Oil and Gas Royalties: Look Before You Lease (E2121)
In recent years, some oil companies have been adding a small phrase in their leases that has cost landowners money.
The New “Royalty Phrase”
In recent years, some oil companies have been adding a small phrase in their leases that has cost landowners money. The phrase appears in the royalty clause and usually goes something like this: the oil company will pay the agreed upon royalty rate, but the landowner will have to “bear the cost of treating the product to render it marketable or pipeline quality.”
The landowner signing this type of lease must pay a share of the production costs for the well. The oil company subtracts the landowner’s share of the costs to make the product marketable or pipeline quality before paying the royalty. This reduces the actual royalty money a landowner receives. In most cases, such an arrangement is like knocking a percentage point or two off the agreed upon royalty rat; a 1.8 or 12.5% royalty rate may convert to a 10% or 11% actual payment. On a few marginal wells, deducting the portion of production costs has nearly eliminated the royalty payment altogether.
If you look before you lease, however, it’s possible to delete this costly phrase from your contract through negotiation. To do so you must know several things: 1) the cost to make the product “marketable or pipeline quality” can be considerable, 2) paying your share or the costs versus your share of the costs versus having the company pay all costs is negotiable (just like every other clause in a lease), 3) you may have to sacrifice something to get the oil company to pay the treatment costs, 4) but if you ask for too much (and get it!), particularly with marginal wells, the company may not be able to make enough money to keep pumping the well as long as they might otherwise have done. If they stop pumping early you may receive less money, as royalty owner, over the life of the well.
Some examples are presented to help clarify the main trade-offs involved in the royalty agreement. First, however, we must establish some facts about how much oil or gas to expect from a typical well in Michigan, even though there really is no “typical” well. Every well is different—unique. Even averages for the state don’t do justice to most new wells. But some numbers are necessary to develop case examples, and Michigan’s oil and gas records are the best place to start.
The Geological Survey Division of Michigan’s Department of Natural Resources collects data and keeps records on oil and gas exploration and development in Michigan.
In 1985, there were 5,898 producing oil and gas wells in Michigan located in 51 of our 83 counties. Approximately 800 new wells are drilled each year. Generally, wells have their highest production when first completed, then taper off as underground pressures are released and the quantities of oil and gas diminish. The average life of a Michigan will is between 10 and 12 years, but a few wells in Michigan produced for up to 50 years.
Most of the wells in Michigan (over 60%) are what the Michigan Department of Natural Resources (DNR) calls “hardly-able wells.” These are “hardly able” to produce oil or gas any more because they are old wells, drilled 20 or 30 years ago, or they tapped a modest geologic reservoir. Such wells are also called “stripper” wells: they pump just a few barrels of oil per day. They usually don’t flow by themselves, the oil has to be pulled, or “stripped” from the rocks by the pump.
If we took Michigan’s 1985 total oil production (about 31 million barrels) and total gas production (about 151 billion cubic feet) and divided it by the total number of wells in Michigan that year (5,898), we’d find that the average production per day per well is just 16 barrels of oil and 73 Mcf of gas. At today’s well-head prices, the oil would be worth about $320 per day and the gas about $175 per day. That’s not much revenue from wells that usually cost over a quarter of a million dollars to drill.
Some wells, of course, produce at above average rates and few are truly outstanding. Almost all wells do better at the beginning of their life cycle than in later years. For the largest wells, the DNR sets limits on the amount of oil or gas that a company can pump in order to prevent the waste that rapid extraction can cause. This limitation is called “prorating.” The DNR currently prorates about a third of all the wells in the state.
Two “Typical” Michigan Wells
Even though there aren’t any typical wells, I’ve developed some typical well conditions so that we can see how much various royalty arrangements might cost landowners. The conditions are for two different geologic targets. The first is the Salina-Niagaran geologic formation, which has been the target of over 50% of the wells drilled in Michigan over the last ten years. Oil is usually the primary product from these wells, but gas is in solution with the oil. The average depth runs between 4,500 feet and 7,000 feet. The cost of drilling a typical well in the Salina-Niagaran is about $350,000 to $500,000 and it takes three to four weeks. The drilling unit—the spacing of wells as regulated by the DNR—is usually 80 acres.
My “typical” production figure for a new well in the Salina-Niagarn is 100 barrels of oil per day for 330 day s per year (i.e., 10% downtime for maintenance). At $20 per barrel, which is about the current selling price, this well would yield $660,000 for the first year.
The second geological formation that has drawn a lot of attention in Michigan recently is the Prairie du Chien horizon. It is deeper than the Salina-Niagaran. Only about 5% of the wells being drilled in Michigan are into the Prairie du Chien, but this new target zone has been a source of excitement ever since 1980 when it yielded Michigan’s first deep well discovery (the Dart-Edwards well in Missaukee County). Most of the Prairie du Chien wells are 10,000 to 13,000 feet deep. Generally, the drilling units are 640 acres, but the Michigan DNR has allowed a few wells to be drilled on 320 acre drilling units. The deep Prairie du Chien wells usually take six months to drill and cost anywhere from $1.5 million to $2.5 million dollars each.
The Prairie du Chien formation has produced only gas to date. When this gas is drawn up to the ground surface, however some of it condenses into a light hydrocarbon liquid, like propane. This “condensation” is a valuable product too, and some deep wells have produced a considerable amount.
My “typical” new well production figure for a Prairie du Chien well is 1,000 Mcf of gas per day for 350 days of production per year (gas wells require less maintenance time per year than oil wells). The current price is about $2.40 per Mcf, so this typical new well would yield $840,000 in the first year.
Now that we have some basics for wells in Michigan, let’s reconsider the royalty-clause again. Remember, different factors are important to different people.