Oil and Gas Leasing

This MontGuide is intended to help land and mineral owners understand the oil and gas leasing process. Other mineral property, such as coal or hardrock minerals, may be leased as well, but those substances may require slightly different lease terms. Even though oil and gas resources vary around the state, the terms of leases are similar.

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What is an oil and gas lease?

An oil and gas lease is a contract that gives another party an interest in your mineral property. Oil and gas companies use leases to acquire acreage on which they can find and produce hydrocarbons. Mineral leases are binding legal agreements. Owners may want to retain the services of a qualified legal professional to advise them throughout leasing negotiations.

The terminology of leases is sometimes confusing. The property owner leases some of his or her rights: the property owner is therefore the lessor. An interested party, often an oil and gas company, obtains the bundle of the owner’s rights that are specified in the lease. The company is the lessee.

Usually the mineral owner benefits monetarily from the lease in at least two ways. First, the mineral owner usually keeps a royalty interest in the production, if it occurs. This means that the owner is paid for a fraction of the value of any minerals produced from the land. Second, the owner usually gets a payment at the time the lease is signed. This payment is called a bonus payment. Owners may be able to negotiate additional financial terms such as rental payments. It may also be important to negotiate non-monetary terms about how development will proceed. These conditions are called stipulations and may include timing or location restrictions.

Why a lease?

Another option that an owner has is to sell – either just the mineral property or the whole property (surface and mineral rights) – but many landowners prefer to lease the minerals instead of making a sale. Mineral development is so technically and financially demanding that landowners have little ability to develop their mineral property themselves. There are also financial risks that mineral owners may not be willing to accept. Therefore, the developer and the mineral property owner use a mineral lease so that they can each address their needs and concerns. The developer wants mineral resources; the owner wants a way to realize the value of their mineral property, but may want to balance that value against other concerns. One way to think of the lease is that it specifies a partnership between the mineral owner, who potentially owns valuable resources, and an oil and gas company, which has technical expertise to extract the valuable resources.

An alternative to leasing for the mineral owner is to wait until a later time to develop the minerals. Sometimes mineral owners worry about whether their minerals will still be in the ground at a later time – the threat of another individual extracting the minerals before the owner can. This is because of the rule of capture, which means that oil and gas does not become personal property until it is extracted and brought to the surface. For example, an oil well drilled on a neighbor’s property may reduce the amount of oil that can be obtained from future drilling on your property. This has happened in the past, but newer technologies and existing regulations are likely to reduce this risk. Another concern is that future prices or regulations will limit a landowner’s ability to develop their minerals for a profit. Each owner will have to consider the benefits of signing a lease now or waiting until the future.

How is the lease I sign affected by the kind of minerals that I own?

Mineral deposits and their value vary around the state, so it is important for owners to understand what kind of minerals they own and how those minerals fit into the bigger development picture. When considering a lease, an owner needs to evaluate how much risk is acceptable.

The mineral owner whose property is surrounded by proven wells has much less risk than one far from a producing region. A new development area, sometimes called a wildcat, may have different terms or lower payments offered in a lease contract because the lessee has to consider the possibility that no economic deposits exist.

Example 1:

Jay and Kristyn live far from any proven oil and gas deposits, but signed a lease with a bonus of $2 per acre and a royalty rate of 12.5 percent. In contrast, Mike and Christine own minerals next to two producing leases. When they signed their lease they negotiated for a bonus payment of $500 per acre and royalty rate of 18.75 percent.

Is there a “standard” mineral lease?

No. Oil and gas leases are similar across the state, but there is no such thing as a standard oil and gas lease. Terms are negotiable and a mineral owner does not have to sign a lease unless they are comfortable with the terms it contains. A common lease template, known as the “Producer’s 88,” contains many typical oil and gas lease provisions. Examples of leases may include clauses that are useful to owners or lessees. Legal counsel experienced with mineral leases may be able to help the landowner include advantageous clauses.

Often a potential lessee (company) has their own “standard” oil and gas lease. This standard lease is typically the starting point for negotiations. Some companies are willing to negotiate many of the points in their lease while others may be less willing. Some terms that a landowner sees as necessary for a lease may be deal-breakers for the company, or vice versa.

With whom do I negotiate?

Usually a landowner will negotiate a mineral lease with a professional called a landman. Landmen (women included) provide a valuable service and bring extensive expertise in leasing.

