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Trials and tribulations in the Permian

Efficiency gains have streamlined operations at the world’s most exciting shale patch. But with the threat of a pandemic and ongoing oil price volatility, can production growth be sustained?

The unprecedented growth of US shale over the last decade, particularly in the Permian basin, upended the global oil market with a multitude of independents wresting de facto control from the Opec cartel. This will be severely tested in the coming months as Saudi Arabia and others ramp up production in search of market share. But, either way, the days of breakneck growth at the expense of solid financial fundamentals are long gone. Technology and efficiency gains have allowed producers to dramatically cut costs while achieving record production volumes, which in turn attracted a fresh influx of companies.

Whether shale output growth can be sustained in a world already awash with supply is debatable and the latest boom may well prove to be short-lived. Petroleum Economist sat down with Artem Abramov, head of US shale at energy research consultancy Rystad Energy, to discuss the future of the shale patch.

What factors have allowed production growth to flourish over the past few years?

Abramov: We are in the second stage of shale growth. The first was 2011-14 when the industry was really new. Investors saw it as a very attractive investment opportunity, and some E&Ps were a little bit over optimistic about the returns and their ability to replicate earlier successes.

The oil price collapse in 2014 was a major trigger for the industry and created a learning curve. During 2015-16, the period of very low prices, we saw the most significant structural improvements in well design and completion techniques.

“The business model is changing to one based on more disciplined spending and cashflow generation”

Costs suddenly became the focus. The industry transformed into a much more efficient, low-cost source of supply, which triggered fresh activity and attracted new investors. The massive productivity gains and increasing activity during the 2017-18 boom meant production roughly doubled between 2016-19.

The business model of the shale industry is changing. Investors prefer profitability and more disciplined spending programmes. It does not mean the shale industry is not profitable—many people wrongly reach this conclusion. It is a very attractive investment opportunity, at least among greenfield projects globally, and offers some of the best returns. The business model is changing to one based on more disciplined spending and cashflow generation, away from aggressive growth and significant overspend.  

To what extent will Covid-19 and the Opec+ fallout impact US shale?

Abramov: The most important driver in the US is price—this is what producers look at when setting their budgets. A WTI price of $30/bl still allows for some commercial drilling in US light tight oil basins. But it would not work for the majority of operators, which do not have core acreage and cannot further high-grade their activity.

Most drilled but uncompleted wells (Ducs) are still profitable, but the industry will rush to adjust activity down to achieve adequate cashflow. Producers such as Diamondback and Parsley made instant announcements. The difference between now and 2015-16 is the lack of additional capital available.

There will be a lag to the industry’s reaction, due to service commitments and cashflow support from hedges. We expect modest production growth in the second quarter but this might be eliminated by declines starting from the fourth quarter.

“Given there is so much cheap gas, there is a ceiling on how high gas prices could rise”

We expect a decline of 1.9-2.6mn bl/d between the fourth quarter of this year and the fourth quarter of 2021 if $30/bl WTI persists. Most of this will come in 2021, depending on the willingness of investors to accept an increase in spending. The price needs to go back to $40/bl to stabilise US oil in the medium term, and above $40/bl for growth.

Bankruptcies started to rise again last year. Do you think this trend will continue?

Abramov: This is a positive trend for the industry—the least-efficient companies are being eliminated. The time has probably come for the industry to become more efficient in this area. We might see a few more cases this year—but last year was probably the peak of this new wave of bankruptcies. But there are still financially distressed companies. I would expect to see more of this on the oilfield services side this year, as opposed to E&P. 

Many operators say they have reached an inflection point for productivity, which is no longer improving much in most basins. But there are still many efficiency gains that can be realised around drilling completion.

Are smaller independents making efficiency improvements?

Abramov: There is always a significant share of small private producers in US onshore oil and gas. Some of these are not as interested in optimising frack designs and development patterns as the public players. If small producers achieve certain returns, they will stick to what they know. But the largest players, such as public shale producers, are very focused on achieving excellent returns.

Does this focus extend to water management and frack sand?

Abramov: Water infrastructure became significantly bottlenecked in the Permian in 2016-18 because a lot of the new activity was in areas remote from the legacy disposal infrastructure. A lot had to be created, and this took quite some time. It is much more difficult to get a permit for a disposal well than for a production well—sometimes up to a year.

These bottlenecks were delaying activity. Specialised private equity companies came in and consolidated wastewater disposal and the water supply in general. This brought down costs for producers and resulted in a much more profitable business for water companies.

