• What type of interest? E.g., Mineral, Royalty, Overriding Royalty, Working Interest, Production Payment, Executive Rights, etc.
• How large of a geographic area – i.e. how many surface acres – does it cover?

• What is the lease royalty?
• How much of the original acreage remains subject to the lease?
• What other monetization opportunities does the lease provide?
• How has pooling impacted the division of interest?

• What type of interest? E.g., Mineral, Royalty, Overriding Royalty, Working Interest, Production Payment, Executive Rights, etc.
• How large of a geographic area – i.e. how many surface acres – does it cover?

• What is the lease royalty?
• How much of the original acreage remains subject to the lease?
• What other monetization opportunities does the lease provide?
• How has pooling impacted the division of interest?

While the operator’s potential obligations to the mineral owner are too numerous to cover here, there are three primary value categories that require active oversight:Operator’s Ability to Hold Acreage: Oil and gas leases often restrict the amount of surface acreage and/or the non-producing formations that operators can hold through existing production. In such cases, the operator is generally required to record a release of the lands and depths that are no longer subject to the lease. As an industry standard, actual compliance with these release requirements is generally low. This results in considerable amounts of unleased acreage/depths that appear to be leased as of public record, potentially preventing additional leasing and bonus opportunities.

Operator’s Ability to Pool Acreage/Drill Allocation Wells: Most oil and gas leases place reasonable restrictions on anoperator’s ability to pool acreage into a producing oil or gas unit or drill allocation wells. Though pooling is invalid where minerals are pooled beyond the authorization contained in a lease, it is often incumbent upon the mineral owner to monitor compliance.

Surface Operations: Often, surface use on hydrocarbon-producing lands can yield significant value in terms of agricultural or recreational use. Oil and gas leases place varying degrees of restriction on an operator’s surface use and/or need to remediate the impacts of surface operations. These include surface acre restrictions for drilling sites, the maintenance of fences and roads, usage of water, and the need to return the surface to its original condition after any development.

Massive Minerals Management ensures that where oil and gas leases limit the acreage or depths that operators are allowed to hold from production or pooling, releases are filed of public record so that the relationship of the parties is clear and any potential cloud on the mineral owner’s title is removed. We also review the actual operations to ensure that any surface or subsurface operations are being conducted in compliance with the lease, and that any previous operations and environmental hazards have been appropriately remediated

The Environmental Protection Agency estimates that there are 2.1 million unplugged and abandoned oil and gas wells in the United States. These unplugged and abandoned wells not only cause significant environmental damage and pose public safety hazards, they can materially impact the market value of any tract of land.Environmental concerns from improperly managed operations are not limited to abandoned wells. Improperly mitigated surface drilling locations, tank batteries, production facilities, and frac tanks/ponds can all pose significant risks to health and safety, as well as materially impact your ability to use, develop, or sell your surface.

Massive Minerals Management works with clients to not only identify these improperly mitigated surface hazards, but more importantly to navigate the contractual relationship with oil and gas operators and administrative procedures with state agencies to eliminate these environmental concerns.

Can you locate your mineral holdings on a map?
Are you certain as to the exact size and nature of your mineral interests?
Have you compiled a comprehensive collection of all records – oil and gas leases, deeds, and agreements – that will be necessary for the next generation to accurately administer these assets?
How does production this month/quarter compare year over year?
What is the production forecast for the next quarter, year, etc.?
At Massive Minerals Management, we seek to create massive outsized value for clients not only in the monetization of their mineral assets, but also in empowering them with the knowledge they need to make informed decisions regarding their mineral portfolio. Much more important than providing data, our goal is to ensure that clients are educated and aware of the meaning behind the data.

