U.S. LNG exports in recent months have gone from providing a consistent and growing source of demand to balance the U.S. natural gas market to now being a drag on demand growth and the gas market balance. Rising storage surpluses and record low prices in Europe and Asia, along with relative strength in the U.S. national benchmark prices at Henry Hub, have turned the economics upside down for U.S. exports and led to widespread cancellations of contracted cargoes. Feedgas deliveries and cargo liftings at Lower-48 terminals both have plummeted to the lowest levels since early 2019, despite domestic liquefaction capacity climbing by more than 4 Bcf/d since then. Moreover, the dynamics that led to the current predicament are likely to persist at least through injection season and potentially even beyond that to a certain extent. Today, we provide an update on how cargo cancellations have affected U.S. gas demand for exports, overall and at individual terminals.
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A federal judge’s order that the 570-Mb/d Dakota Access Pipeline be taken out of service for a year or more starting August 5 has the potential to wreak more havoc for producers in the Bakken Shale at a time when they are still reeling from drastic, COVID-related production curtailments. While those production cuts have opened up at least some capacity on other takeaway pipelines out of western North Dakota and crude-by-rail terminals may be able to ramp up their operations, that may not be enough to make up for the loss of DAPL — still more well shut-ins may be required. Then there’s the matter of taking the 1,172-mile, 30-inch-diameter pipeline offline in only four weeks’ time — it involves much more than flipping a switch and may not even be possible within that time frame. Today, we consider the hurdles and implications of removing DAPL from service.
So far, 2020 has been another bad year for bitumen producers in Alberta’s oil sands. For the second year in a row, they have been forced to endure production curtailments, this time in response to COVID impacts on demand and the resulting record-low heavy oil prices. Still, there are at least glimmers of hope that the bitumen market will soon enter at least a modest recovery mode, and that further gains will be possible in 2021 and beyond. Moving all of that bitumen to market in pipelines and in rail cars is going to require even more diluent than the record amounts already consumed in late 2019 and early 2020. Today, we consider the outlook for bitumen production, what that outlook means for future diluent demand, and if that demand can — or cannot — be met by the various sources of diluent supply.
They’re generally small in size, but renewable diesel refineries are popping up in many parts of the U.S., incentivized by government programs aimed at reducing carbon emissions and very gradually weaning Americans — and Canadians — from crude oil-based diesel fuel. Recently, HollyFrontier Corp. announced that it will be converting its decades-old Cheyenne, WY, refinery into a renewable diesel facility. While the news of another entrant into the renewable diesel market is not surprising, the complete shutdown and transformation of an existing refinery for this purpose marks only the second time this has occurred in the U.S. Today, we discuss HollyFrontier’s plans and provide an update on renewable diesel supply and demand dynamics.
The demand destruction caused by COVID-19 hasn’t only hurt producers and refiners; it’s also slowed the development of a number of planned midstream projects. In fact, the only multibillion-dollar crude-related project to reach a final investment decision (FID) during the pandemic is TC Energy’s Keystone XL, which in late March won financial backing from Alberta’s provincial government. But Keystone XL soon hit another snag, this time in the form of U.S. district and appellate court rulings that vacated the project’s Nationwide Permit 12 for construction in and around hundreds of streams and wetlands along the U.S. portion of the pipeline’s route in the U.S. More important, the courts also put on ice — at least for now — the use of the general water-crossing permit for other new oil and natural gas pipelines as well. As we discuss in today’s blog, that could result in delays and legal challenges to dozens of projects that midstreamers and their counterparties have been counting on.
