There are no absolute certainties in the energy industry, but one thing a lot of people are betting on is increasing demand for LNG in Asia. A long list of countries there — China, Japan, and South Korea among them — have been shifting from nuclear and coal-fired power generation to natural gas, and as they do, their demand for LNG will be mind-blowing. The U.S. has emerged as a major supplier, but shipping LNG from the Gulf Coast to Asia involves either transiting the busy and costly Panama Canal or taking much longer routes through the Suez Canal or around the Cape of Good Hope. All of that has helped spur interest in developing LNG export terminals in western Mexico that would pipe in and liquefy Permian gas, then ship it straight across the Pacific Ocean. Today, we discuss plans for a large-scale liquefaction/export project aimed squarely at Asian buyers.
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Daily energy Posts
Talk about whiplash! Not that long ago, the global LNG market was reeling from the effects of the pandemic: stunted demand, severe oversupply, brimming storage, and record low prices, all of which led to a squeeze on offtaker margins and mass cancellations of U.S. cargoes. Within a matter of months, however, the market has done a 180. Global supply has tightened significantly as cargoes can’t get delivered fast enough, and international LNG prices are near two-year highs. U.S. LNG exports and domestic feedgas demand are at record highs in December, for the second straight month. That’s not to say U.S. LNG producers and the domestic gas market are out of the woods. Cancellations are rearing their heads again — not because the demand isn’t there, but because of logistical constraints and a severe vessel shortage, which are injecting more uncertainty into the market. Today, we provide an update on domestic LNG exports and the immediate factors driving them.
Canadian natural gas storage levels finished the most recent injection season at a record high. With what has been a fairly mild start to the heating season so far in North America, you might be tempted to think that Canadian storage levels would have been slow to draw down. On the contrary: so far, gas is being withdrawn from storage more quickly than might be expected from the winter weather alone, partly because of structural developments that have been emerging in the Canadian market. And these changes will help to draw storage levels down closer to historical averages by the end of the current heating season in March 2021. Today, we consider these structural changes and what the current heating season might have in store for the Canadian gas market.
Motor gasoline, diesel, and jet fuel need to be delivered in large volumes to every major metropolis in the U.S. While most big cities are well-served, some by multiple pipelines or a combination of pipelines and barges, others are more isolated and susceptible to supply interruption. Nashville, the home of country music, is one such place; so are Chattanooga and Knoxville to its east. All three Tennessee cities depend heavily on stub lines off the Colonial and Plantation refined-products pipeline systems as they work their way from the Gulf Coast to the Mid-Atlantic states. When supplies on these pipes are interrupted — and they have been from time to time — these cities can experience shortages and price spikes, and be forced to turn to trucked-in volumes from Memphis and elsewhere. Today, we discuss a supply alternative now under development that will pipe motor fuels south from BP’s Whiting refinery in northwestern Indiana to a proposed Buckeye Partners storage and distribution terminal just west of Nashville.
To succeed over the long term in the music business, professional sports, or the midstream sector, you need to learn from your successes and failures, and — most important — continue adapting and evolving. For many North American midstreamers, a key to success has been a thoughtful combination of expansion and diversification, plus an affinity for financial discipline, especially when the broader energy industry is going through tough, uncertain times. A prime example of that strategy is Canadian midstreamer Pembina Pipeline Corp., which after C$14 billion in acquisitions over the last four years is instituting a more cautious approach to new investment that’s largely based on self-funding and a new, more rigorous return criteria for new projects. Today, we preview our new Spotlight report, which focuses on the risks and rewards of Pembina’s new strategy.
Cushing. This small town in central Oklahoma is the center of the U.S. crude oil universe, with prices at the Cushing hub serving as the reference price for all of the crude produced in the U.S. — and given the role that U.S. oil has assumed on the global stage, one of the most important determinants of global crude oil pricing. Considering the hub’s significance, it’s frequently surprising to industry veterans just how misunderstood Cushing can be. Like, for example, how SHOCKED the world was when Cushing prices dropped below zero back in April. Cushing traders had seen that coming for weeks — the only surprise to them was how far the price plunged that crazy Monday morning. It’s easy to see how something as enigmatic and complex as Cushing might be misunderstood — or underestimated — if you’re not familiar with its history, its inner workings, and its many crucial roles in both the physical and financial crude oil markets. It’s also tempting to think you can get by with only a passing knowledge of Cushing and how it operates. Au contraire! Cushing really matters, and market participants ignore it at their peril. The good news is that there’s finally a combo encyclopedia and user’s manual for “The Pipeline Crossroads of the World.” Today, we examine the hub’s significance to producers, refiners, midstreamers, marketers, and traders, and discuss highlights from RBN’s new Cushing Playbook.
