Indian Payor Handbook

2.4.1 Royalty Measurement Points

Lessees must report and pay royalties on the quantity and quality of production measured at the point of royalty settlement, also referred to as the BLM-approved Royalty Measurement Point (RMP). This handbook will use “point of royalty settlement” and “RMP” interchangeably.

The point of royalty settlement/RMP is the meter where production is measured for royalty purposes and is determined by the Bureau of Land Management (BLM) for onshore production.

The RMP is usually located on the lease or agreement, at or near the wellhead. Lessees require prior approval from the BLM to place the RMP off of the lease or agreement. If you have questions about which meter is the RMP, check with your local BLM office for assistance.

2.4.2 Timeline for Reporting

Most leases contain language stating that you must pay royalties using the appropriate value for the month when production is removed, saved, or sold from the lease. For example, if you remove production from the lease or agreement and place it in an underground gas storage reservoir in January, royalty value is the value of production in January, even though you may have removed production from storage and sold it at a different price at a later date.

In situations where gas is processed, royalty is generally due on the monthly net output (quantity) of residue gas and gas plant products measured at the tailgate of the plant and attributable to the lease under 30 CFR §1206.175. For more information, please refer to Chapter 4 of this handbook, which will discuss processed gas valuation in more detail.

ONRR requires electronic reporting unless you qualify for an exception under 30 CFR §1210.105. You must receive prior approval from ONRR to report via paper reports. If you receive approval from ONRR, you must use the official Oil and Gas Operations Report Form ONRR-4054 (OGOR) to report. Please refer to the Forms page for information about ONRR forms.  

2.4.3 Reporting Standards

Lessees must report the quantity (volume) and quality of production using the units of measurement specified under 30 CFR §1202.101 for oil and §1202.558 for gas. Please see the table below for a summary.

*Wet vs. Dry Reporting on the (OGOR) & Form ONRR-2014

For production periods after February, 2017, the regulations under 43 CFR §3175.126(a)(1), require operators to report heating values on a dry basis on the OGOR.

ONRR’s regulations at 30 CFR §1202.152, Standards for reporting and paying royalties on gas, require you to:

(i) Report gas volumes and British thermal unit (Btu) heating values, if applicable, under the same degree of water saturation;

Therefore, for periods after February 2017, you must report using a dry water vapor content on the Form ONRR-2014 and the OGOR.

For production periods prior to February, 2017, contact your local BLM office for additional information on wet vs. dry reporting.

**Converting to 14.73 psia

The figure below illustrates one way to convert from a different pressure base to 14.73 psia. For our example, we used a standard conversion factor from a publicly-available source. You are not required to use this factor or this method in your calculations.

2.4.4 Adjustments for Quantity and Quality

If the lessee’s sales price or value of production is based on a quantity or quality different from that measured at the point of royalty settlement, the value must be adjusted to compensate for any differences under 30 CFR §§1206.53(a)(2) and 1206.174(a)(2). For instance, if a lessee’s gross proceeds from the sale of gas are based on a volume measured at a point other than the approved point of royalty settlement and that volume is less than the volume measured at the approved point of royalty settlement, then the gross proceeds for royalty purposes must be increased to reflect the higher volume measured at the approved point of royalty settlement.

2.4.5 Actual or Theoretical Losses

Under 30 CFR §§1206.58 and 1206.175, you may not take any deductions from the royalty volume or royalty value for actual or theoretical losses.

Royalty is due on 100 percent of the volume measured at the point of royalty settlement. ONRR published a Dear Reporter Letter explaining reporting of Fuel Used or Lost Along a Pipeline on December 18, 2014. See the December 18, 2014 Reporter Letter for reporting and valuation information.

Lessees are not required to report losses that occur prior to the point of royalty settlement if the BLM determines such losses are unavoidable. Fuel used on or for the benefit of the lease may also be considered beneficial use. Although these volumes are not royalty-bearing, lessees must report them using the currently-adopted ONRR production accounting system.

2.4.6 Quantity Determinations for Processed Gas and Gas Plant Products

When gas is processed for the recovery of residue gas and gas plant products, a portion of the net plant output is allocated to each lease supplying production to the plant. The specific allocation procedure depends on whether the plant processes gas of uniform content or non-uniform content.

