A long, long time ago — or, more precisely, in the spring of 2014, when WTI was selling for more than $110/bbl — a handful of exploration and production companies were convinced they were onto something big in southwestern Mississippi and east-central Louisiana. There, they believed, the Tuscaloosa Marine Shale (TMS) was poised to become the next Bakken, the U.S.’s premier shale play at the time, but even better for producers seeking more robust crude prices because of TMS’s very low gas-to-oil ratio — an oil cut north of 92%! –– and proximity to Gulf Coast refineries. While there had been a host of failed efforts by producers to wring out large volumes of premium-priced Louisiana Light Sweet (LLS) oil from the marine shale’s sedimentary silts and clays, the E&Ps felt in their bones that they were finally “cracking the code.” Then, at just the wrong time, came an oil price crash that set the whole industry back on its heels and activity in the TMS quickly slowed to a crawl. As we discuss in today’s RBN blog, an even smaller cadre of Tuscaloosa Marine Shale true believers is now banking on a production revival in the core of the play.
Recently Published Reports
|NATGAS Appalachia||NATGAS Appalachia - September 22, 2021||3 days 9 hours ago|
|Crude Gusher||Crude Oil GUSHER - September 22, 2021||3 days 11 hours ago|
|NATGAS Billboard||NATGAS Billboard - September 22, 2021||3 days 17 hours ago|
|Canadian Natgas Billboard||Canadian NATGAS Billboard - September 22, 2021||3 days 18 hours ago|
|Hydrogen Billboard||Hydrogen Billboard - September 22, 2021||3 days 19 hours ago|
Daily energy Posts
Energy markets are red hot and are showing no signs of cooling off anytime soon. Natural gas prices have soared 20% to $ 4.615/MMbtu in just the last couple of weeks and could soon breach $5/MMBtu. In the NGL market, propane prices are up to $1.17/gal, the highest level for the month of September since 2011, with the possibility of shortages threatening domestic suppliers this winter. Even crude oil has continued to find support near the $70/bbl range, providing remarkable drilling and completion economics for well-positioned E&Ps. All these markets are data-intensive, and it can be a challenge to keep up with the most important developments. That’s what our ClusterX app is all about. It delivers to your phone or browser everything we believe is important as soon as the information hits RBN databases. And it is free! In today’s blog, we’ll look at some of the key capabilities of ClusterX, including a number of new features we’ve added. Warning: Today’s blog is a blatant advertorial for ClusterX.
The seven years since the heady days of $100/bbl oil in mid-2014 have been a tumultuous time for midstream companies tasked with funding a massive infrastructure build-out to support surging crude oil and natural gas production. Midstreamers have been buffeted by volatile commodity prices, waves of E&P bankruptcies, rapidly shifting investor sentiment, and, finally, a global pandemic. Perhaps no company has had a more challenging road than master limited partnership (MLP) Plains All American, which had to cut unitholder distributions three times over a turbulent five years as it built out a crude gathering and long-haul transportation portfolio focused on the Permian Basin. With its capital program winding down, commodity prices rising, and a new joint venture in the works, can Plains performance rebound and win back investor support? In today’s blog, we discuss highlights from our new Spotlight report on Plains, which lays out how the company arrived at this juncture and how well-positioned it is to benefit from the significant recovery in commodity prices and Permian E&P activity.
The year-on-year gain in U.S. LNG feedgas demand has been the single biggest factor behind the soaring natural gas prices and storage shortfall this year. And there is more of that demand on the horizon. Cheniere Energy’s Sabine Pass Train 6 and Venture Global’s new Calcasieu Pass facility are due to start service in the first half of 2022. However, feedgas volume is likely to ramp up ahead of the new year as both projects progress through the commissioning phase and aim to export their first commissioning cargoes before the end of the year. How soon could that incremental feedgas demand show up? Getting a handle on the timing requires an understanding of how a liquefaction plant works and the various steps of the commissioning process. Today, we start a short series on what’s involved when bringing a liquefaction plant online and what that can tell us about the timing of incremental feedgas flows this fall/winter.
