RBN Energy

The oil and gas industry is being pushed by regulators, third parties and investors to better identify and mitigate its methane emissions, especially the few “super-emitter” sites that make outsize contributions to overall emissions. But while operators are ramping up capital spending on new technology, one thing has become clear: There is no silver bullet when it comes to reducing emissions, and each option includes one or more drawbacks, including source attribution, costs, quantification, and detection limits. In today’s RBN blog, we’ll break down the advantages and disadvantages of the different measurement technologies.

Analyst Insights

Analyst Insights are unique perspectives provided by RBN analysts about energy markets developments. The Insights may cover a wide range of information, such as industry trends, fundamentals, competitive landscape, or other market rumblings. These Insights are designed to be bite-size but punchy analysis so that readers can stay abreast of the most important market changes.

By RBN Team - Friday, 3/31/2023 (6:30 pm)

It was a good week for crude oil, with the price of WTI up 9.3% since last Friday.  Today WTI settled at $75.67/bbl, up $1.30/bbl.  The primary driver continues to be the export cuts of 450 Mb/d from Iraq's Kurdistan region.   Oil production in the region is being shut in at several oil fields due to curtailments on a Turkish pipeline.  Crude prices are also being supported by economic data (the U.S.

By Jeremy Meier - Friday, 3/31/2023 (2:30 pm)

US oil and gas rig count declined this week after two consecutive weeks of growth, falling to 755 for the week ending March 31 vs. 758 a week ago according to Baker Hughes.  The Permian (-1), Haynesville (-1) and All Other Basins (-1) all posted small declines.  Total US rig count is down 24 in the past 90 days, and up 82 vs. one year ago.

Daily Energy Blog

It’s been another tumultuous few months for natural gas prices, particularly amid what European Commission President Ursula von der Leyen has called Russia’s war on Europe’s energy and economy.  Europe is staring down aggressive curtailments of Russian gas supplies and rising consumer utility bills, necessitating austerity measures and beyond to bail out consumers and utilities and prevent a dangerous shortfall this winter. Prices in continental Europe have now topped $20/MMBtu for a year, higher than the previous single-day record. On top of the elevated prices, outrageous spikes higher and lower have become a semi-regular occurrence as the gas market struggles to find balance. And high prices and volatility are not going anywhere anytime soon as Europe braces for a winter with little or even no Russian gas. In today’s RBN blog we look at European gas prices, the latest energy policy proposal from the EC and how U.S. LNG exports fit into the ongoing crisis.

Lower 48 natural gas production this month hit a once-unthinkable milestone, topping the all-important psychological threshold of 100 Bcf/d for the first time. Volumes have remained at record highs through mid-September, with year-on-year gains expanding to a breathtaking 7-9 Bcf/d above last year at this time (when hurricane-related shut-ins were in effect). The record production levels coincided with a seasonal decline in weather-related demand, as well as the ongoing outage at the Freeport LNG export terminal. Remarkably, however, even with all-time high, ~100 Bcf/d natural gas production and Freeport LNG offline, the Lower 48 gas market balance averaged tighter year-on-year — a testament to just how strong consumption has been lately, and for much of this summer for that matter. In today’s blog, we look at how the supply-demand balance has shaped up this month and where it’s headed near-term.

With international gas prices ranging somewhere between ridiculous and ludicrous since last fall, the entire global trade of LNG is going through an unprecedented period of change as gas-consuming nations try to cope with the current situation and seek protection from tight supplies and high prices in the future. The problems of Europe in securing supplies for the imminent winter have been well documented here and elsewhere in the trade press. In addition to being a major struggle for consumers and a headwind to economic development, there are also numerous, less-obvious consequences of the tectonic shifts in gas fundamentals, including countries’ individual plans for long-term energy supplies, potential tax-related issues, the contractual structures used to transact LNG, and even the assessments of the commodity price itself. These issues aren’t new and, in many cases, have been discussed for years. What’s changed is that extremely high prices have thrown into sharp relief any inefficiency or risk that exposes market participants. In today’s RBN blog, we consider the impact of high global gas prices on countries in Asia and Europe and how pricing mechanisms might be affected.