When the net plant output is derived from gas produced from a single lease, the quantity and quality of residue gas and gas plant products attributable to the lease are simply the net plant output. However, gas from multiple leases supplying the plant frequently contains diverse amounts of hydrocarbons and/or non-hydrocarbon substances. In these situations, the allocation must be based on the theoretical or tested volume of residue gas and gas plant products contained in the gas at the lease. See Chapter 4, Indian Gas Valuation, for further information.

2.5.1 Lease Language

The specific language in each lease instrument dictates how lessees must report and pay royalties. For example, under the lease language below, the lessee pays a fixed annual amount for gas, per well, regardless of the volume of gas produced.

Under the following lease language, the lessee values royalties based on the amount they receive, less transportation and processing allowances under ONRR’s regulations.

Royalty - To pay a royalty of 20 percent of the value or amount of all oil, gas, and/or natural gasoline, and/or all other hydrocarbon substances produced and saved from the land leased herein, save and except oil, and/or gas used by the lessee for development and operation purposes on said lease, which oil and gas shall be royalty-free. During the period of supervision, "value" for the purposes hereof may, in the discretion of the Secretary[emphasis added], be calculated on the basis of the highest price paid or offered (whether calculated on the basis of short or actual volume) at the time of production for the major portion of the oil of the same gravity, and gas, and/or natural gasoline, and/or all other hydrocarbon substances produced and sold from the field where the leased lands are situated, and the actual volume of the marketable product less the content of foreign substances as determined by the oil and gas supervisor. The actual amount realized by the lessee from the sale of said products, may, in the discretion of the Secretary[emphasis added], be deemed mere evidence of or conclusive evidence of such value. When paid in value, such royalties shall be due and payable monthly on the last day of the calendar month following the calendar month in which produced, when royalty on oil produced is paid in kind, such royalty oil shall be delivered in tanks provided by the lessee on the premises where produced without cost to the lessor unless otherwise agreed to by the parties thereto at such times as may be required by the lessor. Provided, that the lessee shall not be required to hold such royalty oil in storage longer than 30 days after the end of the calendar month in which said oil is produced. And Provided further, That the lessee shall be in no manner responsible or held liable for loss or destruction of such oil in storage caused by acts of God. All rental and royalty payments, except as provided in section 9(a) and 4(c) shall be made by check or draft drawn on a solvent bank, open for the transaction of business on the day check or draft is issued, to the BUREAU OF INDIAN AFFAIRS. It is understood that in determining the value for royalty purposes of products, such as natural gasoline, that are derived from treatment of gas, a reasonable allowance for the cost or manufacture shall be made, such allowance to be two-thirds of the value of the marketable product unless otherwise determined by the Secretary of the Interior[emphasis added] on application of the lessee or on his own initiative, and that royalty will be computed on the value of gas or casinghead gas, or on the products thereof (such as residue gas, natural gasoline, propane, butane, etc.), whichever is greater.

Those concepts are: secretarial discretion, accounting for comparison or dual accounting, and major portion. This chapter will introduce each concept and specific examples will be provided in Chapter 3 - Oil Valuation, and Chapter 4 - Gas Valuation.

2.5.2 Secretarial Discretion Language

If a lease instrument contains language giving the Secretary of the Interior discretion to determine value, lessees must value the royalty share of production from that lease under ONRR’s regulations under 30 CFR 1202 and 30 CFR 1206.

2.5.3 Major Portion

Many Indian leases contain a “major portion provision,” indicating that the lessee must use a value representative of the highest price paid for the majority of production in a field or area for the royalty share, whether the lessee received that price or not. The following lease language with emphasis added is an example of a major portion provision:

“During the period of supervision, "value" for the purposes hereof may, in the discretion of the Secretary, be calculated on the basis of the highest price paid or offered (whether calculated on the basis of short or actual volume) at the time of production for the major portion of the oil of the same gravity, and gas, and/or natural gasoline, and/or all other hydrocarbon substances produced and sold from the field where the leased lands are situated, and the actual volume of the marketable product less the content of foreign substances as determined by the oil and gas supervisor.”

ONRR defines Major Portion for oil under 30 CFR §1206.51 as follows:

Major Portion Price means the highest price paid or offered at the time of production for the major portion of oil produced from the same designated area for the same crude oil type.

There are differences between major portion prices under ONRR’s Indian Oil and Indian Gas regulations. This handbook will address Indian oil and Indian gas major portion in detail and provide specific examples in Chapter 3 - Oil Valuation and Chapter 4 - Gas Valuation.