Though crude oil prices have been rebounding lately, this spring’s price crash sent shockwaves through the U.S. midstream industry, which not too long ago had emerged from a decade of massive infrastructure investment in response to unprecedented upstream production growth. Just as midstreamers were looking forward to steady earnings growth, waves of huge capex cuts and well shut-ins by producers shattered forecasts and shifted strategic instincts toward survival instead of growth. Every company is different, of course, but a lot can be learned by examining a single firm in detail to see how it will fare in the current market environment, given its particular set of assets and arrangements. Take Targa Resources. An analysis of its performance provides insights into the outlook for integrated natural gas and NGL assets, especially in the Permian Basin, as well as the value of forming joint ventures. Today, we preview our Spotlight report on Targa.
Solar photovoltaic projects accounted for an impressive 40% of all the new electric generating capacity installed in the U.S. in 2019 — the third time since 2015 that solar additions outpaced installations of natural-gas capacity. And the early 2020s are shaping up as another good period for solar, especially in states that offer both intense sun and the broad expanses of land required for large-scale solar projects. Texas is a case in point; some 8,000 megawatts (MW) of new solar capacity is expected to be added there in the 2020-22 period. Solar power, like wind power before it, has come to be so prolific in the Lone Star State that you’d think it would be having a significant impact on how much gas-fired generation is needed day to day, right? Today, we discuss the increasing role of solar generation in the second-largest state and its impact on the demand for traditional power plant fuels.
Producers in Alberta’s oil sands have been through good times and bad times the past few years. Sure, there’s been a lot of growth in output since 2010. But they’ve also seen wildfires that forced one-third of production offline. And pipeline takeaway constraints that sent prices tumbling and spurred government-imposed production cutbacks. And lately, they’ve been struggling through a global pandemic that slashed crude-oil demand and led to further curtailments. Despite it all, producers and the province of Alberta are hopeful about an oil sands rebound, and shippers are optimistic that they can source an increasing share of the diluent they would need to transport bitumen from Western Canada. There’s good news on that front: there appears to be plenty of diluent pipeline capacity already in place between Alberta’s diluent hubs and its oil sands production areas. Today, we continue our series by exploring the major pipeline systems that distribute diluent supply to the oil sands.
U.S. exports of motor gasoline and diesel to Mexico increased steadily from 2013 through 2018 as demand for refined products south of the border increased and throughput at Pemex’s six older, investment-starved refineries declined. U.S.-to-Mexico shipments of gasoline and diesel sagged in 2019, though, as Pemex started to implement a major refinery rebuilding program, and fell further in the spring of 2020 as the social and economic effects of COVID kicked in and Mexican demand for motor fuels plummeted. So what’s ahead for U.S. refined product exports as Mexican demand gradually rebounds later this year and in 2021? As we discuss today, that will largely depend on the Mexican government’s determination to have its debt-laden energy company produce gasoline and diesel at a loss and proceed with expensive refinery projects.
Chesapeake Energy’s announcement yesterday that it has filed for Chapter 11 bankruptcy protection is only the latest sign of how much the seismic economic shocks from the pandemic-triggered demand destruction have roiled the U.S. E&P sector. With equity prices plummeting to historic lows, oil and gas producers have focused their efforts on shoring up their balance sheets and share prices, by tightening their belts going into 2020, reducing capital expenditures by an average 14% in order to boost free cash flow and increase shareholder returns. So, it’s no surprise that the industry has aggressively battened down the hatches operationally and financially, mothballing rigs, suspending completions, shutting-in producing wells, slashing dividends, and suspending share repurchase programs. First-quarter 2020 earnings releases and investor calls provided a clear picture of the dimensions of the cost-cutting by the 41 U.S. E&Ps we track. But continued uncertainty about the course and duration of the COVID-19 pandemic, the pace of economic recovery, and the outlook for commodity prices have triggered reluctance on the part of oil and gas executives to issue production guidance for the remainder of 2020 and beyond. Today, we review the current capital expenditure reductions by U.S. E&Ps and piece together clues on their impact on oil and gas production.
