Rystad Energy: Shale Newsletter - July 2019 - eng
Tall order for Wolfcamp E&Ps to beat their 2017 after-tax well returns
Future shale wells in the Wolfcamp A zone in the Permian Delaware – the most prospective US liquid basin – seem like a sure bet for investors. As long as WTI oil prices remain above $50 per barrel, these Delaware wells are likely to deliver after-tax internal rates of return (ATAX IRR) of 20% or more – even after salt water disposal (SWD) costs, midstream and overhead components are taken into account. The corporate-level financials don’t tell investors the whole story, which is why Rystad Energy has begun analyzing wells by their “vintage” – an aggregate sum of the wells that were turned-in-line in a single year. If we look at all capex, opex, revenues and other cash flows associated with each vintage and evaluate it as a single big project or company, is it still a profitable investment opportunity?
In a previous commentary, we focused on the profitability of modern shale wells across the Wolfcamp A zone. This time, we are analyzing historical vintages of Wolfcamp A wells from 2014 to 2018. Figure 1 shows a historical three-stream production profile for these vintages from ShaleWellCube, along with the forecast for future periods. The combined output from all five vintages peaked at 1.452 million barrels of oil equivalent per day (boepd) in December 2018 and it is expected to decline to 420,000 boepd by December 2022.
We can select a particular vintage year as an example – 2016 in this case – and we can view all the cash flows associated with this vintage (Figure 2). For simplicity, we assigned drilling and completion (D&C) costs associated with each well in the month when the well was turned-in-line. In reality, most D&C spending is incurred within four to eight months ahead of first oil.
On the chart, the total capex associated with this vintage is represented by yellow bars, which average about $270 million per month and correspond to the 38 completions made per month in 2016, a majority of which were one-mile laterals. “All-in” opex is shown by the brown bars and includes lease operating expenses (LOEs), the midstream component, salt water disposal (included in capex if capitalized) and overheads. The gray bars capture royalties and gross production taxes, while the light green bars are revenues associated with hydrocarbon sales. It should be noted that the relatively flat revenue trend between 2Q17 and 2Q18 was driven by a continuous improvement in oil prices throughout this period rather than the vintage production profile. For future periods we consider a price environment of $55 per barrel of oil, $2 per MMBtu of gas, and $18 per barrel of natural gas liquid (NGL).
So just how profitable was this Delaware Wolfcamp 2016 vintage? If we set aside SWD, midstream and overhead costs, the vintage as a whole was exceptionally profitable with a vintage-level ATAX IRR of 56%. This is largely consistent with major E&P company reporting when it comes to D&C-level project economics. In fact, some exceptional acreage positions exhibit three-digit D&C ATAX IRRs. Once all overhead costs are taken into account, the ATAX IRR goes down to 24%, which still makes the 2016 vintage a very profitable investment.
If we compare the performance of the 2016 vintage to the 2014 and 2015 vintages, the difference in returns is quite dramatic. It appears that the wells from 2014 and 2015 failed to deliver even 10% ATAX IRRs once overhead costs are taken into account.
While structural industry improvements over time explain a significant part of the gains in profitability, it is also evident that the evolution of the oil price had a paramount impact on the performance of different vintages. The decisions for the 2016 vintage were made in a much lower oil price environment compared to the actual oil prices in 2017 and 2018, the years when the most significant cash flows for the 2016 vintage were realized.
The 2017 vintage was arguably the best in the history of the Delaware Wolfcamp A play, and it also got a boost by higher oil prices in 2018. In turn, the vintage from 2018 faced both modest service cost inflation and a decline in oil prices throughout 4Q18, which resulted in degradation of ATAX IRRs. Yet they remained at a level of 20% and above, with overhead costs included.
We took a closer look at this sensitivity relationship, as seen in Figure 4, and show the after-tax IRR changes in various oil and gas price scenarios. The price for NGL is kept constant at a 1:3 ratio to the oil price.
While the vintages from 2014 and 2015 have already recovered a major part of their lifetime present value and cash flows, this is not yet the case for more recent vintages. Our analysis shows that the ATAX IRR for the 2018 vintage has a higher sensitivity to oil and gas prices, especially since the wells drilled in 2018 have been producing for less than 12 months. If the oil price collapses to $35 per barrel, the vintage will not deliver even 10% ATAX IRR in the considered gas price range.
On the flip side, if the oil price jumps to between $65 and $75 per barrel, this will push ATAX IRRs to 30% and higher. Last year’s vintage still has a chance to deliver higher ATAX IRRs than the 2016 vintage. This would require either an oil price of $65 per barrel along with a natural gas price of $3 per MMBtu, or an oil price of $75 per barrel. Yet it would be difficult for the 2018 vintage to outperform the vintage from 2017 as it would require the oil price to hit $80 per barrel.
For the average well in Wolfcamp A Delaware, the natural gas price does not significantly affect ATAX IRRs. Typically, a change in gas price of $1 per MMBtu impacts ATAX IRR by 1.5% to 2% if oil and NGL prices remain unchanged. Yet we remind our clients that some of the gassiest parts of the Delaware basin, such as Culberson County, experience more volatility to gas economics and persistent basin-wide infrastructure challenges.While the economics of recent vintages in the most prospective US liquid basin remain exceptionally robust, we should note that these ATAX IRRs still do not correspond to fully-burdened returns. For a complete picture, we also need to take into account land cost, where the variability between early and late entrants is expected to be significant. We aim to tackle this assumption in a forthcoming analysis.