Increasing U.S. shale oil production has benefitted many U.S. refineries, but along the Gulf Coast, the primary beneficiaries have been in Texas. As production increased in the Permian and Eagle Ford plays, new pipelines were built to supply refinery centers in Corpus Christi, Houston, and Beaumont/Port Arthur. In contrast, the availability of shale crude by pipeline to refineries in Southeast Louisiana has lagged. However, new pipeline capacity to the crude hub in St. James, LA, is about to change the dynamic in a major way. Today, we continue our series on St. James by discussing the Bayou State’s refinery infrastructure and how new pipelines could impact refinery crude slates.
In a world where Marcellus/Utica natural gas supplies and Gulf Coast gas demand are increasingly interdependent, what would happen if flows along a critical route connecting the two regions were disrupted? The market caught a glimpse of that on January 21, when an explosion on Texas Eastern Transmission’s 30-inch line in Noble County, OH, shut down flows through its Berne compressor, which serves as a key gateway for Gulf Coast-bound gas out of Appalachia. Partial service was restored a few days later, but a chunk of the capacity remains offline as repairs are completed, and southbound volumes are running at 60% of what they were prior to the outage. Not too long ago, an outage severing Northeast producers’ access to a major takeaway route to the Gulf would have hammered Northeast supply prices, even during the peak winter demand months. But as expansion projects have vastly improved pipeline connectivity within Appalachia and takeaway capacity out of the region, they’ve transformed how some of those legacy long-haul pipelines function and even the role they play in the market. The TETCO outage provides a glimpse into what that will mean for the Northeast and its downstream markets. In today’s blog, we begin a series looking at the implications of a well-connected Marcellus/Utica, starting with a recap of the TETCO event and its immediate impacts on southbound flows.
The U.S. midstream sector has been on a development binge the past few years, mostly in an effort to catch up — and then keep up — with production growth in the Shale Era’s two premier plays: the Marcellus/Utica in the Northeast and the Permian Basin in West Texas and southeastern New Mexico. What’s sometimes overlooked, however, is that significant numbers of new pipelines, processing plants and other key assets are being built in smaller, lower-profile production areas. The Niobrara’s Denver-Julesburg and Powder River basins are cases in point. Exploration and production activity in the D-J in particular has been soaring, and the resulting gains in crude oil, natural gas and NGL output has been stressing the region’s hydrocarbon-related infrastructure, thus spurring the development of new processing plants and pipelines. Also, interest in the Powder has been renewed — production there has been rebounding after crude-production ups and downs and gas-production declines through the 2010s. Today, we discuss highlights from RBN’s new Drill Down Report on the Niobrara production region.
With about 30 million metric tons per annum (MMtpa) of liquefaction capacity scheduled to come online in 2019, feedgas deliveries are poised to be the biggest driver of Lower-48 natural gas demand this year. The timing of this emerging export demand growth from these complex, multi-process facilities will come down to a veritable obstacle course of construction and testing timelines and regulatory approvals. Understanding these factors will be key to anticipating the gas-market impacts of the oncoming demand. Today, we begin a short series breaking down the liquefaction train commissioning process and what it tells us about the timing of incremental feedgas demand over the next several months.
In the past month, two integrated majors with strong footprints in the Permian Basin announced plans to increase their refining capacity along the Texas Gulf Coast. During the last week of January 2019, ExxonMobil announced a final investment decision to expand its Beaumont, TX, facility’s capacity by 250 Mb/d, making it the largest U.S. refinery, and then confirmed an investment with Plains All American and Lotus Midstream to build a 1-MMb/d pipeline to ship crude to its Beaumont and Baytown, TX, refineries. In the same week, Chevron announced its purchase of the 110-Mb/d Pasadena, TX, Houston Ship Channel refinery from Brazil’s national oil company, Petrobras. Both Exxon and Chevron boasted record Permian production in their fourth quarter 2018 earnings calls. Today, we review Chevron’s purchase and Exxon’s expansion in light of Permian production growth and the changing Gulf Coast refining market.
