A Marcellus royalty rate is the fraction of production or proceeds that an oil and gas lease pays the mineral owner, and in the two core Marcellus states the law sets a floor: Pennsylvania voids a lease that does not guarantee the lessor at least a one-eighth royalty, and West Virginia requires at least one-eighth of gross proceeds, free of post-production deductions, before it will permit new drilling under a flat-rate lease, whenever that lease was signed.
The royalty rate is the share of production, or of the money from selling it, that the lease reserves to the mineral owner, written as a fraction (1/8, 3/16, 1/5) or a percentage. It is set by the lease, not by the market. Royalty rates in oil & gas leases commonly range from 1/8 (12.5%) up to about 1/4 (25%); a larger fraction means a bigger share of production revenue. What you can actually negotiate depends on your leverage and the local market — talk to an oil & gas attorney or an experienced landman before you sign.
Two other things decide what the rate is worth on a check: the base it is applied to (gross proceeds, a value "at the wellhead," or a market value) and what the lease lets the company deduct before applying it. In the Marcellus those questions have been fought over in court and in the legislature, and Pennsylvania and West Virginia answer them differently.
Pennsylvania's Oil and Gas Lease Act provides that a lease conveying the right to remove or recover oil or natural gas "shall not be valid if the lease does not guarantee the lessor at least one-eighth royalty" of all oil and gas removed or recovered from the property. The rule dates to the Guaranteed Minimum Royalty Act of 1979. According to the Superior Court's 2022 opinion in Dressler Family, LP v. PennEnergy Resources, that act was repealed in 2013 and replaced with the Oil and Gas Lease Act, which carries an almost identical guarantee.
The act also reaches older leases that never paid a metered royalty. A well or lease without a one-eighth metered royalty is escalated to a one-eighth metered royalty when its original state is altered by new drilling, deeper drilling, redrilling, artificial stimulation, hydraulic fracturing or another procedure to increase production. Routine maintenance and cleaning do not trigger it.
In Kilmer v. Elexco Land Services (2010) the Pennsylvania Supreme Court considered whether the one-eighth guarantee forbids leases that compute royalty after post-production costs. As the Superior Court summarized it in Dressler, many Pennsylvania leases calculate the royalty as one-eighth of the sale price minus one-eighth of the post-production costs of bringing the gas to market, a calculation called the net-back method, whose goal is to value the gas "at the wellhead." The Supreme Court held the guarantee should be read to permit calculation of royalties at the wellhead, as provided by the net-back method in the lease before it.
Kilmer did not settle every lease. In Dressler (2022) the landowner argued that its lease, unlike the one in Kilmer, did not expressly provide for post-production deductions. The Superior Court found its royalty provision ambiguous, reversed a summary judgment for the producer and sent the case back for the factfinder to decide what the lease meant, offering no opinion on the result. In Pennsylvania, then, the words of your royalty clause decide whether and what the company may deduct.
As amended in 2022, the Oil and Gas Lease Act requires a fuller check stub for production from unconventional formations such as the Marcellus: the well name and API number, production month, volumes and price for each well, the aggregate amount of each category of deduction for each well, gross and net value, the owner's decimal or fraction, and the payor's contact information. An owner who does not get it may request it by certified mail and, if the payor neither provides it nor gives a reason within 60 days, may sue to enforce the act and recover attorney fees and costs.
Unless the lease provides otherwise, proceeds from unconventional production are due no later than 120 days from the first sale and then within 60 days after the end of the month the production is sold, with an interest penalty at the legal rate for late payment. Payment may be held where the owner lacks marketable record title, the interest is in bona fide dispute, or the owner cannot be located.
Two provisions govern horizontal wells across tracts. Where an operator may develop contiguous leases separately, it may develop them jointly by horizontal drilling unless a lease expressly prohibits it, and without an agreement of all affected royalty owners it allocates production among the leases as it reasonably determines. A 2019 amendment lets an operator drill a horizontal well across more than one unit if it reasonably allocates production to each unit and no lease expressly prohibits it.
Many old West Virginia leases pay a flat well royalty: a fixed annual sum per well, unrelated to how much is produced. The Legislature found that such leases deprive owners of the just benefit of the state's natural wealth and declared a policy against producing oil and gas under them. Under W. Va. Code § 22-6-8, the state will not issue a permit to drill a new well, or to redrill, deepen, fracture, stimulate or otherwise physically change an existing production well, under a flat-rate lease unless the applicant files an affidavit committing to tender the owner of the oil or gas in place not less than one-eighth of the gross proceeds, free from any deductions for post-production expenses, received at the first point of sale to an unaffiliated third party in an arm's-length transaction. Section 22-6-8(h) directs that the requirement be enforced irrespective of when the lease was executed.
The "free from any deductions" language is recent. In Leggett v. EQT Production Co. (2017) the Supreme Court of Appeals read the earlier statute to allow deduction of reasonable post-production expenses. As the court later recounted, the Legislature amended § 22-6-8(e) in 2018, effectively overruling Leggett.
For leases that are not flat-rate leases, West Virginia follows the rule of Wellman v. Energy Resources (2001) and Estate of Tawney v. Columbia Natural Resources (2006), which the Supreme Court of Appeals reaffirmed in SWN Production Co. v. Kellam (2022). The court answered the federal court's question "Is Tawney still good law in West Virginia?" in the affirmative and restated the rules in its syllabus:
If a lease provides for a royalty based on proceeds received by the lessee, unless the lease provides otherwise, the lessee must bear all costs of exploring for, producing, marketing and transporting the product to the point of sale. Lease language meant to allocate those costs to the lessor must expressly say the lessor bears some part of the costs between the wellhead and the point of sale, identify with particularity the specific deductions, and indicate the method of calculating them. And where a lease does allocate costs, the lessee is entitled to credit only for costs actually incurred and reasonable, which it must prove.
