U.S. Northeast natural gas producers may be on the other side of a years-long battle with perpetual pipeline constraints and oversupply conditions. But they’re now facing new challenges to supply growth, at least in the near-term, from low crude oil and gas prices and the decline of a major downstream consumer of Appalachian gas supplies: LNG exports along the Gulf Coast. Most of the U.S. well shut-ins since the recent oil price collapse are concentrated in oil-focused shale plays, and gas volumes associated with those wells will be the hardest hit. However, a number of gas-focused Marcellus/Utica producers also have announced or escalated supply curtailments in recent weeks, as they wait for associated gas declines to buoy prices enough to support drilling. The pullback has had immediate effects on the region’s production volumes and supply-demand balance. Today, we provide an update on the latest Appalachia gas supply trends using daily gas pipeline flow data.
Daily energy Posts
In the stormiest market environment for crude oil in many years, it’s hard to find a spot where the sailing is smooth. If even-keel conditions exist anywhere in the oil-producing world today, it might be the offshore Gulf of Mexico, where producer decisions to invest in new platforms or subsea tiebacks are based on very long-term oil-price expectations and the production, once initiated, is steady. In the second half of the 2010s, Gulf producers significantly reduced the average breakeven prices needed to justify their most promising new investments — from more than $55/bbl back in 2015 to less than $35/bbl today. Given what’s happened to crude oil prices the past few days, however, it’s logical to wonder whether any of even the best prospective Gulf of Mexico projects will be sanctioned this year. Today, we discuss how cost-cutting and efficiency improvements have made the offshore Gulf a comparatively steady, growing base of U.S. crude oil production that so far has been less vulnerable than shale output to oil-price gyrations.
The collapse in crude oil prices and COVID-19’s very negative effects on global gasoline, jet fuel and diesel demand are putting an unprecedented squeeze on U.S. refiners. Even before the initial coronavirus outbreak in Wuhan, China, started to grab headlines around New Year’s Day, refineries had already been incentivized to shift their refined products output toward diesel, which can be used to help make IMO 2020-compliant low-sulfur bunker. Now, with the COVID-19 pandemic spreading to Europe and North America and stifling consumer transportation fuel demand, the price signals are even stronger, pushing refineries to do everything they can to minimize their gasoline and jet fuel production and enter what you might call “max diesel mode.” Today, we discuss how there are challenges and limits to what they can do, and a number of refineries may need to shut down due to lower demand, at least temporarily.
Statewide shelter-in-place orders, worldwide business shutdowns, market meltdowns, medical calamities. Much of what is going on right now is unprecedented in the modern era, and there are no guideposts to help predict what happens next to the world as we knew it. But in the boom-bust energy sector, it is déjà vu all over again. We have seen steep drops in prices, drilling activity and production enough times to have some idea about how this is likely to play out. Granted, this time around it is particularly bad, but that doesn’t change the sequence of events that we are likely to experience over the coming months and years. Today, we’ll look back at what happens to Shale-Era basins after a price collapse, focusing on the inherent lag between a major reduction in activity level and the inevitable production response.
You wouldn’t know it yet from outright crude oil production volumes, which stood at 13.1 MMb/d last week, but with crude oil prices in the cellar, the situation for U.S. E&P companies has rapidly gone from bad to worse. The double whammy of the coronavirus and the Saudi’s decision to flood oil markets with new production has cast a pall over the U.S. E&P sector, sending share prices plummeting. Producers had already taken a stripped-down approach to 2020 investment, with previous guidance reducing capital expenditures by 14% in order to boost free cash flow and hike shareholder returns. That was on top of the 7% decline in capex seen in 2019. But in the last 10 days, about half of the 42 E&P companies we track have announced further, substantial cuts in planned capex. And with West Texas Intermediate prompt crude oil futures settling at $25.22/bbl yesterday — well below breakeven for many producers — and still-lower prices a real possibility, more industry-wide reductions are looming as first-quarter earnings are announced in April. Today, we break down what the recent announcements mean for capex and production volumes.
