In the three years since the deadly electrical outages caused by Winter Storm Uri, the Texas Legislature, the Public Utility Commission of Texas (PUCT), and the Electric Reliability Council of Texas (ERCOT) have been working overtime to design and implement changes to ensure a more reliable Texas power grid. But it hasn’t been easy. The state’s energy-only electricity market and its outsized reliance on intermittently available wind and solar power have forced policymakers, regulators and the electric-grid operator to develop a wide range of fixes aimed at maintaining a competitive atmosphere while at the same time incentivizing market players to have power available when it’s needed most. In today’s RBN blog, we look at what they’ve been up to.
Daily Energy Blog
Mexico’s state-owned Comisión Federal de Electricidad (CFE) and private-sector developers of LNG export terminals have been aggressively advancing new natural gas-consuming projects in Northwest Mexico. But while plans for a number of new pipelines to help bring in gas from the Permian are on the drawing board, it remains to be seen if they can be built as quickly as they would need to be to avert a potentially ugly competition for gas supplies. In today’s RBN blog, we discuss the gas-demand and gas-delivery projects now under development in Northwest Mexico.
The Energy Information Administration (EIA) recently changed the weather forecast methodology for one of its most important energy models — the Short-Term Energy Outlook (STEO) — and while we talk about the effects of weather on energy markets fairly often (571 times in the past 12 years, or about once a week, but who’s counting?), we rarely take a step back and explain how those weather forecasts are used. In today’s RBN blog, we look at different approaches to weather forecasting, the recent change made by the EIA, and how the new approach might affect our understanding of EIA forecasts.
Faced with sustained sub-$2/MMBtu natural gas prices and dim prospects for significant gas-demand growth until sometime next year, a number of major gas-focused E&Ps have been tapping the brakes on production and trimming their planned 2024 capex. But one company — Chesapeake Energy, slated to become the U.S.’s largest gas producer thanks to a recently announced acquisition — has taken a more dramatic step, implementing a novel strategy that will slash production by 25% but leave the E&P ready to quickly ramp up its output as soon as demand and prices warrant. In today’s RBN blog, we’ll review the 2024 guidance of the major U.S. gas producers and delve into the analysis of Chesapeake’s unusual approach.
It’s been a devastating few weeks for the natural gas market. Sure, Shale Era abundance was supposed to keep gas prices from skyrocketing — and it generally has. But seriously? Henry Hub gas sinking below $2/MMBtu — and staying there, in the depths of the winter heating season? Prices have stabilized a little in recent days as a few E&Ps announced cutbacks in capex and gas-focused drilling, but gas-storage levels are abnormally high, coal-plant retirements have trimmed opportunities for coal-to-gas switching, and any significant gains in LNG exports aren’t going to happen until this time next year. With all that, you’ve gotta ask — as we do in today’s RBN blog — how low could natural gas prices go?
Natural gas prices remain at near-record lows, but with so much production being driven by still-favorable crude oil economics there’s a distinct possibility — especially given the warm winter we’re in — that gas inventories may test storage capacity this year, perhaps as early as Labor Day. Of course, there are many market factors that might prevent this outcome, including lower production, a scorching-hot summer, and gas-to-coal fuel switching. But it could happen. And whenever we approach the limitations of natural gas infrastructure, we’ve seen time and again the disruptions and dislocations the market must deal with. The most obvious market signals are prices. But when it comes to gas flows another important barometer is the use of operational flow orders (OFOs). In today’s blog, we update one of RBN’s Greatest Hits and take a deep dive into the world of OFOs and what they can reveal about the state of the gas market.
Observers of the natural gas market over the past 20 years know that the main story has been one of enormous growth. The Shale Revolution gave new life to the U.S. natural gas sector, leading to the record production levels we are seeing in early 2024. The economy has found many uses for this new gas: increased power generation, more pipeline exports to Mexico, expanded industrial gas usage and — most prominently — the many LNG export facilities that have cropped up since 2016. But with the pause on new LNG export licenses and the push to renewables in the power sector, there’s a looming question of where the new natural gas would go if production continues to expand. In today’s RBN blog, we look at how that new gas might be absorbed, both domestically and internationally, and what continued growth would imply for gas prices and producers in the long term.
