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.
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 world is in desperate need of more crude oil right now and anybody with barrels is scouring every nook and cranny for any additional volume that can be brought to market. Some of that may come from increased production, but the oil patch is a long-cycle industry, just coming off one of the most severe bust periods ever, and it will take time to get all the various national oil companies, majors, and independents rowing in the same direction again. For now, part of the answer will be to drain what we can from storage — after all, a major purpose of storing crude inventories is to serve as a shock absorber for short-term market disruptions. To that end, the U.S. is coordinating with other nations to release strategic reserve volumes to help stymie the global impact of avoiding Russian commodities. Outside of reserves held for strategic purposes though, commercial inventories have already been dwindling as escalating global crude prices have been signaling the market to sell as much as possible. Stored volumes at Cushing — the U.S.’s largest commercial tank farm and home to the pricing benchmark WTI — have been freefalling for months, which raises the question, how much more (if any) can come out of Cushing? In today’s RBN blog, we update one of our Greatest Hits blogs to calculate how much crude oil is actually available at Cushing.
Russia’s war on Ukraine turbocharged global crude oil prices and spurred price volatility the likes of which we haven’t seen since COVID hit two years ago. The price of WTI at the Cushing hub in Oklahoma — the delivery point for CME/NYMEX futures contracts — has gone nuts, and the forward curve is indicating the steepest backwardation ever. In other words, the market is telling traders in all-caps, “SELL, SELL, SELL! Sell any crude you can get your hands on. It’s going to be worth far less in the future.” So anyone with barrels in storage there for non-operational reasons is pulling them out, and fast! In today’s RBN blog, we look at the recent spike in global crude oil prices and what it means for inventories at the U.S.’s most liquid oil hub.
WTI is selling for north of $120 a barrel, gasoline and diesel are retailing for more than $4.10 and $4.80 a gallon, respectively, and, with Russia continuing its unprovoked war against Ukraine, it’s hard to imagine prices for hydrocarbons easing by much anytime soon. As startling as the recent spikes in crude oil and refined products prices may be, however, it’s worth keeping in mind that, in real-dollar terms, prices for these commodities have been considerably higher in the past, including through much of the 2006-14 period and back in 1979-81. And don’t forget, the car, SUV, or pickup you’re driving today consumes about two-thirds as much fuel per mile, on average, as the vehicle you (or your parents) drove back when Ronald Reagan was running for president and Pink Floyd’s The Wall was the best-selling album. In today’s RBN blog, we put today’s “record-breaking” prices for crude oil and motor fuels in perspective.
Russia’s unprovoked war against Ukraine has posed a dilemma regarding Russian crude oil. Russia is the world’s second-largest oil exporter after Saudi Arabia, sending out an average of more than 7 MMb/d last year, or about 7% of global demand. And the world needs more oil — demand for crude has rebounded from its COVID lows, and OPEC+ (of which Russia is part) and U.S. producers alike have been ramping up production only gradually. So the dilemma is, does the U.S. continue importing Russian crude oil to help hold down gasoline, diesel, and heating oil prices, or does the U.S. ban such imports as an additional rebuke to Russia’s actions in Ukraine? In today’s RBN blog, we look at which refiners and refineries have been importing Russian crude oil, heavy gasoil, and resid and what would happen if the U.S. said “Nyet” to Russian imports.
Well, it took a hot war in Europe, constrained capital spending by U.S. producers, continued restrictions in OPEC+ production, and ongoing economic recovery from a global pandemic, but it’s finally happened: Brent shot past $100 and even $105/bbl Thursday before dropping in the last hour of trading to settle a hair above $99. Even WTI touched $100/bbl briefly. The market has been buzzing about the prospects for the breach of this threshold since October, coming along with waves of speculative trades, a dozen false starts, and countless pundit predictions. Now that it has happened, what does it mean — other than higher gasoline prices, of course? In the good ole days, high prices would spur production growth that would help bring prices back down — eventually. But this time, things are different. Which begs the #1 question: Will triple-digit oil prices last? In today’s RBN blog, we’ll consider these issues in the context of historical price behavior and what we might expect this time around.
Multibillion-dollar mergers and acquisitions have attracted a lot of attention the past couple of years. Chevron buys Noble. ConocoPhillips acquires Concho. Cabot merges with Cimarex. Pioneer adds Parsley and DoublePoint. While it’s understandable that these mega-deals grab the spotlight, they tend to overshadow the many smaller-but-still-substantial agreements being announced at a rapid pace over the same period. Many of these less-than-$4-billion deals involve crude-oil-focused producers expanding their holdings in basins where they were already active, and many — no surprise — are happening in the Permian, although acreage in the Denver-Julesburg and the Eagle Ford are in play as well. In today’s RBN blog, we look at a few of the more interesting small and midsize acquisitions announced recently.
