The race is heating up for building natural gas pipeline takeaway capacity out of the Permian. Associated gas production from the crude-focused basin is at record highs this month and gaining momentum, which means that without additional pipeline capacity, the Permian is headed for serious pipeline constraints — and potentially negative pricing — by late this year or early next, which would, in turn, limit crude oil production growth there. Midstreamers are jockeying for the pole position to move surplus gas from the increasingly constrained basin to LNG export markets along the Gulf Coast. One of the contenders, Matterhorn Express Pipeline (MXP), a joint venture (JV) between WhiteWater, EnLink Midstream Partners, Devon Energy and MPLX, announced its final investment decision (FID) late yesterday. In today’s RBN blog, we provide new details on the greenfield project.
Recently Published Reports
|Canadian Natgas Billboard||Canadian NATGAS Billboard - May 18, 2022||3 days 18 hours ago|
|Hydrogen Billboard||Hydrogen Billboard - May 18, 2022||3 days 19 hours ago|
|Chart Toppers||Chart Toppers - May 18, 2022||3 days 19 hours ago|
|Crude Voyager||Crude Voyager Report May 17, 2022||4 days 12 hours ago|
|LNG Voyager||LNG Voyager Weekly - May 17, 2022||4 days 16 hours ago|
Daily energy Posts
With soaring oil prices dominating recent headlines, it’s no surprise that profits and cash flows for the U.S. exploration-and-production (E&P) sector rebounded dramatically in 2021 from heavy, pandemic-induced losses in 2020. Rising crude oil and natural gas demand fueled a whopping $150 billion turnaround in results, as the 43 major publicly traded E&Ps we monitor recorded $86 billion in pre-tax income after incurring a net loss of $66 billion in 2020. Oh, and by the way, 2021 was the most profitable year in at least the last two decades for producers, which reported income two-thirds higher than the previous peak in 2014, when commodity prices were significantly higher. In today’s RBN blog, we compare producers’ 2021 performance with 2020 and 2014 and explain why results should be even stronger this year.
Even before the recent spike in crude oil and gasoline prices, the subject of a contentious House committee hearing Wednesday with executives from six large oil and natural gas companies, electric vehicles (EVs) were having a bit of a moment. From legacy brands such as BMW and General Motors to the EV startup Polestar, several automakers used their spots during February’s Super Bowl — the most-watched event on the TV calendar, where the cost for a 30-second ad went for a whopping $6.5 million — to highlight their latest EV offerings. Now, with gasoline prices about 50% higher than they were a year ago (and about 20% higher than they were on Super Bowl Sunday), EVs are getting a whole new level of attention from everyday drivers, not just Tesla fanboys, car afficionados, or the environmentally conscious. In today’s RBN blog, we look at whether the recent run-up in gasoline prices will help turn EVs into a more economical option.
When the world’s second-largest container-ship company makes a massive, long-term commitment to a carbon-neutral shipping fuel, you can’t help but take notice. Over the past few months, A.P. Moller-Maersk has placed orders for a dozen large, ocean-going container vessels that will be fueled by “green” methanol, which can be produced by “breaking up” water to produce hydrogen, then combining the H2 with captured CO2 to “make up” enviro-friendly bunkers. And, to ensure an ample supply of the climate-friendly fuels for its first 12 “boxships,” the shipping giant also has entered into strategic partnerships with six alternative fuel companies that by 2025 will be producing a total of at least 730,000 metric tons (MT) a year of either bio-ethanol or e-methanol — two chemically identical forms of green methanol. In today’s RBN blog, we discuss why Maersk thinks bio-methanol and e-methanol may be the carbon-neutral shipping fuels everyone’s been searching for.
