CARROLLTON, Ohio, May 25, 2021 /PRNewswire/ — Gateway Royalty, which invests in oil and gas production by buying a portion of the mineral owner’s royalty interest, is sounding the alarm about an industry backed bill that would require unleased mineral owners to accept net proceeds royalties from the well operator.
Ohio’s H.B. No. 152 seeks to amend R.C. section 1509.28, which provides for the mandatory pooling of unleased mineral owners in drilling units approved by the Chief of the Ohio Division of Oil and Gas Resources Management. Under the existing statute, an unleased mineral owner can choose to (1) participate in unit operations under lease terms negotiated with the unit operator, (2) participate under the terms of the unit order, or (3) elect to not participate and pay a nonconsenting penalty charge in an amount determined by Chief.
H.B. No. 152, if enacted, “would fundamentally alter an unleased mineral owner’s options in ways that would greatly benefit the Unit Operator to the detriment of the mineral owner,” says Chris Oldham, Gateway Royalty’s president. The mineral owner’s first option (which is the default option if the mineral owner declines the other two) requires the mineral owner to accept a royalty of 1/8th of the net proceeds received by the operator. “Net proceeds” is defined in the bill as “proceeds on the sale of production less any and all taxes and fees levied on or as a result of production and less all post production costs incurred between the wellhead and the point of sale.” Based on some of the current operators’ cost deductions, a 12.5% royalty under a net lease is the equivalent of a 6.25% royalty interest or less.
According to Oldham, an unleased mineral owner should be permitted to negotiate for a “gross proceeds/no deduct” royalty, as well as for a royalty percentage greater than 12.5%.
Oldham says that many oil and gas leases are gross proceeds leases in which the royalty is a negotiated percentage of the gross sale price. Oldham says that this percentage was traditionally 12.5% (1/8th), but with the Utica shale boom the percentage is now “more often between 16 and 20 percent.” H.B. No. 152, Oldham says, “removes the ability of an unleased mineral owner to negotiate for a gross proceeds royalty and for a royalty percentage above 12.5%.”
The mineral owner’s first option (which is the default option under the Bill) requires the operator to pay the unleased mineral owner a bonus of 75% of the current market rate for a bonus payment per acre. This provision is also unacceptable because it does not represent fair market value, according to Oldham. He says that the per acre bonus should be “the average bonus paid for all acreage in the unit in primary term of the lease, excluding any acreage held by production.”
The second option to unleased mineral owners under the Bill is to participate in the unit operations as a consenting party under the terms of the joint operating agreement (“JOA”) attached to the unit operation application. Oldham says this is not a viable option because very few mineral owners, if any, can take the risk and liability of a working interest owner, let alone have the financial ability to join in the drilling, completion and production operations of these Utica horizontal wells, which cost a minimum of $6.0 million to $8.0 million per well.
The third option is to participate in the unit operations as a nonconsenting party under the terms of the JOA along with a 300% non-participation charge payable from the nonconsenting owner’s share of production. Oldham says the third option is not viable either because there is a high probability that the mineral owners’ interest will never pay out. Oldham says since neither the second nor third option is viable, the unleased mineral owners “will be stuck with the first option.”
It is the forced deducts that rankles Oldham the most. “By forcing mineral owners to accept a net proceeds royalty, this Bill gives operators unfettered freedom to deduct post production costs,” says Oldham. These costs, he says, “are sometimes paid to midstream affiliates of the operator and are often grossly inflated.”
Oldham says that, for federal tax reporting purposes, Gateway uploads into Integra oil and gas revenue accounting software all 8/8ths information on the monthly royalty statements Gateway receives from each operator on the wells in which Gateway owns a royalty interest. The 8/8ths information includes the amount of each product sold, the gross sale price, the post production costs by category and amount, the net sale price (the gross sale price less the post production costs), Gateway’s royalty decimal interest in the net, and the dollar amount of the royalty payment to Gateway.
Utilizing the individual well information from the Integra oil and gas revenue accounting software, the following table summarizes certain information by operator on 1,466 producing wells in which the Gateway companies own a royalty interest and the operative lease is a net proceeds lease. All well information is from date of first production through March 31, 2021, except for the wells that Encino acquired from Chesapeake in October 2018. When Chesapeake owned the wells, they did not disclose on the monthly royalty statements the types and amounts of post production costs they deducted from the gross price it was paid. In May of 2019, several months after it acquired the wells, Encino began to report all cost deductions on its royalty statements. The “Encino (CHK)” well information is through December 2020.
The following table shows the wide variance among ten operators as to the percentage of the gross sales price they deduct in costs. The operators deduct on average 28% of the gross price. On the high end of the spectrum is EAP Ohio (Encino-CHK), which deducted an average of 57% of the gross sales price from 650 wells with a high of 95%. On the low end of the spectrum are Rice and Equinor. Rice deducted an average of 13% of the sale price from 192 wells with a high of 38%. Equinor deducted an average of 13% from 11 wells with a high of 20%.
