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Post-Productions Decuctions, The Beast and Pesky Check Statement Details

First, a definition for post-production deductions (PPD) is necessary. Operators consider exploration and the drilling phase to be exclusively working interest owner’s expenses. Once oil and gas are out of the ground and from that point producers assert royalty is subject to post-production expenses. These expenses are typically to transport and market the products.

NARO was hearing from members, and some non-members, about the amount of deductions taken from the gross oil and gas values. In response to growing concerns, the NARO Board at its Oct 2016 board meeting formed a PPD committee to gather data to better understand the issues and to separate the emotion of perceived unfairness due to not knowing the details from the actual lease language and lawful facts.

The typical lease form royalty clause contains terms for calculation oil royalty payments, such as, “free of cost, in the pipeline” “at the well or wellhead”, and for gas, “computed at the mouth of the well” or ” “at the prevailing market rate for gas”. The lease often does not defile what those terms mean…

Last December, the committee crafted and released a survey to member royalty owners seeking information about their knowledge of lease, royalty statement disclosures and industry practices. Responses were received from 138 owners representing 85 different lessees. The largest response numbers were for properties owned in Pennsylvania, Texas and Oklahoma, in that order. For a number of states though, the response numbers were too few to be statistically meaningful.

The survey also requested information about whether the lease prohibited or permitted deductions. Many did not offer supporting lease royalty clause or royalty statement documentation, and without the documentation the committee could not determine the answer to the most important question, does the lease prohibit or permit deductions. This vital question, although important in analyzing statement details, was not the end-all for the committee. It just meant the committee needed to work harder to get the information. Calls were made and additional data collected, and a sampling of recorded leases was reviewed to determine common royalty terms.

The oil and gas lease agreement is a legally binding contract with every word having meaning as to the parties’ intent. The common practice is for most mineral owners to accept a company-prepared lease form. The typical lease form royalty clause contain terms for calculating oil royalty payments, such as, “free of cost, in the pipeline”, “at the well or wellhead”, and for gas, “computed at the mouth of the well” or “at the prevailing market rate for gas”. The lease often does not define what those terms mean, but a number of state and federal court decisions have opined as to meaning and therefore provided a methodology for lessees to calculate royalty payments.

Different court venues throughout the United States have recognized two methods used to determine market or product value for royalty payments; a “gross proceeds” and a “market value at the well” lease language. There are variations of each method. The majority of the states follow the “at the well” rule and there are two methods that can be used to determine value with the rule, a comparable sales approach that averages what other producers in the field receive, and a work-back (or sometimes called “net-back”) method. The work-back method calculates the market value at the well by using a price; typically for gas this is the processing plant tailgate or non-processed gas point of sale, and then subtracting post-production expenses to arrive at the wellhead price. Expenses can include transportation, gathering, compression, processing, treating, marketing and sometimes other charges such as risk capital and depreciation.

Some states have adopted the “first marketable product” rule or doctrine. Under this method, the lessee pays the cost to make unmarketable gas into a marketable product. This occurs as some point before the plant tailgate, and thereafter the lessee and lessor share additional cost to enhance marketability.

What this all means is that if the lessors and lessees do not clearly spell-out royalty calculation components in the lease, such as point of sale, the basis for product price, and costs related to marketing or enhancement to make the product more marketable, the courts will do it for you.

The survey also told us that royalty owners were generally unsure if their lease prohibits deducts or even if they were being treated fairly. In response to the question if their lease prohibited deductions, 40 percent were unsure. Striking though is that 106 of 128, or 83 percent, felt they were unfairly treated or were unsure if their lessee paid them fairly.

The committee’s study also revealed many different variations in the monthly royalty statement format. This lack of uniformity adds to the difficulty to understand gross and net amounts. Many statements also provide only the product price net of deductions or lack an explanation or description as to deduction types. For example, a number of statements only have an “other deduction” column with no code for an explanation of deduction type.

Prior to putting all of this together it is important to revisit NARO’s mission, and that is to educate, advocate and assist royalty owner members. The survey results telling us the majority of royalty owners are unsure how to interpret if their own lease prohibits or permits PPD makes the compelling case that NARO needs to do more to educate owners.

At the September 6, 2017 Board meeting six committee recommendations were adopted. These include:

1. NARO should develop a “Lease Management 400” course for national education opportunities for members.

2. State and regional chapters are encouraged to supplement the Lease Management 400 course with state specific laws, rules and regulations, and jurisdictional case law, and present the entire course during local events.

3. NARO needs to take a national position against operators assessing unreasonable and excessive deductions in amount or type, unless specifically authorized by the lease contract.

4. An electronic repository should be created to allow chapter representatives to upload administrative and court case summaries with links categorized into different folders.

5. NARO needs to advocate that mineral owners insist on well-defined terms in all prospective lease negotiations or ratifications to existing leases.

6. NARO needs to support royalty statement transparency to owners requiring lessees to fully disclose, by providing complete explanations for all deductions by type and amount, including identifying whether the deduction is the result of a transaction with an affiliate or third-party.

Additionally, any deductions netted against product price should be disclosed, purpose provided and amount quantified. Post Production Deductions would be an offered track of a Lease Management course with the objective to provide royalty owners with information as to typical lease royalty provisions, case law, industry practices, understanding royalty statements and lease compliance monitoring (auditing).  The intent here is for royalty owners to be better informed when it comes to negotiating leases, and for those with existing leases held-by-production, to have the tools to better manage lease compliance. Armed with this knowledge, royalty owners should be able to determine if a deduction is appropriate, and if not, to pursue reimbursement for underpayment.

Gary Preszler, CMM, NARO

North Dakota VP, Post Production Deduction Committee Chairman

SOURCE: National Association Of Royalty Owners

 

Compiled and Published by GIB KNIGHT

Gib Knight is a private oil and gas investor and consultant, providing clients advanced analytics and building innovative visual business intelligence solutions to visualize the results, across a broad spectrum of regulatory filings and production data in Oklahoma and Texas. He is the founder of OklahomaMinerals.com, an online resource designed for mineral owners in Oklahoma.

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