Oil, Gas, And Fracking News Read 09May 2021 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 08 May 2021. Part 2 is available here.

This is a feature at Global Economic Intersection every Monday evening or Tuesday morning.

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Record jump in oil exports to a 54 week high leads to largest crude inventory draw since January, with 12 million barrels still unaccounted for; refinery utilization rate is highest in 58 weeks; gas rigs see largest increase in 37 months

Oil prices rose this week as traders antipitated higher demand for fuel as global economies eased Covid-related restrictions… after rising 2.3% to $63.58 a barrel last week on strong economic reports and on rising product demand, the contract price of US light sweet crude for June delivery traded lower Monday morning in Asia as surging COVID-19 cases in India dampened fuel demand hopes, but opened higher and rose in New York trading, supported by a weaker U.S. dollar, as hopes for a demand recovery outweighed worries about surging infections in India, with oil settling 91 cents higher at $64.49 a barrel….oil prices moved higher a second day on Tuesday as traders bet that easing COVID-19 restrictions in the U.S. and Europe would lead to higher fuel demand, and closed $1.20, or nearly 2% higher at $65.69 a barrel, after more U.S. states eased lockdowns and the EU sought to encourage travellers…oil prices extended those gains in after hours trading after the American Petroleum Institute reported the largest draw from US crude supplies since January, and opened 76 cents higher on Wednesday, but then faded late to close 6 cents lower at $65.63 a barrel, as traders reconsidered the outlook for oil demand in light of rising gasoline supplies…oil prices moved lower again on Thursday after Saudi Arabia cut the selling price of its crude to Asia, and ended trading down 92 cents at $64.71 a barrel amid uneven recovery signs among countries still battling the coronavirus…oil prices edged higher in Asia trading early Friday as global economic recovery and easing travel curbs in the US and Europe buoyed the fuel demand outlook, even as the surging pandemic in India capped prices, and June oil went on to close 19 cents higher to $64.90 a barrel in New York, and thus posted a 2.1% gain on the week…

Natural gas prices also edged higher this week on near record exports and on forecasts for a cooling trend…after rising 4.0% to $2.931 per mmBTU last week on record exports and on declining gas field output, the contract price of natural gas for June delivery opened higher on Monday and climbed 3.5 cents to a 10 week high of $2.966 per mmBTU, despite forecasts for milder weather, on forecasts for near record exports…prices held steady at a 10-week high on Tuesday on forecasts for cooler weather, settling a tenth of a cent higher at $2.967 per mmBTU. but then slid 2.9 cents to $2.938 per mmBTU on Wednesday ahead of expectations for a more substantial build in underground inventories with this week’s EIA storage report…however, prices slipped again on Thursday, despite a bullish inventory print and continued robust demand for both LNG and pipeline exports, and settled a penny lower at $2.928 per mmBTU…natural gas prices rebounded Friday, rising 3.0 cents to $2.958 per mmBTU, on forecasts for cooler weather and higher heating next week and hence finished week 0.9% higher, even as they failed to penetrate the $3 level or match the highs set earlier in the week…

The natural gas storage report from the EIA for the week ending April 30th indicated that the amount of natural gas held in underground storage in the US rose by 60 billion cubic feet to 1,958 billion cubic feet by the end of the week, which left our gas supplies 345 billion cubic feet, or 15.0% below the 2,303 billion cubic feet that were in storage on April 30th of last year, and 61 billion cubic feet, or 3.0% below the five-year average of 2,019 billion cubic feet of natural gas that have been in storage as of the 30th of April in recent years….the 60 billion cubic feet that were added to US natural gas storage this week was more than the average forecast of a 51 billion cubic foot addition from an S&P Global Platts survey of analysts, but was well below the average addition of 81 billion cubic feet of natural gas that have typically been injected into natural gas storage during the same week over the past 5 years, as well as well below the 103 billion cubic feet added to natural gas storage during the corresponding week of 2020…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending April 30th showed that because of a drop in our oil imports and a big increase in our oil exports, we needed to withdraw oil from our stored commercial crude supplies for the fourth time in eleven weeks and for the 26th time in the past forty-one weeks….our imports of crude oil fell by an average of 1,164,000 barrels per day to an average of 5,451,000 barrels per day, after risng by an average of 1,211,000 barrels per day during the prior week, while our exports of crude oil rose by an average of 1,581,000 barrels per day to an average of 4,122,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 1,329,000 barrels of per day during the week ending April 30th, 2,745,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was reportedly unchanged at 10,900,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production appears to total an average of 12,229,000 barrels per day during this reporting week…

US oil refineries reported they were processing 15,243,000 barrels of crude per day during the week ending April 30th, 225,000 more barrels per day than the amount of oil they used during the prior week, while over the same period the EIA’s surveys indicated that a net of 1,291,000 barrels of oil per day were being pulled out of the supplies of oil stored in the US….so based on that reported & estimated data, this week’s crude oil figures from the EIA appear to indicate that our total working supply of oil from net imports, from storage, and from oilfield production was 1,722,000 barrels per day less than 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 plugged a (+1,722,000) 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 there must have been a error or errors of that magnitude in this week’s oil supply & demand figures that we have just transcribed….furthermore, since last week’s EIA fudge factor was at (-150,000) barrels per day, there was a 1,872,000 barrel per day balance sheet difference in the unaccounted for crude oil figure from a week ago, which renders the week over week supply and demand changes we have just transcribed meaningless….however, since most everyone treats these weekly EIA reports as gospel and since these figures often drive oil pricing and hence decisions to drill or complete wells, we’ll continue to report them as they’re published, just as they’re watched & believed to be accurate by most everyone in the industry….(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 5,831,000 barrels per day last week, which is still 7.8% more than the 5,408,000 barrel per day average that we were importing over the same four-week Covid impacted period last year… the 1,291,000 barrel per day net withdrawal from our crude inventories included a 150,000 barrel per day withdrawal from our Strategic Petroleum Reserve, space in which has been leased for commerical purposes, and a 1,141,000 barrel per day withdrawal from our commercially available stocks of crude oil….this week’s crude oil production was reported to be unchanged at 10,900,000 barrels per day even though the rounded estimate of the output from wells in the lower 48 states was 100,000 barrels per day lower at 10,400,000 barrels per day because a 15,000 barrel per day increase in Alaska’s oil production to 457,000 barrels per day added 100,000 barrels per day to the rounded national total….our prepandemic record high US crude oil production was at a rounded 13,100,000 barrels per day during the week ending March 13th 2020, so this reporting week’s reported oil production figure was 16.8% below that of our production peak, yet still 29.3% above 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 86.5% of their capacity while using those 15,243,000 barrels of crude per day during the week ending April 30th, up from 85.4% the prior week, and the highest refinery utilization rate in 58 weeks, reflecting the refinery utilization level during the last week before the pandemic related refinery slowdown…while the 15,243,000 barrels per day of oil that were refined this week were 17.4% higher than the 12,976,000 barrels of crude that were being processed daily during the week ending May 1st of last year, they were still 7.1% below the 16,405,000 barrels of crude that were being processed daily during the week ending May 3rd, 2019, when US refineries were operating at a still low 88.9% of capacity…

Even with this week’s increase in the amount of oil being refined, the gasoline output from our refineries decreased by 483,000 barrels per day to 9,146,000 barrels per day during the week ending April 30th, after our gasoline output had increased by 243,000 barrels per day over the prior week…while this week’s gasoline production was 36.4% higher than the 6,705,000 barrels of gasoline that were being produced daily over the same week of last year, it was still 8.3% lower than the March 13th 2020 pre-pandemic high of 9,974,000 barrels per day, and 9.7% below the gasoline production of 10,129,000 barrels per day during the week ending May 3rd, 2019….meanwhile, our refineries’ production of distillate fuels (diesel fuel and heat oil) decreased by 128,000 barrels per day to 4,498,000 barrels per day, after our distillates output had increased by 71,000 barrels per day over the prior week… and since the onset of the pandemic last year didn’t appear to impact distillates’ production, this week’s distillates output was still 11.5% lower than the 5,082,000 barrels of distillates that were being produced daily during the week ending May 1st, 2020…

Despite the decrease in our gasoline production, our supply of gasoline in storage at the end of the week increased for the nineteenth time in twenty-five weeks, and for 23rd time in 43 weeks, rising by 737,000 barrels to 235,811,000 barrels during the week ending April 30th, after our gasoline inventories had increased by 92,000 barrels over the prior week...our gasoline supplies managed to increase again this week because the amount of gasoline supplied to US users decreased by 13,000 barrels per day to 8,864,000 barrels per day and because our exports of gasoline fell by 49,000 barrels per day to 555,000 barrels per day while our imports of gasoline fell by 1,000 barrels per day to 1,020,000 barrels per day….but even after five straight inventory increases, our gasoline supplies still were 8.0% lower than last May 1st’s gasoline inventories of 256,407,000 barrels, and about 2% below the five year average of our gasoline supplies for this time of the year…

With the decrease in our distillates production, our supplies of distillate fuels also decreased for the 10th time in 20 weeks and for the 24rd time in thirty-six weeks, falling by 2,896,000 barrels to 136,153,000 barrels during the week ending April 30th, after our distillates supplies had decreased by 3,342,000 barrels during the prior week….our distillates supplies fell by a bit less this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, fell by 205,000 barrels per day to 4,125,000 barrels per day, while our imports of distillates rose by 34,000 barrels per day to 68,000 barrels per day, and while our exports of distillates rose by 48,000 barrels per day to 956,000 barrels per day….after four consecutive inventory decreases, our distillate supplies at the end of the week were 10.1% below the 151,490,000 barrels of distillates that we had in storage on May 1st, 2020, and about 2% below the five year average of distillates stocks for this time of the year…

Finally, with the drop in our oil imports and the big jump in our oil exports, our commercial supplies of crude oil in storage fell for the 14th time in the past twenty-five weeks and for the 27th time in the past year, decreasing by 7,990,000 barrels, from 493,107,000 barrels on April 23rd to 485,117,000 barrels on April 30th….after this week’s decrease, our commercial crude oil inventories fell to about 2% below the most recent five-year average of crude oil supplies for this time of year, but were still about 37.3% above the average of our crude oil stocks as of the end of April over the 5 years at the beginning of this decade, with the disparity between those comparisons arising because it wasn’t until early 2015 that our oil inventories first topped 400 million barrels….since our crude oil inventories had jumped to record highs during the Covid lockdowns of last spring, our commercial crude oil supplies as of April 30th were 9.1% less than the 532,221,000 barrels of oil we had in commercial storage on May 1st of 2020, but still 4.0% more than the 466,604,000 barrels of oil that we had in storage on May 3rd of 2019, and also 11.8% more than the 433,758,000 barrels of oil we had in commercial storage on May 4th of 2018…

This Week’s Rig Count

The US rig count rose for the 30th time over the past 34 weeks during the week ending May 7th, but is still down by 43.5% from the pre-pandemic rig count….Baker Hughes reported that the total count of rotary rigs running in the US was up by 8 to 448 rigs this past week, which was also up by 74 rigs from the pandemic hit 374 rigs that were in use as of the May 8th report of 2020, but was still 1,481 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 their first attempt to put US shale out of business….

