Recently the total amount of deductions from operators applied to royalty checks have been estimated and total amounts are impressive.
I like to address it on a USD per bbl costs as that is an amount I can relate to.
So how are these deductions calculated?
If I am right deductions should only relate to the transporting and processing of the oil from the well head to the sales point. The royalty owner gets a net 'well head oil price' minus state taxes for his equity oil.
In this way the operator has sold the royalty owner equity oil for you at the refinery gate and the royalty owner paid for processing and transport to the refinery gate (sales point).
Processing and transport of gas after it is separated from the oil is not included.
Operating costs related to pumping, water disposal, water injection and workovers etc. are not to be included. These operating costs (not sure whether transport and processing costs are included) are possibly some 5-10 USD /bbl (reported in the company quarterly reporting slides).
So how would the oil company calculate the well head price for us?
I think they take the monthly weighted avg. oil price (Sales revenue/ volume bbls) they sold their oil at Chicago or any refinery gate (they may sell every day for a spot price and / or may have at the same time have other deals I do not know). This is not exact your oil as it is all mixed and processed oil (to stabilise and remove the gas). Say this gives the weighted avg. monthly sales oil price in USD/bbl for the specific operator.
The sales oil price for ND oil is likely related to the WTI price and the difference depends on quality compared to WTI oil and sales point and marked conditions.
It is important to watch that they do not sell cheap to their own refinery and make the profit in the refinery processing. How can we check that? This is an important task for the state as they get their taxes based on well head price. An individual royalty owner has no control.
Similarly if they transport the oil with high costs to the refinery they can deduct and create a low well head price. The railway or pipeline company makes then a good profit. This is interesting if they own their own transport. Also a task for the ND State to watch and control for us.
On the revenue check an oil price is reported, but I am not clear which oil price that is as some operators deduct TRN and others call it other deductions.
The interesting part is what is the net oil price before the State tax calculation.
Is the transport and processing related to oil (deductions) some 5 or 10 USD /bbl? That makes a large difference. That is not so evident from the statements I receive.
Some historical statistics split by transport and processing on these costs by operator would be interesting to see.
So what is the operators avg. monthly sales oil price for ND oil received?
Appreciate you comments.
North Dakota Administrative Code 43-02-06-01, subsections 6 and 11 dictate that to properly request information from a mineral royalty disburser, it must be sent via certified letter and a 30 day response time is also required of the mineral royalty disburser.
You are absolutely correct that we have no means to verify whether we are being properly compensated. It required a lawsuit to substantiate the right of the North Dakota Department of Trust Lands to audit and expect that requested information being submitted to the Department.
Many financial experts suggest that Oil & Gas transactions are the most complex financial instruments in the world, bar none. Further complicating the issue is that leases have evolved over the years as court cases have been decided in a manner that was adverse to the industry. A new lease form has been created at various junctures when a loss was too substantial. This wide variation in lease language makes the situation more and more difficult to assume what is or Is not appropriate or legal.
When the oil and gas leases were signed in ND during the late 40's and early 50's, it was assumed that a 1/8 lease meant you would get 1/8 of the value of whatever oil and gas was produced. That practice seemed to be followed for more than 50 years. It was the "trust me" practice that reputable industry leaders took pride in providing. The new corporate leaders seem to have no inhibitions to violate that policy and the "trust me" philosophy has died. We are now dependent on the courts making all decisions about what the language in a lease means. I believe it is time for the state legislature to address the many issues related to our concerns, but it is incumbent on us to work together and help define the solutions we believe appropriate.
I also believe you are asking how the $319 million dollar figure was determined. I will try to delineate.
Using the latest production numbers from the NDIC of 1,480,000 barrels per day (bpd), $43.28/ barrel being used by the Legislative Assembly for budget projection purposes, and assuming everyone has a 1/8 (12.5%) I will run through the process.
But first we must make an assumption of what we believe the average Postproduction cost (PPC's) is that is being assessed. Hess Bakken Investments since the beginning of 2016 has assessed more than 35% PPC's. Rumors have it that other companies are also at a similar percentage being withheld as well. Some companies suggest that there PPC's are much less but it difficult to understand why the same companies pay less for the produced oil. So we are going to assume that the average PPC being assessed by some means is only 10% overall. I would suggest that is very conservative.
So here is the math and you are welcome to tell me where I may have erred in my assumptions or calculations:
1,480,000 BPD x 12.5%= 185,000 BPD to Royalty Owners (RO)
185,000 BPD x $43.28= $8,006,800 Dollars/Day to RO
$8,006,800 x 10% PPC's=$800,680 /day PPC's
$800,680 /day x 365 days= $292,248, 200 per year
This number includes the latest daily production from NDIC but also includes the per barrel price used by Legislative Council for projections rather that the original estimate of $50 per barrel. If $50 / barrel is used, the estimate becomes $337,625,000. We also know that not everyone has a 1/8th lease. I believe this to be a conservative estimate of real PPC's.
I just joined the WBROA.
I'm trying to figure out why Hess deducts an astronomical amount of money for "Administrative Costs" (according to their revenue statement). For instance, for June, 2020 natural gas they deducted a net amount of $115,794.99 (Product Code 204). I actually lost $101.57 for just that one transaction based on $1.54 per mcf.
Other operators don't have nearly the amount of deductions that Hess does. When pressed for details, Hess explains that the breakeven point for natural gas is about $4.00 per mcf.
Does anyone know if Hess has been audited by anyone in this matter? It would seem that the logical route to take would be to audit Hess and see where these costs are coming from. If Hess or any other company has been gouging the royalty owners then a class action lawsuit may clear up this whole mess.