The CME/NYMEX Henry Hub prompt contract settled at $1.482/MMBtu yesterday, down 11.5 cents (7%) from the previous day and the lowest settle that the market has ever seen during June trading. That’s also a 33-cent (18%) drop from just two weeks ago when prompt futures were around $1.80/MMBtu. The immediate rationale is the larger-than-expected and larger-than-normal storage build reported by the Energy Information Administration yesterday. But current price levels are also indicative of bigger problems looming for the gas market, namely that while gas production is down, total demand, including exports, has been exceptionally weak too. As a result, by mid-July, the storage inventory appears likely to reach record highs for that time of year — record highs that may well persist through the end of injection season in early November unless there is a substantial correction in the gas supply-demand balance. Moreover, it’s looking less and less likely that relief will come from the demand side. Today, we look at the drivers behind the latest gas market meltdown and implications for the balance of injection season.
Tallgrass Energy and DCP Midstream’s Cheyenne Connector pipeline and the REX Cheyenne Hub Enhancement projects are set to begin operations tomorrow, June 26, after receiving FERC approval yesterday. The natural gas projects will add takeaway capacity out of the Denver-Julesburg and Powder River production basins. For Tallgrass, the incremental capacity has the potential to increase utilization of its Rockies Express Pipeline (REX), which has struggled to fully recontract its mainline capacity after a slew of long-term contracts expired last year. For gas producers, the new capacity and hub upgrades mean an alternative route out of the core DJ with farther-reaching destination options for gas flows, including access to REX and its growing direct-connect load and numerous third-party interconnects in the Midcontinent/Midwest. About 600 MMcf/d in firm contracts will kick in for each project with the start of service, but given that Niobrara gas production is down and there’s likely no new production waiting behind the capacity, gas flows on the two projects may come down to economics. In today’s blog, we provide an update on the projects in the context of today’s uncertain market.
The folks who transport bitumen from the Alberta oil sands to faraway markets depend on light hydrocarbons collectively known as diluent to help make highly viscous bitumen flowable enough to be run through pipelines or loaded into rail tank cars. The catch is — or was, we should say — that Western Canada wasn’t producing nearly enough condensate and other diluent to keep pace with fast-rising demand, so a few years ago, two pipelines from Alberta to the U.S. Midwest were repurposed to allow diluent to be piped north. More recently, though, Western Canadian production of diluent has been soaring and new pipeline capacity has been built within Alberta to deliver it to the oil sands. That has the potential to reduce the need for imports from the U.S. and may soon lead to at least one of the import pipes being repurposed yet again. Today, we continue our series on diluent with a review of the pipeline systems that collect locally produced light hydrocarbons that are eventually employed in the oil sands.
Lower crude oil prices whack oil-directed drilling, slashing crude production, which cuts associated gas output, tightening the gas supply-demand balance, and boosting gas prices enough to spur more gas-directed drilling — it’s a classic case of commodity market schadenfreude, where one product benefits at the expense of another. That’s the way it was supposed to work, according to various trading strategies touted a few weeks back. But here we sit, with crude oil prices still around $40/bbl and gas prices languishing at a paltry $1.66/MMBtu. Was there something wrong with the schadenfreude thesis, or do we have to look deeper to understand how prices will behave in this convoluted COVID era? In today’s blog, we’ll explore this question and what it may mean for natural gas prices in the coming months.
On Thursday, June 18, the Federal Energy Regulatory Commission (FERC) issued a Notice of Inquiry (NOI) to reset the index that’s used to make annual changes to the rate ceilings for interstate pipelines that transport crude oil, refined products, and other hydrocarbon liquids. Every year, the highest rate an indexed oil pipeline can charge goes up or down — almost always up — using the FERC index. The commission’s new proposal, which would become effective in July 2021, follows an already-approved index adjustment that will take effect a week from Wednesday, on July 1. Taken together, the two changes would reduce the maximum annual increase in the rate ceiling from more than 4% now to less than 1%, which could have a major impact on liquids pipeline owners. Today, we discuss the NOI, the meaning of the pipeline index, where it came from, and where it might be headed.