The number of rigs drilling for oil was up by 2 to 344 oil rigs this week, after falling by 1 the prior week, thus giving us 52 more oil rigs than were running a year ago, but still just 21.4% of the recent high of 1609 rigs that were drilling for oil on October 10th, 2014….at the same time, the number of drilling rigs targeting natural gas bearing formations was up by 7 to 103 natural gas rigs, the biggest gas rig jump since March 2018, which was also up by 23 natural gas rigs from the 80 natural gas rigs that were drilling a year ago, but still just 6.6% of the modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008….however, the so-called “miscellaneous” rig that had been drilling in Lake County, California was pulled out this week, leaving just a horizontal rig in the Permian basin in Midland county Texas that was classified as ‘miscellaneous’ this week, compared to the “miscellaneous” rig count of two a year ago..

The Gulf of Mexico rig count was unchanged at 13 rigs this week, with 12 of those rigs now drilling for oil in Louisiana’s offshore waters and 1 rig continuing to drill for oil in Alaminos Canyon offshore from Texas…that was 2 fewer Gulf of Mexico rigs than the 15 rigs drilling in the Gulf a year ago, when all 15 Gulf rigs were drilling for oil offshore from Louisiana…since there are no rigs operating off of other US shores at this time, nor were there a year ago, this week’s national offshore rig totals are equal to the Gulf rig counts…meanwhile, in addition to those rigs offshore, a rig continues to drill through an inland lake in St Mary parish Louisiana, matching the “inland waters” rig count of one a year ago…

The count of active horizontal drilling rigs was up by 10 to 408 horizontal rigs this week, which was also up by 70 rigs from the 338 horizontal rigs that were in use in the US on May 8th of last year, and less than a third of the record of 1372 horizontal rigs that were deployed on November 21st of 2014….meanwhile, the directional rig count was unchanged at 23 directional rigs this week, which was still down by four from the 27 directional rigs that were operating during the same week a year ago….at the same time, the vertical rig count was down by 2 to 17 vertical rigs this week, but those were up by 8 from the 9 vertical rigs that were in use on May 8th of 2020….

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 May 7th, the second column shows the change in the number of working rigs between last week’s count (April 30th) and this week’s (May 7th) count, the third column shows last week’s April 30th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running on the Friday 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 May, 2020..

From the tables above, it’s not entirely obvious where that 7 rig increase in natural gas rigs was this week….checking first for the details on the Permian basin in Texas from the Rigs by State file at Baker Hughes, we find that that three oil rigs were added in Texas Oil District 8, which is the core Permian Delaware, that two oil rigs added in Texas Oil District 7C, which encompasses the southern counties of the Permian Midland, and that another oil rig was added in Texas Oil District 8A, which includes the northern counties of the Permian Midland, while the last oil rig remaining in Texas Oil District 7B, which includes furthest east counties of the Permian Midland, was pulled out, thus accounting for the national Permian basin 5 rig increase…elsewhere in Texas, we had a natural gas rig added in Texas Oil District 1, and two oil rigs pulled out of Texas Oil District 2, all of which had to be Eagle Ford rigs, to account for both the increase of one gas rig and the loss of two oil rigs in the Eagle Ford, which now has 31 oil rigs and two gas rigs deployed…in addition, a natural gas rig was added in Texas Oil District 6, accounting for one of the Haynesville shale rigs seen above, whiile the other three Haynesville rigs were added in northern Louisiana…thus to get to our 7 natural gas rigs, we have the 4 that were added in the Haynesville shale, the gas rig that was added in the Eagle Ford, the gas rig that was added in Pennsylvania’s Marcellus, and a natural gas rig that was added in a basin that Baker Hughes doesn’t track, which could have been in Utah, since that’s the only obvious rig addition we haven’t accounted for yet…

Overview of Recent Nationwide Permit Program Changes –National Law Review (excerpts):

• Ohio EPA Waived Water Quality Certifications: Under Section 401 of the CWA, a federal agency may not issue a permit, such as a NWP, to conduct any activity that may result in any discharge into waters of the United States unless a Section 401 water quality certification (“WQC”) is issued by a certifying authority such as the Ohio EPA. The certifying authority must timely verify compliance with water quality requirements, or its certification right is waived. A WQC can be waived expressly or by failure to act on a certification request within a reasonable period of time provided by the Corps. The Corps, in a Public Notice issued on March 8, 2021, took the position that the State of Ohio Section 401 WQC has been waived for the newly issued NWPs. Ohio EPA received a request for certification under Section 401 of the CWA for the proposed issuance the NWPs in October of 2020 with 60 days to respond. Ohio EPA did not respond until March 4, 2021. In its WQC, Ohio EPA provided that “any lowering of water quality in various waters of the state as authorized by these certifications is necessary;” meaning that impacts to waters of the state of Ohio may occur pursuant to activities authorized by the NWPs subject to specified conditions. However, at this point in time, the specified conditions do not apply to NWPs issued for activities in Ohio. Activities that meet the conditions of the current NWPs do not require an individual Ohio Section 401 WQC. Therefore, anyone applying for coverage under the newly issued NWPs need only apply for, obtain coverage under, and comply with the federal NWP requirements. Ohio EPA’s currently waived WQC for the newly issued permits can be found here.
• Ohio EPA Issues General Permit to Protect Ephemeral Streams and Isolated Wetlands No Longer Protected by the Clean Water Act: On April 21, 2020, the United States Environmental Protection Agency and the United States Army Corps of Engineers (“Corps”) published the Navigable Waters Protection Rule (“NWPR”) in the Federal Register. The NWPR finalized a revised definition of “waters of the United States” under the Clean Water Act (“CWA”) and replaced the 2015 Clean Water Rule which previously defined the term. The definition of “waters of the United States” in the CWA controls permitting and regulatory requirements for waterbodies that fall within that definition. While individual states normally have the authority to stop a federal agency from issuing a permit for a project that does not comply with that state’s additional requirements in their Water Quality Certification (“WQC”), the NWPR potentially left unprotected the estimated 36,000 miles of ephemeral streams in Ohio. In response, the Ohio Environmental Protection Agency (“Ohio EPA”) issued the Ohio General Permit for Filling Category 1 and 2 Isolated Wetlands and Ephemeral Streams (“General Permit”) on June 25, 2020. Ohio EPA cited Ohio Revised Code (“ORC”) ff 6111 as its source of authority to regulate the filing of and discharges into these waterbodies in Ohio that are now explicitly excluded from the CWA. A 2017 letter concerning the proposed changes to the NWPR provides a basis for Ohio EPA’s current actions. Ohio EPA stated: Due to the broad definition and prohibitions in ORC 6111, ephemeral and intermittent streams would be protected, but there would be no permitting mechanism to allow the placement of dredge and fill material similar to the 404/401 permitting mechanism. The 401 program in Ohio is dependent on the 404 process, so if certain streams were considered not a water of the US (non-jurisdictional), then a 401 WQC could not be issued for placement of dredge and fill material.

Rep. Baldridge fights for pipeline, jobs in Michigan visit –An Ohio lawmaker went on the road to try to convince Michigan officials to abandon plans to force the shutdown of a fuel pipeline that could cost jobs in the Buckeye State. Rep. Brian Baldridge, R-Winchester, testified last week before the Michigan Senate’s Energy Committee and met with the state’s Senate leadership in response to the recently adopted Ohio Resolution 13, which urged Michigan to keep the Enbridge Line 5 pipeline operating. “I drove to Michigan for one reason: to protect Ohio jobs,” Baldridge said. “We cannot allow a political decision to get in the way of hardworking Ohioans providing for their families. House Resolution 13 would keep Line 5 safely operating and protect Ohio jobs and protect the Great Lakes Region’s shared economy.” A shutdown affects jobs and fuel availability in the region, according to Enbridge, leaving Ohio, Pennsylvania and Michigan and Canadian provinces Ontario and Quebec with a 14.7-million-U.S.-gallons-a-day supply shortage of gas, diesel and jet fuel. That represents about 45% of the current supply. A shutdown could cause the loss of $5.4 billion in economic output to Ohio and southeast Michigan, the company said. Michigan Gov. Gretchen Whitmer, Michigan Attorney General Dana Nessel and Michigan Department of Natural Resources Director Dan Eichinger filed a lawsuit Nov. 13 in Ingham County Court demanding Enbridge cease Line 5 operations by May 2021. The easement has been in place since 1953. The Line 5 pipeline services two Oregon refineries in northwest Ohio. According to Ohio officials, closing the line would cause a significant disruption in the supply chain, which serves as a source of jet fuel for several regional and international airports, particularly in Cleveland and Detroit. Whitmer and Eichinger said the administration’s actions are based on what they are characterizing as Enbridge’s violation of the public trust doctrine, which protects the state’s natural resources.Among the violations cited by the governor are “the unreasonable risk that continued operation of the dual pipelines poses to the Great Lakes,” according to a November news release. Whitmer cited events in April 2018 and another in 2019 in which Line 5 was damaged.