Well, now we all know how it feels when the bottom falls out. In fact, it seems there is no bottom, with WTI crude at Cushing settling on Wednesday at $20.37/bbl, down $6.58/bbl. There is no point in belaboring the sad story here. You can read about pandemics, OPEC price wars and collapsed markets in every periodical on the planet. Likewise, there is no point in trying to predict what will happen next. Any pundit who tries to predict future prices in this environment is picking numbers out of the air at best. But at RBN, we are energy market analysts. As such, we are compelled to analyze something. And in these market conditions, there is one thing we can hang our hat on: No matter how bad things get, hope springs eternal. Thus, the market consensus is that things will be better a year from now, and even better a year after that. The implication? In a flash, crude is in steep contango, and that has repercussions for pipeline flows, regional price differentials and for storage — in production areas, at refineries, in VLCCs on the water, and especially at Cushing, OK, the king of oil storage hubs. Today, we examine one aspect of the chaos that now envelopes all aspects of energy markets.
Throw out your old production forecasts. Delete your pricing model spreadsheets. Push out the dates on your infrastructure project timelines. Or kill the projects all together. We’ve got a black swan on our hands here, folks. Perhaps a flock of black swans. And while we may see something like normal again in a few months, there is little doubt that it will be an entirely new normal. How do we even think through the wrenching transformations that are working through energy markets? At RBN, we don’t have any more answers than anyone else, but we do have a structured approach to market analysis supported by a set of spreadsheet models that are the core of our School of Energy, scheduled for April 14-15. We think that’s exactly the kind of approach necessary to make sense out of this volatile and chaotic market. And although we have cancelled the in-person conference, we’ve made the decision to GO VIRTUAL! Today, we explain our decision to move forward with the virtual School of Energy and discuss the new material we are incorporating into the curriculum to address today’s market realities.
With a number of U.S. producers slashing their drilling plans for 2020, crude oil production may flatten or even decline somewhat in the oil-focused basins over the next few months. Still, large volumes of crude — somewhere north or south of 3 MMb/d — will need to be exported from Gulf Coast docks for the foreseeable future to keep U.S. supply and demand in relative balance. That raises the questions of whether more export capacity will be needed, and if so, how much and when? The answers to these questions depend in large part on how much crude the existing marine facilities in Texas and Louisiana can actually handle. Today, we begin a series that details the region’s export-related infrastructure and examines its capacity to stage and load export cargoes this year and beyond.
The natural gas market dynamics that were expected to turn gas flow patterns and price relationships in the Eastern U.S. on their heads and, in turn, transform supply-demand dynamics in Louisiana — including around the U.S. price benchmark Henry Hub — have come to fruition. LNG exports have surged as new liquefaction and export terminals have come online, injecting a new demand source along the Louisiana coastline. Producers have lined up to serve that demand. And midstreamers have worked to get the gas there, reversing and expanding existing northbound pipelines to move gas south into and through the Bayou State. Now, Louisiana’s gas market is nearing a critical juncture: the pipelines that connect the supply gateways in northern Louisiana to the demand centers along the Gulf Coast are nearing saturation. Today, we begin a series providing an update on Louisiana’s gas pipeline constraints and the projects lining up to alleviate them.
The crude-oil price crash of the past couple of weeks is forcing producers in every U.S. shale play to reassess their drilling-and-completion plans for the balance of 2020. Still, while the pace of activity in the Permian, the Bakken and other major plays may slow somewhat in the coming months if crude prices stay low, the vast majority of the new wells that are drilled will need to be connected to crude gathering systems — ideally ones that offer producers and shippers a high degree of destination optionality. Today, we continue our series on crude-related assets in western North Dakota with a look at another leading midstreamer’s gathering system, and its link to the Dakota Access Pipeline and a nearby refinery.
