Thanks to a warm start to the season and low Asian demand for LNG, Europe has so far been able to stave off a worst-case scenario for natural gas supply this winter. Still, the European market is keeping a keen eye on the years ahead, when the continent will need to rely on new sources of LNG to meet demand and refill inventories with little chance of any Russian gas. The call for more LNG has ushered in a new wave of export-project development, with two U.S. projects reaching a positive final investment decision (FID) this year and LNG offtakers in Europe and elsewhere committing to an incredible 37 MMtpa (4.9 Bcf/d) of long-term contracts from pre-FID sites in North America. This momentum has revived a number of projects from the COVID-induced wasteland, including Sempra’s Port Arthur LNG. In today’s RBN blog, we continue our series on U.S. LNG projects by taking a closer look at Port Arthur, the one most likely to take FID next.
Daily Energy Blog
Natural gas pipeline project permitting sits at the nexus of the debate about the best path toward decarbonization. Industry proponents rightly point out that pipelines can reduce aggregate emissions by displacing much higher burner-tip emissions from coal in power generation. Environmental opposition, though, highlights that a high rate of methane emissions along the gas value chain could undermine those potential improvements. In today’s RBN blog, we consider the net decarbonization impact of new gas pipelines, including the importance of quantifying upstream methane emissions, by looking at a couple of canceled or long-delayed pipeline projects that could make a big difference.
Last week, even as natural gas day-ahead prices went negative in the Permian’s Waha Hub in West Texas, spot prices at northern California’s PG&E Citygate last week traded at a record-smashing $55/MMBtu, according to the NGI Daily Gas Price Index — close to 100x the Waha price. Other hubs west of the Continental Divide also surged to record levels, while markets just east and north of there were largely unruffled — a sure sign of bottlenecks for moving gas into West Coast markets. This is just the latest instance of severe gas supply shortages and constraint-driven price disruptions out West in recent years (even ignoring Winter Storm Uri and the Deep Freeze of February 2021). Moreover, it’s arguably taking progressively more benign market events to trigger similar or worse shortages. What’s going on? In today’s RBN blog, we break down the factors driving the latest Western U.S. gas price spikes.
The first wave of Gulf Coast liquefaction and LNG export facilities was well-timed, coming as it did with fast-rising natural gas supplies in the Lower 48 and a slew of pipeline reversals and expansions that enabled billions of cubic feet a day of low-cost Marcellus-Utica gas supplies to reach Gulf Coast markets. Permian and Haynesville supplies helped too. The next wave of LNG development, which will kick off in earnest in 2024, may not go quite as smoothly, however. Global demand for LNG is there — there’s little doubt about that. But the next phase of export capacity growth may well be hemmed in by domestic factors, namely the timing and availability of gas supplies to the Gulf Coast due to potentially serious midstream constraints. In today’s RBN blog, we look at where the feedgas supply is likely to come from and what that will mean for pricing dynamics.
Despite many challenges, natural gas production in Western Canada has been hitting record highs this year, powered by what seems to be the inexhaustible energy of the unconventional Montney formation. This immense resource remains the primary focus of most Canadian gas producers, and those that operate in the British Columbia portion of the Montney know they have their work cut out for them in the next few years if they are to meet the growing need for gas, especially when the LNG Canada export terminal comes online mid-decade. In today’s RBN blog, we update the Montney’s production and productivity trends in British Columbia and evaluate whether enough progress is being made.
The need for more LNG export capacity, driven both by Europe’s push to wean itself off Russian gas and long-term Asian demand growth, is resulting in a new wave of development. Two major U.S. projects have reached a positive final investment decision (FID) in the past six months and more are likely to do so soon, both in the U.S. and elsewhere. But conventional export terminals take time to build, leading at least some, like New Fortress Energy, to explore the potential for floating LNG (FLNG) facilities — basically, an LNG export terminal located on the topside of a large tanker — which can bring new capacity online faster, much like the floating storage and regasification units (FSRUs) that are now boosting European import capacity. In today’s RBN blog, we take a look at FLNGs, what’s already out there, and what could be coming to North America in the next few years.
The energy landscape in Texas has undergone significant changes in the two years since the calamitous events of Winter Storm Uri in February 2021. The extreme weather wreaked havoc on the state’s electric generation and natural gas systems, and subsequent investigations resulted in two reform bills — Senate Bill 2 and Senate Bill 3 — aimed at installing new leadership at the Electric Reliability Council of Texas (ERCOT), the electric grid operator, and requiring state regulators to develop rules and standards to address the points of failure in electricity and natural gas infrastructure and operations. Since the bills were signed into law in June 2021, oil-and-gas, electric-grid and utility monitors have adopted a number of requirements, some more prescriptive than others. In today’s RBN blog, we highlight what has changed and where there are still potential gaps.
