The Division Order

After the Oil and Gas Lease, the Division Order is the second most common instrument the Oklahoma oil and gas mineral and royalty interest owner will be exposed to. Like the oil and gas lease, the division order has a lotta ins, a lotta outs, a lotta what-have-yous, but we will focus on the basics for this post.

The purpose of the division order is to divide the revenues from a producing oil and gas well proportionally among those entitled to revenue in the well. A description of how those parties came to own a revenue interest can be found here.  The division order specifies the division of interest from the well. The decimals described in the division of interest are used to determine the percentage of the monthly revenues owed to the interest owner which equate directly to the royalty check.

There are three steps in the division order process:

1. Receive the division order from the oil and gas company.
2. Review and verify the royalty interest decimal.
3. Sign (execute) the division order.

Not all Oklahoma mineral owners will have a well drilled on their mineral rights, so to receive a division order is a wonderful thing. It means that millions of years ago the dinosaurs died in the little square under their family farm and the oil company's geologist was competent enough to find them. It also means that the well is producing in paying quantities and the oil company is almost ready to distribute the first revenues from the well. 

The oil company has determined the percentage of ownership through a document called the Division Order Title Opinion. A Division Order Title Opinion is prepared by an attorney who specializes in title ownership. He will check every document in the county courthouse from the beginning to present day.

Review and Verify

It is necessary to know what to look for when reviewing the division order. The company issuing the division order requires the royalty owner to take the following two actions:

1. Verify the legal description is accurate and it matches the description on the lease.
2. Verify that the royalty owner’s decimal interest stated in the division order is accurate and there are two formulas needed for this task:
   • Net Mineral Interest equals the net mineral acres in the spacing unit divided by the gross acres in the spacing unit. For example, if James, from Enid, owns 160 net mineral acres in a 640 acre section, then his net mineral interest is 0.25 or (160/640=.25)
   • The Decimal Interest, equals the net mineral interest multiplied by the royalty rate. If James, from Enid, agreed to a lease with a 3/16th royalty, his decimal interest would be 0.046875 or (160/640)*(3/16).
   • All of the owners' decimals will add up to 1.00000000 after the interests are accounted for under the DOTO.
3. Agree that the oil company can make payments based on that certain decimal interest specified on the division order until notified by the royalty owner that the ownership has been changed.

By signing the division order, the mineral owner releases the operator from liability to third parties who claim to own the interest being paid to you as the royalty owner. This means that if a owner is being paid more than his fair share another owner has the right to pursue him for compensation, with no responsibility on the part of the operator. Yes, you read that correctly, the mineral owner can be held liable even if the mistake was originally made by the title attorney in preparation of the DOTO or the oil company who used the DOTO.

Sign (Execute) and Return

Once the mineral owner has reviewed the division order and verified his decimal interest, send it it back to the operator. It may take up to six months before a check from the oil company. The State of Oklahoma allows operators six months from completing a well to when royalty payments must start being paid to mineral owners after which a 12% annual interest must be paid on unpaid royalties.

If there is any confusion, please seek the counsel of an experienced oil and gas attorney. While he might charge a few hundred dollars for his services, an error in a division order or DOTO could cost the mineral owner many times that over the life of a well.

More to follow.

BR

Oil and Gas Lease Clauses and Provisions Part 2, The Pugh Clause

The Pugh Clause is named after the Louisiana Barrister Lawrence Pugh in 1947 after the state Supreme Court ruled on Hunter v. Shell Oil Co., 211 La. 893 (1947). In this case, the Court, held that production from a unit with maintain the Oil and Gas Lease in force as to all lands described on the lease even if they are not contiguous.

What does this mean for the mineral owner? It means than if he leases multiple tracts of land on the same oil and gas lease, all lands with be held by the lease even if only one well is producing in paying quantities. As the mineral owner, you should request a Pugh clause from the lessor.

An example of a vertical Pugh Clause:

• "If at the end of the primary term, a part but not all of the land covered by this lease, on a surface acreage basis, is not included within a unit or units in accordance with the other provisions hereof, this lease shall terminate as to such part, or parts, of the land lying outside such unit or units, unless this lease is perpetuated as to such land outside such unit or units by operations conducted thereon or by the production of oil, gas or other minerals, or by such operations and such production in accordance with the provisions hereof."

With the remarkable advances in engineering with regards to horizontal drilling, many of the wells drilled in the past few years in these areas are indeed horizontal wells. Often times, the lessors are now requesting Pugh clauses to release the deeper geological formations after the expiration of the primary term.

