Just a few years ago, Mexico was focused on importing LNG to help meet its natural gas needs, especially in parts of the country far from Permian and other U.S. supplies. Lately though, most of the talk about LNG in Mexico has been about liquefaction and/or exporting, not importing and regasifying, as evidenced by a final investment decision on the Energía Costa Azul liquefaction project in Baja California and progress on Mexico Pacific Ltd.’s liquefaction/export project in Mexico’s Sonora state. Both projects are aimed squarely at Asian markets, but yet another prospective LNG project “south of the border” is targeting bunkering, transportation, and industrial markets for natural gas along the Pacific side of Latin America — from Mexico itself down to Ecuador. In today’s blog, we discuss plans for what could be Mexico’s third major liquefaction project — this one aimed at both domestic and export markets.
The gas that emerges from wells in U.S. shale plays differs widely in its characteristics and quality. In the aptly named “dry” Marcellus in northeastern Pennsylvania, the gas is almost all methane, with only minute volumes of NGLs and contaminants, and requires minimal treatment before it’s fed into transmission pipelines. At the other end of the spectrum, the associated gas from a subset of crude-oil-focused wells in the Permian has high levels of hydrogen sulfide (a potentially deadly chemical) and carbon dioxide (a potent greenhouse gas), as well as a lot of NGLs. If the H2S level in the gas is relatively low, it can be removed from the gas stream onsite with a chemical “scavenger,” but higher levels of H2S quickly make that method prohibitively expensive. Another alternative, an onsite amine treatment facility, is more economical for removing higher levels of H2S — and it removes CO2 as well — but air permits typically limit how much can be flared off, requiring the costly and time-consuming development of acid-gas injection wells. Yet another, more centralized approach to dealing with H2S and CO2 — one that permanently stores large volumes of both deep underground — is being implemented over the next few weeks in southeastern New Mexico, as we discuss in today’s blog.
As nobody in Texas will soon forget, in February of this year freezing temperatures across the southern U.S. hammered energy markets and resulted in widespread and long-lasting blackouts across the Energy Reliability Council of Texas (ERCOT) power region. Life for many Texans came to a standstill for a week until power could be restored. The resulting economic damages have been estimated in the billions. Many people, rightfully, questioned how an energy-rich state like Texas could have been so affected. And then the blame-game started. Lacking a forum of qualified experts, productive discussions took a back seat to self-serving rhetoric, special-interest advocacy, and political posturing. But if real solutions were going to be found, it would take more than finger-pointing. It would take a meeting of experts whose primary focus was a resolution, rather than a constituency. Fortunately for Texans, that’s what they got two weeks ago. In today’s blog, we take you through the symposium and its outcome, particularly regarding the role of natural gas.
It’s been a while since the Appalachian natural gas market has looked this bullish. Outright cash prices at the Eastern Gas South hub are at multi-year highs. Regional storage inventories are sitting low, setting the stage for supply shortages and still higher prices this winter. But the potential for severe takeaway constraints and basis meltdowns are lurking, and by next year, they could become regular features of the market again like they were in the 2016-17 timeframe, or worse — at least in the spring and fall when Northeast demand is lowest. Regional gas production is still being affected by maintenance and has been somewhat volatile lately as a result, but it averaged 34.5 Bcf/d in June, just 300 MMcf/d shy of the December 2020 record. What’s more, at current forward curve prices, supply output could surpass previous highs by next spring and grow by ~ 5 Bcf/d (15%) by 2023. Outbound flows set their own record highs this spring, running at over 90% of takeaway capacity, and will head higher, which means that spare exit capacity for supply needing to leave the region is shrinking. The handful of planned takeaway expansions that remain are facing environmental pushback and permitting delays, and the few that are targeting completion in the next year may not be enough. Today, we provide the highlights of the latest forecast from our new NATGAS Appalachia report.
