LNG Canada, the newly sanctioned liquefaction/LNG export project in British Columbia, is an entirely different animal than its operational and under-construction counterparts in the U.S. The Shell-led LNG Canada project is being developed without any of the long-term offtake contracts that financed Sabine Pass, Cove Point and the projects now being built along the Louisiana and Texas coasts, and it requires the construction of a new, long-haul pipeline — Coastal GasLink. What’s also different is that the BC project’s co-owners have been developing their own gas reserves to supply the project, though they may also turn to the broader Montney and Duvernay markets for the gas they will need. Today, we conclude a two-part series with a look at how the project expects to undercut its U.S. competitors.
Daily Energy Blog
U.S. natural gas supply continues to set all-time records, and strong production growth is expected to continue. Most of these supply gains will come from the Northeast, where another round of pipeline capacity additions are being completed. But despite all this incremental gas output, a combination of cold weather last winter and hot weather this summer means that U.S. gas storage inventories are likely to end the fall season at their lowest levels since 2005. And even this comparison understates how low inventories are — gas consumption has grown dramatically in the past 10 years, and storage inventories are at all-time lows when considered in terms of the number of days of average consumption. Today, we begin a series on the implications of historically low gas storage inventories, including what the gas market might look like if this winter turns out to be colder than normal.
Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission pipeline saw its first natural gas flows this week, as the Federal Energy Regulatory Commission (FERC) approved partial service on the project, opening another nearly 1 Bcf/d of capacity from Appalachia’s Marcellus/Utica producing region to the Midwest. NEXUS marks the last big westbound takeaway project from the Northeast, except for the remaining pieces of Energy Transfer’s (ETP) Rover Pipeline. It also marks the escalation of gas-on-gas competition in the Midwest market, where U.S. Midcontinent and Canadian gas supplies are also battling it out for market share. Today, we take a closer look at the NEXUS project and its potential implications for the Northeast and Midwest gas markets.
The final investment decisions by Royal Dutch Shell and its partners in the LNG Canada liquefaction and export project in British Columbia are a long-term boon to Western Canadian natural gas producers and to TransCanada, which now can proceed with its planned Coastal GasLink pipeline across the full breadth of BC. But the LNG Canada facility in Kitimat and the new 420-mile, 2.1-Bcf/d pipe won’t come online until 2023 — an eternity for producers in the region’s Montney and Duvernay shale plays, who through much of 2018 have been enduring profit-crushing price discounts for their gas relative to Henry Hub. Today, we consider the largest North American liquefaction/LNG export project to be sanctioned in several years, and why BC and Alberta producers wish it were coming online much sooner.
While many are getting ready for the usual trappings of fall — Halloween, Thanksgiving turkey and Black Friday sales — Northeast natural gas market participants are gearing up for their own seasonal ritual — gas pipeline takeaway expansions. Two days ago, Enbridge/DTE Energy’s 1.5-Bcf/d NEXUS Gas Transmission pipeline received approval to start partial service for nearly 1 Bcf/d of capacity. That follows Williams/Transco’s Atlantic Sunrise natural gas project, which launched service for its full 1.7 Bcf/d of southbound capacity last week (on October 6). Also last week, TransCanada/Columbia Gas Transmission was given the nod for partial service on both its Mountaineer Xpress and WB Xpress projects. Then there’s Energy Transfer’s Rover Pipeline, which is awaiting approval for its final two laterals. Combined, these projects are poised to add more than 4.0 Bcf/d of Marcellus/Utica takeaway capacity before the coldest months of winter arrive. What does that mean for the Northeast gas market this winter? Today, we provide an update on Atlantic Sunrise’s early effects and other upcoming projects completions.
With the addition of new large-diameter natural gas pipelines like Energy Transfer Partners’ Rover Pipeline and Enbridge and DTE’s NEXUS Gas Transmission, the dog days of severely depressed gas prices in the U.S. Northeast will be diminishing (though not disappearing entirely), but they are just getting started for its downstream markets. After years of constrained natural gas supply growth, Northeast takeaway capacity appears to be outpacing regional production volumes more and more, and RBN’s analysis of production economics suggests that, left unconstrained, the Marcellus/Utica gas market is set to unleash an incremental 8 Bcf/d into the broader U.S. gas market by 2023, with the bulk of that volume targeting consumption in the Midwest and Gulf Coast regions. In today’s blog, we walk through our outlook for Northeast takeaway capacity and gas production, and by extension, U.S. gas supply.
It’s crunch time in the race to advance the next-round of liquefaction/LNG export projects along the U.S. Gulf Coast to a Final Investment Decision (FID). And if we’re to assume that only a small number of these multibillion-dollar projects will get their financial go-aheads, it would seem eminently reasonable to put a win-place-or-show bet on a joint venture that includes the world’s leading LNG producer (by far) and one of the largest U.S. natural gas producers — oh, and the partners have very fat wallets too. Size and money aren’t everything, of course, but as we discuss in today’s blog, the team behind the Golden Pass LNG project plans to build its liquefaction trains at the site of an existing LNG import terminal with strong interconnections with coastal pipelines already in place.
Florida’s electric utilities are turning to natural gas-fired power and renewables for all their incremental generation needs and as replacements for the older coal units they’ve been retiring. The state’s big bet on natural gas has been spurring the development of new pipelines. And, because of big shifts in where gas is being produced and where it’s flowing, the Sunshine State will soon be receiving an increasing share of its gas needs from the Marcellus region. Today, we discuss the slew of new gas-fired power plants that have come online, the additional plants planned, and gas flows on Sabal Trail, the first new gas mainline into the state in almost two decades.
