For much of the past few years, natural gas at Northeast demand market hubs has been priced at deep discounts, particularly in the low-demand summer months, because of the flood of Marcellus Shale gas that couldn’t go anywhere else. But now, those markets could soon see some upward pressure as pipeline projects that will expand takeaway capacity from the region come online. One of those projects is Williams’s Transco Pipeline Dalton Expansion, which includes an expansion of Transco’s mainline as well as a new, “greenfield” lateral. The project has already commenced partial-path service to move as much as 448 MMcf/d south on the mainline from Transco’s Zone 6 in New Jersey to its Zone 4 segment in Mississippi. And just yesterday (Thursday, July 13), Transco submitted a request with the Federal Energy Regulatory Commission (FERC) to place the remaining portion — the new Dalton Lateral pipeline extension and related connections — into service less than three weeks from now (on August 1). Today, we provide an update on the project and potential market effects.
One of the major target markets for Appalachian natural gas is the U.S. Southeast. More than 32 GW of gas-fired power generation units are planned to be added in the South-Atlantic states by 2020 and LNG exports from the Southeast are increasing. Of the 15.5 Bcf/d of takeaway capacity planned for Appalachia, close to 5 Bcf/d is targeting this growing demand. Despite the need, these pipeline projects designed to increase southbound flows from the Marcellus Shale have faced regulatory delays and setbacks. Today, we provide an update on capacity additions moving gas south along the Atlantic Coast.
The contiguous U.S. natural gas market is on its way to having its second major LNG export terminal and a new source of demand in the Northeast region by the end of the year. Dominion’s Cove Point liquefaction project, located on the Chesapeake Bay in Calvert County, Maryland, last month received approval from the Federal Energy Regulatory Commission (FERC) to introduce fuel gas, signaling the start of commissioning activities, a precursor to start-up activities for the liquefaction train itself. Dominion also last November applied for permission from the Department of Energy to export up to 250 Bcf of LNG during pre-commercial operations starting as early as fourth-quarter 2017, and is awaiting a response. Once operational, the facility, which is located within just a few hundred miles of the Marcellus/Utica shales — will have access to one of the primary southbound pipeline corridors for Marcellus/Utica takeaway capacity and add nearly 0.8 Bcf/d of demand to the Northeast gas market. Today we provide a detailed look at the Cove Point LNG facility.
U.S. LNG exports via Cheniere Energy’s Sabine Pass LNG export facility are poised to be a major demand driver of the domestic natural gas market in 2017. Pipeline deliveries to the terminal have more than tripled since mid-2016 and are set to climb further as more liquefaction capacity ramps up. With two liquefaction trains already operational, the Federal Energy Regulatory Commission last month approved Train 3 to begin operations and also green-lighted the start-up of Train 4 commissioning. Today, we provide an update of Sabine Pass’s export activity and its potential effect on U.S. gas demand this year.
The Florida natural gas market will soon have access to another supply source. In June 2017, the Sabal Trail Transmission natural gas pipeline project is expected to begin service, bringing the market one step closer to connecting Marcellus/Utica natural gas to demand markets on the increasingly gas-thirsty Florida peninsula. The project will increase gas supply options for growing power generation demand in the Sunshine State while effectively also increasing gas-on-gas competition between producers in the Northeast, Gulf Coast and Midcontinent. Today we provide an update on Sabal Trail and its related projects.
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.
We talk a lot here in the RBN blogosphere about the bearish market effects of the Shale Revolution, and frequently highlight the U.S. Northeast natural gas region — rapidly growing gas production from the Marcellus/Utica; oversupplied, trapped-gas conditions; and resulting regional price discounts. These dynamics are driving massive investments in pipeline reversals, expansions and new capacity to move the gas to market. Northeast producers are counting on that increase in takeaway capacity to relieve price pressure and balance the market. But all this gas moving out of the region needs a home. Fortunately, new demand is emerging, from exports (to Mexico and overseas LNG) and into the U.S. power sector. One of the big growth regions is the U.S. Southeast, where power utilities are investing heavily in building out their fleet of gas-fired generation plants and are banking on this new, unfettered access to cheap Marcellus/Utica gas supply. Today’s blog provides an update on power generation projects coming up in the southern half of the Eastern Seaboard, based on a recent report by our good friends at Natural Gas Intelligence — “Southern Exposure: Gas-Fired Generators Rising in the Southeast; But Will Northeast Gas Show Up?”
