The only three essential terms of an oil and gas lease are the granting clause, including a description of the property, the habendum clause, which defines the term of the lease, and the royalty clause. The following would be a valid, enforceable lease:
John Doe hereby leases to Gusher Oil Company the oil and gas in and under Section 5, Block 4, T&N RR Co. Survey, Jones County, Texas, for the purpose of exploring for and producing oil and gas. This grant shall be for a term of three years and as long thereafter as oil or gas is produced from the property. John Doe reserves a royalty of 1/4th of all oil and gas produced and saved.
Dated ___________________, 2014
All other provisions of the typical lease, although important, are not essential. The above lease would be legal and enforceable and might be all the parties need, assuming that they get along with each other. The numerous other provisions now used in leases have been added to answer questions that have arisen in the course of time, as the industry developed and parties faced disputes over the lessor-lessee relationship.
For the landowner, the royalty clause is the most important part of the lease. The royalty is the principal consideration for granting the lease. In its most general terms, a royalty is a share of profits or revenue from sale of a product — think book royalties paid to the author. In oil and gas, it is a share of the revenue from the sale of the oil and gas produced.
In Texas, leases generally provide that the royalty on oil is a share of the oil itself – an “in-kind” royalty, whereas the royalty on gas is a share of the proceeds or amount realized from the sale of the gas. Oil was traditionally sold by the producer to a purchaser who would pick up the oil from tanks at or near the well. As a service to the producer, the purchaser would agree to be responsible for paying the royalties owed on the oil. The purchaser would send the royalty owner a division order setting out the percentage of oil owed to the royalty owner and providing that the purchaser would purchase the royalty owner’s share at the “posted price” in the field. The division order was therefore a purchase agreement between the purchaser and the royalty owner. If the producer sold gas, the producer would pay the royalty owner her share of the gas proceeds.
Today, most royalties on both oil and gas are paid by the producer, who sells the oil and gas and remits the royalty owner’s share.
Most disputes about royalties concern how royalties are calculated on gas production. Most oil production is still sold to purchasers at or near the well, and there is an established price in the field for the oil; the producer and royalty owner are both paid based on that price. Gas is more complicated.
Natural gas, as consumers think of it, is what is burned when you turn on your stove. That gas is methane, each molecule containing one carbon atom and two hydrogen atoms — CH2. But gas coming out of a well may also contain some ethane, butane, propane and other “heavier” gases. Those heavier gases have a higher Btu content. Burning one cubic foot of ethane will create more heat than burning one cubic foot of methane. Also, the heavier gases have uses in various manufacturing processes. Also, the heavier gases can be compressed into liquid form for transporting — they are sometimes called “natural gas liquids,” or NGL’s. If gas contains NGL’s, it has a higher Btu value than methane. One cubic foot of methane, at a standard temperature and pressure, will create 1,000 Btu of heat when burned. We say that it is 1,000-Btu gas. But if the gas has some NGL’s in it, its Btu content may be 1,200 or more.
Gas with significant amounts of NGL’s must be processed to remove the NGL’s, and the NGL’s will be sold as separate products. Often the producer will contract with a gas processor to process the gas before sale. So the calculation of the amount realized from the sale of the gas includes proceeds from the sale of the methane and the NGL’s.
Gas may also contain impurities such as hydrogen sulfide and water that must be removed before the gas can be sold.
All of the activities that must take place in order to sell or market the produced gas have a cost, and those costs are referred to as post-production costs. If an oil and gas lease provides for royalties based on the “net proceeds” or “amount realized” or “market value” “at the well,” courts have ruled that the producer may deduct those post-production costs from gas sales proceeds before paying the royalty owner her share. So the royalty owner must bear her share of the post-production costs. Litigation over how gas royalties are calculated and whether and how post-production costs can be deducted has engaged lawyers for as long as natural gas has been a valuable resource.
You would think that lawyers drafting oil and gas leases could come up with language that would clearly define how gas royalties are calculated and paid and what post-production costs can be deducted, so as to avoid controversy and litigation. Unfortunately, that has often not been the case. The result is continued litigation, some of which I have written about. Technology advances. Gas markets evolve. Producers become more creative in how they structure their marketing programs to shift costs to royalty owners. Royalty owners become more sophisticated in understanding the industry and crafting language to avoid post-production costs. And lawyers continue to prosper from the disputes that arise.