are voicing their opinions after a change in a proposed LNG project in Beauregard parish. The Louisiana Connector project, a part of the Port Arthur Pipeline, was approved last year and will run through Ragley. But, due to changes in the project, the Federal Energy Regulatory Commission, or FERC, wanted to meet with locals to hear their thoughts – good and bad – about the proposed compressor station. “One of those improvements amounts to moving a compressor station that was approved previously, moving it down the pipeline to a more optimal location,” J.D. Morris, director of permitting and compliance for Sempra LNG, said. Back in January we reported the station was originally set to be off of Gaytine Road, but Sempra, the company over the project, got push back because homeowners say it would’ve been an eyesore and noisy for the area. Now the compressor station will sit off of Coonie Jackson Road in Ragley.

Sempra Energy, Bechtel Team Up on Port Arthur LNG Project – Port Arthur LNG LLC and Bechtel Oil, Gas, and Chemicals Inc., subsidiaries of Sempra Energy and Bechtel, respectively, have signed an engineering, procurement and construction contract for the Port Arthur LNG liquefaction project under development in Port Arthur, Texas. “Building new export infrastructure in the U.S. is critical to providing overseas markets with cleaner fuel alternatives,” said Jeffrey W. Martin, chairman and CEO of Sempra Energy. Bechtel Oil, Gas, and Chemicals will perform the engineering, procurement, construction, commissioning, startup, performance testing and operator training activities for the project. The agreement also includes continuing pre-final investment decision engineering. The project is expected to initially include two liquefaction trains, two liquefied natural gas storage tanks, a marine berth and associated loading facilities and related infrastructure to provide liquefaction services, with a nameplate capacity of about 13.5 million tonnes per annum (Mtpa) of LNG. The project site is on 3,000 acres of land along three miles of the Sabine-Neches waterway and has the potential to become one of the largest LNG export projects in North America, with expansion capabilities of up to eight liquefaction trains and approximately 45 Mtpa of capacity, according to the companies. The Port Arthur LNG development project received authorization from the U.S. Department of Energy to export domestically produced LNG to countries that do not have a free trade agreement with the U.S. in May of last year. Also, FERC issued the approval to site, construct and operate the liquefaction-export facility in April 2019.

Tellurian tightens belt amid dim short-term outlook for LNG – Houston liquefied natural gas company Tellurian is cutting costs and reorganizing some debt as LNG prices remain low amid a global supply glut caused by a warm winter in Asia and the coronavirus outbreak.The company said Monday that it would cut corporate expenses by about 18 percent to $6 million per month to help ride out the storm. It also is trying to extend the maturity of a term loan due in May.“Given current global financial market conditions and increasing restrictions on travel caused by the onset of coronavirus, we are taking the steps necessary to focus on preserving the value we have created at Tellurian and Driftwood LNG,” CEO Meg Gentle said in a statement. Monday’s announcements came less than a week after the company posted a $151.8 million loss in 2019, up 21 percent from a $125.7 million loss a year earlier. Annual revenue, however, grew by 180 percent to $28.8 million from $10.3 million in 2018.Tellurian has no operating export facility and relies entirely on sales from its 67 natural gas wells for revenue. It has a federal permit to export 27.6 million metric tons of LNG per year from a planned Driftwood LNG facility in Lake Charles, La., but hasn’t made a final investment decision on the project.

Mounting pressure on U.S. LNG industry – A global supply glut has placed intense pressure on U.S. liquefied natural gas companies. There are now six LNG export terminals in operation in the United States and another 10 projects that hold permits but lack contracts and financing to move forward. A warm winter and the coronavirus outbreak have weakened global LNG demand, forcing two companies with ties to Houston to make moves for their projects to survive. Houston liquefied natural gas company Tellurian is lowering expenses, renegotiating some of its debt and selling stock among its moves to save its Driftwood LNG project in Louisiana. LNG Limited, an Australian company with its principal offices in Houston, is selling all of its assets to a Singapore firm that will take over the company’s proposed projects in Louisiana and Canada. The sale still needs stockholder approval. LNG Limited received a federal permit in 2016 but has spent the last four years unable to land supply contracts or secure financing.