An example of a horizontal Pugh Clause (also known as a depth clause):

• All rights 100' below the deepest depth drilled shall be released one (1) year following the expiration of the primary term, or upon completion of any drilling or reworking operating conducted thereunder which was commenced during the primary term, whichever occurs last.

Many lessors will want a clause such as " Lessee will release all depths below the stratigraphic equivalent of the deepest producing horizon." This sentence injects ambiguity and uncertainty in the oil and gas lease. While this clause initially seems more restrictive to the lessee, there is current on-going litigation regarding the term "stratigraphic equivalent," and neither party should desire to end up in court.

Interestingly enough, the State of Oklahoma 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 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. For the Oklahoma mineral owner, this means that he does not have to insert a vertical Pugh clause into his lease, but may still request a horizontal Pugh clause or depth severance.

More to follow.

BR

Oil and Gas Lease Clauses and Provisions Part 1

In our last post, we discussed the basics of the Oil and Gas Lease. Today we will discuss some of the finer points, provisions, and clauses of the lease.

Granting Clause: Usually, the opening paragraph of the lease is the granting clause. It outlines the purposes of the lease and describes the substances that can be explored and produced.

Duration: Both the Primary and Secondary Terms were discussed in yesterday's post and will not be rehashed here. However, there are three important provisions that should be discussed.

• Shut-in Provision: Allows the lease to remain in effect whenever the production from a well capable of producing in paying quantities is not being sold. The lessee must pay shut-in royalties to the lessor to maintain the lease after the expiration of the primary term.
• Dry Hole Provision: Will extend both the primary and secondary terms of the lease if oil and gas is not discovered when a well is drilled and certain conditions are met.
• Cessation of Production: Will extend the secondary term of the lease if certain conditions are met.

Royalty Clause: Again, discussed yesterday.

Surface Damages: Unless stated otherwise, the granting of an oil and gas leases carries the implied right to use as much of the surface as in reasonable necessary for the development of the minerals. This is because the surface estate is subservient to the mineral estate.

Pooling Clause: A provision giving the lessee the right to consolidate the leased premises with adjoining leased tracts in order to meet the requirements for the state mandated size for drilling and spacing units. Pooling, both compulsory and voluntary, will be covered in a post at a later date.

Assignment Clause: A provision permitting the lessor and the lessee to assign their rights under the lease to other parties.

Warranty Clause: A clause requiring lessors to defend their interest in, or title to, the leased premises.

Force Majeure Clause: The clause that protects the lessor from liability and loss of the lease whenever an "Act of God" causes the lessor to suspend operations. These acts can range from a tornado to a terrorist attack to the unavailability of a drilling rig.

More to follow.

BR

The Basics of the Oil and Gas Lease

For the mineral owner, the Oil and Gas Lease is the most common, but also the most important legal instrument that he will have to negotiate. Many books have detailed the Oil and Gas Lease, however, we will limit our study today to the basics.

99.9% of mineral owners will lease their mineral rights to an oil company for the right to explore and drill for oil and gas. The Oil and Gas Lease is a legally binding agreement between two parties, the mineral owner, called the Lessor, and the oil company or his agent, call the Lessee.  In exchange for the opportunity to lease the mineral rights, the Lessee will tender consideration to the Lessor. 

There are two components to the consideration. First, the Lessee will pay a cash bonus payment to the Lessor. Bonus payments vary widely and are dependent on local market conditions. Second, the Lessee will pay a royalty to the Lessor if a well is drilled and it produces oil and gas. The royalty is a percentage of the production revenues. The most commonly negotiated royalties are 1/8th and 3/16th. This means that if a Lessor agrees to a 3/16th royalty, he will receive 3/16th of the revenues attributed to the minerals he leased in the well free of any charges.

When leasing, most oil companies will offer at least two options with differing cash bonuses and royalty percentages which are inversely related.

For Example:

Option 1: $200/net mineral acre and a 1/8th royalty

Option 2: $150/net mineral acre and a 3/16th royalty

As mineral owners have differing horizons, each may choose a different option based on his current financial situation.

The Lease will also have a Primary Term. The Primary Term is the amount of time, usually three years, the oil company has to drill an oil and gas well. If the company does not drill a well capable of producing oil and gas in paying quantities, then the lease will expire. If the oil company does drill a well, then the lease will enter its Secondary Term and will remain in force as long as the well is capable of producing in paying quantities.

The Lease will also describe the lands being leased using the legal description. These will usually include the section, township, and range along with a more specific description of the tract. Legal descriptions will be detailed more thoroughly in a later post.

Stay tuned for more information about the Oil and Gas Lease in future posts.

BR