As we navigate the complexities of the second half of 2024, it is essential to stay informed about the evolving landscape of the minerals and royalty market. This e-book distills insights from both our Enverus and Enverus Intelligence® Research* (EIR) teams based on our mid-year webinar, shedding light on pivotal trends such as natural gas and oil price forecasts, the intrinsic value of minerals, basin-level activities and the nuanced challenges and opportunities associated with revitalizing mature fields.
*Investment advisory products and services provided by Enverus Intelligence® Research, Inc. Visit www.Enverus.com/disclosures for additional information.
Research written by:
Phil Dunning, Director of Product, Enverus
Oil & Gas Research Team, Enverus Intelligence® Research
Dive deep into the minerals and royalty market’s evolving landscape as our experts unravel key trends for the latter half of 2024, from nuanced shifts in oil and gas pricing to strategies that unlock the true value of minerals and increase basin activity. Attendees will learn how to skillfully navigate the challenges and seize the opportunities in revitalizing mature fields, all while adapting to the rapid changes in market dynamics. Additionally, gain insight into how these factors combine to shape investment opportunities and strategies in an era marked by fluctuating energy demands and economic considerations.
As mineral and royalty owners, we have come to bemoan the cost of globalization as geopolitics and events halfway around the world influence what’s on our checks. At the same time, we read the headlines about decarbonization and dwindling demand for oil domestically as electric vehicles replace the combustion engine. But globalization also brings access to emerging markets for hydrocarbons and even the rise of AI, pointing to strong demand for oil and gas in the decades to come, so it’s still a good time to be in the minerals business.
A look at the energy industry over the last five years has seen oil and gas transform from growth oriented to value driven. The zealous drilling that led to oversupply and capital destruction intersected with demand destruction in 2020. And since 2021, the new normal has continued with operators focused on capital discipline, optimizing remaining inventory and returning maximum value to shareholders.
The name of the game in 2024 is consolidation. The midmarket is vanishing with the steady flow of mega mergers and acquisitions, which is having a knock on effect as multi-basin E&Ps redirect capital allocation from less economic acreage to the most profitable tier one drilling inventory.
While it may feel that mineral and royalty owners are simply along for the ride, knowledge is power. Let’s start with EIR’s price forecast so you can feel more empowered about what your royalty checks will look like in the coming years.
From $1 Mcf during the pandemic to $9 Mcf following the short lived energy panic in Europe during the early days of the Ukraine war, natural gas has finally settled down into its relatively normal range of $2 to $3. Recently, gas prices have drifted lower due to the oversupply of cheap associated gas in the Permian Basin, where it’s not uncommon for operators to pay midstream companies to haul away the commodity with negative Waha prices, or else just flare it.
While Permian natural gas takeaway bottlenecks are eventually resolved with new pipelines coming online in 2026, pure gas plays like the Haynesville are biding their time and positioning their leases and permits in anticipation of new LNG export facilities being completed in 2025. When this occurs, capitalizing on rising natural gas prices is all about location as realtors always say. Indeed the best real estate will be the Haynesville and southern parts of Appalachia with other basins further away having to compete and pay higher transportation fees to the Gulf Coast.
Putting even more wind in the sail of natural gas prices, EIR expects domestic demand to rise to meet the escalating need for power generation in the US. Beyond the normal increases in base load as communities grow, the demand increase is being led by the steady growth of electric vehicles and the insatiable appetite for data centers and heat pumps largely driven by AI and the need for more and more computational power. Data center power generation demand alone is expected to drive up to 4 Bcf of growth over the next five years.
It’s a growth market for natural gas from next year onward, especially in the south – but what about renewable energy that has seen explosive growth? Consistency is king on the power grid, so when the sun isn’t charging solar farms and the wind isn’t powering turbines, natural gas is the fuel supply that can deliver reliable power into the future. All good news for your royalty checks.
Unlike gas, there is no stateside demand growth driver for oil, making output from North American basins very dependent on the global demand picture. From the lows during the pandemic to north of $100 after Russia’s invasion, oil prices have settled into a $75 to $85 per barrel range. The days of the U.S. claiming a swing producer status are gone, giving way to a realization that overproducing only comes back to haunt North American operators and that the new price range is a good fit for our own economics while keeping OPEC+ happy.
Pre-pandemic, EIR asserts that domestic oil demand was driven by motor fuels, jet fuel and kerosene. And despite increasing EV use, today’s demand picture is largely driven by increases for motor and jet fuels, telling the rebound story as COVID travel restrictions gave way to record numbers of flights and road trips.
On the spectrum of energy maturity, the U.S. and even China are shifting into less fossil fuel intensive economies through EVs and renewable power generation. Yet there are still many countries who must rely on coal because their economies lack adequate investments in LNG, natural gas, nuclear or renewables. Instead of blaming globalization for wreaking havoc on our royalty checks over the last decade, mineral and royalty owners should count our lucky stars that declining demand for oil in the U.S. is more than offset by emerging energy consumers in India and Africa. Remember that the next time you drive by a pumpjack in your Tesla.
