Leasing Mineral Rights

 
 
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 Mineral rights | The lease agreement, unit or area covered | Bonus or signing consideration | Length of the lease | Delayed production payment and/or drilling rental | Royalties | Gas cost allowance | Other areas of concern in your mineral lease | The lease agreement | Some additional clauses for consideration | Oil and gas brokers | Options and top leases | Contacts for further assistance

This publication is intended to provide a comprehensive discussion of mineral leasing for freehold mineral owners. It will address features of mineral leasing in Alberta to help dispel the uncertainties and implications of the granting process. It is not intended to support or recognize any one agreement as superior, or to recommend any rate of compensation. Rather it is to provide information regarding the considerations that should be made prior to entering into an agreement.

Mineral Rights

It has been said that a little knowledge is dangerous. There are few places where this is more applicable than in the area of leasing or disposing of mineral rights.

Mineral rights constitute real property and can be leased, traded, divided, willed, sold or given away. Mineral rights do not automatically revert to the government. The government can take title to freehold mineral rights only when a mineral owner has passed away without a will and without any relatives or heirs.

Mineral developers attempting to lease mineral rights may oversimplify the process by referring only to the following four points:

  1. bonus or signing consideration
  2. length of term of a lease
  3. annual delay rental payment
  4. the royalty

These four points, while import, are only the tip of the negotiating iceberg. They are also the easiest concepts for mineral owners to understand and feel comfortable with. However, other areas of concern pose very real pitfalls that can cost the mineral owner large sums of money if not properly addressed. We will deal with the above four points, and then go into more detail on the other matters of significance, particularly those that can have disastrous effects on a mineral owner if the clauses have been misunderstood or have not fairly dealt with the owner’s interest.

A mineral owner must first study his mineral title to fully understand what minerals he indeed owns. While “minerals” include naturally occurring mineral substances, such as copper, iron, sulphur, petroleum, oil, oil sands, natural gas, coal, granite, limestone and others, we will focus on petroleum and/or natural gas. You must understand that even if you own minerals, only those being sought by the company should be leased. If you are dealing with a petroleum company, there is no need to lease all the minerals you own to that company.

Note: gold and silver are always reserved unto the Crown.

The Lease Agreement, Unit or Area Covered

If both petroleum and natural gas are sought, you would be advised to lease each of these minerals on a separate agreement. Also, if you have title to more than one mineral unit (usually one quarter section) each unit should be leased on a separate agreement. Never lump all of the minerals that you own in different locations into one lease agreement. Serious consequences can follow your doing so.

If one lease only is used for all mineral units, any operations conducted by the leasing company on any part of one mineral unit will keep the lease in full force on the remaining mineral units. This has serious implications, because the drilling of a well on any one unit or parcel of land will satisfy the drilling requirement, permitting the company to hold all your other land. The same result could occur even when one quarter section of your land is pooled with units of other mineral owners. Such an arrangement clearly benefits the company seeking to lease your minerals, and can be damaging to the mineral owner. Lands not consisting of the unit drilled can be tied up indefinitely under such circumstances, with no prospect of early drilling or giving you a chance to re-lease.

By insisting on separate leases, the company must attempt to develop both the oil and gas potential of all parcels.

Various clauses of the mineral lease, the most important document regarding the leasing of your minerals, will be discussed in greater detail. The lease document sets out the obligations of each party and more importantly, establishes the rules on how the mineral development will take place and how the money generated by the development will be distributed.



Bonus or Signing Consideration

A company wishing to acquire your minerals will offer a signing bonus for your entering into a lease agreement. The amount of the bonus can vary greatly; it is basically an enticement to get you to enter into the lease agreement. Often the bonus is considered to be the area of greatest interest to you, because it represents ready cash received at the time of signing. Considering only the bonus can be very short-sighted, as the mineral royalty can generate far more dollars for you if minerals are discovered, produced and marketed. However, if minerals are not discovered and production does not take place, the bonus consideration could be the major source of revenue generated. The mineral owner is therefore faced with a gamble as to the possibility of success in discovering minerals.