Cabot, Southwestern Remain Disciplined in 1Q, Despite Jump in Prices –Appalachian heavyweights Cabot Oil & Gas Corp. and Southwestern Energy Co. stayed in maintenance mode during the first quarter of 2021, keeping production flat and delivering free cash flow (FCF) in line with plans for the period. Both companies reported an increase in average realized prices during the quarter, but that didn’t prompt them to change course as Appalachian operators have scaled back in recent years amid volatile commodity prices and calls for better returns from investors. Cabot produced 2.29 Bcfe/d during the quarter, all of it natural gas produced solely in Susquehanna County, PA. That was down slightly from 2.36 Bcfe/d in 1Q2020. But the company had guided for a drop during the period given a decrease in operating activity and capital spending during the second half of 2020. Cabot’s full-year guidance remains unchanged at 2.23-2.28 Bcfe/d, but CEO Dan Dinges said production wouldn’t begin ramping up until later this year. “Our production guidance for the second quarter implies a slight sequential decline relative to the first quarter, which is a result of lower activity levels and capital spending during the winter season,” Dinges said. “Activity levels are expected to increase in the second and third quarters, resulting in sequential growth during the second half of the year, primarily during the fourth quarter in anticipation of higher natural gas prices and the in-service of the Leidy South expansion project.” Transcontinental Gas Pipe Line LLC’s Leidy South would carry about 600 MMcf/d from Pennsylvania to Atlantic Seaboard markets. Partial capacity on the system was brought online late last year. . The company reported net income of $126.4 million (32 cents/share), compared to a profit of $53.9 million (14 cents) in 1Q2020. Southwestern has similar plans for 2021, announcing guidance late last year to keep 4Q2021 production flat with 4Q2020 levels, including the assets ittook in the acquisition of Appalachian pure-play Montage Resources Corp. that was completed last November. The company had a stronger start to the year, though, reporting 269 Bcfe of production, which consisted of 79% natural gas, 17% natural gas liquids and 4% oil. That’s up from 201 Bcfe in the year-ago period. The company’s Southwest Appalachia division accounted for 151 Bcfe of 1Q2021 volumes, while its Northeast Appalachia division, where volumes are drier, produced 118 Bcf. Southwestern in the first quarter drilled its first Utica Shale well in Ohio after entering the state with the Montage acquisition. COO Clay Carrell said the well is currently being completed and is expected to come online this quarter. The company has 12-15 Utica wells planned for this year, Carrell said, adding that “we get the incremental benefit from that program of now consistently drilling Utica wells and all the learning that’s going to come from that.”

Gas industry slowdown hurting western Pa. economy, taxpayers – For the past decade, the natural gas industry has boomed in Western Pennsylvania. But the industry is facing tough times now, and that is having a major impact in communities where the industry has a large presence. Advertisement Waynesburg was the center of the natural gas boom but you wouldn’t know it these days. A downtown building hosting a Welcome to Greene County sign is for sale. Other buildings are seeking renters as stores shut down. Area leaders said it’s not just the pandemic causing the slowdown. “It used to be if you sat on the sidewalk in Waynesburg you’d see water trucks and sand hauling trucks just lined up going through there and that is no longer the case,” said County Commission Chairman Mike Belding. In late 2014, records show the natural gas industry employed 33,181 people in Pennsylvania. But by late 2020, that number had dropped by 30 percent to 23,360. From 2017 to 2020, the number of new wells statewide dropped by nearly half from 810 to 476. That’s had an impact on other businesses that relied on the gas industry. At Lavern’s Restaurant outside Waynesburg, Action News Investigates caught up with former Greene County Sheriff Richard Ketchem. After leaving office he oversaw security for a trucking company that serviced the gas industry. “For a while when I was running the agency they wanted guys all the time to check the wells, go around well sites. There’s none of that anymore,” said Ketchem, who lost his job before the pandemic. “We had five companies there, almost 1,100 people, and they all got laid off,” he said. The downturn has also hurt people who own gas leases, like Bill Schamp of Greene County. His lease paid up to $5,000 per year but no more. Five years later we’re supposed to renew it and it’s 17-18 acres of property and they just never called me back, let the lease expire,” Schamp said. “A few people I know were getting $40,000 to $50,000 a month, and they built new houses, bought new cars and trucks, then it dried up and now they’re going into foreclosure.” The county also spent freely during the boom, according to Belding who took over last year. He said his predecessors used millions of dollars in gas impact fees to plug budget holes. “We inherited a 2020 budget that was passed in 2019 with a $5 million budget deficit out of a $40 million budget. Because of that, we ended up raising taxes,” . Marcellus Shale Coalition president David Callahan said the pandemic is part of the reason, but a much bigger factor is the sharp drop in the price of natural gas. “All commodity industries are cyclical. We’re very very reactive to prices. Low price means more supply on the market and the industry responds to those market signals,”

Why EQT’s making a $3B deal to purchase a top-10 Pa. driller –EQT Corp. is already the country’s largest independent natural gas producer, with its footprint mostly in the tri-state area south of Pittsburgh in what is one of the Marcellus Shale’s two most prolific gas fields. With the pending $2.9 billion acquisition of Alta Resources Development LLC that was announced Thursday, EQT will be getting something new: a hefty chunk of wells and acreage in the Marcellus’ other center of development, northeastern Pennsylvania. The two companies together will not only be the largest producer of Marcellus and Utica shale gas but that much bigger in the overall national picture. EQT (NYSE: EQT) is already producing 4.9 billion cubic feet per day of natural gas, well above its next-nearest competitor, Exxon Mobil and its new Marcellus Shale neighbor, Cabot Oil & Gas Corp. Adding in Alta’s 1 billion cubic feet per day will give EQT almost 6 billion cubic feet a day. Or, put another way, it’ll bring together the No. 1 and No. 8 drillers in Pennsylvania, according to the 2021 Pittsburgh Business Times Book of Lists. EQT has 1,985 wells across mostly southwestern Pennsylvania while Alta Resources has 499 wells in Centre, Clinton, Lycoming and Sullivan counties. And EQT CEO Toby Z. Rice told analysts on Thursday’s first-quarter analyst call that the company is already thinking of all the opportunities that an EQT-Alta combination provide. “We have the ability to shape the portfolio, to continue to optimize it and still benefit from the commercial opportunities that present themselves that I do believe are starting to become apparent and unique to EQT, what you get from managing such a large production base,” Rice said. That 6 billion cubic feet of natural gas won’t just be going to EQT’s traditional markets but also to other markets in the Northeast where the Pittsburgh-based driller didn’t normally have a pipeline to sell gas into. The assets are a combination of operated by Alta and a portion that’s operated in a deal with Chesapeake Energy Corp. (NYSE: CHK). EQT plans to have one rig drilling enough to keep production steady on its operated side; it’s still to be seen what it will be drilling in conjunction with Chesapeake. The operated and nonoperated assets are about 50% each of the acquisition. Alta’s assets were built from another top-tier driller, Anadarko. Rice said EQT plans to add the Alta assets to its combo development strategy, a highly choreographed and efficient plan to drill and complete wells that Rice Energy used during its time as a company and EQT under Rice has also used. EQT will keep Alta’s key personnel and its own chiefs of drilling and production have experience in northeastern Pennsylvania.

The Supreme Court Case That Could Change Everything For U.S. Pipelines – A Supreme Court hearing began this week that could seal the future fate of gas pipelines across the United States. It could also change the balance of power between federal and state authorities in a way that federal authorities would hardly like. The case involves the proposed PennEast pipeline, a 120-mile, 1-billion-cu-m piece of infrastructure that will take natural gas from the Marcellus shale across Pennsylvania and New Jersey. New Jersey is opposing the pipeline. PennEast and FERC want to use eminent domain to condemn the state and private land they need to build the infrastructure.On the face of it, it is a simple case – just another pipeline dispute of the sort that has been enjoying growing popularity among environmentalist groups and politicians in the past few years. In this case, the politicians want to stop PennEast from receiving easements for 40 parcels of federal land. The only way for PennEast to receive these easements, then, is to sue New Jersey. What makes this case different is that its outcome could have major implications for the industry.As Forbes’ Christopher Hellman explained in an article from earlier this week, the argument of the New Jersey political pipeline opponents is that under the 11thAmendment to the Constitution, states have sovereign immunity against lawsuits brought against them by private parties such as companies. In other words, PennEast simply has no right, under the Constitution of the United States, to sue New Jersey’s politicians on the pipeline issue.A counter-argument, used by a district court in 2018 to rule in favor of the natural gas project, is that PennEast is not acting on its own with its plans to carry 1 billion cubic meters of natural gas across two states. It is acting, the court ruled, under the auspices of a government authority: the Federal Energy Regulatory Commission.Forbes’ Hellman notes this was not a first, either: since the passing of the Natural Gas Act in 1938, FERC has on more than one occasion delegated its powers to invoke eminent domain to energy companies. From PennEast’s perspective, then, since federal power supersedes state power and since FERC has approved the New Jersey pipeline, it has every right to sue the state for that land.New Jersey appealed the district court ruling, and the appeals court found in its favor. It said that the state had sovereign immunity against lawsuits brought against it by private entities such as PennEast, noting that the power to invoke eminent domain as delegated to it by FERC was a completely different matter from its right to sue a state.“Thus, the federal government’s ability to condemn State land … is, in fact, the function of two separate powers: the government’s eminent domain power and its exemption from Eleventh Amendment immunity,” the U.S. Court of Appeals for the 3rd Circuit said in its decision. “A delegation of the former must not be confused for, or conflated with, a delegation of the latter.”