2.5.4 Dual Accounting/Accounting for Comparison

Many Indian leases require accounting for comparison, or “dual accounting.” The following lease language, with emphasis, requires accounting for comparison:

“… and that royalty will be computed on the value of gas or casinghead gas, or on the products thereof (such as residue gas, natural gasoline, propane, butane, etc.), whichever is the greater.”

Dual accounting may not be the only requirement of your lease. Section 2.5.5 addresses other elements of your lease provisions including Index Zone Pricing, Arm’s-Length Dedicated Contracts, and Safety Net. Please read the complete details of your lease to be sure you meet all the provisions in it.

2.5.5 Indian Gas Valuation Basics

The best way to ensure that you are reporting and paying royalties correctly on Indian gas production is to begin with your lease terms. If your lease terms do not contain language giving the Secretary of the Interior discretion to determine value or reference the valuation regulations at 1206, then the value for royalty purposes is calculated using the specific language within your lease.

If your lease terms do contain language giving the Secretary of the Interior discretion to determine value or reference the valuation regulations at 1206, then you will use ONRR’s regulations to determine whether your lease is subject to index-zone or non-index-zone valuation.

2.5.5.1 Index-Zone Valuation

The regulations under 30 CFR §1206.171, governing Indian gas valuation, define an index zone as follows:

Index zone means a field or an area with an active spot market and published indices applicable to that field or area that are acceptable to ONRR under 30 CFR §1206.172(d)(2).

The regulations define index-pricing points as “any point on a pipeline for which there is an index.”

You must value your Indian gas production using the index-zone method under 30 CFR §1206.172 if your lease is located in an index zone and your lease either has a major portion provision, or provides for the Secretary of the Interior to determine the value of production, whether or not you received the index price. Index-zone values only apply to the hydrocarbon components of your gas stream.

ONRR published a list of tribes and counties in each index zone in the Federal Register. See 64 FR 66771 – November 30, 1999

ONRR also published a list of index price points used in each index-zone price calculation. See 76 FR 37828 – June 28, 2011.

The map to the right shows the locations of Indian gas index zones. The following table delineates which Designated Areas are in Index and Non-Index Zones.

2.5.5.2 Arm's-Length Dedicated Contracts

The first safeguard built into index-zone valuation is the provision addressing arm’s-length dedicated contracts. ONRR’s regulations under 30 CFR §1206.171 define dedicated as:

Dedicated means a contractual commitment to deliver gas production (or a specified portion of production) from a lease or well when that production is specified in a sales contract and that production must be sold pursuant to that contract to the extent that production occurs from that lease or well.

Dedicated gas sales occur before the index-pricing point. If you sell your production under an arm’s-length dedicated contract, you must:

1. Determine your gross proceeds under 30 CFR §1206.174(b)
2. Compare the gross proceeds value to the index-based value (including dual accounting)
3. Pay royalties on the higher of the above two values

2.5.5.3 Safety Net Calculation

The second safeguard built into index-zone valuation regulations is the provision under 30 CFR §1206.172(e) addressing safety net calculations.

The safety net calculation is used to capture potential additional royalty value when the first arm’s-length sale by a lessee or a lessee’s affiliate takes place downstream of the first index pricing point (generally outside of the index zone).

The safety net price is:

• a volume-weighted average contract price per delivered MMBtu
• based only on arm’s-length sales beyond the first index-pricing point
• for production from leases in the same index zone
• not reduced by the lessee’s transportation costs
• not reduced by costs associated with placing production into marketable condition or to market the gas.

Under 30 CFR §1206.172 (e) (4) (i), lessees must also determine the safety net differential (SND) for each month for each index zone.

The following is the formula for calculating the SND:

SND = [(0.80 x S) - (1.25 x I)]

Where: S = safety-net price and I = index-zone price

Additional royalties are due if the safety net differential is positive.

By June 30 following each calendar year, lessees must calculate, for each month of the calendar year, a safety net price and safety net differential. Then, lessees must submit the results to ONRR using Form ONRR-4411.

This handbook will address both dedicated contracts and safety net calculations in detail and provide specific examples in Chapter 4 - Gas Valuation.