U.S. Gas Export Pioneers Forced to Sell Shares to Satisfy Loan Requirements— Two pioneers of the U.S. natural gas export industry were forced to sell shares of the company they founded amid a global market rout and concern that a key supply deal won’t be finalized. Tellurian Inc. Chairman Charif Souki and Vice Chairman Martin Houston sold 4 million and 3.4 million shares respectively, according to filings late Friday. In both cases, the transactions were forced by a lender to satisfy loan requirements, the filings show. Tellurian declined to comment. Shares of the company, which is trying to develop a $28 billion liquefied natural gas terminal in Louisiana, plunged by more than half on Friday to close at $1.80. The total weekly decline was 72%. India’s Petronet LNG Ltd., a potential major customer that Tellurian has courted, announced earlier this week it would seek competing offers. The move highlights the mounting pressure on sellers amid a worldwide glut, and adds to doubts that Tellurian will be able to secure a sizable anchor investment from Petronet for its Driftwood LNG project. The Petronet news also dashed hopes that the two companies might finalize a supply agreement during President Donald Trump’s visit to India this week. The coronavirus outbreak, meanwhile, sent global markets spiraling lower, adding to Tellurian’s woes. The epidemic has hit China, South Korea and Japan, the world’s biggest LNG importers, particularly hard. “Continued commercial slippage, mounting liquidity concerns, and the broader market de-risking have combined to price-in the new economic reality for Tellurian: It’s not going to make it,” Michael Webber, managing partner at Webber Research & Advisory LLC, wrote in a note to clients Friday. Tellurian said Thursday it had extended a memorandum of understanding with Petronet by two months to May 31. Under the memorandum, Petronet agreed to negotiate the purchase of as much as 5 million tons a year of LNG from Driftwood, along with an equity investment.Collapsing LNG prices in Asia and Europe have squeezed profits for American gas exporters, already under pressure after China halted U.S. imports of the fuel a year ago amid trade tensions. Without commitments from Chinese buyers, some American export projects may be delayed or canceled.

LNG opponents sue feds over two Port of Brownsville permits – Opponents of the liquefied natural gas industry have sued a federal agency that issued permits for a controversial LNG export terminal at the Port of Brownsville and a related pipeline. In a petition filed before the U.S. Court of Appeals for the District of Columbia Circuit, the Sierra Club, the City of Port Isabel and four other opponents are asking a federal judge to review and overturn permits issued by the Federal Energy Regulatory Commission for Rio Grande LNG and the Rio Bravo Pipeline.No court hearing has been set in the lawsuit. FERC officials issued a permit for the controversial projects in November and then denied a request by opponents to reconsider the agency’s decision.Citing safety and environmental concerns, opponents of the projects say that Rio Grande LNG will become the largest polluter in the Rio Grande Valley, an impoverished region along the U.S./Mexico border.”FERC has consistently ignored concerns about how Rio Grande LNG and other fracked gas facilities would harm already-marginalized Latinx communities in the Rio Grande Valley,” Sierra Club organizer Rebekah Hinojosa said in a statement. “This fracked gas export facility would devastate our local economy and subject our families to dangerous pollution, and it’s unacceptable that FERC has refused to take these threats into consideration.”However, supporters of the projects say they will reduce flaring in the Permian Basin of West Texas by creating a market for natural gas that would otherwise be burned off. Designed to export 27 million metric tons of LNG per year, the plant and pipeline will also bring billions of dollars of private investment to the impoverished region, generate thousands of construction jobs and hundreds of high-paying permanent jobs.

