Natural gas producers in Western Canada, with their share of U.S. and Eastern Canadian markets threatened by competition from producers in the Marcellus/Utica and other shale plays south of the international border, for years have seen prospective LNG exports to Asian markets as a panacea. But efforts to develop liquefaction “trains” and export terminals in British Columbia failed to advance earlier this decade — for starters, their economics weren’t nearly as favorable as those for U.S. projects like Sabine Pass LNG. Then, by 2016-17, global markets were awash in LNG as new Australian and U.S. liquefaction trains came online, and the BC LNG projects still alive were either delayed further or scrapped. Now, with LNG demand on the upswing and the need for additional LNG capacity in the early-to-mid 2020s apparent, the co-developers of LNG Canada — Shell, PetroChina, Korea Gas and Mitsubishi — have attracted a new and significant investor: Petronas, Malaysia’s state-owned oil and gas company and owner of Progress Energy Canada, which has vast gas reserves in Western Canada. Today, we continue our review of efforts to send natural gas and crude oil to Asian markets with a fresh look at the LNG project and TransCanada’s planned Coastal GasLink pipeline, which will deliver gas to it.
Three years ago, U.S. Lower-48 LNG exports were zero. Today that number is above 3.0 Bcf/d. Three years from now, U.S. exports will make up about 20% of the global LNG trade. Perhaps even more momentous, LNG exports will equal 10% of U.S. gas demand. That’s more than deliveries to the entire residential and commercial market sectors during the six summer/shoulder months each year. All of which means that U.S. LNG exports are quickly becoming a much more important factor in both domestic and international markets. The U.S. gas market is no longer an island. In fact, the long-awaited integration of the U.S. into global gas markets is upon us, with significant implications for infrastructure utilization, trade flows and of course, price. To make sense of these new market realities, it is necessary to assess the gas value chain from U.S. wellhead to global destination — in effect, to follow the molecule from the point of production, through pipeline transportation to liquefaction and export, and from the dock to destination markets. That’s exactly what we will do in the blog series we are kicking off today.
Gas producers in the Permian are facing the prospect of severe transportation constraints over the next year or so before additional gas takeaway capacity comes online. Left unchecked, continued production growth could send gas at Waha spiraling to devastatingly low prices for producers. However, there are a number of ways producers and other industry stakeholders could mitigate the growing supply congestion in West Texas, at least in part, and possibly dodge the proverbial bullet. The longer-term solution will come in the form of new pipeline capacity, which will shift vast amounts of Permian gas east to the Gulf Coast and potentially create a new problem — supply congestion and price weakness along the Gulf Coast, at least until sufficient export capacity is built there to absorb the excess gas. Today, we wrap up our Permian gas blog series, with our analysis of how these events will unfold, including an outlook for Waha basis.
The new, larger locks along the Panama Canal have been in operation for almost two years now, enabling the passage of larger vessels between the Atlantic and the Pacific. The timing couldn’t have been better — when the expanded canal locks came online in June 2016, exports of U.S. LPG, crude oil, gasoline and diesel were about to take off, and Cheniere Energy had only recently started shipping out LNG from its Sabine Pass export terminal in Louisiana, with Asian markets in its sights. Hydrocarbon-related transits through the canal soared through the second half of 2016, in 2017 and so far in 2018. But the gains are mostly tied to LPG and LNG — even the expanded canal isn’t big enough for the Very Large Crude Carriers (VLCCs) favored for Gulf Coast-to-Asia crude shipments, or for fully laden Suezmax-class vessels. And there already are indications that the canal’s capacity may not be sufficient to meet future LNG needs. Today, we consider the expanded canal’s current and future role in facilitating U.S. hydrocarbon exports.
