Propane prices at Mont Belvieu soared above $1/gallon on Wednesday — the first time that’s happened in the month of June since 2014. This buck-and-change price doesn’t come as much of a surprise for industry insiders, however. U.S. propane inventories have been very skinny lately, sitting at 56.2 MMbbl — or only 587 Mbbl above the five-year minimum based on yesterday’s EIA data. At the same time, propane exports have been riding high, averaging 1.3 MMb/d so far this year, up nearly 90 Mb/d from the same time frame in 2020, while production has remained virtually flat over the past 18 months. Surprise or not, the spike past $1/gal raises an important question: How high will U.S. propane prices have to go before exports are reined in so U.S. inventories can increase? Today, we discuss the key drivers behind the current price level and our propane market outlook for the second half of the year.
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Daily energy Posts
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.
IMO 2020, the mandate that ships plying most international waters slash their sulfur emissions starting in January of last year, was only another step in the International Maritime Organization’s long-running effort to ratchet down the shipping industry’s environmental impact. The group’s next focus, as you might expect, is reducing shippers’ carbon footprint — while no specific rules have been set, the IMO in 2018 laid out the goal of cutting ships’ carbon dioxide emissions by 40% from their 2008 levels by 2030. One way to move toward that goal would be fueling more ships with LNG, which emits 20-25% less CO2 than very low sulfur fuel oil. But as we discuss in today’s blog, shippers could augment those emission reductions by moving from the LNG trade’s traditional point-to-point model to optimization through cargo swapping.
The Montney Formation in British Columbia and Alberta is exclusively responsible for the turnaround in Western Canada’s natural gas production in the past decade. Gas production in the Montney — a vast area with extraordinary reserves — has doubled in that time, with most of that growth coming from the BC side of the formation. This phenomenal growth story stems from a few key factors, including steadily improving gas well performance and increasing wellbore length, coupled with access to an established network of gas pipelines. Today, we delve into what has made BC’s portion of the Montney such as standout.
On the surface, it may seem that the LNG market has normalized after the past year’s tumult, and it’s true that many of the day-to-day disruptions that plagued LNG offtakers and operators have subsided. Mass cargo cancellations are a distant memory, and U.S. LNG exports have been flowing at record levels. Global demand has recovered, and buyers are back to worrying more about what they normally worry about: storage refill and securing enough supply for the next winter. However, in other ways, the pandemic and the more decisive shift toward decarbonization measures in many ways have fundamentally changed how deals for future LNG development will get done. Today, we look at what the global initiative to reduce greenhouse gas emissions will mean for LNG project financing.
Appalachia natural gas producers hoping to get a big boost in pipeline takeaway capacity later this year were dealt some bad news recently. On May 4, Equitrans Midstream officially pushed back the in-service date for the already-delayed Mountain Valley Pipeline. The 2-Bcf/d, greenfield project is the last of the major planned expansions that would add substantial capacity from the prolific Appalachia gas-producing region and help stave off severe seasonal pipeline constraints, at least in the near- to midterm. Previous guidance had it coming online late this year, but Equitrans said it is now targeting start-up in the summer of 2022, pending water and wetland crossing permit reviews. The news is far from surprising considering the numerous regulatory and legal challenges midstream projects, including MVP, have previously faced in the Northeast over the past decade or so. But the resulting uncertainty leaves Northeast producers in a tight spot. In today’s blog, we will consider the implications of the MVP delay for Appalachia’s outflows.
A lot of people know that Permian natural gas prices have spent many days in negative territory over the last few years, only to skyrocket over $100/MMBtu during the Deep Freeze in February. Those events were mostly viewed as transitory, driven by a chronic lack of pipeline capacity in the former case and a crazy round of arctic weather in the latter. It may come as a surprise to hear that forward basis prices for natural gas in the Permian are trading at a premium to Henry Hub for at least some months over the next year or so. How could it be that gas from a supply basin way out in West Texas, where gas is considered a byproduct, trades at a premium? The answer lies in the key infrastructure changes expected in the weeks ahead and a premium in forward basis for the Houston Ship Channel gas market. How long the Texas premiums will last depends on Permian gas production, which is starting to take off again. Today, we aim to explain the latest developments in Permian and Texas natural gas markets.
U.S. LNG export terminals are running at their operationally available and contracted levels and will continue to do so, with no economically driven cargo cancellations anywhere on the horizon. Global gas prices are well supported by low storage levels in Europe, and it will take time to refill inventories, which means these high prices are not going away anytime soon. The upshot: U.S. LNG will have a very different kind of summer than it did last year, when global prices were at historic lows and many U.S. terminals saw more cargo cancellations than exports. Feedgas in April this year averaged 10.77 Bcf/d, nearly 3 Bcf/d higher than last year, and as we progress into summer, the year-on-year delta will become even more pronounced. Barring any major operational issues, feedgas demand will stay around 11 Bcf/d, which is the level needed for the terminals to produce at full capacity. That’s in stark contrast to last summer, when feedgas demand cratered and averaged as low as 3.34 Bcf/d in July as cargo cancellations peaked. Today, we look at what’s supporting global gas prices, how that impacts export economics for U.S. LNG, and what that means for feedgas demand in the months ahead.
Outbound natural gas flows from Appalachia over the weekend hit a new record high of 17.3 Bcf/d and averaged 16.7 Bcf/d for April — an all-time high for any month. That’s despite pipeline maintenance season being well underway last month and intermittently curtailing production and outflow capacity. Utilization rates of takeaway pipelines from the region are soaring above 90%, with little more than 1 Bcf/d of spare exit capacity for outflows of surplus Northeast production. Whether that will be enough to stave off severe constraints and discounted pricing in Appalachia in what’s left of the spring season, and again in the fall will depend on how much surplus gas is left after meeting in-region consumption and storage refill requirements. What happens when seasonal demand declines occur in May and June? In today’s blog, we wrap up our analysis of current outbound capacity utilization and where that leaves the Northeast gas market this spring.
In just a few years, the Montney Formation has become the most prolific natural gas production region in Western Canada. Starting from zero in 2005, the Montney has been the primary growth engine for gas supplies and continues to challenge producers to deal with its vast geographic extent and enormous reserve potential. Spread across swaths of Canada’s two westernmost provinces, the formation’s unique geology has meant that its gas production growth has moved at different speeds depending on location, geology, and pipeline access. In this first part of a three-part series, we take a closer look at this important formation.