While any number of variables can result in mineral owners being underpaid on production, the most common are:a. The operator has under-credited the mineral owner’s interest in the tract.
Prior to disbursing funds from a well’s production, an operator typically obtains a legal title opinion that sets out each interest owner’s share of royalties from production. Deed interpretation is often a complex task that involves a number of judgments and assumptions by the examining attorney. It is imperative that prior to signing any agreed division orders or accepting royalty payments, mineral owners ensure that they are credited with their correct and full interest in production.b. The ownership interest credited for payment does not match the agreed interest in the division orders.
Due to the volume and complexity of oil and gas production accounting, at times the fractional interest in production credited on revenue statements can differ from the agreed fractional interest stated on division orders. Prior to accepting any royalty payments, mineral owners must be confident that their revenue statements are based on the correct interest for each well or producing unit.c. The operator is charging post-production costs in contradiction to lease terms.
While royalty interests are generally considered to be cost-free in terms of production costs, they may be subject to their proportionate share of post-production costs. These include compression, transportation, dehydration, and marketing costs associated with bringing the hydrocarbons to market. Depending on the terms of your lease, however, you may be exempt from bearing these post-production costs.When an operator unintentionally deducts post-production expenses on a no-cost lease, investors can lose as much as 25% of their revenue, or in extreme cases be responsible for negative royalties.Massive Minerals Management utilizes a comprehensive software-based approach to link client revenue statements with lease records to ensure that any inappropriate royalty deductions are identified and rectified. This includes monitoring the manner in which deductions are categorized and reconciling the realized versus benchmark pricing for the various commodities involved.d. The operator is behind on payment and has not paid the statutory interest.
The Texas Natural Resource Code § 91.402 governs the time in which oil and gas operators must pay royalties on oil and gas production. Similarly, North Dakota Century Code Title 47-16-39.1 provides the required timelines for payment of royalties on production to mineral owners. Each oil producing state has its equivalent statute, generally providing that late payments may result in the operator being responsible for statutory interest in addition to the royalties owed.e. Underreported Production/Sales Volumes
Production accounting is an inherently complex process, further complicated by the fact that oil and gas companies are subject to two separate yet overlapping monthly production reporting periods. The first of these is dictated by the various state regulatory agencies – all producers must comply with rigid government production reporting requirements on a well and/or lease basis.These governmental reporting requirements often vary widely from state to state. At the same time, operators must account to all interest owners for production sales on a monthly basis in order to determine and issue payments.Due to this complexity, reported production in these two periods does not always align. As a result, it is not uncommon for mineral owners to be underpaid because the production volume reported on monthly revenue statements is less than the number ultimately reported to the state.Identifying these volume discrepancies is difficult due to the highly fractured datasets, numerous commodity datapoints for oil, gas, or NGLs, and varying reporting standards from state to state.Massive Minerals Management utilizes a software-based approach to reconcile multiple production data streams – both public and private – in real-time to ensure that all royalty payments are based on actual state-reported volumes. Where discrepancies arise, we are able to quickly begin recovering any underpaid funds.f. Right to Recover Unpaid Royalties Can Be Forfeited Over Time
Not only is it common for unintentional mistakes in payment to be made, this problem can be compounded by delay in seeking to recover unpaid royalties. Texas law, for instance, places time limits on the ability of mineral owners to seek re-payment for improperly paid royalties, and in many cases delay in seeking payment will not be excused where the mineral owner could have discovered the underpayment with reasonable diligence.Massive Mineral Management monitors payments in real time as they are disbursed by the operator to ensure all payments are timely, are calculated according to the correct interest, and made in strict compliance with the terms of the governing oil and gas lease. Where discrepancies are discovered, we take immediate action to prevent the passage of time from limiting our ability to recover the maximum amount possible.

Monthly production volumes provide insight into a number of potential issues and should be closely monitored for many reasons.The most important of these are to identify any potential lease termination issues. Aside from a total cessation of production, un-mitigated low production volumes over time can cause an oil and gas lease to terminate. The failure to timely raise issues or obtain a release in these situations can result in a mineral owner’s inability to exercise its rights, or in the worst-case scenario the operator adversely possessing the right to produce minerals.

An on-going comparative analysis of monthly production volumes can also spot trends short of lease termination that are important for mineral owners. These include negatively-trending cash-flow projections or early indications of reservoir depletion.

