Oil, Gas, And Fracking News Reads: 05July 2020 – Part 1

Written by rjs, MarketWatch 666

Here are some selected news articles from the week ended 04 July 2020. Part 2 is available here.

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

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Q2 oil prices up most in 30 years, but still down 36% YTD; natural gas price logs best quarter in 2 years 2 days after 25 year low.

Oil prices rose for the 2nd week of the past three this week on improving economc data and falling US crude inventores….after falling 3.6% to $38.49 a barrel last week on a resurgence of covid-19 cases in the US and globally, the contract price of US light sweet crude for August delivery opened higher on Monday, supported by improving economic data in Europe and China, and rallied with stock markets to close $1.21 higher at $39.70 a barrel as U.S. pending home sales posted a record gain, supporting the economic recovery hypothesis…but another surge in US coronavirus cases dampened the outlook on Tuesday and prices fell 43 cents to $39.27 a barrel as a potential resurgence of Libyan oil production reminded traders there’s still a massive global oversupply, even as oil prices ended the 2nd quarter 92% higher than March 31st but remained 36% lower year to date…but oil prices jumped in overnight trading after the American Petroleum Institute reported the largest draw from crude oil inventories since 2019, and then opened 57 cents higher on Wednesday, and rose to as high as $40.58 a barrel after the EIA confirmed the draw, but faded after the EIA report to settle with a gain of just 55 cents at $39.82 a barrel as another surge in US coronavirus cases tempered the gains…oil prices then rose 83 cents, or 2.1%, to settle at $40.65 a barrel on Thursday after the labor department reported a larger jump in payrolls and a much bigger drop in unemployment than was expected, thus finishing the holiday shortened week 5% higher, at the highest level since March 6th…

Natural gas prices also rose this week, as the long awaited summertime air conditioning demand finally kicked in …after falling more than 10% to a 25 year low of $1.495 per mmBTU last week on the largest June storage build on record, trading in the contract price of natural gas for July delivery expired and natural gas opened this week with the the contract price of natural gas for August delivery trading at $1.567 per mmBTU, 2.3 cents higher than it’s $1.544 per mmBTU Friday close, and it quickly jumped more than 10% to a session high of $1.753 as forecasts for much warmer weather drove expectations of higher cooling demand, before it settled at $1.709 per mmBTU, still an increase of 16.5 cents for the day…the rally continued into Tuesday, with prices rising 4.2 cents, or 2.5%, to settle at $1.751 per mmBTU, which oddly enough turned out to finish the 2nd quarter with the largest quarterly gain since June 2018….but natural gas prices turned lower and fell 8 cents on Wednesday, as another spike in coronavirus infections fueled fears of another lockdown, which would lower the demand for gas-fired electricity…but greater than expected cooling demand led the EIA to report a smaller addition to storage than was expected Thursday, and August gas prices rose 6.3 cents to settle at $1.734 per mmBTU, thus finishing the week a gain of 12.3% for the August gas contract and 16% higher than the prior week’s close…

The natural gas storage report from the EIA for the week ending June 19th indicated that the quantity of natural gas held in underground storage in the US rose by 65 billion cubic feet to 3,077 billion cubic feet by the end of the week, which left our gas supplies 712 billion cubic feet, or 30.1% greater than the 2,365 billion cubic feet that were in storage on June 19th of last year, and 466 billion cubic feet, or 17.8% above the five-year average of 2,611 billion cubic feet of natural gas that has been in storage as of the 19th of June in recent years….the 65 billion cubic feet that were added to US natural gas storage this week was less than the consensus forecast from S&P Global Platts’ survey of analysts, who expected a 77 billion cubic feet increase, and it was also less than the 92 billion cubic feet addition of natural gas to storage during the corresponding week of 2019, but it exactly matched the average of 65 billion cubic feet of natural gas that has been added to natural gas storage during the same week over the past 5 years…

The Latest US Oil Supply and Disposition Data from the EIA

US oil data from the US Energy Information Administration for the week ending June 26th indicated that because of a sizable drop in our oil imports and an increase in oil used by refineries, we had to pull oil out of our stored commercial supplies of crude oil for the 1st time in four weeks, and for the 12th time in the past forty-two weeks….our imports of crude oil fell by an average of 571,000 barrels per day to an average of 5,969,000 barrels per day, after falling by an average of 102,000 barrels per day during the prior week, while our exports of crude oil fell by an average of 65,000 barrels per day to an average of 3,092,000 barrels per day during the week, which meant that our effective trade in oil worked out to a net import average of 2,877,000 barrels of per day during the week ending June 26th, 506,000 fewer barrels per day than the net of our imports minus our exports during the prior week…over the same period, the production of crude oil from US wells was unchanged at 11,000,000 barrels per day, and hence our daily supply of oil from the net of our trade in oil and from well production totaled an average of 13,877,000 barrels per day during this reporting week..

US oil refineries reported they were processing 14,033,000 barrels of crude per day during the week ending June 26th, 193,000 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 786,000 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 631,000 barrels per day more 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 inserted a (-631,000) barrel per day figure onto line 13 of the weekly U.S. Petroleum Balance Sheet to make the reported data for the average daily supply of oil and the data for the average daily consumption of it balance out, essentially a fudge factor that they label in their footnotes as “unaccounted for crude oil”, thus suggesting an error or errors of that magnitude in the oil supply & demand figures we have just transcribed…however, since the media usually treats these weekly EIA figures as gospel and since these numbers often drive oil pricing and hence decisions to drill for oil, we’ll continue to report them, just as they’re watched & believed as accurate by most everyone 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 6,504,000 barrels per day last week, which was 11.3% less than the 7,330,000 barrel per day average that we were importing over the same four-week period last year….the 786,000 barrel per day net reduction of our total crude inventories was as 1,028,000 barrels per day were being pulled out of our commercially available stocks of crude oil, which was partially offset by 242,000 barrels per day that were added to our Strategic Petroleum Reserve…this week’s crude oil production was reported to be unchanged at 11,000,000 barrels per day because the rounded estimate of the output from wells in the lower 48 states was unchanged at 10,600,000 barrels per day, while a 1,000 barrel per day increase in Alaska’s oil production to 363,000 barrels per day had no impact on the rounded national total….last year’s US crude oil production for the week ending June 28th was rounded to 12,200,000 barrels per day, so this reporting week’s rounded oil production figure was about 9.9% below that of a year ago, yet still 30.5% more than the interim low of 8,428,000 barrels per day that US oil production fell to during the last week of June of 2016…

Meanwhile, US oil refineries were operating at 75.5% of their capacity while using 14,033,000 barrels of crude per day during the week ending June 26th, up from 74.6% of capacity during the prior week, but excluding the 2005 & 2008 hurricane-related refinery interruptions, still one of the lowest refinery utilization rates of the last thirty years…hence, the 14,033,000 barrels per day of oil that were refined this week were still 18.8% fewer barrels than the 17,290,000 barrels of crude that were being processed daily during the week ending June 28th, 2019, when US refineries were operating at 94.2% of capacity….

With the increase in the amount of oil being refined, gasoline output from our refineries was also higher, increasing by 111,000 barrels per day to 8,905,000 barrels per day during the week ending June 26th, after our refineries’ gasoline output had increased by 438,000 barrels per day over the prior week… however, since our gasoline production is still recovering from a multi-year low, this week’s gasoline output was still 10.5% lower than the 9,948,000 barrels of gasoline that were being produced daily over the same week of last year….at the same time, our refineries’ production of distillate fuels (diesel fuel and heat oil) increased by 63,000 barrels per day to 4,624,000 barrels per day, after our distillates output had also increased by 63,000 barrels per day over the prior week…but even after this week’s increase in distillates output, our distillates’ production was still 13.3% less than the 5,336,000 barrels of distillates per day that were being produced during the week ending June 28th, 2019….

With the increase in our gasoline production, our supply of gasoline in storage at the end of the week increased for the 4th time in 10 weeks and for the 8th time in 22 weeks, rising by 1,199,000 barrels to 256,521,000 barrels during the week ending June 26th, after our gasoline supplies had decreased by 1,673,000 barrels over the prior week…our gasoline supplies increased this week because the amount of gasoline supplied to US markets decreased by 47,000 barrels per day to 8,561,000 barrels per day, and because our imports of gasoline rose by 307,000 barrels per day to 1,011,000 barrels per day, while our exports of gasoline rose 197,000 barrels per day to 483,000 barrels per day….after this week’s inventory increase, our gasoline supplies were 9.9% higher than last June 28th’s gasoline inventories of 232,225,000 barrels, and roughly 10% above the five year average of our gasoline supplies for this time of the year…

Even with the increase in our distillates production, our supplies of distillate fuels decreased for the thirteenth time in 24 weeks and for the 23rd time in 39 weeks, falling by 593,000 barrels to 174,720,000 barrels during the week ending June 26th, after our distillates supplies had increased by 249,000 barrels over the prior week….our distillates supplies fell this week because the amount of distillates supplied to US markets, an indicator of our domestic demand, rose by 312,000 barrels per day to 3,778,000 barrels per day, even as our exports of distillates fell by 62,000 barrels per day to 1,066,000 barrels per day while our imports of distillates rose by 66,000 barrels per day to 135,000 barrels per day….but even after this week’s inventory decrease, our distillate supplies at the end of the week were still 37.3% above the 126,788,000 barrels of distillates that we had stored on June 28th, 2019, and about 28% above the five year average of distillates stocks for this time of the year…

