Frequently Asked Questions
Don’t assume the highest price is the best deal. Determine which company seems the most transparent, professional, and has the funds to close. -G. Knight
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Over the years, we have realized that mineral owners are interested in selling their royalties and minerals for a variety of reasons. From selling a portion of royalty interest to add income for retirement, to selling non-producing minerals to buy land or help pay for college tuition, each customer is different.
Complexities in Owning Minerals
In many instances, mineral owners acquire ownership through inheritance or from their family members, which sometimes presents complexities that the new mineral owner may not understand or be privy to. Unlike inheriting stocks or bonds whose values are easily determined and can be speedily divested, mineral rights are generally not readily marketable or divested, and determining the value is always difficult.
One must determine how to “own” the asset of record, and how you hold title can significantly affect your estate upon death. These considerations of whether to hold title individually, in a corporate entity or trust, are decisions that should be made early on and can mitigate the need and cost for probates, especially since the ownership of oil and mineral rights will subject that asset to probate in the state where the right exists.
Because valuation is so difficult and there is no broad market for leasing and selling, many new, small, or simply inexperienced mineral owners elect to sell their minerals and invest in assets they know and understand and that is where we are able to help.
REASONS OWNERS MAY WISH TO SELL:
- QUICK, LUMP-SUM CASH
- TAX SAVINGS
- DEBT RELIEF + FINANCIAL BURDENS
- ESTATE PLANNING
- MONEY FOR OTHER INVESTMENTS: WEDDINGS, COLLEGE EXPENSES, DOWN PAYMENTS
- ELIMINATION OF ACCOUNTING HASSLES
We get this question all the time. Your value depends on many factors. Location of minerals, producing or non-producing, unleased or leased, royalty amount, regulatory activity (spacing, pooling, permits, etc.) and many more scenarios all play a factor in how much a buyer is willing to pay you today for your minerals.
What your minerals are worth today could be drastically different 6 months from now (both lower and higher).
The process should be similar to selling your home, but it isn’t. The market lacks transparency, liquidity and governance. We are successful as mineral owners because we have been in it since 1980, understand it and know all of the players.
To take advantage of the high mineral prices over the last 5 years, we have sold some of our minerals which we acquired back in the 1980’s and 1990’s and we know who the legitimate buyers are.
As mineral owners, we receive offer letters daily from companies offering high prices, usually with vague terms and conditions (see example). MOST of these companies are flippers, looking to tie down your minerals with a contract, and then hoping to find a buyer for a higher price. They are not looking out for your best interest. We know who they are – BUT you don’t.
It is a small community of players in this market and we all know each other. We keep a list of blacklisted companies – those who either we had some bad dealings with or our friends and partners have – and we share that information on who not to deal with.
There are several common mistakes that people make when they are looking to sell or lease their mineral rights. One of them is waiting too long to sell, thinking that they will get more money ultimately. Another mistake many make is that they try to sell their rights themselves. Although this option might work for some, it can result in a lengthier, more stressful process and less profit for you. Fortunately, with the right mineral rights specialist working with you, you can avoid most, if not all, of these pitfalls.
Determining Mineral Ownership:
This should be a matter of record in the courthouse of the county where the land is located. Tax Commission records may also help. You may need a landman or attorney to research this for you. If you are interested in selling or leasing your minerals, fill out this form and we can help determine what you own.
The types of documents that can change ownership on a real property account include (but are not limited to): a deed, title, a court order, a death certificate, or probate. In some cases, there may be a need to file more than one type of document to complete the process. The documents must be recorded in the county where the minerals are located. If you have any questions about the preparation or filing of a document, you may want to consult with an attorney, real estate professional or landman.
To calculate your division of interest (DOI) or payment decimal, in any well other than a multi-unit horizontal well you must know how many net mineral acres (nma) you own in the spacing unit, your royalty percentage, and the total number of acres in the spacing unit.
For example, if you own 40 nma at 3/16 (.1875) royalty in a 640-acre spacing unit, your DOI would be calculated as follows:
40 divided by 640 then x .1875 = .011719
To calculate your DOI in a multi-unit horizontal well you must know how many net mineral acres (nma) you own in the spacing unit, your royalty percentage, the total number of acres in the spacing unit, and the percentage of the well attributed to your spacing unit as described in the final multi-unit well order.
For example, if you have 40 nma at 3/16 (.1875) royalty in a 640-acre spacing unit and the percentage of the multi-unit well in your unit is 43%, you would calculate your decimal as follows:
40 divided by 640 x .1875 = .011719 x 43% = .00503917
A division order stipulates the percentage of royalty that one owns and is the instrument by which the oil company makes payment of proceeds. The royalty owner should ascertain that his or her percentage is correct before signing. If uncertain, they should contact their attorney, banker, or some knowledgeable source.
Deciphering Royalty Statements:
The Oklahoma Tax Commission (405) 521-3674 is responsible for collecting state production taxes on oil and gas produced in Oklahoma, and has the records on gross production, including volumes and values, from individual wells. The figures given to you by the oil company should match those reported to the Oklahoma Tax Commission. The Oklahoma Tax Commission can provide information regarding volumes and values of production sold.