2.5.5.4 Non-Index-Zone Valuation (Major Portion)

ONRR designated twelve areas that are not subject to index-zone valuation. These non-index-based pricing areas are reflected in the following map*

Value Indian gas produced from non-index-zone designated areas under 30 CFR §1206.174. Lessees must initially report the current month’s value using the regulations under 30 CFR §1206.174(b) or (c), depending on whether the transaction is arm’s length or non-arm’s length.  

ONRR calculates the major portion price approximately eighteen months after the lessee’s initial reporting. If your sales price was less than the ONRR calculated major portion price, you must submit adjustments valuing your gas at the major portion price. If your sales price was higher than the ONRR calculated major portion price, do not adjust your reporting.  

  ONRR notifies lessees of the major portion values and due dates in the Federal Register, as well as through ONRR’s electronic messaging system. In addition, ONRR’s Marketing and Spatial Analysis group publishes major portion values.  

2.5.6 Indian Oil Valuation Basics

The new Indian Oil regulations took effect July 1, 2015. Information for Indian Oil is divided into production after July 1, 2015 and production before July 1, 2015.

2.5.6.1 Production After July 1, 2015

On May 1, 2015, based on consensus from the Indian Oil Negotiated Rulemaking Committee, ONRR amended the regulations governing the valuation of oil produced from Indian leases (80 FR 24779 (May 1, 2015)), effective for production beginning July 1, 2015. ONRR also published new reporting requirements for Indian oil valuation.

ONRR published two Dear Reporter Letters in 2015 that detail the new valuation rule:

1. May 15, 2015 (covering the new rule) and
2. August 21, 2015 (clarification of inadvertently described land descriptions as they pertain to the North Fort Berthold and South Fort Berthold Designated Areas).

For each of the sixteen designated areas, the value of oil for royalty purposes is the higher of the two options identified below:

• Your price based on gross proceeds (less any applicable transportation)

-OR-

• The Index-Based Major Portion (IBMP) price

The IBMP price is calculated by using the New York Mercantile Exchange (NYMEX) Calendar Month Average (CMA) and adjusting this value for a designated area-specific Location and Crude Type Differential (LCTD).

2.5.6.2 Production Before July 1, 2015

Report your actual gross proceeds and allowable transportation costs separately. Use the sales type code (ARMS or NARM) based on your sales contract. Use product code 01 for all crude types. ONRR will send out orders with instructions to amend reporting if the major portion price is above your reported gross proceeds less applicable transportation.

2.5.7 The ONRR Royalty Equation

For valuation purposes, royalty is due on the volume of production, multiplied by the unit value of production, multiplied by the royalty rate. Allowances are reported separately except under specific circumstances.

2.5.8 Arm's-Length Contracts

ONRR’s regulations define arm’s-length contracts under 30 CFR §1206.51 for Indian oil and §1206.171 for Indian gas. Arm’s-length contracts are contracts or agreements that were arrived at in the marketplace between independent, non-affiliated persons with opposing economic interests regarding those contracts.

The lessee has the burden to prove that a contract is arm’s length. The lessee must show that the contract was negotiated at arm’s length and that the parties operating under the contract have an arm’s-length relationship during the month of production. That is, even if a contract was negotiated at arm’s length, if, during the production month, the parties to the contract don’t have an arm’s-length relationship, the contract is not considered arm’s length. Further, if the parties to a contract are related by blood or marriage, the contract is automatically considered non-arm’s length.

When determining whether a contract is arm’s length, you should first look at ownership and control between the parties to the contract. If there is more than 50% ownership or operational control (shown in this bar graph in blue) between the parties, the presumption is that a non-arm’s-length transaction has taken place. If there is less than 10% ownership or operational control, the presumption is that an arm’s-length transaction has occurred. If the degree of ownership or operational control falls between 10% and 50%, additional factors need to be considered to establish whether the transaction is arm’s length or non-arm’s length. These additional considerations include:

• Common officers between entities, or members of the Board of Directors
• Percentage ownership and voting securities
• The owners’ participation in day-to-day operations

ONRR may also consider other factors to determine whether a contract is arm’s length or non-arm’s length, including evaluating the process of negotiating the contract (e.g., were the negotiations difficult or complex?); examining specific contract terms (e.g., does the contract evidence fair market practices?); and considering whether the contract includes any type of index pricing as a basis for value.