In the past four years, natural gas production in the Permian Basin has doubled — from 6.6 Bcf/d in August 2017 to 13.4 Bcf/d now. To keep pace, the midstream sector has spent many billions of dollars on new gas gathering systems, processing plants, and takeaway pipelines, with virtually all of that investment backed by long-term commitments from producers and other market players. Thanks to that build-out, the Permian now has sufficient takeaway capacity — at least for another couple of years. But despite the 50-plus processing plants that have come online in the play’s Delaware and Midland basins in recent years, still more processing capacity is needed, as evidenced by the expansion projects and new plants that we discuss in today’s blog.
California has a long history of leading the U.S. in environmental regulations and of taking federal environmental rules to the next level. Back in the 1960s, for example, the state became the first to regulate emissions from motor vehicles. In more recent decades, it has led the way in reducing greenhouse gas emissions. Many of these progressive regulations migrate to other states over time, which adds significance to a Northern California environmental agency’s recent decision to put stricter limits on emissions from refinery fluidized catalytic cracking units, or FCCUs. In today’s blog, we discuss the new regulation and its potential implications.
U.S. LNG is in the midst of a record-breaking year. Total LNG feedgas has averaged nearly 10 Bcf/d so far in 2021 and the country is on track to export somewhere around 1,000 cargoes this year, 40% more than last year. Although pipeline maintenance and flow constraints have knocked feedgas off the all-time highs seen earlier this year, feedgas and exports are likely to hit new record levels to close out the year as Sabine Pass Train 6 and Calcasieu Pass prepare to start service in early 2022. The strength in U.S. LNG export demand this year is underpinned by an incredibly bullish global gas market, which has led prices in both Europe and Asia to hit all-time highs. This has not only benefited the existing fleet of terminals, but the prolonged bullish global gas market has accelerated commercial activity for future LNG projects. Since May, more than 12 MMtpa of capacity from LNG terminals or liquefaction trains under development has been sold, pushing several prospective LNG projects closer to a final investment decision (FID). RBN covers all of the latest in our LNG Voyager Quarterly report, but in today’s blog, we take a look at some of the highlights from the report, focusing on the biggest changes in LNG development this summer.
This summer’s resurgence of the COVID-19 pandemic in many parts of the world will wreck forecasts of demand for petroleum products and, therefore, for crude oil. Most oil-market forecasts published in the first half of 2021 didn’t anticipate the 75% jump in new weekly coronavirus cases that has occurred since mid-June, or new possibilities for travel limits and other restrictions of the type that clobbered economies — and oil demand — around the globe in 2020. Obviously, swerves away from expectations for oil consumption scramble the supply-demand balances widely used in oil-market analysis. But they do happen. In fact, deviation between forecast and actual demand is the rule, not the exception. It’s just not always as extreme as the balance adjustments likely to be needed after the latest COVID surprise. Even when there’s no deadly pandemic to worry about, demand can be tricky to define, difficult to measure, and frustrating to predict. In today’s blog, we discuss the intricacies of oil-demand assessment and explain why balance calculations, based on forecasts destined to be wrong, remain meaningful to analysts mindful of their limitations.
Beginning in 2020 and so far through 2021, we at RBN have devoted a lot of our energy to covering the latest developments in environmental, social and governance (ESG) trends in the energy sector. That’s no accident – in fact, it’s been a necessity. As we recently discussed in Bullet the Blue Sky, environmentally focused initiatives have taken center-stage as society, investors, and governments demand higher standards from companies. The consequences to businesses that don’t heed the new paradigm could be dire for both their reputations and their pocketbooks. As a result, companies up and down the energy value chain have begun examining their operations to identify areas of improvement, particularly as it relates to their greenhouse gas (GHG) emissions. In today’s blog, we’ll focus on one of the most significant of GHGs – methane. We will look at what’s being done to monitor and address those emissions, and how companies may ultimately benefit by reining them in.
The high-demand season for propane is just around the corner: crop drying, then winter heating demand. This is when propane marketers make most of their money; so under normal circumstances it’s a happy time, when all participants across the supply chain are making last-minute preparations for the season of peak propane demand. But this year is different. There is palpable concern in the market about the level of inventories available to meet demand, and the possibility that propane could be in short supply. How could this be? As we have covered many times in the RBN blogosphere, U.S. propane production is more than double domestic demand. So how could a shortage possibly happen? The answer is pretty simple: exports. The U.S. exports more of its propane production than it uses here at home. This year the domestic market needs more barrels, so all that needs to happen is for U.S. prices to increase enough to shut off exports, right? Wrong. Propane prices have been spiraling up all year, and August prices are higher than they’ve been since 2013. But exports are still running strong, and so far, inventories are not building fast enough. In today’s blog, we’ll look at the drivers behind this seeming market aberration and consider why the upcoming winter season looks like uncharted territory for propane marketers.