Gas volumes can be found on the OCC website at www.occeweb.com. Oil volumes for wells that are classified as oil wells are only available by accessing the actual production reports in our Document Image Access database. To do this, you must know the Production Unit Number that was assigned to the lease by the Oklahoma Tax Commission and the purchaser number. Oil Production volumes are not available on the OCC website.
All sales of oil, gas, natural gas liquids, and reclaimed oil for the last twelve months can be found on the Oklahoma Tax Commission website at www.ok.gov/tax.
Payment of Proceeds of Oil or Gas Production: Payment of proceeds of oil or gas production is covered under the Production Revenue Standards Act, Title 52 O. S. Section 570.1, et. seq., which calls for first payment to be made within six months from the date of the first sale, and indicates that if not, interest is due. The Production Revenue Standards Act also provides various guidelines for the timely payment of royalties after the initial payment. District Court has jurisdiction when litigating these matters.
Once in pay, typically, royalty checks are issued once a month, usually near or on the last day of the month. For smaller interests, most companies will wait until you have accrued >$100 before issuing a check.
Your Royalty Paystub
The Production Revenue Standards Act contains a list of ten pieces of information that must be included with every royalty payment. They are:
- Lease or well identification,
- Month and year of sales included in the payment,
- Total barrels or MCF attributed to such payment,
- Price per barrel or MCF, including British Thermal Unit adjustment of gas sold,
- Total amount attributed to such payment of severance and other production taxes, with the exception of windfall profit taxes,
- Net value of total sales attributed to such payment after taxes are deducted,
- Owner’s interest, expressed as a decimal, in production from the property, must be carried out at least six spaces to the right of the decimal,
- Owner’s share of the total value of sales attributed to such payment prior to any deductions,
- Owner’s share of the sales value attributed to such payment less owner’s share of the production and severance taxes, and
- A specific listing of the amount and purpose of any other deductions from the proceeds attributed to such payment due to the owner upon request by the owner.
Wells in the State of Oklahoma?
Department in the Oil & Gas Conservation Division of the Oklahoma Corporation Commission handles all of the regulatory activity associated with the drilling of oil and gas wells in the State of Oklahoma. These actions include Spacing, Pooling, Increased Density, Permits, and Completions.
A drilling and spacing order issued by the Corporation Commission establishes a geographical area in which only one oil and/ or gas well can be initially drilled and produced from the geological formation listed in the order. The spacing unit communitizes all royalty interest owners for the purpose of sharing in production from oil and/or gas wells in the unit. A spacing order establishes the size of the unit; names the formations included in the unit; divides the ownership of the unit for the formations into the “royalty interest” (1/8) and the “working interest” (7/8); puts all the owners of royalty interests into one community; establishes that each unleased “working interest” owner has the right to drill within the unit, and; establishes an area within the unit where the well may be drilled.
Only one well can be drilled and completed in each common source of supply. The spacing order will also specify the permitted location where the unit well may be drilled. Under certain circumstances, additional wells may be drilled, but only after an application is filed, a hearing conducted, and an Increased Density Order is issued by the Commission.
Drilling and Spacing Unit:
Below is a list of the standard sizes for drilling and spacing units and the permitted well locations within the unit.
The well can be located no closer to the unit boundaries than this:
|640 acres||1320 feet|
|160 acres||660 feet|
|40 acres||330 feet|
|10 acres||165 feet|
|320 acres||660 feet|
|80 acres||330 feet|
|20 acres||165 feet|
A horizontally drilled well has a different footage setback requirement for the Well’s location but still often requires a Location Exception Order from the Commission. Horizontal wells are sometimes designated by an “H” in the well name, such as Smith #1H-10 or Smith #1-10H.
Below is a list of the standard sizes for drilling and spacing units for horizontal wells and the permitted well locations within the unit.
The well can be located no closer to the unit boundaries than this:
|640 acres||660 feet|
|160 acres||330 feet|
|40 acres||165 feet|
|10 acres||165 feet|
|1280 acres||660 feet|
|320 acres||660 feet|
|80 acres||330 feet|
|20 acres||165 feet|
Horizontal Spacing Size and Irregular Units:
In Oklahoma, horizontal well spacing can be the same size as any other spacing unit from 10 to 640 acres in a square or rectangular shape. Irregular 640acre horizontal units have been created by stacking two 320-acre units, creating a rectangular 640-acre unit that is one-half mile wide and two miles long.
In May of 2017, Senate Bill 867 was passed to amend 52 O.S. 87.1 (f) to increase the maximum size of horizontal spacing units from 640 acres to 1280 acres. The lateral length of the initial unit well must be at least 7,500’ unless reasonable cause is shown. Multi-unit horizontal wells may be created including 1280 acre spacings as long as the proposed completed lateral is at least 10,560’.