Williams Q1 Earnings Beat Estimates, Increase Y/Y –The Williams Companies, Inc. WMB reported first-quarter 2021 adjusted earnings per share (EPS) of 35 cents, beating the Zacks Consensus Estimate of 28 cents as well as the year-ago quarter’s earnings of 26 cents.This outperformance can be attributed to higher-than-expected contributions from its two segments. Precisely, adjusted EBITDA from the West and the Northeast G&P units totaled $315 million and $402 million each, ahead of their respective Zacks Consensus Estimate of $247 million and $397 million.Also, for the quarter ended Mar 31, the company’s revenues of $2.61 billion beat the Zacks Consensus Estimate by 22.71% and also increased from the year-ago figure of $1.9 billion.Adjusted EBITDA was $1.4 billion in the quarter under review, reflecting an increase of 12.1% from the corresponding period of 2020. Cash flow from operations totaled $915 million compared with $787 million in the prior-year period. Favorable net working capital changes drove cash flow in the quarter. Segmental Analysis

• Transmission & Gulf of Mexico: Comprising Williams’ massive Transco pipeline system and the Northwest Pipeline, the segment generated adjusted EBITDA of $660 million, lower than the year-ago quarter’s $669 million. Despite marginal gains in service revenues, commodity margins and investee EBITDA, the unit’s performance was offset by higher operating and administrative expenses.
• West: This segment includes gathering and processing assets in the Western region of the United States. It delivered adjusted EBITDA of $315 million, which is 45.8% higher than $216 million recorded in the year-earlier quarter. The improved results were driven by higher product marketing margins resulting from elevated prices and the absence of prior-year inventory effects plus lower operating and administrative expenses.
• Northeast G&P: Engaged in natural gas gathering and processing along with the NGL fractionation business in Marcellus and Utica shale regions, the segment generated an adjusted EBITDA of $402 million, up 8.7% from the prior-year quarter’s $370 million. Increased gathering volumes on its Bradford and Marcellus South systems and higher equity-method investments contributions drove the results.

Invenergy proposed natural gas-fired plant questioned in Pennsylvania – Residents and concerned citizens questioned the chief engineer of the Allegheny County Health Department’s permitting section about potential emissions for a proposed natural gas-fired power plant that a Chicago company wants to build along the Youghiogheny River in Elizabeth Township. Invenergy first proposed in 2016 building the 639-megawatt Allegheny Energy Center power plant in Elizabeth Township. But the township turned down the proposal, as was a proposed rezoning from rural residential to light industrial to allow the plant at a different location along the river and near the Great Allegheny Passage Bike Trail in 2017. But another rezoning proposal made in 2018, to allow a power plant on the 147-acre site, was approved. Work hasn’t begun on the process nor has Invenergy applied for a land-use permit to begin construction. Invenergy has, however, applied to the ACHD for an air-quality permit. The meeting brought out residents from Elizabeth Township as well as the Westmoreland County towns across the river from the plant site. It was sponsored by the Mountain Watershed Association, whose Executive Director Ashley Funk said there are concerns about how close it is to the Youghiogheny River and the bike trail as well as the environmental impact on the communities of West Newton and Sutersville. Both meet the standard of at least 20% low-income residents. “We also want to take into account that this region has a significant amount of source polluters,” Funk said. It’s seven miles from U.S. Steel Clairton, the county’s largest emitter, and about six miles from another natural gas-fired power plant in Smithton. The March 21 draft permit recommends approval of the air quality permit. JoAnn Truchan, ACHD’s section chief of engineering, said the plant has to meet federal guidelines for air emissions and also that it must have the best control technology for emissions without regard to cost to the company. “This permit meets that (federal environmental standards),” Truchan said. According to a draft air-quality report from ACHD, the plant will emit nitrogen oxide, carbon monoxide and volatile organic compounds. It will have emissions limits as set out by the installation permit, and will be required to perform monitoring and testing for those emissions as well as particulate matter. Some residents noted the other air emissions in the region and wondered if it were better to focus on cutting down other pollution sources before approving a new plant.

Residents protest approval of power plant in Keasbey – A group of concerned citizens attended the Woodbridge Township Council meeting on May 4 to voice concern about, and protest, the board’s approval of a new 630-megawatt gas-fired power plant in the Keasbey section of town. The plant would be the second of its kind in the township. The CPV Woodbridge Energy Center (CPV Woodbridge) is a 725-megawatt combined-cycle gas power generation facility that began operations in January 2016. The power plant is located on Riverside Drive on the site of an abandoned chemical plant that became the Brownfields Development Area (BDA) in 2009. The New Jersey Department of Environmental Protection’s (DEP) Brownfield Remediation and Reuse Element established a BDA initiative in order to work with selected communities affected by multiple brownfield sites to design and implement remediation and reuse plans for the abandoned and unused properties. Benefits included access to various grants from the DEP of up to $5,000,000 per year. With that incentive in mind, and so much abandoned space in the community, township officials identified multiple sites in Keasbey to be considered for such projects of redevelopment, officials said. According to the activist group EmpowerNJ, the developer’s application indicates that “the plant would pour millions of tons of greenhouse gases and significant quantities of toxic poisonous chemicals every year that will negatively affect the health of residents in Central Jersey and Staten Island.”Although the plans for the new facility have already been approved by Woodbridge Township, final approvals are yet to be received from the DEP.

New York advisory panel recommendations to include gas-fired plant moratorium – New York’s Power Generation Advisory Panel will recommend a moratorium against new fossil fuel-fired plant construction to the state’s Climate Action Council, the panel’s chair said May 3. The concept of a moratorium has been included as a recommendation, though consensus on it was not reached among all panel members, said Sarah Osgood, panel chair and director of policy implementation at the ‎New York State Department of Public Service, during a remotely held meeting of the panel. “We had presented at our last meeting that there was a concept of a moratorium on new and repowered gas facilities and that has been incorporated as a component of a recommendation,” Osgood said. Based on public comments, there was generally broad support for the advisory panel’s agenda with “lots of support for energy efficiency and renewables as well as energy storage” and a lot of calls for equity and urgency of action, Osgood said. There was some concern with the pace of renewable energy project build-out and requests for earlier engagement with local communities when planning renewable energy projects, according to a presentation given during the meeting. The panel is preparing to present its recommendations to the state’s Climate Action Council on May 10. The CAC is charged with developing the rules and regulations that will guide the implementation of the Climate Leadership and Community Protection Act which mandates an emissions-free power system by 2040, among numerous other goals. Other key topics regarding the panel’s recommendations identified by commenters were around the role of nuclear power and natural gas infrastructure in New York’ energy transition. Most commenters were evenly split between pro- and anti-nuclear power. Those in favor of the power source pointed to the benefits of its emissions-free baseload generation, contribution to power grid reliability and it being a preferred alternative to building out gas-fired power plants that would increase carbon dioxide emissions, according to the presentation. Those against nuclear power highlighted health and safety concerns associated with radiation and spent fuel rod storage while expressing a preference for supporting renewable energy instead.Most commenters called for preventing continued gas infrastructure build out, specifically regarding new power plant construction. Many also said there should be a plan to phase out existing gas-fired power plants with a priority on closing peaking facilities around New York City, the presentation said. Feedback also focused on the inconsistency of expanding gas infrastructure with the state’s greenhouse gas emissions reduction goals, as well as the negative impacts fossil fuel infrastructure can have on communities. Many said they would prefer investments are made in renewable energy, energy storage and power transmission that can replace the need for gas-fired generation.

Over 60% of natural gas pipeline extension completed in Salisbury – The pipeline grows. The Salisbury City Council heard the latest update Monday evening on a controversial natural gas pipeline set to extend service to Somerset County. The Del-Mar Energy Pathway pipeline will extend natural gas service to Eastern Correctional Institution and the University of Maryland Eastern Shore, as both anchors look to transition off more polluting fuels.Chesapeake Utilities Corp. got the unanimous green light from the Maryland Board of Public Works in January for the $34 million project, which will add nearly seven miles of 10-inch-diameter gas pipeline from Delaware, through Wicomico County and into Somerset County. “Residents and businesses along the line will soon have the choice to use environmentally beneficial and less expensive natural gas service,” wrote Justin Mulcahy, spokesman for Chesapeake Utilities Corp., in a statement that month, “something elected officials and community members have advocated for more than two decades.”That line includes a section running through Salisbury, along Route 13. “They’re at approximately 64% complete with the pipeline installation to-date,” Ongoing construction activities remain at various locations, and horizontal drilling for installation under the South Prong of the Wicomico River was completed in February.