Texas jury opposes felony charges for protesters who shut Houston Ship Channel – (Reuters) – A Texas grand jury on Wednesday declined to issue felony indictments against a group of Greenpeace USA activists who closed a key oil export waterway for 18 hours last year by tying themselves to a Houston bridge and dangling over the water. Felony charges had been brought against 31 activists involved in the September 2019 protest. The indictments, sought by the Harris County District Attorney’s Office, were under Texas’ new critical infrastructure law, which makes it a felony to interfere with oil and gas pipelines and ports, and other “critical infrastructure.” The Harris County jurors opted instead for 25 misdemeanor indictments for obstructing a highway or other passageway. Six cases were dismissed before submission and 22 people still face separate a federal misdemeanor charge for blocking a navigable waterway. The misdemeanor charge has a penalty of up to 180 days of jail time and a fine of up to $2,000. “No one violated Texas’ critical infrastructure statue,” said Tom Wetterer, general counsel for Greenpeace USA, adding that the new law and similar laws “unconstitutionally criminalize peaceful protest and violate First Amendment rights to free speech.”

Greenpeace Activists Avoid Felony Charges Following a Protest Near Houston’s Oil Port – Texas prosecutors downgraded charges filed against a group of Greenpeace activists on Wednesday, deferring a potential courtroom debate over a controversial new law the state passed last year.More than two dozen protesters were arrested in September after several had dangled themselves off a bridge over the Houston Ship Channel, a vital conduit in one of the nation’s busiest oil ports.The Harris County District Attorney’s office had originally charged the protesters with felonies under the new law, which imposes harsh penalties on anyone who disrupts energy infrastructure. But prosecutors changed the charges to misdemeanors on the same day that a grand jury indicted 23 of the protesters on those misdemeanors. The felony charges were the first issued by prosecutors under similar laws that have been enacted in at least eight other states since 2017. The bills generally allow prosecutors to seek lengthy prison terms and steep fines for people who trespass on or damage “critical infrastructure” facilities, including pipeline construction sites.The Texas protesters had faced up to two years in prison and $10,000 in fines under the felony charges, said Ryan Schleeter, a Greenpeace spokesman. He said the organization’s lawyers had argued that the activists hadn’t violated the new law, and that “the law is intended to chill protest and free speech.” Twenty-two of the activists also face separate federal misdemeanor charges connected to the protest, Schleeter said. Prosecutors dropped all charges against another six before the indictment.

Report: Crude oil exports soar while U.S. inventory grows slightly – Crude oil production and exports soared during the last week of February while U.S. inventories grew slightly, a new report from the Department of Energy showed. During the last week of February, the United States produced a record 13.1 million barrels of crude oil per day and exported nearly 4.2 million barrels of that production, a Wednesday morning report from the Department of Energy shows.Production was up 100,000 barrels per day from the previous week while exports were up nearly 500,000 barrels per day. However, those gains in exports did not offset commercial crude oil inventories, which were at 444.1 million barrels — up roughly 800,000 barrels from one weak prior. The inventory comes at a time when crude oil prices are weak. West Texas Intermediate crude oil is trading was trading in the $47 per barrel range amid a global supply glut attributed to weaker demand in China where the coronavirus outbreak has cut imports. Some fear that largest drop in oil demand in history is underway due to the outbreak and that it could be even worse than that experienced during the 2008 financial crisis, analysts at the research firm IHS Markit said Wednesday.

Drilling rig operator files for Chapter 11 bankruptcy – After enduring more than five years of losses, San Antonio drilling rig operator Pioneer Energy Services has filed for Chapter 11 bankruptcy.In its Chapter 11 filing in U.S. Bankruptcy Court in San Antonio, Pioneer listed more than $100 million in assets and more than $100 million in debt owed to more than 200 creditors.Pioneer hasn’t made a profit since the third quarter of 2014. The filing comes weeks after company executives reached a financial restructuring deal with key investors that included forgiving debt in exchange for equity in the reorganized company. Active in shale plays across the U.S., Pioneer makes most of its revenue from its drilling rig fleet, but the company also provides other related services. The bankruptcy filing comes as crude oil prices have fallen below $50 per barrel, well below the break-even point for most exploration and production companies.In a statement, Pioneer said the bankruptcy filing only covers the company’s U.S. assets and not its international assets that include drilling rig operations in Colombia.”Our objective is to use the restructuring process to implement a balance sheet restructuring and set the company on a path to succeed in the future with a right-sized debt structure and ample liquidity going forward,” Pioneer Energy Services CEO William Stacy Locke said in a statement.

