Permian wells are churning out 22 Bcf/d of residue natural gas, but for many producers that gas abundance is a hindrance. A persistent shortfall in takeaway capacity has made negative prices at Waha an all-too-regular thing. But the situation will soon be changing for the much-better.
Market signals are suggesting that we’re on the cusp of another midstream revival. Higher crude oil and natural gas prices are prompting producers to ramp up output, and higher production will lead to increasing midstream constraints and cratering supply prices. We’ve seen this reel before and in past cycles, midstreamers would swoop in right about now with plans for a host of pipeline expansions to relieve bottlenecks and balance the market again. The problem is that for capacity to get built, you need producers to sign up with long-term commitments, and that’s the catch. Wall Street has drawn a hard line when it comes to capital and environmental discipline in the energy industry, and regulatory support for hydrocarbon newbuilds has waned. This is especially a problem for two major basins — the Permian and Marcellus/Utica — but is liable to affect producer behavior across the Lower 48. In today’s RBN blog, we take a closer look at how this will play out at the basin level, starting with the Permian.
This year has been a mixed bag for Appalachian natural gas producers. Outright prices in the region are higher than they’ve been in a few years, thanks to lower storage inventory levels and robust LNG export demand. However, regional basis (local prices vs. Henry Hub) is weaker year-on-year as higher production volumes have led to record outbound flows from Appalachia and are threatening to overwhelm existing pipeline takeaway capacity. Last month, Equitrans Midstream officially announced that the start-up of its long-delayed Mountain Valley Pipeline (MVP) project will be pushed to summer 2022 at the earliest. Then, just last week, outbound capacity took another hit as Enbridge’s Texas Eastern Transmission (TETCO) pipeline was denied regulatory approval to continue operating at its maximum allowable pressure, effectively lowering the line’s Gulf Coast-bound capacity by nearly 0.75 Bcf/d, or ~40%, for an undefined period. Today, we consider the impact of this latest development on pipeline flows, production, and pricing.
A combination of new-pipeline development, lower capex by producers, production shut-ins, and changing expectations for future production has significantly altered crude oil and natural gas market fundamentals in the all-important Permian Basin. Just over a year ago, Permian production was rising steadily and oil and gas pipelines out of West Texas were running at or near full capacity. Since then, nearly 2.2 MMb/d of incremental crude takeaway capacity has come online, and production dropped by about 700 Mb/d before rebounding somewhat in recent weeks. As for gas, some takeaway constraints remain, but they are limited to when pipelines are offline for maintenance, and will be alleviated when new pipelines start operating in 2021. Today, we discuss the recent downs and ups in Permian production, takeaway capacity additions, and the resulting impacts on markets and market participants.
The rapid increase of natural gas processing capacity in the Bakken in recent months has helped to ease producers’ growing pains, clearing the way for more crude oil and associated gas to be produced there and more Bakken gas to flow into the Midwest. That good news is countered, however, by bad news for Western Canadian gas producers, whose long-standing pipeline takeaway constraints only worsen as more Bakken gas flows into the Northern Border pipeline that cuts through North Dakota on its way to Chicago and other downstream markets. Today, we continue our series on the fight between Bakken and Western Canadian producers for space on Northern Border with a look at incremental flows into that key pipe.
Crude-by-rail has saved the day for Alberta producers before, and it’s about to again. The talk of the Western Canadian province the past few days has been the Alberta government’s October 31 announcement that it will allow incremental crude oil production beyond the province’s 3.8-MMb/d cap — if that crude is transported to market by rail. Within hours of the government’s statement, a trio of major producers indicated that they now expect to ramp up their Alberta output by a total of more than 100 Mb/d over the next few months, with a good bit of the gain occurring by year’s end. Production increases from others are likely to follow, as are parallel plans to load that crude into tank cars and rail it to market. But can Alberta producers really thrive without more pipeline capacity? Today, we review recent developments in “Canada’s Energy Province” and what they mean for producers and Alberta crude prices.
Crude oil and natural gas production in the Bakken are at all-time highs, as are the volumes of gas being processed in and transported out of the play. The bad news is that for the past few months, the volumes of Bakken gas being flared are also at record levels, and producers as a whole have been exceeding the state of North Dakota’s goal on the percentage of gas that is flared at the lease rather than captured, processed and piped away. State regulators last week stood by their flaring goals, but in an effort to ease the squeeze they gave producers a lot more flexibility in what gas is counted — and not counted — when the flaring calculations are made. Today, we update gas production, processing and flaring in what’s been one of the nation’s hottest production regions.
Right now, pipeline capacity out of the Permian is constrained, and consequently some producers have cut back on well completions, more gas is getting flared, and ethane recovery is being driven more by bottlenecks than by gas plant economics. But even with these issues, there are still 487 rigs drilling for oil in the basin (according to Baker Hughes), and all will come along with sizable quantities of natural gas. Not only does this production need to be moved out of the Permian, the volumes need to find a home — either in the domestic market or overseas. These were all issues that were considered by our speakers, panelists and RBN analysts last month at PermiCon, our industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. In today’s blog, we continue our review of some of the key points discussed during the conference proceedings.
Permian oil and gas production may have slammed up against capacity constraints, but that does not mean production growth has ground to a halt. Far from it. In the past 10 weeks, Permian gas production is up another 8% — a gain of almost 700 MMcf/d. Crude production now tops 3.5 MMb/d, with incremental barrels finding their way to market via truck, rail and new pipeline capacity — soon including Plains All American’s new Sunrise project, which will move more Permian crude toward the hub in Cushing, OK. Record-setting volumes of NGLs are streaming their way out of the Permian to Mont Belvieu. This market is moving so fast that if you blink, you’ll miss something important. So to get caught up with all things Permian, last week RBN hosted PermiCon, an industry conference designed to bridge the gap between fundamentals analysis and boots-on-the-ground market intelligence. We think PermiCon accomplished that goal, and in today’s blog, we summarize a few of the key points discussed during the conference proceedings.
The late-August decision by Canada’s Federal Court of Appeal to overturn the Canadian government’s approval of the Trans Mountain Expansion Project will delay the project’s completion to at least 2021 or 2022. And — who knows? — the unanimous ruling may ultimately lead to TMX’s undoing, despite the Canadian government’s acquisition of the existing Trans Mountain Pipeline and the expansion project and its commitment to get TMX built. As producers in the Western Canadian Sedimentary Basin (WCSB) know all too well, TMX’s 590 Mb/d of incremental pipeline capacity would help to resolve ever-worsening pipeline takeaway constraints out of the Alberta oil sands and other production areas in the WCSB. These constraints are having a major economic impact every day — as evidenced by price differentials wide enough to run a locomotive through. Speaking of trains, crude-by-rail exports out of Western Canada reached a record 205 Mb/d in June, an 86% increase from the same month last year, and with WCSB production rising as new oil sands capacity comes online and with only limited relief likely on the pipeline capacity front from the Enbridge Line 3 Replacement Project in late 2019, many producers will need to depend on rail shipments of crude well into the 2020s. Today, we discuss the recent court ruling and what it means for Western Canadian producers, price spreads and the future of crude-by-rail.
