The last ten years have been a wild rollercoaster ride for oil and gas prices and the check stubs of mineral and royalty owners. Take the baseline boom and bust cycle of the industry and layer on oversupply from U.S. shale producers back when they were considered growth companies, a global pandemic that led to unprecedented capital destruction, and wars in Europe and the Middle East and you get a sawtooth view of pricing that is continuously rebounding due to steady and increasing global demand for hydrocarbons. Indeed, mineral and royalty owners are intimately linked to global demand and geopolitics, placing revenue streams at the mercy of events that take place far from U.S. basins. Despite the rough ride of the past, global oil demand is strong and forecasted to rise to nearly 105 million barrels per day by 2030. Demand for U.S. LNG is also strong supported primarily by the Haynesville with Permian, Eagle Ford and Bakken oil driving U.S. oil production. Influencing the supply and demand picture is the replenishing of the U.S. Strategic Petroleum Reserve after the Biden administration sold half of it to stabilize the market following Russia’s war of aggression on Ukraine as well as India and China buying the Russian barrels that have been removed from global markets due to ongoing sanctions.
The drumbeat of steady M&A activity makes consolidation a major factor in shaping what your mineral and royalty streams will look like going forward. Small cap and single private operators who consistently drill in a single basin or sub-play (and consistently add new wells to an owner’s acreage) are being driven out by large, publicly traded E&Ps and the supermajors in search of the best economics and through acquisitions. These multi-basin operators who also often have offshore and international development, can pick and choose where to allocate capital. Basins that a private E&P would readily drill are now less attractive for public E&Ps who are adopting a more cautious approach to drilling in areas without top tier acreage and breakevens, which will directly impact many check stubs. So, who’s at risk?
Driving U.S. oil output and paving the way for LNG exports
With its stacked pay zones, long runway of drilling inventory and favorable breakeven prices, it’s no wonder that the Permian continues to reign supreme as the country’s oil powerhouse. The best concentrated stacked pay sits just west of the Texas and New Mexico Stateline in the Delaware Basin with the Midland Basin providing more dispersed opportunities.
Hydrocarbon output from the Permian gives operators a double-edged sword – high quality crude with ample takeaway capacity and associated gas production that increases in lock step with oil. Permian natural gas can’t be moved to profitable markets due to midstream bottlenecks and although some can be directed into local power generation and crypto currency mining, much of the gas is either flared or disposed of at the expense of operators which, in turn, leads to negative prices for mineral and royalty owners.
More than 700 miles to the east of the Permian, the natural gas story couldn’t be starker where the Haynesville Shale offers another hydrocarbon powerhouse. Despite the wide swing in prices over the last year, natural gas has a long-term bright future with the Haynesville and southwestern Marcellus at the center providing ample supply for a new generation of LNG trains being born nearby on the Gulf Coast. Prices are expected to increase in 2025 as these facilities come online.
Although the Permian and Haynesville are becoming the sole domain of large-cap E&Ps and the supermajors, there is still small cap and single basin operators to be found drilling with private companies dominating the Appalachian Basin and others finding their niche in the Eagle Ford, Bakken and Austin Chalk. And as contracts for the new LNG facilities continue to firm up, the gassy western extension of the Eagle Ford is well positioned to capitalize on Gulf Coast terminal exports while continuing to export directly into Mexico.
Low growth, no growth basins
In the Rockies, consolidation and the exodus of smaller independents have resulted in a mere handful of large, public E&Ps holding remaining inventory and most of this acreage is held by production, making it less likely that these sites will be drilled in the near term. And across the U.S., the core of many basins has been completely drilled out, leaving infill drilling inventory in the DJ Basin, Eagle Ford and Utica. The same goes for the Williston Basin which may have had a boisterous 2023 yet has likely hit peak production and on the glide path down in terms of interest and drilling.
Improving the economics and potentially extending the life of maturing basins are refracs, introduction of enhanced oil recovery and drilling of 3-mile laterals. But given its history and complete lack of interest from major operators to drill (as summarized below), the Midcontinent’s heyday is at an end. The private E&Ps that are holding on to acreage in Oklahoma’s SCOOP, STACK and SWISH are primarily focused on squeezing efficiency out of operated wells not drilling. And the remaining natural gas potential that exists will have to compete with Haynesville, Eagle Ford and even Permian associated gas as the economics improve with LNG facility buildout.
Emerging royalty streams
In 2023, Exxon acquired the rights to 120,000 gross acres in the Smackover formation where the high concentration of lithium makes it one of the most prolific sources of this important mineral in North America. This is a leading indicator of the renewed interest in stripping lithium from produced water, helping the U.S. bring the supply chain home and meet demand for electric vehicles. Good news if you hold acreage in southern Arkansas. But given the unstoppable move to EVs to reduce carbon intensity and abundance of produced water across U.S. basins, owners in many states may see lithium appear on their check stubs in coming years.
Carbon dioxide, a potent greenhouse gas, has traditionally had a place in the oilfield as a driver for enhanced oil recovery in mature fields, resulting in CO2 pipelines across many U.S. basins. Billions are being deployed to begin capturing carbon emissions at their source and transport CO2 to viable storage reservoirs. The ideal combination of large emitters, midstream takeaway and proximity to good rock points to Appalachia and the Gulf Coast as the best candidates along with the Bakken.
The jury is still out on who owns the pore space in the reservoir rock and who will profit from carbon capture and storage. Some argue that the surface rights owner should claim the royalty stream akin to saltwater disposal wells and that the mineral estate owner profits from what is produced, a debate that is being settled in supreme courts in many states. Unlike oil and gas revenue streams that decline over time, renewable energy royalties can provide owners with a consistent revenue stream that increases over time. With today’s high cost of capital, many wind and solar project developers are reaching for “energy community” tax credits identified in the Inflation Reduction Act. Given the renewable energy building boom, these new royalty streams are coming to areas historically linked to coal mining and generation, communities with specific economic links to oil and gas production, and sites identified in the EPA’s RE-Powering America’s Land Initiative.
Despite the roller coaster ride of commodity prices over the last decade, ongoing M&A activity and the momentum of the energy transition, U.S. hydrocarbons remain crucial to meet global demand with net zero policy and renewables only adding to the mix of opportunities. What an exciting time to be a mineral and royalty owner!
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