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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.

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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.

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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.

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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.

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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.

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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.

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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.

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Well, it finally happened. After several years of assessing the possible development of a large, integrated propane dehydrogenation (PDH) plant and polypropylene (PP) upgrader unit, a joint venture of Canada’s Pembina Pipeline and Kuwait’s Petrochemical Industries Co. (PIC) earlier this week announced a final investment decision (FID) for the multibillion-dollar project in Alberta’s Industrial Heartland. The new PDH/PP complex won’t come online until 2023, but when it does, it will provide yet another new outlet for Western Canadian propane, which has been selling at a significant discount in recent years. Today, we discuss Pembina and PIC’s long-awaited PDH/PP project, Inter Pipeline’s development of a similar project nearby, Western Canadian propane export plans — and what they all mean for propane prices.

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The U.S. Treasury Department last week announced new sanctions on Petróleos de Venezuela, S.A. (PDVSA), the national oil company of Venezuela, that effectively halts imports of Venezuelan crude oil into the U.S. Given that the Venezuelan crude imported to the U.S. is of the heavy sour variety, which is not produced in large amounts in the U.S. (except for California), certain refineries along the Gulf Coast are left scrambling to find alternative sources of feedstock for their facilities. Today, we evaluate historical crude oil imports from Venezuela, the refineries that are most heavily impacted, and the potential effects of the sanctions on U.S. refiners.

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U.S. crude oil exports from Gulf Coast ports are soaring — in January they averaged well over 2 MMb/d — and when you’re moving large volumes long distances by water, there’s no vessel as efficient as a Very Large Crude Carrier (VLCC). A number of midstream companies are planning costly offshore terminals that could fully load 2-MMbbl VLCCs, but jobs like that take years, and Moda Midstream is in no mood to wait. Since it acquired Occidental Petroleum’s (Oxy) Ingleside marine terminal near Corpus Christi last September, Moda has been adding new tankage and loading equipment to enable it to load up to 1.25 MMbbl onto a VLCC within 24 hours from arrival to departure, then send the supertanker out to the deep waters of the Gulf for a quick top-off via reverse lightering. Upon completion of further expansion programs, the terminal’s loading capabilities will reach a combined 160 thousand barrels per hour (Mb/hour) among its three berths. Today, we discuss recent and near-term enhancements at Texas’s newest VLCC loading facility.

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