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Oil/Gas/Division orders and distribution of payments among partners in the pooling unit


QUESTION: Hi Marsha,
I am the steward for a 100 acre family property in Bradford County Pennsylvania that has leased the full acreage for oil and gas exploration in the Marcellus Shale

We successfully negotiated a suitable lease with Chesapeake Energy in 2011 and 33 of our acres was included in a producing pooling unit with two wells drilled and fracked in Nov 2011, from which we are receiving royalties.

Our first checks arrived, but from 5 different partners - Chesapeake, Anadarko, Statoil, Chief, and Mitsui. This is allowed by the terms of the lease, though it came as a surprise since our lease is with a single company.

My understanding of this condition is that the 5 partners in the pooling unit proportionally divide the responsibilities for and the income from the pooling unit under identical terms specified by our lease, as though they were a single entity (or as though we had an identical lease with each of the 5 entities), and each entity pays their percentage of the royalties to us in proportion to the percentage of their interest in the pooling unit.

My question is regarding this: The payments we receive each month vary in proportion to one another. If the lease conditions are identical for all 5 partners, and they are paying royalties on the same pooling unit for the same period, and their percent interest in the well doesn't vary, why would the proportion each pays relative to what their partners pay vary month to month?

Would you recommend that we hire someone to review the lease and payment records of the 5 partners to ensure that they are operating within the terms of the lease, recording the production of the wells properly, and paying their proportion of the royalties correctly, now that we have a couple of years of reports?

ANSWER: You have presented a very important question. It appears you understand correctly the nature of a pooled unit, and that all 5 of the payers are obligated to collectively pay to you all of the royalties that are due to you from production from the well.

Now, to address your questions. First, there are many variables affecting what and how a partner in a well pays. Let's start with the Accounting Database System that the partner is using. Let's say for example that Partner One owns 20% of your lease (which is how this works when more than one company is responsible for paying you). Let's say for example that you are entitled to a full 1/8th royalty in everything that comes out of the well. That means Partner One owes you 20% x 1/8 = 0.02500000 RI. But if their database will not allow them to base their payment record on only 20%--since they are receiving 100% of their 20% money and having to pay you out of it--then they must "inflate" your 0.02500000 RI by 20%, and you will see "0.12500000" decimal on your check detail from Partner One.

But now lets say that Partner Two owns only 10% of your lease. They are only responsible for 10% x 1/8 or 0.01250000 RI.  Then Partner Three owns 30% of your lease, and owes you 30% x 1/8 or 0.03750000 RI. If Partner Four owns only 15% of your lease, they must pay 15% x 1/8 or 0.18750000 RI.  Partner Five would have to own all of the remaining 25% of your lease and pay you 25% of 1/8 or 0.03125000 RI.  When you add all of the pieces together: 20% + 10% + 30% + 15% + 25% = 100% of your 1/8th royalty is being paid, but not in proportion to one another.

After explaining those two variables, the next one has to do with post-production costs. Your share of post-production costs of getting the production to market is deducted from your check each month. Each of these partners most likely are selling their respective share of total well production to their own purchaser, to their own contract with that purchaser. The terms of the contracts will vary. Some contracts will have higher post-production costs than others for various reasons. Again, if their database system requires it, your payment decimal will vary month-to-month from the same partner possibly due to changes in post-production costs.

I hope this explains well enough, but please remember that you are allowed to call a remitter and ask exactly how your payment decimal was calculated, and they have to tell you.  Or, you can hire someone like a CPA experienced in gathering that type of information, to do it for you and make certain you have been paid everything owed to you. In most states that requirement is statutory (required by state law). Please let me know if I can help you further.  Best of luck.

---------- FOLLOW-UP ----------

QUESTION: Thank you Marsha, and yes, that is very clear.

In going through the records I have from each of the 5 partners over the last 2 years, I observe exactly what you describe. They split the pooling unit up among themselves each with their own percentage of the whole, and they pay out according to the percentage they own. For example, in checking the records the volume of gas production reported for the month in each partner's reports reflects exactly their percent interest for that month, and this does not vary from month to month.

However, there are two areas of the reports where there are inconsistencies - The amount of the deductions, and the price of the gas that is used to calculate the payments.

The percentage deducted from each partner's payments varies among the partners from month to month by as much as 20%, with one partner deducting a portion of the total deductions different from their percent interest one month, and then reducing their portion of the deductions to less than their percent interest in another month. Is this because of the effect you mentioned that their contracts with their own buyers is not regulated by the lease conditions they have with us so the deductions they charge each month are not related to the lease, nor are they similar in nature between each of the partners so the percentage of deductions will vary greatly among the partners? This would explain why they change from month to month, and from partner to partner each month.

