RBN Energy

It’s true, the Permian is — and will likely remain — the center of attention in the U.S. oil and gas industry, not just for its massive and still-growing production volumes but also for the ongoing consolidation among producers in the West Texas/southeastern New Mexico play. But while the Permian has dominated production and M&A activity the past couple of years, Chevron’s recently announced $7.6 billion acquisition of Denver-Julesburg (DJ) Basin-focused PDC Energy highlights the potential for producers to generate significant production and profits from other major U.S. regions, including the Rocky Mountains. In today’s RBN blog, we analyze Chevron’s latest mega-deal and its impacts on the buyer, seller, and the broader oil and gas industry.

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, 5/26/2023 (4:45 pm)

Crude oil prices rebounded on Friday with WTI up $0.84/bbl to settle at $72.67/bbl.  That comes after a big decline on Thursday when WTI dropped 3.5% due primarily to statements from Russian Deputy Prime Minister Alexander Novak that no new cuts in OPEC+ production quotas should be expected.   Putin was out with the same message, saying energy prices are approaching "economically justified" levels.  Those statements undercut not so veiled threats from Saudi Energy Minister bin Salman earlier in the week warning oil shorts that they could “ouch” after the next OPEC+ meeting scheduled for Vie

By Jeremy Meier - Friday, 5/26/2023 (3:00 pm)

May was a tough month for US oil and gas rig count, with producers ending the month with a fourth consecutive weekly decline (-44 vs April 28).  Total US rig count was 711 for the week ending May 26, according to Baker Hughes. Rigs were added in the Permian (+1) and Eagle Ford (+1) this week, while the Anadarko (-5), Haynesville (-3), Gulf of Mexico (-1) and All Other Basins (-1) all posted declines.  Total US rig count is down 42 in the last 90 days, and down 16 vs. this same week a year ago.

Daily Energy Blog

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.

Freeport LNG is expected to be offline for an extended period following last week’s explosion and fire at the export terminal, leaving the global gas market even more undersupplied than it already was. The outage cuts U.S. export capacity by about 2 Bcf/d at a time when Europe is still taking in huge volumes of LNG to offset declines in Russian supplies and bolster storage ahead of winter. This is all happening as another large exporting nation, Australia, is facing a critical winter energy crisis of its own and South American demand is headed toward its seasonal high, straining an already tight market. Today’s RBN blog continues our series about the ongoing Freeport outage, this time looking at the impact to the global gas and LNG markets.

Before the bullish winter of 2021-22, it appeared the Northeast natural gas market was headed for familiar territory: worsening seasonal takeaway constraints and deeper, constraint-driven price discounts starting as early as this spring. Instead, the market went in the other direction the past few months. Takeaway utilization out of Appalachia has been lower year-on-year and, for the most part, Appalachian supply basin prices have followed Henry Hub higher even as that benchmark rocketed to 14-year highs. That’s not to say that constraints out of the Northeast aren’t on the horizon. But the market is now poised to escape the worst of it this year, despite the completion of the last major takeaway pipeline project in the region, Mountain Valley Pipeline (MVP), being pushed out another year or longer, if it crosses the finish line at all. In today’s RBN blog, we provide an update on regional fundamentals and what recent trends mean for gas production growth and pricing in the region.

The Russian war against Ukraine has focused Europe on the issue of energy security, especially as it relates to natural gas. The continent has previously relied on Russia for more than 40% of its gas, but it now must scramble for new suppliers and alternative forms of energy. The matter is particularly urgent in a few countries along or very near the Russian border, including Lithuania, Poland and Ukraine itself. Fortunately, almost two years ago the three countries formed the “Lublin Triangle,” an alliance of sorts with the aim of enhancing military, cultural and economic cooperation while also supporting Ukraine’s prospective integration into the European Union and NATO. In today’s RBN blog, we discuss the potential for developing a “New Gas Order” in Europe.

An explosion June 8 at Freeport LNG, the 15.3 MMtpa (2 Bcf/d) export terminal on Quintana Island, TX, has knocked it offline at a time when the global market is already facing tight conditions because of the war in Ukraine and other factors. The explosion, fire and subsequent shutdown — which fortunately did not include any injuries — sent U.S. natural gas tumbling off recent highs and shot global gas prices higher. Much is still unknown about the developing situation, including exactly how long the outage will last. While Freeport has said it expects the terminal to be offline for at least three weeks, multiple regulatory agencies have investigations underway and will likely need to approve a return to service. In today’s RBN blog, we look at the latest news from Freeport LNG and run through the potential market implications, starting with impacts to the U.S. gas market.

The momentum for North American LNG right now is incredible. With Europe’s efforts to wean itself off Russian natural gas supplies boosting long-term LNG demand in the continent and Asian demand expected to grow even further, there has been a strong push for new LNG projects in the U.S., Mexico and Canada, with enough commercial support and capital present to advance at least some of them to construction and operation. Venture Global on May 25 reached a final investment decision on Phase 1 of Plaquemines LNG, the first North American project to take FID since Energía Costa Azul LNG in 2020. But it’s unlikely to be the last. Cheniere’s Corpus Christi Stage III is likely to follow in the coming months and support is coalescing around a handful of other projects too. So far this year, more than 20 MMtpa of long-term, binding commitments tied to new North American LNG capacity have been signed, propelling a new wave of LNG projects towards FID. In today’s RBN blog, we take a look at the trends in the recent commercial commitments.