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Oil and gas market decimated by COVID-19 in 2020, production poised for recovery next year

Adrian Hedden
Carlsbad Current-Argus

New Mexico’s fossil fuel market finished 2020 in recovery from the COVID-19 pandemic and historic losses in the value of oil and gas and production levels throughout the state.

After April’s market crash to as low as -$40 per barrel, the lowest price in history, and a dramatic drop in New Mexico’s rig count by more than 60 percent in the months after the pandemic struck the state in March, the late fall and early winter saw some slight rebound.

But the market was still far off from the record-setting, pre-pandemic growth.

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As of Tuesday, Nasdaq reported domestic oil was trading at about $47 per barrel, following a steady increase this month after starting December at about $44 per barrel.

The year started at about $61 per barrel, well above the $50 benchmark most analysts say is needed for operations to remain profitable.

That increase in price was followed by an uptick in active oil and gas rigs in New Mexico, Texas and the shared Permian Basin.

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As of Dec. 18, the latest data from Baker Hughes showed New Mexico had 66 active rigs, averaging 62 so far in December after climbing to 59 on Dec. 4 and 60 on Dec. 11.

The growth in December continued an upward trend that started in the fall, reversing a downward spike from a peak of an average 114 rigs in February and March to a valley of 44 rigs in September.

Texas also saw big losses in rigs this year, starting 2020 with an average of 398 rigs but dropping to 105 in August.

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The Lone Star State also saw a slight recovery in its rig county this fall, inching up to an average 154 active rigs so far in December.

The Permian Basin, the U.S.’ most active oil play spanning southeast New Mexico and West Texas, was down 240 rigs in the last year to 174, but was up six rigs in the last week, records show.

Oil and gas majors merge to survive

To weather the downturn, many major oil and gas operators in the Permian merged to survive in numerous multi-billion-dollar deals intended to decrease capital spending and focus extraction efforts on the most profitable areas of the basin.

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Most recently, Diamondback Energy acquired QEP Resources and Guidon Energy to increase its footprint by 80,000 acres in the Midland Basin – a sub-basin of the Permian on the Texas side – for a total of $3 billion – $2.15 billion for QEP and $862 million for Guidon.

Andrew Dittmar, merger analyst with Enverus said the move was consistent with the continued consolidation trend seen in the industry amid the lower-price environment.

 “The acquisition of QEP by Diamondback fits firmly within the mold established for 2020 public (exploration and production) consolidation,” he said. “It focuses on immediately boosting cash flow to fund shareholder capital returns and debt reduction.”

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Diamondback’s acquisitions followed a $13 billion deal where Chevron Energy acquired Noble Energy in July, Pioneer Natural Resource’s $7.6 million buyout of Parsley Energy in October and ConocoPhillips’ $9.7 billion acquisition of Concho Resources earlier that month.

In a recent report, Enverus predicted fuel demand, and thus oil and gas production, would not return to pre-pandemic levels until 2024, expecting more outbreaks of the virus as public health restrictions are lifted.

“Our expectation that annual oil demand likely will not revert to pre-COVID levels until 2024 rests on the assumptions related to employment levels, economic activity, the efficiency of oil use and structural elements influencing the macroeconomy and oil demand,” the report read.

“Rather than dwell on the specific date of 2024, however, the major takeaway here is that demand will require time to recover, and certainly more than a year or two.”

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As officials expect widespread vaccinations by the spring and end of 2021, led by two vaccines recently developed by Pfizer and Moderna, Enverus predicted demand for fuel could spike as people were likely to increase travel and other uses dramatically when restrictions are lifted.

“Hopefully, the global COVID-19 pandemic will be vanquished in 2021 as a large swath of the global population gets vaccinated,” read the report. “The return of pent-up demand in the latter half of 2021 should provide positive momentum heading into 2022.

But the impact of the virus on fuel demand and the oil and gas markets could be felt for years to come, the report read, and the industry could be challenged further by an increase governmental focus on climate change and restrictions on production as Democrat President-elect Joe Biden takes office.

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“Even once global oil consumption returns to pre-pandemic levels, increasing social and policy obstacles to fossil fuel consumption, technological advances and possibly enduring impacts of the pandemic on consumer and business behavior will be headwinds to further demand growth, read the report.

Is oil and gas industry running out of land to drill in New Mexico?

But even if demand improves in the coming years, there may be less available state land in New Mexico, where about a third of the state’s oil and gas production occurs.

The New Mexico State Land Office reported its final oil and gas lease sale of 2020, held on Dec. 15, brought in about $2.36 million for 2,880 acres.

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In total, 2020 leases sales brought in about $16.9 million – a 67 percent drop from 2019’s total of about $52.7 million.

The Land Office reported the decline was brought on by a diminished availability of State Trust land mineral estates, especially in the Permian Basin.

Leases remain active if oil or gas is being produced and cannot be resold until deemed unproductive.

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Following the final sale last week, only 9 percent of mineral estate on State Trust land in the Permian Basin was available for leasing – 2 percent in the Delaware and 7 percent in the Capitan Reef sub-basins.

And for the last bits of State Trust land to be leased to the industry, New Mexico Commissioner of Public Lands Stephanie Garcia Richard said her office intends to get the best return possible, petitioning lawmakers to increase royalty rates operators pay to the state on production and implementing minimum bids for tracts of public land while increasing efforts to enforce remediation obligations.

Garcia Richard advocated for similar policy changes in the 2019 Legislative Session, but the measure was defeated.

Stephanie Garcia Richard

“We’re taking a hard look at the data available to us, and what it is telling us is that all or almost all of the premium state trust land oil and gas tracts could be held by a lease within the next few years,” she said.

“The State Land Office has taken action to assure that we are making as much money for our beneficiaries as possible from the land that we still have available.”

Adrian Hedden can be reached at 575-628-5516, achedden@currentargus.com or @AdrianHedden on Twitter.