Massive Mineral Management tracks production volumes and performs monthly period-over-period analysis (monthly, quarterly, yearly, etc.) to monitor trends and gain valuable insight into likely future outcomes. This analysis is provided on a monthly basis to ensure that clients are kept updated and informed as to the comparative performance of their mineral portfolio.

The presence of a producing well adjacent to a property line could signal that hydrocarbons are being drained from under the neighboring lands. While all states have strong regulatory regimes governing how close a well can be to a neighboring tract to combat drainage, the general rule, known as the Rule of Capture, provides that a drained mineral owner’s remedy is to drill her own well to essentially stop the drainage from occurring.Depending on the state, certain implied covenants exist that may require an offsetting operator to drill an ‘offset well’ to prevent drainage; these implied covenants, however, are difficult to enforce. For this reason, many oil and gas leases contain Offset Production Clauses that expressly define an operator’s duties in the event that a neighboring well is drilled adjacent to a lease line. These clauses often provide that if a producing well is drilled within a certain distance of their lease, the operator is bound to drill an offsetting well, release acreage, or pay compensatory royalties.

Determining whether an offsetting well has been drilled adjacent to your mineral estate requires vigilant monitoring of drilling and production activities for the lands surrounding your tract. Manually performing this process from the available public records is a time-consuming task. Massive Minerals Management utilizes a software-based approach to conduct a constant analysis of offsetting activities that enables us to monitor your entire portfolio in real time in order to identify any potentially draining activity. Should such potentially draining operations occur, we work with operators to determine the appropriate course of action under the terms of the governing oil and gas lease to ensure that clients are fully compensated.

When building a forecast of future income from production, it is critical that a mineral owner have an informed understanding of how the following variables will impact their income stream from production:a. What hydrocarbons are being produced?
b. What is the expected value of the commodity produced in 6 months, 1 year, 5 years?
c. How long has the well been producing?
d. Is it a conventional or unconventional well?
e. How much is production expected to decline over the next 6 months/1 year/5 years?
While the only constant is change, Massive Minerals Management empowers clients to make informed financial decisions by providing a realistic data and engineering based forecast of production that is responsive to changes in price, production volumes, etc.

How long you can expect an oil or gas well to produce varies widely depending on a broad range of factors that alter a well’s production profile. Namely, these factors include the type of well (horizontal or vertical), the type of hydrocarbons targeted (oil, gas, NGLs), and the nature of the producing reservoir itself. The expected productive life of the well, in turn, is one of the key drivers of a mineral owner’s expected monetary returns.Massive Minerals Management utilizes engineering and historical well data to develop a forecast of the productive life of your wells, so that you have a more complete picture of your expected monetary gains. This information is a critical component in your overall financial planning.

While there has been an informal market for mineral and royalty assets for the past 100 years, the past five years has seen exponential growth from a small private niche into a significant segment of the overall oil and gas industry. This growth has been driven largely by the entrance of both private-equity backed and publicly traded mineral acquisition companies, as well as oil and gas operator backed teams.The emergence of the mineral trade has significantly increased the liquidity options for mineral owners, as they now have an additional opportunity to monetize their mineral interests outside of revenue from production. For one, non-producing minerals can be monetized. Additionally, mineral owners have the opportunity to accelerate a portion of their returns by divesting a percentage of their producing mineral interests to pursue a more diversified investment portfolio, or perhaps to fund personal or philanthropic goals.

Anyone familiar with minerals assets, however, has heard the adage, “Never sell minerals.” There is definite truth in this prescriptive warning. Generally, individuals inherit or acquire minerals at a low or no cost basis. These mineral assets have been passed down by the family, with each generation standing more in the status of caretaker for the generations to come than individual owners or investors considering an asset’s worth.