Emissions concerns, job hopes share center stage during meeting on proposed Pleasants County methanol facility – Environmentalists objected to and county and union officials welcomed an application to build a $350 million natural gas-to-methanol facility in Pleasants County during a public meeting that West Virginia environmental regulators held Tuesday evening.The state Department of Environmental Protection’s Division of Air Quality held the meeting virtually to take comments and answer questions about the application from West Virginia Methanol, Inc., which applied in November to construct the plant off Route 2 between Belmont and St. Marys near the Ohio River on the site of the former Cabot Corporation carbon black manufacturing facility.Six out of 10 speakers who commented on the application during the meeting expressed concern about the planned facility, which would produce about 1,000 tons of methanol from natural gas daily.The Department of Environmental Protection had already announced its preliminary determination to issue a permit for the facility prior to the meeting.But representatives of Concerned Ohio River Residents, a group opposed to petrochemical development in the Ohio Valley, the Ohio Valley Environmental Coalition, the Sierra Club and the West Virginia Rivers Coalition said that West Virginia Methanol should have to go through a more extensive permitting review process. Environmental regulators did not perform any air quality impact modeling analysis since the proposed facility’s estimated maximum emissions are less than applicability thresholds that would define the facility as “major” under a state legislative rule adopted in accordance with the federal Clean Air Act.The proposed facility does not have the potential to emit more than 100 tons per year of any regulated pollutant according to the permit application, meaning that it is not subject to a state legislative rule that would require a full environmental impact statement and consideration of greenhouse gases and non-air quality impacts, including potential impacts on property values, traffic, zoning and national energy issues.But the facility is close to meeting that threshold in potential to emit nitrous oxides (92.98 tons per year) and carbon monoxide (91.76 tons per year), which those wary of the project contended is close enough to subject the permit application to the more rigorous review process. “If you don’t, there will be a human toll,”

2 arrested after Giles County pipeline protest – Last November, Thomas Adams was elected to the board of the Skyline Soil and Water Conservation District, which protects the natural resources of the New River Valley. On Friday, he chained himself to a truck involved with the construction of the Mountain Valley Pipeline, which opponents say is ruining those same natural resources. Adams, a former hydrologist with the National Weather Service, was arrested after he refused to leave. The 68-year-old Blacksburg resident was charged with abduction, unauthorized use of a vehicle and obstruction of free passage, according to Virginia State Police. Police were called about 10:30 a.m. to Brickyard Road in the Maybrook area of Giles County, where they saw a crowd of people blocking the road. They also found a man lying beneath a tractor-trailer, attached to its underside with what’s called a sleeping dragon. Specially trained troopers dismantled the lock-box device and removed Adams, who was then checked by paramedics before being taken to a magistrate. “Many will ask: why have I chained myself to a truck carrying pipe for the Mountain Valley Pipeline?” Adams said in a statement released by Appalachians Against Pipelines. “I had no choice.” “I know what looms before us if we continue down the path with our obsessive use of fossil fuels. As a scientist and engineer who has been active in the field of water resources and hydrometeorology in the U.S. and internationally, working on issues related to climate change and global warming, I believe the science,” he said.

Pipeline opponents sentenced to spend day in jail for each day in tree-sit protest – Two nonviolent protesters must serve a day in jail for every day they spent in tree stands blocking the path of the Mountain Valley Pipeline, a Montgomery County judge ruled Wednesday.For Alexander Samuel Parker Lowe, who occupied the so-called Yellow Finch tree-sit from Nov. 16, 2020, to when he was removed by state police March 24, that worked out to a 254-day jail sentence.For Claire Marian Fiocco, who went up in a tree Jan. 3 and was extracted March 23, the sentence was 158 days.The case pitted the tree sitters’ right to protest a controversial natural gas pipeline against Mountain Valley’s legal authority to cut trees and plow a trench for its buried pipe through a forest near Elliston.“There’s nothing wrong with peaceful protest,” Chief Deputy Commonwealth’s Attorney Patrick Jensen argued. “But the rule of law does not cease to exist just because people disagree with what the pipeline was legally entitled to do.”After convicting the two of obstructing justice and interfering with Mountain Valley’s property rights, General District Judge Randal Duncan said he tried to “apply some common sense” in sentencing them on the misdemeanor charges.The jail sentences were actually double the time Lowe and Fiocco spent in the trees, but Duncan took into account a standard credit toward release of one day they will receive for each day served. Both have been held without bond since their arrests.

Criminal investigation of Mountain Valley Pipeline ends with no charges – A two-year criminal investigation of the Mountain Valley Pipeline has concluded with no charges filed.In a report filed Tuesday with the U.S. Securities and Exchange Commission, the lead partner in the project said it was informed last month that a federal investigation was completed, “without an adverse determination to the MVP joint venture.”Mountain Valley spokeswoman Natalie Cox said it was the company’s understanding that there was no finding of wrongdoing, and that no criminal or civil action would be taken.The case began more than two years ago with a complaint by Preserve Bent Mountain, a Roanoke County group that had been fighting the natural gas pipeline for years.Representatives for the group presented a large amount of evidence to the U.S. Attorney’s Office in Roanoke, asking it to investigate possible violations of the Clean Water Act and other federal laws.While Mountain Valley has repeatedly run afoul of administrative regulations meant to keep muddy runoff from contaminating nearby streams and rivers, a criminal charge would have carried a higher burden of proof.Brian McGinn, a spokesman for the U.S. Attorney’s Office, declined to comment Tuesday.Although federal prosecutors rarely confirm that an investigation is in progress, Mountain Valley was required to inform investors, through its SEC filings, of any potential risk to the company’s financial well-being.

Mountain Valley Pipeline delayed again as project cost keeps rising – The projected in-service date for the Mountain Valley Pipeline has been pushed back yet again. Equitrans Midstream Corp. announced Tuesday it was moving its targeted in-service date for the pipeline from the end of 2021 to the summer of 2022, a delay the company predicted would add at least $200 million to the now $6.2 billion project. The delay factors in more time that the primary developer of the pipeline slated to travel from Northwestern West Virginia to Southern Virginia says it will need to get water crossing permits for the project, which was originally scheduled for completion by the end of 2018 at a cost of just $3.5 billion. Diana Charletta, Equitrans Midstream president and chief operating officer, noted during the company’s first-quarter earnings call Tuesday that Mountain Valley Pipeline LLC, the joint venture that owns the pipeline, still has applications pending with West Virginia and Virginia state environmental regulators for about 300 water crossings while it seeks approval from the Federal Energy Regulatory Commission to tunnel under 120 additional waterbodies. The West Virginia Department of Environmental Protection last month asked for an additional 90 days beyond the 120 days the U.S. Army Corps of Engineers gave the agency to review Mountain Valley Pipeline LLC’s water permit request. But the Virginia Department of Environmental Quality in March requested an additional year to review the pipeline permit application. “Based on the complexity of this project and past public controversy, we cannot reasonably issue the [water] permit before December 2021 and we believe it is quite likely that we could not issue this permit until early 2022,” Melanie Davenport of the department’s water permitting division wrote to the Corps in March. West Virginia and Virginia state environmental regulators are still awaiting responses from the Corps, their spokespeople said Tuesday. Charletta said Equitrans Midstream’s targeted summer 2022 in-service date is based on receiving all water crossing approvals and the lifting of a remaining exclusion zone around Jefferson National Forest by the end of 2021. First announced in 2014, the 42-inch-diameter, 303-mile Mountain Valley Pipeline is slated to provide up to 2 billion cubic feet per day of natural gas from the Marcellus and Utica shale formations to markets in the Mid-Atlantic and Southeastern regions of the United States, traveling from Northwestern West Virginia to Southern Virginia.

Why Equitrans pushed back two pipeline in-service dates – Equitrans Midstream Corp.’s extended timeline to complete the Mountain Valley Pipeline by summer 2022 assumes the Canonsburg-based company gets the remaining approvals by the end of this year. Equitrans (told investors in its first-quarter earnings release that it had pushed back the MVP in-operation date to 2022 because it no longer expected to receive its permits in the previous time frame. That is due in part to Virginia and West Virginia regulators asking the U.S. Army Corps of Engineers for more time to review water permits that MVP needs. Equitrans President Diana Charletta said MVP supported and expects the additional time. That means Equitrans will need another winter season to finish the 303-mile pipeline that will take Marcellus and Utica shale natural gas to Virginia. The pipeline was originally supposed to be in service by the end of 2018 and cost between $3 billion and $3.5 billion, but the cost has steadily been increasing with court and regulatory delays. The estimate is now $6 billion, which is about $200 million more than previous due to what the company said was increased costs due to protecting the rights of way and shifting resources. Equitrans, which will operate the pipeline and own about half, expects to cover $3.1 billion of the cost. Construction on the pipeline resumed in March, and it’s expected to conclude much of it by September with only about 10 miles in water crossings and 8 miles in and near the Jefferson National Forest left to do. Charletta said the timeline assumed MVP would receive the water crossing approvals and a lifting of the Federal Energy Regulatory Commission stop-work order by the end of the year. It previously expected them by July. But even if that happens by the end of December, Equitrans executives said the winter would make it more difficult to complete. More likely the construction schedule will resume in March 2022 and be in service in the early summer, she said. It might still be possible if the company doesn’t get a permit until 2022. “We are not going to do a ton of work over the winter so that if one of those (permits) lags til first quarter we can still hit that same guidance range,” Charletta said. The construction work, instead of going on at the same time as planned, will now be done separately. CEO Tom Karam said the company was frustrated by having to keep a right of way open during the work before allowing the land to be permanently restored. “(Equitrans’ hope and objective is) getting the reviews done as quickly as possible, (with) FERC approval, so we can complete the project and permanently restore the right of way quickly and get off everyone’s property,” he said. “We think that is the most environmentally sound thing we can do right now.” The delay in the Mountain Valley Pipeline is spilling over to a related project, MVP Southgate. That 75-mile pipeline is designed to take the Marcellus and Utica shale gas down through the MVP and then in two counties in North Carolina. The $500 million extension has a commitment from Dominion Energy, but has twice been denied by North Carolina environmental regulators over concerns about the timeline for MVP itself. Southgate is now being planned for construction in 2022 and in service in spring 2023. That would put MVP Southgate about a year behind the previous schedule. “It would be midyear starting construction, that’s our plan right now,” Charletta said. “We want to make sure we get all of our permits and everything taken care of.”

PIPELINES: Moderate Dems join GOP in calling for faster permitting — Friday, April 30, 2021 –A collection of Senate Republicans and moderate Democrats called on the Federal Energy Regulatory Commission to expedite its review of 14 pending natural gas pipelines.

