JurisdictionUnited States
Natural Gas Marketing
(May 1987)


Judith M. Matlock
Whittington & Matlock, P.C.
Denver, Colorado








A. Exchange of Natural Gas and Plant Services

B. Additional Economic Factors

1. Shrinkage and Plant Fuel Costs
2. Other Charges to Producers
3. Capacity of the Plant
4. Start-up Expenses
5. Outside Risks

C. Calculations and Allocations


A. Converting Data to Standard Bases and Common Units

B. Basic Calculations

1. Total Production—Gallons of Liquids Produced
2. Sales of Liquids
3. Residue Gas Deliveries
4. Shrinkage
a. Calculating the MMBTU Content of Products Produced
b. Calculating Shrinkage on the Basis of Inlet and Outlet Meters
5. Fuel

C. Allocations Between Multiple Inlet Sources, Single Residue Purchaser

1. Allocating Total Production
2. Allocating Total Sales
3. Allocating Residue Gas Deliveries
4. Allocating Shrinkage
5. Allocating Fuel
a. Plant Fuel
b. Inlet Compression Fuel
c. Residue Compression Fuel
d. Allocating Purchased Fuel

D. Additional Allocation Complexities

1. Outside Fractionation
2. Multiple Residue Gas Purchasers
3. Sweet and Sour Gas Processing

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4. Multiple Streams Behind the Plant Inlet (joint venture processing)

E. Balancing Over and Under Deliveries

F. Calculating Plant Compensation

G. Drafting the Accounting Procedure

1. Drafting metering, measuring and sampling/analysis provisions
2. Drafting calculation/allocation provisions


A. Payment Provision

B. Settlement Reports





A Gas Processing Agreement

B Accounting Procedure

C Schematic Diagram



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This paper is a supplement to the paper presented by Mr. Watson regarding fundamentals of gas marketing contracts. Natural gas processing agreements contain many provisions in common with other gas marketing contracts and those provisions will generally not be discussed in this paper. However, the negotiation of natural gas processing agreements and the calculations and allocations required by such agreements distinguish natural gas processing agreements from other types of gas marketing contracts. This paper will discuss these unique aspects of natural gas processing agreements in detail.

For purposes of this paper, the term "natural gas" is used to mean "hydrocarbons which at atmospheric conditions of temperature and pressure are in a gaseous phase."1 Additionally, for purposes of this paper, the phrase "natural gas processing agreements" includes all agreements which involve the processing of natural gas for the removal of liquid hydrocarbon products contained therein.2

This paper does not attempt to discuss every possible natural gas processing arrangement. Rather, it is intended to give the reader a basic understanding of the considerations which should go into negotiating a natural gas processing agreement, and the ability to analyze or draft such an agreement regardless of the particular arrangement which the parties eventually negotiate. It is hoped that the examples,

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checklists and sample contract provisions included in this paper will be useful in achieving this goal. However, this paper is not intended to be a training manual for the gas accountant.3

This paper has been prepared primarily from a comparison of natural gas processing agreements currently in use by several natural gas processing plants or found in published sources. Throughout this paper the supplier of the inlet gas stream to the plant is referred to as the "Producer" and the owner or operator of the Plant is referred to as the "Processor." However, purchasers of natural gas at the wellhead or elsewhere upstream of a natural gas processing plant may also be the suppliers of the inlet gas stream to the plant. Such purchasers may process the natural gas where the producers do not reserve the right to remove liquids or where the producers, although having reserved such a right, have not exercised it. In the latter situation, the

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purchaser and the Processor may enter into a natural gas processing agreement and take the risk that the producers will later decide to construct their own natural gas processing plant or make arrangements to have their gas processed in a third-party facility.

Before discussing the negotiating and drafting of natural gas processing agreements, Section I below provides a brief overview of natural gas processing and certain definitions necessary to an understanding of the provisions to be discussed elsewhere in this paper. Many of the readers will, of course, already be familiar with this background information.