Global gas prices have had a record-breaking year so far, with JKM in Asia hitting all-time seasonal highs in spring, and TTF in Europe last week reaching the highest level since 2008. Prices have been spurred on by a global LNG market that is undersupplied and hunting for additional cargoes. If you were just looking at U.S. feedgas levels over the past several weeks, though, you would never know that we are in the middle of an incredible bull run. U.S. LNG feedgas deliveries have trailed below full-utilization levels for more than a month due to a combination of spring pipeline maintenance, LNG terminal maintenance, and operational issues. The reduced availability of pipeline and liquefaction capacity led feedgas deliveries in June to average 9.35 Bcf/d, or about 85% of full capacity. However, this was just a small and short-lived setback before what is likely to be a breakthrough summer for U.S. LNG. Feedgas demand is already back above 95% utilization and is poised to head even higher over the next few months both from new liquefaction capacity coming online and potentially from spot market cargo production. In today’s blog, we take a look at the impact of spring maintenance on U.S. LNG production and potential feedgas demand growth in the months ahead.
Usually when we write about natural gas markets in the Western third of the U.S., we spotlight the Permian Basin and its Waha gas hub. The focus on Waha has been for good reason, as the last three years have been nothing if not exciting in the Permian’s primary gas market. The basin’s huge volume of associated gas production and Waha’s volatility and deeply negative basis — even negative absolute prices — have made the West Texas market eminently watchable. Though a flurry of new pipelines out of the Permian have helped tame the market somewhat recently and driven Waha to the point of positive basis on its best days, the markets west of the Permian are a different story. They have seen very little in the way of new gas infrastructure, and the constrained inbound pipeline capacity has recently driven prices in the Desert Southwest to some incredible premiums. In today’s blog, we take a look at the gas markets there.
The developers of the embattled PennEast Pipeline project this week caught a big break: over the objections of the state of New Jersey and in contradiction to a prior lower court ruling, the Supreme Court said in a 5-4 decision on Tuesday that the project could exercise eminent domain in order to seize state-owned land necessary for building its 1.1-Bcf/d Appalachia takeaway pipeline. The ruling, while not a slam dunk for the pipeline’s completion, offers a ray of hope to a project that was all but dead for the past couple of years and that many had written off. It also represents an increasingly rare victory for the frequently vilified gas industry in the Northeast. The pipeline represents more capacity and greater optionality for producers in the northeastern Pennsylvania region who currently have limited takeaway options and are facing worsening pipeline constraints even as prices and downstream demand are taking off. Today, we provide an update on the PennEast project and its implications for the Appalachian gas market.
Western Canada’s Montney-sourced natural gas production has been on a remarkable upward trajectory in the past decade. Most of this growth has been focused in one province: British Columbia. However, that progress has not come without difficulty. A key challenge during BC’s gas boom has been providing sufficient pipeline takeaway capacity — the hurdles include the BC Montney’s remoteness, various regulatory impediments, and the unique geologic nature of the play. For this amazing gas supply growth story to continue well into the future, more pipeline capacity needs to be constructed. In our concluding blog on the Montney, we discuss recent pipeline developments and the challenges still ahead.
The immense Montney Formation in Western Canada is almost equally divided between the two provinces of Alberta and British Columbia. However, on either side of the provincial border there are stark differences in the number of wells drilled, well length, well productivity, and natural gas production. All these differences have resulted in Alberta being the much smaller player in the Montney gas story, with production from its side of the formation only helping to hold the line on Alberta’s total gas output in the past few years. Today, we continue our Montney analysis by looking at gas well trends on the Alberta side of this prolific formation.
Appetite for new North American LNG export capacity had been waning already when COVID-19 brought it to a screeching halt. The global gas market was expected to be well-oversupplied through the mid-2020s as U.S. liquefaction capacity additions, combined with supply growth from Australian LNG projects, were far outpacing any increase in demand. However, the past year or so has proven how quickly things can swing from oversupplied to undersupplied. The extended run of high global gas prices is bringing renewed interest in expanding North American LNG export capacity. Although COVID dashed the prospects of many LNG projects, a handful have emerged from the morass of the past year stronger and with a clearer path to FID than ever before. Those that remain will be better positioned if they can navigate four emerging trends that are key for offtaker agreements in the post-COVID era: shorter contract terms, increased pricing or deal-structure diversity, reduced environmental impact, and a prioritization of brownfield expansions or phased greenfield projects. Today, we conclude the series on the status of the second wave of LNG projects.
