Brutal arctic cold may have chilled broad swaths of the U.S. last month, but the scorching pace of upstream M&A activity continued to be red hot, with nearly $20 billion in deals announced in January after a record-setting 2023. Last year’s transaction value totaled an astounding $192 billion, a mark 79% higher than the previous 10-year high and more than the previous three years combined. Why the surge? A wide range of factors influenced corporate decisions to grow through acquisitions rather than organic investment, including commodity prices, equity values, debt levels, operating costs, and production trends. In today’s RBN blog, we’ll analyze M&A trends through several statistical lenses and provide some insights into 2024 activity.
Crude oil production in the offshore Gulf of Mexico (GOM) increased by more than 50% from 2013 to 2019, an extraordinary period of growth supported by new discoveries, new offshore platforms and new subsea tiebacks. Then, battered by Covid and major hurricanes, GOM output stumbled in 2020 and 2021, twice falling to less than 1.1 MMb/d, barely half the all-time mark of 2.04 MMb/d achieved in August 2019. More recently, production in the Gulf has been rebounding. But despite these gains — and a relatively mild 2023 hurricane season in the central and western Gulf — the region faces new challenges, including federal leasing delays, a significant oil spill, and an endangered species of sea giants known as Rice’s whales.
The cacophony of Black Friday promotions may make us all wonder if the “giving thanks” part of the fourth Thursday of November has been subsumed by rampant consumerism. But we suspect that E&P executives sat down to more traditional celebrations of gratitude as the upstream part of the oil and gas industry rebounded nicely in Q3 from five consecutive periods of declining profits and cash flows. In today’s RBN blog, we analyze Q3 2023 E&P earnings and cash flows and provide some perspective on the past and future profitability of U.S. oil and gas producers.
Continued growth in Permian crude oil production can’t happen without sufficient infrastructure — not just takeaway capacity for crude, natural gas and NGLs but also the capacity to process the fast-increasing volumes of associated gas being produced in the Midland and Delaware basins. The incremental need for processing capacity is enormous, as evidenced by the ongoing, almost frenetic build-out of gas processing plants across the Permian. More than 1 Bcf/d of new capacity is slated to come online by the end of this year, with another 1.9 Bcf/d in the first half of 2024 and another 1.8 Bcf/d after that. In today’s RBN blog, we discuss the race to add processing plants in key locations in West Texas and southeastern New Mexico and the drivers behind it.
The headwinds facing producers in the Permian, the Eagle Ford and other shale plays are trimming the valuations of oil and gas assets and making it easier for deep-pocketed acquirers and private-equity-backed sellers to reach deals. For proof, look no further than the ongoing frenzy of M&A activity in South and West Texas, where large and medium-size E&Ps alike continue to gobble up smaller producers with complementary assets. Their goals are one and the same: increase scale, improve efficiency, cut costs and build inventory in highly productive plays with easy access to Gulf Coast refineries, fractionation plants, and export docks for oil, LNG and NGLs. In today’s RBN blog, we discuss the most significant deals in the Lone Star State so far this spring and what they mean for the acquiring companies.
For the U.S. oil patch, exports are the lifeblood of today’s market. U.S. refineries are operating at more than 90% of their rated capacity and using as much domestically produced light-sweet shale oil as their sophisticated equipment will allow. That means that virtually all of the incremental U.S. unconventional light-sweet crude oil production will need to be piped to export terminals along the Gulf Coast, loaded onto tankers, and shipped to refineries overseas. In today’s RBN blog, we discuss what this undeniable link between crude oil exports and production growth means for U.S. E&Ps and midstream companies — and the future of the oil and gas industry.
May the 4th be with you! Today — Star Wars Day to many of us — we borrow (and bastardize) one of the most memorable quotes from that epic collection of movies, “May the Force be with you,” to make the point that, like the “Force” that shapes events in the Star Wars universe, for the U.S. oil patch, exports are the lifeblood of today’s market. U.S. refineries are operating at more than 90% of their rated capacity and using as much domestically produced light-sweet shale oil as their sophisticated equipment will allow. That means that virtually all of the incremental U.S. unconventional light-sweet crude oil production will need to be piped to export terminals along the Gulf Coast, loaded onto tankers, and shipped to refineries overseas. In today’s RBN blog, we discuss what this undeniable link between crude oil exports and production growth means for U.S. E&Ps and midstream companies — and the future of the oil and gas industry.
For a major oil and gas producer, organic growth over time is all well and good. But if you want next-level scale — and the economies that come with it — there’s nothing like cannon-balling into the deep end of the pool with a huge, game-changing acquisition. ExxonMobil has already done that twice — first in 2010 with the $41 billion purchase of XTO Energy, then in 2017 when it bought the Bass family’s oil and gas assets for $6.6 billion. Now it’s said to be poised for another big plunge, and to be eyeing the Permian’s largest E&P, Pioneer Natural Resources. In today’s RBN blog, we analyze a potential deal that would make Exxon the dominant producer in the premier U.S. shale play.