The volume of natural gas in storage and the flow of gas into and out of it are among the most closely watched indicators in the U.S. gas market. That makes sense, given that these numbers provide important weekly insights into the supply-demand balance, gas price trends, the impact of LNG exports, and any number of other market drivers. However, what’s often ignored by those not involved in the day-to-day physical gas market are the mechanics and economics of storage itself. Who uses gas storage, and for what purposes? What are the value drivers for a storage facility? Why are there different types of gas storage contracts? How much does storage cost, and what do storage rates reflect? Today, we explore these and other questions.
The high-tech space programs of Elon Musk, Jeff Bezos, and Sir Richard Branson may seem far removed from the down-to-earth business of producing and processing hydrocarbons. In fact, however, the multibillion-dollar efforts by SpaceX, Blue Origin, and Virgin Galactic to normalize space travel — and maybe even put the first men and women on Mars! — depend at least in part on some pretty basic oil and gas products, including regular jet fuel, highly refined kerosene, and LNG. Oh, and hydrogen too — or, more specifically, the liquid form of the fuel that has recently caught the attention of a number of old-school energy companies. In today’s blog, we look at what’s propelling the latest generation of space vehicles.
Northeast natural gas production in 2021 to date has averaged 34 Bcf/d, up 1.4 Bcf/d year-on-year, and the higher gas price environment currently is signaling more upside to production in the years to come. At the same time, downstream feedgas demand from LNG export facilities is at a record high and also headed higher as more liquefaction capacity is set to come online in the coming months. So, despite lower-than-normal inventory levels in the Northeast, outflows from the Appalachian basin have soared to new highs this year, and utilization of outbound pipeline capacity is up to an average 90%, a level we haven’t seen since the 2016-17 timeframe. Unlike 2016-17, when there was a slew of major pipeline projects to expand egress, now there are just two or three at most — and two of those are greenfield projects that face an uncertain future. As such, spare exit capacity is getting increasingly sparse, and Appalachian producers are bound to hit the capacity “wall” in the next two years. When will the Northeast run out of exit capacity and how bad could constraints get? Today, we provide highlights from our new Drill Down report, which brings together our latest analysis on Northeast gas takeaway capacity and flows.
Supplies of natural gas liquids, especially propane, have become increasingly tight in recent months, with prices reaching multi-year highs in the U.S. and Canada. Despite the strong price signals, increasing production is typically a lengthy, complex, and expensive process involving producers drilling new wells to yield more liquids-rich natural gas and crude oil. There is also another way to increase supplies: by extracting them from already processed and pipelined natural gas via a straddle plant that more intensively recovers additional NGLs, such as propane, from the existing gas supply. Canada’s Wolf Midstream has recently sanctioned such a plant, as well as a related pipeline and extraction plant in Alberta that it hopes to bring into service in 2023. In today’s blog, we examine this new straddle plant and Western Canada’s current propane supply situation.
It’s often said that the offshore Gulf of Mexico is a different animal than its onshore counterparts, especially shale and tight-oil plays like the Permian and the Bakken. Decisions to invest in new production in the GOM aren’t based on crude oil demand and price forecast for the next two or three years; they’re based on expectations for the next two or three decades. Well, 30 years from now will be 2051, a year after Shell and a number of other energy companies have pledged to achieve “net-zero” carbon emissions. What does decarbonization mean for future development in the offshore Gulf, where the upfront capital costs are enormous and wells can be prolific producers for many, many years. In today’s blog, we discuss the final investment decision (FID) on Shell’s Whale project in the western Gulf of Mexico and the prospects for further development in the GOM.
Every day, midstream companies in North America transport massive volumes of crude oil, natural gas, NGLs, and refined products to market. Without their pipelines, economic activity would rapidly grind to a halt. Still, environmental critics and ESG-conscious investors and lenders are quick to point out that the commodities that midstreamers pipe are among the leading sources of greenhouse gas emissions, and that, at the very least, pipeline companies should be reducing or even offsetting the carbon dioxide (CO2) and other GHGs associated with operating their networks. That’s now happening in a big way — and in a variety of ways — as we discuss in today’s blog.