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Permian pipelines bring relief—and challenges

Two major new crude pipelines out of the Permian Basin entered service this month, but while this provides some relief to producers, it shifts the congestion to the Gulf Coast

Permian Basin producers should see some relief from the takeaway capacity crunch that has helped constrain crude output growth in the region since last year. From the beginning of August, two out of three major oil pipeline projects scheduled for start-up in the second half of 2019 have entered service.

However, while this additional capacity is expected to help boost Permian production, it also creates new challenges for the region's energy industry. It effectively shifts the congestion out of the basin and onto the US Gulf Coast.

Within a week of midstream firm Plains All American Pipeline bringing the Cactus II project online, its peer Epic Midstream confirmed that it had started a temporary crude transport service on its natural gas liquids (NGLs) pipeline. The EPIC Y-Grade project will be re-converted to NGL service when the company's permanent crude pipeline comes online in early 2020. Epic's decision to invest in converting the pipeline to crude for a relatively short window illustrates the urgency with which pipeline operators are acting in to try to provide new Permian takeaway capacity.

New capacity

Cactus II has a total capacity of 670,000bl/d, and Plains expects the pipeline to be fully operational by the first quarter of 2020. Epic will ship up to 400,000bl/d on the Y-Grade pipeline, while the permanent crude pipeline will have an initial capacity of 600,000bl/d.

Later this year, US refiner Phillips 66's Gray Oak pipeline will add 900,000bl/d of capacity from the Permian to the Gulf Coast, while midstreamer Energy Transfer's Permian Express 4 expansion will contribute a further 120,000bl/d. Additional pipeline projects have been proposed for the coming years as well.

"There is a big risk in the basin right now that there could be a massive overbuild," says John Zanner, an analyst at fundamentals analysis firm RBN Energy. Under a scenario where crude prices remain at around $55/bl until 2024, he says, it would be tough to argue the case for both the planned Wink-to-Webster and Midland-to-ECHO 3 pipelines to be built. "I think it is probably more likely that Wink-to-Webster or Midland-to-ECHO 3 falls off the line and never gets built out," says Zanner.

It is not only planned pipelines that face headwinds—challenges are now becoming more apparent for those that have just started up or will arrive imminently. By the beginning of 2020, there will be almost 2.8mn bl/d of new pipeline capacity from the Permian to the Gulf Coast, according to energy analytics firm RS Energy Group (RSEG). But, by the end of next year, the company projects Permian production growing only by an additional 1.7mn bl/d—not sufficient to fill all of the new capacity. Midstream operators may have to compete to lock-in capacity bookings on their new pipelines.

"With so much incremental additional capacity, shipping optionality has returned to producers. In order to maintain volumes, we could see long-haul pipelines undergoing rate changes," says Stephanie Kainz, a senior associate at RSEG.

This is already evident, with Epic halving the spot rate on its new pipeline to $2.50/bl before the project was placed into service. Plains, meanwhile, set the term contract rates for Cactus II at between $1.05/bl and $3.20/bl—lower levels than had been anticipated by traders. The company set its spot rates at $4.75-5.60/bl, although the majority of capacity is under long-term contract. "You are going to start to see a massive compression in tariff rates," says Zanner.

Steel surcharge

At the same time as bringing down the contract rates for Cactus II, however, Plains has proposed imposing a $0.05/bl surcharge for shipments on the pipeline from next April. The move is an attempt to offset the impact of higher construction costs due to US tariffs on imported steel imposed in 2018. Plains says the tariffs have resulted in an additional $40mn of construction costs.

The US Department of Commerce has denied two requests by the company for a waiver on tariffs for its imported steel, although a third application has been lodged. In the meantime, Plains is trying to very explicitly pass the costs on to shippers through an advertised surcharge, rather than quietly building it into its contract rates. It is the first pipeline operator to attempt such a move in response to the 25pc steel import tariffs.

"I think it is a publicity stunt," says Sandy Fielden, director of oil research at financial services firm Morningstar. "By publishing it and making it part of their fee they are making their point that they do not like the idea of there being a steel tariff."

The move has led to a backlash from some producers, with Canada's Encana and US independent ConocoPhillips requesting that the US Federal Energy Regulatory Commission (Ferc) reject the proposed surcharge.

"We feel the tariff filing should be denied because it is procedurally incorrect, does not clearly describe or justify the surcharge and is premature considering the outstanding tariff waiver at the Department of Commerce," says ConocoPhillips.

While the surcharge will be relatively insignificant given that rates are going down overall, shippers will be keen to avoid a precedent being set for similar levies that other pipeline operators could also seek to apply.

"Producers need to ship their crude and $0.05/bl is a relatively nominal charge. But, in the current climate, it may represent a meaningful piece of their full-cycle margins. If they have an option to move volumes to other pipes without this cost we would expect them to do so," says RSEG's Kainz.

The surcharge is "inconsequential" in the grand scheme of things, says RBN's Zanner, who sees the overall contraction of pipeline tariff rates as the bigger story. A lot of operators "are going to have to ship at a loss just to maintain volume on their pipe", he predicts.

Gulf Coast congestion

Even if pipeline operators are able to find users for the majority of their capacity, questions remain over what will happen to the oil when it reaches the Gulf Coast. The congestion is especially challenging for the Corpus Christi area, where the industry is also scrambling to build new export infrastructure.

"If you are shipping to Corpus, there is nowhere else for oil to go except the export market," says Fielden, noting that there are more options available to crude arriving in the Houston area. Provided global demand—particularly in Asia—keeps growing, this should not pose too much of a problem in the longer term as more export infrastructure arrives. In the shorter term, however, Gulf Coast export capacity constraints will increasingly come into play as shippers figure out where to send their Permian crude.

"Nobody really knows how long these terminals are going to take to get permitted, how long they are going to take to get built, what they will cost and how many of them are actually going to make it through this process," says Fielden. "It is almost inevitably going to take longer than expected."

Despite these challenges, Permian output is still anticipated to grow, with producers committed to capacity on the new pipelines. The trend is likely to be boosted by the large volume of drilled but uncompleted (Duc) wells in the basin.

"I think we will see a rash of completions and we will see Permian production crank up in the last quarter of 2019," says Fielden. "The question is, what happens to it when it gets to the coast, and what is the overall impact on the price of WTI?"

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