After years of debate and speculation regarding prospects for U.S. exports of liquefied natural gas (LNG), the first cargo left the Gulf Coast around 8:30 pm EST Wednesday (February 24, 2016) from Cheniere’s Sabine Pass terminal, according to Genscape’s global LNG cargo monitoring service. The vessel carrying a little more than 3.0 Bcf of LNG is reportedly bound for Petrobras in Brazil. The incremental export demand that this LNG cargo and others like it to follow represent, is potentially good news for U.S. gas producers, with benchmark futures prices at Henry Hub, LA closing yesterday (February 25, 2016) near record seasonal lows at $1.711/MMBtu in the face of mild winter demand, record production and brimming storage levels. Today we look at how this first cargo was supplied and what that tells us about current and future impact to flows and regional prices.
As we stated in Part 1 of this series, New York City will need increasing amounts of natural gas as it continues its shift from oil-fired power plants and oil-based space heating. New gas pipeline capacity to and through the Big Apple has been added as recently as May 2015, but the nation’s largest city still faces wintertime gas-delivery constraints that cause costly spikes in gas and power prices. Given the challenges of adding new pipeline capacity in one of the most densely populated parts of the U.S., developer Liberty Natural Gas is planning an offshore liquefied natural gas terminal that by late 2018 would inject gas into the city’s existing pipeline network on an as-needed basis. Today, we continue our look at the economics of using imported LNG to supplement gas supplies in the Northeast.
The availability of pipeline flow data makes the U.S. natural gas market uniquely positioned to grasp with reasonable accuracy where it stands with regional or national supply and demand on a daily basis. If you understand how to wrangle and finesse this robust data source, you can make a pretty good estimate of where the supply is, where it is headed, how it’s being consumed, and ultimately, what that all means for prices. Today we wrap up our series on natural gas production estimates and how the industry uses pipeline flow data to track gas production trends in real time.
The acquisition of Williams Companies by Energy Transfer will create a midstream behemoth. The deal is expected to close during the first half of 2016 subject to regulatory approval. Once complete the main holding company Energy Transfer Corp (ETC) will be a C-Corp entity sitting atop Master Limited Partnerships (MLPs – see Masters of the Midstream for a more complete explanation of these structures) containing the assets of Energy Transfer Partners (ETP), Williams Energy Partners (WPZ), Sunoco LP (SUN) and Sunoco Logistics (SXL). The combined natural gas pipeline network will carry as much as 45% of U.S. Lower 48 dry gas production. Today we take a look at the natural gas infrastructure assets in the deal.
The start-up of Sabine Pass, the first liquefied natural gas (LNG) export terminal in the Lower 48, is only months away, and the complicated gas-delivery logistics behind the project are coming into focus. Surely one of the biggest challenges has been assembling the long-haul pipeline capacity needed to move several billion cubic feet of gas a day (Bcf/d) to Sabine Pass from deliberately diverse sources as far away as the Marcellus/Utica. After all, the nation’s pipeline network was initially designed to move gas from the Gulf Coast to the Northeast and Midwest, not vice versa. Today, we continue our look at the challenges of securing and moving huge volumes of gas to LNG export terminals, the emerging epicenters of U.S. gas demand.
The six liquefaction “trains” under development at Cheniere Energy’s Sabine Pass liquefied natural gas (LNG) terminal will demand nearly 4 Bcf/d of natural gas on average, the first 650 MMcf/d of that starting within a few months. And the five trains now planned at Cheniere’s Corpus Christi site—yes, now five, not three—will require another 3.2 Bcf/d. Taken together, that’s about 10% of current daily gas production in the U.S.; in other words, a monumental logistical task. Today, we start a series looking at the challenges of securing and moving huge volumes of gas to LNG export terminals, the emerging epicenters of U.S. gas demand.
For gas producers in Appalachia, this has not been such a good summer for basis – the price they get for their gas versus the benchmark at Henry Hub, LA. Basis in the eastern part of the Marcellus has been particularly weak, with negative differentials extending into New York. Even at some West Virginia points like Dominion South, producers have faced ugly basis for the past few months. But there are some points that have been relatively immune, including Columbia Gas TCO, which has been hanging in there at pricing pretty close to Henry. Even when parts of the Dominion South and TCO pipeline systems are on top of each other. Why are basis differentials in the Appalachian Mountains hopping around all over the place? Today we look into why some Northeast prices have taken a hit and others have not.
With U.S. natural gas production continuing to hit all-time records, the big question for the gas market is demand. Where is all that gas going to go? Well, we are pretty sure that most of the supply growth will be absorbed by the triad of new gas fired power generation, industrial demand and exports. The funny thing is that most of the volumes associated with these demand sources are located in one region – the southeastern U.S., with a heavy concentration of demand in Louisiana, home of the Henry Hub. This shift is turning what was a major supply area into an epicenter of natural gas demand, with the need for extensive new transportation paths into, rather than out of, the region. Today, we explore the implications of this transformation.