Finally, with the increase in our refining and the decrease in our oil imports, our commercial supplies of crude oil in storage fell for the just 4th time in twenty-three weeks and for the 18th time in the past 52 weeks, decreasing by 7,195,000 barrels, from a record high of 540,722,000 barrels on June 19th to 533,527,000 barrels on June 26th….but even after that decrease, our our commercial crude oil inventories were still around 15% above the five-year average of crude oil supplies for this time of year, and around 53% above the prior 5 year (2010 – 2014) average of our crude oil stocks for the third week of June, 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 have generally been rising since September of 2018, except for during last summer, after generally falling until then through most of the prior year and a half, our crude oil supplies as of June 26th were 13.9% above the 468,491,000 barrels of oil we had in commercial storage on June 28th of 2019, 27.7% above the 417,881,000 barrels of oil that we had in storage on June 29th of 2018, and 6.1% above the 502,914,000 barrels of oil we had in commercial storage on June 30th of 2017…

However, even with the big drop in our crude inventories, our inventories of products made from oil increased by even more, and hence the total of our commercial oil supplies and the stockpiles of all the refined product made from oil have again increased by 1,124,000 barrels this week to yet another record high of 1,451,779,000 barrels, 11.5% more than the 1,302,493,000 barrel total of the same week a year ago…

This Week’s Rig Count

The US rig count fell for the 17th week in a row during the period ending July 2nd, leaving the rig count down by 66.8% over that seventeen week period…(note that this week’s report was released on Thursday because of the widespread celebration of July 4th on July 3rd, and hence only covers 6 days)…Baker Hughes reported that the total count of rotary rigs running in the US decreased by 2 rig to 263 rigs this past week, which again was the fewest active rigs in Baker Hughes records going back to 1940 and 141 fewer rigs than the all time low prior to this year, and was also down by 700 rigs from the 963 rigs that were in use as of the July 3rd report of 2019, and 1,666 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 decreased by 3 rigs to 185 oil rigs this week, after falling by 1 oil rig the prior week, leaving oil rig activity at its lowest since May 29th, 2009, which was also 603 fewer oil rigs than were running a year ago, and less than an eighth 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 rose by 1 rig to 76 natural gas rigs, which was still down by 98 natural gas rigs from the 174 natural gas rigs that were drilling a year ago, and less than a twentieth of modern era high of 1,606 rigs targeting natural gas that were deployed on September 7th, 2008…in addition to those rigs drilling for oil & gas, two rigs classified as ‘miscellaneous’ continued to drill this week; one on the big island of Hawaii, and one in Lake County, California… a year ago, there was just one such “miscellaneous” rig deployed, drilling a test well in Sandusky county Ohio..

The Gulf of Mexico rig count was up by 1 to 12 rigs this week, with 10 of those rigs drilling for oil in Louisiana’s offshore waters and two of them now drilling for oil offshore from Texas…that was 12 fewer rigs than the 24 rigs drilling in the Gulf a year ago, when 22 rigs were drilling offshore from Louisiana and two rigs were operating in Texas waters…meanwhile, there are no rigs operating off other US shores at this time, nor were there a year ago, so the Gulf of Mexico rig count is equal to the national rig count, just as it has been since the onset of last winter…

The count of active horizontal drilling rigs decreased by 4 rigs to 226 horizontal rigs this week, which was the fewest horizontal rigs active since December 30th, 2005, and hence is a new 14 1/2 year low for horizontal drilling…it was also 613 fewer horizontal rigs than the 839 horizontal rigs that were in use in the US on July 3rd of last year, and less than a fifth of the record of 1372 horizontal rigs that were deployed on November 21st of 2014…meanwhile, the directional rig count was unchanged at 20 directional rigs this week, but those were still down by 46 from the 66 directional rigs that were operating during the same week of last year…on the other hand, the vertical rig count rose by 2 rigs to 17 vertical rigs this week, but those were also still down by 41 from the 58 vertical rigs that were in use on July 3rd of 2019….

The details on this week’s changes in drilling activity by state and by major shale basin are shown in our screenshot below of that part of the rig count summary pdf from Baker Hughes that gives us those changes…the first table below shows weekly and year over year rig count changes for the major oil & gas producing states, and the table below that shows the weekly and year over year rig count changes for the major US geological oil and gas basins…in both tables, the first column shows the active rig count as of July 2nd, the second column shows the change in the number of working rigs between last week’s count (June 26th) and this week’s (July 2nd) count, the third column shows last week’s June 26th active rig count, the 4th column shows the change between the number of rigs running on Friday and the number running before the same weekend of a year ago, and the 5th column shows the number of rigs that were drilling at the end of that reporting week a year ago, which in this week’s case was the 3rd of July, 2019…

There were again very few changes in drilling activity this week, with just a handful of rig removals and even fewer additions, which suggests that prices have risen high enough that drillers are no longer anxious to shut down money-losing operations, but not high enough to encourage the addition of new rigs to the field…checking the rig counts in the Texas part of Permian basin, we find that three rigs were shut down in Texas Oil District 8, or the core Permian Delaware, while the rig counts in Texas Oil District 7C and Texas Oil District 8A, the southern and northern reaches of the Permian Midland respectively, remained unchanged…since the overall Permian basin rig count was down by 5 rigs nationally, that means that the 2 rigs that were shut down in New Mexico would have been drilling in the western Permian Delaware to account for that national decrease…elsewhere in Texas, there was a new rig added in Texas Oil District 6, which accounts for the Haynesville shale increase, and two rigs began drilling in the state’s offshore waters, while at the same time another offshore rigs was pulled out the water in Louisiana, accounting for that state’s 1 rig decrease…the new rig in the Haynesville shale, plus the one that began drlling in West Virginia’s Marcellus, account for this week’s natural gas rig increase, which was reduced to one after a natural gas rig was pulled out of Ohio’s Utica shale…

Public Utilities Commission of Ohio fines Dominion Energy $1 million for Pepper Pike gas explosion – cleveland.com — The Public Utilities Commission of Ohio fined Dominion Energy $1 million for a November gas pipeline explosion in Pepper Pike. PUCO determined that the cause of the explosion was the “failure of a 30-inch steel distribution main, that released natural gas into the atmosphere which subsequently ignited,” according to a news release from PUCO Wednesday afternoon. PUCO’s report says Dominion failed to follow proper procedures, had poor construction practices and a lack of oversight. The agreement also requires Dominion Energy to create a plan to improve its gas safety program. “A third-party consulting firm will investigate and provide a root cause analysis within 90 days. Dominion and PUCO staff will review the analysis and determine an implementation plan,” PUCO said in a statement released Wednesday. “A third-party consultant will then evaluate Dominion’s adherence to the implementation plan to ensure the company adequately improves its processes and procedures.” The company will pay the $1 million to the state with an additional $500,000 that the commission can impose if Dominion Energy does not fulfill the terms of the settlement or implementation plan. A preliminary investigation showed that a welding failure caused a rupture that, in turn, caused an explosion that happened at 12:54 a.m. on Nov. 15 on Shaker Boulevard near the Pepper Pike Services Department. Firefighters from Pepper Pike and Beachwood went door to door to evacuate residents living within the vicinity of the explosion. They were later allowed to return to their homes.

Ohio AG Yost fights to reopen Line 5 pipeline in Great Lakes region – On the eve of a major hearing that could decide the fate of the Great Lakes region’s most controversial pipeline, Ohio Attorney General Dave Yost has asked the hearing’s judge to consider the potential loss of 1,000 northwest Ohio refinery jobs if he allows Enbridge Energy’s Line 5 to remain shut down.In an 11-page brief filed Monday with Ingham County Circuit Court in Lansing, Mich., Mr. Yost – along with attorneys general from Indiana and Louisiana – said the state of Ohio “has a significant interest in the continued operation of the West Line of Enbridge’s Line 5 pipeline and will experience far-reaching consequences if it is shut down.”The brief states that officials recognize “that environmental protection and economic impact are not mutually exclusive” and that Ohio, Michigan, and Indiana all have a duty to protect the Great Lakes. “However, Ohio, Indiana, and Louisiana also owe a duty to their citizens whose livelihoods depend on commerce that crosses state lines,” the brief states. Line 5 is a 645-mile pipeline owned by Calgary-based Enbridge Energy, the same pipeline company that experienced one of North America’s worst inland oil spills when a pipeline it owns along the Kalamazoo River near Marshall, Mich., burst in 2010. Line 5 became a flashpoint of controversy in early 2018 when the anchor of a boat passing through the Straits of Mackinac dented – but did not rupture – it.Activists quickly underscored the dangers of polluting Lake Michigan and Lake Huron, which sit at the center of the world’s largest collection of freshwater lakes, the Great Lakes. They flow south to Lake Erie.Enbridge worked out a deal with former Michigan Gov. Rick Snyder, a Republican, during the waning days of his administration to build a new pipeline beneath the Straits and submerge it in a tunnel 100 feet below Lake Michigan’s lakebed. That project is expected to cost up to $500 million and take as long as a decade to build.Michigan’s current governor, Democrat Gretchen Whitmer, and that state’s attorney general, Democrat Dana Nessel, campaigned on a platform of shutting down Line 5 to minimize risks to the Great Lakes. The pipeline splits into two as it passes through the Straits. Soon after Enbridge announced recently that an anchor support on the east line had been “significantly” damaged, Ms. Nessel filed a motion to have the entire system shut down on at least a temporary basis. Judge James Jamo granted that motion last Thursday, and scheduled a hearing to discuss the pipeline’s fate for Tuesday. Line 5 serves PBF Energy’s 123-year-old Toledo Refining Co. plant in East Toledo, which employs 585 people, and the BP-Husky Toledo refinery in Oregon, which employs 625 people, according to figures provided by Mr. Yost’s office.

