Northeast producers are about to get a new path to target LNG export demand at Cheniere Energy’s Sabine Pass LNG terminal. Cheniere in late December received federal approval to commission its new Sabine Pass lateral—the 2.1-Bcf/d East Meter Pipeline. Also in late December, Williams indicated in a regulatory filing that it anticipates a February 1, 2017 in-service date for its 1.2-Bcf/d Gulf Trace Expansion Project, which will reverse southern portions of the Transcontinental Gas Pipe Line to send Northeast supply south to the export facility via the East Meter pipe. Today we provide an update on current and upcoming pipelines supplying exports from Sabine Pass.
Northeast production growth, the primary driver of overall gains in U.S. natural gas output in recent years, has largely stalled in 2016. Rig counts in the Marcellus/Utica dropped to near six-year lows, and the region has been facing constraints—from takeaway capacity and in the past month or two from storage injection capacity. But market factors are again about to roil the Northeast: 1) winter heating demand is on its way, and 2) more takeaway capacity has come online in the past month and still more is coming before the year is up. Today, we review recent Northeast natural gas production trends using pipeline flow data from Genscape and assess factors that will impact regional production this winter.
A total of 13 U.S. liquefaction trains with a combined capacity of about 58 MTPA (~8 Bcf/d) are either in early stages of operation along the Gulf Coast or under construction and scheduled to be online by the end of 2019. Of that, about 3.2 Bcf/d is being developed along the Texas Gulf Coast. Beyond that, a “second wave” of liquefaction projects is lining up, with as much as an additional 11 Bcf/d of capacity proposed for Texas by the early 2020s. While many of these second-wave projects may not get built, those that do will require the construction or rejigging of hundreds of miles of pipelines, particularly along that Gulf Coast corridor. Several of the first and second wave liquefaction projects have proposed to build laterals that connect to and branch out from nearby long-haul pipelines, creating new Gulf Coast-bound delivery points for Eagle Ford shale gas as well for supply that will eventually move south from supply basins as far north as the Marcellus and Utica shales. Today, we take a closer look at these liquefaction-related pipeline projects and how they will connect to and impact the existing pipeline network.
New power plants in Mexico have spurred natural gas demand south of the border––and fast-rising gas imports from the U.S, particularly Texas. Thus far, pipeline exports from Texas to Mexico have primarily been supplied by gas produced within the Lone Star State, but a big squeeze is on as nearby Texas production volumes decline (particularly the Eagle Ford) and export demand continues to increase, not just from Mexico but from new liquefaction/LNG export terminals along Texas’s Gulf Coast. Today, we unpack the shifting Texas supply and demand balance and potential implications for the market.
Mexico’s power sector is one of three major demand centers U.S. natural gas producers and pipeline projects are targeting, the other two being the U.S. power sector and LNG exports. U.S. natural gas exports to Mexico are up 20% year-on-year in 2016 to date to nearly 3.5 Bcf/d––more than double the export volume five years ago––and are poised to soar past 6 Bcf/d by the end of the decade. Mexico’s energy operators are on a tear adding new natural gas-fired power generation capacity and building a sprawling network of natural gas transportation capacity. But delivering increasing volumes of U.S. natural gas to Mexico will require substantial changes on the U.S. side as well, particularly in Texas. Today, we continue our look at plans for adding pipeline export capacity along the Texas-Mexico border.
There is a natural gas renaissance of sorts happening south of the U.S.-Mexico border. The state-owned Comisión Federal de Electricidad (CFE) is investing heavily in expanding and modernizing its power generation fleet with thousands of megawatts of new, natural gas-fired power plants, and the energy secretary also last October put forth an aggressive five-year plan to build out a pipeline system to supply growing gas-fired generation demand. Mexico’s power generation demand is increasingly a target for U.S. gas producers and pipeline projects. At the same time, as we discuss in Part 2 of RBN’s Miles and Miles of Texas Drill-Down Report published last week, a good portion of this new demand is relying on — and in large part has been driven by — availability of low-priced gas from the U.S. via Texas and the U.S. Southwest states. But there is a lot that needs to happen on both sides of the border over the next few years to facilitate this mutually beneficial relationship. Already since October, Mexico’s newly appointed independent pipeline operator, Centro Nacional de Control del Gas Natural (CENAGAS), has pulled back on the pipeline buildout. Today, we begin a two-part series on how plans to facilitate this new demand are progressing, starting on the Mexico side of things.
It’s no secret that a long list of pipeline projects have been proposed to help move natural gas out of the Northeast production areas. But if you were a Marcellus or Utica producer, how would you decide whether you were interested in new capacity that hadn’t been proposed or built yet? Of course, pipeline companies have armies of engineers, cost estimators, and market analysts to bring one of these monster projects to fruition. But for anyone else, particularly in the early stages, how do you even know it’s a reasonable idea? For anyone testing a concept, you need a way to ballpark some scenarios for a new pipe. We’ve been running a blog series on our RBN Pipeline Economics Estimation Model, a quick, rule-of-thumb “sanity test” for new capacity. Today, we wrap up our walk-through of the model, with a real-world example to gauge the accuracy of the model, and then with a discussion on how the model can be used to measure economies of scale in picking the minimum volume you probably need for a new pipeline.
