CHAPTER 11 ROYALTIES ON PROCESSED GAS

• Jurisdiction: United States

PRIVATE OIL & GAS ROYALTIES
(Sept 2003)
CHAPTER 11
ROYALTIES ON PROCESSED GAS
By Thomas C. Jepperson, Division Counsel
Questar Market Resources, Inc.
Salt Lake City, Utah
SYNOPSIS

INTRODUCTION

I. TECHNICAL ASPECTS OF GAS PROCESSING

A. Natural Gas Constituents and Gas Classification

B. "Processing" versus "Treating"

C. Historical Overview of Gas Processing Technology

1. Casinghead Gas Era,

2. The Natural Gasoline Era,

3. The LP Gas Era,

4. The Ethane Era, 1960 and Beyond

II. THE MARKETING REALITIES OF GAS PROCESSING

A. Common Types of Gas Plant Systems

1. Traditional Plant System

2. Interstate Pipeline "Spindown" System

3. Intrastate Pipeline System

B. Gas Plant Economics

C. Common Types of Gas Purchasing/Processing Transactions

1. Percent-of-Proceeds

2. Percent-of-Index

3. Keep-whole Processing

4. Fixed Fee Processing

D. Gas Plant Accounting and Allocations

III. RIGHT TO "USE" GAS: EXPRESS ROYALTY CLAUSE GUIDANCE

A. Early Case Law: The Discovery of a Valuable Product--"Casinghead Gas"

B. Modern Lease Form Revisions for Gas Royalty

IV. ENTITLEMENT TO ROYALTIES ON NATURAL GAS LIQUIDS

A. Duty to Process Gas?

B. Duty to Market Refined Products?

C. Lease Symmetry of Volume and Value

V. DETERMINING LEASE VALUE FOR PROCESSED GAS

———————

[Page 11-ii]

SYNOPSIS

A. Working Forward: Value Based on Comparable Sales

1. The Phillips Panhandle Cases

2. From Craig v. Champlin to Carter v. Exxon

B. Working Backward: Value Based on "Proceeds Less Expenses"

1. Remedy of "Last Resort"

2. Special Work-back Issues

VI. IMPLIED COVENANT IMPLICATIONS FOR PROCESSED GAS

CONCLUSION

———————

[Page 11-1]

INTRODUCTION

The gas processing plant is part of what the oil and gas industry now generally refers to as mid-stream services. At the gas plant, the gas is "processed" to extract or "manufacture" the heavier hydrocarbon molecules such as ethane, propane, butane and natural gasoline into liquid products. Processed gas, however, has resulted in the emergence of various issues regarding the appropriate payment of royalties to the lessor. The royalty implications of processed gas from the perspective of the lessor and the lessee require an examination of the oil and gas lease terms as well as the gas producing, marketing and processing functions.

In today's petroleum industry, the business of gas processing holds a pivotal position between the exploration and production segment and the downstream segment dependent on its refined products such as the interstate pipeline, fuel distribution businesses and the petrochemical industry.¹ The gas processing business is a primary market for wellhead natural gas which is produced and delivered to the gas processor as a valuable feedstock.² In addition, the gas processing business was a moving factor behind the current structure of the modern oil and gas lease. It is well known that in the early days of the petroleum industry, natural gas was considered a waste by-product of oil production, used only on a limited basis as lease fuel. Due to the advent and advances of processing technology, casinghead gas became, and now most wellhead gas is, a valuable feedstock for the gas processing industry.

Prior to delving into the lessons learned from the case law concerning processed gas and their application to current royalty problems, it may be helpful to briefly review gas processing technology and some of the marketing realities of the processing industry.³

[Page 11-2]

I. TECHNICAL ASPECTS OF GAS PROCESSING

A. Natural Gas Constituents and Gas Classification

A typical stream of sweet raw natural gas that has been separated from oil and water consists of a larger group of hydrocarbon constituents and smaller group of non-hydrocarbon substances. The hydrocarbon constituents are sometimes referred to by their molecular structure such as C₁ for methane (the major constituent) having one carbon atom, C₂ for ethane having two carbon atoms and so on -- the heavier the hydrocarbon molecule, the higher its "C" number. The C₂+ series of gases processed for liquids can be divided into a couple of groups: (i) liquefied petroleum gases (LP Gases) which include ethane, propane, iso-butane, normal butane, and (ii) natural gasoline gases including iso-pentane (C5) and heavier hydrocarbons. Both natural gasoline and LP Gases are referred to as "natural gas liquids" (NGLs).⁴

Processing is based on the "dew point" principle that each hydrocarbon gas will condense to a liquid at a certain temperature and pressure. Heavier hydrocarbons have a higher dew point, e.g., natural gasoline will liquefy at a pressure of 10 to 34 "pounds per square inch absolute" (psia) at 100° F. In contrast, ethane will liquefy at -130°F. Because "wet" gas will condense in pipelines of higher pressure and/or lower temperature, the processing industry also plays an important role in controlling the dew point of the gas for efficient and safe transportation.

