Will New Mexico learn from coal’s decline?

The state relies on oil and gas revenue, but the industry faces an uncertain future.


Aerial view from 15,000 feet showing oil and gas infrastructure in Raton Basin, New Mexico.

This story was originally published by Capital and Main and is republished here by permission.

Satellite images of the land outside Artesia, New Mexico, show an arid brown landscape pockmarked with dots. Zoom in a bit, and a semiregular grid pattern appears, which could be mistaken for a suburban development. Zoom once more and the truth becomes clear: oil drilling sites, thousands of them. Each of these wells will one day need to be cleaned up: the borehole plugged and the land restored. When abandoned, wells like these will leak methane and other pollutants into the atmosphere for years.

More than 1,500 miles east and north of Artesia, among rolling hills of Appalachia, there are streams tinged orange by acid mine drainage and mountaintops flattened by companies seeking the hard, black coal seams underneath. Many of these companies are now bankrupt, or shadows of their former selves, while the industry’s legacy persists in billions of dollars in cleanup costs.

Petroleum replaced coal as America’s fuel of choice and, in coal’s decline, oil and gas may catch a glimpse of its own future.

Beginning last year, the pandemic buffeted New Mexico’s oil and gas drillers. After the pandemic tanked global oil demand, drillers and oilfield service companies went bankrupt, thousands of workers lost their jobs, and the industry’s aggregate debt approached record levels. A significant chunk of New Mexico’s annual revenue – often ranging from 15% to 25%, according to the state, and reaching 34% in 2020 – depends on drilling dollars, while the prospective cleanup costs are monumental. This bind is not new or unique. In fact, New Mexico only has to look at the coal industry’s decline – and what that decline meant for mining dependent states – to see what happens when a fossil fuel industry goes under.

States like West Virginia in the East and Wyoming in the West were as reliant on coal dollars as New Mexico is on oil and gas revenue.

In 2013, Wyoming took in $239 million in revenue from federal coal leases, money that went to public schools, according to our analysis. By 2019, that number was zero. Last year, Wyoming – which, like New Mexico, is also suffering from oil and gas’s decline – enacted enormous budget cuts, with more on the way.

And the outlook shows a clear trend: A recent report from Morgan Stanley suggests coal could be fully eliminated as a source of electricity in the U.S. by 2033.

This future was avoidable, says Shannon Anderson, an attorney with Wyoming’s Powder River Basin Resource Council. Anderson argues that state leaders denied coal’s decline for more than a decade, missing multiple chances to diverge from its mineral extraction dependence and diversify the economy. But when the money is good, she explained, state lawmakers have little incentive to change, even when the warning signs are clear.

“Lots of fossil fuel economies are like this,” Anderson says. “Once you get a lot of revenue, you spend it in an earmarked way, you want to pump it into programs, and you come to expect that it will be there.”

New Mexico stands today, in its relation to oil and gas, approximately where coal states like Wyoming were a little more than a decade ago.

Beyond the budgetary dependence, coal’s cautionary tale for New Mexico extends to corporate behavior as market share declines and environmental obligations and reclamation costs kick in. New Mexico stands today, in its relation to oil and gas, approximately where coal states like Wyoming were a little more than a decade ago, says Clark Williams-Derry, an energy finance analyst with the Institute for Energy Economics and Financial Analysis.

He cautions that the oil and gas industry’s decline will not be the same as coal’s – which he compares to “Wile E. Coyote running off a cliff.” But, he says, “when it comes to corporate inability and unwillingness to meet their cleanup costs, there are worrying similarities between the two extraction industries.

“If there’s a financial collapse,” Williams-Derry says, “there’s a chance that large segments of the oil and gas market are already insolvent and wouldn’t be able to pay their corporate debt, let along their environmental obligations.”

THE COAL INDUSTRY powered American industrialization, as Appalachian coal fueled power plants and fed the blast furnaces that made iron and steel. Petroleum reduced coal’s market share starting in the mid-20th century, but coal persisted as an economic power. By the early 2000s, Wyoming had overtaken the East as the dominant coal producing region of the U.S., opening some of the largest mines in the world, where giant excavators known as draglines pummel 80-foot-thick seams of coal.

Coal consumption in the U.S. hit a peak in 2007, with most of production bound for electrical generation. But the industry has been in a steep decline ever since, down by more than 60%, as natural gas and renewable generation undercut coal’s profitability.

Now, thermal coal – the kind that goes in power plants – is on its way out, leaving barren state budgets and a trail of bankruptcies, abandoned workers and billions of dollars of cleanup. And who will foot the bill for the cleanup of the mines – the tons of refuse and millions of gallons of toxic water – still remains unclear.

Oil and gas’s parallels to coal are not exact, especially on the demand side. Coal consumption relied on power plants and manufacturing industries, while oil and gas markets depend on electric utilities, but also plastics manufacturing and the automobile industry. And while electric cars could well cut into fuel consumption, that’s only a possibility at this point.

But even before the pandemic, the industry had been in a multiyear decline. “In hindsight, 2020 stands out over this dismal period for the industry,” writes Haynes and Boone LLP, a law firm that tracks industry bankruptcies.

