Oil and Gas Lawyer Blog
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
John Doe
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 either what value is used to determine the royalty owed, or whether the lessee is entitled to deduct post-production costs from the lessor’s royalty.
Although the lease may provided for royalties “in kind” on oil – a share of the oil produced – in practice the operator sells the oil and pays royalties on the proceeds received. Royalties on gas may be expressed as a share of its “market value” or “amount realized.” When operators sell oil and gas today the purchase contract usually provides a price based on a published index less certain deductions. Operators usually calculate the royalty based on the net price received, after any deductions or adjustments provided for in the purchase contract.
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 NGLs. If gas contains NGLs, 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 NGLs in it, its Btu content may be 1,200 or more.
Gas with significant amounts of NGLs must be processed to remove the NGLs, and the NGLs will be sold as separate products. Often the producer will contract with a gas processor to process the gas before sale. The processor will charge processing fees or may take a share of the extracted NGLs as its fee. So the calculation of the amount realized from the sale of the gas includes proceeds from the sale of the methane and the NGLs.
Gas may also contain impurities such as hydrogen sulfide and water that must be removed before the gas can be sold.
In the past most oil was sold “at the well.” The oil purchaser would pull up to the tank battery on the lease with a truck, load the oil from the tanks, and pay the contract rate for that oil. Today, oil may be transported through gathering and transportation pipelines before sale, and the point of sale may be many miles from the lease. The closer to the refinery the oil is delivered, the more the purchaser is willing to pay for the oil. This difference in price is known as the “location differential.”
All of these post-production activities that must take place in order to sell or market the produced oil or 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 sales proceeds before paying the royalty owner her share, so the royalty owner must bear her share of the post-production costs. Lawyers for mineral owners, on the other hand, seek to draft language prohibiting deduction of post-production costs from the landowner’s royalty.
You would think that lawyers drafting oil and gas leases could come up with language that would clearly define how 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.