The U.S. natural gas market is one of the most transparent, liquid and efficient commodity markets in the world. Physical trading is anchored by hundreds of thousands of miles of gathering, transmission and distribution pipelines, and well over 100 distinct trading locations across North America. The dynamic physical market is matched by the equally vigorous CME/NYMEX Henry Hub natural gas futures market. Then, there are the forward basis markets — futures contracts for regional physical gas hubs. These pricing mechanisms play related but distinct roles in the U.S. gas market, based on when and how they are traded, their respective settlement or delivery periods, and how they are used by market participants. In today’s RBN blog, we continue a series on natural gas pricing mechanisms, this time with a focus on the futures and forwards markets.

Two of the biggest challenges that Europe faces in the race to wean itself off Russian natural gas are the need to develop new pipeline connections between the continent’s many isolated gas networks and to integrate the European Union’s multiple gas markets. Addressing these won’t be easy. Unlike the U.S., whose pipeline systems were designed to transport gas long distances and across jurisdictional lines, Europe’s networks are more regional or even local in nature, and only recently has the EU been taking steps to link the continent’s markets. Oh, by the way, U.S. producers and LNG exporters should care about all this, because if Europe gets its act together, it could become an even larger and longer-term recipient of gas originating from the Permian, Haynesville, Marcellus/Utica and other shale plays. In today’s RBN blog, we discuss the prospects for tying together the EU’s gas pipelines, gas storage facilities, LNG import terminals and gas markets.

The 2022 hurricane season is off to a quiet start, but the tropics seem to have awakened in recent days and are likely to ramp up in September — the peak month for tropical storm activity. Forecasters are still predicting an above-average season, calling for as many as 10 hurricanes and up to five major ones. That would mean greater volatility for energy markets in any year, but the stakes are arguably higher this year than any time in recent memory — especially for natural gas. That’s because prices are already at the highest level in over a decade and flirting with the $10/MMBtu mark. The gas market is tight domestically and globally, particularly in Europe. Lower 48 storage remains near the five-year low. European gas storage, after lagging far behind, has caught up to the five-year average this month, but the continent is still dependent on a consistent stream of U.S. LNG cargoes, particularly as it works to wean itself off Russian gas supplies. What happens when you add to that the prospect of hurricane-related disruptions to Lower 48 production or LNG exports, or both? Much of that will come down to the timing, path and strength of any impending storms. That’s a lot of unknowns, and where there is that much uncertainty, volatility is sure to follow. With the National Hurricane Center (NHC) predicting high chances of potential cyclone development as early as later this week, today’s RBN blog considers the possible implications for the U.S. gas market balance.

We’ve seen this movie one too many times. Just when natural gas prices are rallying across the world to multi-year or historic highs, another monkey wrench gets thrown into the workings of the Western Canadian gas market, imploding its suite of price markers. Last week, gas prices in Western Canada collapsed to mere pennies and even went negative for a time due to an unfortunate combination of pipeline restrictions and record-high production — a situation that will cost the region’s gas industry billions if left unchecked. In today’s RBN blog, we examine the root cause of the latest price collapse and when a turnaround might be expected.

The momentum for U.S. LNG right now is powerful. With Europe’s efforts to wean itself off Russian natural gas boosting long-term LNG demand and Asian consumption expected to grow even further, there has been a strong push for new LNG projects in North America. So far, that has helped propel two U.S. projects, Venture Global’s Plaquemines LNG and Cheniere’s Corpus Christi Stage III, to reach a final investment decision (FID). With these two projects getting a green light, total export capacity in the U.S. will be at least 130 MMtpa — or 17.3 Bcf/d — by mid-decade. That top-line export capacity could be much higher, however. There are currently eight U.S. Gulf Coast pre-FID projects with binding sales agreements, and a handful of projects that are fully subscribed in credible non-binding deals. If all those projects go forward, it would add a staggering 86 MMtpa (11.4 Bcf/d) of export capacity to the U.S., pushing the total toward 30 Bcf/d, or 225 MMtpa. In today’s RBN blog we look at U.S. LNG under development, how high export capacity could go, and the implications for the U.S. natural gas market.

The build-out of natural gas processing plants in the Permian continues unabated. In just the past few days, four of the largest midstream players in the U.S.’s premier hydrocarbon production area have unveiled plans for a combined 1.3 Bcf/d of new processing capacity, most of it in the gassier Delaware Basin portion of the crude-oil-focused play. And that’s on top of the 11.7 Bcf/d of processing that’s already been added in the Permian over the past four-and-a-half years — and the 2.6 Bcf/d of soon-to-be-finished projects announced previously. That’s quite a run, and still more processing plants may be in the cards — if midstreamers build more takeaway-pipeline capacity. In today’s RBN blog, we discuss recent processing-plant and pipeline developments in West Texas and southeastern New Mexico.