The battle lines were drawn. The drive toward decarbonization was rushing headlong into the reality of energy markets. Things were going to get messy, but at least it was becoming more evident how the energy transition would impact key market developments, from the chaos in European natural gas, to producer capital restraint in the oil patch, to the rising impact of renewable fuels and, of course, the escalating roadblocks to pipeline construction. Then, a monkey wrench was thrown into the works. The world was confronted with the madness of war in Europe, with all sorts of consequences for energy markets: sanctions, boycotts, cutbacks, strategic releases, price spikes and, here in the U.S., what looks to be a softening of the Biden administration’s view against hydrocarbons — at least natural gas and LNG. So now the markets for crude oil, natural gas and NGLs aren’t only inextricably tied to renewables, decarbonization and sustainability, they must navigate the transition turmoil under the cloud of wartime disruptions. It’s simply impossible to understand energy market behavior without having a solid grasp of how these factors are linked together. That is what School of Energy Spring 2022 is all about! In today’s RBN blog — a blatant advertorial — we’ll highlight how our upcoming conference integrates existing, war-impacted market dynamics with prospects for the energy transition.
The Biden administration’s March 31 announcement that it will release an average of 1 MMb/d of crude oil from the Strategic Petroleum Reserve over the next six months was an acknowledgement of sorts that U.S. E&Ps won’t be ramping up their production enough in the near term to bring down oil or gasoline prices. It seems like a good assumption because, while the 40-plus crude oil and natural gas producers we monitor have indicated they are planning a 23% increase in capital spending this year and an 8% increase in production, further examination reveals that those numbers are somewhat misleading — the real gains will be significantly smaller. In today’s RBN blog, we scrutinize producers’ spending plans and production outlooks by peer group and company-by-company.
At first glance, it would appear that President Biden’s announcement regarding the release of up to 180 MMbbl of crude oil from the Strategic Petroleum Reserve over the next six months could have a significant impact. After all, it would, in a sense, increase the flow of U.S. oil into the market by almost 9% –– 11.7 MMb/d of current U.S. production plus an incremental 1 MMb/d from the SPR — and boost global supply by about 1%, which is no small thing. There are a few unknowns, though, such as (1) how much sweet crude oil and how much sour will be released, (2) where the pipelines connected to the four SPR sites could take that oil, (3) whether those pipelines have sufficient capacity to absorb the incremental flows out of SPR, and (4) what the ultimate market impacts of the SPR releases will be. In today’s RBN blog, we look at the president’s announcement and its implications.
Russia’s invasion of Ukraine has pushed U.S. LNG into the spotlight as Europe seeks to wean itself off Russian natural gas. In the short term, U.S. LNG to Europe is constrained by liquefaction capacity on the LNG output side but also by Europe’s own import capacity and pipeline grid. Very little can be done to quickly increase global LNG production, and while many export terminals will operate at peak capacity for longer to boost output, LNG terminals take time to build, so capacity for this year and the next few years is already set. Further out, however, there is no shortage of new projects hoping to capitalize on the current clamor for LNG and reach a final investment decision (FID), and the U.S. could be headed toward its biggest year for new LNG capacity ever. In today’s RBN blog, we continue our series examining key U.S. projects, turning our lens to what is arguably the most discussed and reported-on project on our list — and one that is moving forward potentially without a formal FID — Tellurian’s Driftwood LNG.
Just a few years ago, when the Shale Revolution had matured into the Shale Era, the world settled into a nice groove, with crude prices generally rangebound between $40 and $70/bbl. As the U.S. looked to assume OPEC+’s role and evolve into the world’s swing supplier of oil, ramping up production when prices rose and slowing it down when they fell, it seemed reasonable to expect that market-driven responses would help maintain stability. Well, things haven’t turned out that way. COVID, the emphasis on ESG, a hydrocarbon-averse administration, and Russia’s war on Ukraine combined to put “reasonable expectations” in the trash. An entirely new set of expectations is emerging, and few metrics explain it better than today’s different-as-can-be relationship between crude oil prices and the U.S. rig count, as we discuss in today’s RBN blog.
The Biden administration said last Friday it would help ensure deliveries of an additional 15 billion cubic meters (Bcm) of LNG to the European Union (EU) market in 2022. A frenzy of media articles followed and the targeted increase was widely cited. The April CME/NYMEX Henry Hub futures contract rallied nearly 3% to $5.55/MMBtu on Friday, and the stock price for Cheniere Energy, the largest LNG producer in the U.S., jumped 5.5% the same day. But U.S. liquefaction facilities have already been running full tilt and sending record volumes to Europe. So, what does the news really mean for U.S. LNG exports and the domestic gas market? In today’s RBN blog, we put that 15 Bcm in perspective and distill the key takeaways for U.S. LNG production.