Reports Offer Different Outlook On Ohio Valley’s Petrochemical Future –A new report by the Trump administration suggests the Ohio Valley’s growing petrochemical industry could be an unprecedented source of economic opportunity and growth when the county, and region, eventually emerge from the COVID-19 pandemic. But the assessment is drawing criticism from environmental groups and some financial analysts that warn the risk is growing for plastics and petrochemical manufacturers.The Department of Energy assessment released Tuesday makes the case that natural gas production in the region, which includes parts of West Virginia, Ohio, Pennsylvania and Kentucky, will continue to grow in the coming decades. The report argues the region is on the “cusp of an energy and petrochemical renaissance” due to the fact that gas extracted from the region is rich in natural gas liquids, including ethane, the building block of many plastics and chemicals, and the Ohio Valley’s proximity to the bulk of downstream manufacturers. The 75-page document was commissioned under president Donald Trump’s April 2019 executive order “Promoting Energy Infrastructure and Economic Growth.” Six additional federal agencies and the Appalachian Regional Commission contributed. Officials in the region have been working on the so-called Appalachian Storage and Trading Hub for nearly a decade. The natural gas storage hub cleared its first major hurdle in 2018 when it got approval for the first of two phases for a $1.9 billion U.S. Department of Energy loan. A previous DOE report, requested by lawmakers in Congress, found the hub is crucial for growing the region’s petrochemical industry. Sarah Carballo, a communications specialist with the Ohio Valley Environmental Coalition, a regional advocacy group, said the new DOE report did not take into account the growing financial risk associated with a regional petrochemical industry buildout, or the concerns of some residents in the region. “Communities across Appalachia deserve viable, fair and sustainable economic transition strategies that protect public health and environmental quality,” she said. “So, instead of investing in petrochemicals and coal as a basis for economic renaissance – industries that poisoned our land, air, water, communities – we think it’s time for our leaders to explore more feasible and sustainable economic development strategies that provide long term prosperity for the people of our region.”

Fracking Trailblazer Chesapeake Energy Files for Bankruptcy – Chesapeake Energy filed for bankruptcy protection Sunday as an oil- and gas-price rout stoked by the coronavirus pandemic proved to be the final blow for a shale-drilling pioneer long hamstrung by debt. Chesapeake is the latest debt-laden U.S. oil and gas producer to file for bankruptcy, as a coronavirus-induced economic slowdown saps demand for fossil fuels. More than 200 shale companies may file for bankruptcy over the next two years if oil and gas prices stay around current levels, analysts say. Co-founded in 1989 by the late wildcatter Aubrey McClendon, the company was early to recognize that horizontal drilling and hydraulic fracturing could unlock vast troves of natural gas, a trend that led to a rebirth of American fossil-fuel output and eventually made the U.S. the top oil producer in the world. By the end of 2008, the Oklahoma City-based company had drilling rights to nearly 15 million acres, according to a securities filing, an empire roughly the size of West Virginia. That vast footprint once helped Chesapeake earn the title of second-largest U.S. gas producer. But Chesapeake’s breakneck growth left it highly leveraged, and it was far slower than many of its peers to pivot to tapping shale formations for oil, which turned out to be much more lucrative than gas. U.S. natural gas prices are at their lowest levels in years. The result was a painful fall in recent years as Chesapeake shrank, selling assets to pare debt before winding up in bankruptcy court. “They were at the forefront, and they were the most aggressive. But because of how aggressive they were, it left them unable to pivot to what ended up being the real moneymaker,” said Chris Duncan, a Brandes Investment Partners director with a say in mutual funds that own Chesapeake debt. Chesapeake, which filed for chapter 11 protection with more than three dozen affiliated companies, listed assets of $16.2 billion and liabilities of $11.8 billion in its petition with the U.S. Bankruptcy Court in Houston. The company reached a restructuring agreement with many of its lenders that is intended to guide the bankruptcy process and seeks to eliminate some $7 billion in debt.

Chesapeake Files For Bankruptcy, Wiping Out $7 Billion In Debt And Any Existing Equity Value – After years of melting, the Chesapeake icecube is finally history: at exactly 350pm on Sunday afternoon, the company that launched the US shale boom, finally gave up and filed for a pre-packaged bankruptcy in the Southern District of Texas. In so doing, the company with roughly $9.5 billion in debt has become one of the biggest victims of a spectacular collapse in energy demand from the virus-induced global recession, and follows the collapse of another high-flyer in the US oil patch, Whiting Petroleum, which filed for Chapter 11 at the start of April after championing what was once the premiere U.S. shale field, the Bakken of North Dakota. As part of its prepack agreement, Chesapeake announced that it had entered into a Restructuring Support Agreement (“RSA”) with 100% of the lenders under its revolving credit facility, holders of approximately 87% of the obligations under its Term Loan Agreement, approximately 60% of its senior secured second lien notes due 2025, and approximately 27% of its senior unsecured notes, pursuant to which Chesapeake will implement a Chapter 11 plan of reorganization to eliminate approximately $7 billion of debt. Of course, since 73% of unsecured bondholders refused to sign off on the deal, expect a very vicious bankruptcy fight over the recoveries, as hedge funds that accumulated positions in the bonds unleash hell in their fight with the secureds (even as the equity committee claims that all classes above it should be unimpaired). Also, we have some bad news for Jefferies, which won’t be able to repeat its hilarious attempt to fund the company in bankruptcy by selling stock to Robnhood daytraders: as part of the RSA, the Company has secured $925 million in debtor-in-possession financing lenders under Chesapeake’s revolving credit facility. The DIP will provide Chesapeake the capital necessary to fund its operations during the Court-supervised Chapter 11 reorganization proceedings. To summarize: Chesapeake which enters bankruptcy with just over $9.5 billion in debt… … will eliminate about $7 billion of it, and emerge with a $2.5 billion exit financing, consisting of a new $1.75 billion revolving credit facility and a new $750 million term loan. Additionally, according to the RSA, the Company has the support of its term loan lenders and secured note holders to backstop a $600 million rights offering upon exit.

Chesapeake Energy’s Long Road to Bankruptcy — Chesapeake has been a dead man walking for the best part of a decade. The company will reorganize approximately $7 billion in debt and receive $925 million in debtor-in-possession (DIP) financing to continue operating. Chesapeake also has secured a $600 million rights offering, backstopped by some of its existing lenders, and a $2.5 billion exit financing package. At the end of March, Chesapeake reported $9.2 billion in long-term debt. According to Bloomberg, the company listed assets of $10 billion and liabilities of $50 billion. CEO Doug Lawler, who took over in 2013, said that even though the company had eliminated some $20 billion of leverage and financial commitments, “we believe this restructuring is necessary for the long-term success and value creation of the business.” In its early days, the company, under co-founder and CEO Aubrey McClendon, was an early adopter of the drilling practice that has come to be known as fracking. In the middle of the first decade of the 21st century, natural gas prices soared to more than $13 per million BTUs in 2008 (as of Monday morning, the price is around $1.60 for an equivalent amount). If the company couldn’t make money once prices collapsed, the next best thing was to buy and sell leasing rights to proven reserves. The company’s business model began to emphasize an aggressive plan to lease acreage in many shale gas plays. Next, the company proved the presence of the energy resource and, finally, flipped the property for a profit. In early 2012, for example, Chesapeake sold a 25% stake in its leases in Ohio’s Utica shale play to French oil major Total for $2.3 billion. At time, McClendon said, “This Utica transaction is our seventh significant JV and in these seven JVs, Chesapeake has sold approximately 1.5 million net acres for total leasehold consideration of $14.8 billion while retaining 3.6 million net acres as of the JV date with an indicated value by the JV partners of $45.7 billion.” By then, natural gas traded at around $3 per million BTUs. A few months later, Chesapeake’s board discovered (it said) that McClendon had reportedly borrowed up to $1.1 billion using his interests in Chesapeake’s wells as collateral without disclosing the loans to shareholders. In May, the board ousted McClendon as board chair and terminated the program that gave him the right to participate in every new well the company drilled. In June, Reuters reported that it had discovered a series of emails between Chesapeake and Canadian oil and gas firm Encana that suggested the companies had engaged in bid-rigging. (Encana changed its name to Ovintiv in January 2020 and moved its headquarters to the United States.) In 2016, McClendon was indicted on the charges. The day following that announcement, he was killed in car crash.

Hidden wine cave, $110 million parking bill: Energy collapse wasn’t only thing that sunk Chesapeake – Fracking giant Chesapeake Energy’s bankruptcy filing comes following a financial mess at the company that included no budgets, a massive wine collection and a nine-figure bill for parking garages, sources told CNBC’s David Faber. CEO Robert D. “Doug” Lawler found in examining the company’s books a $110 million bill for two parking garages, Faber reported Monday. That was part of about $30 billion in spending above cash flow that happened from 2010-12, while the late Aubrey McClendon was CEO and prior to Lawler taking over in 2013. Other revelations include a wine collection in a cave hidden behind a broom closet in the Chesapeake office. Extravagances further included a season ticket package to the NBA’s Oklahoma City Thunder that was the biggest in the league and a lavish campus that was modeled after Duke University, complete with bee keepers, botox treatments and chaplains for employees. The company announced its bankruptcy filing on Sunday, amid a brutal time for the energy sector. Prices have tumbled throughout the coronavirus pandemic as demand has crumbled and the economic expansion that began in 2009 ended in February. Chesapeake’s share price has fallen nearly 93% in 2020. “While today is a challenging day, your leadership team and I are confident that this is the best path forward for Chesapeake, and that we will emerge from the Chapter 11 process as a stronger and more competitive company,” Lawler said in a memo to employees. In the Chapter 11 announcement, Lawler added that the company is “fundamentally resetting” its capital structure and business “to address our legacy financial weaknesses and capitalize on our substantial operational strengths.” Chesapeake declined comment for this report.

