The competition to develop the one or possibly two new offshore crude oil export terminals that the U.S. will likely need by the mid-2020s has been under way for more than a year now, and the field of contestants continues to expand. Within the past few weeks, both Phillips 66 and Sentinel Midstream filed applications with the U.S. Maritime Administration (MARAD) — Phillips 66’s project would be located off the coast of Corpus Christi and Sentinel’s in the waters off Freeport. And who knows, maybe another deepwater project or two capable of fully loading Very Large Crude Carriers (VLCCs) might still be in the offing. Today, we update our series on prospective offshore crude export terminals with a look at the P66 and Sentinel project details revealed by their applications to MARAD.
Daily Energy Blog
The margin for producing ethylene by steam-cracking ethane has been less than a dime per pound since mid-March 2018, and less than a nickel for nearly nine of the past 15-and-a-half months. In fact, for two weeks last September, the ethylene-from-ethane margin fell below zero. And yet, a joint venture of two of the world’s savviest companies — energy giant ExxonMobil and petchem behemoth Saudi Basic Industries Corp., or SABIC — recently committed to building what will be the world’s largest ethane steam cracker: a 4-billion-pounds/year facility to be constructed near Corpus Christi by 2022. Is this a case of blind optimism? No, not when you factor in the cracker’s location, the JV’s concurrent plan to construct two polyethylene plants and a monoethylene glycol plant right next door, and the co-developers’ global market reach. Today, we discuss the thinking behind ExxonMobil and SABIC’s big investment in Texas’s San Patricio County.
Just two years ago, severe transportation constraints and steep price discounts were part and parcel of the Northeast natural gas market. Midstreamers were racing to add much-needed pipeline capacity out of the region, but not fast enough for producers. It was an inevitability that any pipeline expansions would instantaneously fill up. Gas production records were an almost monthly or weekly occurrence, and just as unrelenting were the takeaway constraints and pressure on the region’s supply prices. Not so today. Northeast gas production in June posted a record high, with the monthly average exceeding 31 Bcf/d for the first time. Yet, June spot prices at Dominion South, Appalachia’s representative supply hub, were the strongest they’ve been in six years relative to national benchmark Henry Hub. Why? The spate of pipeline expansions and additions in the past two years have not only caught up to production but capacity now far outpaces it, and consequently, producers now have something they haven’t had in a long time — optionality. Today, we break down how much spare capacity is available and its effect on regional pricing.
For a few years now, Buckeye Partners’ plan to revise the current east-to-west refined products flow on its Laurel Pipeline across Pennsylvania has pitted Midwest refiners against their Philadelphia-area brethren — and gasoline and diesel marketers in western Pennsylvania. Each side has good arguments. Midwest refiners note that westbound volumes on Laurel have been declining through the 2010s, and assert that making the western part of the pipeline bidirectional would result in higher utilization of the line and enhance competition in central Pennsylvania, Maryland and eastern West Virginia. Pittsburgh-area marketers counter with the view that allowing refined products to flow east on a portion of Laurel would hurt competition in Pirates/Steelers/Penguins Country, while Philly refiners — their ranks now thinned by the planned closure of the fire-damaged Philadelphia Energy Solutions (PES) facility — say Buckeye’s plan would further threaten their economic viability. Amid all this, might there be a “perfect-world” solution? Today, we provide an update on this still-in-limbo project and discuss a few possible paths forward.
Independent refiner PBF Energy on June 11 announced its plan to acquire Shell Oil’s Martinez, CA, refinery for about $1 billion; the deal is expected to close by the end of 2019. The purchase will give PBF its sixth U.S. refinery and add 157 Mb/d to the company’s existing 865-Mb/d refining portfolio, pushing its total capacity past 1 MMb/d. Post-acquisition, PBF will retain overall fourth place in the U.S.
Philadelphia Energy Solutions (PES) announced last week (on June 26) that it was shutting down its 335-Mb/d refinery in Philadelphia, PA. This announcement came just five days after a major fire destroyed a portion of the refinery, which turned out to be the last straw for the facility that has been struggling financially for many years. Today, we consider the various market impacts that will likely follow the closure of the PES refinery, including its effect on fuel supply, where the closure leaves refinery production capacity in the region and how the refined product supply will need to adjust in response.
Enbridge’s long-running effort to revamp how it allocates space — and charges for service — on its 2.9-MMb/d Mainline crude oil pipeline system is about to enter a new and important phase. On July 15, the Calgary, AB-based midstream giant plans to initiate an open season for shippers interested in locking up long-term capacity on the Mainline, which serves as the primary conduit for heavy and light crude from Western Canada to U.S. crude hubs and refineries. If all goes well, shippers will know by late in the year how much space they will have on the system starting in mid-2021, assuming Enbridge’s plan is approved by regulators. This is a huge change. The Mainline isn’t just the largest crude pipeline system out of Western Canada, it’s also the only major line whose service is currently 100% “uncommitted” — that is, the Mainline has no capacity under long-term contracts with shippers. Today, we discuss the latest on the midstreamer’s Mainline tolling plan.