There’s a lot of confusion out there — both in the media and the general public — about how producers in the U.S. oil and gas industry plan their operations for the months ahead and the degree to which they could ratchet up their production to help alleviate the current global supply shortfall and help bring down high prices. It’s not as simple or immediate as some might imagine. There are many reasons why E&Ps are either reluctant or unable to quickly increase their crude oil and natural gas production. Capital budgets are up in 2022 by an average of 23% over 2021. That increase seems substantial, but about two-thirds (15%) results from oilfield service inflation. And there are other headwinds as well. In today’s RBN blog, we drill down into the numbers with a look at producers’ capex and production guidance for 2022, the sharp decline in drilled-but-uncompleted wells, the impact of inflation and other factors that weigh on E&Ps today.
Predictions about what the energy market and the global economy might look like in the future can feel a bit like stargazing — the closer something is, the clearer it appears. But if something is really far away, even the Hubble Space Telescope won’t bring it precisely into view, especially if it’s a still-developing solar system or a distant planet. That’s pretty much where things stand with bioethylene, which could become a shooting star but might also end up as a big cloud of dust. In today’s RBN blog, we discuss the developing market for bioethylene: where it’s being made, what changes might make it more economical to produce in the U.S., and its target markets.
Getting by without a few million barrels a day of Russian crude oil won't be easy for the global market, but it's gotta be done. One way to help ease the supply shortfall would be for U.S. E&Ps to ramp up their crude oil production, but the oil patch's output has remained close to flat — so far at least. Why aren't producers jumping in? Are the Biden administration’s policies and mixed messages on hydrocarbons putting the kibosh on production growth? Is it a scarcity of completion crews, or pipes or frac sand? Perhaps it’s worries that increasing production would send oil prices sliding and hurt producers’ bottom lines? Or is it all about ESG and the shift by many large investment funds and banks away from anything related to fossil fuels? Possibly all of the above? In today’s RBN blog, we look at what’s really behind the snail’s pace of U.S. crude oil production growth.
The European natural gas market has been in crisis this winter, with prices skyrocketing north of $100/MMBtu recently. Tight supplies, low storage levels, and a new gas-supply-security issue sparked by the war in Ukraine has many European nations, especially Germany, embarking on a crash course to increase supplies and diversify away from Russian gas imports. In this quest, increasing gas supplies in both the short- and long-term is a top priority and will require substantially more LNG capacity to replace — and eliminate the need for — Russian gas. With Europe’s gas-supply urgency on the rise, long-dormant prospects for exporting LNG from Canada’s East Coast are being re-examined. In today’s RBN blog, we look at the potential for repurposing the region’s only LNG import terminal into one that is geared toward exports.
So far, most of the merger-and-acquisition activity among crude-oil-focused producers in the COVID era has occurred where you would expect it: the Permian, which seems to dominate almost every discussion about the U.S. energy industry. More recently, though, there has been an uptick in E&P consolidation in the Denver-Julesburg Basin in the Rockies and, earlier this month, in the Bakken. There, Whiting Petroleum and Oasis Petroleum — two once-struggling producers — have agreed to a merger of equals that will create the Bakken’s second-largest producer and the largest pure-play E&P. In today’s RBN blog, we discuss the companies’ stock-and-cash deal, which will result in a yet-to-be-renamed entity with an enterprise value of about $6 billion.
U.S. LNG exports are at an all-time high, driven primarily by new capacity online or commissioning, but the existing terminal fleet has also been pushing production to the max as offtakers, particularly in Europe, hunt for every spare molecule they can find. Every single terminal in the U.S. set a new monthly export record in either December or January. But is it enough? With the ongoing and tragic war in Ukraine threatening energy security and reliability in Europe, where gas storage inventories are already running low, the focus increasingly turns to LNG to replace at least some of the gas it typically imports from Russia. It sounds great in theory, and in the long term more LNG capacity will be added, but for now, we’re stuck with the infrastructure we’ve got, putting a ceiling on both how much Europe can take and how much exporters, including the U.S., can send. In today’s RBN blog, we look at the potential for incremental LNG exports from the U.S. to Europe to help offset Russian gas.