On January 1, 2020 the International Maritime Organization (IMO) implemented new fuel standards for oil-powered vessels, except those equipped with exhaust scrubbers to remove pollutants. In the absence of a scrubber, the IMO 2020 rule stipulates that ships' bunkers contain less than 0.5% sulfur. Using a scrubber allows the vessel to burn cheaper high-sulfur fuel. Last March, a shipowner’s estimated $2.5 million scrubber investment for a 2-MMbbl Very Large Crude Carrier (VLCC) would take just over three years to recover, based on average fuel prices during the first quarter of 2019. This year, barely a month after the new regulation came into force, the payback period has shortened dramatically, to less than a year, though the coronavirus’s effect on shipping demand and fuel prices, among other factors, could again put payout timing at risk. Today, we look at changing price spreads between high-sulfur and low-sulfur bunker and the scrubber payback economics that suggest a rosier outlook for vessel owners who invested in scrubber installations, at least for now.
Daily energy Posts
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.
U.S. natural gas prices are increasingly susceptible to periodic spikes and volatility as baseload demand for gas — or the minimum level of demand that must be met on a daily basis — specifically from power generators and liquefaction plants, has rapidly climbed in recent years, and is still rising. The power sector has upped the ante on its gas consumption, with gas replacing coal as the most cost-effective go-to fuel for meeting baseload electricity demand. On top of that, feedgas deliveries to LNG export terminals have added 7 Bcf/d of demand to the gas market in the past three years, much of which is flowing at high, baseload-like rates, and that demand is set to increase further as more liquefaction projects are completed. These two market components together — LNG exports and gas-fired power generation — will take a bigger slice of domestic gas supplies, making the gas market ever more sensitive to weather, maintenance and other factors that disrupt that baseload level of demand or the supplies that serve it. We’ve already begun to see the effects of this phenomenon on Henry Hub and other regional gas prices. Today, we delve into this fundamental shift and what it could mean for the gas market.
Anything but normal might be the best way to characterize today’s market for normal butane. Butane production at gas processing plants and fractionators is at or near an all-time high. Butane consumption by steam crackers is maxed out, and so were butane exports until new dock capacity came online this fall. Butane inventories? They’ve risen to record levels too, and this summer, butane prices fell to their lowest mark in more than a decade. Now, with winter-gasoline blending season in high gear and new room for export growth, butane prices at Mont Belvieu are up more than 35% from where they stood a month and a half ago. What does all this mean for the butane market this winter? Today, we discuss recent trends in normal butane production, consumption, exports and stocks.
In February 2019, the U.S. Treasury Department announced new sanctions on Petróleos de Venezuela SA (PDVSA), the national oil company of Venezuela, which halted imports of Venezuelan crude oil into the U.S. Since then, refineries that relied on Venezuelan crude have had to backfill their import requirement with alternative sources of oil. This adjustment has had ramifications not only on the refiners that processed Venezuelan crude, but also on the entire U.S. Gulf Coast crude oil market. Today, we discuss the quality adjustments made to the U.S. crude oil diet.