Chesapeake Energy files for bankruptcy, as details emerge of wine cellars and botox – From 2010 to 2012, the company spent $30 billion more in drilling and leasing than it made from its operations.Chesapeake Energy, the poster child of the U.S. shale revolution, filed for bankruptcy protection on Sunday. The move comes as the company and industry more broadly has been rocked by a drop in oil and gas prices amid the coronavirus pandemic. The heavily indebted company has been in trouble for some time, and in May said that it had concerns regarding its long-term viability. Chesapeake said that $7 billion in debt will be wiped out through the restructuring. The company has secured $925 million in debtor-in-possession financing in order to continue operations during the bankruptcy process. In addition, Chesapeake has secured an agreement in principle from certain existing lenders for $2.5 billion in debt financing on emergence from bankruptcy, as well as a backstop commitment for $600 million in new equity. Franklin Resources and Fidelity are among the biggest creditors, according to people close to the company, and they will be among the primary equity holders following the company’s restructuring. The company will continue operations at a much reduced capacity, with a handful of gas rigs and no oil rigs, according to those familiar with the company’s plans. Chesapeake Energy was founded in 1989 by Aubrey McClendon. An early pioneer of horizontal drilling, he built the company into a key player in the U.S. gas industry. At its peak, Chesapeake had 175 operating rigs, with operations across the U.S. including in Texas, Louisiana, Pennsylvania and Ohio. But the company took on a lot of debt to fuel its rapid expansion, and from 2010 to 2012 spent $30 billion more in drilling and leasing than it made from its operations. The fracking giant’s bankruptcy filing comes following a financial mess at the company that included no budgets, a massive wine collection and a nine-figure bill for parking garages, sources told CNBC’s David Faber.CEO Robert D. “Doug” Lawler found in examining the company’s books a $110 million bill for two parking garages, Faber reported Monday. Other revelations include a wine collection in a cave hidden behind a broom closet in the Chesapeake office. Extravagances further included a season ticket package to the NBA’s Oklahoma City Thunder that was the biggest in the league and a lavish campus that was modeled after Duke University, complete with bee keepers, botox treatments and chaplains for employees.

Chesapeake asks to cancel pipeline contracts, sets drilling cuts – (Reuters) – Chesapeake Energy Corp on Monday sought bankruptcy court approval to cancel $311 million in pipeline contracts, setting up a battle with U.S. regulators and operators including Energy Transfer LP, according to court filings. Chesapeake on Sunday became the largest U.S. oil and gas producer to seek bankruptcy protection in at least five years, falling to heavy debt and the impact of the coronavirus outbreak on energy markets. The company separately said in a filing it plans to operate six to eight drilling rigs for the next two years, about half the 14 rigs active on average in the first quarter, as it battles a historic downturn in oil prices. The shale pioneer wants to walk away from contracts with units of Energy Transfer, Boardwalk Pipelines, and a Crestwood Equity Partners and Consolidated Edison gas joint venture. The contracts involve about $293 million with Energy Transfer’s Tiger Pipeline and $18 million with Boardwalk’s Gulf South Pipeline. Neither Energy Transfer, Boardwalk nor Chesapeake responded to a request for comment. U.S. pipeline regulator, the Federal Energy Regulatory Commission, last week barred Chesapeake from altering its agreement with Energy Transfer and is set to weigh similar requests from Gulf South and from Stagecoach Pipeline & Storage Co, owned by Crestwood Equity Partners and Consolidated Edison. Crestwood said it is positioned to maintain operations for Chesapeake, including its Stagecoach unit. However, Chesapeake must show any rejection benefits the public good for FERC to approve it, a Crestwood spokesman said. Cancelling the contracts are key to winning creditors’ consent of its debt restructuring, Chesapeake told U.S. Bankruptcy court Judge David Jones in a filing. The battle could represent a turning point in energy bankruptcies, said Matthew Lewis, director at pipeline research firm East Daley Capital, with FERC seeking equal footing with interstate pipeline contracts. If FERC is “less liberal with contract rejection, it could force more renegotiations of contracts,” instead of outright cancellations, Lewis said.

Chesapeake sues FERC over pipeline contracts – Chesapeake Energy has sued the Federal Energy Regulatory Commission to keep two pipeline companies from interfering in its Chapter 11 reorganization, Kallanish Energy reports. Named in the suit were ETC Tiger Pipeline LLC and Gulf Southern. Chesapeake Energy is seeking to reject certain negotiated contracts with the pipeline companies for moving natural gas. It wants the federal bankruptcy court, not FERC, to decide the issue. Chesapeake is the sixth-largest natural gas producer in the United States. It was once the No.2 natural gas producer in the country. The company’s Chapter 11 filing on Sunday kicks off one of the biggest energy bankruptcies in recent years. Chesapeake has asked the U.S. Bankruptcy Court in the Southern District of Texas to prevent legal action by the two pipeline companies, saying that to fulfill the contracts would endanger its negotiated reorganization plan to eliminate $7 billion in debt. At year-end 2019, it had $9 billion in debt. The Oklahoma-based company said it had paid $890 million since early 2009 for pipeline transportation under existing agreements with the two companies. Chesapeake owes $311 million for the remainder of the contracts. Both companies last month petitioned FERC to protect their contracts with Chesapeake. If FERC orders Chesapeake to comply with those terms, its Chapter 11 reorganization would face “irreparable harm,” it said in the court filing. Chesapeake said they would likely file an appeal with a U.S. Court of Appeals if FERC orders those contracts to be upheld. A third pipeline company, Stagecoach Pipeline & Storage, made a similar filing with FERC earlier this month. In its Sunday filing, Chesapeake Energy cited debts of $10 billion and its reorganization will affect drilling service companies and pipeline companies from Pennsylvania to Texas to Wyoming. Companies including Williams, Energy Transfer, and Crestwood Equity Partners all have contracts with Chesapeake that may be reduced or rejected in bankruptcy court, said Ryan Smith of East Daley Capital in a Reuters report. Chesapeake is a major player in the Marcellus Shale in the Appalachian Basin, the Hayesville Shale in Louisiana and Texas, the Eagle Ford and Brazos Valley in Texas, in the Powder River Basin in Wyoming and Montana and the Mid-Continent in Oklahoma. It was the major player in the Utica Shale in eastern Ohio but later divested those assets.

Chesapeake Bankruptcy Extends String of 2020 Shale Busts — The shale bust has reached a grim milestone by claiming the pioneer of America’s drilling renaissance. But Chesapeake Energy Corp., which filed for bankruptcy protection on Sunday, is just the latest in a long list of casualties. More than 200 North American oil and gas producers, owing over $130 billion in debt, have filed for bankruptcy since the beginning of 2015, according to a May report from law firm Haynes & Boone. This year alone, at least 20 have gone under after oil prices plunged amid the Covid-19 pandemic. The shale boom spearheaded by the likes of Chesapeake a decade ago was fueled by debt. Profitability and shareholder returns have been consistently disappointing, and investors had already grown wary of throwing more money into shale before this year’s oil crash. The rate of default on high-yield energy debt stood at 11%, Fitch Ratings said in a June 11 report, the highest level since April 2017. Here are a handful other notable shale bankruptcies so far this year:

• Whiting Petroleum -An oil explorer focused on the Bakken Shale in North Dakota, Whiting Petroleum Corp. was already facing headwinds prior to 2020. Last year, the Denver-based company announced it would fire a third of its workforce and scale back production targets after posting a surprise quarterly loss.
• Extraction Oil & Gas – Another Colorado driller, Extraction Oil & Gas Inc. focused exclusively on the Denver-Julesburg Basin in the Rockies. It filed for Chapter 11 on June 15, offering to ease its debt burden of roughly $1.5 billion by giving note holders 97% of new common stock to be issued. Extraction had withdrawn its 2020 guidance in May and warned it may have to file for bankruptcy. Then, in early June, the company announced plans to pay 16 executives and senior managers a total of $6.7 million in return for staying with Extraction ahead of a possible default on its bond payments.
• Ultra Petroleum – Once wasn’t enough. Ultra Petroleum Corp. filed for its second bankruptcy in May, four years after its first. Listing $2.56 billion in debt and $1.45 billion in assets in its Chapter 11 filing, the Englewood, Colorado, driller reached a deal with most of its senior creditors that would slash $2 billion in debt, while looking to restructure within three months.
• Sable Permian Resources – Soon after his ouster from Chesapeake in 2013, co-founder Aubrey McClendon went to work building a new empire, American Energy Partners. Part of that business, American Energy – Permian Basin, merged with Sable Permian Resources LLC last year. That particular business was widely seen as having among the best assets of a half dozen oil-and-gas acquisition vehicles that McClendon set up during his brief tenure at American Energy Partners.Sable filed for bankruptcy last week in Houston alongside affiliates, listing at least $1 billion of assets and liabilities each.

Pennsylvania impact fee could be lower next year – Pittsburgh Business Times -New well spuds dropped 29% to 255 across Pennsylvania between January and June, according to data from the Pennsylvania Department of Environmental Protection.

