Can it make sense for a producer to drill a well in today’s low price environment even if the rate of return on that well is below zero? Surprisingly the answer is yes, and the issue has important implications for the impact lower prices will ultimately have on U.S. oil and gas production volumes. Factors such as lease requirements can incentivize drilling and cause production levels to continue growing, even when spot prices don’t seem to support it. As the new economics of lower oil, NGL and natural gas prices suggest that production declines are just down the road, the market’s quest to nail down when and how much production will decline has brought the role of “hold by production” (HBP) drilling into the spotlight. Questions about HBP status and its role in producers drilling strategies have been a staple in the latest round of earnings calls.Today we take a closer look at HBP drilling.
What is Hold by Production (HBP)?
One of the he biggest differentiators between the U.S. and other countries when it comes to drilling for oil and gas is that in the U.S. individuals own the rights to produce minerals beneath the land. That means when producers want to drill for oil or gas, the mineral rights owner (sometimes but frequently not the owner of the surface rights, generally thought of as the landowner) gets to share some of the proceeds. That is good news for the mineral rights owner but it does require the negotiation of a lease agreement with any would-be producer. A key provision in any such oil and gas lease agreement between mineral right owners and producers is the Habendum clause, which establishes the length of the lease and defines the primary and secondary terms for drilling rights. These primary and secondary terms play a critical role in determining if and when the producer is required to drill for oil or gas.
Many leases in the shale and other high-growth oil and gas basins are structured with a feature designed to protect the mineral rights owner from a producer leasing those rights but then never actually drilling a well (and providing royalties for the mineral rights owner). In this type of lease, the primary term defines the initial period of the lease, which gives the producer time to determine whether to drill or give up the lease. When the primary term expires, the lease terminates or rolls into the secondary term as long as there is a producing well on the lease. In other words, to keep from losing the lease, (i.e., extend the lease beyond the primary term), a producer needs to drill at least one producing well to “hold” the lease by production - HBP. For a producer, a longer primary term is advantageous because it gives them more time to decide whether and when to drill. For the mineral rights owner a shorter primary term is better because it reduces the time they have to wait for drilling and potential production revenues.
To secure a lease, a producer sends out a representative who is an expert in mineral rights negotiations – a Land Man – to offer terms to the owner of mineral rights. It is the Land Man’s job to secure leases with mineral right owners by offering terms favorable to the producer, but generally in line with the terms being offered by other producers in a given play. The leases are quite complicated legal documents but generally have a few basic terms considered most important, include the primary term length (several years) the royalty rate (the split of proceeds that the mineral rights owner will receive) and the key feature – the per-acre “signing bonus”, which is an up front payment to incentivize the mineral rights owner to sign the lease. Those signing bonuses can run into the thousands per acre which can be a lot of money if the mineral rights owner has thousands of acres (see Bayou Billionaires!).
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