For more than six months now, the provincial government of energy-rich Alberta has been trying to mitigate the sometimes painful effects of having too little pipeline capacity to move crude oil to market. They’ve mandated production cuts by larger producers, contracted for crude-by-rail (CBR) services — then moved to undo those deals — and pressed the Canadian government to help advance long-delayed pipeline projects. Things appear to have reached a semi-happy medium for now: the price spread between Western Canadian Select (WCS) and West Texas Intermediate (WTI) has narrowed, but remains wide enough to justify sending crude out by train. Still, it’s clear that the big tranches of new pipeline capacity many had hoped would be built or at least under construction by now face more hurdles. How long will Alberta producers need to wait for unfettered pipeline access to the U.S. Midwest and Gulf Coast and to Canada’s West Coast? Today, we provide an update on WCS pricing, Alberta crude-by-rail, and the key pipeline projects that never seem to get finished.
A key to success for midstream companies developing crude oil gathering systems in the Permian is establishing strong, trusting relationships with the producers driving the region’s growth. Hitch your wagon to one or more producers with top-notch rock and aggressive expansion plans, develop gathering systems that meet their needs for flow assurance and destination optionality, and life will be good. Many of the midstreamers whose Permian gathering systems we’ve been discussing in our ongoing series have done just that. Today, we review the existing and planned systems of EnLink Midstream, another company whose growth is founded in large part on the relationships it has developed with major Permian producers.
The Northeast gas market has come a long way since 2013, when it first began net exporting gas supply to the rest of the U.S. The past several years were marked by dozens of pipeline expansions to relieve takeaway constraints and to balance oversupply conditions in the region; as a result, takeaway capacity is finally outpacing production growth. How much spare capacity is there now, and how long will it be before production growth hits the capacity wall again? Today, we continue our series on Northeast gas takeaway capacity vs. production, this time examining the utilization of pipes in the Northeast-to-Gulf Coast corridor.
Permian midstream development activity has been happening at a rapid pace over the past few years, and we’ve featured many of those projects in the RBN blogosphere. One of the most aggressive players has been Salt Creek Midstream, which is in the midst of a big Permian buildout focusing on natural gas, crude oil, natural gas liquids and even produced water. Salt Creek isn’t only developing local midstream infrastructure; it’s also at work on long-haul solutions that will enable Permian producers to access markets along the Texas Gulf Coast — a wellhead-to-water strategy, you might call it. Helping Permian producers meet their needs to take away all three hydrocarbons plus produced water with integrated transport and pricing options is the key to Salt Creek’s effort. Today, we dive into the details of the company’s expansive Permian infrastructure development plan.
Permian gas marketers were likely breathing a sigh of relief earlier this month when news came that the developers behind the Whistler Pipeline had made a final investment decision (FID) to proceed with the new 2.0-Bcf/d link between the Permian and South Texas. The project provides a crucial link in the gas takeaway picture for the Permian and makes it less likely that gas pipeline capacity constraints in the future will result in the negative prices that are plaguing the present-day gas markets in West Texas. Combined with the two other Permian greenfield gas pipelines that have taken FID — Kinder Morgan’s Gulf Coast Express (GCX) and Permian Highway Pipeline (PHP) — there is now ~6 Bcf/d of incremental Permian supply pointed at the Texas Gulf Coast over the next two years. That’s great news for Permian producers, as well as demand centers along the coast, where tremendous growth in LNG exports is under way. Today, we detail the third natural gas pipeline being built from the Permian to the Texas Gulf Coast.
Crude oil exports out of the U.S. are the topic du jour these days. At the heart of the discussion are the who, what, where and when of how the export capacity will be developed. Who is going to build the next crude oil export terminal, what type will it be (offshore or onshore), where are they going to put it (Corpus, Houston, Louisiana — the list goes on), and when will that new capacity be available? Everyone seems to have a different answer, and for good reason. Crude oil export terminals aren’t easy to develop, any way you look at them. Today, we examine the financial and logistical hurdles that export terminals must clear in order to reach a final investment decision, and what those obstacles mean for what kind of terminal gets built, where it gets built, who builds it and how soon.
Most crude oil gathering systems in the Permian — and elsewhere — have a relatively simple aim: to reliably and efficiently deliver crude from the lease to larger pipelines downstream that provide their shippers a high degree of destination optionality — end of story. A select few systems, though, have evolved into key elements of their owners’ larger value chain. With these, crude flows through gathering systems and takeaway pipes to export terminals — maybe even refineries — all held by the same company or its affiliates. By integrating assets from the site of crude production to the refinery or export dock, such owners add value each step of the way. Today, we continue our series with a look at Marathon Petroleum/Andeavor Logistics’ Permian crude gathering system, which started out relatively small and isolated but has evolved into something much bigger and better connected.
This much seems clear: natural gas demand along Texas’s Gulf Coast will be rising sharply, as will gas supply from the Permian and other inland plays to the coast. The catch is that, like clumsy dance partners, the increases in demand — mostly from new liquefaction/LNG export terminals and Mexico-bound gas pipelines — and the incremental supply to the coast via new, large-diameter pipes from the Permian are likely to be out of sync. That shifting imbalance, in turn, may well cause volatility in Houston Ship Channel gas prices as they relate to Henry Hub. In fact, we’re already seeing signs of what’s to come. Today, we continue our look at upcoming gas infrastructure expansions and their potential impact on the greater Texas Gulf Coast gas supply-demand balance.