Irregularly shaped, non-square or rectangular, spacing units could be created to include “orphaned” acreage, but may not be done if not shown to be geologically feasible or productive. It might not be fair to the mineral owners in a producing unit to include non-producing acreage into the unit and, therefore, diminish their percentage interest in the total unit.
Typically, a horizontal well does not drain from as great a distance from the wellbore as a vertical well does so horizontal wells are allowed to be closer to each other and the section line than are conventional vertical wells. Every effort is 16 made to protect correlative rights of the mineral owners and to prevent a well from draining an adjoining unit.
Many horizontal wells have a surface hole location (SHL) in one section and one or more bottom hole locations (BHL) in another section. The interest owners in the spacing unit from which the well drains receive the royalty from a horizontal well. If you own the land on which the drilling rig is placed, the oil company must negotiate and compensate you for surface damages before drilling.
Normally, only one well is allowed to a common source of supply within a spacing unit. An increased density order of the Commission allows one or more additional wells to the same common source of supply within the unit. Standard spacing units and horizontal spacing units can co-exist with one well allowed per unit without the need for an increased density order. If an additional well is needed to an already developed common source of supply within either the standard or horizontal spacing unit, an increased density order is required for the additional well within that particular unit.
The drilling and spacing order determines the size and boundaries of the unit and the common sources of supply involved. Any person or company owning the right to drill a well within the unit may propose the drilling of a well. The company will try to reach agreement with all the other owners within the unit (does the owner want to lease to the company proposing the well or does the owner want to join in sharing the cost of drilling the well and thereby own a working interest in the well?).
If an agreement to develop the unit cannot be made with all the owners in the unit, the company can file a forced pooling application at the Commission. Under Oklahoma law, forced pooling provides a process under which the Commission sets the options for participation when owners cannot agree on unit development.
Fair Market Value:
At the pooling hearing, evidence will be taken to establish the terms that have been paid for leases within the subject unit and the eight offsetting units. The nine-unit area is the area the Commission usually considers in determining the value of leases. The purpose is to establish the fair market value of the land involved. Often the best evidence of fair market value is the highest amount paid, but sometimes it is not. Each case must be judged on the individual facts presented.
Cash Bonus Election under a Pooling Order:
After the pooling order issues, parties named in the pooling order have twenty (20) days to elect to participate in the proposed oil and gas well or to elect a bonus and royalty option. The pooling election must be made in writing within the allotted time. If an owner selects a cash bonus and royalty option, the order will state how many days the company has to pay the cash bonus. The cash bonus must be paid to those who elect it even if the well is never drilled or if it is drilled and the well is a dry hole. The Commission has no jurisdiction to force the company to pay a cash bonus. An unpaid cash bonus is considered a debt to be collected under the jurisdiction of Oklahoma district courts.
Elections to Participate in the Drilling of a Well under a Pooling Order:
Anyone electing to participate and join in the costs of drilling a well will be given a certain number of days to submit that person’s share of the estimated drilling costs or to make satisfactory financial arrangements for payment. The pooling election must be made in writing within the allotted time. Letters of credit are often accepted rather than up-front cash payment but the arrangements are different for each situation and the party involved depending on the party’s financial position and experience.
If a party fails to make a timely election under a pooling order, the order will provide that such party is deemed to have made a certain election. Normally, if a party fails to elect or elects out of time, the order will provide that a party is deemed to have elected a certain cash bonus and royalty.
If any party elects to participate but fails to submit the party’s share of the drilling costs or make timely financial arrangements with the company, the pooling order will also state that party’s election is rescinded or voided and the party usually will be deemed to have taken a specific cash bonus and royalty.
Leasing under a Pooling Order:
Generally, with rare exception, a person who is listed as a party in a pooling application and order may still lease his or her interest until the twenty-day election period provided in the pooling order has run.
Term of Pooling Order:
A pooling order often provides for 180 days to commence a well but may also provide for 365 days, if the extended time is provided in the notice of hearing. If the operator of the well does not commence operations within the specified time of the pooling order, the pooling order expires. It is not mandatory that the well be drilled; however, cash bonuses are due to those electing a cash bonus regardless of whether a well is drilled. In some cases, the Commission may grant an extension of time under the pooling order; however, the applicant is generally required to pay all or some percentage of the original cash bonus. No new election is usually provided, but a party may appear at the hearing to request a new election or protest the extension.
Statutory “pugh” clause:
Oklahoma has enacted a statutory “Pugh” Clause*, Title 52 O.S. Section 87.1(b), which provides that “in case of a spacing unit of one hundred sixty (160) acres or more, no oil and/or gas leasehold interest outside the spacing unit involved may be held by production from the spacing unit more than ninety (90) days beyond the expiration of the primary term of the lease.”
This law became effective May 27, 1977, and may or may not apply in your case, depending on the date of your lease. It would be advisable to check with your attorney for an interpretation of this law as it relates to your particular facts and situation. [* Named after a Louisiana lawyer, Lawrence G. Pugh, who drafted an oil and gas lease clause calculated to prevent the holding of non-pooled acreage.]
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