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.
Daily Energy Blog
Refined product markets in the U.S. are constantly morphing. Over time, demand for gasoline and diesel rises or falls, refineries are shut down, and the price spread between products sold in neighboring regions widens or narrows. These changes can incentivize refiners and marketers to push into new areas — and encourage midstream companies to develop pipeline capacity to ease the flow of gasoline, diesel and jet fuel into newly attractive markets. Midstreamers have advanced a number of pipeline projects in the past few months to help move increasing volumes of products west across Texas to the Permian, the Great Plains and into the Rockies. In today’s RBN blog, we discuss these projects and what’s been driving their development.
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.
Massive shifts are occurring in the U.S. crude oil export market, but you wouldn’t know it from the steady-as-she-goes pace of activity. The volumes being loaded along the Gulf Coast have stayed within a relatively tight range — 2.5 MMb/d to 3.2 MMb/d — for 12 consecutive quarters now, and the export pace for each of the past three quarters has remained within a few thousand barrels of 3 MMb/d. So, what’s changed? For one thing, Corpus Christi is now by far the dominant point of export, with Houston, Louisiana, and Beaumont/Nederland trailing. Another is that Europe, heavily impacted by the sharp decline in imports from Russia, is now the leading destination for U.S. barrels. There are other changes, too, including increased use of Very Large Crude Carriers (VLCCs) and terminal expansion projects. In today’s RBN blog, we discuss highlights from our recently published Crude Voyager Quarterly Report.
Last year’s $1 trillion-plus infrastructure law calls for the U.S. Department of Energy (DOE) to invest up to $8 billion over five years to support the development of four or more U.S. hydrogen hubs. It’s a safe bet that the DOE will determine that at least one location along the Gulf Coast is worthy of its support — and maybe even a couple, given the extent of existing hydrogen supply, demand and midstream infrastructure already in place in Texas and Louisiana in particular. We’d also be willing to wager that California will be another beneficiary of the federal government’s hydrogen-hub largess. Not only does the nation’s most populous state have extraordinary potential for clean-hydrogen development, its public and private sectors have been aggressively pursuing climate-friendly energy alternatives for decades. In today’s RBN blog, we examine the various efforts underway to develop hydrogen-related infrastructure — and hydrogen demand — in the Golden State.
The thinking behind Next Wave Energy Partners’ late-2019 decision to build a first-of-its-kind ethylene-to-alkylate plant was that a combination of NGL production growth and new ethylene supply — plus increasing demand for alkylate, an octane-boosting gasoline blendstock — would be a win-win-win for ethylene producers, refiners and Next Wave itself. Now, with construction of the plant along the Houston Ship Channel approaching the homestretch, things are shaking out very much as the company had anticipated — even better, in fact. In today’s RBN blog, we discuss the progress being made on Next Wave’s Project Traveler plant and the market forces validating the company’s final investment decision (FID).
The renewed focus on energy security — and the acknowledgment that the world will continue to rely on hydrocarbons for decades to come — may be breathing new life into an often-overlooked U.S. production area: Alaska’s North Slope. The state’s crude oil output is down to its lowest level since before the Trans-Alaska Pipeline System (TAPS) came online in 1977. But now federal regulators are moving toward final approval for ConocoPhillips’s $8 billion Willow project in the National Petroleum Reserve, and Australia’s Santos Ltd. and Spain’s Repsol have taken a final investment decision (FID) on the $2.6 billion first phase of their Pikka project between Willow and Prudhoe Bay. In today’s RBN blog, we discuss recent hydrocarbon-related developments in America’s Last Frontier.
Since the century turned, there’s been a big buildup in refining capacity in the U.S. Midwest, primarily to process the increasing volumes of heavy sour crude being piped in from Western Canada. Over the same period, refining capacity in the Mid-Atlantic region has declined by more than half, mostly for economic reasons — including the lack of pipeline access to favorably priced U.S. shale oil — but also due to events, such as the devastating June 2019 fire at Philadelphia Energy Solutions’ 330-Mb/d refinery in Philadelphia, which led the facility’s owner to shut it down. In addition to spurring more refined product imports to the Mid-Atlantic and increased flows to the region on Colonial Pipeline, the changing market dynamics prompted a push to increase pipeline flows of gasoline and diesel east from the Midwest to markets in Pennsylvania and beyond. In today’s RBN blog, we continue a review of the U.S.’s still-morphing refined product pipeline networks with a look at recently added capacity from PADD 2 to PADD 1.
Not long ago, many considered large-scale industrial carbon capture to be a pie-in-the-sky concept. But neither the capturing of carbon dioxide (CO2) nor permanent underground sequestration is new — naturally occurring sources of CO2 have been used in enhanced oil recovery (EOR) for decades. And, with new financial incentives and a renewed sense of urgency regarding climate action, things are changing fast — so quickly, in fact, that the carbon-capture industry may be poised for exponential growth, both in the U.S. and abroad. In the encore edition of today’s RBN blog, we discuss highlights from our second Drill Down Report on carbon capture.
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.
Champagne corks were popping in E&P boardrooms and executive suites over the past few weeks as they unveiled record-high second-quarter 2022 earnings and cash flows. The strong financial results in the near-idyllic quarter — pre-tax operating earnings and cash flows surged by 29% and 22%, respectively, from the already elevated Q1 2022 levels — were driven by soaring commodity prices and producers’ strict financial discipline. And the celebrations weren’t limited to E&P headquarters. Shareholders have also benefited as companies passed on the unprecedented largess to their investors. In today’s RBN blog, we analyze how U.S. oil and gas producers distributed their soaring free cash flows and discuss the underlying corporate strategies.
Not long ago, many considered large-scale industrial carbon capture to be a pie-in-the-sky concept. But neither the capturing of carbon dioxide (CO2) nor permanent underground sequestration is new — naturally occurring sources of CO2 have been used in enhanced oil recovery (EOR) for decades. And, with new financial incentives and a renewed sense of urgency regarding climate action, things are changing fast — so quickly, in fact, that the carbon-capture industry may be poised for exponential growth, both in the U.S. and abroad. In today’s RBN blog, we discuss highlights from our second Drill Down Report on carbon capture.
Western Canada’s heavy oil producers have become all too familiar with fluctuating and often very wide price discounts for their product. Too often, the culprits have been insufficient pipeline export capacity and/or rapidly rising production. It might be easy to quickly dismiss the latest widening of the heavy oil price discount as being related to these well-known factors, but it turns out that other more international trends are at work, ranging from U.S. government-backed competition in the Gulf Coast to heavy discounting of competing barrels in other far-flung regions of the world. In today’s RBN blog, we look beyond the borders of Canada for an explanation of the latest pressures driving wider Canadian heavy oil price discounts.
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.
Conversations about decarbonization and the energy transition often turn to the transportation sector, which accounted for about 27% of U.S. greenhouse gas (GHG) emissions in 2020. Electric vehicles typically dominate these talks, but alternative fuels like renewable diesel (RD) and sustainable aviation fuel (SAF) also come up, not only because of their lower emissions but also because they are considered “drop-in” replacements for conventional diesel and jet fuel. Policies at the state and national level have already encouraged some production growth, but a tax credit established as part of the recently enacted Inflation Reduction Act (IRA) provides a major incentive for cleaner fuels. In today’s RBN blog, we look at the new 45Z Clean Fuel Production Credit (CFPC), how it will impact the production of RD and SAF, and why facilities that can produce fuels with the lowest carbon intensity (CI) stand to benefit the most.
