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US midstream boom gathers pace

Short-term expansion is baked in, but the new decade could pose challenges

The US midstream sector is on a building spree, connecting rapidly growing oil, gas, and natural gas liquids (NGL) production to demand and export centres. Companies and analysts expect liquids and gas output in the prolific Permian, Bakken, and Marcellus/Utica shale regions to amply justify infrastructure already under construction. But they caution that the sector's growth beyond 2021 faces challenges as projects compete for financing and new volumes, and the US refining sector further adjusts to the country's light tight oil (LTO) and gas bonanza.

Official projections for US oil output are consistently bullish. The Annual Energy Outlook 2019 from the government Energy Information Administration (EIA), published in January, reports in its reference case that total US crude production, including lease condensates, reached almost 10.75mn bl/d in 2018, and forecasts that it will peak at over 14.5mn bl/d in 2027, before gently declining through to 2050, the end of its forecast period. The EIA expects the US to become a net oil exporter in 2020 and to remain so through to 2049, with net exports peaking at nearly 3.5mn bl/d in 2037.

During the forecast period, NGLs are expected to provide a major boost to liquids output, particularly from the Permian Basin and the Marcellus/Utica shale plays. Gas production is expected to rise throughout the EIA's forecast period, with exports via LNG terminals and pipelines to Mexico and Canada stabilising at over 5tn ft³/yr, or about 140bn m³/yr, from 2030.

Such forecasts suggest a long and positive outlook for the US midstream, which will be called on to transport increasing production to processing and export outlets. But some analysts are not sure the short-cycle, industrial-style production that has evolved with the shale revolution will provide the stability to underpin steady, long-term infrastructure growth.

"The shale story is still very young," says an oil industry consultant, adding that the industry's sector's dynamics are different from anything seen before. "The Permian Basin is the crown jewel of the US lower 48 growth story, [but] how big can the Permian get, and how long will it sustain that level?"

Uncertain times

Others agree that the midstream's outlook may be less sure than production forecasts suggest. In its "Midstream 2018 Recap and 2019 Year Ahead" report published in January, Texas-based financial services firm US Capital Advisors (USCA) says the midstream sector is living through a "time of tremendous uncertainty", but adds that "what we do know is that: 1) US production will continue to grow in 2019, even at $45/bl oil; 2) crude oil prices at $45/bl are not sustainable and that the market will rebalance; and 3) midstream provides an invaluable service that is not going away".

Through to 2020, a plethora of projects are underway to relieve pressure on production looking for a market, particularly from the Permian Basin. These include midstream heavyweight Enterprise Products Partners' conversion of an NGL pipeline to Permian crude oil transport, which is expected to come into service in mid-2019, as well as upgrades to some of its other pipelines. Other links expected to come into service in the second half of this year are a pipeline being built by Epic Midstream that will in the long-term carry NGLs but will initially carry crude until a parallel crude line is built, and which is expected to add 590,000bl/d of crude capacity, and Plains All American Pipeline's Cactus II system, due to add 670,000bl/d when it reaches full capacity by spring 2020.

The increase in evacuation capabilities is expected to narrow current wide pricing differentials between Permian Basin and international benchmark crudes and contribute to more consistent LTO quality.

Refinery adjustments

Many new lines are aimed at serving the US refinery system, which is adapting to the glut of US LTO, much of which is over 45° API gravity, after decades of optimising operations on a largely imported 31-32° API crude slate. In January, ExxonMobil formally announced it will nearly double the size of its 365,000bl/d Beaumont refinery in Texas with new processing units tailored to handling Permian Basin crude. Chevron has also announced that it will acquire from Brazil's Petrobras a 112,000bl/d refinery in Pasadena, Texas, which is expected to be modified for Permian LTO throughput.

US LTO's high gasoline yield more closely tracks the US demand barrel, which is nearly 50pc gasoline. "The scene for lots of the US refineries is changing", with several pipelines now being built or modified to ensure refiner access to US-produced crudes, says research analyst David Amoss at Houston equity research firm Heikkinen Energy Advisors.

In another example of improving North American producer-to-refinery logistics, Amoss highlights that shareholders of the underused Capline system-which include Plains, US independent Marathon and BP-are considering reversing Capline flows to improve Canadian and North Dakota oils' access to refineries and export markets. Oil industry officials say that refiners have previously encouraged similar actions, for example adjusting plants to increase condensate intake in 2014-2017, so putting an end to a short-lived condensate export boom.

New export facilities

While condensate exports have faded, US companies are addressing the opportunities provided by the current ramping up of crude oil exports. At least five offshore export terminals are in development on the US Gulf coast, prompting one oil consultant to comment that "the overwhelming theme of this whole strategy is going to be an export-driven story". Export terminal sponsors include Enterprise, fellow US midstreamers Magellan Midstream Partners and Jupiter MLP, and trading house Trafigura. Terminals sites include offshore Texas City, Corpus Christi and Brownsville. Because of permitting times, it is unlikely that any of the terminals will be operational before 2021.