Coronavirus Delivers Another Blow to Embattled Shale Drillers – Shale drillers were already braced for a tough year. Now the new coronavirus is putting them under even greater financial pressure. Exploration and production companies are straining to slow growth – amid an oversupply of oil and gas – and cut spending to appease investors angry over poor returns. Now the virus has further weakened global demand for their products, posing a greater challenge to a sector where many companies are saddled with debt.By some measures, top shale companies have shown improvement in recent earnings reports. Roughly 46% of 37 U.S. independent producers spent less than they took in from operations last year, up from about 30% in 2018, according to a Wall Street Journal analysis of FactSet data. Nonetheless, the whole sector is getting clobbered as concerns about the economic impact of coronavirus pull oil prices lower and cloud 2020 prospects. U.S. benchmark oil prices ended Friday around $45 a barrel, down from about $53 a week earlier. Shares in shale drilling pioneer Chesapeake Energy Corp. tumbled roughly 38% through the week ended Friday amid concerns about the company’s debt load. Whiting Petroleum Corp. WLL 1.18% ’s stock also plunged after it warned that output would decline this year. Continental Resources also traded lower after disclosing 2020 plans that indicated the company could struggle to generate free cash flow at current oil and gas prices. “We see the oil and gas markets as fundamentally oversupplied, with demand even further impacted by the coronavirus,” Continental Executive Chairman Harold Hamm said. Shale drillers have been under tremendous pressure from investors – and increasingly from their lenders – after years of poor financial returns, even as they turbocharged American oil production to nearly 13 million barrels a day, the most in the world. Many are now seeking to win back Wall Street by limiting spending and demonstrating that they can generate free cash flow, positioning them to pay down debt or return money to shareholders. But that was proving a tall order, even before coronavirus added to concerns about soft demand. In addition to lower oil prices, natural-gas prices have been hovering below $2 per million British thermal units for much of the year, down from an average of about $2.69 in February 2019, U.S. Energy Information Administration data show.

CERAWeek energy conference canceled over concerns about coronavirus outbreak – The annual CERAWeek energy conference, which was scheduled to take place in Houston from March 9 to March 13, has been canceled due to the increased spread of coronavirus, according to IHSMarkit, the consultancy that has held the event every year since 1981. “We do this with deep disappointment,” the group said in a statement issued Sunday on its website. “Over the last few days concern has mounted rapidly about the COVID-19 coronavirus. The World Health Organization raised the threat level on Friday, the U.S. government cancelled a summit meeting scheduled in Las Vegas, an increasing number of companies are instituting travel bans and restrictions, border health checks are becoming more restrictive and there is growing concern about large conferences with people coming from different parts of the world. Delegates from over 80 countries were expected to participate in CERAWeek 2020.” CERAWeek is the energy industry’s biggest conference and annually draws senior executives from around the world. The group said it will plan ahead for CERAWeek 2021. This is not the first event that has been canceled over the coronavirus outbreak. Facebook this past week announced its decision to cancel its annual F8 software developer conference due to concerns surrounding the outbreak. Game Developers Conference, a major event for video game programmers and designers, has been postponed. The Mobile World Congress, the world’s largest technology trade show held in Barcelona, was called off after companies including Facebook pulled out. Concerts across Asia have been canceled. The annual Geneva International Motor Show was also canceled.

