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.
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.
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.
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.
The U.S. started exporting ethane by ship less than three years ago, first out of Energy Transfer’s Marcus Hook terminal near Philadelphia and then from Enterprise Products Partners’ Morgan’s Point facility along the Houston Ship Channel. Good news for NGL producers, right? Well yes, sort of. Because while waterborne export volumes rose through 2016, 2017 and the first seven months of last year, they’ve been flat-to-declining ever since, with further ethane-export growth hampered primarily by a lack of international demand. That demand may soon be ratcheting up — mostly in China, but also in Europe — but it won’t happen overnight. Today, we discuss ethane export trends, the Morgan’s Point and Marcus Hook marine facilities, and plans for new ethane export capacity tied directly to new overseas ethane crackers.
Lower-48 natural gas demand surged in 2018, managing to offset ballooning production volumes and putting the gas market on the razor’s edge going into this winter. Demand growth occurred across all domestic sectors as well as export markets, but was led by increased demand from power generators. Some of that was weather-related. However, there also was a level-shift up in demand on a per-degree basis, meaning more gas was burned than historically at the same temperatures, signaling a gain in gas market share. What were the drivers, and can we expect this growth pace to continue? Today, we take a closer look at the demand components behind the recent growth trends.
Imagine a crude oil hub with all this: a central location near the Gulf Coast; pipeline, waterborne and rail access to a wide range of imported and domestic crude; tens of millions of barrels of storage capacity; direct connections by pipe to nearly a dozen major refineries; and the ability to load “neat” or blended barrels of oil onto Aframax-class vessels for export. You’ve conjured up the hub in Louisiana’s St. James Parish, which is fast-becoming an even more significant market player, with even broader access to U.S. and Canadian crude supplies and, very likely, direct outbound links to one or more export terminals capable of fully loading VLCCs. Today, we continue our series on St. James with a look at its storage assets and at the pipes that flow into and out of the hub.
While Permian natural gas pipeline announcements came fast and furious last year, it had been relatively quiet on that front the past few weeks. Leave it to the folks at WhiteWater Midstream to break the lull, which is exactly what they did with the recent announcement of a binding open season for a new interstate pipeline in the heart of the Delaware Basin. Named Steady Eddy, the pipeline would originate in an underserved corner of the Permian and provide access to the Waha Hub, where a number of planned greenfield pipelines leaving the Permian will begin. Today, we look at the details of WhiteWater’s proposed Steady Eddy pipeline project.
The market is used to crude oil spreads in the Permian Basin being volatile. Fast-paced production growth, the addition of new takeaway pipelines — and the rapid filling of those new pipes — have all impacted in-basin pricing, and we’ve seen differentials from the Permian to its downstream markets — Cushing, OK, and the Gulf Coast — widen and narrow as supply and demand fundamentals have changed. But recently, things have gotten a lot wilder. In September 2018, the Midland discount to WTI at Cushing blew out to almost $18/bbl, then narrowed to less than $6/bbl only three weeks later, thanks largely to the start-up of Plains All American’s much-ballyhooed, 350-Mb/d Sunrise Expansion. As Sunrise started to fill up, price differentials initially widened for a brief period of time. But, as we kicked off 2019, the Midland-Cushing spread quickly shrank further and then flipped, with Midland last Friday (January 25) trading at a $1/bbl premium to Cushing crude. You might wonder, how the heck did that happen? In today’s blog, we discuss how things play out when a supply glut evaporates and traders are suddenly caught in a tight market.
There’s a case to be made that midstream-sector stocks are being undervalued, in part because of the market’s stubborn adherence to an old — and now outdated — dictum that links midstream prospects to the price of crude oil. That maxim, based largely on the belief that lower prices result in declining production and pipeline volumes, has been undone by the Shale Revolution’s proven promise that, thanks to remarkable efficiency gains, production of crude, natural gas and NGLs can increase even during periods of not-so-stellar prices. Despite this new Shale Era rule, the outlook for individual midstream players can vary widely, depending on a number of factors, including their assets’ locations, their exposure to shipper-contract roll-offs and their strategies for growth. Today, we discuss key themes and findings from East Daley Capital’s newly updated “Dirty Little Secrets” report assessing the owners of U.S. pipelines, processing and storage facilities, export terminals and other midstream assets.
Mexico’s energy sector has been dealing with a fair amount of uncertainty of late. Newly installed Mexican President Andrés Manuel López Obrador has promised to undo elements of the country’s historic energy reform program, limit imports of hydrocarbons, and focus on domestic production and refining. How much will all this affect the export of natural gas from the U.S. to Mexico? It’s too soon to know what the long-term impact might be, but for now, gas exports remain near record highs and the pipeline buildout within Mexico is proceeding. That’s not to say, however, that the infrastructure work has gone without its own set of challenges — many of those were apparent well before the recent political changes. Today, we begin a series examining the opportunities and potential pitfalls ahead this year for Mexico’s natural gas pipeline infrastructure additions.