Crude oil production in Western Canada has been rising steadily for most of the past decade. Unfortunately, the same cannot be said for its oil pipeline export capacity to the U.S., which has generally failed to keep pace with the increases in production. Dogged by regulatory, legal, and environmental roadblocks, permitting and constructing additional pipeline takeaway capacity has been a slow and complicated affair, although progress continues to be made. The most recent tranche arrived last month with the start-up of Enbridge’s Line 3 Replacement pipeline, which provides an incremental 370 Mb/d of export capacity and should help to shrink the massive price discounts that have often plagued Western Canadian producers in recent years. In today’s RBN blog, we discuss the long-delayed project and how its operation is likely to affect Western Canada’s crude oil market, now and in the future.
Daily Energy Blog
Admittedly, the idea of capturing carbon dioxide, cooling and compressing it into a weird, neither-liquid-nor-gas state, and pumping it deep underground for permanent storage would have baffled the crude oil wildcatters and pipeline builders that created the modern energy industry back in the 1940s and ’50s. They’d surely say, “You’re proposin’ to do what?!” But times have changed. The oil and gas business is entering an extraordinary era of transition, and producers, midstreamers, and refineries alike need to keep abreast of what’s happening regarding carbon capture and sequestration (CCS), how it will affect them, and — ideally — figure out ways to profit from it. That’s the impetus behind today’s RBN blog, in which we begin a deep dive into efforts to reduce emissions of man-made CO2 by capturing it from industrial sources and piping it to specially designed wells for permanent storage.
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.
For all who thought an energy transition was going to be orderly, economic, or rational, the chaos of 2021 energy markets is a wake-up call. It’s not that the shift from fossil fuels to renewables is causing most of the market turmoil, but it is certainly magnifying the effects of a host of energy market glitches that, together with the mechanics of the transition, are wreaking havoc on the global economy. Which underscores the challenge of this generation: We must live, work, and produce hydrocarbons the way the world functions today, while at the same time preparing for — and investing in — a much-lower-carbon future. As we’ve heard this week from Glasgow, it’s a future that a lot of folks believe means net-zero greenhouse gas emissions and no hydrocarbons. That challenge is the underlying theme for RBN’s Fall 2021 School of Energy, to be held next week, November 9-10. Not only have we restructured our agenda to include a half day covering the impact of hydrogen, CO2 sequestration, and renewable diesel, we’ve reworked and updated our core hydrocarbons market curriculum to examine how crude oil, natural gas, and NGL markets will evolve to accommodate what lies ahead. In today’s encore RBN blog edition — a blatant advertorial — we’ll consider these issues and highlight how our upcoming School of Energy integrates existing market dynamics with prospects for the energy transition.
The U.S. oil and gas industry’s upstream sector has seen more than its share of mergers and acquisitions in the year and a half since COVID-19 put energy markets on a wild roller coaster. ConocoPhillips buying Concho Resources and then Shell’s Permian assets. Chevron snapping up Noble Energy. Pioneer Natural Resources acquiring Parsley Energy. And yesterday’s big news: Continental Resources’ planned purchase of Pioneer’s assets in the Permian’s Delaware Basin. It’s not just hydrocarbon producers that are consolidating and expanding, however. There’s also been a flurry of large-scale M&A activity in the midstream sector, mostly involving oil and gas gatherers in the Permian and the Bakken — the nation’s two largest crude oil-focused basins. What’s driving these combinations? In today’s RBN blog, we begin a review of recent, major pipeline-company combinations and the benefits participants expect to realize from them.
After a record-breaking year in which the Japan-Korea Marker topped $30/MMBtu, it looks like 2022 could finally be the year when multiple projects in the long-awaited “second wave” of North American LNG export facilities reach final investment decisions. Developers, financiers, and offtakers are all taking their time, however, to make sure projects make sense in the long term. The recent run of high prices comes after years of price declines and a COVID-related price collapse in 2020, which reduced the spreads between U.S. production and LNG destination markets, slowing the pace of LNG project development. One thing’s clear: Asia — always the focus of LNG demand growth — will become even more important going forward, and perhaps the best way to attract Asian offtakers to U.S., Canadian, and Mexican projects is to export from the Pacific Coast, assuming that feedgas can be sourced and delivered easily. In today’s RBN blog, we conclude our series on Pacific Coast LNG export development, this time focusing on projects in Western Canada.
In the past few months, there’s been a flurry of interest in certified responsibly sourced gas (RSG). RSG is natural gas — it still comes out of wells in the Marcellus, Haynesville, Permian, and other U.S. production areas. What distinguishes RSG is that its producers and pipeline companies have made efforts to significantly reduce the greenhouse gases — mostly methane — that are needlessly emitted along the value chain, and that an independent and respected outsider has certified the success of these efforts. RSG is still new to a lot of folks, including those in the natural gas business, so it’s reasonable to ask, who does the certifying, and what are the differences between them? In today’s RBN blog, we continue our series on RSG with a look at the different approaches taken by RSG certifiers: Project Canary and MiQ.
The U.S. natural gas market is primed for supply growth. The Lower 48 supply-demand balance is the most bullish it has been in years. Exports are at record levels and poised to increase with additional terminal expansions on the horizon, while international prices have recently notched record highs. Henry Hub gas futures prices are at the highest in over a decade. So, producers will unleash a torrent of natural gas, triggering a midstream build-out like we’ve seen in the past, right? Not so fast. The world has changed. For additional capacity to be built, you need producers or utilities to commit to use it. But Wall Street has drawn a hard line when it comes to capital and environmental discipline in the energy industry and regulatory approvals can also be an uphill battle. Therein lies the conundrum. More midstream capacity is needed for production to grow, but it’s harder than ever for that infrastructure to get built, which means constraints for some period of time are all but a certainty. Natural gas may not be as constrained as crude oil, but it is already butting up against capacity in parts of the Permian and Marcellus/Utica. And in the crude-focused Permian, those gas constraints will also cascade to crude production. In today’s RBN blog, we consider the implications of the new world order.