Of the 10 Bcf/d, or more than 75 MMtpa, of nameplate LNG export capacity currently operational in the Lower 48, Japanese companies form the largest single group lifting U.S. cargoes. Their commitments total ~2 Bcf/d of U.S. liquefaction capacity. However, Japan’s LNG consumption has been falling over the past two years, and in 2019 and 2020, U.S. LNG accounted for only 0.6 Bcf/d and 0.8 Bcf/d of Japanese imports, respectively, or about 20% of the country’s total LNG demand in each year. In other words, Japanese companies have made commitments for incremental LNG from their remotest supply option against a backdrop of falling domestic demand. In all cases, the Japanese players have opted not to buy FOB from producer projects, but instead have booked capacity at the Cove Point, Cameron, and Freeport LNG export facilities — all plants that require offtakers to secure and transport the feedgas supply for LNG production. This type of arrangement carries with it the need to set up gas trading desks in the U.S., with front-, middle- and back-office personnel, plus operations staff, representing additional fixed costs. What was the motivation for these commitments, made by no less than seven of Japan’s major LNG buyers, how successful have they been, and what lies in store for these volumes that the country does not appear to need? Today, we look at where these volumetric commitments fit, not only in the portfolios of the capacity holders but within the broader context of LNG commerce and commoditization.
This year has been a mixed bag for Appalachian natural gas producers. Outright prices in the region are higher than they’ve been in a few years, thanks to lower storage inventory levels and robust LNG export demand. However, regional basis (local prices vs. Henry Hub) is weaker year-on-year as higher production volumes have led to record outbound flows from Appalachia and are threatening to overwhelm existing pipeline takeaway capacity. Last month, Equitrans Midstream officially announced that the start-up of its long-delayed Mountain Valley Pipeline (MVP) project will be pushed to summer 2022 at the earliest. Then, just last week, outbound capacity took another hit as Enbridge’s Texas Eastern Transmission (TETCO) pipeline was denied regulatory approval to continue operating at its maximum allowable pressure, effectively lowering the line’s Gulf Coast-bound capacity by nearly 0.75 Bcf/d, or ~40%, for an undefined period. Today, we consider the impact of this latest development on pipeline flows, production, and pricing.
Global gas prices are in the midst of the longest and strongest bull run since 2018 and fundamentals appear supportive of sustaining the rally through at least the upcoming winter. The higher international prices relative to Henry Hub have buoyed demand for U.S. LNG exports. Existing terminals are operating at or near full capacity, and their combined feedgas demand has been steady, averaging more than 6 Bcf/d higher than this time last year when economic cargo cancellations from COVID-19 were heading towards their summer peak. The improved economics for delivering U.S. LNG to international destinations have also renewed interest in offtake agreements for a handful of the second wave of North American LNG projects that had been sidelined because of the pandemic (many others still are). These projects are taking advantage of the less crowded market, which gives them a realistic path forward to reach a final investment decision (FID). In today’s blog, we continue the series on the status of the second wave of LNG projects.
Over the past year, we have witnessed a sort of slow-motion meltdown among the second wave of North American LNG export projects. Appetite for new LNG expansions was already waning due to oversupply even before the pandemic affected demand, but COVID-19 brought project developments to a standstill. Offtake agreements have expired, final investment decisions (FIDs) delayed, and projects have lost funding or been officially put on hold or even cancelled. Just one project, Sempra’s ECA LNG in Mexico, was able to reach an FID last year, and with the pandemic still raging, for a while it looked as if that would be the last project in North America to take FID in the foreseeable future. It’s abundantly clear that many more of the remaining proposed projects will be postponed indefinitely, and probably never be built at all. However, the news isn’t all bad. With the worst of COVID-19’s impacts on international gas demand appearing to be over and the ongoing extended run of high global gas prices, all eyes are back on the second-wave projects that are in various stages of pre-FID development. The pandemic may have forced a culling of the proposed projects, but those near the top now have a clearer path ahead. In fact, several projects could realistically achieve FID in the next few years. Today, we begin a short series providing an update on the second-wave projects.
It’s not often these days that you read about gas markets in the San Juan Basin. In fact, the subject was probably never much of a hot topic because the San Juan has been something of an afterthought when it comes to Western gas markets, just a stop on the road between the Permian and markets along the West Coast and in the Rockies. However, those Western gas markets are setting up to be quite interesting this summer, as is the Waha gas market in the Permian, and understanding the mechanics of the San Juan is just one piece of the overall Western puzzle. In today’s blog, we take a look at the far-flung but increasingly interesting markets west of the Permian Basin.