Natural gas is a mixture consisting essentially of the following hydrocarbons of the paraffin series:

Hydrocarbon Symbol
methane C1
ethane C2
propane C3
iso-butane i-C4
normal butane C4
isopentane i-C5
normal pentane C5
hexane C6
heptane C7
octane C8
nonane C9
decane C10

Methane is the largest constituent of natural gas followed by ethane, propane and the other hydrocarbons listed above. Natural gas processing is primarily concerned with the lighter hydrocarbons (methane through hexane). The heavier hydrocarbons are often referred to as "heptanes-plus" or "C7+".

Natural gas processing recovers marketable hydrocarbon products ("liquids" or "products") from natural gas. The products are removed as a bulk product known as propane-plus (C3+). In some instances, natural gas processing will also

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treat the natural gas to remove water (a process known as "dehydration") and impurities such as carbon dioxide (CO2) and hydrogen sulfide (H2S). (Natural gas containing an excess of hydrogen sulfide is known as "sour gas" as opposed to "sweet gas.") What remains of the inlet gas stream after the propane-plus bulk product has been removed is a marketable natural gas, containing primarily methane, which is known as "residue gas" and is used commercially and domestically as fuel. Residue gas may also be used for lease operations.

The extracted propane-plus bulk product is marketable. However, some natural gas processing plants also have the ability to reduce the propane-plus product into separate products such as propane, butane and natural gasoline through a separation process called fractionation. Some processing plants also remove ethane as a separate product. These separated products can be marketed more profitably than the propane-plus bulk product.

The amount of product recovered from any natural gas stream is dependent on a number of factors: (1) the volume of gas coming into the plant, expressed in terms of cubic feet (cf), 1000 cubic feet (Mcf) or 1,000,000 cubic feet (MMCF), (2) the concentration of recoverable liquid hydrocarbon products in the natural gas stream, expressed in terms of gallons per Mcf (GPM),4 and (3) the technical efficiency of the processing equipment at the plant which determines the percentage of the recoverable liquid hydrocarbon products actually removed, also expressed in terms of gallons per Mcf (GPM).

Natural gas processing decreases both the volume and gross heating value (measured in British Thermal units or BTUs) of the inlet gas stream due to removal of the products. This decrease is known as "shrinkage." Additionally, the residue gas in some cases is used as fuel for operation of the gas processing plant (including, in some cases, inlet or outlet compressors) leading to a distinction between "residue gas" and "residue gas available for sale." Depending on the terms of a particular natural gas processing agreement, the gas processing plant may be required to pay for or replace such shrinkage and fuel.

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Natural gas processing plants may generate revenues from the sale of products (if the plant obtains title to some or all or the products) and residue gas (again if the plant obtains title to some or all of the residue gas). Gas processing plants may also generate revenues through gathering fees, compression fees, processing fees and fractionation fees. The cost of purchased inlet gas, shrinkage and fuel costs, if any, and plant operating costs must be subtracted from gross revenues to arrive at the net revenues generated by a natural gas processing plant.


The earliest form of natural gas processing agreement was the 1932 Natural Gasoline Association of America Casinghead Gas Contract.5 The contract involved only the processing of casinghead gas. The primary product to be produced was natural gasoline although other products were permitted to be produced. The casinghead gas was sold by the Producer to the Processor upstream of the plant. The sales price for the gas was a price per Mcf which varied with the gasoline content of the gas and the average price per gallon received by the Processor for sales of natural gasoline extracted from the gas. The gasoline content of the gas was determined by multiplying the Producer's inlet volume times the gallons per Mcf of gasoline in the casinghead gas, determined by a field compression test. No further payments for the casinghead gas were required regardless of the actual gallons of gasoline (and perhaps other products) produced even though actual gallons produced might be as much as twice the number of gallons predicted to be producible by the field compression test.6

Under the 1932 form contract, the Processor was permitted to use residue gas for plant operations and was required to return the balance of the residue gas attributable to each inlet stream to that stream's Producer for...

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