The U.S. nuclear power sector is facing its biggest crisis in years, with an increasing number of nuclear units being retired for economic reasons and the four new units now under construction in the Southeast facing possible cancellation. Bad news for the nuclear sector is good news for owners and developers of natural gas-fired power plants — and, of course, for natural gas producers — because gas plants are a primary alternative to nuclear in providing reliable, around-the-clock power. Gas plants also are a go-to choice for supporting intermittently available renewable sources like wind and solar. Today we review the woes facing the nuclear sector, efforts by some states to prop it up with subsidies, and the strong economic/environmental case for ramping up gas-fired generation.
Daily Energy Blog
The U.S. natural gas market in recent weeks has turned less bullish than when it began the injection season on April 1. Last week, natural gas production surpassed year-ago levels for the first time this year. Meanwhile, weather and related demand are lagging behind historical comparisons. The result has been larger injections into storage, a fast-rising inventory and lower prices. The CME/NYMEX Henry Hub futures price for the prompt July contract has been averaging about $3.029/MMBtu, down about 21 cents (6.4%) from where the June contract expired at $3.236/MMBtu. Today, we provide an update of the gas supply and demand balance and prospects for injection-season storage fill.
After years of oversupply conditions and pipeline constraints, the U.S. Northeast natural gas market is on the verge of reaching a point where it is unconstrained by transportation capacity and enjoys increased optionality for reaching growing demand markets downstream. There are no fewer than 20 pipeline projects in the works to facilitate that. If all – or even most of them get built, the region would develop the opposite problem — not enough gas to fill all that new pipe. Ultimately, the state of the Northeast market will come down to the timing of the expansions projects compared with the pace of production growth. Today, we conclude this series with a look at how supply will line up with pipeline expansion in-service dates over the next five years.
For years now, U.S. Northeast natural gas production growth has been paced by the availability of pipeline takeaway capacity out of the Marcellus/Utica shales. Midstream companies have been racing to build the infrastructure to support drilling and rising supply in the region. And, until now, it was safe to assume that as new pipeline projects come online, volumes would grow to fill them in short order. But over the next couple of years, that may flip: takeaway capacity additions could soon outpace supply increases, and producers might not be able to keep up. Today, we provide an update of RBN’s Northeast gas production scenarios.
A record amount of natural gas supply — close to 8.0 Bcf/d — from the Marcellus and Utica shale plays is making its way to the broader U.S. market. That’s happened with the help of a substantial build-out of pipeline infrastructure to reverse gas flows out of the now oversupplied Northeast, which has allowed regional production to grow to nearly 23 Bcf/d from less than 8 Bcf/d five years ago. One of the major target markets for this gas has been the Midwest. About a third of current outbound flows is heading to the Midwest, primarily via the reversal and expansion of Tallgrass Energy’s Rockies Express Pipeline, completed earlier this year. Moreover, midstream companies are due to install an additional 5.5 Bcf/d or so of takeaway capacity to target the Midwest and Canada by late 2020, with 70% of that due this year alone, starting with Energy Transfer’s Rover Pipeline. However, many of these expansion projects have been embattled by regulatory, environmental and political hurdles during the approval process. Today we provide an update of Rover and other Midwest- and Canada-bound takeaway projects.
Plans for LNG export terminals, petrochemical plants and gas-fired power generation along the Gulf Coast have made it the #1 target market for Marcellus/Utica natural gas producers. At the same time, these demand projects along the coast, from the Southeast, Texas and even farther down in Mexico, are counting on more supply growth from Appalachia. Since 2014, close to 5.0 Bcf/d of southbound pipeline capacity has been added and another 4.0 Bcf/d is due by early 2019. Today, we continue our update of pipeline expansions out of Appalachia, this time with a focus on the Ohio-to-Gulf Coast corridor.
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.
For several years now, power generators and other major energy users in the Caribbean have been working to shift from diesel or fuel oil to alternative fuels — mostly natural gas delivered by ship as liquefied natural gas (LNG), but also propane. A few significant projects have advanced, and new infrastructure to receive LNG and propane has been put in place to support additional fuel imports into the region. But other projects have been delayed or even scrapped because of financial or regulatory troubles. Today we update the laid-back region’s efforts to wean itself off diesel- and fuel-oil-fired power.