West Virginia's horizontal-well unitization statute, § 22C-9-7a, lets the oil and gas conservation commission unitize tracts for horizontal wells when its conditions are met, including that the applicant has obtained the right, consent or agreement to pool or unitize from executory interest royalty owners of 75 percent or more of the net acreage in the target formation. Overriding royalty owners and non-executive interest royalty owners are not counted toward that share. The statute defines a weighted average sales price without deduction of post-production third-party costs charged to or incurred by the applicant or its affiliates, other than costs after the first liquid trading point (or, for production that is not processed, after delivery to the first interstate pipeline). It also says that nothing in it alters West Virginia's common law on deducting post-production expenses in calculating royalty.
The two states share the Marcellus but not a royalty rulebook:
| Question | Pennsylvania | West Virginia |
|---|---|---|
| Minimum royalty | A lease must guarantee at least one-eighth or it is not valid (Oil and Gas Lease Act § 1.3) | For flat-rate leases, at least one-eighth of gross proceeds before a new or rework permit issues (§ 22-6-8(e)); otherwise as the lease provides |
| Post-production deductions | Allowed where the lease provides for them; Kilmer approved the net-back method; an ambiguous clause goes to the factfinder (Dressler) | Lessee bears costs to the point of sale unless the lease expressly provides otherwise, itemizes the deductions and states the method (Wellman, Tawney, Kellam) |
| Flat-rate and unmetered leases | Escalate to a one-eighth metered royalty when the well is altered by new drilling, fracturing or similar work (§ 2) | One-eighth of gross proceeds, free of post-production deductions, as a condition of new permits (§ 22-6-8(e)), whenever the lease was executed (§ 22-6-8(h)) |
| Horizontal wells across tracts | Joint development of contiguous leases and cross-unit wells unless a lease expressly prohibits it (§§ 2.1, 2.2) | Commission unitization of horizontal well units when statutory conditions are met (§ 22C-9-7a) |
| Check stub | Itemized per-well stub for unconventional wells, including each category of deduction (§ 3.3) | Depends on the lease and any statute that applies to it |
The arithmetic is the same everywhere; the lease decides the inputs. For each well and month, your royalty is the volume sold, times the price or value the lease specifies, times your royalty fraction, times your share of the unit, minus whatever deductions the lease and state law allow. Under a net-back lease in Pennsylvania the post-production costs come off before your fraction is applied; under a West Virginia proceeds lease without the particularity Tawney requires, they do not.
To check your own numbers, see how to read your royalty check and how to calculate oil and gas royalty payments, and for what deductions are, post-production costs.
Three parts of a lease work together on a royalty: the royalty fraction, the base it applies to, and any deduction or cost-bearing language. In Pennsylvania, unconventional-well check stubs must show each category of deduction. In West Virginia, the § 22-6-8 one-eighth rule for flat-rate leases applies when a well is drilled or reworked under the permit affidavit that section describes. For background on each state, see mineral rights in Pennsylvania and West Virginia flat-rate leases.
This page is general information, not legal advice. Royalty and deduction questions turn on the exact lease wording; consult a qualified oil and gas attorney licensed in your state.
Mineral Rights in Pennsylvania
West Virginia Flat-Rate Leases
Marcellus and Utica Mineral Rights
How to Read Your Royalty Check
Oil & Gas Encyclopedia — all terms
Educational information only — not legal, tax, or investment advice. Consult a qualified attorney, CPA, or landman about your specific situation.
Whatever the lease says, subject to state minimums: Pennsylvania requires a lease to guarantee at least a one-eighth royalty. Royalty rates in oil & gas leases commonly range from 1/8 (12.5%) up to about 1/4 (25%); a larger fraction means a bigger share of production revenue. What you can actually negotiate depends on your leverage and the local market — talk to an oil & gas attorney or an experienced landman before you sign.
One-eighth. Under the Oil and Gas Lease Act, a lease that does not guarantee the lessor at least a one-eighth royalty of the oil and gas removed or recovered is not valid. The rule began with the Guaranteed Minimum Royalty Act of 1979.
They can where the lease provides for it. In Kilmer v. Elexco (2010) the Pennsylvania Supreme Court held the one-eighth guarantee permits royalties calculated at the wellhead by the net-back method. Where a lease is ambiguous, as in Dressler (2022), its meaning goes to the factfinder.
A way of valuing gas at the wellhead by subtracting from the sales price the costs of getting the gas from the wellhead to market. Many Pennsylvania leases compute royalty as one-eighth of the sale price minus one-eighth of those post-production costs.
Only if the lease expressly says the lessor bears part of the costs between the wellhead and the point of sale, identifies the specific deductions and states the method of calculation, and only for costs actually incurred and reasonable. The Supreme Court of Appeals reaffirmed this in SWN Production Co. v. Kellam (2022). Flat-rate leases converted under W. Va. Code 22-6-8 pay one-eighth of gross proceeds free of post-production deductions.
A lease that pays a fixed annual sum per well regardless of production. The Legislature found that "a great portion, if not all," of such leases have been in existence "for a great many years," but the rule applies whenever the lease was signed: West Virginia will not permit a new or reworked well under one unless the operator commits by affidavit to pay at least one-eighth of gross proceeds, free of post-production deductions.
It was repealed in 2013 and replaced with the Oil and Gas Lease Act, which keeps an almost identical one-eighth guarantee and adds rules on apportionment, check stubs and payment timing.
For unconventional production, unless the lease provides otherwise, no later than 120 days from the first sale and then within 60 days after the end of the month of sale, with an interest penalty at the legal rate for late payment.
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