US shale operators prepped to spend more to produce more
 

 August 2018

US shale operators prepped to spend more to produce more

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Identifying top performing E&Ps in the Permian Basin

Speaker:

Veronika Akulinitseva, Senior Analyst
 
 
Article: Diamondback eyes synergies in the Permian Basin with Energen acquisition

Article: Eagle Ford Shale: horizontal completion activity by distance to the closest well and year


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Second quarter 2018 results recently released by US E&P operators signaled higher expected capital investments and oil production growth from US shale than guided in early 2018. While selected operators increased yearly capital budgets by around 8% on average during 2Q, oil production volumes were revised upward by only 1.4%. This disconnect might suggest that the shale industry requires more capital than before to achieve healthy production growth.

In fact, while a part of increased spending is due to service cost inflation, a significant part of the incremental budget is also planned to be used for additional drilling throughout 2H 2018 to support more intensive completion activity and production growth in 2019. Despite serious bottlenecks and widening Midland-Cushing differentials, the Permian Basin continues to stand out as the key area realizing upward oil production revisions and attracting more capital.

During 2Q 2018, capital expenditure guidance for selected shale producers in the US increased by $3.7 billion or 8% relative to the initial guidance provided in early 2018. According to our analysis of 33 US onshore operators, a number of producers reported plans to increase spending during the year.

Figure 1 compares the original capital budget for 2018 with the new revised target, split by type of company and the key operators driving the increase. The largest contribution comes from pure-Permian and Permian-focused companies, which have at least 50% of the total production from the Permian Basin. Cumulatively, these companies added about $2.5 billion to their capex targets for the full year 2018.

Among notable revisions, Occidental Petroleum increased capital guidance in the Permian by $900 million. Following a strategy to invest excess cash in high-return projects, the operator is planning to add two rigs in the play and pre-build facilities for 2019 activity, supporting higher production in the short to medium term. The company expects market cost inflation to be offset by operational and logistical efficiency gains.

Furthermore, Pioneer increased Permian spending by more than $400 million, attributing this to four extra rigs in the play to support the 2019 plan, a higher number of completions, and the effects of cost inflation. The operator intends to fund the program fully from operating cash flow and proceeds from the divestiture program.

Among Permian-focused producers, Apache and WPX stood out as the companies that had the highest capex revisions during the period, adding $400 and $250 million, respectively. Apache commented that its drilling and completion operations in the Permian were very efficient and incremental capital was necessary to optimize D&C activity and fund investments into longer laterals, larger completions and facility expansions. WPX specified that the updated capex forecast is driven by additional investments for non-operated wells, facilities and infrastructure in the Delaware Basin, along with more intensive completions in Williston Basin, where the company had about a 30% increase in oil volumes during 2Q 2018.

Companies active in multiple shale plays reported plans to increase investments by a total of $1.24 billion. Anadarko added $450 million across the DJ and Permian Basins, attributed to higher non-operating activity, longer-lateral developments and cost inflation. Outside the Permian Basin, Continental Resources is increasing its capital budget by $400 million, directed to additional drilling and completion activity in the high rate of return Bakken and Oklahoma shale plays.

While the US onshore landscape has seen a rather significant revision in capital budgets over the quarter, there was only about a 1.4% increase in oil production guiding among the same selection of companies. In total, almost 65% of the players included into the sample increased oil production guidance to some extent during the 2Q 2018 earnings release, while only 12% decreased their oil production target for the year.

Figure 2 depicts the original oil production guidance and the revised outlook, with the resulting growth split by company type. In such a way, we see that it is mostly pure-Permian and Permian-focused players that increased full year output targets during the quarter. Pure-Permian producers increased guiding by 2% and Permian-focused by 4%. On a cumulative basis, companies active across multiple shale plays increased production by just around 0.5%.

Figure 3 provides a more detailed insight into operator-level revisions reported during the quarter. Overall, Permian companies increased oil production targets the most. Producers like Jagged Peak Energy, Matador Resources and QEP Resources forecasted the highest increases, ranging between 8-12% relative to their original guidance. All of them reported greater than planned performance of wells, underpinned by continued increase in drilling and completion efficiency.

On the other hand, we have also seen downward revisions in oil production targets. Resolute Energy decreased oil production guidance by about 5% due to less than expected oil content realized so far this year. Noble Energy guided 3% less oil volumes, deferring completion activity in the Delaware Basin due to industry constraints. The company has also reallocated near-term investments to other US onshore basins. None of the well-established Permian operators reported a planned decrease in completion activity in the basin this year. EP Energy is expected to temporarily shut-in recently completed wells in Eagle Ford, which would lower near-term production.

Comparing capital budget revisions to oil production increase forecasted for 2018, one might conclude that a large part of investments is in fact attributed to higher service cost inflation rather than an acceleration of drilling and completion activity planned for the year. While higher cost inflation played a role in the uptick in investment budgets, as evident from 2Q earnings reports, the majority of incremental capital expenditure is still planned to be directed to a larger number of intensive long-lateral completions and facility build-outs.

However, as multiple producers stated, many of these wells are expected to contribute to production during 2019, supporting ambitious growth plans going forward. Given current takeaway constraints in the Permian and resulting widening differentials between WTI Midland and Cushing – issues that are expected to be alleviated in mid-2019 – it seems reasonable for US operators to invest incremental cash flow now, reaping the benefits once the price is at a more favorable level.

During 2Q 2018, Permian companies faced larger differentials compared to the last quarter and expected even lower realized prices for the remainder of the year. For the majority of pure-Permian and Permian-focused companies, the differentials averaged around $6 per bbl, while they trended at around $2 per bbl last quarter.

Figure 4 presents 1Q and 2Q WTI differentials for a selection of US shale operators. EOG Resources and Anadarko remain among the players that exhibit the highest realized oil prices. Both companies have well-diversified pricing strategies. EOG, performing the best among peers, reported that only 20% of its Permian production was Midland priced.

At the same time, Anadarko had about 50% of Delaware volumes priced at the Gulf Coast and is planning to increase the share to 100% once the Cactus II pipeline comes online. Among pure-Permian players, Parsley Energy stands out with the lowest differential of $3.5 per barrel. The company implemented a proactive marketing strategy that sought to diversify regional pricing exposure just a year ago. WPX Energy similarly boasted exceptional oil price results, commenting that lower differentials were an outcome of proactive marketing strategy with only 5% of Permian production exposed to Midland pricing.

On the other hand, Cimarex Energy mentioned that the company’s differential in the Permian alone reached $8 per bbl. With 70-80% of oil production on pipe and sales agreements in place, the company’s production in the Permian is mostly Midland priced.

Most other companies active in the Permian showed comparable realized price results and apart from seeking and establishing firm transportation and term sales agreements with favorable pricing options, relied on oil basis hedges to mitigate exposure to widening price differentials. Several companies were also exploring alternative options for crude oil disposition. In such a way, Lilis Energy specified that until a firm crude takeaway agreement is in place in mid-2019, it would continue to transport and sell its crude oil via trucks. Similarly, Matador Resources mentioned dependability on trucks during 2018 until crude takeaway capacity is expanded next year. Matador also ensured investors that despite ongoing concerns they had not experienced any pipeline-related interruptions to hydrocarbon production.