A major driver for global growth in natural gas use, including LNG, derives from the power-generation sector. Large Japanese utilities introduced LNG into the power fuel mix in the early 1970s. More recently, a number of utilities in other countries have increased their use of gas-fired generation — and their imports of LNG — largely due to gas’s lower emissions profile and the flexibility that gas plants offer in balancing variable demand loads with variable dispatch profiles, including wind farms and solar facilities. The growing availability of LNG has also spurred interest among independent power producers (IPPs) in developing similar gas-fired projects, but so far fewer than 10 such projects have come online and some do not operate at their full potential. Why has LNG-to-power made such little headway in the independent-power segment? In today’s RBN blog, we examine the special nature of IPP-owned LNG-to-power projects and the challenges they pose not only to their sponsors but to LNG suppliers.
The recently announced acquisition of Questar Pipeline LLC by Southwest Gas has stirred up a hornet’s nest. Southwest sees it as a milestone moment that will allow it an increased role in the energy transition, but activist investor Carl Icahn sees it as a serious blunder that would make all previous management missteps pale in comparison. As Dave Mason sang in “We Just Disagree,” a dispute over value is at the heart of the matter, one which has led to a proxy fight, a tender offer for Southwest Gas, and a lot of harsh words. In today’s RBN blog, we take a closer look at Questar’s natural gas pipelines and other assets, the roles they play in relation to the Rockies’ other pipelines, and how it all factors into Questar’s perceived value.
Crude oil prices continued to increase this week, with WTI at Cushing closing Tuesday at $84.65/bbl, the highest level since October 13, 2014. The rise in crude since the spring of 2020 has been swift and almost relentless, interrupted only by pauses at $40, $60, and $70, when the market took breathers and seemed to say to itself, “We’re not done yet, right?” The question now is, can anything stop WTI from topping $90 and yes, the magic $100 mark — something that few would have predicted we’d see again so soon . The reality is, there are many factors driving crude prices higher but few holding prices down. In today’s RBN blog, we discuss what’s driving the rapid run-up in oil prices, whether $100/bbl WTI is a sure thing, and what happens if — when? — oil hits triple digits.
Some things you can pretty much count on this time of year, like the end of 100-degree days in Houston, Aggies rooting against Longhorns, and the Astros in the World Series. Permian natural gas production has also been consistently higher the last few years. It’s usually on its way to new highs as we approach the holidays and 2021 is another fine example. After a bang-up 2020, this year has been one of continuously solid gas production growth in the Permian, with gas volumes currently sitting near 14 Bcf/d, up around 1.5 Bcf/d versus this time last year. What’s more, at today’s crude oil prices, which encourage increasing production of oil and associated gas, there is no end in sight for Permian gas growth. Which means, as many gas traders already know, that the Permian’s primary gas market, the Waha Hub, may soon be headed back into the familiar territory of deep basis discounts. In today’s RBN blog, we look at the latest developments in Permian gas markets.
It seems that hardly a week goes by without another announcement on responsibly sourced natural gas (RSG). Either in response to rising interest among electricity generators, gas-distribution utilities, and gas-consuming industrials in procuring RSG or as proactive moves to boost their own ESG cred, a number of players in the gas sector — from producers to pipeline companies to LNG exporters — have been working to qualify their natural gas, their long-haul pipes, or their liquefaction plants for RSG status. A few producers have also been reaching deals to supply independently verified RSG to the market, with the expectation that at least a subset of gas/LNG buyers will be willing to pay the price premium involved. But all this is relatively new, and there’s still a lot that needs to be sorted out on the RSG front. In today’s RBN blog, we continue our series on RSG with a look at recent announcements and the associated challenges when selling RSG.
None of us knows with any certainty how big a role hydrogen will ultimately play in helping the U.S. and the rest of the world decarbonize. Sure, some true believers are convinced H2 is the next big thing, but even they must acknowledge the economic and other challenges associated with scaling up the production of “green” or “blue” hydrogen. Do we really want to devote the energy from thousands of wind turbines or many square miles of solar panels to produce relatively small volumes of green H2 from water via electrolysis? And is blue hydrogen — produced by breaking natural gas into hydrogen and carbon dioxide, then capturing and sequestering the CO2 — really a solution considering efficiency losses and the fact that only about 50% of the CO2 from steam methane reforming (SMR) units is actually snared? Which brings us to Air Products & Chemicals’ newly announced final investment decision (FID) on a $4.5 billion complex in Louisiana that will use a proprietary process — and not SMR — to produce what you might call deep-blue hydrogen and capture and sequester 95% of the resulting CO2. In today’s RBN blog, we discuss the project and its implications.
For many years, the exploration and production sector of the oil and gas business was notorious for its profligate ways. When energy prices were high and money was flowing in, many E&P companies would spend like Beyoncé. But the commodity price volatility of the past few years gave E&Ps a new-for-them financial discipline. Even when prices rebounded, they held down their capital spending, and focused on paying down debt and returning cash to shareholders in the form of stock buybacks and dividends. But there’s been a shift in all that lately, with a bigger share of the inflowing money now being used to build cash balances. In today’s RBN blog, we analyze recent cash flow allocation by the 38 E&Ps we monitor and examine what this new shift may mean.