As mightily as U.S. LNG exports have impacted global trade dynamics, so have U.S. natural gas flows been reshaped by the pull toward Gulf Coast export terminals. The next new terminal on deck is Venture Global’s enormous Plaquemines facility in Louisiana, which could begin taking feedgas as early as late fall 2024 and will eventually ramp up to more than 2.6 Bcf/d. For Southeast Louisiana, home to a massive industrial corridor along the Mississippi River as well as the U.S. natural gas benchmark Henry Hub, the introduction of such a huge source of demand will change how gas flows into and out of the region — with knock-on effects across the Gulf Coast. In today’s RBN blog, we’ll turn once again to our Arrow Model to help illuminate what the path forward may look like.
Big changes are coming to the new epicenter of the global LNG market: Texas and Louisiana. On top of the existing 12.5 Bcf/d of LNG export capacity in the two states, another 11+ Bcf/d of additional capacity is planned by 2028. The good news is that the two major supply basins that will feed this LNG demand — the Permian and the Haynesville — will be growing, but unfortunately not quite as fast as LNG exports beyond 2024. And there’s another complication, namely that the two basins are hundreds of miles from the coastal LNG terminals, meaning that we’ll need to see lots of incremental pipeline capacity developed to move gas to the water.
The Biden administration’s recently announced decision to pause further action on new LNG export permits for at least several months sent shockwaves through the industry and shook up expectations regarding which projects will be hurt by — or benefit from — the pause. As we’ll discuss in today’s RBN blog, the decision is likely to put a number of Gulf Coast LNG export projects (one of them a real giant) in limbo, set back a Mexican project that would depend on Permian and Eagle Ford gas, and boost a couple of projects up in Canada. Oh, and there’s this: The pause also may help two avowed enemies of the U.S.: Russia and Iran.
Since the mid-2010s, Mexico’s Comisión Federal de Electricidad (CFE) has developed a massive fleet of natural-gas-fired combined-cycle plants and helped to underwrite the buildout of a far-reaching network of gas pipelines from South Texas and West Texas into and through much of Mexico. Now, there’s a big push to extend that network southeast through the Yucatán Peninsula to serve new power plants and industrial facilities there. The question is, with the vast majority of the pipeline capacity down Mexico’s East Coast already locked up, where will the Yucatán’s incremental gas come from? In today’s RBN blog, we discuss this potential disconnect between Mexico’s gas-related aspirations and reality.
So far this winter, front-month CME/NYMEX natural gas futures have fallen, risen and fallen again but, until their most recent dip, generally remained within the same $2.30-to-$3.30/MMBtu range where they have been lingering since mid-2023. With production sustaining near-record levels, LNG export volumes down from the winter highs, and temperatures back to normal, the supply of gas remains plentiful — a bearish scenario. In today’s RBN blog, we look at why there’s been a lid on natural gas prices — and the odds that the situation might change before the rapidly-approaching end of the winter season.
Natural gas storage — especially well-sited storage with lightning-fast deliverability rates — is taking on a new significance (and value) as LNG export facilities and power generators seek to manage their often-volatile gas demand. But developing new gas storage capacity is costly and, with only a few exceptions, it’s hard to make an economic case for greenfield projects. That reality has spurred a lot of interest among midstream companies in acquiring existing storage assets and, where feasible, expanding that storage. In today’s RBN blog, we discuss one of the biggest storage-acquisition deals to date: Williams Companies’ recent purchase of six facilities with a combined working gas capacity of 115 Bcf in Louisiana and Mississippi. (It’s not all that Williams has been up to on the gas-storage front.)
There’s no doubt about it: The Biden administration’s decision to pause approval of LNG export licenses poses a new threat to a number of projects thought to be nearing a final investment decision (FID). The questions brought on by the move are profound: how big of a problem is this for U.S. developers, how does the timeout affect the projects now in limbo, and — over the longer term — what does the added uncertainty regarding incremental LNG exports mean for U.S. crude oil and natural gas production and what does it mean for the global energy landscape? In today’s RBN blog, we discuss the factors that led to the administration’s announcement — and the case to be made that expanded LNG exports are in the U.S.’s economic and strategic interest.
The current winter heating season in Canada has seen extremes of warmth and cold, but much more of the former than the latter. Given that the Canadian natural gas market was already oversupplied and struggling with record-high gas storage levels as winter approached, even the most intense cold blast in mid-January wasn’t enough to return the supply/demand balance north of the 49th parallel to anything near normal. In today’s RBN blog, we discuss where the Canadian market stands as the calendar turns to February and what that might mean for end-of-winter gas balances.