Wolf Administration advances proposed emission limits on thousands of oil and gas sites – The Wolf Administration wants to limit emissions from thousands of oil and natural gas sites in Pennsylvania. It’s proposing a new regulation that would require better monitoring and control of emissions at existing oil and gas wells, including those that use hydraulic fracturing, and related sites. Companies would have to install equipment to stop emissions from escaping, and inspect sites for leaks every three months. The rule targets volatile organic compounds (VOCs), which contribute to ozone and can affect people’s health. The Department of Environmental Protection says the tighter controls will also prevent leaks of the potent greenhouse gas methane. DEP said the rule would reduce annual air pollution by 4,404 tons of VOCs and 75,603 tons of methane. A recent Environmental Defense Fund study found Pennsylvania’s shale gas industry leaked more than 1 million tons of methane in 2017 – seven times more than state reporting showed. People can offer written comments on the plan through July. They can also participate in their choice of three virtual hearings in June. In 2018, the Wolf Administration enacted a similar regulation for new sources of emissions, as part of the governor’s plan to reduce methane leaks and fight climate change. The administration has faced criticism from environmental groups for moving too slowly on the new rule. Methane is the main component of natural gas. Compared to carbon dioxide, it has about 30 times the warming power, according to the Environmental Protection Agency. Scientists say greenhouses gases must be curbed significantly to stop the worst effects of climate change. “Pennsylvania is one of the leading states in the country as far as natural gas production, and to have existing source regulations in Pennsylvania will make a dent into the climate pollution problem that we have in this country,” said Dan Grossman, senior director of state advocacy for the Environmental Defense Fund. He added that enactment in Pennsylvania could spur adoption of methane standards in other oil and gas producing states. Colorado, California, and Ohio have created similar rules.

Department of Health says it is looking into fracking public health risks following grand jury report -The Pennsylvania Department of Health says it is taking steps to learn more about the health risks of fracking following criticism from an investigative grand jury.The department’s comments come days after the grand jury’s report said the Pennsylvania Department of Environmental Protection and the health department failed to protect people from the adverse health effects of the fracking boom that began about 10 years ago.The report, which resulted from a two-year investigation, describes drinking water turned brown from chemical-intensive fracking operations, and includes testimony describing children and adults getting sick, animals dying and, in one case, a state DEP that threatened someone who spoke up with “filing a false report” rather than helping them.While the DEP took the brunt of the criticism in the report, the grand jury also criticized the health department’s response, saying it was “unable to meet the challenge” of understanding how fracking could affect people.The health department did launch two studies in November to look at the role of fracking in Ewing sarcoma and childhood cancers in Southwestern Pennsylvania, and is committing $3.9 million to those studies over three years, said spokesman Nate Wardle.In a formal response to the grand jury report, Health Secretary Dr. Rachel Levine said the report was a helpful tool for the department to continue to improve in its public health role. However, the department already has taken some of the measures recommended in the report, such as setting up an oil and natural gas registry that allows people to submit public health complaints. Some of the other measures would require action by the state legislature, Levine said. Read the grand jury report:

Attorney: Politics at play in pipeline prosecution – The attorney who won dismissal of criminal charges against a Delaware County man accused of orchestrating a “buy-a-badge” scheme to provide security for the controversial Mariner East 2 pipeline construction project said Monday that the case had been unduly influenced by political considerations rather than “sound, fair prosecutorial decisions.” Justin Danilewitz of the Philadelphia law firm of Saul, Ewing, Arnstein & Lehr said in an interview that he had urged the Chester County District Attorney’s Office on multiple occasions not to file charges of bribery and conspiracy against his client, Frank Recknagel, the head of security for Energy Transfers Partners, the parent company of Sunoco Pipelines, which is building the massive project through Chester and Delaware counties. He said he had given the prosecution ample evidence that Recknagel had done nothing wrong in getting state constables to work as off-duty security on the pipeline, and had been in consultation with local township police and elected officials about their work. But he was ultimately put off, and left shaken after the charges were filed late last year. On Thursday, Magisterial District Judge John Bailey of West Whiteland dismissed all charges against Recknagel at the conclusion of a five-hour-long preliminary hearing. Bailey determined that the prosecution had not shown that Recknagel had sought to commit a crime in the matter, and had, in fact, tried the best he could to follow the law, Danilewitz said. “Our argument to the judge was essentially no different than the argument we made to the D.A.’s Office on many occasions,” Danilewitz, who was assisted in Recknagel’s defense by defense attorney Thomas Bellwoar of West Chester. “Our client had no criminal intent. Our point was that he was a careful security person, and that he would ultimately be vindicated.

High Court Wants White House View on PennEast Pipeline Case – The U.S. Supreme Court wants the Trump administration’s views on a major energy case that could decide the fate of the proposed PennEast pipeline. At issue is whether developers can seize state-owned land in New Jersey to build the $1 billion natural gas project, which is backed by Enbridge Inc., Southern Co., and other companies. The justices on Monday asked the solicitor general to file a brief expressing the U.S. views on the question – a sign of interest in the case. The move comes as pipeline opponents increasingly ask judges to halt development, and industry lawyers look to the high court to intercede. The justices did just that two weeks ago when they resolved a separate pipeline dispute, siding with the natural gas industry and the Trump administration in a case involving the Atlantic Coast project. PennEast supporters say the industry will face severe disruptions – giving states a new tool to block projects – if the Supreme Court leaves a lower court’s decision in place.The project is slated to move natural gas 116 miles across Pennsylvania and New Jersey, and is part of a broader buildout of gas infrastructure across the East Coast. PennEast pipeline spokeswoman Patricia Kornick said the project backers are pleased the Supreme Court requested the administration’s views on the case. “PennEast remains hopeful that the U.S. Supreme Court will grant the petition,” she said in an email. The Interstate Natural Gas Association of America likewise said it welcomed the development.

‘Gimmick’ is how future pipelines will avoid environmental and permitting issues – What if PennEast could secure a pipeline through Hopewell without having to apply for a single permit? Recently, several residents, who live along Jacobs Creek, received a letter from a representative of Sunoco Logistics Partners LP (Sunoco) that it had filed an application for an “Emergency Repair” permit with the New Jersey Department of Environmental Protection (DEP), that they had 15 days to visit the DEP offices or the township clerk’s office to examine Sunoco’s application and file any objections. Unbeknownst to all residents with whom we spoke, including several who have lived along the creek for over 50 years, there is an underground pipeline beneath Jacobs Creek, which is the subject of the Sunoco permit. Sunoco’s letter proposes “Two (2) 1250-foot HDD [horizontal directional drill] pipeline strings,” a replacement and an additional pipeline, or two new pipelines. Why have a pipeline beneath a fresh water stream in the first place? The creek is a source for wildlife, including birds, deer, red foxes, raccoons, and other small animals, to drink and bathe. And yes, this is the same creek that General George Washington and his ragtag army traversed to surprise the Hessians at the Battle of Trenton, changing the course of the Revolutionary War. Since this pipeline predates the 1970s, we have learned much about the ecology of streams, wetlands and the flora and fauna in the habitat that the creek supports. According to Sunoco’s 2016 SEC Form 10-K, Sunoco plans to transport NGLs [natural gas liquids] from the Marcellus and Utica Shale areas in Pennsylvania, West Virginia and Ohio east, through Northern Pennsylvania, across the Delaware River to Northern New Jersey, then south through New Jersey, and then west, back across the Delaware River at Jacobs Creek, into Pennsylvania and south, down to its Marcus Hook refinery. With the “total takeaway capacity to 345 thousand barrels per day.” There is a global glut of fossil fuels, they at historically low prices, another fracker, Chesapeake Energy, just filed for bankruptcy, and renewable energy is cheap. Therefore, these pipelines are unnecessary. PennEast has been unsuccessfully trying to put a pipeline through this area for years. Is Sunoco/PennEast just using this “Emergency Repair” Permit Application as a ruse to install two new pipelines, circumventing the necessary permit process? Then, afterwards, Sunoco could sell or lease these pipelines, maybe even to PennEast? If this ploy is successful here, maybe this gimmick is how future pipelines will avoid environmental and permitting issues: find an old pipeline, get a permit for “repair,” in which it is actually replaced, then sneak in an additional pipeline. This would yield two brand new pipelines and avoid the messy business of having to apply for all those nasty permits. Genius!

Controversial gas pipeline project that would run through Chesapeake delayed – State regulators declined for now to give the go-ahead for a proposed $346 million gas pipeline project that would run through Chesapeake, arguing Virginia Natural Gas needs to do more legwork on securing financing and environmental justice issues before construction. Opponents of the Header Improvement Project said it would affect communities of color and people living on low incomes, exposing them to air and noise pollution. For now, Virginia Natural Gas has until Dec. 31 to meet a host of requirements laid out in an 18-page ruling Friday from the State Corporation Commission. That includes addressing financial concerns raised during recent testimony from the primary driver of the project, an electricity-generating plant known as C4GT, as well as protecting the utility’s ratepayers from added costs. A Virginia Natural Gas spokesman, Rick DelaHaya, said in an email Monday that the company will work with state officials “to develop a model project that meets all regulations.” A number of concerned residents and groups including the Sierra Club and Chesapeake Climate Action Network have cried foul on the project, saying the pipelines and compressor stations used to push gas through the pipelines would be built around communities predominantly composed of African Americans and Latinos. The project includes three new pipelines totaling 24 miles and three new or expanded gas compressor stations spanning northern Virginia to Hampton Roads.

