OGV Energy’s US Energy Overview – The Unknowns of 2021

The US oil and gas industry and the global energy markets entered 2021 with a lot of unknowns.

Two of the biggest unknowns in the US will be how President Joe Biden’s climate and energy policies will impact oil and gas permitting, leasing, and production on federal lands and in federal waters, and how US oil producers will react to the oil price rally so far this year. The price gains have sent the US benchmark West Texas Intermediate up to $65 per barrel, a level at which most operators can profitably drill new wells in the US shale patch.

While it is certain that US crude oil production will not return to the pre-pandemic records of nearly 13 million barrels per day (bpd) this year and next, American output still has the capacity to surprise the market to the upside and potentially undermine the OPEC+ group’s current efforts to tighten the market.

Early into 2021, most public exploration and production companies in the US are showing the promised restraint in spending on drilling, preferring instead to reward shareholders and reinvest a larger portion of their cash flows into returns to shareholders. Even at higher oil prices, the larger listed US firms continue to guide for modest increases in production this year compared to last year.

The Million-Dollar Question: Will Higher Cash Flows Result in Output Boost?

US tight oil operators kept a 55% reinvestment rate in the fourth quarter of 2020, maintaining their commitment of keeping balanced operations despite rallying oil prices that made drilling economics much more favorable across most regions compared to a few months earlier, Rystad Energy said in a report in March.

“The number of operators that balanced their spending in 4Q20 reached 90%, a level never previously recorded in the history of US shale,” Rystad Energy noted.

The peer group of 28 shale producers that the energy research company tracks accounts for 43% of the estimated 2020 US tight oil output. That peer group reported the second-highest level of free cash flow in the shale industry’s history, at $2.8 billion in Q4, following the peak of $3.5 billion in the previous three months, Rystad Energy said.

“Operators continue to focus on balanced spending and free cash flow at levels they have never done before,” the research firm noted.

The top public E&P companies seem to be sticking with promises to keep a rein on spending on drilling activity, but the smaller privately-held firms could be the wild card in estimating US oil production this year.

The closely-held operators generally boost their revenues and profits with more drilling, especially when prices allow profitable drilling in many fields in the shale patch. Those smaller firms do not feel the pressure of the stock market and shareholders, unlike the listed companies which have been punished by the market for not rewarding shareholders enough over the past decade.

The US shale patch is on track to generate a lot of cash flow this year, as operators keep budgets low while oil prices rally. The top 10 independents are set to generate nearly $10 billion of free cash flow over the next 12 months at WTI prices of $50 a barrel, and $20 billion if the US benchmark averages $60 per barrel, according to Alex Beeker, Principal Analyst Corporate Research, at Wood Mackenzie.

Drilling activity and the number of active rigs are picking up from the lows in August 2020, but another 150 oil rigs would be needed just to reverse the production decline from the 2020 hiatus in drilling. At the present rate, that will take six months, Beeker noted. The million-dollar question is will rising cash flows translate into more rigs.

“Our sense is that most still intend to keep a tight rein on spend in 2021,” WoodMac’s Beeker said.

“The risk is that capital discipline wilts under the heat of sustained high prices, and external capital floods back into the sector. WTI at US$50 keeps US Lower 48 output flat at 9 million b/d, US$60/bbl adds 1 million by the mid-2020s and US$70/bbl another 1 million b/d,” Beeker noted.

Due to higher expected oil prices, the US Energy Information Administration (EIA) expects in its March Short-Term Energy Outlook (STEO) crude oil production to average 12 million bpd in 2022, an upward revision of 500,000 bpd compared to the February projection. This year, production is seen slightly down from 2020, at 11.1 million bpd in 2021, compared to 11.3 million bpd last year.

US Oil Production Growth Set To Slow Due To Leasing Restrictions

Apart from the unknowns of how the US oil and gas industry will react to oil price trends this year, the sector is also bracing for possible changes to oil leasing and permitting requirements governing federal lands and federal waters.

In Texas, the biggest oil-producing US state, a small portion of onshore federal lands would be impacted directly by leasing restrictions, Jason Modglin, President of the Texas Alliance of Energy Producers, said at the virtual Congressional Western Caucus series. The main impact in Texas will be in challenges to offshore leasing and permitting, Modglin added, noting that a study commissioned by the American Petroleum Institute (API) found that a total interruption of federal leasing and permitting would lead to US offshore natural gas and oil production decreasing by 68% and 44%, respectively, raising at the same time US imports of crude oil.

The outcome of the Administration’s review of federal leasing and permitting policies is still uncertain, but Garrett Golding and Kunal Patel, business economists in the Research Department at the Dallas Fed, tried to estimate the impact of a range of restrictions on the Permian Basin in a report in March.

Permian oil production is expected to rise in all three scenarios—little-changed policies; no new federal leasing but existing leaseholders continue receiving drilling permits; and the most extreme scenario, in which no new federal permits or extensions are granted starting in 2023, when the most-recently issued permits will expire.

With little-changed policies, Permian Basin oil production is set to grow from 4.3 million bpd today to 5.3 million bpd in December 2025. New Mexico’s production will increase from 1.0 million bpd to 1.5 million bpd, according to Dallas Fed’s economists. In the hybrid case assuming no new federal leasing, but existing leaseholders continue receiving drilling permits, Permian production would rise to 5.1 million bpd in 2025, and New Mexico’s oil output would rise only slightly to 1.1 million bpd.

In the restrictive-case scenario, however, in which no new federal permits or extensions are granted starting in 2023, Permian production still rises to 4.8 million bpd in 2025, but New Mexico’s output drops to 700,000 bpd, as many areas of the Permian in New Mexico are on federal lands.

“Half of New Mexico’s production comes from federal acreage in the Permian Basin, and the anticipated actions would slow economic growth, adversely affecting that state’s employment and tax collections,” the Dallas Fed said.

The analysis focused on the Permian, but the economists expect production from other basins to also drop compared to business-as-usual forecasts.

In Wyoming, for example, the federal lease moratorium will impact 75% of the state’s conventional fields and 60% of drillable land, the University of Wyoming’s Enhanced Oil Recovery Institute (EORI) said in a report in early March.

“This policy will restrict, or possibly prevent, access to 2.9 billion barrels of potentially recoverable oil reserves on federal lands and the associated $12.9 billion in tax revenue,” the report says.

This year is already shaping up as a crucial year for the US oil and gas industry. It will show how well – financially and production-wise – US operators have handled the worst price crash in decades, and how much future federal leasing policies would impact the sector.

Published: 02-04-2021

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