U.S. natgas futures climb to 10-week high on near record exports – U.S. natural gas futures climbed to a 10-week high on Monday on forecasts for near record exports. That price increase came despite forecasts for milder weather and less heating demand this week than previously expected. Front-month gas futures NGc1 rose 3.5 cents, or 1.2%, to settle at $2.966 per million British thermal units, their highest close since Feb. 19. That kept the front-month in overbought territory with a Relative Strength Index (RSI) over 70 for a sixth day in a row for the first time since November 2019. In the power market, meanwhile, the Electric Reliability Coordinator of Texas (ERCOT), the state’s grid operator, said late on Friday that there could be a reserve capacity deficiency Monday afternoon. That caused next-day prices for Monday at the ERCOT North hub EL-PK-ERTN-SNL to jump to $115 per megawatt hour (MWh), their highest since a February freeze when the grid ran short of power and ERCOT imposed rotating blackouts. Real-time prices in ERCOT, however, remained in the $10s and $20s per MWh on Monday and even fell into negative territory for several hours overnight.

June Natural Gas Futures Retreat Despite Favorable Inventory Result – Natural Gas Intelligence – Natural gas futures slipped lower for a second consecutive session on Thursday, despite a bullish government inventory print and continued robust demand for both U.S. liquefied natural gas (LNG) and pipeline exports. The June Nymex contract fell 1.0 cent day/day and settled at $2.928/MMBtu. The contract lost 2.9 cents on Wednesday. July shed eight-tenths of a cent to $2.974 on Thursday. NGI’s Spot GasNational Avg. declined 5.5 cents to $2.705. The prompt month has repeatedly bumped up against the $3.00 threshold in recent sessions but failed to close above it. Futures remain well off the 2021 high of $3.316 reached in February amid the spike in demand caused by Winter Storm Uri. However, they are well above the spring season low near $2.450 early last month. LNG feed gas levels approached 11.7 Bcf on Thursday, hanging close to record levels. Cool weather and waning supplies in Europe continue to fuel strong demand for U.S. exports. Demand from Asia remains elevated, too, analysts said. Refinitiv analyst Shuya Li, participating on The Desk’s online energy platform Enelyst, said cargo cancellations, a challenge amid the coronavirus pandemic in summer 2020, are unlikely this year with demand holding steady at lofty levels. U.S. pipeline exports to Mexico also are near record levels – regularly approaching 7 Bcf/d. “This summer, overall pipeline exports will be nearly 0.8 Bcf/d higher year-on-year,” Li estimated. Export activity helped keep overall natural gas demand solid during the week ended April 30, the period covered by the U.S. Energy Information Administration’s (EIA) latest storage report. The agency on Thursday posted an injection of 60 Bcf into storage for the week. The print came in a few ticks below expectations, but it failed to galvanize market support. Analysts on The Desk said traders likely noted that the result was four times greater than the week earlier injection and that it signaled larger injections to come in May. Early estimates for next week’s report were for builds in the 70s-80s Bcf. For this week’s print, estimates generated by Reuters and Bloomberg polls landed at medians of 65 Bcf, while a Wall Street Journal survey produced an average of 62 Bcf. NGI’s model predicted a 76 Bcf increase. Last year, EIA recorded a 103 Bcf injection for the similar week, and the five-year average is an 81 Bcf build. The build for the April 30 week lifted inventories to 1,958 Bcf, though the total was well below the year-earlier level of 2,303 Bcf and slightly below the five-year average of 2,019 Bcf. By region, the South Central build of 20 Bcf led all others. The Midwest and East regions followed closely with builds of 15 Bcf and 13 Bcf, respectively, according to EIA. Pacific inventories grew by 7 Bcf, while Mountain region stocks increased by 5 Bcf.

U.S. natgas futures rise on cooler forecasts next week (Reuters) – U.S. natural gas futures rose on forecasts for cooler weather and higher heating demand next week than previously expected. That lack of price movement came despite forecasts for milder weather in mid May, a small decline in exports and an even smaller increase in output so far this month. Front-month gas futures NGc1 rose 3.0 cents, or 1.0%, to settle at $2.958 per million British thermal units. For the week, the front-month was up over 1%, putting the contract on track for its fourth week of gains in a row for the first time since February. Data provider Refinitiv said gas output in the Lower 48 U.S. states averaged 90.8 billion cubic feet per day (bcfd) so far in May, up from 90.6 bcfd in April, but well below November 2019’s monthly record of 95.4 bcfd. Refinitiv projected average gas demand, including exports, would rise from 87.2 bcfd this week to 88.1 bcfd next week as temperatures decline before falling to 84.7 bcfd as the weather turns milder. The forecast for next week was higher than Refinitiv estimated on Thursday. The amount of gas flowing to U.S. LNG export plants averaged 11.4 bcfd so far in May, down from April’s monthly record of 11.5 bcfd. Buyers around the world continue to purchase near-record amounts of U.S. gas because prices in Europe and Asia remain high enough to justify the cost of buying and transporting the U.S. fuel across the ocean.

US working gas storage capacity increases marginally in 2020: EIA | S&P Global Platts – Although total US working gas storage capacity has remained mostly static in the last two years, strong production and less price volatility has reduced the need for investing into additional underground storage. US natural gas’ demonstrated peak storage capacity declined slightly year over year in 2020, while total working gas capacity increased marginally, according to the US Energy Information Administration’s annual storage report. “Working natural gas design capacity increased by 5 Bcf in the South Central region,” the report said. “The most notable increase in the region was the 4.2 Bcf gain reported for the Egan Storage Dome by Egan Hub Partners. Dewatering the salt cavern raised the capacity of this field.” Demonstrated peak storage capacity represents the highest amount of working gas recorded. Working natural gas design capacity means the maximum amount of working gas that could feasibly be injected into storage. Demonstrated peak capacity from December 2015 through November 2020 totaled 4.253 Tcf. The South Central region had the highest demonstrated peak capacity volume of 1.439 Tcf of all five regions. However, at 1.186 Tcf in the Midwest region, it was at 97% of maximum capacity compared with 93% reached in South Central. It was the second consecutive year in which Midwest stocks nearly reached peak capacity. Data by S&P Global Platts Analytics demonstrates the region is already showing strong injection activity early in the season. Injections in the first half of April averaged 1.4 Bcf/d, 399 MMcf/d above 2020 and the strongest for the time in at least six years. Temperatures, however, dropped later in the month and brought injections for the entire month to their weakest since 2017 at 1.4 Bcf/d. However, injections did ramp up at the end of the month, leading to another remarkable start to May injections, at 4.4 Bcf/d month to date. Platts Analytics expects this to mellow slightly, with an average of 4.1 Bcf/d this month, up roughly 700 MMcf/d year on year. The EIA report finds several trends in recent years have reduced the necessity for investing in new underground storage. Higher levels of natural gas production compared with a few years ago may have reduced some customers’ need to withdraw from storage to meet their natural gas needs. Gas price volatility has declined in recent years. The seasonal spread between summer and winter gas prices has shrunk, reducing economic incentives to inject supply into reservoir and aquifer storage. Also, midstream investment has enhanced grid interconnectedness and flexibility. However, growing demand in gas-fired power generation as well as ever-increasing exports via LNG terminals and pipelines to Mexico could increase the need for additional storage, especially in the South Central region. In April, exports to Mexico reached record levels just shy of 7 Bcf/d, Platts Analytics’ data shows. The record-setting volumes were accompanied by population-weighted temperatures in the upper 70s Fahrenheit, about 5 degrees above normal, and by a spike in electric cooling demand.

Eastern Kentucky oil refinery exceeds EPA emissions limit for cancer-causing chemical — An oil refinery in Eastern Kentucky exceeded federal emissions standards for a chemical known to cause cancer.According to a report by the non-profit watchdog group Environmental Integrity Project, Catlettsburg Marathon in Boyd County exceeded the U.S. Environmental Protection Agency’s benzene action level by 53% in 2020. The net concentration was 13.8 micrograms per cubic meter – the EPA’s action level is nine micrograms a year.In a one-year span, the concentration of benzene grew by 344% at Catlettsburg Marathon.The refinery has been a major polluter in the Tri-State area for decades, according to Robin Blakeman, an Ohio Valley Environmental Coalition organizer.Benzene is a carcinogen that can contribute to cancer of the blood cells and respiratory ailments. The report stated benzene is one of the most dangerous pollutants released by oil refineries and petrochemical plants.The EIP report documented high levels of benzene at 13 refineries, many of them surrounded by communities with high amounts of poverty. On average, 43% were in poverty and 57% were people of color.“We have President (Joe) Biden saying that environmental justice will be at the center of everything and we are suggesting today the administration start here,” said Eric Schaeffer, director of EIP. “This is a great place to start keeping that promise.”About 11,500 residents live within three miles of the Catlettsburg refinery, of that 45% are living below the national poverty level.“Unfortunately, due to high poverty levels in this area, the health risks of toxic chemicals like benzene are often ignored,” Blakeman said in a statement. “Once again, Appalachian communities are considered acceptable sacrifice zones.”