But analysts wonder how many of the terminals, which are designed to ease loading of very large crude carriers (VLCCs) capable of transporting 2mn bl or more of crude, will eventually reach fruition. "The industry tends to move together, like a herd of sheep,", says an oil consultant. While the terminals' locations, typically 25-80 miles (40-129km) offshore, will make operations occasionally subject to the Gulf of Mexico's hurricane-prone weather, sponsors argue that they will still be more economic than lightering cargos from smaller vessels onto VLCCs.

The current surge of midstream activity also encompasses chemicals, refined products, gas and NGL logistics, but, ironically, arrives as the sector is facing perception and financial challenges that may make raising the necessary capital harder than might previously have been expected. A key element has been a perceived tie, arising out of the 2015 price downturn, between the earnings of midstream companies, which had in the past been assumed to be reliably steady, and the boom-and-bust cycle of the exploration and production (E&P) sector. Analysts say cuts in unit holder distributions since the price collapse have spooked investors, who now psychologically link midstream with upstream companies and shy away from both.

"To work, the [midstream] group has to have visibility to oil at over $50/bl and a view on producer activity,", says the USCA report. While US benchmark WTI oil prices have recovered since hitting a low of just under $50/bl in December, analysts are not sure the market recovery since is sustainable. And, while throughput through installations under construction is assured, new projects are subject to increased volume risk. "You do not see the midstream solutions materialise until the producers feel the pain" of not being able to evacuate their volumes, says one consultant.

Difficult capital markets

In addition, retail investor interest in the master limited partnership (MLP) structure of many midstream companies-which enabled them to pass earnings onto investors free of corporate tax and, while there is a mismatch between limited and general partners, to the benefit of the latter, in earnings take, the overall incentive should be to increase distributions-has greatly reduced. Repeated cuts in earnings distributions to LP investors since 2015 by a large proportion of the companies making up the benchmark Alerian MLP infrastructure index discouraged retail interest.

Institutional investors have not so far been persuaded to take up the slack. "Capital markets have been very difficult,", says Becca Followill, senior managing director at USCA, which notes that 2018 saw "less capital raised via ETFs, ETNs and open-ended mutual funds than in any previous year this decade", adding that, since June 2018, cumulative capital flows to MLPs have been negative by $1.25bn.

To improve their appeal, many MLPs have revised partnership structures, reducing or eliminating incentive distribution rights (IDRs) which, in many cases, had granted general partners increased earnings at the expense of the limited partners. They are also financing a rising share of their investments via self-generated cash flows and reducing debt-to-Ebitda ratios. USCA would like to see an industry ratio of net debt to Ebitda of 4, compared with about 4.3 at the end of 2018. Amoss says these moves are limiting the ability to return cash to shareholders this year.

Some MLPs are reportedly contemplating converting to more conventional status as joint-stock corporations. Because investments in MLPs were often seen as a tax-efficiency exercise, analysts say that certain provisions of president Trump's tax-cutting 2017 Jobs and Tax Act might accelerate these switches. But other actors lack confidence in the longevity of that legislation and may wait before taking the plunge into more conventional structures.

Export constraints

Any gyrations in corporate structure could add further distractions to the core challenge of raising capital beyond 2020, despite the forecast rise in US hydrocarbons output. In addition to the Permian, other production basins, such as the Bakken and Marcellus/Utica, remain export constrained, leading to more expensive rail shipments and wasteful gas flaring.

Midstreamers Phillips 66 and Bridger Pipeline have announced plans to build a 350,000bl/d pipeline by the end of 2020 to help alleviate exports constraints on Bakken crude.

Meanwhile, the Marcellus/Utica basin recently benefitted from the partial opening of the Mariner East 2 line, sponsored by New York-listed Energy Transfer Partners, which allows additional transport of NGLs to the large US Atlantic Coast export terminal at Marcus Hook, Pennsylvania.

US midstream heavyweight Kinder Morgan, among others, has recently completed additional NGL lines to chemical demand centres, and new petrochemical plants in the US southwest region will ease the pressure to export. Enterprise has indicated that 49pc of its capital spending through to the end of 2020 will be on new NGL transport capacity.

Rising US gas production will be met by additional infrastructure to carry gas to the several LNG liquefaction plants entering operation. US independent Cheniere's two terminals at Sabine Pass and Corpus Christi are now operational, and utility Dominion Resources' Cove Point LNG facility is also exporting. Kinder Morgan's Elba Island terminal, despite recent imports during a US East Coast cold snap, is readying itself to also be able to export, while a slew of other terminals is being developed.

Industry officials say these facilities, as well as additional gas pipeline exports, can be expected to take the pressure off producing basins where gas flaring is beginning to encounter resistance from state authorities and environmentalists, and where regional gas hub prices have plunged for lack of evacuation infrastructure.

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