PADDs 4 and 5 — the Rockies and the West Coast regions, respectively — are each outliers in the U.S. refining sector. Refineries in the Rockies, for example, are generally far smaller than those in other PADDs and, due to pipeline flows, source their crude oil from either Western Canada, the Bakken, or in-region production, including the Niobrara and Utah’s Uinta Basin. West Coast refineries, in turn, have no crude oil pipeline links with U.S. points to the east, and depend on a mix of imported crude from Canada, Latin America, and the Middle East, as well as domestic oil from California, Alaska, and rail receipts. Today, we conclude a series on region-by-region crude oil imports and refinery crude slates with a look at PADDs 4 and 5.
No one could’ve seen the energy market disruptions of 2020 coming, and most of us are ready to write off what has been one of the most challenging years the industry has seen in a long time. Yet the events of the past year will most certainly define what unfolds in the New Year and beyond. To make sense of what 2020 will mean for the post-COVID era, we retooled and refreshed our models and forecasts to tackle the hard questions facing U.S. crude oil, natural gas, and NGL markets. As it turns out, beyond the immediate chaos of the pandemic, there is a new order taking shape, and that’s what we laid out in the RBN Fall Virtual School of Energy, sharing our results and the Excel spreadsheets behind the models to get you ready for what’s coming. Some of what we expected has come to fruition, and we still think that there is a pretty good chance that the rest will unfold in the months and years ahead. If you weren’t able to join us for the live broadcast, we invite you to sit by the fire, put your feet up and dig in over the holidays. The entire 14+ hours of streaming content, plus slide decks and spreadsheets, are available online. Today’s advertorial blog provides highlights from our key findings and the overall conference curriculum.
It’s been a wild and woolly December in the U.S. propane market. The Mont Belvieu propane price is up by almost 40%, blasting past 70 c/gal on Friday — a level not seen since February 2019, when WTI at Cushing was trading at $57/bbl, $8/bbl above where that price sits today. Is it simply cold weather goosing demand? Sure, that’s one factor. But it’s really all about exports. Just as 2020 cold weather finally arrived in U.S. propane country, exports hit the highest levels ever recorded. December Gulf Coast export volumes — 92% of the U.S. total — are up 21% over last month, and 39% above December 2019. So both international and domestic demand are pulling hard on supplies at the same time. No wonder propane prices are soaring. We started this series on winter 2020-21 supply/demand in late November by suggesting that there could be a few gotchas still out there that were not being reflected in the forward propane market. Well, we’ve now seen one of those gotchas. But there’s a lot of winter left to go — in fact, the official start of winter is this morning! Today, we review what’s happened so far in propane markets, and what could be coming next.
U.S. crude oil exports are off from the record highs they reached earlier this year, leaving the Gulf Coast even more flush with surplus export capacity than it had been going into 2020. And yet … Energy Transfer is developing an crude export terminal off the coast of Beaumont, TX, that would be capable of fully loading a 2-MMbbl VLCC every day or so. Is the company’s Blue Marlin project based simply on a hunch that U.S. oil production and exports will rebound over time and eventually leave PADD 3 short of dock and ship-loading capacity? Or is Energy Transfer’s proposed offshore terminal, with its extensive re-use of existing infrastructure, a cost-efficient way of giving oil-sands, Bakken and other producers more direct access to deep water and the supertankers that long-distance shippers prefer? Today, we discuss what may be behind the seemingly long-shot effort to develop new export capacity in a region that’s already got way too much.