New U.S. liquefaction trains and export terminals have added LNG to an oversupplied global market. International gas prices are at their lowest levels in several years, price spreads between the U.S. and destination markets have collapsed and — to make matters even worse — a coronavirus pandemic threatens to undermine LNG demand growth. U.S. LNG exports nevertheless have been increasing with each new liquefaction train that comes onstream, though, mostly because their long-term offtake contracts make cargo liftings relatively insensitive to global prices. The question is, will dire global market conditions somehow undo U.S. LNG production growth? Today, we discuss highlights from our new Drill Down Report on the future of U.S. LNG exports.
It’s a new world, folks. The Saudis and Russians, who until a few days ago had been trying to prop up crude oil prices through supply management, are now engaged in an all-out war for market share. Crude oil prices are sharply lower. Three weeks ago, West Texas Intermediate was selling for $53/bbl and Western Canadian Select for $37/bbl; yesterday, they were selling for $34/bbl and $22/bbl, respectively. And things may get worse. All this has profound implications for North American production, but the effects on production in U.S. shale plays versus the Canadian oil sands will be very different. Today, we explain how the oil sands provide steady-as-she-goes baseload supply through pricing peaks and valleys while U.S. shale plays serve as a global swing supplier.
Canada has been facing a similar situation to the U.S. in recent years in which the production of natural gas liquids, such as propane, has been rising sharply thanks to a focus on liquids-rich gas wells in unconventional gas plays. In response to the rising bounty of propane, infrastructure development in Canada has focused on export projects, and in 2019, the completion of the new Ridley Island Propane Export Terminal in British Columbia enabled the first overseas exports of propane from Canada’s west coast, allowing Western Canadian producers to access destination markets beyond just the U.S. for the first time. Later this year, Pembina Pipelines, a developer of energy infrastructure projects across Western Canada, will complete a new propane export terminal just outside Prince Rupert, BC, further boosting propane exports to overseas markets. Today, we take a closer look at propane supply issues, Pembina’s new propane export terminal and recently announced plans to further expand the terminal’s export capacity.
On Friday, global energy markets entered uncharted territory. Already facing declining demand due to the impact of COVID-19, markets then were dealt a body blow with the collapse of the OPEC-Plus alliance and the resulting prospect of a significant increase in supply. Saudi Arabia wanted to manage supply to balance against lower demand, but Russia was having none of it. Instead, reports from the OPEC-Plus meeting indicate that Vladimir Putin has declared war on U.S. shale. Then on Saturday, the plot thickened. Saudi Arabia made huge cuts in the price of its crude oil, presumably in a high-stakes move to bring Russia back to the negotiating table. Even though we are witnessing unprecedented market conditions, it’s not Armageddon. Crude oil will continue to be pumped, piped, shipped and refined. Most infrastructure projects under construction before the collapse in oil prices will be completed. The big question is, how will the market adapt? In today’s blog, we’ll begin an exploration of that question.
It’s been a good couple of years for many of the midstream companies active in the Bakken. Crude oil-focused drilling and completion activity has rebounded from a mid-decade slump, flows through their crude and gas gathering systems have been rising, and gas processing constraints that had threatened continued production growth have been on the wane. All that has led Bakken producers to plan for further gains in output in 2020 –– though that may change as the economic effects of the coronavirus become clearer. In any case, production growth is only possible if there’s sufficient gathering infrastructure in place to handle it. Today, we continue our series on crude-related assets in western North Dakota with a look at two midstreamers that have experienced big gains in their Bakken crude-gathering volumes.
Unlike most natural gas producing jurisdictions in North America facing a pullback in drilling and capital spending, producers in Western Canada appear to be doing the opposite and lining up for a year of rising production, higher average prices and additional pipeline capacity from producing basins. In short, 2020 should be a year in which supplies in the region mount a comeback after the dismal down year for supplies — and prices — that characterized 2019. A good part of that supply and pipeline capacity growth optimism has to do with a major pipeline expansion out of the Montney Basin in northeastern British Columbia that just recently entered service. Dubbed the North Montney Mainline and operated by Canada’s largest gas pipeline company, TC Energy, this vital piece of new pipeline egress from one of the most prolific unconventional gas basins in North America is setting up Western Canadian gas supplies for recovery in 2020 and beyond. Today, we continue our series with a look at what this may portend for gas supplies this year.