Royality Calculations: audit or accuracy

Does anyone have experience in companies offering review and analysis of royalty payments for accuracy and correctness? We have been approached in Ohio by Law offices who charge either a flat fee or % of findings to review and verify if you are receiving the proper amount based on your contracted percentage, fees, costs and equation.

A flat fee risks your being charged with no work done. Make sure they do not get you dragged into a lawsuit.

Audits should have been written into your lease - namely the oil company has to pay for it if the auditor . Few people do it. Yes, if you have reason to believe you are being screwed, then an audit is appropriate and sometimes necessary. It isn't cheap however.

So many provisions in a lease that mineral owners should have DEMANDED. And should have joined with other royalty owners into large groups to make sure the companies had to deal with it. Divided we fall. They pick you off one by one.

Thanks TL, I will review the lease, I have my lawyer here looking into that and other tactics to ensure the royalty is correct and account for the costs charged.

Any other info?

T L Shields is right on target. Look your lease over carefully. It is your foundation.

First, you verify that the decimal on your check is accurate. I don’t know Ohio remittance detail requirements specifically, but based on my experience, typically there are TWO decimals on your check: your entitlement decimal, and your payment decimal. The difference? It’s this:

Say you own 50% minerals in a 20.0 net-acre tract in a 320-acre pooled unit. Your lease has a 3/16 royalty clause. The correct calculation for your share of proceeds from 100% of the production coming out of the well (entitlement) would be 50% x 20/320 x 3/16 = 0.00585938 RI. But what if your lease is owned 50% by the operator, and the other 50% by one of the partners, and they are both selling to different contracts?

Each company receives the revenue for their 50% of the sales directly from their respective purchaser. Each owes you 50% x 0.00585938 RI or 0.00292969 RI. That is your 8/8ths payment decimal that each company is remitting for your 0.00585938 RI entitlement decimal. Bear in mind that the price per unit (mcf or bbl) on each check will be different, and the costs deducted might be different (if your lease doesn’t have a cost-free royalty clause).

Now let’s say that the check from the operator shows the 0.00292969 RI decimal, but the check from the partner shows the 0.00585938 RI decimal instead. That would be because the partner is inflating your payment decimal by the 50% of total well production (8/8ths) sold only by the partner: 0.00292969 divided by 50% = 0.00585938 RI.

Once you’ve verified that you are receiving your entire entitlement decimal (even if it’s in pieces), next you have to find out if the “price per unit” on your check stub is the gross price paid by the purchaser to the payer, or if the payer has deducted post-production costs of any kind from it, thus reducing it to the price you see on your stubb. I can tell you that this practice is exactly what got Chesapeake into such hot water, that they finally settled some $50 million worth of lawsuits in January, 2018, pretty much all claiming the same foul-play practice of deducting post-production costs from the per-unit price, trying to skirt around the cost-free royalty clause in the plaintiffs’ leases. “Cost-free royalty” means free of post-production costs. “Free of costs royalty” means free of costs of exploration, drilling, equipping and producing.

The first part is usually easy, as long as you accurately know your percentage of royalty rights, the correct size of the tract, and the correct size of the pooled unit. The second part (deducts) is the hardest to audit. Good luck.