Coronavirus delivers another hit to energy –The spread of the coronavirus forced the cancellation of CERAWeek by IHS Markit, the annual gathering in Houston of the most powerful and influential people in the energy world. Organizers at the research and consulting firm IHS Markit made the call Sunday as the global pandemic has spread in recent weeks and the Trump administration imposed additional restrictions on travel from Iran and issued advisories on travel to Italy and South Korea. The conference was scheduled to begin Monday March 9. The cancellation of the conference, sometimes called the Davos of energy, is another symbol of the threat the coronavirus has posed to economic growth, energy demand and oil and gas industry. It follows the worst week for crude since the 2008 financial crisis .Crude lost 16 percent last week and settle Friday below $45 a barrel. It’s down nearly 30 percent from its recent peak in the beginning of January. As James Osborne reports, the industry was already struggling with lackluster prices, falling profits, shrinking capital and waning investor confidence. Some analysts worry about a repeat of 2014, if the coronavirus continues its march and oil prices resume their slide for an extended period. Our columnist, Chris Tomlinson, writes that Texas and its energy-sensitive economy is already feeling the impact as oil and gas companies prepare to pull more rigs and workers from oil fields.As Tomlinson notes, “Oil companies producing in the Permian Basin do not make money at $55, let alone $44.76 a barrel.”How dark the forecasts become will depend on how long the markets continue their slide. OPEC and its allies are considering another production cut while the clamor for the Federal Reserve to slice already low interest rates is building. Actions by these institutions could provide a lift to oil prices. But if recent history shows anything, those hoping for a long-lasting period of healthy oil prices are likely to be disappointed.

Is The US Shale Boom Over? Four Major Threats To The Fracking Revolution – The U.S. is awash in cheap shale oil and gas. After decades of declining U.S. oil output, the fracking revolution unlocked vast oil and gas deposits and made America the world’s No. 1 oil producer. The once-massive U.S. petroleum deficit – $436 billion in 2008 – turned into a surplus last September. “We do not need Middle East oil,” President Donald Trump declared in January. Yet just as Americans have begun to take cheap energy for granted, along with the jobs and extra spending money spawned by the shale economy, the U.S. shale boom’s next act looks uncertain. While the government projects continued growth for shale oil and gas production, that forecast may understate the threats. Political, financial, technological and geological pressures are closing in.Well productivity has peaked, while prime drilling areas may soon be fully tapped. Meanwhile, shale oil and gas companies – from pure plays such as EQT to oil majors Exxon Mobil and Chevron – haven’t generated returns. Investors, who no longer want to finance expansion given environmental and political risks. The growth phase of the shale boom is “screeching to a halt,” says Raoul LeBlanc, vice president for energy at IHS Markit. “We expect zero growth next year, and if the coronavirus continues, we could have negative growth this year.” LeBlanc sees big reasons for the abrupt slowdown that have nothing to do with the Covid-19 virus. “The technology has largely matured,” he said. After a period of big well productivity gains, “we’ve largely optimized what we can do.” Further, the best ground for drilling will be exhausted in about five years, LeBlanc says. Another reason is all about cash. Shale companies simply haven’t made much money from the fracking revolution. “This is one of the most capital-intensive businesses in the world,” LeBlanc said. “Investors that were willing to fund this massive growth are starting to focus on profitability and getting money back,” LeBlanc said. That means spending less on drilling new wells. On Thursday, Exxon Mobil said its Permian shale operations will operate at a “reduced pace” in 2020 and 2021 vs. its prior plans. The Dow Jones energy giant sees its Permian production at 360,000 barrels of oil equivalent a day this year, though Exxon still plans to nearly triple output in the area by 2024.