Imported liquefied natural gas from the U.S. is helping Mexico address major challenges facing its gas sector. For one, LNG shipments from the Sabine Pass export terminal in Louisiana to Mexico’s three LNG import facilities have been filling a gas-supply gap created by delays in the country’s build-out of new pipelines to receive gas from the Permian, the Eagle Ford and other U.S. sources. Imported LNG also is playing — and will continue to play — a key role in balancing daily gas needs within Mexico, which has virtually no gas storage capacity but is planning to develop some. Today, we consider recent developments in gas pipeline capacity, gas supply, LNG imports and gas storage south of the border.
This past winter’s gas price spikes shined a bright light on the changing dynamics driving Eastern U.S. natural gas markets, especially the growth in gas-fired generation that is contributing to more frequent — and more severe — spikes in gas prices in the region on very cold days. There are other changes too. For one, gas is increasingly flowing from the Northeast to the Southeast as prodigious Marcellus/Utica production growth is pulled into higher-priced, higher-demand growth markets. In today’s blog, we conclude our series on ever-morphing gas markets on the U.S.’s “Right Coast” by examining how gas pipeline flows back East have changed on days besides the winter peaks, how much demand could be unlocked by forthcoming pipeline projects, and what that new demand will mean for flow and price patterns.
The worst of this winter’s cold has passed, but the impact of structural changes in U.S. power generation will be felt in natural gas markets for years to come. The generation mix has been changing rapidly in recent years, and the switch from coal to gas is happening at an even faster pace on the East Coast than in the country overall. This switch reflects both coal-plant retirements and ongoing competition between remaining coal plants and gas plants. But low-cost gas supplies in the Marcellus and Utica plays don’t always have ready access to the biggest consuming markets, and this winter, we saw how the increasing call on gas for Eastern power generation can stress the gas pipeline grid and cause price blowouts. Today, we continue a series on Eastern power generation and prices by untangling the sources and drivers of gas-fired generation growth in the region.
After a three-year hiatus, winter returned to the U.S. natural gas market this year in the form of a “Bomb Cyclone” and more than a week of frigid temperatures. The cold weather pushed Henry Hub prices above $6/MMBtu and East Coast prices higher than $100/MMBtu on some days. This winter, the pain wasn’t just confined to New England. Prices at Williams’ Transcontinental Gas Pipeline (Transco) Zone 5, which includes the Carolinas, Virginia and Maryland, hit all-time highs on January 5. Exports from Dominion’s Cove Point terminal in Maryland are only just getting started so it’s not liquefied natural gas (LNG) exports from the East Coast that are driving prices higher. Instead, it’s gas’s increasing role in winter power generation that has been putting pressure on East Coast gas pipeline deliverability. Today, we begin a series explaining why prices have been so high on very cold days this winter and why more price spikes may be ahead.
The clock is ticking for international shipping companies, cruise lines and others to determine how they will meet the much more stringent standard for bunker fuel sulfur content that will kick in just over two years from now. While many shipowners will likely meet the International Marine Organization’s 0.5% sulfur cap in January 2020 by shifting to low-sulfur marine distillate or a heavy fuel oil/distillate blend, a smaller number are investing in ships fueled by LNG. LNG easily complies with the sulfur cap, and while it costs more than high-sulfur HFO — the bunker that currently dominates world shipping — it is less expensive than the low-sulfur distillate and HFO/distillate blends that will be needed to meet the new standard. But there are catches with LNG, including the need to dedicate more onboard space for fuel tanks and (even more importantly) the lack of LNG fueling infrastructure in a number of ports. Today, we discuss the short and long-term outlook for LNG as a marine fuel.
U.S. trucking companies, trash haulers and transit agencies continue to invest in new vehicles fueled by compressed natural gas or liquefied natural gas, in part to meet corporate or agency carbon-footprint goals. But the economic rationale for switching trucks and buses from diesel to CNG or LNG is weaker than it was a few years ago, when diesel cost two-thirds more than natural gas fuels on a per-BTU basis — prices for diesel, CNG and LNG are now in the same ballpark. Also, developing regional or national networks of CNG/LNG fueling stations doesn’t come cheap. Today, we discuss the growing use of natural gas in trucks and buses — and threats to that trend.