The other discrepancy is the price of the gas by which the royalties are calculated. The period of reporting for each of the 5 partners is the same, but the price they use is always different, sometimes one partner stating the price at half of another partner (in a single month the price among the 5 partners varies between $3.05/MCF to $7.13/MCF. What makes that discrepancy possible? We originally negotiated for a lease condition that stipulated how the price of gas was calculated, but it was struck off by the gas company during our negotiations and we accepted that strikeout.

The partners are Chesapeake, Anadarko, Chief, Mitsui, and Statoil.

As for your third paragraph, you are on the right track, but need additional information to correct your picture.  Each partner has their own contract with their purchaser, and each contract most likely is going to vary as to price and fees charged to make the production marketable or transportable.  That partially explains the most likely reason for the differences in unit price and deduction decimals.  The deductions you are seeing may or may not be allowed by your lease.  You must read your lease.  Does the royalty clause say the royalties are to be paid "at the well"?  And do you have an Addendum (page with added clauses) that contains a clause that says that royalties paid are to be free of cost of transportation, compression, treating, marketing, or any other post-production (after the wellhead) costs? If there is no Addendum clause like that, then you do have to pay your share of costs, whatever they are. But other reasons why the deductions change from month to month for each partner are (1) not all post-production costs are incurred each month, for many reasons, too many to explain here; and (2) purchasers typically charge an estimated fee initially when making a payment, then they adjust that estimate up or down to the true, final deduction on the following month's check to the Partner. All of this shows up as additions and subtractions in your check, but should always be labeled as to the month of production that the addition or deduction applies. So always be sure to compare same-month addition and subtractions. This should be shown on your royalty check as "Sale Mo." or "Prod Mo."

As for your last paragraph, what you are describing sounds like the partner crediting you with half-price gas may have already taken out the post-production costs but failed to itemize them.  There are numerous court cases that rule in favor of the royalty owner against the oil companies doing this, but it still happens because too many companies are still using old database systems that are not programmed to stop the practice.  Texas statutes require certain specific pieces of information to be included on every royalty check detail, and itemized deductions is one of them.  You might want to consider consulting with an oil and gas attorney so they can help you decide what, if any, action you should take to clarify and possible get reimbursement for non-compliant deductions.

Lease negotiations are important. You have to have your deal-breaker must-haves (royalty rate, bonus per acre, maximum length of the lease, Pugh clause and other terms you feel are mandatory), and everything else is flexible. It sounds like the provision on how gas is to be calculated was a flexible item for you, in order to get what you wanted in the "must-haves" column.

Some insider information: Chesapeake is always dealing with entry-level (new hires) division order analysts and revenue accountants who don't know too much about what they are doing so it doesn't matter what database they use; Anadarko uses a state-of-the-art computer database system so statutory compliance is no problem, and they have an extensive in-house training system so their analysts are highly effective, even the new ones; Chief uses an old, outdated computer system and adequate but not well-experienced analysts; Mitsui has an employee revolving door (how we jokingly refer to high turnover rate among us analysts) and a less-than-ideal computer database system for itemizing deductions; and Statoil uses the same database system as Anadarko but does not have the highly-evolved training system Anadarko has. That might help you as you further analyze your check details.  


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Marsha Breazeale, M.Ed., CDOA, CPLTA


All questions regarding division orders; ownership decimal calculations; title ownership and payer record changes (testate/intestate inheritance; deed; assignment; court order); oil and gas lease analysis for record-keeping and purposes of payment by operator or payer; pooling, horizontal wells, horizontal well allocation units; unclaimed property reporting; royalty owner relations questions. All questions concerning administration of surface land contracts and payment questions, such as for Surface Right-of-Way, Sub-Surface Right-of-Way, Easement, Surface Use Agreement. All questions regarding industry-standard and company-specific policies that affect land owners.


Sr. Staff Division Order Analyst. Certified Division Order Analyst (CDOA, National Association of Division Order Analysts) and Certified Lease Analyst (CPLTA, National Association of Professional Lease and Title Analysts) with 35 years of experience as a combination division order analyst and lease analyst in exploration and production in the oil and gas industry.

National Assoc. of Division Order Analysts (NADOA), National Association of Division Order Analysts (NALTA), American Association of Professional Landmen (AAPL), American Society of Trainers and Developers (ASTD)

"How an Oil & Gas Exploration & Production Company Operates" and "Principles of Oil & Gas Lease Analysis: Standard Clauses", Oil Patch Press; Articles in NADOA Magazine; LandFocus EDU Professional Training Manuals

Education/Credentials Management from Our Lady of the Lake University in San Antonio; M.Ed. in Instructional Design from WGU Texas.

Past/Present Clients
Past 15 years: GeoSouthern Energy Corporation; Contango Oil Co./Crimson Exploration & Operating Inc.; Apache Corporation; BP America; Marathon Oil; Newfield Exploration

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