A New Approach to Minerals Valuations

[Editor's note: A version of this story appears in the 2020 edition of Oil and Gas Investor’s Minerals Business Supplement. See more stories like this here.] 

The U.S. mineral and royalty market has evolved sub­stantially over the past three to four years as mineral buyers have taken a new approach to valuation and substantial capital has been allocated to the sector. As ad­ditional sophistication has entered the space, valuations have trended toward a discounted cash flow approach, which more accurately ascribes value to both producing and undeveloped reserves, versus the more traditional method where buyers bid a multiple of annual or monthly cash flow generated by the assets.

While cash flow multiples and cash yield are still import­ant factors in buyers’ ability to pay in the current market en­vironment, the deciding factor in valuation has transformed into the inherent risked value of future production and asso­ciated revenues, i.e., a discounted cash flow analysis.

Similar to the approach employed by working interest acquirors for decades, mineral and royalty buyers are now focused on detailed technical work as they form views on potential future cash flows and ultimately risked net pres­ent value. Mineral/royalty cash flow is now projected—and value is determined—by well/location and reserve category, with riskier reserve classifications discounted at increasingly higher discount rates.

Proved developed producing (PDP) cash flow, the low­est risk reserves, are forecast per well based on historical production data, while the remaining, riskier (non-PDP) value is based on type curves generated by reservoir engi­neers with higher discount rates applied.

Due to minerals and royalties having no associated costs of production (capital or operating costs), buyers typically utilize lower discount rates than those for a similar working interest position due to the former having zero cost risk—an extremely attractive proposition, especially in highly capital intensive, rapidly growing basins.

Key valuation factors

Commodity pricing is the largest driver of market value for mineral/royalty assets due to its impact not only on mineral revenue but also on operators’ returns and will­ingness to spend capital developing the mineral position—and thus the development pace of the mineral resources.

Similar to a nonoperated working interest package or a midstream position, mineral owners lack operational control, and development pace is a primary focus of buy­ers. Valuation underwriting is typically based on historical average pace held constant going forward; however, with proper rationale and justification, increasing development pace can also be utilized during bid formulation.

Another important facet of minerals valuation is type curve generation, with the resulting per-well reserve estimates uti­lized to project production and cash flow from future non- PDP wells and locations. Similar to an increase in commodity price, a commensurate increase in type curves leads to a sim­ilar increase in the value of the mineral position. Engineers must take care when selecting offsetting wells for use in type curve analysis, taking into account well vintage, lateral length and completion techniques, among other parameters.

Multiple horizons often exist across a sales package, and type curves must be generated for each zone with typically multiple type curves for each horizon, e.g., three Wolfcamp A type curves, two Wolfcamp B type curves and four Lower Spraberry type curves for a Midland Basin minerals package. While a concentrated package contained in a handful of adjacent units may require a single type curve for valuation, a more typical, diversified mineral package across multiple townships (or even coun­ties) may require dozens of type curves per zone.

The third key variable in determining mineral value is development pace, i.e., when future wells come online and commence production. For drilled but uncompleted wells (DUCs), timing is typically based on each well’s spud date, while the start dates for permitted locations are typically based on the granted date of the permit.

The length of time between spud date and completion date (DUCs) and between permit date and completion date (permits) is usually based on the historical average for similar wells and permits within the basin.

The final delay, which is unique to mineral and royalty owners, is the length of time required from completion to receipt of cash flow/revenue checks, which is typically based on historical averages, e.g., three to six months post-completion. (Figure 1)

Undeveloped inventory

While forecasting cash flow from PDP, DUCs and per­mits is relatively straightforward, the most complicated reserve classifications to be valued are those containing undeveloped inventory—locations which have not yet been drilled or permitted.

There are two main approaches here: first, the spac­ing unit model, where drilling spacing units (DSU) are drawn across the acreage position and discrete remain­ing inventory is assigned for only these units along with actual owned royalty interest (RI) per well; and second, the super unit model, where broader development areas are drawn, capturing acreage both on and off the mineral position, with an artificially low RI per well.

The former approach is best used for packages with a smaller footprint and/or a limited number of operators where the buyer can reasonably estimate development tim­ing on the mineral and royalty lands, while the latter is typi­cally best used for a diversified package providing statistical exposure to the basin and where it is more reasonable to forecast basin-wide activity versus on-mineral activity.

For example, in the super unit example (Figure 2), Area A would be more valuable than Area B due to higher net royalty acres (NRA), lower gross acres and higher rig count (ignoring any variances in type curves).

For either approach above to valuing undeveloped re­source, a buyer first needs to estimate working interest economics—including drilling and completion capital, lease operating expenses, production taxes and royal­ties—for each type curve.

For those areas that generate adequate working interest returns in the current environment, inventory is included in the minerals development program and valuation. This remaining economic inventory—beyond PDP, DUCs, and permits—is based on well spacing by type curve area by bench, which is estimated based on geologic interpre­tation of in-place oil and gas volumes along with regional down-spacing tests.

Finally, the inventory is assigned to specific reserve cat­egories by level of risk, e.g., proved, probable, possible, resource, and a development schedule is applied to esti­mate the pace at which future inventory is brought online by operators.

Types of mineral and royalty assets

Beyond the technical merits of a mineral and/or royalty position, it is also important to understand the different types of mineral and royalty assets, with two primary cat­egories: mineral interests and overriding royalty interests.