Some landmen work for oil and gas companies. Others are independent and acquire leases for themselves. Independent landmen often bundle leases together and try to sell or assign them to other companies that will actually develop the minerals. Just as lessees want to make sure they are negotiating with the mineral owner, owners want to know what kind of landman they are negotiating with and who will hold the lease after it is signed. Whether or not the lease can be assigned is negotiable. There is no hard and fast rule about which kind of landman is better from the lessor's perspective.

What is in a mineral lease?

Mineral leases can vary. Some leases contain terms that are advantageous to the mineral owner. Qualified legal counsel can recommend lease terms that represent industry best practices and help avoid terms that may create problems down the road for mineral owners. Because they are legal documents, leases often contain many of the same major clauses. Understanding the purpose and variations of these clauses is helpful to mineral owners as they consider crafting a lease to address their particular concerns. The following sections discuss different clauses, or parts, of the lease.

Granting

The first issue that needs to be defined is what is being leased. This will include a legal description of the property that is being leased. The minerals included in the proposed lease will also be specified. Some leases may say “oil and/or natural gas” while others specify “all minerals.” All minerals includes more than just oil and gas, including coal and other types of minerals.

A question to ask is whether seismic exploration is permitted under the terms of the lease. Some landowners prefer to sign a separate seismic exploration agreement. This allows flexibility and more information to negotiate the oil and gas lease terms after the seismic work is done. The process of seismic surveys is different from oil and gas production, so many of the landowner concerns are different. Any damages caused by seismic exploration can be addressed in the lease if it allows seismic surveys, or in a separate seismic survey agreement. If seismic exploration is not addressed in the lease or in a separate seismic survey agreement, the lessee will be entitled to reasonable use of the surface, including reasonable seismic activities. If a landowner seeks to avoid an argument over what amount of seismic activity is reasonable, the landowner should address seismic activity in the lease or in a separate seismic survey agreement.

Duration

The next major issue that needs to be specified is how long the lease will be in effect. The primary term is the initial amount of time that the lease will extend. Often the primary term is three or five years. Federal oil and gas leases have a ten year primary term, but private oil and gas leases are rarely that long. The primary term is a time window in which the operator can find and begin to produce oil and/or gas. This is a time during which the lease is certain to be in effect.

Leases generally specify a secondary term in addition to the primary term. The secondary terms extends “so long as oil or gas are produced in paying quantities” or something similar. This is the term during which the lease is held by production.

Example 2:

Roger signed a lease with an operator that allowed him a 12.5 percent royalty. Two months before the primary lease was due to expire, the operator brought in a well at 25 barrels per day, or 750 barrels per month. The production quickly declined to two barrels a day, or 60 barrels per month. The operator has drilled no more wells, even though Roger would like him to. Roger receives a royalty check of approximately $400 per month and cannot sign a new lease because the existing one is held by production.

Sometimes an extension of the primary term is written as an option that the lessee can exercise. In the event of an option structure, there may be an additional bonus payment due if the option is exercised. Sometimes a renewal option is included.

Example 3:

Ken and Pam have two leases with one operator. One lease has a producing well and they receive a monthly royalty check. The other lease is not producing and is nearing the end of the primary term. They hoped to write a new lease when it expired. One month, an “extra” check for $500 arrived. Ken and Pam deposited the check in the bank. They later discovered that by cashing the $500 check they accepted a renewal of their existing, non-producing lease through a provision in the original lease agreement.

In addition to a bonus or royalty payment, landowners can recognize value from an oil and gas lease through annual rental payments. These payments are made only if there has been no production and therefore the owner is not receiving a royalty payment. In some cases, the rental payment may be waived if drilling or operations have commenced. If rental payments are included, it should be clear what the amount of the payments is, when they are paid, and what conditions prevent or allow them to be paid.

Sometimes leases are written that effectively avoid having to make any rental or delayed bonus payments. These are called paid-up leases. The mineral owner receives a one-time, up-front payment for leasing, and a royalty only if production occurs. Paid-up leases are becoming more common, with the result that rental payments are becoming less common.

A standard clause in an oil and gas lease is that the lease will be held by production, which means that the lease remains in effect if there is production from any well on the lease. Even a low amount of production can hold a lease, depending on the lease terms.

A popular landowner protection is a Pugh clause, which is especially important for a lease covering a large acreage. Suppose a lease has one producing well. The production from the well is low, and the mineral owner thinks that other wells could be drilled to increase royalty payments. However, the lessee thinks differently. A Pugh clause allows the lease to terminate at the end of the primary term on acreage outside of the spacing unit for the producing well.