This accelerated slide may come as a surprise to New Mexicans, since this same period coincided with a drilling boom in the Permian Basin, driven largely by advances in horizontal drilling technology – and lots of capital from Wall Street. Even while fracking companies struggled to show profits, investors continued throwing money at the industry, what Williams-Derry describes as a “bubble mentality on Wall Street.”

Even though oil prices did not recover to pre-2014 levels, New Mexico’s crude output nearly tripled between 2016 and the start of the pandemic, according to the U.S. Energy Information Administration. This was the crest of a boom going back to the early 2000s, when oil prices surged and advances in fracking technology opened up new shale formations to drillers, who poured into the southeastern corner of the state.

This brought boom times for towns like Hobbs and Carlsbad, New Mexico. Not that there weren’t problems. Residents reported headaches, respiratory problems and other ailments associated with air pollution, as our investigation revealed. Noise from the drilling rigs was a constant backdrop, and oilfield service trucks clogged rural dirt roads.

But the economic benefits were undeniable. Local workers could get jobs on rigs or with oilfield service companies, while local merchants benefited from the out-of-state crews brought in by oil majors. Local and state government coffers filled with lease sale and severance taxes.

In 2018, the largest ever single federal oil and gas lease sale allowed the state to increase education funding by almost half a billion dollars. But New Mexico’s production boom coincided with a slow rolling economic bust for the industry at large. Since the last big oil price crash in 2014, the energy sector has been either the worst or second worst performing sector on the S&P 500 in six out of the past seven years.

Oil prices have crept back up since bottoming out at record lows last spring and currently sit at around $60 per barrel. Rig counts in the Permian Basin show that new wells are being drilled, though substantially fewer than before the pandemic.

But there needn’t be a coal-like collapse in consumption for the economics not to work for many New Mexico drillers, according to Williams-Derry.

In the San Juan Basin, Marathon Petroleum closed its Gallup refinery; there’s been at least one bankruptcy in the New Mexico Permian, while dozens of drillers in West Texas filed for Chapter 11 last year.

It was in this first wave of bankruptcies after the initial pandemic fallout that the parallels with the coal industries became clear.

Last spring, Whiting Petroleum issued nearly $15 million in payments to its top executives, while Chesapeake Energy – one of the original fracking companies that drilled in the Permian – gave its executives a combined $25 million before declaring bankruptcy. One company took millions of dollars in CARES Act stimulus money, declared bankruptcy and gave the exact same dollar sum to its executives, the New York Times found. Similar executive payouts by bankrupted – or soon to be bankrupt – companies became infamous in the coal industry during the 2010s, in what was dubbed “Coal’s Bankruptcy Decade.”

Even as the executives walked away flush, coal companies would use bankruptcy proceedings to spin off their environmental obligations and pension commitments. These risky mines and the attached obligations were then acquired, and then defaulted on again, by smaller and smaller companies, each one looking to make a short-term profit. All together, the nation’s four largest coal companies avoided billions of dollars in environmental and labor obligations, leaving taxpayers responsible for reclamation and cleanup of the mines.

Oil wells in Carlsbad, New Mexico.

THE OIL AND GAS INDUSTRY’S DECLINE may not track coal’s, but industry observers note echoes of coal’s bankruptcy decade. This is especially true in the San Juan Basin, the core of New Mexico’s natural gas drilling industry. Gas prices lagged behind oil after the 2014 crash, which compelled large drillers in northwestern New Mexico to sell their unprofitable wells. Many of these wells were acquired by smaller companies, with less financial ability to reclaim the drilling sites. Many wells were shut in or abandoned, leaking methane into the atmosphere.

“It’s a downward spiral of sites owned by majors, then passed on to independents, then to tiny, itty bitty companies with limited environmental cleanup capacity,” says Nathalie Eddy of Earthworks, an environmental watchdog. More rigorous enforcement is needed, she argues, or the industry’s aftermath risks becoming a public burden.

“If the systems aren’t fixed and the enforcement isn’t there, we are traveling down a pretty phenomenal path of destruction,” Eddy says.

It may not mean much to New Mexicans, but in Appalachia, the name “Patriot Coal” remains notorious. In 2007, Peabody Energy Corp., one of America’s largest coal operators, created a new company, Patriot, which contained all of its financially risky assets. Patriot would subsequently take on a similarly bad batch of mines from Arch Resources, another coal giant.

The bankruptcy was almost inevitable, “a company created to fail,” according to the United Mine Workers of America. Coal miners lost pensions and benefits, and states remain on the hook for enormous reclamation costs. Patriot survived long enough to pay its executives several million in bonuses before going bankrupt a second time in 2015.

It seems that oil majors are now adopting this tactic.

Occidental Petroleum is one of the largest oil drillers in the world, with most of its assets concentrated in West Texas and eastern New Mexico. A few years ago, Occidental spun off most of its less productive assets, largely concentrated in California, into a company called California Resources Corporation (CRC).