Just downstream from the Appalachian supply basin — where daily spot natural gas prices are among the lowest in the country — cash and forward prices in the Mid-Atlantic and Southeast have rocketed, becoming the highest gas prices in the land, and in some cases are at never-before-seen levels for this time of year. No doubt it’s been a sweltering summer so far, and low storage levels aren’t helping either. But there’s more to the price premiums than that. Limited access to supply and constraints on Williams’ Transco Pipeline — the primary system delivering gas to the region — have created a demand “island” there just as persistent heatwaves boosted cooling demand. Moreover, without additional pipeline capacity, the dynamics unfolding this summer could become a regular feature of the Southeast/Mid-Atlantic markets. In today’s RBN blog, we break down the factors driving regional prices to new heights.

Escalating Russian aggression and LNG supply shortfalls, exacerbated by outages in the U.S. and Australia, have put the pressure back on international gas markets and sent prices in Europe and Asia back toward their winter highs. Around the world, high prices have pushed some end users out of the LNG market and spurred on the global, cross-commodity energy shortage that has had utilities and governments scrambling, sometimes unsuccessfully, to keep the power on. The European Union (EU) is pushing its members to reduce gas consumption by 15% through winter and parts of Europe face austerity measures. Some European countries are turning back to coal generation as the continent prepares for the prospect of a winter with less — or potentially even no — Russian gas. In today’s RBN blog, we look at where things stand in the international gas market and the ramifications for the winter ahead and beyond.

Increasing scale. Improving efficiency. Expanding into a fast-growing production area. These are only a few of the many reasons that midstream consolidation has remained an ongoing phenomenon in U.S. oil and gas basins — nowhere more so than in the Permian. The slew of acquisitions, mergers and joint ventures announced in the past couple of years is resulting not only in more concentrated ownership of midstream assets in West Texas and southeastern New Mexico, but in large, smooth-running systems for gathering, treating and processing hydrocarbons and transporting them to market. In other words, in magnificent molecule-moving machines. With today’s RBN blog, we begin a short series on the latest round of midstream M&A activity in the U.S.’s hottest production area.

Europe’s push to reduce and eventually eliminate its reliance on Russia for natural gas has pushed LNG imports back into the forefront of Europe’s long-term energy plan. This year, with European natural gas prices trading above Asian prices, the continent has been able to attract an incredible amount of LNG, with imports at record levels this winter and sitting just shy of those records this spring. That helped mitigate some of the risks to energy reliability from Russian aggression, at least until the Freeport LNG outage and the latest Russian gas curtailments, but import capacity in Europe was maxed out last winter and more LNG imports can’t happen in the long term without more import capacity. Most of the LNG terminals in Europe are operating at full capacity or don’t have enough market access on the other side of the pipe to take more. While plans to build new import terminals are underway, those take time, and lots of it, so Europe is also pursuing a more immediate option, floating storage and regasification units (FSRUs) — basically, an LNG import terminal on a ship. In today’s RBN blog, we take a look at all things FSRU, from what and where they are to the recent deals with European offtakers.

Canadian gas storage levels concluded the most recent heating season at multi-year lows, especially in the western half of the nation, which hit a 16-year low at the end of March. Though storage sites have been refilling at a steady rate so far this summer, storage in the west, a region vitally important for balancing the North American gas market during high winter demand, remains unusually low for this time of year. In today’s RBN blog, we examine the latest developments in Canadian natural gas storage and explain why storage levels in Western Canada may start the next heating season at critically low levels.

It’s well understood that methane is a significant greenhouse gas and that reducing methane emissions from oil and gas production is critical to hitting long-term emissions targets, but that’s about where most of the common ground ends. There are serious disagreements about the actual magnitude of methane emissions, the proper role of government regulation, and whether requirements to control those emissions would place an undue burden on the energy industry and lead to decreased supply. In today’s RBN blog, we look at how emissions estimates are made, why they can vary significantly, and how the disagreements about how to curb those emissions might be resolved.