Hilcorp acquisition of XTO 2024 TX deductions

Has anyone been able to get an adequate explanation from Hilcorp regarding the additional deductions Hilcorp is taking from the royalty checks since they purchased the XTO assets in Texas in early 2024? My checks are significantly less and it seems to be from some allocations being done called Service Mkt Fee and Other. I have tried a few times, but no explanation. I believe they reversed the Service Mkt Fees one month after I asked, so maybe if they appear, they are errors?-not sure. I am in the process of trying to go back and verify what they have done for the past few months to figure it out.

You should review your O&G lease for clauses relating to “no post production costs”.a/k/a marketing or transportation costs. There are court rulings in Texas that determine the validity of these clauses based on whether the lease sets the payment of royalties “at the wellhead” ( most all “producer 88” forms use this language ) or if addendums set the payment on “gross proceeds”. If your lease (or subsequent addendums, letter agreement , etc ) refer to payment based on gross proceeds , send a certified letter stating such, and request reimbursement with statutory interest.

Havent received a check since 4/25 of this year… spoke to owner relations…was told this…XTO wasnt keeping very good books and habe not been properly deducting costs…

Now Hilcorp took over Jan1st and we received first Hilcorp check in March for Jan production. Assisde from SRVICE MKT FEE everything seemed fine. Check for April was for Feb productoin, and same as before with MKT FEE now being applied in positive amounts for some wells. Noticed a new fee for OTHER which seemss odd…

My qeustioning is since there is a statue of limitation on my claiming underpaid royalties… does this also apply for Hilcorp for issuing corrections to the like?

I find it hard to beleive tha XTO/Exxon would have not deducted fees properly and the idea that they wernt keeping very good books just doesnt seem correct.

Also if were paying back Hilcorp for XTO overpaying us then why would we receive a check from XTO in May for Oct 2023 production corrections?

Generally, this is governed by the effective date of the asset transfer from XTO to Hilcorp, which will be stated on the Bill of Sale / Assignment filed in the deed records. Corrections for production months before that date will be issued by the seller (XTO) and the purchaser (Hilcorp) will make payments and corrections for production months starting with the effective date. XTO continues to have the right to make corrections (positive and negative) for prior production months.

I’m hoping to analyze what I can from my end soon and then contact XTO and Hilcorp to hope for some clarification. XTO has been consistent on their reporting since I starting reviewing their royalty payments in 2003 on my wells other than some of the expense breakout changing. I’m finding it difficult to understand how more costs can be involved than what XTO was already charging.

Several reasons why the costs could vary. Some companies are more aggressive than others in charging costs against royalty owners. Oil and gas law is not absolute and changes with case law on what can and cannot be charged. The Hilcorp legal department may have analyzed your lease and decided that there is an additional cost which can be deducted. The contractual terms of gathering, transportation and processing will vary and one company may pay $0.10 per mcf and another may be paying $0.20 per mcf. The two legal departments are not going to compare their contracts and legal opinions and come to a jointly agreed position in answer to your question. You should focus on asking Hilcorp for a breakdown of all the costs which are being charged and then review your lease provision(s) addressing royalties and costs. If your lease cites proceeds or value at the wellhead, then you will have fewer arguments against the costs. This is an increasing problem for mineral owners as some companies are writing new contracts to implement cost deductions. You are not alone in being frustrated by this.

Surely there has to be some reasonable statue of liimitation on this type of activity? This would highly effect the value of the leases if they are able to make corrections on prior production indefinitly.

Oil company pays royalties under a contract (lease) and is bound to make corrections, whether resulting in an increase or decrease in royalty payment. Oil company cannot delay paying royalties on the grounds that there is some uncertainty as to the exact pennies due. So the payment is made within a couple months of production. Later the company may audit and find that there was an incorrect calculation of the production volumes, or that the oil or gas purchaser made a correction to the price or total sales revenues, or other errors. So the oil company makes the adjustments. The mineral owner has 4 years to challenge the royalty calculation or cost charges. If a PPA adjustment / correction is made on two years later, then the mineral owners has 4 years to challenge the adjustment. In my experience, PPA result in an increased royalty as frequently as a decreased royalty. I have seen adjustments which go back 6-7 years, but that is rare. Here is a link to a good article on monitoring lease compliance. Monitoring Lease Compliance — Oil and Gas Lawyer Blog — August 14, 2017