You would be advised to take a lower signing bonus if you can obtain a higher royalty, provided you feel confident the well to be drilled will be successful. However, if no minerals are found, the owner would of course have been better advised to have obtained the largest possible signing bonus.

The oil company is in a better position to determine what might result from drilling, but no one can foresee the results with certainty. So, the amounts to be paid as a bonus and the rate of royalty are open for negotiation. However, we stress that the signing bonus should not be the sole factor in deciding whether to enter into a lease. Many mineral owners have, with regret, based their entire decision to lease on the bonus factor alone.

Length of the Lease

A mineral lease grants a company the exclusive right to drill for the minerals for a specific length of time. If the company fails to perform its obligation to drill under the terms of the lease agreement within the time frame set out, the lease expires and the company no longer retains a legal interest to your minerals. You may then lease, or otherwise deal with your minerals, with any other company.

If the company drills within the lease period, the lease then extends for as long as production is taken from your land and royalties are paid. Upon the company establishing a producing well, the royalty payments must continue at the rate provided for in the lease, and are not subject to renegotiation.

Companies acquiring mineral leases prefer to lease for the longest term possible, usually three to five years. The initial payment or signing bonus is not dependent upon the length of the lease nor is it increased by your agreeing to a longer term. The company seeking the lease will want to hold the minerals for as long a period as possible. However, as the mineral owner, you must realize that it is your best interest to have the minerals developed as soon as possible, which means you must seek as short a lease period as possible.

One must realize that the mineral developers may not be in a financial position, or have the other facilities necessary to develop all of their holdings in any given year. A reasonable term should be agreed to which extends an adequate opportunity for the mineral developer to develop minerals. A term of three years is common.

Delayed Production Payment and/or Drilling Rental

The delayed production payments provision permits the oil company to continue the lease by making a yearly payment to the mineral owner if a well is not drilled during the first year or each following year in the lease period. It also permits an extension if a well is drilled but not produced. For example, if a well is “shut-in” or “suspended” (drilled but not being produced), such payment is made in lieu of royalty, and the lease continues.

You should know there is no statutory or legal requirement for a $1.00 per acre delayed production payment, and that you can negotiate a higher per acre payment. Some recent leases offer “an amount equal to that sum calculated by dividing the Lease Payment by the number of year(s) in the Primary Term.”

Royalties

As a mineral owner, you are entitled to 100 per cent of the minerals underlying your land. If you were to develop the minerals yourself, you would receive 100 per cent of all funds generated from their sale. However, there are substantial risks and problems in locating and producing minerals. Generally the costs are high, so the mineral developer risks losing a substantial amount of money if a dry hole is encountered. When you are not sharing this substantial risk, you naturally take a smaller share of the production. The royalty you are entitled to through your negotiation with the company is your share of the production.

The amount of the applicable royalty is based on the value of the oil at the well head. If oil is worth $25 per barrel [a barrel consists of 35 Imperial gallons and 42 American gallons, (six barrels equals a cubic metre)], and if you are to receive 20 per cent gross royalty, you will be paid $5 for every barrel produced, less certain applicable taxes. Royalties on oil are basically straightforward.

Royalties payable with respect to gas produced are more complicated. While a mineral lease which includes gas could indicate that a gross royalty of 20 per cent of gas production at the well head will be paid, you must be aware that gas does not have its value set at the well head but rather at the point of sale.

This factor will likely reduce the net royalty received.

Note: the value and percentages used throughout this booklet are intended as examples only.

Gas Cost Allowance

Natural gas leases provide for the deduction by the producer of various factors of expense and profit known in the trade as Gas Cost Allowance. This reduces the value of gas at the point of sale and determines the gross well head value of your gas. The Gas Cost Allowance deduction was originally created for Crown minerals. It is computed by adding up the cost of all gathering system pipelines, gas plant equipment and facilities, and allocating these costs to the probable years of production from the field and then adding in annual operating costs for such facilities, as well as a percentage return on the total investment in all production facilities.

