U.S. LNG cargoes’ ability to reach different destinations has become increasingly important for the global market as more liquefaction trains continue to come online, oversupply conditions worsen, and international price spreads have shrunk. Earlier this week, Freeport LNG’s first train began commercial service, marking the sixth U.S. liquefaction and export facility to start commercial operations. About 30% of U.S. long-term contracts for currently operating or commissioning liquefaction trains are held by global portfolio players — i.e., offtakers with large international portfolios and the ability to shift cargoes around the world as prices move. And destination flexibility doesn’t end there, as the other types of offtakers also have shown an increased willingness to divert or even re-sell cargoes in the spot market to better take advantage of shifting price spreads. Today, we continue a series on U.S. LNG export trends, this time focusing on how global prices impact cargo destinations.
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Daily energy Posts
Propane stockpiled in Canada has often been a mid-winter godsend for propane consumers in the U.S. Midwest and Great Plains states. If supplies in PADD 2 ever got tight due to unusually cold weather, greater-than-normal crop-drying demand and/or kinks in the U.S. supply chain, the higher prices spurred by the shortfall would incent more Canadian propane to be piped, railed or trucked south. This winter may be different, though. A new propane export terminal in British Columbia and steady-as-she-goes exports from the U.S.’s northern neighbor to PADDs 2 and 5 have left Canadian propane inventories nearly one-third lower than a year ago, and propane in the Edmonton, AB, hub is selling at a far-from-typical premium to propane at Conway, KS, and Mont Belvieu, TX. Today, we explain why a supply-demand imbalance in the U.S. heartland this winter might be harder to fix.
As exports of crude oil, natural gas and NGLs have surged, U.S. markets for these energy commodities have undergone radical transformations. Exports now dominate the supply/demand equilibrium. These markets simply would not clear at today’s production levels, much less at the volumes coming on over the next few years, if not for access to global markets. Making sense of these energy market fundamentals is what RBN’s School of Energy is all about. Did you miss our conference a few weeks back? Not to worry! You’ve got a second chance! All the material from the conference — including 20 hours of video, slide decks and Excel models — are now online. Fair warning: Today’s blog is an unabashed advertorial for the latest RBN School of Energy + International Online.
Crude oil gathering systems play an important role in a matter critical to producers, marketers and refiners alike: crude quality. Well-designed gathering systems can help deliver crude with the API gravity and other characteristics that refiners desire and are willing to pay a premium for. This has become a particularly big deal in the Denver-Julesburg Basin, where a big expansion of gathering capacity is under way, and where the market gives extra value to “Niobrara-spec” crude with an API of 42 degrees or lower. Today, we continue a series on existing and planned pipeline networks to move D-J-sourced crude from the lease to regional hubs and takeaway pipes with a look at Taproot Energy Partners’ system.
New U.S. liquefaction trains and LNG export terminals are entering an increasingly oversupplied global market in which international LNG prices are well below where they stood a year and a half ago and price spreads from the U.S. have collapsed. That hasn’t deterred U.S. LNG exports from increasing with each new liquefaction train and capacity contract that goes into effect, as long-term offtake contracts, which anchor more than 90% of the U.S. liquefaction capacity, have made cargo liftings relatively insensitive to global prices. However, the destinations for U.S.-sourced LNG have been in flux based on the types of offtakers holding capacity on newly commercialized trains as well as shifting global prices. Today, we continue a series on cargoes and destinations, this time focusing on how contracts impact cargo destinations.
Production of alternative, non-petroleum-based fuel continues to be a hot topic around the globe as government policies have incentivized or even mandated these products with the aim of reducing greenhouse gas emissions. In the U.S., we’ve seen waves of ethanol and biodiesel enter the fuel supply chain, but the latest commodity that has piqued industry interest is renewable diesel, whose chemical characteristics make it a particularly desirable replacement for conventional distillate. Today, we provide an overview of the renewable diesel market, the legislative programs in North America that are incentivizing its production, and the projects currently on the books to produce it.
A little over a year ago, we discussed the rapidly expanding third-party shipper market for crude oil in West Texas. At the time, crude at Midland was trading at nearly a $15/bbl discount to Gulf Coast markets. Pipeline space out of the Permian was hard to come by and extremely valuable, and everybody and their brother — literally, in some cases — were forming a limited liability corporation and trying to secure space as a walk-up, “lottery” shipper. A lot of people made a lot of money, but now, just over a year later, much of that lottery opportunity has dried up. Nowadays, these same folks are looking for new opportunities, or going back to old strategies, only to find that being a third-party shipper today is more expensive and more burdensome. In today’s blog, we recap how lottery shippers made buckets of money in late 2018 and early 2019, only to see their target of opportunity dry up due to midstream investment.
As a most eventful decade for the U.S. energy industry draws to a close and 2020 looms, it’s a perfect time to consider what’s ahead for the midstream sector — and, more important from an investor’s standpoint, for the individual companies within it. The last few years have driven home the point that while all midstreamers are impacted to some degree by what happens on a macro-level, the relative success of each company is tied to the myriad decisions its leaders make over time regarding which basins and hubs to focus on and which assets to build, expand, acquire or divest. Assessing these micro-level assets and the contributions they each make to a company’s bottom line requires particularly deep analysis. Today, we discuss key themes and findings from East Daley Capital’s newly issued 2020 Midstream Guidance Outlook.
