Natural Gas Price Improves, Oil Price is Range Bound, and Carbon Capture Royalties
Mineral and royalty owners benefit from a steady revenue stream, yet depending on where your assets are located, checks may be
looking very different compared to just a few years ago. Various factors are at play influencing the size of your checks, including the price
of oil and gas by local market, shifting operator focus that reduces drilling in one basin and increases it in another, and even geopolitical
events on the other side of the planet. All of this makes oil and gas interest owners feel like they are merely along for the ride without any
power to control their financial destiny.
To understand how shifting economics and geopolitics may impact mineral and royalty owners down the road, consider where the ride
has taken interest owners so far. In less than 10 years, it’s been an eventful journey indeed.
2017 – 2019
The era of proving out unconventional resource plays across the U.S. led to overzealous drilling where cash flow returns were reinvested
to accelerate development, leading to oversupply that weakened oil prices.
2020 – 2021
The era of capital destruction that followed the demand collapse of COVID-19 global lockdowns, leading to an oil and gas price slump
and operator bankruptcies.
2022 – 2023
The era of returning value to shareholders and sustained capital discipline led E&Ps to drill within their means, stabilizing
commodity prices.
2024 and Beyond
A period of accelerated mergers and acquisitions reduces the Permian, Bakken and DJ Basins to a few operators, impacting drilling in
other basins by shifting operator focus to the most economic plays.
Navigating 2025:
Consolidation, ESG Impact, Emerging Opportunities in Oil and Gas
As we move into 2025, the oil and gas industry will continue the era of consolidation. Yet even as the pool of E&Ps shrinks, new
opportunities arise. This includes non-core, conventional assets being divested by the majors as well as a return of private equity in a big
way that may spawn a new wave of A&D minded E&P startups, expanding the consolidation pool.
Even as the industry shifted from growth to returning value to shareholders, ESG turned from a topic of debatable longevity into an
unstoppable force that has led to numerous regulatory changes aimed at reducing greenhouse gas emissions. The focus on clean
energy also accelerated the future of carbon capture, utilization and storage projects (CCUS).
At the end of the day, mineral and royalty owners want to know what their checks will look like in the coming years. Read on for an
Enverus Intelligence® Research (EIR) team forecast of where oil and gas prices are headed in 2025, basin activity that may lead to new
wells on your property, and the revenue generating potential of CCUS.
Demand for natural gas in the U.S. has historically been fairly stable given the relatively predictable base load growth in the power
grid and seasonal changes in household consumption. But as mineral and royalty owners will know, over the past five years natural
gas prices have been on a roller coaster starting with the demand shock of the pandemic that crashed both oil and gas prices before
recovering and soaring to record highs in 2022 following Russia’s invasion of Ukraine. And following a warmer than expected winter,
Europe realized it could do just fine without Russian natural gas, which sent prices lower.
Natural gas prices have no doubt been hit hard by recent ups and downs but light is beginning to appear at the end of the tunnel. The days of negative Waha prices on Permian interest owner checks may be coming to an end with the opening of the Matterhorn Express pipeline bringing 2.5 Bcf per day to the Gulf Coast where LNG facilities are opening the doors to global markets. With more Permian gas pipelines nearing completion or planned, liberated associated gas will join ample supply from the Haynesville Shale ideally situated on the Texas and Louisiana coast. Here, operators have anticipated the coming gas boom by increasing their drilling-uncompleted (DUC) count. As contracted LNG export capacity increases, these DUCs can be quickly completed to meet demand.
Adding to the upside potential for prices, the U.S. power grid’s base load is rapidly increasing driven by skyrocketing demand for data centers that require vast energy supplies to operate. The continued adoption of electric vehicles and build out of charging infrastructure continues to increase demand as well. To keep the lights on when the wind isn’t blowing and the sun isn’t shining, the rapid advance of renewable energy also requires secondary natural gas power generation, which has replaced coal as the preferred fuel source.
The EIR team believes that increasing demand domestically and new LNG exports in 2025 all point to higher prices and more natural gas revenue on royalty checks. Meeting export demand will largely be achieved by the Haynesville, Permian, and Eagle Ford due to their favorable proximity to the Gulf Coast while power generation is fueled from basins across the country.
