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.
Daily Energy Blog
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.
When U.S. lawmakers introduced the 45Q tax credit in 2008, they were planting a seed they hoped would one day sprout into a flourishing carbon-capture industry. As the years wore on and the number of successful projects remained small, they added a little fertilizer in 2018, not only enhancing the value of the credits but easing some of the limitations in the earlier legislation. It’s now 2022 and, with climate concerns and the energy transition at top of mind, Washington is again looking at ways to make the tax credit more effective and spur new growth in carbon-capture projects. In today’s RBN blog, we look at how economic and technological challenges have so far limited the success of carbon-capture initiatives.
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 primary 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 take a closer look at the primary pricing mechanisms driving the U.S. gas market.
For many, coal has become a hydrocarbon non grata in recent years, mostly due to the considerable amount of carbon dioxide (CO2) generated when it is burned to produce electric power or heat. But what if, instead of combusting coal on its own, coal plants were co-fired by a combination of environmentally friendly versions of ammonia and the volumes of CO2 generated were way less? And what if, through the 2030s and ’40s, the ratio of fuels used in these coal-and-ammonia-fired power plants shifted away from coal and toward ammonia, and by mid-century the plants were fueled only by “green” or “blue” ammonia, which generates little or no CO2? It may sound too good to be true — heck, it may well turn out to be! But there is a lot of interest in the idea, especially in Japan, where coal still retains a big share of the power generation mix. In today’s RBN blog, we continue to look at the prospects for environmentally friendly hydrogen (H2) — and ammonia, an H2 carrier — in the power generation sector.
The Federal Energy Regulatory Commission (FERC) issued two new statements of policy February 17 regarding the certification of new pipelines and the assessment of greenhouse gas (GHG) impacts. Together, the two updates reflect a more meticulous regulatory environment and a stricter adherence to policies that midstreamers must comply with in an effort to avoid lengthy and expensive court challenges that have become more commonplace recently. The guidelines will affect most new projects within FERC jurisdiction and, among those, some of the biggest impacts will be felt in the U.S.’s rapidly expanding LNG sector — the terminals themselves and the pipelines that deliver feedgas to them. That could be cause for concern as Russia’s war on Ukraine has exacerbated an already precarious gas situation in Europe and a global LNG supply crunch. In today’s RBN blog, we explain the impact of FERC’s latest guidance on pipeline certification and GHG policy with regard to the LNG sector.