A spacing unit is an area of land where only one well may be drilled. The Board of Oil and Gas Conservation (BOGC) establishes spacing units to avoid unnecessary wells and to avoid wasting oil and gas. Depending on the location, spacing units vary in size from 40 to 1280 acres for oil wells; they vary from 640 to 2560 acres for natural gas wells. A Pugh clause allows the lessor to lease the terminated acreage instead of having it held by production indefinitely from the original producing well.

Example 4:

David and Tanya included a Pugh clause in their lease when it was initially signed. The primary term was five years. After two years, a producing well with a 640-acre spacing unit was completed and began paying a royalty. The lease initially covered 2500 acres but no more wells were drilled. Because of the Pugh clause, David and Tanya terminated the lease on 1860 acres after the five years passed. The other 640 acres were held by production and continued to yield a royalty.

There are a number of issues about the termination of a lease that are important for the lessor to consider. Normally, a lease will expire at the end of the term if the lessee has not discovered oil or gas. As the primary term expires, many times a commencement clause will allow the lessee to hold the lease. In Montana, in order to hold a lease, a drilling rig capable of reaching total depth needs to be on location and actively drilling. This issue has recently been litigated in North Dakota. However, if a different commencement clause is specified in the lease, it will apply when the primary term ends.

Dry hole provisions are also important. If a well is drilled that is dry, how long does the lessee have to declare it a dry hole? Alternatively, a low-producing well may be shut-in rather than produced. This deprives the mineral owner of a royalty payment. Is there a shut in rental payment included in the lease to ensure that the mineral owner is paid until there is actual production? Or is there a specified amount of time a lease can be held by a dry hole or shut-in well? In times of volatile oil and gas prices, this can be an important consideration.

Royalty

A royalty is the share of the income from oil and gas production that mineral right owners receive.

Federal onshore oil and gas leases reserve a one-eighth, or 12.5 percent, royalty for the federal government. State leases reserve a one-sixth, or 16.67 percent, royalty for the state. Private leases may negotiate for higher or lower royalty amounts. Another common royalty rate is three-sixteenths, or 18.75 percent. In areas with proven oil and gas production, landowners are more likely to receive a higher royalty rate. There are cases where mineral owners have successfully negotiated for a one-fifth (20 percent) or higher royalty.

In some cases, the lease will specify different royalty rates for different minerals. It is not uncommon to have different royalty rates for oil and gas, for example.

Royalty payments are subject to withheld charges for “post-production” costs. It is common for a lessee to deduct some costs associated with marketing produced oil or gas because the product is not marketable at the wellhead. For example, cleaning and transportation costs may be incurred to deliver the product to a location where it can be sold. The lessee can require the royalty owner to share these costs. It is in the interest of the mineral owner to be clear about the accounting and definition of these costs.

One common way for a lessor to avoid some of these costs is to negotiate a non-participating royalty (or overriding royalty) for part of the royalty interest. Non-participating royalties are not reduced by deductions.

Example 5:

Monica and Terry were initially offered a 16? percent royalty for their mineral interest. They countered with a request for a 12.5 percent royalty with a 5 percent non-participating royalty. The combined royalty interest in their counteroffer is 17.5 percent, but only 12.5 percent of that is subject to deductions for production costs.

Clearly stating how royalties will be calculated (what benchmark price, for example) may help avoid confusion later. It is also important to be clear about what records regarding production and royalty calculations will be made available to the lessor. If left unaddressed in the lease, royalty calculation can become a “black box” that offers little transparency to the mineral owner. Specifying how and where the records will be made available can potentially help avoid later confusion. See the MSU Extension MontGuide, Owning Leased Oil and Gas Minerals (MT201208HR), for more information.

Most royalties are paid monthly after the initial check arrives. The first check will typically cover the initial six month of production. If you prefer a different royalty payment schedule, it should be specified it in the lease.

In Montana the mineral owner is liable for a severance tax of 15.06 percent of the gross value of production. This amount if typically withheld from royalty checks and submitted directly to the Department of Revenue on the royalty owner’s behalf.

Example 6:

Sam and Joe share ownership of a leased parcel that recently had an oil well completed on it. In their lease they negotiated an 18.75 percent royalty. The well produced 1500 barrels of oil in its first month, and that oil was sold for $78 a barrel. The gross revenue for that month is: 1500 barrels x $78/barrel = $117,000. The royalty owner share is $117,000 x 0.1875 = $21,937.50. Sam and Joe owe severance tax of 15.06 percent, or $3303.79. If there are no post-production costs, they can expect that month’s royalty check to net $18,633.71.

