Ciaran Nolan
Director, Nolan Geoscience Limited

U.S. shale and Light Tight Oil (LTO) may not be your thing, but it's part of the reason why many of us in the oil and gas industry, or energy transition sector, have a bit more time on our hands at present.

This article (Part 1 of 2) provides insights into the second largest and oldest of LTO plays, the Bakken. Recent production data suggests the Bakken is leading the way and going 'where no shale play has gone before', but is it going in the right direction?

In a research note in April 2020 entitled the Great Compression, Deloitte estimated the entire U.S. shale industry registered net negative free cash flows of $300 billion, impaired more than $450 billion of invested capital and saw more than 190 bankruptcies since 2010. Continuing low oil prices have forced producers to adopt a raft of measures to reduce their costs, here are few more recent and noteworthy examples;

• In April 2020 Whiting filed for Chapter 11.
• In May 2020, Continental Resources, which has limited price hedging in place, announced that it had shut in 70% of their production.
• In June 2020, one of the pioneers of the shale revolution Chesapeake Energy filed for Chapter 11 protection.
• In August 2020 Equinor announced that it will stop further shale drilling in 2020.
• In September 2020, Japanese trading house Sumitomo Corp, have called time on US shale, having announced that it is selling it's entire stake in Marcellus shale gas project.
• In September 2020, Oasis decided to enter into a 30-day grace period for paying the delayed interest that was due Sep 15, 2020. The company owed interest on its 6.875% Senior Unsecured Notes due 2022 and 2.625% Senior Unsecured Convertible Notes due 2023.
• In September 2020 Whiting announced it had exited Chapter 11 decimating it's share holders (Whiting's old shares were exchanged for new shares at a 75 to 1 ratio).
• Today, September 28th 2020, Devon to Buy WPX After Permian Investors Push for More M&A.

As Rachel Adams-Herd of Bloomberg mentions in her article of June 2020; 'America’s shale revolution grew out of a well-orchestrated dance. For almost a decade, producers wooed investors by touting rosy estimates of how much crude oil they could profitably drill, and investors forked over money. That ended last year, even before the global pandemic sent oil prices tumbling. Investors, after years of meagre returns, began demanding that shale companies stop marketing mythical future barrels that would never earn a dollar.' Bloomberg recently reported that Mike Lister, a JP Morgan energy banker, estimated that banks wrote off approximately $1 billion in reserve based loans for shale companies in 2019, exceeding their total losses for the past 30 years, and that trend is continuing.

So what actions are shale producers taking and who are best placed to survive? Raw Energy in their articles from January 2020 set out the results of borrowing base reviews, debt maturities and financial and operating metrics for producers. It also outlines the actions companies often take to deal with debt, particularly in restructuring situations (the so called Playbook).

The Playbook comprise at least 16 possible actions; looser terms with existing lenders, sell unsecured debt, create additional first/second/third line debt, sell assets, create joint ventures, reduce capex, reduce Lease Operating Expenditure (LOE), reduce General & Administrative (G&A) costs, sell existing derivatives to raise cash, repurchase debt at a discount, debt for debt exchanges, debt for equity exchanges, sell equity, retain financial/restructuring advisors, merge with another company.

Simon Todd of Capriole Energy in his article entitled 'Caught in a trap' outlined what an ideal company would look like in terms of future cost performance. He also proposes Shale Bank: a business model and plan to optimize recovery from bankrupt US E&P assets.

So, have we reached the end of the debt restructuring process? As Winston Churchill famously said; ' Now this is not the end. It is not even the beginning of the end. But it is, perhaps, the end of the beginning'.

In this article we review the production performance, reserves and net present value of wells that started producing from 2008 onwards in the North Dakota part of the Bakken and Three Fork Light Tight Oil (LTO) play. The study provides lenders and financial institutions with an independent analysis of the second largest U.S. LTO shale play. These insights may help determine possible strategies for producers, investors and lenders. In Part 2 we compare the performance of three major Bakken producers; Whiting Petroleum, Marathon Oil and Hess.

So is there a future for mature shale plays such as the Bakken or has the sun finally set on them? The results from this study demonstrate that that with current production levels oil prices of $63 (WTI) or more are required to generate healthy returns (IRR 15%) in the Bakken and $50 to breakeven. This is an average across the entire play and it assumes a full cost model that includes certain costs typically excluded by producers and some analysts. There is a wide range in oil prices required to generate IRR15% between producers. Producers with the best positions in the 'core' such as Marathon Oil, ConocoPhillips and WPX can generate reasonable returns (IRR15%) at around $50 WTI.

As the oldest of the U.S. shale plays the Bakken is leading the way and going where no shale play has gone before. There are clear indications that the current mean 24 month oil produced, a key economic metric, has started to decline (2018-2020). This is not unexpected and is typical of late stage field performance. The lower rates are a response to tighter well spacing (including parent-child behaviour), lower reservoir pressure (and hence energy) and the onset of the bubble point (as indicated by the significant increase in GOR and water cut). The decline in the average 24 month oil produced is clear, the future rate of decline is uncertain. The ability of producers to withstand the combined effects of declining production and sustained low oil prices is also uncertain.

Therefore historical well spacing and stimulation programmes will no longer be appropriate or optimal to develop the remaining recoverable resources.

So what do you do when you are $300 billion in the red? Keep spending - but spend wisely and efficiently, pray for $63 WTI or more (in the case of the Bakken), adapt your well completion and spacing programme to the new realities and most importantly listen to your geologists and engineers.

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