The US shale industry is set to achieve a significant milestone in 2021: If WTI futures continue their strong run and average at $60 per barrel this year and natural gas and NGL prices remain steady, producers can expect a record-high hydrocarbon revenue of $195 billion before factoring in hedges, a Rystad Energy analysis shows. The previous record of $191 billion was set in 2019.
The estimate includes hydrocarbon sales from all tight oil horizontal wells in the Permian, Eagle Ford, Bakken, Niobrara and Anadarko regions. The Permian Basin alone is set to generate a pre-hedge $110 billion in hydrocarbon sales from tight oil activity this year, compared to $91 billion in 2019.
However, corporate cash flows from operations may not reach a record before 2022. This is because more than $10 billion worth of revenue is going to be absorbed by significant hedging losses in 2021.
While hydrocarbon sales, cash from operations and EBITDA for tight oil producers are all testing new record highs in the $60 per barrel WTI environment, capital expenditure is not growing exponentially as producers remain committed to maintaining operational discipline.
“From the upstream cash flow perspective, we see reinvestment rates falling to 57% in the Permian and to 46% in other oil regions this year. Corporate reinvestment rates are generally expected to be in the 60-70% range this year due to debt servicing and hedging losses,“ says Artem Abramov, head of shale research at Rystad Energy.
When it comes to the medium-term tight oil production sensitivity, we use a “status quo” scenario where current policies and tax codes for oil producers remain unchanged. Reinvestment rates are assumed to decline gradually over the forecast period of 2021 to 2025 as the industry matures, but the average reinvestment rate clearly depends on oil prices.
Updates from the latest earnings season show that even as oil prices rise, companies still prioritize accelerated balance sheet improvements and higher investor returns over increased capex and production growth spending. This indicates that the reinvestment rate itself will be a function of the oil price in future, with a stronger market resulting in lower reinvestment rates.
Our bottom-up, company-by-company research suggests an average industry-wide reinvestment rate of 50% at $65 WTI, 60% at $55, and 70% at a $45 per barrel in 2021-2025. We have used these assumptions to analyze the supply outlook for US tight oil.
The $45 per barrel WTI environment is viewed as the new maintenance scenario, with a conservative spending profile. The $55-$65 range paves the way for significant output growth in the next five years, with pre-Covid-19 production records being surpassed by late 2022 or 2023. The forecast is not for total US oil volumes, which are also affected by conventional production declines.
The Permian Basin alone can grow comfortably even in a $45 per barrel world, likely plateauing at 1 million bpd above its pre-Covid-19 production peak by the middle of the current decade. If we assume $55 as a long-term price deck, Permian tight oil volumes are set to deliver a compound annual growth rate (CAGR) of 11-12% in the next five years, or 2.6 million bpd of cumulative oil production growth.
This will be partially offset by a decline of 500,000 bpd in all regions outside of the Permian, which require a price of $60 per barrel to demonstrate some production recovery in the forecast period. A continuous expansion in the Permian is consistent with the guidance shared by public tight oil producers. Many of them forecast stable volumes through 2021 at a portfolio level, which for most diversified producers implies some growth in the Permian offset by declines in more mature or less economic basins.
How taxes, federal carbon price policy can affect output
Impressive efficiency gains have positioned the tight oil industry for substantial output growth in 2021-2025, even at conservative reinvestment rates – as long as WTI futures hold above $45 per barrel. This growth potential assumes a status quo on taxes and other domestic energy policies.
In a $55 environment, the US shale industry is set to generate about $43.8 billion of upstream free cash flow in 2022. With around $9.1 billion of estimated debt that needs to be serviced, the industry would still have a staggering $34.6 billion left at a corporate level.
What happens if some recent initiatives by the Biden administration are implemented immediately? An increase in the federal corporate tax rate from 21% to 28% would remove $4.1 billion from the free cash flow expected in a status quo scenario. Potential removal of deductions for intangible drilling and development costs (IDC) and reservoir depletion tax incentives would together account for a free cash flow reduction of $2.9 billion.
Add to that a hypothetical carbon price of $100 per tonne on upstream companies’ Scope 1 carbon emissions (which has been suggested by many market participants), and the industry would send another $9.4 billion from the free cash flow it would have generated under the status quo scenario to government coffers.
If an increase in the corporate tax rate, removal of incentives and a carbon price of $100 per tonne are all implemented simultaneously, US shale producers’ corporate free cash flow in 2022 could drop to $18.3 billion from $34.6 billion. Such a reduction would imply an increase in the industry’s reinvestment rate from 68% to 81%, if producers choose to stick with a flat capital program and aim to maintain their production growth trajectory.
If we consider an “all-in” new policy scenario – a federal income tax rate of 28%, the removal of IDC and reservoir depletion incentives, and a carbon tax of $100 per tonne on Scope 1 emissions – the US tight oil industry’s supply outlook in a $45-$65 WTI environment will be markedly different if producers stick with the reinvestment rate target from the status quo scenarios. In such an environment, a $65 per barrel WTI be required to maintain production, while a $45-$55 price would result in a sustainable decline at a varying pace.
However, such a development wouldn’t necessarily eliminate future US tight oil growth. Tier 1 inventory depth in the Permian and several other regions remains significant and producers are maintaining a low reinvestment rate partially on a voluntary basis. Essentially, the industry will have some room to increase its reinvestment rate compared to the status quo assumptions in each price scenario.
Any regulatory changes will weigh on US tight oil’s market valuations, but we believe that many producers will respond with only a marginal reduction in capex to increased taxes or carbon costs. Then, instead of a 60% reinvestment rate on average in a $55 per barrel WTI world, we might see a reinvestment rate of 70%. With such spending, the nation’s tight oil production will gradually climb to its pre-Covid-19 record by 2025, but will not necessarily surpass it, falling 1.4 million bpd short of the outlook under the status quo scenario in 2025.