Oil sands, the workhorse of Alberta’s — and Canada’s — crude oil production growth, achieved a record production year in 2021. A steady turnaround in crude oil prices, improved market access, and the tried-and-true resilience of oil sands producers combined to drive the increase in output. With 2022 barely out of the starting blocks, the oil sands players have provided production guidance for this year that, if fulfilled, could set the oil sands on track for another year of record output. In today’s RBN blog, we consider the latest production guidance estimates and what these could mean for the availability of oil pipeline export capacity from Western Canada.
Even through the market turmoil of the past couple of years, the Permian has been a production powerhouse, lately churning out an average of nearly 5 MMb/d of crude oil and 14 Bcf/d of natural gas. But is the Permian on shaky ground? Well, sort of. Distinct areas within both the Midland and Delaware basins in West Texas have experienced an increasing number of higher-magnitude earthquakes that have been linked to the saltwater disposal (SWD) wells that E&Ps use to get rid of the massive volumes of “produced water” their oil and gas operations generate. As a result, regulators have been ordering some of these disposal wells to be shut down and directing producers and midstreamers to develop “seismic response action plans” aimed at reducing the frequency and severity of quakes. In today’s RBN blog, we look at what has been happening on the earthquake front in West Texas and how E&Ps can deal with it.
It’s possible for a single new infrastructure project to be a game-changer — the Transcontinental Railroad comes to mind, and so do the New York City subway system and the Hoover Dam. In the energy industry’s midstream sector, things work a little differently. There, projects are incremental. They’re privately, rather than publicly backed and so they must be commercially justified, which means they need to serve a specific purpose. That’s not to say they can’t shift the landscape of the areas they serve. For example, when the Shale Revolution transformed and disrupted U.S. hydrocarbon markets, supply and demand dynamics were turned on their head and waves of projects had to be built to handle surging production in suddenly supercharged shale plays like the Bakken, Appalachia, and Permian and to serve new markets, most notably exports. Sometimes, it’s a more complicated combination of projects and events that, as a group, cause not-so-subtle shifts in how things are done. Lately, handfuls of pipeline projects and refinery closures — plus increasing regional crude oil production in both the U.S. and Canada — have spurred changes in traditional pipeline-flow patterns and may breathe new life into oil-export activity at the Louisiana Offshore Oil Port and the Beaumont-Nederland area in Texas. In today’s RBN blog, we discuss these changes and their effects.
Pandemic. Deep freeze. Decarbonization. Stymied production growth. Sky-high prices. 2021 was definitely one for the record books. But thank goodness we made it and can look forward to a New Year! That means it is time for our annual Top 10 Energy Prognostications, the long-standing RBN tradition where we consider what’s coming next to energy markets. Say what? Surely it would be foolhardy to make predictions now. After all, we’re in the midst of a chaotic energy transition, a pandemic that’s becoming endemic, and political shenanigans in Washington and across the globe. Foolhardy? Nah. All we need to do is stick out our collective RBN necks one more time, peer into our crystal ball, and see what 2022 has in store for us.
You can count on certain things this time of year. Alabama is in the hunt for a college football national championship, there’s fresh powder somewhere in the Rockies, it’s mostly still shorts weather in Houston, and there’s a catchy new country song ripe for blog titles. January also brings some unknowns, with pundits throwing out various scenarios for stock and commodity markets, as well as the more recent trend in postulating the outcomes of the latest COVID variant. When it comes to the U.S. onshore oil and natural gas markets, the Permian continues to be old reliable, especially with crude north of $70/bbl and natural gas prices flirting with $4/MMBtu. There’s a lot we can’t predict about the year ahead (like the NCAA football championship, though this writer, at least, is pulling for Georgia next week), but our view of Permian production growth hasn’t changed. In today’s blog, we provide this year’s outlook for Permian crude oil and natural gas markets.
Mexico’s state-owned Petróleos Mexicanos, the second-largest exporter of crude oil to the U.S. after Canada, said in late December that it will slash its export volumes in 2022 and eliminate them completely in 2023. The plan is premised on Pemex’s expectation that, with increased utilization of the company’s six existing refineries and the impending start-up of a new one, it will need every barrel of the Maya, Isthmus, Olmeca, and other varieties of oil it produces. While at first glance it may seem that Mexico phasing out exports of crude would pose a major challenge to some U.S. refineries, there’s good reason to believe that in reality it won’t. In fact, as we discuss in today’s RBN blog, there may be less to Pemex’s planned export phase-out than meets the eye.