Surface Damage

A separate surface damage clause is not always included in a lease, particularly a wildcat lease. However, it is an important way that an owner, particularly an owner
5of both surface and minerals, can protect the surface. For split estate owners who have an opportunity to negotiate a surface use agreement, the elements of the surface damage clause constitute the main terms of a surface use agreement.

Surface damage clauses address a number of issues that will be specific to the parcel in question; a sample of considerations is listed here.

• Are roadways, pipelines, storage tanks, or other infrastructure allowed?
• How much of the surface area may be used? Where, exactly?
• May these facilities be used in connection with oil/gas/minerals removed from other lands?
• For what damages to the surface is the lessee responsible?
• To what condition must the site be restored?

Because of the risk in wildcat leases, the lessor may be less interested in signing a surface damage clause into the lease. In such a case, a surface use agreement may be signed when and if drilling does proceed. See Owning Leased Oil and Gas Minerals for more information on signing a surface use agreement after leasing.

Assignment

It is very common for oil and gas leases to change hands after they are signed. The original lessee will assign it to another lessee. If this happens, the lessor should be informed of the transfer so that a positive relationship with the new assignee can begin. During the lease negotiation, an assignment clause can be included that specifies how a mineral owner will be informed of lease assignment. For example, the clause may provide for written notice within 30 days of the transfer. A lease may also expressly prohibit an assignment of the lease. In some cases, the original lessee may be held liable for later performance by a subsequent assignee, but this is rare. The landman negotiating a lease is likely to be long gone if and when any issues arise down the road.

Other Clauses

A number of other clauses may be present in an oil and gas lease. Minerals owners need to consider the merits of any additional clauses and may wish to consult legal counsel to determine the merits in their particular situation.

I own fractional minerals. Can I lease? Should I?

In the case where fractional interests do not want to lease jointly, or cannot agree on lease terms jointly, it is possible for a fractional owner to lease his or her interest. However, leasing fractional interests is both more costly and riskier for the lessee. The lessee has to lease a majority of the mineral interest to be able to enter and begin development.

Montana does allow for forced pooling of interests, though this is not especially common. North Dakota allows for forced pooling and uses it frequently. Fractional interests (such as siblings) may find it advantageous to reach internal agreement before trying to sign leases for each fractional interest, though many fractional owners do sign leases independently.

How should I handle multiple offers?

A mineral owner fortunate enough to have multiple lease offers to consider will usually have a stronger negotiating position. Letting the competing companies know about the other(s) will help strengthen the negotiating position of the mineral owner.

Can I lease by depth? Is that the same as top-leasing?

One common question about granting clauses is the separation of mineral property by depth. Leasing by depth is explicitly writing certain depths into the original lease; oil and gas companies usually do not favor these clauses

Example 7:

Chad and Yvonne leased their minerals in the relatively shallow Cody formation to one company, but included a depth provision. They later signed another lease for rights to the underlying Bakken formation. They were able to lease by depth.

Leasing by depth is not the same thing as top-leasing. A top-lease is a second lease that is signed while another lease is still in effect. Landowners may sign a top-lease to ensure that upon expiration of an earlier lease their minerals do not go unleased. Because of the terminology, some landowners think this refers to leasing by depth; however top-leasing and leasing by depth are not necessarily the same.

Example 8:

Jason and Christy signed a lease during a period of great interest in their area. Their lessee was not able to get the lease drilled before the last year of the term of the lease. During the interim, the leasing activity in their area cooled down, so Jason and Christy signed another lease set to take effect the day after the first lease expired. They top-leased.

There are several risks with this strategy. One is that the original lessee does not surrender the lease (perhaps because drilling operations started) and the subsequent lessee wants to initiate operations.

A vertical Pugh clause allows a mineral owner to release other depths even if a well is completed on their lease. A vertical Pugh clause states that a lessee cannot hold a lease over the entire mineral estate just byoperating a single well at a single depth. This might allow another operator to enter and pursue deeper or shallower oil and gas deposits. Most oil and gas companies are very hesitant to include this kind of clause.