The once unthinkable level of 100 Bcf/d for U.S. natural gas production is just around the corner, it would seem. Lower-48 gas production last week hit a new high of 96.4 Bcf/d, after surpassing 95 Bcf/d not too long ago (in late October). That’s remarkable considering that production was only 52 Bcf/d just 12 years ago. Gas demand from domestic consumption and exports this year has set plenty of records of its own, but the incremental demand has not been nearly enough to keep the storage inventory from building a significant surplus compared with last year. CME/NYMEX Henry Hub prompt gas futures prices tumbled nearly 40 cents last week to $2.28/MMBtu, the lowest November-traded settle since 2015. Today, we break down the supply-demand fundamentals behind this year’s bearish storage and price reality.
Cold weather and spiking demand from Midwest and Great Plains farmers trying to dry their late-maturing, soggy crops have sent the PADD 2 propane market into a tizzy. Supply is not a major issue — propane inventory levels in the region are only a little below average, and stocks are plentiful along the Gulf Coast in PADD 3 — but distributing propane by rail and truck for crop-drying use has been a bigger-than-normal problem. As a result, farmers are scrambling to get more of the fuel, and propane prices in the U.S. heartland have been skyrocketing. Worse yet, Canada may not be able to come to the rescue as it has in the past, because its propane exports to Asia are up and its inventories are down. Today, we review recent developments on the fuel front in the nation’s breadbasket.
In 2019, there has been a significant shift in crude oil and natural gas markets. Prices have remained stubbornly low, even when faced with the risk of significant turmoil like the Saudi drone attacks. Investors are far less forgiving, and energy-related equity values continue to lag most other sectors, despite most companies returning more of their earnings to shareholders. Oil and gas producers are focused on their sweetest of sweet spots, wringing every crumb of financial return from their investments. The risk-return equation has changed. All this makes now a good time to examine the strategies and tactics necessary for survival in this challenging phase of the Shale Era. That is especially true for the players who seem to be doing everything right, because some of the worst management mistakes can occur when performance is good.
The doubling of crude oil production in the Denver-Julesburg Basin over the past 18 months spurred a rapid build-out of crude gathering systems and other infrastructure. Unlike the sprawling Permian Basin, with its numerous centers of drilling and production activity in parts of West Texas and southeastern New Mexico, the vast majority of the D-J Basin’s incremental crude output has come from Weld County, CO. Understandably, Weld County also is where most of the D-J’s crude gathering systems are located, and where most of the gathering system expansions are being planned and built. Today, we continue a series on existing and planned pipeline networks to move D-J crude from the lease to regional hubs and takeaway pipes.
U.S. LNG export capacity has increased 40% in the last seven months, from 4.3 Bcf/d in April to about 6 Bcf/d now, and feedgas demand at the terminals already exceeds that, with more than 7 Bcf/d flowing to the facilities in recent weeks. With each new liquefaction train coming online, feedgas deliveries to export terminals have steadily climbed, and, for the most part, have sustained at rates that suggest consistently high utilization of the facilities’ capacity, particularly once they begin commercial operations and regardless of international market dynamics. And, that demand is expected to increase further as more liquefaction capacity comes online in 2020 and beyond. The emergence of this seemingly inelastic demand with a baseload-like pull on domestic gas supplies marks an underlying shift in the U.S. gas market that, along with the rising baseload demand from power generation, will make national benchmark Henry Hub prices more prone to spikes. Today, we explain how ever-increasing LNG exports will reshape the U.S. demand profile and, in turn, Henry price trends.
With oil and gas prices drifting lower and markets continuing to pummel exploration and production companies, shareholders and analysts approached the third-quarter 2019 earnings season with the sense of impending doom akin to awaiting the results of an IRS audit. There was a lot of talk that the Shale Revolution was fizzling out and that the industry was approaching yet another financial Armageddon, like the 2014-15 oil price crash crisis. But the results belied the worst fears: while lower commodity prices did reduce profits and cash flows, E&Ps as a group remained solidly profitable in the third quarter, with 40 of the 47 companies we track ending up in the black. The reductions in operating income and cash flows were generally in line with lower realizations from oil and gas sales, although lower commodity prices did trigger some write-downs of properties that could no longer be profitably developed. Once again, E&Ps held the line on costs, continuing the financial discipline that fueled the industry’s recovery after the mid-decade price crash. Although producers generally cut back expenditures in line with lower cash flows, increases in drilling efficiency allowed production to keep growing. Today, we examine the financial health of the 47 E&Ps we track in this analysis and the ways they are navigating the price downturn.
Crude oil production in the Permian grew steadily through the 2010s and now tops 4.5 MMb/d — five times what it was at the start of the decade. Production in the Bakken and the Denver-Julesburg (D-J) Basin sagged when crude prices plummeted in 2014-15, but both regions chugged their way back, with output setting new records every month or two in 2018-19. SCOOP and STACK are another story. Only a year or two ago, many producers and others were talking up the neighboring crude-focused plays in central Oklahoma as the next big thing, maybe even a Sooner State Permian. But while SCOOP/STACK production increased through 2018, it’s been flat or falling ever since, and most producers there have been slashing their drilling activity. Today, we look at recent developments in the once-hot region.
As new crude oil pipeline capacity to the Gulf Coast comes online, a growing disconnect is developing between the surplus crude volumes available for export and the actual export capacity at coastal terminals, particularly projects that would accommodate the more economical and efficient Very Large Crude Carriers (VLCC). This is especially true in the Beaumont-Port Arthur, TX, area, where the relatively shallow depth of the Sabine Neches Waterway limits vessels to Aframax-class ships or partially loaded Suezmax tankers. If planned pipeline expansions into the BPA region over the next two years are completed, over 1 MMb/d of additional crude exports would need to leave BPA terminals to balance the market. Today, we look at current and future export capacity out of BPA.