It’s so ironic. New England is only a stone’s throw from the burgeoning Marcellus natural gas production area, but pipeline constraints during high-demand periods in the wintertime leave power generators in the six-state region gasping for more gas. Now, with only minimal expansions to New England’s gas pipeline network on the horizon, the region is doubling down on a long-term plan to rely on a combination of gas liquefaction, LNG storage, LNG imports and gas-to-oil fuel switching at dual-fuel power plants to help keep the heat and lights on through those inevitable cold snaps. Today, we discuss recent developments on the gas-supply front in “Patriots Nation.”
Developers are scrambling to advance the next round of liquefaction/LNG export projects, primarily along the U.S. Gulf Coast. Earlier this month, LNG marketing behemoth Total SA signed initial agreements with Sempra Energy that would support Sempra’s efforts to add more liquefaction capacity at its Cameron LNG project in southwestern Louisiana and to build a liquefaction plant at its Energía Costa Azul LNG import terminal in Mexico’s Baja California state. A few days later, Total, Mitsui & Co., and Tokyo Gas signed heads of agreements for the entire capacity of the Mexican liquefaction project, propelling that project to the fore. Sempra also continues to pursue a third project: Port Arthur LNG. Today, we continue our series on the next round of liquefaction/LNG export terminals “coming up” with a look at Phase 2 of Cameron LNG, as well as Energía Costa Azul and Port Arthur LNG.
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.
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.
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.
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 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.
With global demand for LNG rising and U.S. natural gas producers needing markets for their burgeoning output, it’s not a question of whether another round of U.S. liquefaction/LNG export facilities will be built, but which developer will be first and when it will make its final investment decision (FID). Odds are that the initial FID for this “next round” of projects is only months away, but as for the specific developer and project that will lead the pack, that has yet to be determined. We do know, however, that a handful of projects appear to be making real progress, and today we consider one of them: Tellurian’s Driftwood LNG project near Lake Charles, LA.
Federal regulators are preparing to accelerate their review of a wave of applications to build new liquefaction plants and LNG export terminals — most of them sited along the Gulf Coast and scheduled for commercial start-up in the early 2020s. Only a few of the multibillion-dollar projects are likely to advance to final investment decisions (FID), construction and operation, but even they will have profound impacts on U.S. natural gas production, pipeline flows, and the global LNG market. Today, we begin a look at projects still awaiting FIDs, their developers’ efforts to line up Sales and Purchase Agreements (SPAs), and the Federal Energy Regulatory Commission’s (FERC) push to review project applications in a timely manner. Warning: this blog includes a few ever-so-subtle promotions for RBN’s new LNG Voyager Report.
Everyone in the North American gas industry knows that a big wave of U.S. LNG exports is coming. Although Cheniere Energy’s Sabine Pass terminal in southwestern Louisiana started shipping out LNG in 2016, exports really started having a major impact in 2017 — increasing demand for U.S.-produced gas, providing an outlet for Marcellus and Utica supplies, and affecting physical flows at the Henry Hub and in south Louisiana more generally. But with the first four liquefaction trains at Sabine Pass all but fully ramped up, attention in recent months has been turning to the next facility being commissioned: Dominion’s Cove Point terminal on Chesapeake Bay in Maryland, which exported its first cargo in early March. But tracking gas pipeline flows into the Cove Point plant has not been easy, and in today’s blog, we consider the various possibilities and discuss our view of how best to monitor the amount of LNG feedgas going into Cove Point.
Growth in LNG supply and demand, the ongoing restructuring of the LNG sector and other factors are giving new significance to the nearly 500 specialized, oceangoing vessels that transport the supercooled, liquefied natural gas around the world. It used to be that the vast majority of LNG was delivered in milk run-like fashion under long-term contracts between suppliers and buyers, but that’s no longer the case. Now, the LNG market is much less structured and more fluid, with spot-market sales becoming more common and with the captains of some LNG-laden vessels not sure where they will end up as they head out of port. Today we describe the ins and outs of the shipping sector that moves hundreds of millions of metric tons of LNG annually.
The international spot price for liquefied natural gas (LNG) has been steady-as-she-goes the past few months, within a few dimes of $5.50/MMBtu, but that stability belies the upheavals the LNG industry continues to experience. The old paradigm of long-term contracts and milk-run deliveries from supplier to buyer is breaking down. New Australian and U.S. liquefaction capacity is coming online fast and furious, exacerbating the global LNG supply glut, and Qatar — the world’s largest LNG supplier, just announced plans to increase its output by 30%. With LNG readily available and priced to sell, new LNG buyers are entering the fray, developing natural gas-fired power plants that will be fueled by imported LNG. What does all this mean for the next wave of U.S. liquefaction projects and for natural gas producers in the Marcellus/Utica and the Permian? Today we continue our look at the topsy-turvy LNG sector.
In only three years, the international liquefied natural gas (LNG) market has undergone a major transformation. The old order, founded on long-term, bilateral contracts with LNG prices linked to crude oil prices, is being replaced by a more-fluid, more-competitive paradigm. That’s good news for LNG buyers, who are benefiting from a supply glut and lower LNG prices—the twin results of slower-than-expected demand growth in 2014-15 and the addition of several new liquefaction/LNG export facilities in Australia and the U.S. But the new paradigm poses a challenge for facility developers: How do they line up commitments for new liquefaction/LNG export capacity that will be needed a few years from now in a market characterized by LNG oversupply and rock-bottom prices? Today we begin a two-part series that considers the hurdles developers face and which types of projects may have the best prospects.
Every day, crude oil producers on Alaska’s North Slope re-inject nearly 7.8 Bcf of natural gas into their wells, enough gas to supply the entire U.S. West Coast—California, Oregon and Washington State. If only there were some way to monetize that gas supply, to move it to market. The problem is that there isn’t, at least in today’s gas/LNG market, which is characterized by ample supply and relatively low prices. This same market also favors infrastructure projects that are simple and low-cost; no one wants to make multibillion-dollar commitments when natural gas prices and margins are so low. Today we conclude our series on the tough times ahead for Alaska’s energy sector with a look at the state’s vast natural gas reserves and the challenges associated with tapping them.
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.