As bitumen production in Alberta’s oil sands has grown over the past decade, so has demand for diluent, which is blended with molasses-like bitumen to help it flow through pipelines or be transported by rail. With bitumen output expected to continue rising through the first half of the 2020s, we have estimated that Alberta demand for field condensate, natural gasoline and other diluent will increase by more than 40% — to almost 1 MMb/d — by 2025. The catch is, diluent production in Western Canada isn’t growing fast enough to keep pace, and there are limits to how much diluent can be imported on the two existing pipelines from the U.S. What if there were a way to slash how much diluent is needed to put bitumen in rail tank cars — and make rail transport safer in the process? Today, we discuss Gibson Energy and US Development Group’s new diluent recovery unit in Hardisty, AB.
Back in 2005, marine terminals along the Gulf Coast were importing more than 6 MMb/d of crude oil, mostly to feed refineries within PADD 3 but also to pipe or barge north to PADD 2. By 2019, with U.S. shale production finishing up a decade-long rise, imports to the Gulf Coast had declined to less than 1.7 MMb/d. In COVID-impacted 2020, imports sagged, soared, then sagged again, recently settling in at about 1.2 MMb/d, their lowest level in — wait for it — 35 years! The 80% decline in Gulf Coast oil imports since the mid-2000s was made possible in part by big changes in the crude slates at refineries in Texas, Louisiana, and other PADD 3 states, mostly involving the swapping out of light sweet crude from overseas with favorably priced light sweet crude from the Permian and other U.S. shale plays. Today, we look at imports into PADD 3, the home of more than half of the U.S.’s total refining capacity.
Natural gas economic shut-ins! Shutting off a producing well on purpose, because the market won’t take the produced volume at a reasonable price. There was a time, back before gas commodity decontrol, when shut-ins were standard operating procedure, but that practice went the way of the dodo bird 40 years ago. Until earlier this year that is, when amid crushingly low prices, Appalachian producers said: enough is enough — and shut off the spigot themselves. In the months that followed, various producers have continued to see-saw their production in response to weather-related demand and regional market prices. The behavior signals that Appalachia’s shale gas producers are increasingly employing a light-switch approach in dealing with short-term weakness in demand and prices. Today, we take a closer look at the price-driven curtailments in the Northeast and potential implications for the market.
Wafting through the late autumn air in November, along with the sharp scent of burning leaves and the cinnamon-tinged aroma of pumpkin pie, was a moderate whiff of optimism for the energy industry’s long-beleaguered exploration and production sector. Equity prices in general were buoyed by news on the efficacy of the COVID-19 vaccines and the prospects of imminent approval that could finally bring the pandemic under control and improve industry fundamentals. E&P stocks, which also benefited from a rebound in third-quarter earnings, recorded the largest monthly gain in history: a 32% rise in the S&P E&P Index. However, their share prices were still down 69% from the 2019 highs and 45% from end-of-last-year levels as oil and gas producers still face a long road to return to “normal.” Today, we analyze the third-quarter earnings of the 40 major E&P companies we track and review the major impacts on the sector since the onset of the pandemic.
The energy world has been turned upside down in 2020 by COVID-19, resulting in the cancellation, scaling back, or deferral of numerous pipeline projects in both the U.S. and Canada. One such deferral involved a planned NGL pipeline that would run through the heart of Alberta’s Montney and Duvernay plays. Originally slated to begin construction earlier this year, a one-year deferral was announced back in May by the joint venture of Canadian midstream players Keyera and Energy Transfer Canada, the latter of which is itself a JV of Energy Transfer and KKR. Since then, a stabilization in energy markets and signs of recovery in Alberta NGL production has provided the co-developers with the confidence to commit to a construction start in 2021. Today, we review the project and what has changed to get it back on track.
Closing midstream deals has been a bit of a challenge in 2020, to say the least. In fact, this has been a year when many projects have been sidelined or cancelled outright, with most decisions on even the best prospects getting pushed to next year. But it hasn’t been all bad news. In a few cases, assets with advantages have made it across the finish line, even in the land of liquefied natural gas (LNG) export projects. Despite this summer’s collapse in U.S. LNG exports, driven by a compression of the spreads in global gas prices, Sempra Energy recently announced that it is going ahead with Phase 1 at its Costa Azul liquefaction project in Mexico’s Baja California. How did they pull this off in such a tumultuous year? Well, Costa Azul isn’t your everyday LNG export project. Today, we detail the most recent U.S. LNG export project to receive a final investment decision (FID) to proceed.