Belinda Joyner Is Tired of Fighting the Atlantic Coast Pipeline, But She’s Still Fighting – “We are tired of being dumped on.”In February, Belinda Joyner caught a ride to the U.S. Supreme Court. Alongside a couple of close friends, the 67-year-old rode from her home in Garysburg, a 1,000-person town near the North Carolina-Virginia border, up to Washington, D.C.They were there to watch the court hear arguments over whether the U.S. Forest Service should be allowed to issue permits for the Atlantic Coast Pipeline to be built through national forest lands connected to the Appalachian Trail.The 600-mile, $8 billion pipeline – spearheaded by Dominion Energy and Duke Energy and first proposed in 2014 – would run through West Virginia, Virginia, and North Carolina, delivering some 1.5 billion cubic feet of natural gas per day from the Appalachian Basin. In North Carolina, the pipeline is set to snake through eight counties: Halifax, Nash, Wilson, Johnston, Sampson, Cumberland, Robeson, and Northampton – Joyner’s back yard.This week, the Supreme Court ruled 7 – 2 to allow the companies to secure right-of-way under the AT.The ruling was a blow to Joyner and her neighbors. The pipeline, they say, is just the latest example of unwanted industry development disrupting their community with dire consequences for human and environmental health. But in the marathon that is the fight for environmental justice, setbacks come with the territory. In the shadow of the nearby second-home tourist haven Lake Gaston, Northampton County, with its predominantly Black population, has been a hotbed of environmental activism for more than 25 years. But with the ACP halfway in the ground and the nearby Enviva wood-pellet facility recently granted permits to expand by the state Department of Environmental Quality – a development that raises additional concerns over air pollution – community members say they’ve been worn down by the Sisyphean task of fighting for a healthy future.”[The companies] don’t live here, so they don’t have to suffer with the damage they cause to the community,” Joyner says. “We are tired of being dumped on.”

U.S. natgas futures jump 10% on forecasts for warmer weather – (Reuters) – U.S. natural gas futures rose over 10% on Monday, regaining ground after slumping to a more than 25-year low the previous session, as forecasts for warmer weather drove expectations of higher cooling demand for the fuel. In its first day as the front month, gas futures for August delivery rose 16.5 cents, or 10.7%, to settle at $1.709 per million British thermal units (mmBtu). Prices had earlier touched their highest since June 15 at $1.753. U.S. natural gas futures slumped to their lowest since August 1995 in the previous session as the market focused on demand destruction from the coronavirus, swelling stockpiles and lower liquefied natural gas exports earlier in the month. “With temperatures going up, cooling demand has increased and forecasts say they will continue to increase. Along with that, Chesapeake’s restructuring has also signaled some drop in supply,” said Phil Flynn, Price Futures Group senior market analyst. Chesapeake Energy filed for Chapter 11 on Sunday, becoming the largest U.S. oil and gas producer to seek bankruptcy protection in recent years as it bowed to heavy debts and the impact of the coronavirus outbreak on energy markets. Refinitiv data indicated 222 cooling degree days (CDDs) in the lower 48 states over the next two weeks. The normal is 190 CDDs for this time of year. Prolonged lockdowns to curb the spread of coronavirus have kept many U.S. businesses shut, curbing LNG demand. LNG exports have also fallen, dropping by half since the start of 2020, with burgeoning stockpiles expected to reach a record 4.1 trillion cubic feet by the end of October. Refinitiv said production in the Lower 48 U.S. states averaged 87.8 billion cubic feet per day (bcfd) in June, down from a 16-month low of 88.2 bcfd in May and an all-time monthly high of 95.4 bcfd in November.

-U.S. natgas hits 3-week high, wraps up best quarter since mid-2018 – (Reuters) – U.S. natural gas futures rose to their highest in nearly three weeks on Tuesday, ending the best quarter since June 2018, as forecasts for hotter-than-normal weather increased demand for cooling. August futures rose 4.2 cents, or 2.5%, to settle at $1.751 per million British thermal units, having jumped more than 14% on Monday, the biggest daily gain since January 2019. Prices have gained nearly 7% this quarter, the most since June 2018. “We are seeing some support coming from expectation of summer heat and after last week’s collapse some prolonged heat could actually start to bring in the extra demand and curb injections a little bit lower,” said Daniel Myers, senior market analyst at Gelber & Associates. Refinitiv data indicated 243 cooling degree days (CDDs) in the lower 48 states over the next two weeks. The normal is 191 CDDs for this time of year. “Prices might have some trouble holding these gains until LNG export demand goes up and if supply does not ramp up as expected by many investors,” Myers said. For the month, futures suffered their second straight fall after slumping to their lowest since August 1995 last week, hurt by demand destruction from the coronavirus, swelling stockpiles and lower liquefied natural gas exports earlier in the month. Prolonged lockdowns to curb the spread of the coronavirus have kept many businesses shut, cutting U.S. LNG exports by half since the start of the year with stockpiles filling fast, expected to reach a record 4.1 trillion cubic feet by the end of October. Chesapeake on Sunday became the largest U.S. oil and gas producer to seek bankruptcy protection in at least five years, falling to heavy debt and the impact of the coronavirus outbreak on energy markets.

U.S. natgas breaks 3-day win streak as virus cases resurge – (Reuters) – U.S. natural gas futures on Wednesday snapped a three-session gaining streak as concerns about another lockdown due to surging coronavirus infections clouded demand outlook. The August gas futures contract fell 8 cents, or 4.6%, to settle at $1.671 per million British thermal units, having hit its highest since June 12 in the last session. The front-month contract also posted its biggest quarterly rise since June 2018 on Tuesday. “We are seeing some investors walking away with profit as concerns of another wave of coronavirus is resurfacing on the horizon,” said Raymond James analyst Muhammed Ghulam. Increases in infection have fueled concerns of another lockdown, which could lead to closure of offices and factories, in turn reducing the demand for electricity and cooling, Ghulam added. New U.S. COVID-19 cases rose by more than 47,000 on Tuesday, according to a Reuters tally, the biggest one-day spike since the start of the pandemic, as the government’s top infectious disease expert, Dr. Anthony Fauci, warned that number could soon double. Prolonged lockdowns to curb the spread of the coronavirus have kept many businesses shut, cutting U.S. LNG exports by half since the start of the year with stockpiles filling fast, expected to reach a record 4.1 trillion cubic feet by the end of October. “The expected end of season higher storage level is the most significant factor that keeps a lid on gas prices at this point,” said Zhen Zhu, economist at Oklahoma City-based C.H. Guernsey. However, “several factors are still providing some support to prices: summer weather uncertainty (more on the warmer than normal side), possible damaging tropical storms, and expected gas lower production for this year.” Weather forecasts pointed toward a warm summer with Refinitiv data indicating 248 cooling degree days (CDDs) in the Lower 48 states over the next two weeks. The normal is 193 CDDs for this time of year.

US working natural gas storage volumes rise by 65 Bcf on week: EIA | S&P Global Platts – One week after it reported a much larger injection than the market expected, the US Energy Information Administration estimated a smaller-than-expected addition to US storage fields for the week ended June 26, boosting the remaining Henry Hub summer strip by 4 cents, as analysts struggle to nail down weekly injections during this period of mid-summer demand and wavering coronavirus restrictions. The amount of natural gas in US underground storage facilities increased by 65 Bcf to 3.077 Tcf, according to US Energy Information Administration data released July 2. The injection was much smaller than the consensus expectations of analysts surveyed by S&P Global Platts, which called for a 77 Bcf build. Responses to the survey ranged from an injection of 66 Bcf to one of 85 Bcf. The injection was also smaller than the 92 Bcf build reported during the same week a year earlier, but it matched the five-year average increase of 65 Bcf, according to EIA data. The injection was nearly 50% smaller than the build reported the week prior as warmer temperatures boosted gas-fired power generation and LNG feedgas deliveries showed some signs of recovery. Power burn estimates ramped up 5.9 Bcf/d while feedgas demand increased by 300 MMcf/d, according to S&P Global Platts Analytics. However, residential and commercial as well as industrial demand, fell by a combined 800 MMcf/d week over week. Storage volumes now stand 712 Bcf, or 30%, above the year-ago level of 2.365 Tcf and 466 Bcf, or 18%, higher than the five-year average of 2.611 Tcf. The NYMEX Henry Hub balance-of-summer contract, August through October, increased 5 cents to $1.78/MMBtu in trading following the release of the data. The ICE end-of-season storage contract is treading close to the 4 Tcf mark as nearly all regions are on track for high storage fills by the end of the season, in some cases possibly prompting a drop in supplies by late summer as caverns reach their upper limits. S&P Global Platts Analytics’ supply and demand model currently expects a 59 Bcf injection for the week ending July 3, which would be 9 Bcf below the five-year average. Fundamentals have seen a continued tightening in supply and demand balances by an additional 1.8 Bcf/d compared with the week prior. Total supplies have held essentially flat, but warmer weather has contributed roughly 2.2 Bcf/d of incremental demand from the power sector as the market enters the peak months of the cooling season.

U.S. natgas futures gain as cooling demand reduces injection U.S. natural gas futures rose on Thursday after a federal report showed a smaller-than-expected storage build last week amid greater demand for cooling as the weather turned hotter in the United States. The August gas futures contract was up 6.3 cents, or 3.7%, to settle at $1.734 per million British thermal units. “Warmer-than-expected weather has increased cooling demand and that is being reflected in the report with injection coming below expectations,” said Thomas Saal, senior vice president of energy at INTL FCStone. Weather forecasts pointed toward a hot summer, with Refinitiv data indicating 248 cooling degree days (CDDs) in the Lower 48 states over the next two weeks. The normal for this time of year is 194 CDDs. The U.S. Energy Information Administration said U.S. utilities injected 65 billion cubic feet (bcf) of natural gas into storage last week, lower than the 78 bcf forecast by a Reuters poll on Wednesday. The increase during the week ended June 26 has increased stockpiles to 3.077 trillion cubic feet (tcf), which is still 17.8% higher than the five-year average and about 30.1% above the same week a year ago. Prolonged lockdowns to curb the spread of the coronavirus have kept many businesses shut, cutting U.S. LNG exports by half since the start of the year, with stockpiles filling fast and expected to reach a record 4.1 trillion cubic feet by the end of October. “Futures are still below $2 because the LNG exports have dropped drastically due to the pandemic and a recovering crude oil price have ramped up production,” Saal added.