Expect the West Texas Intermediate (WTI) oil price to move between $72 and $80 for the coming years with occasional breakout above or below this range. Despite the electrification of the US and other developed economies as electric vehicles replace the internal combustion engine, global decrease in demand for oil is being offset by increases from developing countries. This follows a natural progression on the energy spectrum as countries in Africa and Asia move from wood to oil, coal, and natural gas fuel sources.
Keeping oil prices relatively stable is due to OPEC’s willingness to increase or curtail production to keep prices within a preferred range. This can be a balancing act if OPEC does decide to cut oil supply overnight to increase prices since it takes months for US producers to drill and bring additional production online. In theory, consolidation that has resulted in a few major producers controlling top oil plays should enable them to better serve as a swing producer. However, a supermajor operating in the Permian also balances production goals with offshore assets and wells around the world that have longer development windows and production profiles compared to US shale wells that have a sharp decline.
When it comes to US oil supply and the checks of mineral and royalty owners, the Permian continues to reign supreme, though the Bakken, Eagle Ford, and DJ Basin all contribute substantially to total output. With only a small number of operators left holding acreage in these basins due to mergers and acquisitions, the pace of drilling will be set according to global considerations and economics. As a result, drilling and DUC count across non-Permian plays are at near record lows as operators drill only where and when it is economically viable.
The price of WTI or Brent oil only has a broad influence on royalty checks with the local market setting the final price. Even within the same county, prices are dictated by the grade and weight of oil produced at the wellhead with many other factors influencing price, including whether oil is trucked or piped to market. Some operators are better at negotiating midstream contracts, which also improves commodity prices.
With oil prices varying so widely from operator to operator, knowing who has the lowest expenses to get oil to market (and in turn pays more to owners) is essential when deciding who to sign a lease with. Similarly, owners who are considering the sale of some of or all of their oil & gas interest should take into account the local market, the quality of their assets, and seek multiple offers from buyers to maximize deal value. In some areas, royalties can demand a 7 or even 10 times multiple on the annual earnings before interest, taxes, depreciation, and amortization (EBITDA). Wells in Michigan will not sell for the same price in Oklahoma or Texas and one operator may see upside potential on a property where another producer does not.
Every basin in Texas is actively being developed but none more dramatically than the Permian where the stacked pay zones and vast acreage footprint provide ample oil and gas resources for decades to come. The epicenters for development are the Texas and New Mexico Stateline for the Delaware sub-basin and Martin County in the Midland sub-basin.
In these premier plays, there are only a few operators that own the majority of remaining drilling locations. Likely years away, once the core of the Delaware and Midland have been drilled out, activity will shift to secondary production targets in the Permian.
The level of consolidation is perhaps even greater in the Permian than it appears from the news headlines about mergers and acquisitions as most operators are linked together through joint operating agreements. Operators who manage their own wells may also own non-operated working interest in nearby wells, shrinking the ownership pool of Permian wells to a handful of companies.
The risk to mineral and royalty owners from putting the future of Permian development in the hands of a few major producers is that they may not see new wells on their property if they hold non-core assets. Basin pure play operators are likely to continue their laser focus on the heart of the Delaware and more diffuse activity across the Midland. A supermajor with prime drilling inventory in the same areas may defer new projects as it prioritizes an even more capital intensive, multi-year deep-water development project. However, as technology evolves and economics shift, other areas of the Permian may see renewed activity, such as the gas-rich southeastern extension of the Midland.
Strong oil output from the Permian also makes it a top producer of associated gas. Lack of midstream takeaway capacity has forced operators to either flare gas, sell at a lower price, or even pay to have gas hauled away. Pipelines and LNG facilities on the Gulf Coast will finally allow stranded Permian gas to find a profitable end market.
With the most economic region concentrated in Louisiana with economic pockets all over the Texas and Louisiana side of the play, the Haynesville Shale is poised to shine. With many LNG facilities on the Gulf Coast nearing completion in 2025, operators have committed to meeting LNG export contracts by pre-positioning DUCs until the time is right. For mineral and royalty owners in this region, expect to be in pay on new wells as soon as next year as DUCs are rapidly put on production.
In the next couple of years Haynesville drilling could increase as much as 50% to sustain contracted LNG exports. Previously competing with the Eagle Ford in gas markets, the Haynesville will quickly become an LNG-focused producer of feedstock. Once LNG export capacity is maximized, the flurry of development should plateau as the emphasis shifts to incremental drilling to replace feedstock reserves.