Byhalia Pipeline rally ahead of Memphis City Council vote – Boxtown and Westwood neighbors are continuing to put pressure on elected officials to stop the Byhalia Pipeline. Members of those communities rallied Saturday afternoon to continue bringing awareness to a potential health crisis that will affect many marginalized Memphis neighborhoods. On Tuesday, the Memphis City Council is expected to vote on a city ordinance that would limit new pipeline projects with oil or “hazardous” liquids from being built or expanded within city limits. Neighbors and critics, like Dr. Roz Nichols of Memphis Interfaith Coalition for Action and Hope are concerned if the pipeline project is approved by the Memphis City Council, it will contaminate the water in Memphis and parts of northern Mississippi. “We will remain steadfast, unmovable, always abounding in the work of justice determined to save what is ours,” Nichols said. Nichols said the predominantly Black and low-income communities that would be affected will not back down to the oil companies. “Boxtown is a community of people,” Nichols said. “They will not be silenced, they will not be overlooked, they will not be dismissed because they are people and people matter.” The Southern Environmental Law Center sent a letter to the state of Tennessee on Thursday urging them to stop the Byhalia Pipeline claiming it’s “unneeded.” It further claimed the Byhalia Pipeline did not disclose the existence of the Collierville Connection Pipeline, which would eliminate a need for a new one. “If the company had disclosed the Collierville Connection Pipeline, the Tennessee Department of Environment and Conservation (TDEC or Department) would have been required to evaluate it as an alternative to the construction of the Byhalia Connection Pipeline because the use of an existing pipeline or pipeline route has the potential to avoid and minimize new impacts on waters of the State, including streams, wetlands, and groundwater,” The Southern Environmental Law Center stated in the letter. “Use of an existing pipeline would also avoid impacts on residents along a new path.” Neighbors said they will not stop fighting for justice and a quality of life they think everyone deserves. “This fight is not over by a long shot!” Boxtown neighbor Batsell Booker said.

Charity or manipulation? Memphis nonprofits discuss, defend accepting donations from Byhalia Pipeline – – Byhalia Pipeline arrived in Memphis with gifts in one hand and plans for a crude oil pipeline in the other and called both community investments. But what is charity to the Texas corporation is manipulation to critics, who see it as a tactic to buy support and weaken opposition to the project.Byhalia Pipeline, a joint venture of Plains All American Pipeline and Valero Energy Corporation, has donated over $1 million to Mid-South community development corporations, church-affiliated groups and other nonprofit organizations over the past year. The proposed route of the Byhalia Connection Pipeline is through several Black Southwest Memphis communities that are already surrounded by polluting industries.(See which organizations kept donations from Byhalia Connection Pipeline, who returned the money and who didn’t respond.)Critics have called the plan environmental racism and say the route poses a risk to theMemphis Sand aquifer, where the city draws its water. Byhalia Pipeline disputes those assertions.Since the proposed project’s announcement in 2019, the company has formed a community advisory board and handed out donations to a range of organizations, including the NAACP Memphis Branch, Uplift Westwood CDC, the Mid-South Food Bank, the Memphis Library Foundation and a group building a memorial to Black journalist Ida B. Wells. There was no requirement to support the pipeline to receive the donation, officials of some organizations said.The NAACP and MCAP will host a rally against the pipeline at 2 p.m. Saturday at Alonzo Weaver Park, next to Mitchell High School, 658 W. Mitchell Road. Attendees should park at the school.But gifts with no apparent strings attached is a well-known tactic used by fossil fuel companies to manipulate communities, according to a reportreleased this month by the national NAACP Environmental and Climate Justice Program.“Co-opting can be used as a tactic to neutralize or weaken public opposition,” according to the second edition of “Fossil Fueled Foolery: An Illustrated Primer on the Fossil Fuel Industry’s Deceptive Tactics.”“It creates deceptive alliances with local churches, non-profit organizations, and other groups by offering financial support in the form of charitable contributions, gifts, and endowments,” the report says.

Memphis pipeline faces environmental justice reckoning — Monday, May 3, 2021 — – The Byhalia Connection pipeline, a 50-mile oil conduit planned to run through and around Memphis, has come under fire from environmental groups and community activists. Opponents are also seeking to harness deep-seated resentment from years of pollution from the heavy industry that flanks the city’s heavily Black southwest corner.

Byhalia pipeline: Environmental groups demand TN agency withdraw construction permit – A coalition of environmental groups that oppose the Byhalia Connection pipelinehave written a letter demanding the Tennessee Department of Environment and Conservation to revoke or suspend its permit for the planned project.The letter is one of many moves in the fight over the nearly 45-mile crude oil pipeline which would pass through mostly Black neighborhoods as it run from Memphis to Marshall County, Mississippi.Opponents have raised concerns about several environmental issues, including potential damage to the area’s underground water supply.The letter comes from the groups Memphis Community Against Pollution, Protect Our Aquifer and Tennessee Chapter Sierra Club.Plains All American Pipeline is seeking to build the pipeline in partnership with Valero Energy Corp. The letter says the pipeline companies withheld crucial information during their application to the state.”Specifically, Byhalia failed to disclose the existence of the Collierville Connection Pipeline, a crude oil pipeline that already connects the Diamond Pipeline and the Capline Pipeline – the same two pipelines proposed to be connected by the Byhalia Connection Pipeline.””If the company had disclosed the Collierville Connection Pipeline, the Tennessee Department of Environment and Conservation . . . would have been required to evaluate it as an alternative to the construction of the Byhalia Connection Pipeline because the use of an existing pipeline or pipeline route has the potential to avoid and minimize new impacts on waters of the State, including streams, wetlands, and groundwater. Use of an existing pipeline would also avoid impacts on residents along a new path.”Efforts to reach a representative of the pipeline organizations were not successful late Friday. The company has argued the pipeline can be constructed and operated safely. The state agency declined to comment. “We cannot comment due to pending litigation,” said spokesman Eric Ward.

Memphis City Council delays vote to halt Byhalia Connection pipeline — The Memphis City Council won’t vote on an ordinance that would regulate high-volume pipelines, including the Byhalia Connection pipeline, until at least July.The council held the ordinance in question Tuesday after the council’s attorney Allan Wade said the measure raised “constitutional” concerns and the city could lose litigation related to it.When the council decided to hold the pipeline ordinance, Plains All American, the developer of the Byhalia pipeline project, verbally agreed to dismiss eminent domain and condemnation proceedings already underway in Shelby County. Representatives of Plains told the council that the project would pause and that it would communicate directly with city attorneys to come to an agreement.Wade said the ordinance, which proponents had said would not prevent Byhalia from proceeding, would in fact stop the pipeline. If the intention of the council was to stop the pipeline, Wade said, they should just do it and avoid any unintended consequences of a broad ordinance.

Builders of contested Memphis pipeline weigh route changes — Wednesday, May 5, 2021 — Plains All American Pipeline LP says it is considering changing the route of its proposed Byhalia Connection oil pipeline in the Memphis, Tenn., area and has agreed to pause its work on the pipeline for two months.

Abandoned wells a drag on Arkansas –Professors and ecologists Matthew Moran and Maureen McClung started their research with the Fayetteville Shale in North-Central Arkansas around 2019, examining how the wells and their infrastructure were affecting the landscape and the economic costs associated with those impacts. “These costs are often not part of the conversation,” McClung said. “We saw a need to make a case that restoration should be happening after these oil and gas wells run dry, because they basically just exist on the landscape and are doing no good for anybody. It was pretty astounding the number of wells we found sitting useless.” In the mid-2000s, companies arrived in droves and started drilling for natural gas from the Fayetteville Shale, a formation that stretches across the state to the Mississippi River. Drilling peaked in 2008, but development of new wells declined rapidly, hitting near zero by 2016. The Hendrix researchers found almost one-fifth of the more than 6,230 wells in the Fayetteville Shale were nonproducing in 2020. However, many of them are on well pads that still support other producing wells, and therefore are not currently restorable. This was far from the first well boom in the state, though. Thousands of wells dot the landscape of southern Arkansas — reminders of the beginning of commercial oil production in the state and jobs that put food on the tables in towns like El Dorado and Smackover during the Great Depression. By 1925, the Smackover field had become the largest-producing oil site in the world, according to the American Oil and Gas Historical Society. Lands with nonproducing wells can sit unrestored for years, even decades. Old wells can leak methane gas and contaminate groundwater, and they are safety hazards for wildlife and communities alike. But what’s being lost from these lands can be difficult to quantify financially. For its work, the Hendrix team looked at agricultural production and carbon storage. The researchers estimated that restoring the 2 million acres across the nation would cost $7 billion but return $21 billion to the economy over the next 50 years. Agriculture makes up two-thirds of that value.

Groups sue over US program allowing pipelines on wetlands (AP) – Environmentalists have filed a new legal challenge to a U.S. government program that allows oil and gas pipelines to be built across wetlands, rivers and other bodies of water. The lawsuit filed Monday in U.S. District Court in Great Falls, Montana, alleges that the U.S. Army Corps of Engineers has let companies skirt environmental reviews of potential spills by granting a blanket construction permit to the industry. The Center for Biological Diversity, Sierra Club and other groups behind the litigation won a court order last year that temporarily blocked the program, known as Nationwide Permit 12. U.S. District Judge Brian Morris said officials did not adequately consult with wildlife agencies about pipelines’ potential harm to drinking water supplies and imperiled plants and animals. The Army Corps issued a new permit in January, saying it expects the permit to be used more than 8,000 times a year and affect 615 acres (249 hectares) annually of wetlands and other bodies of water. The groups behind Monday’s lawsuit said the agency failed to consider how that work could affect endangered sturgeon, whooping cranes and other wildlife that depend on wetlands. The permit can be used only for pipeline crossings that disturb a half-acre or less of steams or wetlands. Critics say that ignores the cumulative effects from hundreds of individual water crossings along a major pipeline’s route. The Army Corps has issued nationwide permits since the mid-1970s, and they were put into law in 1977 under Democratic President Jimmy Carter, according to the Congressional Research Service. But opposition to pipelines has grown more intense in recent years as the industry has been pulled into a broader debate over climate-changing greenhouse gases that come from burning the fossil fuels the lines carry. Sierra Club attorney Doug Hayes said the permit program has become “a tool for corporate polluters to fast-track climate-destroying oil and gas pipelines and exempt them from critical environmental reviews.”