In marking the third anniversary of COVID’s onset, the Washington Post detailed a study that showed most of us are already shedding the virus-impacted memories of that tedious and often traumatic time to concentrate on looking ahead — a trait scientists label “future-oriented positivity bias.” That transition was clearly evident in the 2022 investment decisions of U.S. E&Ps as the capex budgets of the 42 companies we monitor, pared to the bone during the pandemic, expanded through last year from initial guidance of a 24% increase over 2021 to a final 54% reported increase for the full year. They increased production by 9% year-over-year, but producers haven’t forgotten fiscal discipline or a focus on cash flow generation. In today’s RBN blog, we analyze 2023 capital budgets that generally sustain the pace of Q4 2022 spending and eschew additional increases in a lower commodity price environment.
For the first 10 years of the Shale Revolution, it was a foregone conclusion: High prices stimulated more drilling, and more drilling meant higher production. It worked in both directions. When prices crashed, so did production. The correlation was great. The relationships were right on cue in 2014-15 when $100/bbl crude crashed to $30, rebounded to $60 by 2019, and wiped out in 2020 when the COVID meltdown hit. But then the market shifted. As prices ramped up in 2021 — eventually to astronomical levels in 2022 — the phenomenon of producer discipline kicked in, with E&Ps capping their drilling programs and returning a significant slice of their rising free cash flow to their shareholders. The near-term market implications of this new dynamic have been extensively documented in the RBN blogosphere. But what does it mean for the future? Especially for intrepid energy analytics companies (like RBN) that, by necessity, must project producer behavior far into the future to determine what production will look like next year, next decade and even further over the horizon. In this new RBN blog series, we will examine that dilemma, the assumptions RBN makes, and what our forecasts for the next few years look like.
The numbers don’t add up. Literally. The most closely watched energy statistics in the world have a problem, and it’s been getting worse over the past two years. We’re talking about EIA’s U.S. crude oil supply, demand and inventory balances, which are published each week and then trued up about 60 days later in monthly data. The problem is that the balances don’t balance. EIA uses a plug number alternatively called “adjustment” or “unaccounted for” to force supply and demand to equate. That would not be an issue if the plug number was small and flipped frequently from positive to negative, likely due to timing inconsistencies with the input data. But that’s not the case. The number is mostly positive, meaning more demand than supply. And the difference can be mammoth: last week it was 2.3 MMb/d, or 18.4% of U.S. crude production. It seems like barrels are somehow materializing out of nowhere. But now we know where, because EIA just finished a 90-day study of the crude imbalance that reveals the sources of the problem and what it is going to take to fix it. In today’s RBN blog, we will delve into what has been causing the problem, what it means for interpreting EIA statistics, and what EIA is doing to address the issues.
While soaring commodity prices have been the most important driver of record E&P cash flow generation over the past 12 months, shareholders have also benefited from a new, post-pandemic financial discipline that has lowered the industry’s reinvestment rate to an all-time low of 35%. However, the 2022 capital expenditures initially planned by the 42 U.S. producers we track were expected to rise a healthy 24% over 2021 levels and their spending plans for the just-finished year continued to increase as 2022 wore on. While only a handful of E&Ps have released their actual 2023 budgets, their most recent conference call comments suggest that the investment momentum will keep building in the new year. In today’s RBN blog, we analyze producers’ 2022 capital investment and the key indicators for 2023 growth.
Storm clouds may be gathering on the economic horizon as concerns about persistent inflation and looming recession roil markets and politics. But for oil and gas producers, the third quarter was the equivalent of a driver putting the top down under a flawless azure sky, dialing up the road tunes, and cruising without a care down an endless highway. Lower oil prices led to a dip in earnings and cash flow after a record-breaking second quarter, but cash still filled producers’ coffers at the second-highest rate in decades. In today’s RBN blog, we review the Q3 results of U.S. E&Ps and discuss what may lie ahead as those storm clouds move closer.
In days gone by, the common sentiment in the oil patch when prices rose was “Drill, baby, drill!” Not only have times changed, but even back when the phrase was made famous by former Republican Vice-Presidential nominee Sarah Palin in 2008 it vastly oversimplified and understated the efforts required to secure new production. It’s easy to overlook how intensive (and time-consuming) the operation at a well site is before even being able to extract any of those precious crude oil, natural gas and NGL molecules found beneath our feet. Prior to hydrocarbon production, well sites must be obtained, tested and developed by exploration and production companies trying to determine their chances of making a reasonable return on their investment. In today’s RBN blog, we take a step-by-step look at the leasing process.
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.