New and expansion natural gas pipeline projects have been part and parcel of the shale production boom in the U.S. Northeast. In fact, Northeast gas production could not have reached anywhere near its current level and become a major natural gas supplier to the U.S. without the substantial addition of takeaway capacity out of the Marcellus/Utica shale areas. At the same time, the competition among pipeline developers jockeying to be in the right place at the right time has been fierce. And now, low natural gas prices and uncertainty about future production growth have only increased the competition---not all projects will make it to in-service. The risks are higher for big pipeline projects, but so are the stakes. These days, the overall risk tolerance among shippers and investors is low, especially among producers. So if you’re a producer, how can you make sure you don’t end up on the wrong side of a transportation deal? In today’s blog, we continue our walk-through of the RBN Pipeline Economics Estimation Model. We’ll follow up in a later installment with a real-world test and other ways to use the model.
We’ve spent a lot of time here in the RBN blogosphere discussing the trials and tribulations of natural gas producers in the Marcellus and Utica shales who are “trapped behind the pipe,” unable to get sufficient takeaway capacity to move supply to market (both within and outside the U.S. Northeast region) where they could get a higher price for their gas. Pipeline companies have ponied up billions of dollars to build lots of pipe to alleviate these constraints and much more investment is planned. Of course, those pipelines and their committed shippers hope that the investment will pay off long-term – that the economics for building the pipe will justify the cost. The pipeline will have scores of engineers, lawyers and accountants to figure that out. But what if you just want to make a quick-and-dirty estimate of the economics? Well, there is a way. In today’s blog, we walk through the factors you need to consider when your boss runs in and asks, “Hey—what would it cost to move gas there in a new pipe?”
U.S. natural gas production growth has spurred a massive build-out of natural gas pipeline capacity in recent years, and a lot more is on the way, particularly out of the Northeast. To Marcellus and Utica producers eager to improve returns on their investments, this incremental pipeline capacity is a long-overdue relief valve for the pressure that’s been building in the region from growing supply congestion and low prices. But pipeline development is an expensive, long-term endeavor, and few, if any, pipeline projects are slam-dunks. Also, market conditions initially driving the development of new takeaway capacity may change, putting a project’s relevance—and, in turn, its utilization and profitability—at risk. In today’s blog, we begin a look at how midstream companies and their potential shippers evaluate (and continually reassess) the economic rationale for new pipeline capacity in today’s very changeable markets.
A year ago (April 2015) the price spread between Light Louisiana Sweet (LLS) the St. James, LA benchmark light crude and Permian West Texas Intermediate (WTI) delivered to Houston was roughly $2.50/Bbl. In the first quarter of 2016 – following the end of the crude export ban and the crash of crude prices below $40.bbl – that spread narrowed to 30 cents/Bbl. This price differential change has thrown a wrench into traditional Gulf Coast price relationships that encouraged the flow of crude east from Houston to Louisiana. Further changes are expected as pipeline projects due to be completed in the next two years will deliver Bakken and Permian crude direct to St. James. Today we wrap up our series on St. James with a look at changing crude prices and flows.
Two midstream operators have added at least 13 MMBbl of crude storage to the St. James hub during the past 8 years (NuStar and Plains All American). These companies have invested in the hub because of its proximity to the Gulf Coast and pipeline connectivity to refineries throughout the Eastern U.S. and as far northwest as Edmonton, Alberta. St. James has also been an active recipient of crude flowing east across the Gulf by barge and tanker from the Eagle Ford via Corpus Christi. These crude movements require terminal, storage and blending facilities. Today we describe crude storage facilities at St. James.
Two weeks ago, Tallgrass Energy, operator of the Rockies Express Pipeline (REX) received final approval to begin construction on its Zone 3 Capacity Enhancement (Z3CE) expansion project, its second east-to-west flow capacity expansion in as many years. The last one went into service last August and has been running at capacity near 1.8 Bcf/d for much of winter 2015-16. The Z3CE expansion will again increase westbound takeaway capacity on the mainline from the heart of the Marcellus/Utica shale by another 0.8 Bcf/d, on top of the existing 1.8 Bcf/d. Today we bring you the up-to-the-minute scoop on the latest REX expansion.
Tallgrass Energy’s Rockies Express Pipeline (REX) last week received final approval to begin construction on its Zone 3 Capacity Enhancement expansion project (Z3CE), which would expand east-to-west capacity out of the Marcellus/Utica shale production area to a record 2.6 Bcf/d. This project comes on the heels of REX’s East-to-West expansion (E2W), which came online last August and in one fell swoop gave Northeast producers their first substantial westbound firm forward-haul transportation capacity, totaling a full 1.8 Bcf/d. The upcoming Z3CE capacity (0.8 Bcf/d) will mark yet another milestone in the Great Pipeline Reversal that’s expected to ease supply congestion in the Northeast and support beleaguered Marcellus/Utica pricing points. That new capacity is not due in-service until late 2016. But now with nearly a full winter’s worth of pipeline flow data for the first E2W expansion, we can get a preview of potential impacts of the additional capacity on flows and pricing. Today we look at winter-to-date gas flows on REX and what they tell us about the Marcellus/Utica market.
Most Canadian oil sands crude production comes from very expensive mining or underground steam heating operations designed to produce consistently for decades that are costly to shutter in a downturn. Right now the crude netbacks (market price less transport costs) for these projects are more or less under water depending on transport routes. Yet production continues and new projects are still coming online. Today we estimate the netbacks (market price less transport cost) that Canadian producers are realizing.