The momentum for North American LNG right now is incredible. With Europe’s efforts to wean itself off Russian natural gas supplies boosting long-term LNG demand in the continent and Asian demand expected to grow even further, there has been a strong push for new LNG projects in the U.S., Mexico and Canada, with enough commercial support and capital present to advance at least some of them to construction and operation. Venture Global on May 25 reached a final investment decision on Phase 1 of Plaquemines LNG, the first North American project to take FID since Energía Costa Azul LNG in 2020. But it’s unlikely to be the last. Cheniere’s Corpus Christi Stage III is likely to follow in the coming months and support is coalescing around a handful of other projects too. So far this year, more than 20 MMtpa of long-term, binding commitments tied to new North American LNG capacity have been signed, propelling a new wave of LNG projects towards FID. In today’s RBN blog, we take a look at the trends in the recent commercial commitments.
Daily Energy Blog
Just like there’s room for Amazon and Etsy in the e-commerce world — one for mass marketers and the other for artisans — there’s room in the energy industry for both large- and small-scale LNG companies and plants. By focusing on the development of niche markets and scaling their production and distribution operations accordingly, a number of smaller (but growing) players in the LNG space have been making natural gas available to a surprising variety of customers: from industrial, oil-and-gas and mining companies to rocket launchers, Caribbean resorts and island utilities. ESG is a big driver — the LNG supplied often replaces diesel, fuel oil and propane, which can have bigger carbon impacts. In today’s RBN blog, we continue our series on small-scale LNG with a look at a cross-section of key players in this space and how they’ve been growing their businesses.
Natural gas futures prices have rocketed to 14-year highs in the past couple of months — during the lower-demand spring months, no less — and they are now trading at 3x where they were at this time last year. The CME/NYMEX Henry Hub futures for June delivery shot up to a high of $9.40/MMBtu in intraday trading last Thursday, the highest level we’ve seen since summer 2008, before expiring at $8.908/MMBtu, nearly $6 (~200%) higher than the June 2021 expiration settlement at just under $3/MMBtu. The newly prompt July futures retreated ~17 cents Friday to about $8.73/MMBtu, but that’s still nearly triple where July futures traded last year. It’s safe to say the low fuel cost of gas-fired power generation that defined the Shale Era has evaporated. Historically, at today’s sky-high prices, gas would have given up market share to coal in the power sector. However, the coal market is battling its own supply shortage and Eastern U.S. coal prices are at record highs. What does that mean for generation fuel costs and fuel switching? In today’s RBN blog, we break down the math for comparing gas vs. coal fuel costs.
The race is heating up for building natural gas pipeline takeaway capacity out of the Permian. Associated gas production from the crude-focused basin is at record highs this month and gaining momentum, which means that without additional pipeline capacity, the Permian is headed for serious pipeline constraints — and potentially negative pricing — by late this year or early next, which would, in turn, limit crude oil production growth there. Midstreamers are jockeying for the pole position to move surplus gas from the increasingly constrained basin to LNG export markets along the Gulf Coast. One of the contenders, Matterhorn Express Pipeline (MXP), a joint venture (JV) between WhiteWater, EnLink Midstream Partners, Devon Energy and MPLX, announced its final investment decision (FID) late yesterday. In today’s RBN blog, we provide new details on the greenfield project.
In the nearly 60 years since its inception, the LNG industry has changed significantly. Once a market in which cargoes were sold under long-term, point-to-point contracts in dedicated ships, it has evolved into one in which destination flexibility accounts for an increasing share of LNG trade, with more volumes being sold under short- and medium-term contracts. The changes reflect a trend toward the increasing commoditization of LNG, with the similarities between the LNG and crude oil markets becoming apparent. In today’s RBN blog, we look at the differences in how the oil and LNG markets have developed, whether LNG might achieve the same commodity status as oil, and why the major market players may not want LNG to follow the path of its older cousin.
Production bottlenecks and global energy security concerns stemming from the Ukraine war have flipped the script on various aspects of the U.S. energy markets. One of them is the softening of Wall Street and regulatory resistance to investment in new hydrocarbon infrastructure. That’s been particularly good news for the swarm of LNG export projects looking to move forward. It’s also improved somewhat the prospects for the embattled Mountain Valley Pipeline (MVP), the last major greenfield project for moving natural gas out of the Northeast from the Appalachian Basin. A court vacated three of the project’s key federal authorizations earlier this year, but the project recently got a greenlight when the Federal Regulatory Energy Commission (FERC) approved MVP’s amendment certificate application. Equitrans Midstream said last week that it would pursue new permits and target in-service in the second half of 2023. But the prospect of more legal challenges looms, and the question is, will it get across the finish line before severe constraints arise? In today’s RBN blog, we provide an update on the Appalachian gas market.
A tight coal market and record-high coal prices in the Eastern U.S. have suppressed gas-to-coal switching in recent months, despite the gas market also contending with a supply squeeze and gas prices trading at Shale Era highs. The coal-market constraints have contributed to record, or near-record, gas demand in the power sector, with gas gaining market share of total generation fuel demand — in spite of wind and solar increasing their share of the pie. Generation fuel dynamics were a driving factor in the tighter gas market balances this past winter and also play a role in how power grids balance cost and reliability during times of extreme customer demand, such as the record-breaking heat wave expected to hit Texas in the coming days. In today’s RBN blog, we take a look at power generation fuel economics, particularly the fuel-switching phenomenon and its underlying drivers.