While the Permian has been reduced to a few major operators, consolidation in the DJ Basin over a longer period of time has left even fewer producers in the Rockies. Though ample drilling locations still reside within the core of the play, virgin rock is quickly dwindling. Operators are steadily drilling out their remaining sites according to development plans filed with the state of Colorado, so if there’s any place mineral and royalty owners can truly anticipate where and when a new well will start generating new revenue, it’s the DJ Basin. As it turns out, Colorado’s strict regulations merely created guard rails that provide better clarity into new production instead of stopping development altogether.
Mineral and royalty owners with property in the fringe of the DJ Basin will likely continue to see some drilling activity but from smaller operators looking to expand the less economic parts of the play.
Expect Bakken development and production to continue holding steady in 2025. Activity has started to move out from the core; however, unlike other basins where operators resort to less productive fringe sections, tier-two acreage is looking just as good as tier one. And continuing to buck the trend of other basins where consolidation has thinned the ranks of operators, the Bakken is seeing DUC count being built back up by both public and private operators.
Given its maturity and prolific number of legacy shale wells, the Bakken is an ideal candidate for refrac using the latest completion designs and proppant loading. Yet not all wells are created equal in the Bakken. Many wells that were drilled before 2015 were completed with an open hole design, i.e., the production casing was not cemented in place. As a result, these wells are not suitable for recompletion, underscoring the need for mineral and royalty owners to know the age of their wells and their completion design. Existing wells on your property may be destined for a second life or merely plugged and abandonment.
Mineral and royalty owners with assets in Oklahoma will be waiting a long time for new wells to go in on their property unless they have the opportunity to sign a lease with a smaller, private operator. Multi-basin majors who hold acreage by production simply aren’t attracted to the poor economics – driven by production complexity and operating difficulty – compared to other drilling inventory they own, leaving little incentive for them to put their money to work in the SCOOP/STACK or other sub-basins of the Midcontinent.
Oil and natural gas can still be readily produced across many parts of the large Midcontinent oilfield, which is why private oil & gas companies with the appetite for risk are willing to drill. Natural gas is also stranded with larger, better positioned gas plays between the Midcontinent and the Gulf Coast, discouraging pipeline build out and constraining prices.
The Appalachian Basin may have short-term pain in terms of operator activity, but it has a long term bright future as a premier natural gas resource with some oil potential.
The basin is well understood in terms of resource opportunities and economics, from the NGL rich Marcellus gas play to Utica’s core dry gas play. Though avoided in recent years for its poor economics relative to other basins, operators are starting to return in small numbers to the western oil rich section of the Utica primarily on the Ohio side. And across the basin DUC inventory has been drawn down, which will likely result in increased drilling in 2025.
Like the Haynesville, the Appalachian Basin is a world class resource whose time to shine is less about economics and more about waiting for the right end market. Ideally situated next to large population centers, the Marcellus and Utica could diversify from a focus on fueling nearby power generators to take advantage of global demand if LNG facilities are built on the East Coast.
Over the last decades the US has made big strides towards achieving a net zero emissions profile. This includes replacing coal-fired power generation with less carbon-intensive natural gas along with a mix of solar, wind, and geothermal energy. Indeed, it is a mix of energy sources that is key to achieving net zero rather than relying on one approach or technology alone and CCUS will play a role as well.
Two of the country’s largest oil producing states are leading the charge into carbon capture and storage. Both Texas and North Dakota have the existing infrastructure to jump-start CCUS with CO2 pipelines used for enhanced oil recovery and depleted gas reservoirs that can be repurposed for storage. To succeed, CO2 transportation and storage will have to scale up further along with significant investment in carbon capture technology at emissions sources, mainly power generators, natural gas processing plants, and industrial natural gas users.
As CCUS becomes a viable business and strategy in the toolkit to achieve net zero, lawmakers are deciding who actually owns the pore space in reservoir rock into which CO2 will be injected. This is good news for owners of surface rights as royalty revenue goes to the surface estate and not the mineral estate in most states.
As ambitions have grown around net zero, the momentum has slowed in the implementation. With several CCUS projects under construction and more permitted, opposition to the required infrastructure has slowed progress and future regulatory changes may also impact projects. But given the unstoppable march toward net zero, CCUS will ultimately succeed with sufficient investment and innovation. For mineral owners with a large surface estate, the opportunities have never been more exciting as new royalties and revenue streams emerge from both CCUS and renewable energy projects.
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