Enbridge’s 2.8-MMb/d Mainline system from Alberta to the U.S. Midwest has been running close to full, as have the other crude oil pipelines out of Western Canada. The Mainline is a unicorn among these pipes, however, in that none of its capacity — zilch — is under long-term contract. Instead, under Enbridge’s almost nine-year-old Competitive Tolling Settlement (CTS), shippers each month submit nominations stating the volumes of crude they would like to transport the following month on various elements of the Mainline system, then hope they get what they need when the available capacity is divvied up. In an effort to give producers and refiners the pipeline-capacity certainty they say they want — and to optimize the efficiency of the Mainline’s operation — Enbridge has been working with shippers on a CTS-replacement plan that would commit as much as 90% of the capacity on the pipeline system to shippers who enter into long-term contracts. Today, we continue this blog series with a look at how the prospective “priority access” capacity-allocation system is shaping up, how it might affect planned pipeline projects, and how it may facilitate the transport of a lot more crude from Alberta to the U.S. Gulf Coast.
After 19 years of natural gas production from the waters off the Canadian Maritime provinces, ExxonMobil, operator of the Sable Offshore Energy Project, shut down production there effective January 1, 2019. Though the closure had been announced well in advance, the end of SOEP output has left the two natural gas-consuming provinces in the region, New Brunswick and Nova Scotia, without any indigenous gas supplies. It’s also made them fully reliant on either pipeline gas from the U.S. Northeast and Western Canada or imported volumes of LNG into the Canaport Energy terminal in New Brunswick. Will the shutdown put even more stress on the already overtaxed gas pipeline system in New England? And will it spur increased flows of Western Canadian gas into northern New England and the Maritimes? Today, in Part 1 of this blog series, we begin an examination of the potential impacts of SOEP’s demise on New England and Eastern Canadian gas markets.
Once the “riverboat gamblers” of U.S. industry, executives at exploration and production companies got religion after the brutal oil price crash in late 2014 and adopted a far more conservative approach to investment based on their new 11th commandment: “Thou shalt live within cash flow.” So it’s no surprise that early 2019 guidance issued by more than half of the 45 major E&Ps we track shows them cutting back capital investment in response to last fall’s decline in oil prices from a more optimistic scenario a year ago. Nearly three-quarters of the 26 companies reporting their 2019 guidance are reducing exploration and development outlays, while only three of the remainder are budgeting increases greater than 10%. What is surprising is that these forecasts include solid production growth virtually across the board, especially for E&Ps that focus on crude oil. Today, we look at how a representative group of U.S. E&Ps are dealing with lower crude prices.
Energy Transfer’s Mariner East pipeline system was supposed to help resolve a growing problem for producers in the “wet” Marcellus and Utica plays — namely, the need to transport increasing volumes of LPG out of the Northeast, especially during the warmer months, when in-region demand for LPG is low. The pipeline system also was meant to spur LPG and ethane exports out of Energy Transfer’s Marcus Hook marine terminal near Philadelphia. So how are things going? Well, the now five-year-old, 70-Mb/d Mariner East 1 pipeline, designed to transport ethane and propane, has been offline ever since a sinkhole exposed a part of the pipe late last month. The 275-Mb/d Mariner East 2 pipe is finally in operation and enabling a lot more LPG to move to Marcus Hook, but for now it can only run at about 60% of its capacity. And last Friday, a key Pennsylvania regulator suspended its review of outstanding water permit applications for the remaining piece of ME-2 and the parallel 250-Mb/d ME-2 Expansion project, and threw into doubt how long it might take to finish the Mariner East system and ramp it up to full capacity. Today, we begin a series on recent Mariner East developments and explain how, despite the mixed bag of Mariner East news in recent weeks, the situation is not as bad as it may seem.
The vast majority of the incremental natural gas pipeline capacity out of the Marcellus/Utica production area in recent years is designed to transport gas to either the Midwest, the Gulf Coast or the Southeast. Advancing these projects to construction and operation hasn’t always been easy, but generally speaking, most of the new pipelines and pipeline reversals have come online close to when their developers had planned. In contrast, efforts to build new gas pipelines into nearby New York State — a big market and the gateway to gas-starved New England — have hit one brick wall after another. At least until lately. In the past few weeks, one federal court ruling breathed new life into National Fuel Gas’s long-planned Northern Access Pipeline and another gave proponents of the proposed Constitution Pipeline hope that their project may finally be able to proceed. Today, we consider recent legal developments that may at long last enable new, New York-bound outlets for Marcellus/Utica gas to be built.