U.S. LNG exports have climbed from zero three years ago to more than 3 Bcf/d now, and export capacity is set to grow to more than 10 Bcf/d by 2023. With the U.S. emerging as a dominant player in the global LNG landscape, international players are now increasingly susceptible to the day-to-day fluctuations of the U.S. natural gas market — a highly liquid, fungible and interconnected arena that’s propelled by constantly shifting transportation economics. The global LNG market inevitably is also moving toward spot-oriented trading based on short-term economic conditions. Thus, prospective buyers of U.S. LNG considering pre-FID projects increasingly need to understand the ever-changing U.S. gas flow and pricing dynamics. At the same time, U.S. market participants trying to understand how 10 Bcf/d of LNG exports will affect the domestic market also will need to closely track LNG activity, including feedgas flows and prices. In today’s blog — which launches our new LNG Voyager service — we look at how U.S. onshore gas market dynamics are affecting gas supply costs at the Sabine Pass LNG facility, and considers what this might mean for several of the pre-FID projects.
For the first time in five years, takeaway expansions are outpacing Northeast production growth. Major natural gas takeaway capacity additions on large-diameter pipes like Tallgrass Energy’s Rockies Express Pipeline and Energy Transfer Partners’ Rover Pipeline over the past couple of years are allowing Marcellus/Utica natural gas producers to send record amounts of gas supply to the Midwest and, indirectly, to the Gulf Coast region. At the same time, there are some small pockets of unused takeaway capacity appearing on some of the legacy routes out of the region, which means that Appalachian basis levels — prices relative to Henry Hub — have risen to the strongest levels since 2013. For downstream markets like Chicago and Dawn, ON, that’s meant a flood of gas and lower prices. In today’s blog, we continue our series on the Northeast gas market with the effects of these new dynamics on gas price relationships.
It’s no secret by now that Permian natural gas pipelines have been running near full the last few months, jam-packed like Southern California traffic while trying to whisk away copious volumes of mostly associated natural gas to markets north, south, west and east of the basin. Despite every major artery running near capacity this summer, Permian prices had so far managed to avoid falling below the dreaded $1.00/MMBtu threshold, a precipice that historically defines a gas producing basin as definitively oversupplied. That all changed yesterday, as word came in that Southern California Gas Company, one of the largest recipients of Permian gas, has nearly filled its gas storage caverns and will soon need far less gas hitting its borders. That’s particularly bad news for the Permian, which has few other options if it needs to reduce the supply that is currently flowing west out of the basin to California. A large unplanned outage for maintenance was also announced on one of the pipelines leaving the Permian and heading north to the Midcontinent. As a result, the SoCalGas news and maintenance combined to put a huge dent in Permian gas prices, some of which plunged as low as 50 cents in Wednesday’s trading. Today, we detail this most recent development and the implications for Permian gas takeaway.
For the first time in years, natural gas takeaway capacity constraints from the Marcellus/Utica producing region appear to be easing, even as production volumes from the area continue to record new highs. That’s allowed regional supply prices this year to strengthen dramatically relative to national benchmark Henry Hub. A closer look at pipeline flow data indicates these developments stem from shifting gas flows that coincide with the ramp-up of Energy Transfer Partners’ Rover Pipeline. In today’s blog, we continue our update of the Northeast gas market with the latest on Rover’s gas receipts, along with its effects on other regional takeaway capacity and price relationships.
Each of the “second wave” liquefaction/LNG export projects along the U.S. Gulf Coast now closing in on a Final Investment Decision (FID) believes it has an edge — that special something that will enable it to cross the finish line ahead of its competitors. Things like a prime location, access to an existing network of natural gas pipelines, lower capital costs, or going with smaller “midscale” liquefaction trains instead of traditional big ones. Some tout the experience and depth of their executive teams, while others claim that thinking outside the box is key. Time will soon tell which two or three (or four) projects advance to FID. Today, we continue our series on the next round of liquefaction/LNG export terminals “coming up” with a look at NextDecade’s plan for the Rio Grande LNG project in Brownsville, TX, which would export large volumes of Permian and Eagle Ford gas.
The Marcellus/Utica region is in the midst of a major turning point. Natural gas production from the region continues to post record highs. But regional basis differentials to Henry Hub are the strongest they’ve been at this time of year since 2013. Spot prices at Dominion South — the representative location for the overall Marcellus-Utica supply — averaged at a $0.35/MMBtu discount to Henry Hub this August, compared with a $1-plus discount to Henry in each of the past four years. The deep discounts in previous years reflected the inadequate takeaway capacity and the resulting pipeline constraints to get gas out of the region. Now, basis shifts suggest those constraints are easing somewhat — a trend that will redefine pricing relationships across the broader gas market. In today’s blog, we continue a series examining the changing flow and price dynamics in the Northeast gas market.
The race is on to be the first to reach a Final Investment Decision (FID) for the next round of U.S. liquefaction/LNG export terminals along the Gulf Coast. And like the Kentucky Derby, being first — or, at worst, second or third — is a do-or-die proposition, because only a very small number of these projects are likely to line up the multibillion-dollar commitments needed to push them over the FID line. The tried-and-true approach of LNG project financing has been to secure a stack of long-term Sales and Purchase Agreements (SPAs) from international LNG trading companies or huge overseas utilities, and that’s the tack being taken by Venture Global LNG, which is developing two projects near the Louisiana coast that, if built, would consume a total of nearly 4 Bcf/d of U.S. natural gas. Today, we continue our series on the next round of liquefaction/LNG export terminals “coming up” with a look at Venture Global’s Calcasieu Pass and Plaquemines projects.