CRC accumulated several years of financial losses before going bankrupt in July 2020 with more than $6 billion in total debt. This leaves in question the cleanup of more than 18,000 oil and gas wells in California, according to the Institute for Energy Economics and Financial Analysis.

William-Derry described California Resources Corporation as a “liability time bomb and a play straight out of the coal playbook.” As for Occidental, the company’s 2019 acquisition of Anadarko Petroleum – one of the largest oil and gas mergers ever – has become a financial drag, and financial investors peg Occidental as a bankruptcy risk going forward. The company remains one of the largest holders of Permian assets.

“It’s like a puzzle for these companies: I know I don’t want to pay for these wells. How do I get out of it?” Williams-Derry says.

Flaring from excess gas from oil drilling can be seen throughout San Juan county in northwestern New Mexico.

FOR NEW MEXICO, questions loom large on the horizon: who will pay for its more than 57,000 active wells, and who will curb the emissions that contribute to the climate crisis? In addition to the active wells, currently there are about 650 “orphaned,” or abandoned, wells that need to be plugged and the drill sites reclaimed.

Drillers are supposed to put forward funds in the form of bonds to pay for their wells, and in 2018, the state did increase bonding requirements. Even so, on New Mexico state land, the financial obligations pale in comparison to the cleanup costs.

The estimate to clean up orphaned wells just on state lands is about $25 million, according to Adrienne Sandoval, Oil Conservation Division Director at the New Mexico Energy, Minerals and Natural Resources Department. That’s using a cleanup estimate of about $37,500 per well, which some industry observers say is a low estimate. As of now, there’s about $2.2 million in available industry bonding, Sandoval says.

On federal land, the divide between the financial commitments and cleanup costs yawns wider still. There are more than 7,700 public land drilling leases in New Mexico – concentrated in the southeastern corner and the Farmington area – which contain more than 30,000 producible wells.

The federal bonding required of drillers is even less stringent – just $150,000 for one company to cover all its wells nationwide. This is what’s known as “blanket bonding,” which allows a single operator to put forward a fixed reclamation fee, regardless of the number of wells. This means that as companies acquire more leases, the attendant reclamation bonds do not rise accordingly. Blanket bonds also apply on state land: These range from $50,000 for up to 10 wells, to $250,000 for operators that have more than 100 wells statewide.

New Mexico also has about 6,200 “shut in” wells, or wells that aren’t currently economically viable. At the start of the pandemic, New Mexico regulators eased restrictions on these unprofitable wells, which are normally subject to the state’s “plugging and abandonment rule” if they’re inactive for 15 months. Environmental advocates like Eddy call this a list of wells that are a step from abandonment. Sandoval says these wells are still regulated. It’s always something we’re being proactive about,” she says. She worries about wells that become orphaned without her knowledge, those whose operators walk away without informing the state.

But taking a look at just one company illustrates the problem New Mexico will face in the coming years, as wells are tapped out – or prices drop so low companies can’t afford to run them.

In a recent report, Carbon Tracker noted that Hilcorp Energy Corporation, New Mexico’s largest operator, has 11,500 unplugged wells.

Given the available state and federal bonds, the state would be able to call on about $1.55 million from Hilcorp to clean up those wells. Meanwhile, Carbon Tracker put the full reclamation costs for Hilcorp’s New Mexico wells at $1.2 billion.

Reclaiming all New Mexico oil and gas wells will cost about $10 billion, only a minuscule fraction of which is covered by bonds.

Statewide, the report estimates that reclaiming all New Mexico oil and gas wells will cost about $10 billion, only a minuscule fraction of which is covered by bonds.

Not only that, but New Mexico’s oil and gas reclamation requirements make those for coal look strong by comparison.

Since 1977, coal companies have paid billions of dollars into the Abandoned Mine Land Reclamation Program, a federal program for cleaning up mines. Some coal states required companies to pay into “bond pools,” which create reclamation funds, in case any specific company cannot meet its own cleanup costs. Yet these have proved utterly insufficient. And billions of dollars of cleanup remains.

If New Mexicans don’t want to be left with a giant cleanup bill – billions of dollars over the next few decades – the financial demands on drillers need to increase right away. Extraction companies produce a commodity for profit, Anderson explains, which incentivizes them to get that commodity out of the ground as quickly as possible. These incentives do not align with the realities of boom and bust economies and planning for a decline.

“Reclamation doesn’t make money,” Anderson says, “so unless you put reclamation bonding at a price point where they have to seriously consider it as a liability for their company, they are just going to ignore it.”

As state analysts predict a continued decline in oil and gas revenue for New Mexico – and put the optimistic price of oil at $43 per barrel through fiscal year 2022, the financial outlook looks bleak. Not just for New Mexico. But for oil and gas companies themselves.

Few drillers in the Permian Basin can earn profits at that low price, which means widespread bankruptcies could be on the horizon. And that would leave New Mexico not only with a gaping budget deficit, but on the hook for billions of dollars in abandoned wells and environmental cleanup.

“States like New Mexico have to be very careful,” Williams-Derry says, “because there are very direct parallels to what’s happened in coal. The party is over, and once the party is over, who pays for the cleanup?”

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