2.5.9 Gross Proceeds

Under no circumstances can value be less than the gross proceeds received by a lessee under its contract, whether that contract is arm’s length or non-arm’s length. The criteria can be found under 30 CFR §1206.52 (a) for Indian oil. The gross proceeds on which a valuation determination is made include all consideration passing between the buyer and seller for production from Indian leases, whether that consideration is in the form of money or any other form of value.

For example, if a small scale, “hobby” oil and gas operator produces a nominal amount of oil from its leasehold and sells it to a neighbor at arm’s length for a negotiated price of $50, two tickets to a theater play, and a bushel of peaches that the neighbor grew on his organic farm, the gross proceeds for that transaction (“total monies and other consideration”) would be:

• $50, plus
• The value of the theater tickets, plus
• The market value of the bushel of peaches

Gross proceeds include reimbursements paid to the lessee for severance and ad valorem taxes as well as any payments to the lessee for certain services, such as placing the lease production into marketable condition, to the extent that the lessee is obligated to perform such services at no cost to the Indian lessor. (See “Marketable condition” in section 2.5.4 for more information.). Also, reimbursements received by lessees from purchasers for certain production-related costs are part of the lessee’s gross proceeds.

Gross proceeds also include all prices or benefits to which a lessee is legally entitled under the terms of the contract, even if the lessee fails to take proper or timely action to secure such benefits.

2.5.10 Values Based on Contracts and Agreements

The value of production for royalty purposes must be based on the highest price the lessee can receive through legally enforceable claims under its contract under 30 CFR §1206.52(f). If the lessee fails to take proper or timely action to receive prices or benefits that are authorized by the contract, the lessee must pay royalty at a value based on the obtainable price or benefit, unless the contract has been revised or amended. Revisions or amendments to contracts must be in writing and signed by all parties to that contract.

Contract disputes. If a purchaser unilaterally reduces contract prices and the lessee takes documented, timely action to force compliance, the lessee may compute royalties on the actual price received until the dispute is resolved. An example of unilateral price reduction would be when a purchaser imposes a market-out price under a contract that does not contain any market-sensitive price provisions.

Likewise, if the lessee makes documented, timely application for a price increase or benefit entitled by the contract but the purchaser refuses, and the lessee takes reasonable measures to force compliance, the lessee does not owe additional royalties unless or until monies or consideration resulting from a price increase or benefit are received under 30 CFR §1206.52(f).

When a dispute is settled, royalty is owed on any additional amount the lessee receives and is due by the end of the month following the month the additional amount is collected.

All actions taken by the lessee to enforce compliance must be documented. However, any action taken by the lessee to enforce compliance must be taken as soon as the lessee knows or should reasonably know that compliance measures should be employed to comply with these regulations.

Late purchaser payments. If a purchaser fails to pay whether in whole, in part, or timely for a quantity of production removed from the lease or unitized or communitized area, the lessee’s obligation to pay royalties on the volume removed at the time of removal is not suspended. For example, if a purchaser removes production from a lease and payment is not received by the time the lessee must report and pay royalties, the lessee must still report the volume removed from the lease and pay royalties on that volume. In those cases where the lessee is not paid by the purchaser, royalties are determined based on the price established by the contract for arm’s-length sales or on a value determined under the benchmark system for non-arm’s-length sales.

2.5.11 Like-Quality Production

When Indian production is not sold under an arm’s-length contract (that is, production is disposed of under non-arm’s-length or no sales conditions), value of that production is based, in part, on the value of like-quality production sold under arm’s-length contracts in the same field or area where the leased lands are situated. Like-quality production (or lease products) is defined under 30 CFR §§1206.51 and 1206.171 as production or products having similar chemical, physical, and legal characteristics.

For valuation purposes, like-quality oil is oil that has similar American Petroleum Institute (API) gravity, sulfur content, paraffin (wax) content, heavy metals components, pour point, and other characteristics. Like-quality gas is gas that has similar methane, NGL, and non-hydrocarbon gas content (sulfur dioxide, helium, nitrogen, carbon dioxide, etc.). Generally, like-quality production will be other production from the same field or area. However, only production that is similar in quality will be used to determine value.