Example 9:

Todd and Frances signed a lease and had a well drilled into the Bakken formation. Their mineral property also includes parts of the underlying Three Forks formation. Their lessee showed no interest in drilling another well into the Three Forks. Therefore, they exercised the vertical Pugh clause (at the end of the primary term) that was written into their lease and signed a new lease for the underlying Three Forks formation. This is an example of a vertical Pugh clause.

What sources of information can I access to help me negotiate?

There are many sources of information regarding current trends and lease terms. Usually landmen, because they are constantly negotiating leases, are better apprised of the current situation. A landowner may sign only a handful of leases in a lifetime. One lease can survive for decades. Information about current leases and other offers in the neighborhood may be forthcoming from neighbors. Montana has landowner associations that may be able to offer advice. Legal counsel, especially from an experienced oil and gas attorney, can provide valuable information.

Information about geological structures, market conditions and nearby leasing may all be valuable for the mineral owner. Geological information and production histories can be obtained from the Montana Board of Oil and Gas Conservation. Much of the information is available online at http://dnrc.mt.gov/bogc. Other private sources of information are available but the veracity of those sources should be considered.

Do I have to sign a lease?

No. As a mineral owner, you are not compelled to sign a lease.

Owners of small acreages (less than 640 acres) pursuing this strategy may expose themselves to the prospect of being forced to join a production pool. A lease is likely to be preferable to a forced pool for most owners. Pooling is a complex issue. A mineral owner may wish to consult experienced legal counsel if this is likely.

What happens if I don’t sign a lease?

In most cases, when the mineral owner refuses to sign a lease nothing happens. Under very specific circumstances, a mineral owner may find him- or herself in a forced pooling situation. Usually this applies to owners of small mineral acreages.

What obligation to a mortgage lender do I have if I lease minerals?

If an owner has a lien against the property, it may be necessary to inform the lender of an oil and gas lease. Depending on the type of mortgage, the lender may be entitled to a share of the royalty payments, which must be used to retire principal as opposed to interest. It may be advisable to check the terms of mortgages before signing an oil and gas lease. This is true for other types of loans as well, such as FSA loans.

Glossary

Assignment: The act of selling or subleasing a leasehold interest.

Bonus payment: An up-front payment made to the lessor when an oil and gas lease is signed.

Held by production: A term describing how an oil and gas lease remains in effect so long as the lease produces some positive (even very small) amount of oil or gas.

Landman: A professional specializing in identifying mineral ownership and signing leases. A landman may work for an oil and gas company or independently.

Lessee: The party obtaining the rights through the lease; for an oil and gas lease, usually an oil and gas company.

Lessor: The party granting the rights through the lease; for an oil and gas lease, usually the mineral owner.

Non-participating royalty: A royalty payment free of post-production costs and other deductions. Such a royalty may also be called an overriding royalty.

Paid-up lease: A lease in which all rental and option payments are made at the time the lease is signed.

Post-production costs: Costs incurred by the operator to market produced oil and gas – may include cleaning, compression and transporting of oil and or gas. These costs can be deducted from royalty payments.

Primary term: The period of time during which the mineral property will certainly be leased and the lessee must commence drilling operations. Sometimes the primary term may be extended by an option.

Pugh clause: A clause that allows the mineral owner to release acreage outside of a pool or spacing unit. A Pugh clause prevents an operator from holding large acreage with production on only a small part.

Rental: Payments made during the duration of a lease before production (or sometime operations) commence.

Royalty: The share of the value of production that the operator pays the lessor. Usually royalty interests are expressed in percent of total value, but sometimes as a fraction. For example, a one-eighth and 12.5 percent royalty are equivalent.

Rule of capture: When resources can move, ownership of the products is established when they are "captured," as when oil or gas is pumped to the surface. This rule creates personal property from real property.

Secondary term: An additional period of time that extends the lease duration. Often this is a period during which production occurs but before final reclamation and lease surrender.

Shut-in: A well that is capable of producing oil or gas, but which the operator chooses not to produce, is called "shut-in." It may or may not be produced in the future.

Spacing unit: a regulatory boundary around a well designed to protect correlative (neighboring) rights. Varies in size; created by Board of Oil and Gas Conservation.

Stipulations: Restrictions included in the lease on how the lessee may conduct operations. Often these are used to protect surface values.

Wildcat: A term that may refer to a lease, well or operator that means that the area has not yet been proven, and therefore includes a significant amount of risk.

Note:

This MontGuide is not a substitute for legal advice. Mineral owners considering an oil and gas lease may wish to consult legal counsel with expertise in oil and gas leasing.