Brown on Business

December 21-27, 2020

ExxonMobil’s $20 billion write-off signals tail-end of Arkansas’ Fayetteville Shale

By Wesley Brown
wesley@dailydata.com

In a nod to Wall Street that it is still on schedule to slash nearly 3% of its early 75,000-person global workforce by 2021 and save the company’s pricey annual dividend payment, ExxonMobil Corp. also has quietly put the final nail in the coffin for Arkansas’ largest and most expensive energy development that reached its peak almost exactly 10 years ago.

On Dec. 1, ExxonMobil Chairman and CEO Darren Woods announced that the Dallas-based oil conglomerate had completed its review of its forward business plans that will prioritize near-term capital spending on oil and gas assets with the highest potential future value, including ongoing exploration and production projects in Guyana, Brazil and the shale-rich U.S. Permian Basin. The former Standard Oil subsidiary also plans to continue focus on its cutting-edge chemicals and research business.

In a year that has highlighted the spectacular bust cycles of the the oil and gas sector, Woods told ExxonMobil shareholders and investors that the company was still on track to cut capital expenses by $10 billion or 30% in 2020, reduce its global workforce by 15% by year-end 2021, and take a non-cash, after-tax fourth quarter write-out of between $17 billion to $20 billion. 

The year-end cost-cutting, Wood said, is part of the efforts by the ExxonMobil’s efforts to reprioritize its investments, strengthen its balance sheet, and continue handing out a pricey $3.48 dividend payment to shareholders that has grown at an average annual rate of 6.1% over the last 38 years.

“Recent exploration success and reductions in development costs of strategic investments have further enhanced the value of our industry-leading investment portfolio,” said Woods.  “Continued emphasis on high-grading the asset base - through exploration, divestment and prioritization of advantaged development opportunities - will improve earnings power and cash generation, and rebuild balance sheet capacity to manage future commodity price cycles while working to maintain a reliable dividend.”

Woods added the business environment in the fourth quarter of 2020 is showing signs of improvement despite the resurgence in COVID-19 cases and accompanying economic restrictions. “Prices and margins for many of our businesses have improved from the third quarter and when coupled with continuing efforts to reduce spending and capture additional efficiencies, quarter-to-date cash flow has improved versus our plan assumptions,” he said.  

Although it not noted in the Dec. 1 statement, the $17 billion to $20 billion impairment charge included the “removal of less strategic assets … that (included) certain dry gas resources in the Appalachian and Rocky Mountains, Oklahoma, Texas, Louisiana and Arkansas in the United States, and in western Canada and Argentina,” the company said of record industry tax write-off.

In essence, ExxonMobil is writing off the $36 billion, stock-and-debt purchase of crosstown rival XTO Energy exactly eleven years ago. Fort Worth, Texas-based XTO that was founded in 1986 with an $35 million investment by Robert Rubin, the former Goldman Sachs executive who famously served as the U.S. Treasury Secretary for former President Bill Clinton.

No longer after that blockbuster acquisition, XTO made a surprise announcement a year later in December 2010 that it was purchasing Fayetteville Shale properties in Arkansas from Petrohawk Energy for $575 million. At the time of the deal, Petrohawk’s had proved reserves of 299 billion cubic feet of natural gas in Arkansas that were already producing 98 million cubic feet of natural gas equivalent per day.

A few months later, Australia industrial conglomerate BHP Billiton also made its first big bet in the rapidly expanding U.S. onshore shale oil and gas sector, paying $4.75 billion in cash to purchase nearly 487,000 net acres of leasehold and producing natural gas properties in the Fayetteville Shale from Chesapeake Energy Corp.

BHP brought its cash investment to the Arkansas shale play nearly five years after peak production in 2007 supported total annual economic output of $2.6 billion and direct and indirect employment of nearly 10,000 workers, according to the study by the University Arkansas.  A few years later, another University of Arkansas study showed that Southwestern and other U.S. oil and gas companies like Chesapeake Energy, BHP and XTO Energy had spent more than $13 billion and hired thousands of high-paid workers in the Arkansas play between 2004 and 2009.

After several years of growth in the decade following the turn of the century, the unconventional Arkansas energy development has been on a steady decline since 2010 as the number of rigs and active drilling programs came to a halt in late 2016, causing to Southwestern cut nearly 600 workers in Arkansas.

By late 2017 and early 2018, both Southwestern and BHP were seeking in exit strategies from the Arkansas development as natural gas prices remained depressed below the $3 per million British thermal units (Btu) breakeven point for several years. In July 2018, BHP announced that MMGJ Hugoton’s Merit Energy subsidiary in Dallas agreed to acquire 100% of the Australian mining conglomerate’s stake in the company’s Fayetteville Shale assets for an asking price of only $300 million. 

That price tag for BHP’s 268,000-acre leasehold position in the once-prosperous Arkansas natural gas play was a far cry from the substantially higher bids near $2 billion that some Wall Street analysts had forecasted. Like ExxonMobil’s pricey $20 billion write-off this year, BHP also booked a pre-tax impairment charge of nearly $7.2 billion against the carrying value of its onshore U.S. oil and gas assets at end of 2019.

Still, the biggest loser in the Arkansas dry gas play was the once high-flying Fayetteville Shale leader Southwestern Energy, whose market value topped $35 billion in the summer of when the oil and gas driller’s stock price topped $45 per share. That same year, Southwestern capital spending rose to more than $2.3 billion with most of that budget targeted in the Arkoma basin across the top half of Arkansas.

In late December 2018, after several straight years of budget cuts amid declining natural gas prices, the Houston-based oil and gas independent’s run in the Arkansas shale play came to an end after it announced that Oklahoma City-based Flywheel Energy LLC had acquired the top leasehold position in the Arkoma basin development in a deal valued at $1.86 billion. Three months earlier, the last natural gas drilling rig operating in Arkansas over the past 29 months was pulled offline, a far cry from the peak in 2008 when the state’s rig count reached 60.

Today, only privately held Flywheel of Oklahoma City and Dallas-based Merit Energy hold substantial investments in the state’s Arkoma Basin. The good news is that most oil and gas analysts believe Fayetteville Shale reserves will likely last for another 30 years, allowing the Texas and Oklahoma leaseholders to squeeze margins from marketed natural gas sales for years to come until spot prices rebound in the future.

Still, the U.S. Energy Information Administration recently cut its forecasts for 2020 by 3.2% to $2.07 per million British thermal units (Btu) and for 2021 by 4.1% to $3.01. At the same time, natural futures prices for January 2021 delivery to the Henry Hub in Louisiana are trading at just over $2.40 per million British thermal units.

And after ExxonMobil’s raised up a white flag on the Arkansas play earlier this month, a strong signal was sent to the rest of the oil and gas industry that the Arkansas shale play’s best days are behind it – at least for the foreseeable future.