With Lower-48 natural gas production at record highs and averaging more than 5.0 Bcf/d higher than this time last year, LNG export demand will be all the more critical this winter and the rest of 2018 in order to balance the U.S. gas market. Deliveries to Cheniere Energy’s Sabine Pass LNG facility (SPL) are above 3.0 Bcf/d. Dominion Energy’s Cove Point LNG is due to add nearly 0.8 Bcf/d of export capacity and begin exporting commissioning cargoes any day now. Two other projects — Elba Island LNG and Freeport LNG — are due online before the end of 2018, while another high-capacity project, Cameron LNG, faces delays. These facilities will increase baseload demand for gas in the new year, but will it be enough, and how will it impact gas pipeline flows upstream? Today, we provide an update on the timing and potential impacts of new export LNG capacity over the next year.
Mexico’s natural gas supply situation is in a state of flux, to say the least. Gas production within Mexico continues to decline, but there’s hope it can rebound in the country’s Burgos Shale region. Gas demand is rising fast, and new gas pipelines are being built to deliver Permian and other U.S. gas to new Mexican power plants. At the same time, though, delays in completing some of these new pipes have forced Mexico’s electricity authority to turn to LNG imports to keep gas supply and demand in balance. And yet, plans are afoot to export LNG to Asia from Mexico’s west coast by the early 2020s — gas that, by the way, would initially originate in Texas. Today, we explore recent developments in the Mexican gas arena.
Energy Transfer Partners Rover Pipeline’s Mainline A first began flowing natural gas west from the Marcellus/Utica on September 1, and volumes are now averaging about 1.0 Bcf/d. The bulk of that is being delivered into TransCanada’s ANR Pipeline and, pipeline flow data shows some of that, either directly or indirectly, is making it all the way south to the Gulf Coast, specifically toward Cheniere Energy’s Sabine Pass LNG liquefaction and export facility (SPL). Deliveries to the facility have climbed to nearly 3.0 Bcf/d in recent weeks as the fourth liquefaction train was brought online. Along the way, the Rover-ANR combo is increasing competition with other pipes that feed ANR, including other Marcellus/Utica takeaway pipelines such as REX and Dominion. Today, we look at how Rover has changed flow patterns for gas targeting Gulf Coast demand.
Cheniere Energy’s Sabine Pass LNG liquefaction and export facility in Louisiana last week received federal approval to begin operating its fourth 650-MMcf/d liquefaction train, bringing the total export capacity at the terminal to 2.6 Bcf/d. Natural gas supply delivered to the terminal for export has averaged 2.0 Bcf/d in recent months, with flows jumping as high as 2.9 Bcf/d on some days last month as the operator readied Train 4 for operations. There are several supply regions targeting this new demand, including the fastest growing producing region, the Marcellus/Utica Shale in the U.S. Northeast. While there isn’t yet a direct beeline from the Marcellus/Utica to Sabine Pass, there are early indications that recent pipeline takeaway and reversal projects from the producing region and the resulting connectivity are indirectly bridging the divide. In today’s blog, we examine pipeline flow data to understand recent changes in flows and what they can tell us about future flow patterns as export demand continues to grow.
Natural gas deliveries for export via Cheniere Energy’s Sabine Pass LNG terminal in Louisiana reached a record in late July, topping 2.5 Bcf/d. In the first seven months of 2017, exports have added an average of 1.5 Bcf/d — or more than 300 Bcf total — of baseload gas demand year on year. Thus far, the terminal has been operating with three liquefaction trains. Now the fourth train, which would bring on another 650-MMcf/d of potential export demand, is nearing completion. The incremental gas deliveries are scheduled to come just as winter heating season is kicking off and likely will tighten the gas market. Today, we look at the latest developments at the terminal.