Colonial pipeline: Cyberattack forces major US fuel pipeline to shut down – A cyberattack forced the temporary shut down of one of the US’ largest pipelines Friday, highlighting already heightened concerns over the vulnerabilities in the nation’s critical infrastructure. The operator, Colonial Pipeline, which transports more than 100 million gallons of gasoline and other fuel daily from Houston to the New York Harbor, according to its website, said it learned of the cyberattack on Friday, causing them to pause operations. “In response, we proactively took certain systems offline to contain the threat, which has temporarily halted all pipeline operations, and affected some of our IT systems,” the company said in a statement. Colonial said it engaged a third-party cybersecurity firm to launch an investigation into the “nature and scope of this incident” and also contacted law enforcement and other federal agencies. CNN has reached out to the US Cybersecurity and Infrastructure Security Agency for comment. The attack comes amid rising concerns over the cybersecurity vulnerabilities in America’s critical infrastructure following recent incidents, and after the Biden administration last month launched an effort to beef up cybersecurity in the nation’s power grid, calling for industry leaders to install technologies that could thwart attacks on the electricity supply. Colonial said Friday that it’s “taking steps to understand and resolve this issue.” “At this time, our primary focus is the safe and efficient restoration of our service and our efforts to return to normal operation. This process is already underway, and we are working diligently to address this matter and to minimize disruption to our customers and those who rely on Colonial Pipeline,” the company said. Colonial, founded in 1962, says it transports about 45% of all fuel consumed on the East Coast. The pipeline system that spans more than 5,500 miles has two main lines: one for gasoline and another for things like diesel and jet fuel.

U.S. pipeline operator that transports 45% of East Coast fuel shuts entire network after cyberattack – Top U.S. fuel pipeline operator Colonial Pipeline has shut its entire network after a cyber attack, the company said in a statement on Friday. Colonial’s network supplies fuel from U.S refiners on the Gulf Coast to the populous eastern and southern United States. The company transports 2.5 million barrels per day of gasoline, diesel, jet fuel and other refined products through 5,500 miles (8,850 km) of pipelines. Colonial Pipeline says it transports 45% of East Coast fuel supply. The malicious software used in a cyberattack was ransomware, a type of malware that is designed to lock down systems by encrypting data and demanding payment to regain access, two cybersecurity industry sources said. The malware has grown in popularity over the last five years and is most often deployed by cybercriminal groups. The company learned of the attack on Friday and took systems offline to contain the threat, it said in the statement. That action has temporarily halted operations and affected some of its IT systems, it said. The company has engaged a third-party cybersecurity firm to launch an investigation, and Colonial has contacted law enforcement and other federal agencies, it said. Colonial did not give further details or say for how long its pipelines would be shut. Reuters reported earlier on Friday that Colonial had shut its main gasoline and distillate lines. During the trading session on Friday, Gulf Coast cash prices for gasoline and diesel edged lower. Longer-term price effects will depend on the amount of time that the lines are shut. If barrels are not able to make it onto the lines, Gulf Coast prices could weaken further, while prices in New York Harbor could rise, one market participant said. Colonial significantly shut down its gasoline and distillate lines during Hurricane Harvey, which hit the Gulf Coast in 2017. During that time, spot Gulf Coast gasoline prices rose to a five-year high, while diesel prices rose to around a four-year high.

Sempra likely to delay decision on Texas LNG project until next year – Sempra Energy – a big player in the global liquefied natural gas export market – said Wednesday during its first-quarter earnings call that the company will likely make a final investment decision on building a proposed LNG facility near Port Arthur, Texas, in 2022 instead of this year. Sempra officials cited the continued impacts of the pandemic on worldwide energy markets and a focus on reducing the project’s greenhouse gas emissions for the potential delay but said they remain bullish on the economics of sending LNG overseas to countries eager to replace coal with natural gas. “The consultants we work with think that by 2030 you could see the market climb to about 550 million tons per annum and today it’s around 365, so we’re pretty optimistic about where we’re at in terms of our development portfolio.,” said Sempra CEO Jeff Martin. Commercial activity for large-scale LNG projects have slowed since COVID-19 affected the global economy and the first phase of Port Arthur project, estimated at 11 million metric tons per year, is a big one that would have to be built at a site without any existing infrastructure, which would add to construction costs. ADVERTISEMENT Sempra is already the majority owner of the $10 billion Cameron LNG facility on the Louisiana Gulf Coast – that has plans to expand – and the company’s subsidiary in Mexico, IEnova, recently received approval from the Mexican government to add an export component to the already existing Energ’a Costa Azul LNG facility in Ensenada. The potential for “greening up of the value chain,” as Martin put it, comes as LNG exporters in the U.S look to blunt criticism of the climate impacts of natural gas, a fossil fuel. In November, the French power company Engie backed out on a $7 billion deal with an LNG firm, reportedly because the government of France – which owns 24 percent of Engie – had environmental concerns about methane leaks and hydraulic fracturing of natural gas at U.S. sites. Earlier this week, Cheniere Energy and Royal Dutch Shell announced they had collaborated to ship a cargo of LNG it called “carbon-neutral” from Cheniere’s Sabine Pass LNG facility in Louisiana that was delivered to Europe in early April, using offsets bought from Shell.

Florida Congress members call to end oil drilling in Big Cypress – A handful of Congress members from Florida are urging a federal agency to deny oil drilling permits in the Big Cypress National Preserve. A letter, sent April 23 by Democratic Congress members Debbie Wasserman Schultz, Ted Deutch, Lois Frankel, Charlie Crist and Frederica Wilson to the Department of the Interior, asks for a full environmental impact statement for two oil extraction permits in the preserve. Burnett Oil Co., based in Texas, filed the permits through the Florida Department of Environmental Protection. The state agency recently took over a federal application process to dredge and fill within wetlands. Burnett is leasing land from Collier Resources Co., which owns the subsurface mineral rights in the preserve. Alia Faraj, spokeswoman for Burnett, previously told Naples Daily News the company’s efforts to minimize environmental impacts will create a net-zero impact on wetlands. The letter was addressed to the department’s deputy director of operations, Shawn Benge, and new Fish and Wildlife and Parks Assistant Secretary Shannon Estenoz. Estenoz was an advocate for Everglades restoration under the Obama administration and worked as the Everglades Foundation’s chief operating officer. Melissa Abdo, Sun Coast regional director for the National Parks Conservation Association, said Big Cypress is an iconic preserve and oil permits should not be allowed. “We’re hopeful DOI’s new leadership is going to have an eye toward implementing what (President) Biden committed to: A clear commitment to halt new oil and gas permitting on public lands,” Abdo said.

One of America’s most powerful oil lobbyists tours Louisiana to fight the offshore drilling ban – Fearful that a temporary ban on new federal leases onshore and offshore won’t be lifted and could become permanent, the top executive for the American Petroleum Association has been in Louisiana this week voicing a desire to sway the Biden administration towards softening what they consider abrupt policies against fossil fuels. Mike Sommers, chief executive officer of the American Petroleum Institute, got the whirlwind tour of Louisiana in recent days, meeting with membership companies and politicians who are vying to sway the Biden administration towards softening what they consider abrupt policies against fossil fuels. Sommers was able to sample plenty of local crawfish, tour a massive liquefied natural gas export terminal and see a wetland supported using oil and gas money, while voicing his top concern that a temporary ban on federal leases onshore and offshore won’t be lifted, ever. “There’s a saying in Washington that there’s nothing more permanent than a temporary program,” Sommers said. While it doesn’t impact the ability for companies to operate on private land, the environmental stewardship push now may stunt the industry for decades to come, he said. API’s members include Exxon Mobil, Shell, Chevron and BP, among others on the extraction and refinery side of the petrochemical pipeline. The long-term impact for the oil and gas sector in the Gulf of Mexico is unclear. All oil and gas exploration offshore are federal waters, requiring leases auctioned off and royalties collected in exchange for extraction of public natural resources. After multinational giants work through existing projects, which could take years, the drilling ban eventually could catch up if the work and the money dries up. “Fossil fuels are not the enemy; greenhouse gas emissions are the enemy,” Sommers said. The fossil fuel lobbyist pushed back on claims the coronavirus pandemic marked the “peak” for oil demand, when workers stayed home and took Zoom meetings for months instead of traveling. The International Energy Agency estimated global demand before the pandemic was 100 million barrels of oil each day in 2019. “In the worst part of the pandemic, in April of last year, the world was still consuming 81 (million) barrels of oil every single day. We basically shut down the world economy and we were still using 80% of what we were using pre-pandemic,” he said. “And we’re getting close to the point now where we’re getting back to that 100 (million) barrels.”

Velesto Provides Update on Sunken Rig –Velesto Energy Berhad has provided an update on the Velesto Naga 7 rig, which was revealed to have submerged on May 4. The company announced on Thursday that the focus remains on rescue, evacuation, and recovery efforts and revealed that all 101 personnel on-board the rig had been transferred safely to Miri, Sarawak. As of Thursday, Velesto Energy highlighted that it was unable to estimate the overall financial impact on the group from the incident but outlined that it expects this to be mitigated as the rig is “adequately insured”. Velesto Energy said it is working closely with the client and insurers and providing full cooperation to the relevant authorities. The company also noted that other businesses of the group are operating as usual, including the other six rigs in its fleet. The Naga 7 rig sinkage occurred due to “oil rapid penetration”, according to Velesto Energy, which highlighted back in March that the rig had secured a deal with ConocoPhillips Sarawak Limited and ConocoPhillips Sarawak Oil Limited with a tentative start date sometime in the first half of this year. The contract included the drilling of up to three wells using the Naga 7, which has a drilling depth capability of 30,000 feet and a rated operating water depth of 375 feet, Velesto Energy reveals on its website. ConocoPhillips did not immediately respond to an emailed request sent by Rigzone on Thursday asking for a statement on the incident. Velesto Energy’s wholly owned rig fleet comprises the Naga2, Naga 3, Naga 4, Naga 5, Naga 6, Naga 7, and Naga 8 jack-up drilling rigs. The company, which was formerly known as UMW Oil & Gas Corporation Berhad, also has four hydraulic workover units comprising the Gait 1, Gait 2, Gait 5, and Gait 6.

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