The first Saturday in May is only a couple of days away, so brush off your seersucker jacket or find that Kentucky Derby hat, as it’s the only time of year most Americans watch an actual horse race. That’s kind of how it goes with the Permian natural gas market as well, with only intermittent interest from general gas market participants, usually when there’s a pipeline capacity issue leading to a noticeable impact on prices. Now is one of those times. Permian gas production is racing higher and the pipelines to get gas to market are quickly getting jammed up. Daily prices in the Permian are trading about 10% lower than those in Louisiana and the forward basis markets suggest they will deteriorate further in the months ahead. Naturally, midstream companies are quickly trotting out new pipeline projects, but sorting out the contenders is much like picking the winner on Saturday. You need data and at least a little luck, and we’re here to help out with the former. In today’s RBN blog, we lay out what we know and how we view the Permian gas pipeline derby.
Extreme blizzard conditions wreaked havoc on North Dakota energy infrastructure last weekend, taking offline as much as 60% of the state’s crude oil production and more than 80% of natural gas output, and leaving utility poles and power lines strewn across the landscape. On the gas side, the unprecedented supply loss is having a never-before-seen impact on regional and upstream flows and storage activity. It is also compounding maintenance-related production declines in other basins, leaving Lower 48 natural gas output at its lowest since early February. Moreover, the extent of the storm-related damage to local infrastructure could prolong the supply recovery. In today’s RBN blog, we break down the aftereffects of the offseason winter storm on regional gas market fundamentals.
It’s been more than two months since Russia invaded Ukraine, sending global energy markets into chaos as most of Europe tries to figure out a way to quickly reduce its reliance on Russian supplies. The initial response from the U.S. and its allies was a slate of economic sanctions, but those largely left natural gas out of the equation, as parts of Europe are so dependent on Russian gas that stopping the flows would pose serious threats to the continent’s economies and energy security. Now, with no sign of an end to military hostilities and continual increases in the scope of sanctions, Russia is responding by starting to shut off flows to European countries that refuse to pay for their gas in rubles. Where is this headed? In today’s RBN blog, we look at the latest escalation, what led to this point and where the market might go from here.
In response to Russia’s invasion of Ukraine, Europe is planning massive and rapid changes in its natural gas supply, including a significant increase in LNG deliveries from the U.S. But there are major challenges and implications associated with this shift. For example, how can the U.S. government prod U.S. exporters to send more LNG to Europe? How can LNG buyers — or sellers — collaborate without running afoul of European Union antitrust laws? Can the development of new LNG import terminals be fast-tracked? And can long-term contracts for Russian pipeline gas be breached without penalty now that Russia has suspended deliveries to Poland and Bulgaria for not paying in rubles? In today’s RBN blog, we discuss what U.S. and European efforts need to overcome.
Despite the highest natural gas futures prices in over a decade, its use for power generation in the Lower 48 has set records in recent months. This is in part by design: economics and environmental regulation have broadly favored gas-fired plants and pushed into retirement hundreds of coal-fired plants in the last decade or so, reducing price-driven fuel-switching capabilities between the two fuels. However, there’s more to it than that: a tight coal market, marked by low stockpiles, high export demand and record high prices, is limiting gas-to-coal switching even further, making gas burn for power much more inelastic to price. In today’s RBN blog, we take a closer look at this key intersection of the gas and coal markets.
The U.S. and its European allies have been working on ways to move away from Russian energy supplies after Russia’s invasion of Ukraine, with increased LNG exports to Europe expected to play an important role in that transition. And with global demand for LNG at an all-time high, it has put some important U.S. export projects closer to reaching a final investment decision (FID). But even with U.S. LNG production surging, questions remain about how much more LNG Europe can realistically handle. Warning — today’s RBN blog is an advertorial in which we discuss the highlights from our new Drill Down Report on the global LNG market.
Increasing global LNG supplies has become of paramount importance given Europe’s decision to move away from pipelined imports of Russian natural gas. As such, any and all LNG export projects — from the expansion of existing sites to proposals for greenfield terminals — are getting a fresh look. As always, though, only the projects that make the most economic sense are likely to advance to a final investment decision (FID), construction and operation. Which raises the question, where do things stand with the handful of LNG export terminals proposed for Eastern Canada, which offers the shortest, most direct access to Europe? In today’s RBN blog, we conclude our series on Canada’s LNG export potential by assessing several greenfield export sites on its East Coast.
Massive LNG export terminals and shipments to Europe get all the attention these days, and for good reason. But there’s a lot more going on with U.S. LNG below the radar, and on a much smaller scale. Peak-shaving liquefaction plants to help gas-distribution utilities up north keep the lights on during high winter demand periods. Plants that make LNG for a wide variety of industrial, mining and oil-and-gas-production customers, and for LNG-powered trucks and ships — often to help reduce emissions and meet ESG goals. And there are a number of small liquefaction plants in the U.S. that export LNG to power-generation and industrial customers in the Caribbean and Mexico. In today’s RBN blog, we begin a short series on an often-overlooked but important market for U.S. natural gas.