Rising crude oil production in the SCOOP and STACK oil and NGLs shale plays is driving the development of processing and natural gas pipeline capacity for associated natural gas volumes from the region. Earlier this month (Wednesday, May 3), Enable Midstream announced Project Wildcat, a 400-MMcf/d rich gas takeaway project. On the same day, SemGroup Corp. announced the Canton Pipeline to provide an initial 200 MMcf/d (and up to 400 MMcf/d) of capacity between the STACK play and its processing facility in northern Oklahoma. Enable last month also announced a firm shipper commitment on another of its takeaway projects — the Cana and STACK Expansion (CaSE). At the same time, late last month (on April 27), NextEra withdrew plans for its 1.2-Bcf/d Sooner Trails Pipeline. Today, we provide an update of the various projects vying to move associated gas from the SCOOP/STACK to downstream demand markets.
Since 2013, nearly 3.0 Bcf/d of natural gas pipeline capacity has been added from Appalachia to the heavily populated, hard-to-reach demand centers along the East Coast. And another nearly 3.0 Bcf/d is in the works. The need for gas supply reliability in the heavily populated East, along with producers’ need to move their gas to market, is driving these expansions. But concentrated population centers, along with the geography, geology and regulatory environment of the area, all also make it tough and expensive for upgrading, expanding and developing the gas transportation system. Many of the proposed projects have been delayed or canceled as a result. Today, we provide an update on eastbound pipeline expansions from Appalachia.
Only a few years ago, pretty much all the natural gas flowing through pipelines in the southeastern U.S. was headed north to serve demand in the Northeast and the Midwest. But that’s all been changing — and fast. Gas production in the Marcellus/Utica has soared and now meets the needs of the Northeast and more. And, as LNG exports from the Gulf Coast ramp up and Southeast gas demand for power generation rises, more and more Marcellus/Utica gas is flowing south, raising the question of whether pipes in the Southeast can handle it all over the long term. Today, we discuss the findings of RBN’s work in preparing a study for the American Petroleum Institute (API) on the adequacy of regional gas pipeline infrastructure. RBN’s work discussed here is the current analysis being used to inform and develop stakeholder briefings. We anticipate API will release the final version in report form, after its completion.
For years now, limited natural gas pipeline takeaway capacity has constrained gas production growth in the Marcellus/Utica natural gas shale plays in the Northeast. To fix that, a slew of pipeline projects were planned to relieve the constraints as regional supply began outstripping demand starting in 2014. Now, the region is on the verge of being unconstrained for the first time since the Shale Revolution hit Appalachia. Many of those projects have come online since then, and another 19 expansions totaling 15.5 Bcf/d are planned for completion by late 2019. If all goes as expected, this next round of projects should turn the Northeast market on its head again, as the capacity additions should start to outpace production growth. The problem, though, is that several projects have faced significant challenges in recent months, resulting in either cancellation or major delays. At the same time, Marcellus/Utica production growth has slowed dramatically in the past 18 months or so. In today’s blog, “In a Northeast Minute…Everything Can Change — An Update of Marcellus/Utica Takeaway Projects,” Sheetal Nasta begins a series looking at the status of regional takeaway capacity expansions.
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.
Natural gas producers in the Canadian province of Alberta have had a heck of a time in recent years. Marcellus/Utica gas production has flooded markets in eastern Canada and the U.S. Northeast and Midwest, squeezing out Alberta gas in the process. Also, Alberta gas producers’ dreams of piping gas west to the British Columbia coast for export to Asia as LNG have been thwarted. Lucky for them, though, gas demand within Alberta is on the rise, thanks to increasing use of gas in the oil sands and a decision by the province’s largest power generator to shift from coal- to gas-fired generation and renewables. Today we update gas output and consumption trends in Canada’s Energy Province.
Natural gas production growth in the U.S. Northeast—the primary driver of U.S. production growth in recent years—has slowed dramatically in the past few months, up no more than 1 Bcf/d year-on-year, compared with growth in increments of 3 and 4 Bcf/d in previous years. Despite the slowdown, the regional balance continues to lengthen, with supply growth outpacing demand. Yet, regional gas prices, specifically at key supply hubs, which previously were struggling under the weight of oversupply coupled with limited access to growing demand markets, are strengthening. Is this the beginning of the end of takeaway constraints and distressed supply pricing in the region? Or will constraints reemerge this summer? Today, we provide an update of Northeast gas supply/demand balance.