Colonial Pipeline to Enter the Terminal Business — Colonial Pipeline Co. reported Wednesday that it plans to expand into the terminal business by acquiring three refined products terminals in the Southeastern U.S. In a written statement emailed to Rigzone, Colonial stated that Colonial Terminals Operating Co. LLC – a unit of affiliate company Colonial Enterprises, Inc. – has entered into an agreement to purchase terminals in Charlotte, N.C., Chattanooga, Tenn., and Fredericksburg, Va., from Lincoln Terminal Co., Inc. According to Lincoln’s website, the three terminals boast 525,000 barrels of tank capacity. Colonial pointed out the Charlotte and Chattanooga terminals are linked to the Colonial Pipeline system. The system spans more than 5,500 miles (8,851 kilometers), linking Gulf Coast refineries to markets throughout the Eastern U.S. Colonial stated the acquisition offers the company an “excellent opportunity” to enter the terminal business. It contends the move will allow it to offer a complementary service to the markets, including Colonial Pipeline customers. Moreover, it stated the company is laying the groundwork for further strategic expansion. “Terminals are a natural extension of Colonial’s overall business, providing the opportunity to serve customers in new ways while building and strengthening relationships,” the firm stated.

‘Kafkaesque’ FERC Pipeline Process Needs Revamp, Court Says –Federal regulators can’t dawdle on pipeline appeals and keep challengers out of court in the process, the D.C. Circuit ruled Tuesday in a landmark decision for energy law. The Federal Energy Regulatory Commission violated the law by routinely issuing “tolling orders” that prevent pipeline opponents from seeking judicial review while an agency petition process drags on and industrial development moves forward, the court said. The ruling is a major victory for landowners, environmentalists, and other pipeline critics who can now get to court faster to challenge projects, and may have a better shot at blocking construction. “Now, the government must stop allowing construction of pipelines while keeping the courthouse doors closed to those who are directly affected by them,” Kelly Martin, head of the Sierra Club’s Beyond Dirty Fuels Campaign, said in a statement. FERC’s tolling order practice effectively rewrote federal law to say “it can take as much time as it wants; and until it chooses to act, the applicant is trapped, unable to obtain judicial review,” Judge Patricia A. Millett wrote for the court. “But the Commission has no authority to erase and replace the statutorily prescribed jurisdictional consequences of its inaction,” she concluded. The full slate of 11 active judges on the U.S. Court of Appeals for the District of Columbia Circuit decided the case. The court agreed to review the case en banc after Millett in 2019 called FERC’s review process “Kafkaesque.” Avoiding Court The D.C. Circuit’s ruling still allows FERC to take extra time to consider whether a contested pipeline approval was proper. But the commission can no longer use tolling orders to avoid judicial review in the meantime. That means the agency must streamline its internal review process, or be equipped to defend against legal challenges earlier in the process. Pipeline opponents, meanwhile, can sue FERC and attempt to block construction before it begins – an option that was often impossible before.

Enbridge: Boat anchor, wire cable may have caused Line 5 damage ⋆ Embattled Canadian oil company Enbridge has still not been able to determine how an anchor support holding up the east segment of the Line 5 pipeline was damaged, according to court documents submitted to the Ingham County Circuit Court Monday.Enbridge does, however, raise the possibility that a boat anchor caused the damage to the east segment of the dual underwater pipeline. The reply brief also states that an “area of interest” on the west segment of Line 5 could have resulted from a wire cable dragged by a boat.The documents were submitted ahead of oral arguments in Nessel v Enbridge, which are scheduled for 1:30 p.m. Tuesday and will address Attorney General Dana Nessel’s request for a preliminary injunction. On Thursday, Judge James Jamo granted Nessel’s request for a temporary restraining order on Line 5’s operation. Enbridge agreed that day to completely shut down the pipeline until a determination is made in court. “While Enbridge has not yet reached a final conclusion, there is visible evidence that the area on the West Line resulted from a vessel dragging a relatively thin item such as a wire cable in a direction perpendicular to the Line,” Enbridge’s reply brief reads. ” … In contrast, the damage to the East Line anchor assembly and markings on the lake bed near the damaged anchor assembly are more consistent with damage caused by a vessel of modest size dragging an object parallel to the Line.” The company’s attorneys argue that neither incident put the pipelines in immediate danger and Enbridge is taking steps to prevent further damage. In Tuesday’s filings, Enbridge attorneys argue that Nessel has neither factual nor legal basis for requesting the “extraordinary injunctive relief” that she seeks. They also contend that because federal regulators at the Pipeline and Hazardous Materials Safety Administration (PHMSA) already gave the OK for Enbridge to restart the west line of Line 5, Jamo should lift the restraining order so as to not violate federal law.

Public hearing to be held on Enbridge Energy’s proposed line relocation – In response to widespread interest in the upcoming public hearing on Enbridge Energy’s proposed relocation of the Line 5 pipeline in Ashland, Bayfield, and Iron counties, the Wisconsin Department of Natural Resources is hosting a virtual public hearing on Wednesday, July 1.The public can watch the hearing live beginning at 4 p.m. After the hearing is over, the same Media Site link will take people to an online recording of the hearing.Members of the public who wish to provide oral testimony during the hearing will be able to do so using the Zoom Remote Conferencing Platform, which is accessible by computer or phone. Information on how to register to participate via Zoom is available on the DNR’s Enbridge Pipeline Projects web page.The DNR is asking people who want to watch the hearing but do not wish to provide oral testimony to use Media Site instead. That will help ensure that people who wish to testify at the hearing will be able to do so.The hearing will cover Enbridge’s application for a waterway and wetland permit, as well as the scope of the Environmental Impact Statement that will be prepared for the overall project. As proposed, the project would involve construction of 42 miles of new 30-inch pipeline needed to relocate the existing Line 5 pipeline outside of tribal lands of the Bad River Band of Lake Superior Chippewa.Members of the public can submit written comments on the waterway and wetland permit application and the scope of the EIS by email, to [email protected], or by U.S. mail to “Line 5 Comments, DNR (EA/7),” 101 South Webster Street, Madison, WI 53707. All electronic and hardcopy comments must be submitted or postmarked by no later than Saturday, July 11.More information on the proposed project, permit application, and to review a draft outline of the Environmental Impact Statement is available here.

Regulators deny quick approval of new Great Lakes pipeline (AP) – A Michigan regulatory panel on Tuesday refused to grant quick permission to run a new oil pipeline beneath a channel that connects two of the Great Lakes, deciding instead to conduct a full review. The state Public Service Commission’s decision involved a proposed replacement for a segment of Enbridge’s Line 5 that extends beneath the Straits of Mackinac, which links Lakes Huron and Michigan. The Canadian energy transport company wants to replace dual pipelines that rest on the lake floor with a new pipe that would be placed in a 4-mile-long (6.4-kilometer-long) tunnel to be drilled in bedrock beneath the waterway. Also Tuesday, a state judge heard arguments on whether to extend an order he issued June 25 to shut down the existing underwater segment after damage was discovered on a support piece at the lake bottom. Circuit Judge James Jamo promised to move quickly but made no immediate ruling. That means Line 5 – which carries 23 million gallons of crude oil and natural gas liquids daily between Superior, Wisconsin, and Sarnia, Ontario – will remain closed for now. The 645-mile-long (1,038-kilometer-long) pipeline supplies refineries in Michigan, Ohio and Pennsylvania, as well as the Canadian provinces of Ontario and Quebec. Enbridge said halting its flow even temporarily threatens fuel supplies in those areas, while the state of Michigan and environmental groups contend a major spill would do considerably worse economic damage. “There is a serious risk of harm … to many communities that potentially endangers the livelihood of many people and businesses as well as the natural resources,” Robert Reichel, representing state Attorney General Dana Nessel’s office, said during the online court hearing. Enbridge filed an application in April with the Public Service Commission to relocate the underwater section of Line 5 into the proposed tunnel. The company asked the commission to approve the plan immediately, arguing that the agency in effect had already given permission by allowing the original Line 5 in 1953. But during an online meeting, the panel disagreed on a 3-0 vote. Members concluded that the proposed tunnel pipe “differs substantially” from the twin pipes that were laid 67 years ago, requiring a new easement and a 99-year lease of public trust property.

Michigan regulator: Enbridge needs permission to move Line 5 into tunnel – The Michigan Public Service Commission will not give Enbridge Energy carte blanche to relocate the Line 5 pipeline inside a tunnel beneath the Straits of Mackinac, it ruled Tuesday. The decision triggers a lengthy administrative process to evaluate Enbridge’s plan to relocate the lakebottom petroleum pipeline inside an underground tunnel; a process Line 5 opponents hope will be a key forum for public scrutiny over the pipeline’s future.Enbridge had asked the commission, Michigan’s energy regulator, to rule that it doesn’t need the state’s permission to relocate Line 5 inside the planned tunnel. The company argued that the commission’s 1953 approval of the existing dual-span lakebottom line also covers its plan to replace that section with a 30-inch diameter pipeline running through a concrete-lined tunnel deep beneath the lakebed. The company already has the state’s initial approval to build the tunnel, but it now needs the commission’s approval to move the pipeline into it. The commission rejected the company’s argument and refused to grant its approval Tuesday, opting instead to forward the matter as a so-called “contested case,” allowing Enbridge and the public to debate the matter before an administrative law judge. Ultimately, commissioners will decide whether to grant Enbridge’s relocation request. The deliberations will test the loyalties of a commission whose political makeup has changed significantly since Democratic Gov. Gretchen Whitmer took office last year, replacing two former appointees of GOP predecessor Rick Snyder, Republican Norm Saari and Independent Rachel Eubanks, with Democrats Dan Scripps and Tremaine Phillips to create a 2-1 Democratic majority, with the third member, Chair Sally Talberg, being an independent. As the commission deliberates on the pipeline, Enbridge is moving forward with the tunnel plan. The company is awaiting state and federal permits with the goal of beginning construction on the tunnel next year. Multiple parties, including Native American tribal governments and environmental groups who have advocated for the pipeline’s shutdown, have filed motions to intervene in the proceedings. They have long called for the 67-year-old pipeline’s shutdown, arguing it poses an unacceptable oil spill risk in the Straits, where it sits exposed on the lakebottom as it pumps crude oil and natural gas between Ontario and Wisconsin.