Specific factors in the Gas Cost Allowance deduction include:
  1. annual operating costs - incurred in running the facility (gas plant, compressor facilities, etc.)
  2. capital cost allowance - depreciation of the equipment used at the facility over a 20-year period
  3. return on the capital invested - amounts invested in the facility by the working interest owners, subject to a 15 per cent rate of return (please note that this rate of 15 per cent is conservative - it may run as high as 30 per cent)

The Gas Cost Allowance deduction will be applied on the basis that all of the costs referred to above will be recovered from the value of the gas sold, and will reduce the value of gas at the well head by a pro-rata amount for each unit of gas produced. This formula then determines the value of the gas and other products at the well head, at which point the royalty payable is calculated.

As an example, if gas has a sale value of $2.00 per gigajoule and Gas Cost Allowance is deducted, the well head value could be significantly lower than the gross sale price. The net result is that the realized price will be much less than $2.00 per gigajoule and, in cases of high cost per gigajoule, no royalty may be payable.

The mineral owner has no control over the factors making up the Gas Cost Allowance deduction.

A mineral owner is not always in a position to understand, question or evaluate the legitimacy or accuracy of Gas Cost Allowance deductions. In many cases the gathering systems, plant and other facilities process gas produced from Crown lands which are subject to much higher Crown royalties than that of freehold mineral owners. The best way for a freehold mineral owner to overcome the uncertainty associated with the Gas Cost Allowance deductions is to have the mineral lease state that the royalty is subject to no deductions whatsoever. However, because of market pressures on gas producers, it is unlikely they would agree to this condition. As an alternative, and in recognition of mineral market fluctuations, mineral owners can agree to allow a portion of the gas cost allowance deductions.

For the protection of the mineral owner’s royalty, the mineral lease can be amended by indicating the maximum amount that can be deducted for Gas Cost Allowance.

An example of such an amendment is a follows:

The processing and transportation fees (Gas Cost Allowance) relating to the lessor reserved royalties shall in no event exceed __________ per cent of its value at the place of sale. The place of sale shall mean that point at which the producer (lessee) has his product metered, value calculated and settlement made.

Most new leases provide a cap on allowable deductions. As, on some occasions, the costs may become inordinately high, a mineral owner should ensure the granting or lease agreement contains some form of clause to limit the Gas Cost Allowance deductions. We cannot over-emphasize the importance of this point.

Other Areas of Concern in Your Mineral Lease

Oil production
As shown in the diagram, the spacing of wells for oil production is usually one well per 160 acres (not including injection or disposal wells.) If a company has the mineral rights for a quarter section, they can drill one oil well. This spacing provision can vary depending on the type of oil, formation characteristics, etc. If you are in doubt as to what the spacing is for your land, contact the Energy Resources Conservation Board at 403-297-8311.

Gas production (and pooling)
Spacing of wells for gas production is usually one well for each 640 acres. Because in the majority of cases mineral interests are held in titles covering a quarter section only, a company must acquire the mineral interests under all four quarters of the same section before commencing any drilling operations. The holdings of other mineral owners within the section are brought together (pooled) to make up the 640 acre spacing unit. The mineral owners will participate equally from the production of a well on the pooled acres. The royalty is calculated on the basis that twenty-five per cent of production comes from each quarter section. In cases where the company wishing to drill cannot acquire the full 640-acre spacing unit, there is legislation available through which mineral owners can be forced to participate. Pooling legislation is very seldom used as it allows the mineral owner to receive a 100 per cent royalty less a share of development and penalty cost.

Unitization of a producing field
The purpose of unitization is to produce oil or gas more efficiently and effectively by bringing together an area involving a large number of sections. Unitization is used where the industry feels that a large portion of the oil and gas can be produced with fewer wells.

Upon unitization, an owner within the boundaries of the unitized field is entitled to participate in production, even though no well is located on his land. The provisions of a lease may therefore permit “pooling,” in which case you receive a portion of the royalty , based on the number of acres you put in the pool. The lease may permit “unitization,” which converts your royalty into a “tract factor,” based on a complex formula.