“Associated gas is a major challenge in the Permian and is on the agenda of all E&P management teams”

Frack sand costs also went down quite dramatically. This is a unique segment with very low barriers to entry. In the last two to three years we got much cheaper but lower quality frack sand, primarily in the West Texas Permian. There is a big oversupply as proppant suppliers added too much capacity and prices collapsed last year.

Many of them operate with negative margins—their business model is to wait for their peers to go bankrupt first—but it will become more balanced. It is a very cyclical market, so it is very easy to add capacity if there is an uptick.      

Do you see gas take-away limitations continuing?

Abramov: Associated gas is a major challenge in the Permian and is on the agenda of all E&P management teams. E&Ps are under more pressure from investors around environmental, social and corporate governance (ESG) topics including gas flaring—in the Permian it is a significant component of the discussion. Nearly all take-away gas pipelines in the Permian are 100pc utilised. They are running at design capacity, not nameplate capacity, which is not recommended for long periods.

The most severe issue was in the middle of last year—local prices at the bottom were negative $9/mn Btu. We are approaching a similar situation because the Permian Highway, which was due online this year, was held back by delays to regulatory approvals. It will not come online until 2021 and is the closest of the planned takeaway pipelines to coming online.

15 minutes The time it took for the Gulf Coast Express pipeline to reach full utilisation

There is some unutilised pipeline capacity to Mexico, but that needs end-user demand. These pipelines were built in 2017, but the connectors on the Mexican side were not finalised on time. The connectors have since been finalised but there is no demand because the power plant projects that were to use Permian gas as feedstock were cancelled.

The only large pipeline to go online in the Permian last year was the Gulf Coast Express pipeline—and that reached full utilisation in 15 minutes.

Are limitations on flaring restricting production?

Abramov: In Texas you can flare during the first 10 days after well completion without permits, but you need a permit to extend this to 45 days. The permit can be renewed for a maximum of six months, but in reality they can be renewed even longer if there are economic reasons. This is the biggest difference between Texas and some other states—valid reasons for flaring include a pipeline simply not being economic.

Large producers get ‘firm’ transportation [deals]. They work with gas plant owners and large pipeline owners to secure capacity for their gas. But that is something only large producers can do. The pipeline owners will not even talk to small producers as they are not able to commit to a certain volume for a prolonged period of time.

Large producers typically have a very low flaring intensity compared to small ones. The largest companies flare the largest volumes of gas—but as a percentage of their production it is typically much smaller.

How much potential is there for supplying LNG exports?

Abramov: A lot of LNG capacity has been added on the Gulf Coast in the last few years and new projects are coming online. A lot of these use Permian gas as a feedstock. The Gulf Coast Express goes straight to export. But we do not always know because the pipeline infrastructure is so complicated.

With almost all gas production growth coming from the Permian, the Haynesville in Louisiana and Appalachia, the goal of producers is to reach the Gulf Coast as this is where there is additional demand.

But there is a big problem when Henry Hub prices are below $2/mn Btu in the middle of seasonal peak demand. We are back to the same low prices of 1998. There are no commodities with such a low nominal price.

Maximum sensitivity scenario for US lower 48 oil production, excluding the Gulf of Mexico. Source: Rystad Energy

The winter was mild, and on top of that there was a mismatch between expectations and what happened. Typically, many US producers backlog production growth, so they increase production in November and December and dissipate it with demand. They did the same this year, but demand reacted very marginally so we did not see any means for uptick. We are in an extremely oversupplied market.

Would you expect that to continue?    

Abramov: Gas-focused producers in the Appalachian basin are coming out with much more conservative capital budgets than the plans they made in the fourth quarter. We will see little to no production growth in the Marcellus, Utica and Haynesville. All gas production growth this year will be in the Permian, but this gas cannot reach the market because of delays with pipeline capacity. The longer the gas environment remains depressed, the higher the chance it will trigger another [price] upcycle. That said, the situation might improve significantly in the second half of the year.

When the planned pipelines eventually reach start-up, will there be enough global demand?

Abramov: From a medium to long-term perspective, it is very clear that there is too much cheap gas in the US. Initially, when the fracking industry started [production] was expensive—then they were able to bring the costs down. This resulted in domestic oversupply in 2009-10 and gas prices collapsed. Then, for the last decade, they have been saying the solution is to sell the gas globally.

Global benchmarks are converging with Henry Hub. They are at record lows and this is probably the new reality. The US is the most market-driven economy in the world and oil and gas is pretty much unregulated. Given there is so much cheap gas, there is a ceiling on how high gas prices could rise.

 

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