Shale Drillers Need A Miracle To Keep Production From Falling – With West Texas Intermediate falling below $45 a barrel after the latest burst in coronavirus panic, U.S. shale oil and gas producers are feeling growing heat. Except for the Permian, where production of both oil and gas is still growing, the U.S. shale patch is retrenching. And the Permian may soon follow suit. In its latest Drilling Productivity Report, released earlier this month, the Energy Information Administration said oil production had declined across six of the seven major shale plays in the country, by some 21,000 bpd. In the Permian, however, production rose by 39,000 bpd, tipping the total into a net increase of 18,000 bpd. Now, while this confirms the star status of the Permian, it also suggests that oil production growth is becoming uneconomical in other shale plays.A recent report on oil and gas production trends in 2019 showed the slowdown is not a sudden one. Titled “Rockies and Bakken in Focus“, the report, by Enverus, says growth in production in these regions had slowed to a crawl amid the low oil prices. Pipeline constraints, the oil and gas info provider noted, were also stifling production growth.While relief for the pipeline constraints in the Bakken and the Denver-Julesburg area is coming, prices don’t look like they are going anywhere except maybe further down if OPEC+ fails to agree to deeper cuts. This means the financial pressure many oil and gas drillers in the shale patch are already feeling will only deepen and production growth will slow further.Earlier this week the chief executive of Schlumberger said as much. Speaking to Reuters on the sidelines of an industry event in Saudi Arabia, Olivier Le Peuch said he expected growth in U.S. shale oil production to slow down to 600,000 to 700,000 bpd this year and further to just 200,000 bpd next year as low prices continue to take their toll.This wasn’t all, either. According to Le Peuch, unless the oilfield service sector comes up with new extraction technology that works at lower than current costs, U.S. shale oil production will not return to growth at all, but plateau. Add to this the fact that the sweet spots are already depleted and producers have moved to not so low-cost locations, and the outlook for U.S. shale oil darkens. The situation in gas is even worse. As the Enverus report notes, the breakeven cost for gas production in the Denver-Julesburg Basin and the Bakken are now higher than the Henry Hub benchmark and quite a bit higher, at that. Henry Hub futures prices are currently below $2 per million British thermal units until July, when the futures price tops $2 per mmBtu. The breakeven for producers in the Rockies and the Bakken, on the other hand, is more than $3 per mmBtu.

The Energy Elite Have Started Listening to Their Enemy No. 1 in Houston -Climate change is a touchy topic in Houston, even if hardly anyone doubts the climate is changing. An already damp city is getting wetter, obvious in the muddy sidewalks and the puddles that linger long after a routine rain. The bigger downpours block highways. The really huge storms – and not just 2017’s Hurricane Harvey, which killed at least 94 people – keep arriving with a size and frequency that meteorologists once insisted was impossible. With initial support from Texas’s governor and U.S. senators (all conservative Republicans), the Army Corps of Engineers wants to spend $23 billion to $32 billion on a coastal bulwark against the rising waters. Say “climate change” too loudly, though, and you’ll get some looks. Many Houstonians still feel like they’re in a standoff with environmentalists who would love to put the Oil and Gas Capital of the World out of business. And anyway the city is booming, with cranes as common as traffic jams on its ever-widening highways. With a population up 11% since 2010, Houston is destined to overtake Chicago as the U.S.’s third-largest city – unless something goes horribly wrong. Something horrible like the worst environmental disaster in American history, which is just one of the looming catastrophes that Jim Blackburn won’t shut up about. The environmental lawyer and Rice University professor shows up everywhere in Houston – at society events, on the radio, in op-eds and at government hearings – and blurts out what the city’s elite, its oil and gas executives, only whisper in their board rooms: Climate change is an existential threat to Houston, putting in real danger both its physical survival and its economic future. In his Texas twang, Blackburn, a 72-year-old native of the Rio Grande Valley, warns that the Army Corps’ coastal barrier is insufficient. The region’s flood maps are wrong, making new infrastructure, designed to last decades, obsolete the day it’s finished. Renewable energy is getting cheaper, and climate activists are getting louder. Without creative thinking, the fossil fuel industry will collapse, and Houston will turn into a warmer, wetter rust belt. He’s backed by hydrologists, weather modelers, engineers, and ecologists, at Rice University and elsewhere, who produce a steady stream of terrifyingresearch. The main takeaway is that the state’s politicians and businesses are still operating on data from the past century, an era before the weather went berserk.

Kinder Morgan uncertain about proposed Texas Permian Pass natgas pipeline – (Reuters) – U.S. energy company Kinder Morgan Inc said its proposed Permian Pass natural gas pipeline in Texas faced an uncertain future since no customers for the project have been lined up in the current low-price environment. In recent years, gas production associated with record oil output in the Permian basin in West Texas and eastern New Mexico has grown faster than energy firms could build new pipelines and other infrastructure needed to transport the fuel to market. That lack of pipeline space prompted drillers to flare record amounts of Permian gas in 2019 and caused prices at the region’s Waha hub to turn negative several times over the past year. Kinder Morgan Chief Strategy Officer Dax Sanders told analysts at the Credit Suisse Energy Summit in Vail, Colorado, on Wednesday the company would not build Permian Pass “until we get good solid long-term contracts, minimum 10-year take-or-pay contracts.” “We don’t have anybody signed up yet,” Sanders said, noting “If it comes together, it does. If it doesn’t, it doesn’t.” Sanders said Kinder Morgan was still seeking customers for the project and could make a final investment decision this year to build the 2.0-billion cubic feet per day (bcfd) pipe if it secures the contracts.