Even though unitization in the vast majority of cases provides a better total income for the mineral owner, an owner should not grant the right to unitize automatically; nor should he leave it up to the company’s discretion. Because participation in a unit is not based on the number of acres you have in the unit but is determined by the company, based on geological factors, you should very carefully assess your position. For example, while you may hold five per cent of the area in a unit, you may be allocated only two per cent of the production.

The mineral owner should only agree to unitization after he has had the opportunity to review the proposed tract factor. Any approval should be in writing. It may also be in his interest to consult a geologist or reservoir engineer.

Shut-in wells
Quite often wells are drilled but then not put into production. This is referred to as a “shut-in” or “suspended” well. The majority of “shut-ins” are gas wells. They are shut-in because there is no nearby pipeline to connect the well or for other reasons that would make producing the well uneconomical. Where this happens a delayed production payment or drilling rental is paid in lieu of royalties.

A problem with shut-in wells is that the operator holding your lease may shut-in the well indefinitely.

Even though a shut-in well clause is standard, you should try to have a provision that sets a time limit to the shut-in well. With the inclusion of a time limitation the company could only keep your well shut-in for a certain period or they must surrender their mineral interest back to you. An alternate option would have the company pay an increased delayed production payment off-setting the loss of royalty that would have been payable if the well had been put into production.

Off-set clauses
This clause forces the operator holding your lease to take specific action, as set out in your agreement, if a well is drilled on any adjoining spacing unit. It is important that you have off-set clause protection; wells near your land can drain the reservoir under your land. Off-set obligations would be triggered by taking production from an adjoining spacing unit. Usually the off-set clause allows the company six months to commence drilling, and thereafter produce from the depth which production is being taken on the adjoining unit.

Again, we stress your main concern is mineral drainage. When a well is produced on the adjoining spacing unit, gas and oil can move through your formation to the producing well and be lost.

Most off-set clauses apply only to laterally adjoining spacing units (quarters or sections), and owners are advised to replace the phrase “laterally adjoining” with “contiguously adjoining” which would look after diagonally off-set spacing units that are not currently included under the phrase “laterally adjoining.”

If you become aware of commercial production being obtained from an offset well, you must notify the company in writing to invoke the offset clause

Depth drilled and zone produced
It is becoming a more common practice to lease only to the depth drilled. For example, if a company drills to 5,000 feet and is able to produce oil or gas from the zone identified, all other zones below the production zone will revert back to the mineral owner. A typical example of an amending clause is:
“and further provided that if at any time after the end of the said term productions is being obtained from the said lands from one or more formations the lessees shall surrender all formations within the said lands which lie below the base of the deepest formation from which the lessee is obtaining production. By including this provision in the lease, you will overcome the possibility of one capped well preventing the attempts of other companies to obtain production of minerals from different depths or formations in your mineral interest.
Depending on your negotiations it may be possible to lease only the zone produced and the company would surrender all zones above and below the production zone back to the mineral owner.

Records and access to them
Most current agreements contain a clause that gives you access to production and financial records of the company. Access to this information may be necessary to review Gas Cost Allowance deductions and royalty payments. It is equally important when dealing with the allocation of production and costs under a unitization agreement. The difficulty lies in interpreting the data once it is received. It may be necessary to consult a specialist to analyze the information.

Taxes
Certain provincial and federal taxes are payable with respect to both ownership and production of minerals. Taxes that are based on the amount of your share of production, other than income tax, are the responsibility of the mineral owner. However, the company usually pays all such tax and deducts your portion from the royalty you should receive. For example, if 20 per cent royalty was retained by you, then 20 per cent of the taxes based on production would be payable by you; the remaining 80 per cent being payable by the company that holds your lease. Usually the company pays 100 per cent of such taxes and deducts your 20 per cent out of the following month’s royalty cheque, or in some other manner agreeable to you.

You should know that you, as registered owner, are legally responsible to pay taxes related to the production of your minerals even though you may only receive a small fraction of the revenues generated from production. For this reason the lease agreement should specify that the company shall be responsible to pay all taxes levied. This may be particularly important as there can be several partners with varying interests involved in the ownership of the well.