Operators today are laser focused on remaining inventory, so placing a value on your mineral and royalty interests starts by understanding whether your assets are Tier 1 or Tier 2, as the prime locations have the best well productivity, economics and midstream infrastructure. What’s more, every well produces oil with widely varying composition. Did you know that oil can appear green, red and black? Differences in chemical compounds and hydrocarbon quality yield different grades that are considered when valuing your assets. This is why our industry and commodity markets use benchmarks like Brent and West Texas Intermediate to reference a specific grade, quality and location.
In the M&A market, we can see that royalties have historically received a premium over working interests and that depending on asset location and upside potential assets receive higher valuation or discounted. Regarding upside, more than half of deal value is now driven by proven-developed-producing vs. undrilled acreage. This is akin to selling a farmhouse where there is a different value between existing construction and the undeveloped land.
Across most North American basins, the activity can be described as status quo with operators shoring up acreage positions. It’s no surprise that Texas remains the growth driver where there’s no acreage left behind. There isn’t one part of Texas with horizontal opportunity that isn’t being drilled, from the Permian and Eagle Ford to the Haynesville and even the Barnett Shale.
The crown jewel of U.S. production is always the Permian; it has it all – the stacked pay, good economics, ideal location to Gulf Coast, running room/inventory, and a favorable regulatory environment for growth.
It’s good news for Permian mineral and royalty owners as development activity continues all over the basin. However, activity in the Delaware appears to be changing as permits point to more focused activity north of Loving and Reeves Counties with the Midland side of the Permian remaining diffuse. When it comes to leases and the longer term view of activity in the basin, the opposite is true with focus shifting to shore up positions in Midland, Martin and Howard Counties and the Delaware side spread out.
Most development activity is centered on the Louisiana side of the Haynesville where the basin is more economic. Permits, leases and drilling activity indicate a holding pattern as operators with export contracts prep for the 2025 gas boom when LNG export capacity comes online.
Recent drilling activity has been spread out from the core and Karnes Trough to the southern border area and north to the Eaglebine. Once thought to have been drilled out, the Karnes Trough is seeing a resurgence as indicated by drilling permits for a new generation of child wells. There is only a little leasing activity in the northeast with much of the basin held by production.
Much of the DJ has consolidated into just a couple of key players amidst heavy regulatory reforms with infill drilling limited to places away from communities. Chevron dominates in the DJ and if the development dollars shift out of the basin that 50% activity will stop, not welcome news if you live in the Rockies. A partial silver lining, leases are still active in the northeast between Laramie and Weld Counties.
The Powder River continues to be a basin that attracts operator attention one day and loses it the next. Those who remain are permitting in south Converse and Campbell Counties with leases all over the place as existing producers shore up their acreage positions focused on core assets vs. less economic extensions.
The Bakken is beginning to look like the DJ Basin as consolidation reduces the number of operators to a few, e.g., the recent acquisition of Grayson Mill Energy’s Bakken assets by Devon Energy. This is a warning sign to mineral and royalty owners as the Bakken is subject to exodus of development capital from large operators via M&A who are chasing the best economics in the Permian and other basins.
An honorable mention to Midcon where there are many mature fields. The small operators who remain are focused on squeezing maximum return from aging assets while multi-basin majors are shifting development dollars to better long-term prospects.
Utah’s biggest oilfield has enjoyed a brief surge of interest over the favorable economics and waxy oil. However, interest owners shouldn’t expect much going forward given the limited development activity and consolidation that is likely to drain capital out of Uinta into other basins with better runway.
Dominated by basin pure play majors like EQT and Antero, permits are mainly limited to the tristate area and Sullivan and Bradford Counties. However, there has been increased activity by EOG on the oily side of the Ohio border where leasing has taken off.
It’s possible to double the life of certain oil and gas assets, extending your royalty checks from 10 years on a well to 20 or even 25 years. Beyond enhanced oil recovery techniques like CO2 and water flooding, refrac, infill drilling and drill overs are poised to bring back production and royalty revenue.
Since the shale revolution accelerated around 2010, drilling and completion designs have evolved rapidly. This has left a large number of parent wells across major basins with wide spacing and under stimulated hydraulic fracturing treatments as early completion designs utilized inadequate proppant. First generation natural gas shale wells, which are subject to decline from sand issues, are also good candidates for refrac. To qualify for a refrac, wells have to meet specific criteria, including cemented casing. This eliminates wells which use an open hole design.
For the four major basins where over half of assets have been drilled, EIR believes redevelopment in the coming years will breathe new life into the Eagle Ford, Bakken, DJ Basin and SCOOP/STACK. Additional basins that will benefit from redevelopment include the Delaware, Haynesville, Marcellus, Midland and Utica.
The increased activity in the Karnes Trough noted above is a great example of this redevelopment trend where generation one shale wells from 2011 to 2014 with under loaded proppant are being pump to modern frac design (from 600 pounds to several thousand pounds per well). Plus, the uptick in permits points to tight infill drilling needed to bring the field up to modern well spacing design.
From redevelopment and abundant remaining inventory in the Permian and Haynesville to a long term favorable natural gas price outlook and steady global demand for oil, interest owners still have ample opportunity and room to grow on royalty checks.
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