Minerals are traditionally considered more valuable as they include perpetual ownership of the oil and gas hy­drocarbons contained within the position, whereas over­riding royalties are carved out of a working interest and can expire along with the lease.

Varying rights also exist within the broader minerals category, with full mineral interest including rights to ne­gotiate leases and collect lease bonus and royalty pay­ments with and from operators (highest value), followed by nonexecutive mineral interests, which include the same rights as mineral interest owners except the right to ne­gotiate the lease, and finally nonparticipating royalties, which also exclude the ability to collect lease bonus and delay rental payments (lowest value).

An important parameter to understand when evaluat­ing mineral and royalty assets, and analyzing valuation comparables, is the definition of net mineral acres (NMA) and net royalty acres (NRA). While net mineral acres rep­resent the surface lands under which you own a right to receive a royalty, NRA normalize NMA for the royalty rate being paid to the mineral/royalty owner.

This technique must be utilized as 100 NMA leased at 25%, for example, is worth 25 times the same NMA position with a 1% overriding royalty; value has a direct correlation with the royalty rate received.

The two most common techniques to normalize NMA to NRA are (i) NRA normalized to 1/8 th royalty, with NRA1/8 equal to NMA multiplied by royalty rate and di­vided by 1/8 th; and (ii) NRA simply normalized to the roy­alty being received, with NRAnet equal to NMA multiplied by royalty rate.

For example, if a seller owns 100 net mineral acres leased at a 25% royalty, this equates to 200 NRA1/8 (100 NMA x 25% / 12.5%) or 25 NRAnet (100 NMA x 25%). Thus, an offer of $2 million for these 100 NMA implies $10,000/ NRA1/8 or $80,000/NRAnet—a substantial difference.

Care must be taken to ensure “apples to apples” com­parisons are made in trading and transaction comparables analysis. (Figure 3)

Minerals A&D

Over the past few years, mineral and royalty acquisitions have increased from less than 5% of sub-$1 billion A&D activity to approximately 35% year-to-date 2020, as three main buyer classes have allocated substantial capital to the sector: public mineral companies, private-equity min­eral companies (and sponsors), and nontraditional public companies. (Figure 4)

Public mineral E&Ps peaked at approximately $12 bil­lion in market capitalization in 2019 as Viper Energy Part­ners LP, Black Stone Minerals LP, Kimbell Royalty Partners LP, Falcon Minerals Corp. and Brigham Minerals Inc. went public on U.S. exchanges from 2014 to 2019.

However, these companies’ collective valuation has pulled back by over 50% due to the degradation of two of the main drivers of mineral value: commodity pricing (due to oversupply and drops in demand for both crude oil and natural gas) and development pace (as operators pull back horizontal activity throughout the country in response to the low-price environment).

Most energy-focused private-equity sponsors have es­tablished mineral acquisition efforts either at the sponsor level or within their portfolio of funded companies. Sev­eral successful private-equity companies have been built and achieved exits throughout highly economic and active basins, most notably the Permian.

Finally, two nontraditional public companies have also been active in the space: Franco-Nevada Corp., a Toronto-based company primarily focused on precious metals royalties, and Alliance Resource Partners LP, a legacy coal producer with a large footprint of existing minerals throughout the U.S. Both Franco-Nevada and Alliance have large balance sheets and a lower cost of capital than public- and private-equity mineral compa­nies, allowing these entities to be highly competitive in sales processes.

The Permian Basin has accounted for the majority of ac­quisition activity over the past three years (~35%) as mineral buyers paid a premium to enter the most economic and ac­tive basin in the Lower 48, followed by Appalachia (driven by Range Resources Corp.’s Marcellus overriding royalty sales) and the Midcontinent (led by Franco-Nevada’s $500- plus million joint venture with Continental Resources Inc.).

Minerals in the current environment

Due to the recent drop in commodity pricing, rig activity and asset values, mineral owners have been hesitant to market for sale larger assets following the COVID-19 lockdowns and OPEC+ supply glut. On-the-ground ac­tivity for smaller transactions, however, has remained relatively constant as cash-strapped owners (typically families or individuals) need to raise capital in the eco­nomic downturn.

As with any asset class tied to the upstream sector, min­erals and royalties sellers’ willingness to transact is severely impacted by commodity price volatility. The second quarter of 2020 was the most volatile quarter over the past decade, and recent transaction activity is down substantially in the mineral and royalty sector. However, we anticipate sellers to begin considering divestitures as volatility decreases and hopefully as commodity prices recover.

The middle market traditionally recovers more quickly than the market for larger assets, a divergence we ex­pect to be especially pronounced over the next 12 to 18 months as capital remains scarce for the industry as Wall Street (and now blue chip private equity) reevaluate risk and returns in the broader oil and gas industry.

In conclusion, minerals and royalties are an exciting subsector of oil and gas that has experienced tremendous growth over the past three to four years as well-capitalized public and private acquirors allocate large sums of capi­tal to the space. Valuing minerals and royalties requires the same approach as evaluating working interest proper­ties—forecasting PDP and nonproducing future cash flow based on detailed technical diligence, with increasing dis­count rates applied to higher risk reserve classifications—albeit with no capital or operating costs.

The mineral and royalty sector continues to offer an incredibly attractive investment opportunity due to the exposure provided to the U.S. leading position as a pro­ducer. While production levels have fallen off in recent months due to supply and demand considerations, the innovation and expertise of our country’s oil industry will undoubtedly unlock more value for decades to come.