The U.S. natural gas market last week was again reminded of the hair-trigger conditions that Permian producers and marketers are operating under — with gas production pushing against available takeaway capacity, all it takes is an otherwise minor/routine maintenance event on even one West Texas takeaway pipeline to send regional gas prices spiraling into negative territory. Waha Hub gas prices last week collapsed to their lowest level ever, with intraday trades even going negative — meaning some had to pay the market to take their gas. This wasn’t the first time that’s happened in the Permian — a similar event occurred in late November 2018 — but it was the worst to date and signals a heightened supply glut in the region, at least until the first new takeaway pipeline comes online in the fourth quarter of this year. Today, we explain the recent price weakness in West Texas and implications for Permian basis in 2019.
Crude-by-rail (CBR) has been a saving grace for many Canadian oil producers. With extremely limited pipeline takeaway capacity, rail options from Western Canada to multiple markets in the U.S. have acted as a relief valve for prices — there for producers when they need it, in the background when they don’t. In 2018, we saw a major resurgence in CBR activity from our neighbors to the north, with volumes reaching an all-time high of 330 Mb/d just this past November. But just as quickly as CBR seemed ready for takeoff, the rug got pulled out from underneath those midstream rail providers and traders who had lined up deals and railcars to take advantage of wide price spreads. When Alberta’s provincial government announced its 325-Mb/d production curtailment beginning at the start of 2019, many midstream/marketing and integrated oil companies bemoaned what it could potentially do to market opportunities. And they were spot-on. Wide price differentials for Canadian crudes to WTI disappeared quickly and eliminated most, if not all, of the economic incentive to move crude via rail, and even by pipeline. In today’s blog, we recap the recent move away from crude-by-rail by some of Canada’s largest CBR players, and discuss the risks of long-term CBR commitments in volatile times.
U.S. crude oil, NGL and gas markets have entered a new era. Exports now dominate the supply/demand equilibrium. These markets simply would not clear at today’s production levels, much less at the flow rates coming over the next few years, if not for access to global markets. This year, the U.S. may export 20-25% of domestic crude production, 15% of natural gas and 40% of NGLs from gas processing, and those percentages will continue to ramp up. What will this massive shift in energy flows mean for U.S. markets, and for that matter, for the rest of the world? The best way to answer that question is to get the major players together under one roof and figure it out. That’s the plan for Energy xPortCon 2019. Warning!: Today’s blog is a blatant advertorial for our upcoming conference.
The dam has broken on the “second wave” of U.S. LNG export projects. ExxonMobil and Qatar Petroleum last week announced a final investment decision on their joint venture liquefaction and export project — called Golden Pass Products — at the brownfield site of the Golden Pass LNG terminal on the Texas side of the Sabine-Neches Waterway. That’s a skipping stone’s throw from Cheniere Energy’s Sabine Pass LNG and Sempra Energy’s Cameron LNG terminals on the Louisiana side of the Gulf of Mexico outlet, as well as a number of other second-wave contenders. With construction slated to begin late next month, the Golden Pass project expects to become operational and begin taking feedgas by 2024. Today, we provide an update on Golden Pass, its potential feedgas needs and how it will be supplied.
The recently mandated reduction in Alberta crude oil production has helped to ease takeaway constraints out of Western Canada, but only temporarily. Worse yet, it’s unclear how long it will take to add new takeaway capacity from challenged projects like the Trans Mountain Expansion Project or Keystone XL. In the midst of all this trouble and uncertainty, Enbridge is pursuing a potentially controversial plan to revamp how it allocates space — and charges for service — on its 2.8-MMb/d Mainline system, the primary conduit for heavy and light crudes from Western Canada to U.S. crude hubs and refineries. Today, we begin a series on the company’s push to shift to a system that would allocate most of the space on its multi-pipe Mainline system to shippers that sign long-term contracts.