2.8.1 The Components of Marketable Condition

Marketable condition typically includes the following four components:

1. Compression: encompasses the process of raising the pressure of gas. This process is defined within ONRR’s regulations under 30 CFR §1206.171 (Indian gas).
2. Gathering: includes the movement of lease production to a central accumulation and/or treatment point (often referred to as the central accumulation point, or CAP). This location can be sited either on or off the lease, unit, or communitized area as approved by the BLM. It is important to keep in mind that ONRR’s definition of gathering 30 CFR §1206.171 (Indian gas) is more limited in scope and application than the definition used by most of the oil and gas industry. Further, transportation does not start until after the central accumulation point as designated by the BLM.
3. Dehydration: involves the removal of unwanted water or water vapor from the product stream. There is no regulatory definition for dehydration, but this specification is often a component part of a contract or purchasing agreement between the lessee and a third party.
4. Sweetening or Treatment: incorporates the processes necessary to remove or reduce “acid gases” such as hydrogen sulfide (H2S) and carbon dioxide (CO2) from the production stream. Although these components are often deemed waste products, that is not always the case. As with dehydration, there is no regulatory definition for sweetening, but this specification is generally a condition of a contract or purchasing agreement between the lessee and a third party.

A series of quality specifications required by the mainline pipeline that transports the product to any of the various markets across the country establish marketable condition. For example, mainline pipeline(s) have an established maximum quantity of acid gases, water vapor, or other objectionable matter, and a pressure requirement for gas to enter the pipeline. It is these specifications that deem what is and is not marketable condition along the subject pipeline. Keep in mind that each marketable condition requirement is independent of the others. For example, gas may be in marketable condition with regard to pressure, but not for water content or sweetening.

The following diagram shows some of the equipment used to meet some of the marketable condition requirements. The top row shows those processes that ONRR may allow as deductions; the bottom row shows those activities that are never allowed as deductions under ONRR regulations:

2.8.2 Gas in Marketable Condition at the Wellhead

In rare instances, gas at the wellhead meets marketable condition requirements without the need for additional gathering, sweetening, dehydration, or compression. However, if a lessee claims that its product is in marketable condition based on the wellhead specifications (or any specification other than a high-pressure pipeline), the lessee has the burden to show that there is a real and active market for the production in that condition.

Further, the fact that the gas can be sold untreated at the wellhead does not mean that it is in marketable condition at the wellhead.

2.8.3 Gas Sold to Multiple Markets

It is not uncommon to have multiple markets for gas within a particular field or area. These separate and distinct markets may call for differing degrees of conditioning (compression, dehydration, and sweetening) in order to satisfy pipeline specifications and requirements for each unique market. In these situations, gas must be placed into the marketable condition that is required for the market that it actually serves, even if other markets in the same location have less stringent requirements.

As an example, let us review the following image that has one gas well (identified by the sunburst to the left) with production being sent along the system to two separate gas plants and three separate mainline pipelines that have varying pressure requirements (from 600 psi at the tailgate of Gas Plant B, to 800 and 1,000 psi at the two mainlines at the tailgate of Plant A):

If the lessee of this well sells all of its production into each of the three markets, the lessee would be obligated to abide by the pressure requirements of each of the three pipeline pressure specifications: some production would have to enter the pipeline to Market 1 at 800 psi, some production would have to enter the pipeline to Market 2 at 1,000 psi, and some production would have to enter the pipeline to Market 3 at 600 psi. In particular, even though production is being processed from the same gas plant, the lessee must allocate costs based on the volume of gas sent to each pipeline. The lessee must determine marketable condition for each of these three markets.

The lessee is also obligated to market the production to the mutual benefit of the lessor and the lessee, whether the lessee uses its own employees to perform marketing services or pays another company to provide such services. If the purchaser incurs costs to market the production, the lessee cannot reduce the sales price to compensate the purchaser for those marketing costs. Neither can the lessee pay another entity for marketing services and deduct the costs of those services from the royalty value.

2.8.4 Allowable Costs

Placing production in marketable condition includes the physical handling and treatment of production such as gathering, measuring, separating, compressing, sweetening, and dehydrating. If the lease’s gross proceeds are reduced by any costs associated with handling or treating production, the gross proceeds must be increased by the amount of such deductions. However, certain costs may be permitted as either a transportation or processing allowance. Lessees must follow the procedures explained in the allowance chapters of this handbook.

A lessee is also not required to place production into marketable condition more than once at the lessee’s expense, or to condition its production beyond specifications at the lessee’s expense. ONRR will allow for transportation costs only if such handling exceeds those services necessary to place production into marketable condition required under 30 CFR §1206.55 for Indian oil.