For decades, gas-gathering pipelines located in rural areas largely escaped the federal scrutiny that was primarily focused on transmission pipelines. But all that has changed with final publication of the so-called Mega Rule, which applies federal pipeline safety regulations to hundreds of thousands of miles of gas-gathering pipelines — previously not subject to federal safety regulation — for the first time. In today’s RBN blog, we look at the history behind the three-part Mega Rule, what it’s designed to do, and the challenges pipeline operators will face to stay in compliance.
The crude-oil-driven Permian has been a hotbed of midstream development in recent years and that’s unlikely to change anytime soon. RBN estimates Permian gross gas production surpassed 22 Bcf/d last month and projects that, if unconstrained by infrastructure, it would grow by another 4 Bcf/d or so over the next couple of years. One determinant of that rate of growth is adequate capacity to process gross gas volumes. In today’s RBN blog, we conclude this series with an assessment of the timing of processing capacity additions in the basin vs. RBN’s Mid-case gross gas production forecast.
A simple problem can be solved with a simple solution, but more complex problems require a more nuanced approach, often using a combination of strategies. That’s the case with plans to mitigate methane emissions, which are not only potent and prevalent, but notoriously hard to quantify, with little common ground among industry, the government and the public about what steps should be taken next. In today’s RBN blog we look at the different approaches the U.S. is taking to regulate methane emissions and address other clean-energy priorities.
The European gas year commenced October 1 with expectations of high winter demand and commensurate gas and LNG prices. However, in recent days the press — both trade and mainstream — have remarked on the number of laden LNG carriers that have been circling, anchored or drifting around the Mediterranean and East Atlantic. This flotilla, currently numbering about 30 cargoes, or 2.1 million metric tons (MMt) of LNG, has been growing since late September and includes some cargoes that have been at sea for over a month. Although floating storage ahead of winter demand is nothing new, the scale of the current phenomenon is unprecedented. In today’s RBN blog, we explore the implications for European gas pricing and market dynamics.
Without a doubt, the two biggest changes to U.S. natural gas markets in the last 15 years have been the Shale Revolution and the development of LNG exports. These completely upended the way gas flowed in this country, with the Northeast now home to the largest gas-producing basin and the Gulf Coast — including its fleet of LNG export terminals — now the U.S.’s largest demand center. Production growth in the Marcellus/Utica has stalled, however, largely due to the regulatory and legal challenges associated with building new pipeline takeaway capacity. One possible fix would be a new East Coast LNG terminal, which in addition to having easy access to cheap, almost-local gas would also be close to gas-hungry European markets. But just how likely is such a project? In today’s RBN blog, we discuss the advantages and hurdles of developing LNG export capacity on the East Coast.
Permian crude oil production has climbed ~30% since the lows of 2020 to about 5.2 MMb/d this summer and helped keep crude oil — and gasoline — prices in check as market balances tightened. With that has come a lot of gross gas, which surged by over 40% to 21.3 Bcf/d on average this summer, up from the 2020 low of just under 15 Bcf/d. If unconstrained by infrastructure, RBN expects that to grow another 30%, or more than 6 Bcf/d, in the next three years, but only if there is adequate midstream capacity — everything from gathering lines to processing plants and, ultimately, gas and liquids transportation lines to deliver the products to consuming markets on the Gulf Coast. While there’s been a significant midstream build-out over the past two years, and more expansions are in the works, there are major outstanding questions about whether it will get built in time and in the right places to prevent prolonged bottlenecks. In today’s RBN blog, we continue our series focusing this time on upcoming expansions and how total processing capacity stacks up against RBN’s Mid-Case production outlook over the next several years.
After the catastrophic experience of Winter Storm Uri in February 2021, the Electric Reliability Council of Texas was restructured, with new statutory requirements and a whole new cast of characters. The Texas Railroad Commission (TRRC) put in place a number of fixes, including more stringent reliability rules for natural gas suppliers, from producers to transmission pipelines. At the same time, booming LNG exports, largely to Europe, combined with growth in Permian production have created new pressures and opportunities around the Texas energy mix — as well as implications for the ongoing transition to low- or no-carbon energy sources. How can all of these issues be understood and addressed at once — and in a way that doesn’t bore us all to tears? In today’s RBN blog, we outline the major themes to be discussed during the Texas Energy Symposium being planned by the Energy Bar Association and the University of Texas Law School.
When it comes to U.S. crude oil plays, no basin has been more resilient than the Permian post-2020, and by extension, no basin has played a bigger role in taming oil prices — and regional natural gas prices — in recent months. While crude production in most other oil-focused basins is flat-to-lower on average since 2020, Permian crude output has climbed 15% in that time, from about 4.5 MMb/d in 2020 to just over 5.1 MMb/d this year to date, with much of that growth occurring in the past year or so. You could say Permian crude saved the day — at least for a time. However, that growth could not have happened without a significant build-out of natural gas midstream infrastructure. And a lot more of it will be needed if Permian crude production is to continue growing and keep U.S. crude oil prices in check. In today’s RBN blog, we provide an update on gas processing capacity in the Permian.