Natural gas may also contain certain non-hydrocarbon substances which generally can also be divided into two basic groups: (i) acid gases that include carbon dioxide (CO₂) and hydrogen sulfide (H2S) and (ii) inert gases that include nitrogen, oxygen and helium. A final element usually found in raw gas is water vapor. See Table 1 "Typical Raw Gas Compositions" at end.

Historically, the petroleum industry has classified gas produced from an oil well as "casinghead gas."⁵ These heavier gas hydrocarbons actually exist in solution in the oil reservoir and as a gas once they reach the surface casinghead of the well. Another name for casinghead gas is "associated" gas - meaning it is associated with oil production from an oil well.⁶ In contrast, gas produced from a gas well is referred to as "non-associated" gas.⁷ The terms "wet gas"⁸ or "dry gas"⁹ typically refer not to the water vapor content of a gas stream but its concentration of heavier and thus more condensable hydrocarbons - hence the term "wet."

[Page 11-3]

With the possible exception of coal bed methane wells, very few wells produce only oil or gas. Most gas wells produce some oil and most oil wells produce some gas. Very "wet" gas might contain five or six gallons of recoverable liquid hydrocarbons per thousand cubic feet whereas a "dry" gas might contain one gallon or less of recoverable hydrocarbons per thousand cubic feet. A gas analysis (commonly done using chromatography) is taken of the gas to determine its composition and from that its potential liquid content. In the industry this liquid potential is commonly referred to as "gallons per thousand cubic feet" (GPM).

B. "Processing" versus "Treating"

In practical usage, the terms "processing" and "treating" are used interchangeably without a material difference in meaning.¹⁰ However, some technical authorities make a distinction between gas "processing" (liquid extraction) and "conditioning" (water and contaminant removal).¹¹ Clearly, the use by mechanical separation (scrubbers, separators, and heater-treaters) which conditions gas and separates out both free liquids, such as water¹² and condensate, should be viewed as "treating" the gas.¹³ On the other hand, "sweetening" refers to the removal of hydrogen sulfide from sour gas. This also, however, has been referred to as both "processing" and "treating" the gas.¹⁴

In addressing cost allocation, the Federal Energy Regulatory Commission (FERC) made some general distinctions between "processing" and "treating":

The Commission recognizes, as Exxon points out, distinctions between gas treating and gas processing. The Commission also recognizes that "gas conditioning" is often acknowledged as a distinct operation, and that sometimes the terms "gas treating" and "gas conditioning" are used interchangeably. As those terms are generally used, "gas treating" refers to the removal of constituents, (e.g., carbon dioxide, hydrogen sulfide, water, etc.,) which interfere with safe and efficient

[Page 11-4]

handling and transportation of natural gas. "Gas conditioning" often refers to those operations (e.g., hydrocarbon dew point control, water dew point control, temperature, etc.) dictated by the design specification of a particular pipeline system. "Gas processing" usually refers to the removal of constituents from the gas stream (e.g., liquefiable hydrocarbons, helium, etc.) which have a higher economic value when isolated and sold separately than when left intact in the gas stream.¹⁵

In a royalty context, distinctions between different types and degrees of treating and processing gas may be material in certain jurisdictions as to when a "marketable product" is obtained or if it is simply "enhanced."¹⁶ The royalty implications of the implied covenant to market as it pertains to processed gas is discussed below in Section VI.¹⁷

C. Historical Overview of Gas Processing Technology

The evolution of gas processing technology can be captured in four main periods, with each period using more sophisticated technology to more efficiently "extract" the hydrocarbon constituents of the raw natural gas.¹⁸

1. Casinghead Gas Era, 1900-1920

It was about 1904 when producers in West Virginia began to experiment with using compression technology to compress the casinghead gas and thereby manufacture "casinghead gasoline." With the arrival of the American automobile, casinghead gasoline was used as a blending stock for motor fuel. The residue gas was generally flared and only occasionally piped to nearby towns. Within a few years, the Mid-Continent area, particularly around Tulsa, Oklahoma, and its oil fields, became a major center for what was then called casinghead gasoline plants.¹⁹

The very characteristics which had made casinghead gas a nuisance (too wet and without enough pressure to vent) now made this natural product into something quite valuable — feedstock for the fledgling gas processing industry. The industry grew quickly and gas plants...