Though the opportunity to sell your minerals exists, the appropriate question is whether you should consider exercising that option at all. Certainly, the expansion of the mineral market over the past half decade has resulted in mineral valuations that in some cases warrant exploration. Whereas mineral offers were traditionally crude estimations based on recent lease bonus rates or a mere multiple of existing production, today’s reputable mineral acquisition offers are generally backed by a more sophisticated reserves-based analysis.

First Question: Who is the Buyer?
While there is an increasing sophistication to the minerals market, the fairly low to non-existent barrier to entry means that mineral owners are confronted with a wide universe of would-be mineral buyers. These would-be buyers vary enormously based on their level of sophistication and ability to execute the transaction.

Thus, the first question when considering selling your minerals is whether this person or entity is an end-user or a mere broker. This is important for two reasons. The first is the proposed buyer’s actual financial ability to consummate the transaction. Often, mineral brokers will commit to a mineral acquisition on a 30-day closing period with no existing means to fund the sale. If they have not already lined up a buyer, their main focus in the ensuing 30-days is to find a buyer to whom they will flip the acquisition contract on the day of sale. In instances where they are unable to find a buyer within the agreed time frame, the sale is likely to never materialize. The broker’s inability to fund the transaction can result in an owner’s lost opportunity with other sellers, as well as frustrating delays that could manifest into legal disputes.

More importantly, divesting mineral assets to a broker is likely to result in a sub-optimal price. Certainly, brokers constitute a valuable function in the overall mineral market, in some cases creating or sustaining markets by ensuring a certain amount of deal flow between owners and end-users. As with utilizing any middle-man in a transaction, however, conducting a mineral transaction through a broker likely results in a lower price to the seller and higher price to the buyer. Without experience and an understanding of the mineral market, individual sellers approached with an offer are generally unable to discern the differences between these brokers and the end-user.

What is the Valuation?
The most important piece of data in a potential offer is the proposed price – what is the price the putative buyer is offering to pay? It is imperative that this price be compared against a realistic valuation of the mineral asset to be sold based on solid engineering and market principles, in order to ensure that fair market value is being achieved.

Comparative Analysis of the Offer v. Asset Value
It is not enough to simply know the price offered, however. In order to make an informed decision on whether to divest all or a portion of your mineral estate, it is imperative that you have a complete understanding of the underlying value of your asset. On a basic level, this includes an analysis of existing production, the likely future outcomes based on actual or likely decline rates from wells producing your minerals (i.e. type-curves), as well as reasonable assumptions regarding commodity price fluctuations.

When weighing a divestiture, it is important that your economic consider the full range of future outcomes – what is potential for, or likelihood of, additional drilling and production from your mineral assets? Commonly, this is known as the identifying the base case, development case, and best-case scenarios for future development activity, as defined primarily by the number of new wells to be drilled.

Once the range of potential future outcomes is identified, an economic evaluation will then look at the facts unique to your situation. These considerations include: What does past performance tell us about this particular operator’s likely ability to execute a successful development program? Based on available information about the operator, what are the reasonable expectations as to the development pace and timing for those future operations? How do the various sensitivities as to commodity price and initial production rates impact the valuation?

A reputable, reserves-based economic projection performed by a qualified petroleum engineer or geologist will answer these questions, and provide a solid basis for ascribing value to your mineral asset. This data-based valuation should form the basis for any potential divestiture decisions.

Once a reserves-based analysis has been conducted, any potential offer should be weighed against the prevailing market rate for minerals in the area. When considering an offer, a mineral owner should compare recent similar transactions in the area, particularly in terms of price. It is here – in pricing similar transactions – that the opaqueness of the mineral market places the highest premium on information. Relationships in the industry and access to market rates create real competitive advantage.

The “Why”: Why Sell?
Dependent on the price, selling all or a portion of your mineral assets can be a worthwhile undertaking. Before parting with these valuable assets, however, it is imperative that the mineral owner consider their own personal “why” for doing the deal. Will the funds from the sale be used to diversify an investment portfolio, and perhaps de-lever the owner’s position off of commodities dependence? Will the divestiture enable a time-sensitive investment or philanthropic venture?