Enbridge to court: State can’t override feds’ regulation of Line 5. – Michigan can’t order the Line 5 oil and gas pipelines on the Straits of Mackinac lake bottom shut down even temporarily over concerns about anchor strikes or other damage – only federal regulators of interstate pipelines have that authority, Enbridge’s attorneys argued in an online court hearing Tuesday. The company is fighting a preliminary injunction sought by state Attorney General Dana Nessel, seeking to keep Line 5 shut down until Enbridge provides the state with all information related to “significant damage” found June 18 to an anchor support on the east leg of the twin underwater pipelines, and a mark from some object apparently striking the west leg of the line, potentially affecting its outer protective coating.The state wants its own evaluators to determine whether it is safe to continue operations of either or both of the pipelines. Nessel’s office cites the state’s 1953 easement with Enbridge allowing it to place and operate the pipes on the state-held lake bottom. A provision in that easement requires the pipeline operator “at all times shall exercise the due care of a reasonably prudent person for the safety and welfare of all persons and all public and private property.”Ingham County Circuit Court Judge James Jamo last Thursday ordered Enbridge to shut down Line 5 in the Straits, pending the outcome of Tuesday’s hearing on a temporary injunction. After more than four hours of testimony Tuesday, Jamo said he would consider the evidence and issue a written ruling, likely within the next few days.”Underlying this case, and relevant to this motion, there is a serious risk of harm, not only to natural resources, but to many communities – that endangers, or potentially endangers, the livelihood of many people and businesses,” assistant state attorney general Robert Reichel said.Though Enbridge last week provided state officials with engineering reports and video from its remote-operated vehicles inspecting the underwater pipes, critical information is still not available to the state to evaluate whether the pipelines should continue operating, Reichel said. Enbridge now believes that the damage was done to the individual underwater lines by two separate boats in separate incidents – one ship traveling east-west through the Straits, dragging something other than an anchor, perhaps a cable, based on drag marks and the glancing loss of outer biological coverings on the west leg pipeline, and the other ship traveling north-south through the Straits, parallel to Line 5, that caused the damage to the east leg anchor support.

Enbridge’s Damaged Line 5 Allowed to Restart by Michigan Judge – Enbridge Inc. can partially restart its dual oil and gas pipeline below Lakes Michigan and Huron, even though one leg of the line remains closed due to damage, a state court ruled Wednesday. The Canadian energy titan convinced Ingham County Circuit Court Judge James Jamo to deny a preliminary injunction to Michigan Attorney General Dana Nessel. The judge issued an amended temporary restraining order requiring Enbridge to provide information to the state’s attorneys and keep the eastern leg of the pipeline closed. Federal regulators gave Enbridge the green light to reopen the western leg of the pipeline, which the company said it plans to start doing immediately. Jamo concluded the risk of rupture in Line 5’s undamaged western section was remote enough that the company should be allowed to operate that portion while investigating damage in the line’s eastern leg. The order saves Enbridge roughly $1.76 million per day, which it says it lost while the line was shut down. Jamo seemed to accept arguments from Enbridge’s attorneys that the pipeline’s west leg must be restarted in order to perform an in-pipeline assessment of the damage discovered on June 18. Jamo said the company’s duty of “due care” required it to restart the western leg so an “in-line-investigation” of the pipeline could be completed and technical data could be shared with state and federal regulators. Enbridge will begin restarting the west segment and anticipates “operations will soon return to normal,” company spokesman Ryan Duffy said in an email. Enbridge doesn’t know what caused the damage to the underwater pipe, but the firm’s initial findings indicate a boat may have dragged a fishing line across the western pipe, and a boat’s anchor may have struck a support for the eastern pipe. The court ordered the eastern leg to remain closed until the Pipeline Hazardous Materials Safety Administration investigates the damage and Enbridge completes all repairs the federal regulator recommends.

Frac sand producer Covia files for bankruptcy; $1B cost reduction plan proposed – other Wisconsin sand mine operator is facing bankruptcy as the COVID-19 pandemic and falling oil prices continue to shake the industry. Covia, which owns permitted mines and plants in Columbia, Dunn, Monroe, Pierce and Waupaca counties, filed for Chapter 11 bankruptcy Monday, saying a restructuring plan negotiated with lenders will eliminate more than $1 billion in fixed costs. The Ohio-based company said it has more than $250 million cash on hand that will allow the company to continue operation during the proceedings. CEO Richard Navarre said the bankruptcy was brought on by a combination of the COVID-19 pandemic and “recent energy price shocks” that significantly affected Covia’s customers, which include oil and gas producers who use sand to prop open cracks in underground rock formations. Along with the pandemic, which has triggered a global recession, oil prices plunged in March when the 13-member Organization of Petroleum Exporting Countries. According to court filings, this came on the heels of two difficult years for producers of the high-quality Northern White sand found in Wisconsin: starting in late 2018, the companies that drill for oil and gas scaled back operations when lenders pulled back; at the same time, the supply of sand essentially doubled as producers opened dozens of new mines, and producers turned to cheaper, lower-quality sand mined closer to oil fields.

A Texas-based oil and gas company files for bankruptcy (AP) – Texas oil and gas company Sable Permian Resources has recently filed for bankruptcy. Sable Permian Resources filed for Chapter 11 bankruptcy protection last week in federal bankruptcy court in Houston, according to a news release. Permian Resources was once part of American Energy Partners, a company founded by Aubrey McClendon in 2013, The Oklahoman reported Tuesday. American Energy announced it would close in 2016, splitting up operations into separate companies, including Permian Resources. In 2017, it became Sable after the company reached a $1 billion deal with creditors to continue operating. The company and its affiliates said the bankruptcy filing will allow them to position the companies for long-term success. If first day motions are approved, the companies would be able to to continue operations. They arranged $150 million for that. Chesapeake Energy, which McClendon also founded, filed for bankruptcy this week.

Houston-based Sanchez Energy emerges from bankruptcy under new name – Houston oil company Sanchez Energy has exited from Chapter 11 bankruptcy with a new CEO and as a privately held company under new leadership and the name Mesquite Energy.Once among the largest drillers of the Eagle Ford Shale of South Texas, bankruptcy proceedings allowed the company to shed $2.3 billion of debt. The company’s founding CEO Tony Sanchez is leaving the company while chief financial officer Cameron George has been named as interim CEO.”We are excited to begin our new chapter as Mesquite Energy, a simpler and leaner company, guided by our core principles of cost discipline and production efficiency to create long-term value for our stakeholders,” George said. Saddled by debt and high interest payments, the company filed for Chapter 11 in August 2019 and emerged with new leadership.Nathan Van Duzer with Fidelity Investments, Wilson Handler with Apollo Global Management and oil industry veteran Harry Quarls have been named to the reorganized company’s board of directors.The company’s general counsel Gregory Kopel will remain at Mesquite as executive vice president, general counsel and corporate secretary.”With a clean balance sheet and substantial repositioning of our cost structure, we have taken the hard but necessary steps to become profitable in this low commodity price environment,” George said.

Some Populated Texas Areas Are At Risk Of Hydrogen Sulfide Pollution According To New Report – The oil and gas industry has become more active in the Permian Basin in recent years, and west Texas residents have complained of noxious smells and increased air pollution. In response, The Texas Commission on Environmental Quality launched two air monitoring surveys in December and February, and the results are now public. The survey teams spent 10 total days in Midland, Odessa, Goldsmith, Seminole and Denver City over December and February. They focused on publicly accessible and populated areas near industrial sites. The surveys measured air pollutants, like sulfur dioxide, and the more poisonous gas, hydrogen sulfide. The legal limit of hydrogen sulfide in Texas is 80 parts per billion over a 30-minute average. That limit was exceeded in several different places on multiple days – in the worst instance, by 500% when the 30-minute average was 400 parts per billion. That level of the gas isn’t enough to cause immediate, serious health concerns, but it can do damage in the long term, says Afamia Elnakat, a doctor of environmental toxicology at University of Texas San Antonio. “Well, in terms of long-term exposure, we look at it the same way we look at either respiratory irritant or long term. And that is basically as much as people will be impacted, you become less tolerant to other irritants,” said Elnakat. She added the levels of hydrogen sulfide documented in the survey would likely affect the most sensitive groups only. (embedded study: Permian Basin Survey: Lubbock and Midland)

Exxon Reports Roof Problem, Spill at Beaumont, Texas, Refinery – Exxon Mobil Corp. said a storage-tank’s floating roof gave way Friday at its Beaumont, Texas, refinery, causing thousands of pounds of chemicals to spill out.”A roof on a floating roof failed,” the 362,000-barrel-a-day refinery said in a filing Friday night to the Texas Commission on Environmental Quality. “The material is being pumped into another tank. Vacuum trucks have been deployed to recover spilled material.”Exxon said it expected to finish cleaning up on Sunday. The spill included some 8,000 pounds of benzene, more than 2,000 pounds of ethylbenzene and other chemicals. This is at least the third storage tank roof problem Exxon has reported at its Texas refineries in the past year. Valero Energy Corp. also reported roof problems at its 293,000-barrel-a-day Corpus Christi, Texas, refinery earlier this month, saying a floating roof sank and caused spillage.

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