Prepayment
As a mineral owner you may have to incur expenses for professional help to adequately protect your interests when a company wishes to lease your minerals. If the company wishing to acquire your minerals decides not to proceed with the lease, you could have no way of recovering the expenses you have incurred.

To avoid this, you could obtain an up-front payment from the party interested in acquiring your minerals. It could also be agreed that such payment would be deducted from the signing bonus in the mineral lease. A request for an advance has the added benefit of identifying a company or individual that is only casually interested in your minerals.

Should the company not agree to prepayment, they may still agree to pay a predetermined limited amount for your out of pocket expenses, particularly if negotiations conclude in the signing of a mineral lease.

The Lease Agreement

From all of the above you will see that leasing your minerals is a specialized and serious responsibility. Those seeking to lease your minerals may have a tendency to over-simplify, and deal only with the three or four major points referred to in the first section. The lease agreement, however, should also set out all of the other terms, conditions and provisions of the arrangement between you and the company.

As many mineral owners have little understanding of the complex issues regarding the leasing of minerals, such as the geological potential. It can be helpful to utilize the services of professionals knowledgeable in those areas least understood by mineral owners before signing a lease.

While there are model lease agreements available from the Farmers’ Advocate’s office and the oil and gas industry, such as CAPL 99, it should be noted that no one agreement may satisfy or contain all of the required conditions or clauses negotiated between the mineral owner and the company.

Some Additional Clauses for Consideration

Some additional clauses for consideration would address:
  • pooling and unitization
  • zone limitation
  • suspended wells
  • shut-in gas wells
Oil and Gas Brokers for Leaseholds and Other Interests

There are a number of companies that offer their services to mineral owners. They may offer to obtain a lease, to sell the mineral interest or just bring the interested parties together, in a manner very similar to a real estate broker. However, you must pay special attention to the terms of the agency or other agreement with such companies. We recommend that the agency or brokerage fee be established prior to beginning any negotiations, and that such fee should not be a percentage of production or income produced.

You should question seriously any agreement where the agent wishes to retain an overriding royalty of say one or two per cent for the service he offers. Such a fee could be excessive or unreasonable for the following reasons:
  • if a producing well is drilled, the one or two per cent may earn the agent thousands of dollars yearly for a service that could have been purchased outright for far less
  • the agent may attempt to lease your minerals upon terms that are not in your best interest (including a low bonus payment and/or royalty), knowing that his one per cent overriding royalty will be just as secure
One should also question any proposal to sell minerals rather than lease them. A decision to sell should only be made after you have fully assessed the value of your mineral interest and understand that you would receive nothing further in the future. As mentioned previously a mineral owner may wish to consult with a professional before making a final decision to sell minerals.

Options and Top Leases

Mineral owners may be approached by companies or individuals seeking a top lease or an option to lease their minerals. A top lease would occur when your minerals are held under a previous lease and a company is seeking to have a new lease signed that would take effect upon the termination of the existing agreement or sooner. An option grants the right to someone or some company, at their future discretion, to obtain a lease of your minerals on terms set out in the option. In both circumstances the mineral owner should approach signing an agreement with caution.

A request for an option or top lease indicates an interest in the minerals. Your negotiating position may be stronger by waiting for any current agreement to lapse. When considering either of these potentials, review the new offer with care. Does it maximize your benefits?

Contacts for Further Assistance

Farmers’ Advocate Office
305 7000 -113 Street
Edmonton AB T5H 5T6
Phone: 780-427-2433 Fax: 780-427-3913

Energy Resources Conservation Board
640-5 Avenue SW
Calgary AB T2P 3G4
Phone: 403-297-8311

Freehold Owners Association
1403 - 12 St SW Calgary AB T3C 1B3
Phone: 403-245-4438
www.fhoa.ca e-mail: fhoa@shaw.ca

Source: Agdex 878-3. Revised April 2009.
 
 
 
 
For more information about the content of this document, contact Duke.
This information published to the web on June 1, 2001.
Last Reviewed/Revised on April 1, 2009.