NYSE Gives Chesapeake Granite Wash Trust the Boot – The New York Stock Exchange has suspended trading of Chesapeake Granite Wash Trust’s units, effective Feb. 28. The NYSE also initiated proceedings to delist the Trust Units. The delisting is due to the Trust’s failure to meet listing compliance standards. The average closing price of the Trust Units fell below $1.00 over a 30-consecutive trading-day period, and the Trust was unable to regain compliance within a six-month period that ended Feb. 28. On March 2, the Trust’s units began trading under the symbol “CHKR” on the OTC Pink Market, which is operated by OTC Markets Group Inc. As OTC Pink is a significantly more limited market than the NYSE, the quotation of the Trust Units on OTC Pink may result in a less liquid market available for existing and potential unitholders and could further depress the trading price of the Trust Units, Chesapeake said in a written statement. At this writing, the shares were trading at $0.45 each. Chesapeake Granite Wash Trust is a Delaware statutory trust formed by Chesapeake to own royalty interests in oil, natural gas liquids and natural gas wells in Washita County, Okla., producing from the Colony Granite Wash play within the broader Granite Wash formation of the Anadarko Basin. The common units do not represent interests in and are not obligations of Chesapeake, according to the company.

Is the U.S. Fracking Boom Based on Fraud? – Much like with the housing crisis that caused the financial crisis of 2008, the fracking boom has led to Wall Street bankers finding innovative ways to finance a money-losing endeavor. Some companies are now even selling bonds based on future well performance, a concept similar to themortgage-backed securities that led to the 2008 housing crisis.Another Wall Street invention is what is called a “special purpose acquisition company” (SPAC), or, as they are also known, blank check companies. The way these investments work is a big bank or private equity firm backs a management team to raise money for the SPAC with the agreement that the leaders of the SPAC will then at some point make a “special purpose acquisition” – which means they will find an existing company and buy it.They are called blank check companies because the management is given a blank check to buy whatever they choose. In the 1980s, the Wall Street Journal (WSJ) noted that “blank-check companies were often associated with penny-stock frauds.” In a 2017 article on the oil industry, the WSJ reported that “SPACs were a hallmark of the frothy days before the financial crisis [of 2008].”Understandably, SPACs were often seen as a risky investment, but much like with the housing crisis, the biggest names on Wall Street are getting involved and giving the concept legitimacy, with Goldman Sachs starting to back SPACs in 2016. And new fracking companies have come about as a result.“SPACs are the most egregious example in the industry of executive misalignment with investors,” Dell told the WSJ. As I have previously reported, one of the problems with the fracking industry is that CEOs are paid very well even when the companies lose money. According to Dell, SPACs take this problem to a new “egregious” level. . Like when a Wall Street Journal reporter, in a room full of people hired to make forecasts of fracked oil and gas production, learned about the existence of much more accurate methods for predicting that oil production. And also learned that with accuracy comes much lower estimates of shale oil reserves.The WSJ article that followed quoted Texas A&M professor and expert on calculating oil and gas reserves John Lee. “There are a number of practices that are almost inevitably going to lead to overestimates,” said Lee. Those are the practices used by the industry, with Alta Mesa serving as just one example.Overestimates are why Alta Mesa received funding but now no longer exists.The Wall Street Journal reported that during a presentation given by Lee, an audience member “stood up and challenged the engineers in attendance,” asking why the forecasters weren’t using accurate models like the ones that were available – as Lee had described.Another audience member explained the reason.“Because we own stock,” replied another engineer, “sparking laughter,” according to the Wall Street Journal.Is it misleading to laugh at your company’s investors if you know the estimates you are giving them are inflated, but because you own the stock that benefits from those estimates, you do it anyway? Is that fraud? Perhaps that depends on if you get you get ethics lessons from Andrew Fastow and Jim Hackett. Will the biggest innovation of the fracking revolution be making financial fraud a laughing matter?