3.1.1 Comparing Gross Proceeds and IBMP Prices

In order to calculate your gross proceeds, you first need to determine whether or not you are selling your oil under an arm’s-length or non-arm’s-length contract. If you sell your oil under an arm's-length contract, under 30 CFR §1206.52, the value of your Indian oil is the gross proceeds accruing to you under that arm's­-length contract, less allowable transportation costs. If you sell your oil under a non-arm's-length contract, under 30 CFR §1206.53, the value of your oil is the volume-weighted average of the gross proceeds paid or received by you or your affiliate, including your refining affiliate, for purchases or sales under arm's-length contracts, less applicable allowances.

Once you calculate your gross proceeds under the regulations above, you will compare those values with the IBMP price for the same crude type and designated area that ONRR published on its website for the same production month.

If your per barrel gross proceeds price, net of allowable transportation, is higher than the IBMP price, report and pay royalties on your gross proceeds. If the IBMP price is higher than your per barrel gross proceeds price, report and pay royalties on the IBMP price, even if you did not (or could not) sell oil for that price.

For example, assume that your gross proceeds calculations, net of allowable transportation, resulted in a value of $85 per barrel for July, 2015. For the July, 2015 production month, the ONRR-published IBMP price for your crude type and designated area was $83 per barrel. Because the IBMP price was lower than your calculated gross proceeds, you would report and pay royalties on $85 per barrel. In this case, you should report allowable transportation costs that you incur separately as a transportation allowance. The table below summarizes the information.

Alternatively, assume that your gross proceeds, net of allowable transportation, resulted in a value of $81 per barrel for July 2015. For the July 2015 production month, the ONRR-published IBMP price for your crude type and designated area was $83 per barrel. Because the IBMP price, net of transportation, was higher than your calculated gross proceeds, you would report and pay royalties on $83 per barrel. The table below summarizes the information.

3.1.1.1 Designated Areas

The price you use to value your oil produced from Indian lands depends on the top hole location of your well, i.e. where your production surfaced. Generally, designated areas are identified by reservation boundaries, including any off-reservation allotments or dependent Indian communities, where location and crude types are similar to each other.

There are 16 designated areas ONRR identifies as unique in the table below. If you have questions concerning which designated area your lease is in, please contact royaltyvaluation@onrr.gov.  

3.1.1.2 Crude Type

To accurately calculate the IBMP price, ONRR must use like quality oil. ONRR relies on lessees to report the type of oil produced from their Indian leases. The crude type is based on, among other things, API gravity and sulfur content. There are six crude types, each with a unique product code, captured in the table below.

3.1.2 Sales Type Codes

If your gross proceeds, less allowable transportation, are higher than the IBMP price, select either the ARMS or NARM sales type code based on your transaction.

If the IBMP price is higher than your gross proceeds, less allowable transportation, use OINX as your sales type code.

3.2.1 Example

Product Code

The product code is based on the type of oil being sold. In this example, we know that the crude is a light, sweet crude. Based on our list of product codes, we should use PC 61.

Sales Volume

In this example, we noted that the lessee is selling 1,000 bbls, which was what was measured for royalty. So, our sales volume is 1,000 bbls.

Sales Value

The sales value is the higher of 1) the lessee’s gross proceeds less transportation, or 2) the value using the IBMP price.

• Gross Proceeds = Sales Volume x Arm’s-Length Sales Price – Transportation Costs
• Gross Proceeds = (1,000 Bbls x $42.50) – (1,000 x $5)
  
• Gross Proceeds = $37,500
  
• IBMP Value = Sales Volume x IBMP Price
  
• IBMP Value = 1,000 Bbls x $43.56
  
• NOTE: The $43.56 price is pulled from the onrr.gov website, based on the location and type of crude
• IBMP Value = $43,560
  

In this case, the IBMP value is higher, so the lessee must pay royalty on the IBMP value.

Sales Type Code

Because the sales value reported and paid by the lessee is based on the IBMP price, the lessee should use sales type code OINX.

Royalty Value Prior to Allowances (RVPA)

• RVPA = Sales Value x Royalty Rate
• RVPA = $43,560 x 16 2/3 %
  
• RVPA = $7,257 
  

Transportation Allowance

In this example, the lessee is paying using the IBMP price. The IBMP price is already adjusted for transportation costs, so the lessee should not take a transportation allowance.

