Pipeline reversals

Over the next few months, a variety of market players — crude oil producers, midstreamers, refiners, and exporters — will be making preparations for one of the most anticipated infrastructure additions in recent years. Actually, it’s not technically new; it’s the long-planned reversal of the 632-mile, 40-inch-diameter Capline, which for a half-century transported crude north from St. James, LA, to Patoka, IL. Line-filling will begin this fall and Capline will start flowing south from Patoka in January 2022, providing Western Canadian and other producers with new pipeline access to Gulf Coast markets. Upstream of Patoka, the impending reversal has been spurring the development of new pipeline capacity to supply the soon-to-be-southbound Capline, and in Louisiana, refiners and exporters have been making plans for the crude that will be flowing their way into St. James. Today, we discuss the broad impacts of the “new” Patoka-to-St.-James pipeline.

The natural gas market dynamics that were expected to turn gas flow patterns and price relationships in the Eastern U.S. on their heads and, in turn, transform supply-demand dynamics in Louisiana — including around the U.S. price benchmark Henry Hub — have come to fruition. LNG exports have surged as new liquefaction and export terminals have come online, injecting a new demand source along the Louisiana coastline. Producers have lined up to serve that demand. And midstreamers have worked to get the gas there, reversing and expanding existing northbound pipelines to move gas south into and through the Bayou State. Now, Louisiana’s gas market is nearing a critical juncture: the pipelines that connect the supply gateways in northern Louisiana to the demand centers along the Gulf Coast are nearing saturation. Today, we begin a series providing an update on Louisiana’s gas pipeline constraints and the projects lining up to alleviate them.

Well, it’s finally going to happen! Without major fanfare, Plains All American and Marathon Petroleum announced earlier this month that they have sanctioned the reversal of the 40-inch-diameter Capline crude oil pipeline, a move that will enable light crude to flow south on that pipe from the Memphis area to St. James, LA, starting late next year and light and heavy crude to do the same from Patoka, IL, by early 2022. Also, Plains said it has committed to expanding the existing Diamond Pipeline between Cushing, OK, and Memphis, and extending that eastbound crude pipe from Memphis to a new interconnection with Capline. Light-crude service on the expanded, extended Diamond will commence in late 2020. Today, we review the newly sanctioned projects and their significance to U.S. and Canadian producers, Louisiana refiners and Gulf Coast exporters.

Enbridge is taking a serious look at converting its Southern Lights pipeline, which currently transports  diluent northwest from Illinois to Alberta, to a 150-Mb/d crude oil pipe that would flow southeast. The potential reversal of Southern Lights is made possible by the facts that Western Canadian production of natural gasoline and condensate — two leading diluents — has been rising fast, and that demand for piped-in diluent from the Lower 48 is on the wane. Alberta producers could sure use more crude pipeline capacity out of the region — and getting crude down to the U.S. Midwest would give them good access to a variety of markets. With Western Canadian diluent production increasing fast, maybe Kinder Morgan’s Cochin Pipeline, another diluent carrier, could also be flipped to crude service later on. Today, we consider how Southern Lights’ conversion/reversal might help.

Throughout the middle and latter parts of the 2010s, crude oil production growth in major U.S. basins and in Western Canada — not to mention the end to the ban on most U.S. crude exports in December 2015 — has caused noteworthy shifts in crude flow patterns, stressed existing pipeline infrastructure, and highlighted the importance of crude storage and distribution hubs. A common theme through all this has been that more and more crude needs to find its way to the Gulf Coast, with its bounty of refineries and export docks. To that end, lately, there’s been a slew of new pipeline and export-terminal projects announced that are tied to the St. James crude trading hub, which is located in Louisiana, about 60 miles up the Mississippi River from New Orleans. Today, we begin a series on St. James and why it’s becoming an even bigger player in crude markets.

There was a time many moons ago when vast quantities of natural gas from offshore Louisiana production flowed through scores of gas processing plants along the coast, then moved north and east in pipelines destined for the Northeast and Midwest. Those flow patterns have since been turned on their head, with offshore production steadily declining and the need for gas supplies for LNG exports along the coast ramping up, driving gas southward to meet that demand. That southbound gas includes Haynesville production — now back in growth mode — and a deluge of inflows from the Marcellus/Utica on reversed pipelines and new pipes. Supply in northern Louisiana will continue rising, while demand in southern Louisiana will do the same. With Henry Hub at the epicenter of this transformation, the consequences not only for Louisiana but for the entire natural gas market will be far-reaching. Today, we begin a series to examine how Louisiana natural gas flowed historically, the shifts that have already happened, the impact of more changes just ahead, and what it all means for the future of natural gas in Bayou Country.

While the recently enacted federal tax cuts have been widely viewed as a boon to corporate America, including businesses in the energy sector, a new report by our friends at East Daley Capital finds a major drawback in the law for midstream companies. By slashing the corporate tax rate from 35% to 21% — and by allowing partnerships and “pass-through” entities to take a 20% deduction on their income pre-tax — the new law will increase the return on equity that midstreamers earn on their crude oil, NGL and natural gas pipelines. That may well lead the Federal Energy Regulatory Commission (FERC) to re-set its formula rates for at least some gas pipelines, and also is likely to heighten regulatory scrutiny of the rates charged by the owners of oil and NGL pipelines. Today, we continue our review of East Daley’s new “Dirty Little Secrets” report with a look at the tax law, the higher pipeline ROEs resulting from the tax cuts, and the midstream companies that may be affected most.

The recent rise in crude oil prices to levels not seen since late 2014 certainly has captured everyone’s attention, and generally boosted the financial prospects for U.S. producers and midstreamers alike. But while it’s often said that a rising tide lifts all boats, the fact is that accurately assessing the relative value of — and prospects for — specific midstream energy companies requires a deep, detailed analysis. Where are their assets located? How do they complement each other? Do their contractual obligations help or hinder? Sure, things may be looking up in the midstream sector in a big-picture sense, but that hardly makes every midstream company a winner. Today, we review highlights from a new East Daley Capital report that shines a bright light on 28 U.S. midstream companies.

Only a few years ago, pretty much all the natural gas flowing through pipelines in the southeastern U.S. was headed north to serve demand in the Northeast and the Midwest. But that’s all been changing — and fast. Gas production in the Marcellus/Utica has soared and now meets the needs of the Northeast and more. And, as LNG exports from the Gulf Coast ramp up and Southeast gas demand for power generation rises, more and more Marcellus/Utica gas is flowing south, raising the question of whether pipes in the Southeast can handle it all over the long term. Today, we discuss the findings of RBN’s work in preparing a study for the American Petroleum Institute (API) on the adequacy of regional gas pipeline infrastructure.   RBN’s work discussed here is the current analysis being used to inform and develop stakeholder briefings.  We anticipate API will release the final version in report form, after its completion.

The natural gas flow patterns that characterized the U.S. energy-delivery sector for the decades preceding the Shale Revolution are gradually being undone, and few, if any, states are more affected by these changes than Texas. The state remains the nation’s largest natural gas producer, and it still produces nearly twice as much gas as its consumes within its borders. But traditional Northeast and Midwest markets for Texas gas are being ceded to Marcellus/Utica producers, and more and more Northeast gas is flowing south/southwest to the western Gulf Coast, drawn by power/industrial demand, new LNG export terminals and rising pipeline-gas exports to Mexico. Today we begin a look at the dramatic shifts in gas flows out of Texas through key gas pipeline exit points.