Gas pipeline firms take electrification in stride but long-term costs loom | S&P Global Market Intelligence – While natural gas pipelines’ long-term contracts insulate them financially from an emerging movement to prohibit gas infrastructure in new buildings and renovations, some industry experts said those bans do signal the long-term potential for stranded midstream assets. Since 2019, the anti-gas movement has gained momentum through electrification measures cropping up in California, the Boston area and Washington state amid concern over global warming and the contribution of fossil fuels to it. Many of the pipeline companies that deliver gas to utility customers have called for mitigating the sector’s negative climate impacts, but they also maintain that gas transportation systems provide unmatched environmental and economic benefits that will ultimately help phase in a cleaner energy economy. The gas bans may not pose an immediate threat to pipelines, but if they remain in place midstream firms could begin to incur costs down the road as contracted capacity rolls off. “Due to the sporadic distribution of the gas bans, and the generally long-term contracts involved in gas pipeline transportation, and the dependence of the majority of the nation on natural gas for heat, food preparation, and industry, it seems like the near-term revenue risk is fairly low as is the risk of stranded assets,” Regulatory Research Associates analyst Brian Collins said in an email. “However, looking ahead one or two decades, the gas ban moves could begin to limit the value of pipelines and gas distribution networks.” When it comes to how much pipeline companies are worth amid the transition to renewable sources, Andrew Logan, senior director of oil and gas at shareholder advocacy group Ceres, added that the stock market is forward-thinking and expects to see that reflected in equity values before assets become stranded. The bans alone, however, are not ultimately what will put gas pipeline operators out of business, he said.”It’s more of the broader context they are signaling around gas demand growing forward,” Logan said. “There continues to be a lot of hope from the natural gas industry that residential demand will continue to grow in the future … but the bans do seem to chip away at the idea that there is much growth to come for anyone in the gas pipeline business.”

Southeast New Mexico plagued by oil and gas spills as production booms in Permian Basin – Uncertainty continued for the people of Malaga and throughout ranching communities in southern Eddy County in the days after the State of New Mexico began investigating a spill on the Black River of chemical-laden drilling mud by Matador Resources. Residents were advised to avoid the river that many grew up swimming and fishing in, and which local livestock relies on for water. Bert Rios, a 67-year-old local farm owner and lifelong resident of Malaga said he called the State of New Mexico when he witnessed the normally clear waters of the river turn milky and began to suspect a nearby pipeline construction project was to blame. The State and Matador quickly moved in on the incident, with multiple agencies assessing the damage as a plume could be observed 75 to 100 miles from site of the spill. But oil and gas spills continued to plague New Mexico, especially in the southeastern corner of the state where the industry boomed in the Permian Basin, throughout 2019. A report from the Center for Western Priorities showed that between New Mexico, Colorado and Wyoming, the three biggest oil-producing states in the Intermountain West, 2,811 spills were reported last year, releasing 23,600 barrels of crude oil and 170,223 barrels of produced water. That’s an average of 2,716 gallons of crude oil and 19,587 gallons of produced water per day. Using data from New Mexico’s Oil Conservation Division (OCD), the study pointed to about four spills per day in the New Mexico, mostly in Eddy and Lea counties where production is highest. In total, 1,352 spills were reported last year in the state, a slight 11 percent decline from the 1,523 spills in 2018. Each day, about 280 barrels of produced water was spilled by oil and gas operators, the study read, with 41 barrels of crude oil spilled and about 2.2 million cubic feet of natural gas leaked. In Colorado, 636 spills were reported across the state last year, a 60 percent increase from 2012. Wyoming reported 823 spills last year, a 15 percent increase from 2018’s total of 715.

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