Form ONRR-2014 Royalty Report

3.2.2 Example

Assuming the same set of pricing facts in Example 3.2.1:

Product Code

The product code is based on the type of oil being sold. In this example, we know that the crude is a black wax. Based on our list of product codes, we should use PC 64.

Sales Volume

In this example, we noted that the lessee is selling 1,000 bbls, which was what was measured for royalty. So, our sales volume is 1,000 bbls.

Sales Value

The sales value is the higher of 1) the lessee’s gross proceeds less transportation, or 2) the value using the IBMP price.

• Gross Proceeds = Sales Volume x Arm’s-Length Sales Price – Transportation Costs
• Gross Proceeds = (1,000 Bbls x $46.00) – (1,000 x $5)
  
• Gross Proceeds = $41,000
  
• IBMP Value = Sales Volume x IBMP Price
  
• IBMP Value = 1,000 Bbls x $40.27
  
• NOTE: The $40.27 price is pulled from the onrr.gov website, based on the location and type of crude
• IBMP Value = $40,270
  

In this case, the gross proceeds value is higher, so the lessee must pay royalty on the gross proceeds value.

Sales Type Code

Because the sales value reported and paid by the lessee is based on the IBMP price, the lessee should use sales type code ARMS.

Royalty Value with Allowances (RVA)

• RVA = Sales Value x Royalty Rate – (Transportation Allowance x Royalty Rate)
• RVA = $46,000 x 16 2/3% - ($5,000 x 16 2/3%)
  
• RVA = $7,664 - $833
  
• RVA = $6,831
  

Transportation Allowance

In this example, the lessee is paying using the gross proceeds, so transportation is allowed.

• TA = 1000 bbl x $5/bbl x 16 2/3%
• TA = $5000 x 16 2/3%
  
• TA = $833
  

Form ONRR-2014 Royalty Report

3.2.3 Example

Assume that a lessee produces 50,000 bbls of oil, which it then refines at a refinery it owns. The lessee also purchases like-quality oil from other producers in the same field at arm's length for use as feedstock in its refinery. The oil produced from the lease that is being valued under this section is Wyoming general sour with an API gravity of 23.5°. In this example, assume that the refinery purchases at arm's-length oil (all of which must be Wyoming general sour) in the following volumes of the API gravities stated at the prices and locations indicated:

Product Code

The product code is based on the type of oil being sold. The Product Code for Sour Crude is 62.

Sales Volume

The refiner will pay on all 50,000 barrels produced from its leases.

Sales Value

Because the lessee does not know the costs that the seller of the 8,000 bbl incurred to transport that volume to the refinery, that volume will not be included in the volume-weighted average price calculation. Further assume that the gravity adjustment scale provides for a deduction of $0.02 per 1⁄10 degree API gravity below 34°. Normalized to 23.5° (the gravity of the oil being valued in this example), the prices of each of the volumes that the refiner purchased that are included in the volume-weighted average calculation are as follows:

  The volume-weighted average price is:

(10,000 bbl × $34.50/bbl) + (9,000 bbl × $33.35/bbl) + (4,000 bbl × $33.30/bbl)) / 23,000 bbl = $33.84/bbl.  

That price will be the value of the 50,000 bbls of oil produced from the lease and refined prior to an arm's-length sale under this section.

Sales Type Code

Because this is a non-arm’s-length transaction, the sales type code will be NARM.

Royalty Value (RV)

• RV = Sales Value x Royalty Rate
• RV = 50,000 x $33.84 x 16 2/3%
  
• RV = $1,692,000 x 16 2/3%
  
• RV = $281,887.20
  

Transportation Allowance

When the value of your oil is based on the volume-weighted average of your arm's-length sales and/or purchases, the transportation allowance is determined under 30 CFR 1206.53(c): If you value oil under this section, ONRR will allow a deduction, under §§1206.56 and 1206.57 or §1206.58, for the reasonable, actual costs:

1. That you incur to transport oil that you or your affiliate sell(s), which is included in the volume-weighted average price calculation, from the lease to the point where the oil is sold.
2. That the seller incurs to transport oil that you or your affiliate purchase(s), which is included in the volume-weighted average cost calculation, from the property where it is produced to the point where you or your affiliate purchase(s) it. You may not deduct any costs of gathering as part of a transportation deduction or allowance.

Form ONRR-2014 Royalty Report